Sustaining growth in shareholder value Annual report to shareholders 2003 Corporate profile Imperial Oil Limited has been a leading member of the Canadian energy industry for more than 120 years and is well positioned to deliver long-term shareholder value by participating in some of the industry’s most promising growth opportunities. One of the largest producers of crude oil and natural gas liquids in Canada and a major producer of natural gas, the company is also Canada’s largest refiner and marketer of petroleum products – sold primarily under the Esso brand name – and a major producer of petrochemicals. Imperial on-line The company’s Web site contains a wealth of information for investors and others seeking to evaluate Imperial’s performance and prospects. The latest news releases, the most recent reports and presentations, information about dividends and taxes, key dates, historical share information, contact numbers and a frequently updated stock-price feed from the Toronto Stock Exchange (TSX) – all this and more is gathered in one convenient location. Information on products and services, career opportunities, corporate citizenship, donations and sponsorships, coast-to-coast operations and the company’s history is also available by visiting www.imperialoil.ca. 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. Contents 2 Letter to shareholders 4 Highlights 5 The year in review 6 Natural resources 10 Petroleum products 13 Chemicals 14 Governance and ethics 16 A partner in the Canadian community 19 Frequently used financial terms 20 Management’s discussion and analysis 28 Management and auditors’ reports 29 Financial statements, accounting policies and notes 44 Natural resources segment – supplemental information 46 Share ownership, trading and performance 47 Quarterly financial and stock trading data 48 Directors, senior management and officers 49 Information for investors Annual report 2003 1 Growth in shareholder value Imperial’s approach to delivering shareholder value is straightforward and focused on the long term. Through a combination of disciplined investments and operational excellence, the company is able to achieve industry-leading returns and strong cash flows. The resulting financial strength enables Imperial to pursue opportunities that will provide the most benefit to its shareholders. Disciplined investment Superior cash flow Growth in shareholder value Operational excellence Industry- leading returns Shareholder returns percent a year, compounded, based on original investment; assumes dividends are reinvested 30 20 10 0 S&P/TSX composite index S&P/TSX energy index Imperial Oil Highlights 2003 Long-term growth in shareholder value is a fundamental objective, and Imperial’s track record demonstrates its continuing success. • In 2003, the total return on shares including capital appreciation and dividends was more than 30 percent (TSX), and about 58 percent (AMEX). • During the past 10 years, the total return on shares has averaged more than 18 percent a year. • Dividends have been paid every year for more than a century, and regular per-share dividend payments have increased in each of the past nine years. • Since 1995, almost 220 million shares have been purchased, reducing the number of shares outstanding by 38 percent. This represents a total distribution to shareholders of approximately $6 billion over the period. 1 year 5 years 10 years Superior investment returns over time Financial highlights Net earnings (millions of dollars) Net earnings per share (dollars) (a) 2003 1 682 2002 1 224 2001 1 255 2000 1 410 – basic and diluted 4.52 3.23 3.19 3.38 Return on average shareholders’ equity (percent) (b) Return on average capital employed (percent) (c) 30.6 24.3 25.7 19.7 29.4 22.8 33.1 26.7 1999 628 1.46 15.0 12.2 (a) Calculated by reference to the average number of shares outstanding, weighted monthly (page 46). (b) Net earnings divided by average shareholders’ equity (page 31). (c) A definition of return on average capital employed can be found on page 19. Dividends per share declared, in cents 90 80 70 60 50 40 30 20 10 0 99 00 01 02 03 Consistent dividend growth 2 Imperial Oil Limited Letter to shareholders T. J. (Tim) Hearn Chairman, president and chief executive officer 2003 was another very good year for Imperial and its shareholders. Earnings reached a new record of $1,682 million, or $4.52 per share. Return on average capital employed of 24 percent and return on shareholders’ equity of 31 percent were among the highest in history. The company’s safety performance was the best on record, and operations were conducted in a continuously improving and environmentally responsible manner. Imperial continued to provide excellent value to shareholders. Regular per-share dividends were increased for the ninth consecutive year, and shareholders continued to benefit from the ongoing share buyback program. The company maintained its strong financial position, while making solid progress on major projects aimed at ensuring long-term growth in shareholder value. For the second year in succession, capital and exploration expenditures exceeded $1.5 billion. The major factors behind Imperial’s financial performance in 2003 were higher crude oil and natural gas prices and relatively strong industry margins for petroleum products. However, commodity prices are volatile and heavily influenced by a variety of factors, including supply, demand, and political and other events. For this reason, Imperial remains committed to its long-standing strategy of focusing on the factors we can control in the business, as reflected in our four corporate priorities. This allows us to weather difficult times and to prosper when market conditions are favourable. We also continued to lay a foundation for future profitability by investing in attractive long-term growth opportunities. Major projects in natural resources included advancing the expansion at Syncrude, further increasing production at Cold Lake, progressing the planned project to develop natural gas resources in the Mackenzie Delta, advancing plans to develop the Kearl oil-sands properties near Fort McMurray, Alberta, and pursuing promising exploration opportunities off Canada’s East Coast. In petroleum products, major upgrades were completed at our refineries that reduced the sulphur content of the company’s gasolines to 30 parts per million – more than a year ahead of the regulatory requirements. Construction also progressed on a cogeneration facility at the Sarnia manufacturing complex. I continue to be encouraged by the prospects for long-term earnings growth driven by the continued need for and growth of petroleum energy. Annual report 2003 3 Imperial remains focused on our four corporate priorities: flawless execution, growth in profitable sales, best-in-class costs and improved productivity of our asset mix. There is a long-standing, proven correlation between population and economic growth and energy use. Growing economies will continue to require reliable and affordable supplies of all forms of energy. Events in 2003, such as the major power outage in Ontario and the northeastern United States, brought home the importance of reliable, affordable supplies of energy and the inextricable link between energy use and our way of life. Most informed forecasters agree that oil and natural gas will supply a major proportion of this growing demand and will remain the dominant sources of the world’s energy for at least the next several decades. No other source of energy provides a competitive combination of availability, affordability, efficient infrastructure and relative ease of safe handling and storage. In addition, petroleum provides the feedstock for literally thousands of products that are critical to our daily lives and economic activity. To meet this projected need for petroleum energy, major new supply development will be required globally. In fact, about half of the oil and gas that will be needed 10 years from now will have to come from fields not currently in production. Canada and Canada’s petroleum industry are uniquely well positioned to become an even more significant producer and exporter than we are today, realizing the full value of our abundant energy resources. We have the natural resources, the expertise and experience to develop them, and close access, along with established infrastructures for transportation of oil and gas, to the world’s largest energy market in the United States. We also offer a degree of political stability and reliability that can attract the major investments needed to develop our resources on the scale required. Imperial, with access to a resource base of about 11 billion gross oil- equivalent barrels from diverse sources and a significant position in Canada’s major opportunity areas, is well positioned to be a major participant in this growth. We have the financial strength, well- delineated and proven strategies, a disciplined management approach, and highly capable, dedicated employees who continue to demonstrate their commitment to excellence. Our capabilities are further leveraged by funding and participating in new and evolving technologies through ExxonMobil’s worldwide research and development programs. We remain committed to the highest standards of corporate governance, ethics and integrity in all aspects of our business. With these strengths and our proven record of performance, I believe shareholders can look forward to a future of long-term earnings growth for Imperial. T.J. Hearn February 18, 2004 4 Imperial Oil Limited Highlights Financial highlights • Earnings of $1,682 million were the highest in the company’s history. • Return on average capital employed was 24 percent – a pace-setting level in the industry. • Regular per-share dividend payments were increased for the ninth consecutive year. • $2.4 billion cash flow from earnings enabled the company to spend more than $1.5 billion on capital and exploration expenditures, distribute $1.1 billion to shareholders through dividend payments and share purchases, contribute more than $500 million to meet pension obligations, and end the year with a cash balance of more than $400 million. • The company’s balance sheet remained strong. Net earnings by segment millions of dollars Natural resources Petroleum products Chemicals Corporate and others Net earnings 2003 1 139 407 37 99 1 682 2002 1 056 127 52 (11) 1 224 2001 957 353 23 (78) 1 255 2000 1 177 313 59 (139) 1 410 1999 567 15 43 3 628 Citizenship highlights • Employee safety performance was the best on record. • More than $310 million was spent on investments and programs to improve environmental performance and safety. • The construction and use of cogeneration facilities continues to improve • energy efficiency and help reduce emissions. In 2002, Imperial’s recovery of 99.7 percent of natural gas associated with crude oil production was the best among the top 50 oil producers in Alberta. Imperial contributed $8.6 million to help improve the quality of life in Canada. • • By year-end, more than 600 meetings and consultations had been held with aboriginal and other groups in support of the proposed Mackenzie gas project. Operating highlights • Cold Lake phases 11–13 completed their first full year of production. • All refineries began producing gasolines with an average sulphur content of less than 30 parts per million, more than a year ahead of regulatory requirements. • Full production from the Wizard Lake natural gas cap began in July and is expected to reach capacity rates of about 180 million cubic feet a day in 2004 and continue through 2006. • A number of regulatory filings required for advancing the Mackenzie gas project were completed. • Production from the Aurora 2 mine at Syncrude began in November and construction of the upgrader expansion continued, with start-up anticipated in 2005. • Progress was made on delineation of the Kearl oil-sands leases near Fort McMurray, Alberta. • Development of the Sable offshore energy project continued, with production from the fourth natural gas field beginning in 2003. • Balvenie, a deepwater exploration well, was drilled off the east coast of Nova Scotia. Imperial acquired a 25-percent interest in exploration rights for eight deepwater parcels in the Orphan Basin region offshore Newfoundland. • • The Sarnia polyethylene plant reached a milestone of five million tonnes of cumulative production and remained one of the most cost-competitive plants in North America. Annual report 2003 5 Coast-to-coast operations: (left to right) Syncrude, Sarnia polyethylene plant, offshore Nova Scotia The year in review Strong commodity prices and industry margins for petroleum products contributed to record earnings of $1,682 million, or $4.52 a share, in 2003. The company’s capital and exploration expenditures of more than $1.5 billion were more than double the average during the 1990s and more than twice the current rate of depreciation and depletion. All major business units under Imperial’s direct control had operating costs in the first quartile of the competitive range, and several were at best-in-class levels. Imperial has a long-term goal of having all its major businesses operating at best-in-class cost levels and employs rigorous external benchmarking processes to monitor performance. In 2003, research expenditures in Canada were $36 million. In addition, Imperial participates in and has access to worldwide research of about $1 billion a year carried out by Exxon Mobil Corporation. Imperial’s financial strength enables it to pursue attractive opportunities relatively independent of short-term market conditions. The balance sheet has remained strong over time, with a debt-to-capital ratio consistently in the 20–30 percent range. The company’s ability to meet its debt obligations was strengthened. In 2003, interest coverage on an earnings basis was more than 63 times, and on a cash-flow basis more than 79 times. This financial strength helped Imperial sustain the only Canadian industrial Triple-A rating from Standard & Poor’s. In 2003, an independent actuarial review of the company’s registered pension plan showed the deficit to be in line with the company’s expectations based on the downturn in equity markets since the last review in 2000. Imperial funded more than $500 million of this deficit in 2003 and expects that it can meet any further funding requirements without affecting current or future investment plans. Net earnings millions of dollars Return on average capital employed (ROCE) percent Investing in growth opportunities millions of dollars Long-term use of cash five year total (1999-2003) $9.5 billion 1 750 1 500 1 250 1 000 750 500 250 0 99 00 01 02 03 Highest earnings on record and double-digit returns 35% 30 25 20 15 10 5 0 Net earnings Net earnings Return on average Return on average capital employed capital employed (ROCE) (%) (ROCE) (%) ROCE of Canadian ROCE of Canadian integrated oil integrated oil companies (%) companies (%) 1 600 1 400 1 200 1 000 800 600 400 200 0 $4.8 billion $0.3 billion $2.8 billion Capital and exploration expenditures Depreciation and depletion 99 00 01 02 03 04 Outlook $1.6 billion Investments Debt repayment Share purchases Dividends $1.5 billion investment is more than twice depreciation Enhancing shareholder value through effective use of cash 6 Imperial Oil Limited Natural resources For Imperial’s natural resources business, 2003 was an excellent year. Earnings after tax were $1,139 million, a near record, and return on average capital employed was 32 percent. Operations generated more than $1.5 billion cash flow from earnings, of which $1 billion was reinvested in capital and exploration. Strong operating performance yielded overall production for the year of 342,000 oil-equivalent barrels a day before royalties. Significant progress was made on projects aimed at ensuring future growth in production and earnings. Oil-sands resources at Cold Lake (above) and Kearl (below and next page) contribute to Imperial’s strong position in heavy-oil development. Annual report 2003 7 Positioned for growth Oil-sands operations Imperial’s Cold Lake operation is a premier oil-sands resource for the company and for Canada – the largest thermal heavy-oil operation in the Western Hemisphere and the second largest in the world. In 2003, bitumen production was 129,000 barrels a day before royalties, an increase of 15 percent over 2002. Phased development of Cold Lake has been a deliberate and successful strategy. New production has been brought on as markets have developed, and the company has been able to make use of the most advanced technologies available. Proved reserves of crude oil and natural gas (a) The most recent expansion, phases 11–13, was successfully commissioned in late 2002 and achieved a production rate of more than 30,000 barrels a day in early cycles. The expansion included a 170-megawatt, natural-gas-fired cogeneration facility that has improved energy efficiency and now supplies all the electric power needed for the entire Cold Lake operation. The expansion was recently named “project of the year” for 2003 by Alberta Construction magazine. year ended 1999 2000 2001 2002 2003 Crude oil and NGLs millions of barrels Conventional net gross 225 267 196 233 165 197 146 175 126 151 Cold Lake Syncrude Total gross 1 016 972 926 895 853 net 878 851 807 801 763 gross 645 679 914 893 874 net 577 610 821 800 781 gross net 1 928 1 680 1 884 1 657 2 037 1 793 1 747 1 963 1 670 1 878 Natural gas billions of cubic feet gross net 1 964 1 692 1 852 1 572 1 670 1 414 1 445 1 224 1 023 1 204 (a) Gross reserves are the company’s share of reserves before deducting the shares of mineral owners or governments or both. Net reserves exclude these shares. Crude oil and NGLs – gross production by source thousands of barrels a day Natural gas – gross production millions of cubic feet a day 300 200 100 0 600 500 400 300 200 100 0 Cold Lake Syncrude Conventional and NGLs 99 00 01 02 03 99 00 01 02 03 Declining conventional production is being offset by increasing oil- sands production Natural gas production declined slightly from 2002 8 Imperial Oil Limited Natural resources (continued) Oil-sands operations (continued) In 2004, a significant development drilling program of more than 300 wells is planned within the currently approved development area to enhance productivity from existing Cold Lake phases. Opportunities are also being evaluated to improve utilization of the existing infrastructure. Regulatory approval for further expansion of the Cold Lake development area is anticipated this year. Expansions and future phases will continue to be advanced as market conditions allow. Production from Imperial’s 25-percent share in Syncrude operations was 53,000 barrels of synthetic crude oil a day before royalties, down from 57,000 barrels a day in 2002, mainly due to unplanned maintenance and equipment reliability issues. Syncrude management has developed plans to address these in 2004. Construction continued on the third stage of expansion at Syncrude. The Aurora 2 mining facilities were completed in October on budget and on schedule, and production began by late 2003. Construction of the new upgrader was about 35-percent complete by year-end, and Syncrude Canada Ltd. expects it to be commissioned by late 2005. The Syncrude project team is developing plans to address increased cost pressures on this aspect of the expansion. The cyclic steam-stimulation process used at Cold Lake STAGE 1 STEAM INJECTION STAGE 2 SOAK PHASE STAGE 3 PRODUCTION STEAM INJECTED INTO THE RESERVOIR STEAM AND CONDENSED WATER HEAT THE VISCOUS OIL HEATED OIL AND WATER ARE PUMPED TO THE SURFACE The Kearl oil-sands mining project was advanced in 2003 with the initiation of a 200-well delineation drilling program on Imperial’s two wholly owned leases. Development activities will continue in 2004 to better define available mining resources and evaluate a range of upgrading options. The project participants, Imperial and ExxonMobil Canada, are investigating the potential development of minable bitumen on three oil-sands leases, some 70 kilometres north of Fort McMurray. A phased approach is being assessed, and the project may have the potential to produce up to a total of 200,000 barrels a day. Mackenzie gas project Imperial leads the Mackenzie gas project, which seeks to develop about six trillion cubic feet (TCF) of natural gas resource in the Mackenzie River delta of Canada’s western Arctic – an important project for future North American gas supply. The largest of three major fields planned for development is Imperial’s Taglu field, with about three TCF of gas. The project design being advanced for regulatory filing is for a pipeline with an initial capacity of 1.2 billion cubic feet of gas a day (50 percent greater than the expected productive capacity of the three major discovered fields) and includes the flexibility to increase capacity up to 1.8 billion cubic feet a day. This would allow for additional northern gas to be brought to southern markets. By year-end 2003, Imperial had completed about one million work hours on the project and had held more than 600 meetings and consultations with parties including aboriginal groups, local communities, government officials, regulatory agencies and potential gas shippers. In June, as project operator, Imperial filed a Preliminary Information Package with regulatory agencies, an important milestone. This followed successful negotiations with other co- venturers, including the Aboriginal Pipeline Group (APG), Annual report 2003 9 Positioned for growth: (left to right) offshore East Coast, Mackenzie gas project, Syncrude which represents the interests of the Aboriginal Peoples in the North. APG participation is an integral part of the project and represents an historic advance for aboriginal involvement in commercial developments of this type. Another milestone was passed in late 2003 when the application for Commercial Discovery Declaration for the Taglu field was filed with the National Energy Board. Assuming that the regulators proceed on the timelines described in their June 2002 Cooperation Plan, filing of the main regulatory applications for the project is expected to take place mid-2004. Community engagement has been critical to the success of the Mackenzie gas project. Building enduring relationships with Canada’s northern communities is an important component of Imperial’s ongoing operations and development initiatives. Conventional Western Canada In Western Canada, full production from the natural gas cap at Imperial’s Wizard Lake oil field in Alberta began in July 2003. Production rates of about 180 million cubic feet a day will be achieved in 2004 once gas plant capacity is available and are expected to continue through 2006. Also, in November, the first natural gas was produced from the Gwillim field in northeastern British Columbia. Additional development of this field is planned. Offshore East Coast In East Coast operations, natural gas production from Imperial’s nine-percent interest in the Sable offshore energy project averaged 40 million cubic feet a day before royalties. During 2003, production began from a fourth Sable field, Alma, and construction was started on facilities for a fifth field, South Venture. Funding was also approved for a natural gas compression facility that will service production from all Sable fields by late 2006. Balvenie, a deepwater exploration well drilled in mid-2003 off the east coast of Nova Scotia, did not encounter commercial quantities of gas and was abandoned. Imperial continues to monitor industry activity in the region, where it retains other exploration licences. In December, Imperial acquired a 25-percent interest in the exploration rights for eight deepwater parcels in the Orphan Basin, off the east coast of Newfoundland. This region is considered to have high potential but is located in a harsh offshore environment and is a high-risk, high-cost area. Plans are being developed with co-venturers ExxonMobil Canada Ltd. (25 percent) and Chevron Canada Resources (50 percent) for potential seismic work in 2004. Imperial’s share of proposed exploration spending on this acreage totals $168 million, with a minimum commitment of $42 million. 1 0 Imperial Oil Limited Petroleum products Imperial continues to upgrade its network of retail outlets (above). In addition to fuels, petroleum provides the feedstock for thousands of products and materials that are essential to our way of life (below). Imperial’s petroleum products operations achieved record earnings of $407 million in 2003, supported by increased sales and strong industry refining and marketing margins. Return on average capital employed was 16 percent and cash flow from earnings was $719 million, of which $478 million was reinvested in the business. Annual report 2003 1 1 Customers enjoy the convenience of the company’s On the Run retail sites Improving productivity and profitability Petroleum products The company’s strategy of focusing relentlessly on providing the best offer to customers, having best-in-class costs and using capital efficiently and effectively continued to serve shareholders well. At the end of 2003, all major business units in petroleum products were at first-quartile unit-cost levels, and some were best-in-class. Sales of refined products were up from 2002 as Imperial retained the leading position in every major market segment. In the retail automotive business, the company’s leading market share was increased with continuing improvements to products and services. At the end of 2003: • The retail network included 787 company-owned sites. Average productivity per site for 2003 was 5.2 million litres a year, up six percent from 2002. Under an ongoing program to improve the network, Imperial built nine new sites, rebuilt 17 and upgraded three. • The company’s network of about 650 Esso convenience stores across Canada, including On the Run and Tiger Express, was the second largest in Canada. On the Run was recently selected as the North American convenience store chain of the year by Convenience Store Decisions magazine. In 2003, 65 new On the Run stores were added. Convenience-store sales rose by about nine percent in 2003, well above the industry average. Imperial’s network of about 400 sites with car-wash facilities is the largest in the industry. • The number of Esso retail sites providing Tim Hortons food and refreshments had increased to more than 300 from 270 in 2002, as this strategic alliance continued to benefit both companies. Esso retail outlets average number Throughput – company-owned and leased retail outlets millions of litres per site 2 500 2 000 1 500 1 000 500 0 6 5 4 3 2 1 0 Company-owned or leased Dealer-owned or leased 99 00 01 02 03 99 00 01 02 03 Network rationalization contributed to retail productivity improvement 1 2 Imperial Oil Limited Petroleum products (continued) Previously introduced customer service and convenience features, such as the Speedpass transponder for payment convenience and the Esso Extra loyalty program, including the points-exchange alliance with Hudson’s Bay Company, continued to help improve market share and sales volumes. agency business. Designed to reduce costs and increase efficiency, the project streamlined this business by replacing a network of rural bulk plants with a network of primary and secondary distribution terminals. In 2003, productivity per site quadrupled to an average of about 25 million litres. Imperial maintained its market-leading share of the finished lubricants market in Canada and continues to be the only supplier with manufacturing, blending and packaging capability in both the east and west. The company is also the exclusive Canadian marketer of Mobil products, for which sales almost doubled in 2003 from 2002. Through its world-leading lubricants research capability, the company commercialized 37 new products in 2003. A centralized customer order and integrated management system was implemented during the year, completing a major program to improve productivity in Imperial’s rural Product inventory days of sales 40 30 20 10 0 99 00 01 02 03 Freeing up working capital for more productive use During 2003, the ancillary equipment-servicing feature of Imperial’s heating oil business was sold to Sears Canada Inc. Under a marketing agreement, Sears will provide equipment servicing for Esso Home Comfort customers, while promoting Imperial as the preferred supplier of heating oil. A continued focus on reducing working capital lowered the number of days for which product is held in inventory by a further four percent versus 2002. Over the last 10 years, this has been reduced by about 25 percent. The reduction in 2003 freed up more than $35 million in cash for more productive use. Capital expenditures in petroleum products operations were $478 million in 2003. This included completion of a multi-year project to enable the company’s refineries to produce low- sulphur gasoline to meet the requirements of 2004 model-year automotive technologies. This project, costing about $600 million and using ExxonMobil proprietary SCANfining technology and other modifications, was completed more than a year ahead of federal regulatory requirements. As a result, gasolines produced by Imperial now have one of the lowest sulphur levels in the world. Other capital expenditures included construction on a cogeneration facility in Sarnia and upgrading of the network of Esso service stations. Imperial’s refineries and chemical plants also continued to benefit from the ExxonMobil Global Energy Management System, a worldwide initiative aimed at improving energy use in manufacturing operations. Energy efficiency improved by one percent in 2003, and over the last 30 years, Imperial’s refineries have improved energy efficiency by more than 40 percent. Annual report 2003 1 3 Chemicals (Left) manufacturing polyethylene, (right) constructing cogeneration facilities Industry-leading performance Imperial’s chemicals operations generated earnings of $37 million, with return on average capital employed of 18 percent and cash flow from earnings of $66 million in 2003. Sales of petrochemical products were 3,300 tonnes a day, down slightly from 2002. In this cyclical business, 2003 was a weak year for the petrochemicals industry in North America, characterized by relatively high energy and feedstock costs and soft sales volumes. The company remains one of Canada’s leading producers of chemical products, with the largest market share in North America for polyethylene used in rotational and injection molding and the largest share of the Canadian market for solvents. The Sarnia polyethylene manufacturing facility is within one day’s trucking of customers representing 70 percent of North American demand for polyethylene. The company’s other chemicals businesses also contributed to profitability. In 2003, the Sarnia polyethylene plant achieved a milestone of having produced five million tonnes of product, and it remains one of the most cost-competitive plants in North America. Through successive low-cost expansions, annual capacity has been increased from 135,000 tonnes in 1983 to about 450,000 tonnes in 2003. A new computer-based managing system for chemicals operations that will improve service to customers throughout North America was completed in 2003 and became fully operational in early 2004. It is designed to realize efficiencies and cost reductions by managing all aspects of the business – from order processing through product delivery, invoicing, collection and financial information. Capital expenditures in chemicals were $41 million in 2003. This included chemicals’ share of a 95-megawatt cogeneration facility under construction at Imperial’s Sarnia refining and chemicals manufacturing complex. When it begins operation in 2004, the facility will significantly improve energy efficiency by using natural gas to generate both electricity and steam simultaneously, and help to reduce emissions. It is estimated that it will reduce the net costs of ethylene production by about 10 percent. Polyethylene sales volumes thousands of tonnes 600 500 400 300 200 100 0 99 00 01 02 03 Sales volumes declined in weak markets Sales of purchased polyethylene Sales from our own production 1 4 Imperial Oil Limited Sound governance. Ethics and integrity above all. Imperial has maintained a long tradition of sound governance practices. The company also recognizes the importance and value of ethics and business integrity and believes these principles are critical to long-term sustainable results. Some of the 244 talented new employees who joined Imperial in 2003 (above), formal training and on-the-job experience help employees develop capabilities (below) Annual report 2003 1 5 Principled people and practices Imperial’s board of directors (Left to right) P. Des Marais II, B.J. Fischer, T.J. Hearn, R. Phillips, J.F. Shepard, P.A. Smith, S.D. Whittaker, K.C. Williams, V.L. Young Sound governance practices Integrity of reporting Imperial’s corporate governance practices are fully disclosed and meet the requirements of the Toronto Stock Exchange and the American Stock Exchange. For example: • The majority of members of the board of directors are nonemployee directors. • All board committees, including the audit committee, are comprised of only nonemployee directors. • Directors and committees have the right to engage an outside adviser at the company’s expense. • Nonemployee directors meet regularly in the absence of management, and these meetings are chaired by a nonemployee director. • The audit committee is finalizing processes for the confidential handling of employee complaints. The company was able to meet the governance requirements of both the Ontario Securities Commission and the United States’ Sarbanes-Oxley Act with only minor changes to long- established practices. Imperial has determined that its existing reserves booking practices do not have to change as a consequence of the Canadian Securities Administrators National Instrument 51-101. A complete description of Imperial’s governance practices can be found in the 2003 Management Proxy Circular on the company’s Web site at www.imperialoil.ca. Imperial has a simple, straightforward capital structure and consistently reports its results using clear, transparent accounting practices. The company does not use special purpose entities, special adjustments or pro-forma reporting, nor does it use derivatives to speculate on the future direction of currency or commodity prices, and it does not sell forward future production. A commitment to maintaining sound financial controls is supported by the company’s controls integrity management system. This establishes a framework of clearly defined expectations that every operation must meet. Principled people Employees are a competitive advantage, and the company strives to be an employer of choice by attracting, developing and retaining high-performing, principled people from diverse backgrounds. Providing people with the opportunity to enhance their professional and technical skills is key to achieving superior business results. For example, in 2003, about a quarter of our employees attended the 100 courses offered to assist them in developing skills applicable throughout the company. All employees and directors are required to comply with the company’s business ethics program. Originally developed in the 1970s, the program covers topics such as conflicts of interest, integrity of dealings both inside and outside the company, competition law and restrictive trade practices. Employees Number of full-time employees at December 31 Total payroll and benefits (millions of dollars) (a) 2003 6 256 1 188 2002 6 460 1 034 2001 6 740 902 2000 6 704 814 1999 6 550 856 (a) Includes both the company’s payroll and benefit costs and its share of the Syncrude joint-venture payroll and benefit costs. 1 6 Imperial Oil Limited A partner in the Canadian community Imperial is fully committed to maintaining the highest standards of health and safety for its employees and contractors, operating and managing its businesses in an environmentally responsible manner, and maintaining close relationships with local communities. In 2003, the company spent $310 million on capital projects and other programs to improve safety and environmental performance, and contributed $8.6 million to help improve the quality of life in Canadian communities. Filling up with Esso low-sulphur gasoline (above), striving to minimize the impact of operations on the environment (below) Annual report 2003 1 7 Supporting literacy in the Northwest Territories Caring about our community “Nobody gets hurt” Improving environmental performance Nothing is more important than the health and safety of our employees, contractors, neighbours and customers. The operations integrity management system (OIMS) provides the framework for the disciplined management of safety, health and environmental activities. Lloyd’s Register Quality Assurance Ltd. has attested that OIMS meets the ISO 14001 requirements for a comprehensive environmental management system. Imperial’s safety performance continues to be among the best in Canadian industry, and in 2003, the company had its safest year on record with the lowest incidence of work-related injuries and illnesses for employees and contractors combined. The company’s goal, however, is that “nobody gets hurt,” and Imperial is committed to continuously improving performance through education, awareness, training and other programs. Employee and contractor safety leadership total recordable incidents per 200,000 work hours Upstream flaring millions of cubic feet of gas a day 3 2 1 0 00 01 02 03 Best safety performance on record for employees and contractors combined 6 5 4 3 2 1 0 Employees Employees Contractors Contractors 99 00 01 02 03 Gas flaring substantially reduced Recognizing the importance of a healthy environment, Imperial is committed to continuously improving in this area. For example, in 2003, the company: • completed a more than $600-million project to reduce the sulphur content of Esso-branded gasolines to among the lowest in the world. • spent about $90 million on environmental remediation programs. • continued to conserve valuable resources and reduce emissions by recovering natural gas associated with crude oil production that would otherwise be flared or vented into the air. Imperial’s 2002 recovery rate of 99.7 percent of associated gas was ranked the best among Alberta’s top 50 oil producers for the second consecutive year. • continued to pursue ways to improve energy efficiency and reduce emissions of carbon dioxide and other greenhouse gases from its operations, and to report annually to Canada’s Climate Change Voluntary Challenge and Response (VCR) program. Imperial’s VCR submissions have consistently achieved a gold-level rating. invested about $65 million in Sarnia cogeneration facilities, which use natural gas to produce electricity and steam simultaneously, thereby reducing total energy consumption and helping to reduce emissions in Canada. Total project expenditures are expected to be about $115 million when completed early in 2004. • In 2002, the government of Canada ratified the Kyoto protocol on climate change. It has not yet introduced any implementing legislation, and any possible effects on Imperial or its plans are uncertain. The government has indicated to industry that its intent is not to discourage energy development and that the impacts of Kyoto legislation will be contained. Through industry associations, Imperial continues to work closely with governments on the implementation of Canada’s response. 1 8 Imperial Oil Limited Caring about our community (continued) Funding environmental education at the Toronto Zoo (left) and supporting hockey and ringette programs across Canada (right) Caring for our neighbours Imperial was proud to assist local communities in 2003: • When concern over SARS affected the tourism industry in Toronto, an “Esso Celebrates Toronto” promotion encouraged people to come back into the city by offering discounted gasoline. A portion of all sales – a total of $250,000 – was donated for research to improve protective equipment for health-care workers. • During the power blackout that affected much of Ontario and when Hurricane Juan hit the East Coast, employees worked around the clock to maintain fuel supplies for essential emergency services. In recognition of their special needs, disabled drivers can buy full-serve gasoline for self-serve prices at company-owned Esso service stations. At sites with both full- and self-serve pumps, the disabled driver can have the tank filled by an attendant for the self-serve price. Self-serve retailers will arrange for assistance at the pump when the customer calls in advance. A tradition of giving In 2003, through donations, sponsorships, scholarships and grants, Imperial contributed a total of $8.6 million to communities, groups and organizations that help improve the quality of life in Canada. The Imperial Oil Foundation donated $6.1 million to more than 400 organizations, with an emphasis on programs for youth and education. This included $1 million to the University of Waterloo to help build the computer-science capability of high-school girls, and grants totalling about $215,000 to fund environmental and conservation programs. In addition, Imperial gave 35 awards to 16 universities, totalling $650,000, under the company’s University Research Award program. Other contributions included $288,000 for aboriginal scholarships and educational programs, almost $350,000 for the Esso Medals of Achievement and other amateur hockey programs, $274,000 to support public policy organizations and about $315,000 for local community sponsorships. The company also contributed $400,000 to Syncrude’s corporate-giving program, an amount representing Imperial’s 25-percent ownership share. In partnership with its employees and annuitants, the company contributed more than $2.5 million to the 2003 United Way/ Centraide campaigns across Canada. This was Imperial’s highest- ever contribution, exceeding its 2002 contribution by more than $100,000. The Toronto campaign received a Corporate Support Award for demonstrating exceptional commitment to the United Way. Through its volunteer involvement program, Imperial provided 278 grants totalling $270,000 to support organizations to which employees and annuitants contributed time and effort. Engagement and dialogue with key communities is an important component of Imperial’s ongoing operations and development initiatives. This includes building enduring relationships with Canada’s aboriginal communities, with a focus on developing and implementing mutually beneficial strategies for business development, employment, education and training within the aboriginal communities in which we operate. A comprehensive description of Imperial’s corporate citizenship practices is available on the company’s Web site at www.imperialoil.ca. Annual report 2003 Frequently used financial terms 1 9 Listed below are definitions of four of Imperial’s frequently used financial performance measures. The definitions are provided to facilitate understanding of the terms and how they are calculated. These terms do not have any standardized meaning prescribed by Canadian generally accepted accounting principles (GAAP) and may not be calculated in the same way as similar measures are by other companies. Capital employed Capital employed is a measure of net investment. When viewed from the perspective of how capital is used by the business, it includes the company’s property, plant and equipment and other assets, less liabilities, excluding both short-term and long-term debt. When viewed from the perspective of the sources of capital employed for the total company, it includes total debt and shareholders’ equity. Both of these views include the company’s share of amounts applicable to equity companies. millions of dollars Business uses: asset and liability perspective Total assets Less: total current liabilities excluding short-term debt and current portion of long-term debt Less: total long-term liabilities excluding long-term debt Add: Imperial’s share of debt-financed equity company net assets Total capital employed Total company sources: debt and equity perspective Short-term debt Current portion of long-term debt Long-term debt Shareholders’ equity Add: Imperial’s share of equity company debt Total capital employed 2003 12 361 (2 817) (2 334) 52 7 262 72 501 859 5 778 52 7 262 2002 11 894 (2 671) (2 469) 49 6 803 72 – 1 466 5 216 49 6 803 2001 10 781 (2 565) (2 404) 29 5 841 460 – 1 029 4 323 29 5 841 Return on average capital employed (ROCE) ROCE is a financial performance ratio. For each of the company’s business segments, ROCE is annual business-segment earnings divided by average business-segment capital employed (an average of the beginning- and end-of-year amounts). These segment earnings include Imperial’s share of segment earnings of equity companies, consistent with the definition used for capital employed, and exclude the cost of financing. The company’s total ROCE is net earnings excluding the after-tax cost of financing divided by total average capital employed. The company has consistently applied its ROCE definition for many years and views it as the best measure of historical capital productivity to both evaluate management’s performance and demonstrate to shareholders that capital has been used wisely over the long term. millions of dollars Net earnings Financing cost (after tax), including Imperial’s share of equity companies Earnings excluding financing costs Average capital employed Return on average capital employed (percent) 2003 1 682 25 1 707 7 033 24.3 2002 1 224 23 1 247 6 322 19.7 2001 1 255 51 1 306 5 738 22.8 Operating costs Operating costs are the combined total of operating, selling, general, exploration, depreciation and depletion expenses from the consolidated statement of earnings and Imperial’s share of similar costs for equity companies. Operating costs are the costs incurred during the period to produce, manufacture and otherwise prepare the company’s products for sale – including staffing, maintenance, and other costs to explore for and produce oil and gas and operate refining and chemical plants. Delivery costs to customers and marketing expenses are also included. Operating costs exclude the cost of raw materials and those costs incurred in bringing inventory to its existing condition and final storage prior to delivery to a customer. These expenses are on a before-tax basis. While Imperial’s management is responsible for all revenue and expense elements of net earnings, operating costs, as defined below, represent the expenses most directly under management’s control. millions of dollars Expenses (from page 29) Exploration Operating Selling and general Depreciation and depletion Subtotal Imperial’s share of equity company expenses Total operating costs 2003 55 2 025 1 269 750 4 099 56 4 155 2002 30 1 865 1 222 705 3 822 49 3 871 2001 45 1 830 1 280 718 3 873 42 3 915 Cash flow from earnings Cash flow from earnings is determined by adjusting net earnings for the effects of non-cash items. It measures the extent of cash generated from the business before the effects of changes in non-cash working capital and before any investing and financing activities by the company. Cash flow from earnings is a measure used by the company’s management for analysis and evaluation of operating performance and liquidity of each business segment and for future investment decisions. A reconciliation of net earnings to cash flow from earnings is provided in the consolidated statement of cash flows on page 30. 2 0 Imperial Oil Limited Management’s discussion and analysis of financial condition and results of operations FINANCIAL SUMMARY millions of dollars Revenues Net earnings by segment Natural resources Petroleum products Chemicals Corporate and other Net earnings Total assets Long-term debt Other long-term obligations Per-share information (dollars) Earnings per share – basic and diluted Dividends 2003 19 208 1 139 407 37 99 1 682 2002 17 042 1 056 127 52 (11) 1 224 2001 17 253 957 353 23 (78) 1 255 2000 18 051 1999 12 853 1 177 313 59 (139) 1 410 567 15 43 3 628 12 361 11 894 10 781 11 244 10 828 859 972 4.52 0.87 1 466 1 207 3.23 0.84 1 029 1 098 3.19 0.83 1 037 1 104 3.38 0.78 1 352 1 172 1.46 0.75 RESULTS OF OPERATIONS Natural resources Net earnings in 2003 were $1,682 million or $4.52 a share – the best year on record – compared with $1,224 million or $3.23 a share in 2002 (2001 – $1,255 million or $3.19 a share). Higher realizations for natural gas and crude oil and higher industry margins for petroleum products, partly offset by the negative impact of a higher Canadian dollar, were the main reasons for the increased earnings. Total revenues were $19.2 billion, up about 13 percent from 2002. The return on average capital employed was 24 percent, compared with 20 percent in 2002 (2001 – 23 percent). Earnings from natural resources were $1,139 million, up from $1,056 million in 2002 (2001 – $957 million). Higher realizations for natural gas and crude oil and higher production of Cold Lake bitumen were largely offset by the negative impact of a higher Canadian dollar. Resource revenues were $5.6 billion, up from $4.9 billion in 2002 (2001 – $5.3 billion). The main reasons for the increase were higher prices for natural gas and crude oil and increased production from Cold Lake. Return on average capital employed was 32 percent for the natural resources segment, compared with 36 percent in 2002 (2001 – 41 percent), reflecting the company’s significant increase in investment in the resources business during the past two years. Factors affecting Imperial’s 2003 earnings millions of dollars 1 224 450 400 (280) (170) 58 1 682 Higher Canadian dollar Higher product margins Higher volume- related costs, maintenance and other expenses Higher volumes and other Higher resource realizations 2002 2003 Annual report 2003 2 1 Financial statistics millions of dollars Net earnings Revenues Capital employed at December 31 Return on average capital employed (percent) 2003 1 139 5 648 3 784 32.0 2002 1 056 4 894 3 325 35.8 2001 957 5 321 2 580 40.5 2000 1 177 5 900 2 142 51.0 1999 567 3 904 2 472 22.5 World oil prices strengthened considerably in early 2003 and remained relatively strong due to a combination of world supply concerns and increased world demand. The annual average price of Brent crude oil, the most actively traded North Sea crude and a common benchmark of world oil markets, was $29 (U.S.) a barrel in 2003, compared with $25 in 2002 (2001 – $24.50). and heavy crude. The price of Bow River, a benchmark Canadian heavy crude oil, increased by four percent in 2003, compared with a nine-percent increase in prices for Canadian light crude oil. Average realizations for Cold Lake bitumen were about two percent lower than the previous year, as the stronger Canadian dollar offset any price increases. The increase in the company’s realizations on sales of conventional Canadian crude oil was diminished by the strengthening of the Canadian dollar. Average realizations during the year were $40.10 (Cdn) a barrel versus $36.81 in 2002 (2001 – $35.56). Prices for Canadian natural gas in 2003 were higher on average than in the previous year. The average of 30-day spot prices for natural gas at the AECO hub in Alberta was about $6.70 a thousand cubic feet in 2003, up from $4.10 in 2002 (2001 – $6.30). Average prices for Canadian heavy crude oil were higher in 2003, but not as high as those for lighter crude oil, as increased supply of Canadian heavy crude oil widened the average spread between light The company’s average realizations on natural gas sales increased to $6.60 a thousand cubic feet from $4.02 in 2002 (2001 – $5.72). Average realizations and prices dollars Conventional crude oil realizations (a barrel) Natural gas realizations (a thousand cubic feet) Par crude oil price at Edmonton (a barrel) Heavy crude oil price at Hardisty (Bow River, a barrel) 2003 40.10 6.60 43.93 33.00 2002 36.81 4.02 40.44 31.85 2001 35.56 5.72 39.64 25.11 2000 41.52 4.99 45.02 34.49 1999 24.75 2.66 27.80 23.51 Gross production of crude oil and natural gas liquids (NGLs) increased to 256,000 barrels a day from 247,000 barrels in 2002 (2001 – 267,000). Net production increased slightly to 225,000 barrels a day from 223,000 barrels in 2002 (2001 – 237,000). Net bitumen production at the company’s wholly owned facilities at Cold Lake increased to 116,000 barrels a day from 106,000 barrels in 2002 (2001 – 121,000). The higher volume was a result of the initial production cycles from phases 11–13, which began operation in December 2002. This was offset in part by lower production from existing operations, due to the cyclic nature of production at Cold Lake. The effective royalty rate on Cold Lake production increased in 2003, as capital expenditures were lower upon the completion of phases 11–13. The rate increased to 10 percent of production from five percent in 2002 (2001 – five percent). Production from the Syncrude operation, in which the company has a 25-percent interest, decreased during 2003 as increased unplanned maintenance affected production through much of the year. Gross production of upgraded crude oil dropped to 211,000 barrels a day from 229,000 barrels in 2002 (2001 – 223,000). Imperial’s share of average net production decreased to 52,000 barrels a day from 57,000 barrels in 2002 (2001 – 52,000). Net production of conventional oil decreased to 35,000 barrels a day from 39,000 barrels in 2002 (2001 – 42,000) as a result of the natural decline in western Canadian reservoirs. Gross production of natural gas decreased to 513 million cubic feet a day from 530 million in 2002 (2001 – 572 million). Net production was 457 million cubic feet a day in 2003, down from 463 million in 2002 (2001 – 466 million). Net production available for sale decreased to 390 million cubic feet a day from 396 million in 2002 (2001 – 376 million). Lower production as a result of reservoir decline was mostly offset by production from the new facilities at Wizard Lake in Alberta, which were completed in the third quarter of 2003. Crude oil prices U.S. dollars a barrel – quarterly average Natural gas average prices dollars a thousand cubic feet – AECO hub 30-day spot 30 25 20 15 10 5 0 99 00 01 02 03 Crude oil prices remained strong in 2003 12 10 8 6 4 2 0 Brent crude Brent crude Canadian heavy Canadian heavy oil (Bow River) oil (Bow River) 99 00 01 02 03 Average natural gas prices increased sharply from 2002 2 2 Imperial Oil Limited Management’s discussion and analysis of financial condition and results of operations (continued) Crude oil and NGLs – production and sales (a) thousands of barrels a day Conventional crude oil Cold Lake Syncrude Total crude oil production NGLs available for sale (b) Total crude oil and NGL production Cold Lake sales, including diluent (c) NGL sales Natural gas – production and sales (a) millions of cubic feet a day Production (d) Production available for sale (b) Sales 53 2003 gross net 35 46 129 116 52 228 203 22 256 225 170 39 28 2002 gross net 51 39 112 106 57 57 220 202 21 247 223 145 40 27 55 56 2001 gross net 42 128 121 52 239 215 22 267 237 167 43 28 2000 gross net 60 46 119 102 42 51 230 190 23 260 213 156 42 30 56 1999 gross net 51 65 132 107 55 253 213 24 284 237 173 43 31 2003 gross net 513 457 446 390 460 2002 gross net 530 463 463 396 499 2001 gross net 572 466 482 376 502 2000 gross net 526 459 345 277 419 1999 gross net 469 413 300 244 393 (a) Daily volumes are calculated by dividing total volumes for the year by the number of days in the year. Gross production is the company’s share of production (excluding purchases) before deducting the shares of mineral owners or governments or both. Net production excludes those shares. (b) Production available for sale excludes amounts used for internal consumption and amounts reinjected. Starting in 2001, production available for sale reflects a change in the supply of natural gas to company operations from company-produced gas to third-party purchased gas. (c) Includes natural gas condensate added to the Cold Lake bitumen to facilitate transportation to market by pipeline. (d) Production of natural gas includes amounts used for internal consumption with the exception of amounts reinjected. Operating costs increased by 11 percent in 2003. The main factors were increased costs associated with the newly completed phases 11–13 and cogeneration facilities at Cold Lake, unplanned maintenance at Syncrude and increased exploration costs. Petroleum products mainly as a result of the strengthening of industry petroleum product margins and increased sales volumes, partly offset by the negative impact of a higher Canadian dollar. Revenues were $16.1 billion, up from $14.4 billion in 2002 (2001 – $14.4 billion). Net earnings from petroleum products were a record $407 million or 1.3 cents a litre in 2003, up from $127 million or 0.4 cents a litre in 2002 (2001 – $353 million or 1.2 cents a litre). Earnings improved Return on average capital employed was 16 percent for the petroleum products segment, compared with six percent in 2002 (2001 – 16 percent). Financial statistics millions of dollars Net earnings Revenues Capital employed at December 31 Return on average capital employed (percent) Sales of petroleum products millions of litres a day (a) Gasolines Heating, diesel and jet fuels Heavy fuel oils Lube oils and other products Net petroleum products sales Sales under purchase and sale agreements Total sales of petroleum products Total domestic sales of petroleum products (percent) Refinery utilization millions of litres a day (a) Total refinery throughput (b) Refinery capacity at December 31 Utilization of total refinery capacity (percent) 2003 407 16 058 2 784 15.5 2003 33.0 26.2 5.4 5.8 70.4 14.6 85.0 93.3 2003 71.6 79.9 90 2002 127 14 434 2 484 5.5 2002 32.9 25.0 4.9 6.4 69.2 13.9 83.1 91.5 2002 71.2 79.4 90 2001 353 14 405 2 148 15.9 2001 32.3 26.5 5.4 5.4 69.6 11.6 81.2 93.4 2001 71.4 79.1 90 2000 313 15 120 2 280 13.9 2000 32.0 27.5 5.1 5.0 69.6 10.7 80.3 94.0 2000 71.6 78.7 91 1999 15 10 665 2 213 0.6 1999 31.9 26.9 4.6 5.8 69.2 10.8 80.0 95.6 1999 70.1 78.7 89 (a) Volumes a day are calculated by dividing total volumes for the year by the number of days in the year. (b) Crude oil and feedstocks sent directly to atmospheric distillation units. One thousand litres is approximately 6.3 barrels. Annual report 2003 2 3 Margins were higher in the refining segment of the industry in 2003 compared with those in 2002, as international wholesale product prices increased more than raw material costs. However, the effects of higher international margins were reduced partially by a higher Canadian dollar. The company’s total sales volumes, including those resulting from reciprocal supply agreements with other companies, were 85 million litres a day, compared with 83.1 million litres in 2002 (2001 – 81.2 million). Excluding sales resulting from reciprocal agreements, sales were 70.4 million litres a day, compared with 69.2 million litres in 2002 (2001 – 69.6 million). Operating costs increased by about five percent in 2003 from the previous year, mainly because of higher energy costs and expenses related to increased sales volumes. Chemicals Earnings from chemical operations were $37 million in 2003, down from $52 million in 2002 (2001 – $23 million). Reduced industry margins on sales of polyethylene as a result of higher feedstock costs and weaker industry demand were the main reasons for the decrease in earnings. Total revenues from chemical operations were $1,232 million, compared with $1,164 million in 2002 (2001 – $1,175 million). Gains from higher prices for polyethylene, intermediate chemicals and aromatics during 2003 more than offset lower sales volumes. Return on average capital employed was 18 percent for the chemicals segment, compared with 28 percent in 2002 (2001 – 14 percent). The average industry price of polyethylene was $1,415 a tonne in 2003, up 15 percent from $1,229 a tonne in 2002 (2001 – $1,284). However, margins were reduced because of higher feedstock costs, reflecting increased prices for natural gas. Sales of chemicals decreased to 3,300 tonnes a day from 3,500 tonnes in 2002 (2001 – 3,300 tonnes) as a result of reduced demand. Operating costs in the chemicals segment increased by about four percent in 2003 mainly because of higher planned capital project-related expenses. Financial statistics millions of dollars Net earnings Revenues Capital employed at December 31 Return on average capital employed (percent) Sales volumes thousands of tonnes a day (a) Polymers and basic chemicals Intermediates and other Total chemicals 2003 37 1 232 246 17.5 2003 2.4 0.9 3.3 2002 52 1 164 178 27.9 2002 2.5 1.0 3.5 2001 23 1 175 195 13.7 2001 2.4 0.9 3.3 2000 59 1 173 140 53.4 2000 2.2 0.9 3.1 1999 43 872 81 48.9 1999 2.0 1.0 3.0 (a) Volumes a day are calculated by dividing total volumes for the year by the number of days in the year. One tonne is approximately 1.1 short tons or 0.98 long tons. Average refining margins Canadian cents a litre 8 7 6 5 4 3 2 1 0 99 00 01 02 03 Industry refining margins improved from 2002 New York Harbor product prices minus Brent crude; weighting reflects Imperial’s product mix. 2 4 Imperial Oil Limited Management’s discussion and analysis of financial condition and results of operations (continued) Corporate and other Earnings from corporate and other accounts were positive $99 million in 2003, compared with negative $11 million in 2002 (2001 – negative $78 million). The improvement was mainly attributable to favourable foreign-exchange effects on the company’s U.S.-dollar-denominated debt. The company retired the remaining balance of its U.S.-dollar-denominated debt in 2003. LIQUIDITY AND CAPITAL RESOURCES Cash flow from earnings was $2,354 million, up from $1,781 million in 2002 (2001 – $2,016 million), mainly because of increased earnings. Cash provided from operating activities was $2,194 million, compared with $1,676 million in 2002 (2001 – $2,004 million). The increased cash inflow was mainly due to higher earnings, timing of scheduled income-tax payments and the effects of commodity prices on receivable and payable balances, partly offset by additional funding contributions to the company’s registered pension plan. In June, the company renewed the normal course issuer bid (share buyback program) for another 12 months. During 2003, the company purchased more than 16 million shares for $799 million. Since Imperial initiated its first buyback program in 1995, the company has purchased 219 million shares – representing about 38 percent of the total outstanding at the start of the program – with resulting distributions to shareholders of $5,968 million. The company declared dividends totalling 87 cents a share in 2003, up from 84 cents in 2002 (2001 – 83 cents). Regular per-share dividends paid have increased in each of the past nine years and, since 1986, payments a share have grown by more than 55 percent. The company’s financial position remained very strong in 2003. Following one of the largest capital investment programs in Imperial’s history as well as funding contributions to the company’s registered pension plan, the cash balance was $448 million at year-end, compared with $766 million at the end of 2002 (2001 – $872 million). In 2003, the company retired its $600-million (U.S.) variable-rate debt, due in 2004, for $818 million (Cdn) and replaced it with $818 million of Canadian-dollar-denominated variable-rate loans from Exxon Overseas Corporation at interest equivalent to Canadian market rates. Total debt outstanding, excluding the company’s share of equity company debt, at the end of 2003 was $1,432 million, compared with $1,538 million at the end of 2002 (2001 – $1,489 million). Debt represented 20 percent of the company’s capital structure at the end of 2003, compared with 23 percent at the end of 2002 (2001 – 26 percent). Debt-related interest expense paid in 2003 was $38 million, down from $40 million in 2002 (2001 – $77 million). The retirement of the company’s long-term fixed-rate debt during the past few years was the main reason for the reduction. The average effective interest rate on the company’s debt was 2.9 percent in 2003, compared with 2.1 percent in 2002 (2001 – 5.1 percent). Financial percentages, ratios and credit rating Total debt as a percentage of capital (a) Interest coverage ratios Earnings basis (b) Cash-flow basis (c) Long-term unsecured debt rating (d) Local currency (DBRS/S&P) 2003 20 63 79 2002 23 46 63 2001 26 26 36 2000 25 23 29 1999 24 9 14 AA/AAA AA/AAA AA/AAA AA/AAA AA/AAA (a) Current and long-term portions of debt (page 31) divided by debt and shareholders’ equity (page 31). (b) Net earnings (page 29), debt-related interest expense (page 43, note 12) and income taxes (page 29) divided by debt-related interest expense. (c) Cash flow from earnings (page 30), current income tax expense (page 37, note 4) and debt-related interest expense divided by debt-related interest expense. (d) Dominion Bond Rating Service (DBRS) and Standard & Poor’s Corporation (S&P) are debt-rating agencies. Capital and exploration expenditures Total capital and exploration expenditures were $1,526 million in 2003, down slightly from $1,600 million in 2002 (2001 – $1,115 million). The funds were used mainly to maintain and expand crude oil and natural gas production capacity, to upgrade refineries to meet low-sulphur gasoline requirements and to enhance the company’s retail network. The following table shows the company’s capital and exploration expenditures for natural resources during the five years ending December 31, 2003: millions of dollars Exploration Production Heavy oil Total 2003 57 181 769 1 007 2002 39 143 804 986 2001 49 109 588 746 2000 56 110 268 434 1999 29 138 263 430 Annual report 2003 2 5 For the natural resources segment, about 90 percent of the capital and exploration expenditures in 2003 was focused on growth opportunities. The single largest investment during the year was the company’s share of the Syncrude expansion. The remainder of 2003 investment was directed to advancing the Mackenzie gas project, drilling for conventional oil and gas in Western Canada, and East Coast development and deepwater exploration. Planned capital and exploration expenditures in natural resources are expected to total about $1 billion in 2004, with nearly 90 percent of the total focused on growth opportunities. Much of the expenditure will be directed to the expansion now underway at Syncrude. Investments are also planned for the ongoing development drilling at Cold Lake, the Mackenzie gas project, development of the Sable South Venture field and the Sable compression platform, as well as further development drilling in Western Canada. Planned expenditures for exploration and development drilling, as well as capacity additions in conventional oil and gas operations, are expected to be about $320 million. The following table shows the company’s capital expenditures in the petroleum products segment during the five years ending December 31, 2003: millions of dollars Marketing Refining and supply Other (a) Total (a) Consists primarily of real estate purchases. 2003 91 368 19 478 2002 133 399 57 589 2001 171 118 50 339 2000 121 100 11 232 1999 80 114 9 203 For the petroleum products segment, capital expenditures decreased to $478 million in 2003, compared with $589 million in 2002 (2001 – $339 million), primarily because of the completion of the project to significantly reduce sulphur content in gasoline, which began in 2001. New investments in 2003 included the products segment’s $32-million share of capital expenditures on a 95-megawatt cogeneration facility to improve energy efficiency and reduce emissions at the petroleum products and chemicals operations in Sarnia. In addition, almost $60 million was spent on other refinery projects to improve energy efficiency and increase yield. Major investments were also made to upgrade the network of Esso retail outlets during the year. Capital expenditures for the petroleum products segment in 2004 are expected to be about $450 million. Major items include investment in refining facilities to reduce the sulphur content in diesel to meet regulatory requirements and continued enhancements to the company’s retail network. The following table shows the company’s capital expenditures for its chemicals operations during the five years ending December 31, 2003: millions of dollars Chemicals 2003 41 2002 25 2001 30 2000 13 1999 20 Of the capital expenditures for chemicals in 2003, the major investment was the Sarnia cogeneration project, a joint development between the petroleum products and chemicals operations at the site. Planned capital expenditures for chemicals in 2004 will be about $20 million. Funds will be used largely to improve energy efficiency and yields. Total capital and exploration expenditures for the company in 2004, which will focus mainly on growth and productivity improvements, are expected to total about $1.5 billion and will be financed primarily from internally generated funds. During 2003, the company spent more than $310 million on projects related to reducing the environmental impact of its operations and improving safety. This included investments of more than $260 million in the company’s four refineries as part of the capital project to produce low-sulphur gasoline and diesel fuels. Reporting investments in mineral interests in oil and gas properties The accounting standards for business combinations and goodwill and other intangible assets issued by the Canadian Institute of Chartered Accountants (CICA) became effective for the company on July 1, 2001, and January 1, 2002, respectively. These Canadian standards are harmonized with specific U.S. standards in these areas. Currently, the Emerging Issues Task Force (EITF) of the Financial Accounting Standards Board (FASB) is considering the issue of whether the U.S. standards require interests held under oil, gas and mineral leases to be separately classified as intangible assets on the balance sheets of companies in the extractive industries. If such interests were deemed to be intangible assets by the EITF, mineral rights to extract oil and gas for both undeveloped and developed leaseholds would be classified separately from oil and gas properties as intangible assets on the company’s balance sheet. The EITF interpretation could potentially have an impact on the Canadian standards and the company’s financial reporting. Historically, in accordance with Canadian generally accepted accounting principles (GAAP), the company has capitalized the cost of oil and gas leasehold interests and reported these assets as part of tangible oil and gas property, plant and equipment. 2 6 Imperial Oil Limited Management’s discussion and analysis of financial condition and results of operations (continued) This interpretation of the current U.S. standards would only affect the classification of oil and gas leaseholds on the company’s balance sheet and would not affect total assets, net worth or cash flows. The company’s results of operations would not be affected since these leasehold costs would continue to be amortized in accordance with GAAP. The amount that is subject to reclassification as of December 31, 2003, was $935 million and $1,109 million as of December 31, 2002. Pension An independent actuarial valuation of the company’s registered pension plan was completed in 2003. As a result of the valuation, the company contributed $500 million to the registered pension plan. While equity markets improved in 2003 and the company’s contribution levels increased, the company plans to take a measured approach to the pace of funding, within the requirements of pension regulations. However, pension liabilities need to be assessed in light of the company’s strong credit position and prudent financial management. The company has in the past used and expects to continue to use its strong balance sheet to effectively manage pension liabilities. Future funding requirements are not expected to affect the company’s existing capital investment plans or its ability to pursue new investment opportunities. Contractual obligations To more fully explain the company’s financial position, the following table shows the company’s contractual obligations outstanding at December 31, 2003. It brings together, for easier reference, data from the consolidated balance sheet and from individual notes to the consolidated financial statements. millions of dollars Long-term debt and capital leases Imperial’s share of equity company debt Operating leases Unconditional purchase obligations (a) Firm capital commitments (b) Pension obligations (c) Asset retirement obligations (d) Other long-term agreements (e) Total Financial statement note reference note 3 note 9 note 9 note 9 note 5 note 6 note 9 Payment due by period 2005 to 2008 834 – 185 161 13 100 112 500 1 905 2009 and beyond 25 – 114 98 – 318 181 277 1 013 2004 501 52 72 90 176 138 34 260 1 323 Total amount 1 360 52 371 349 189 556 327 1 037 4 241 (a) Unconditional purchase obligations mainly pertain to pipeline throughput agreements. (b) Firm capital commitments related to capital projects, shown on an undiscounted basis, totalled approximately $189 million at the end of 2003, compared with $284 million at year-end 2002. The largest commitment outstanding at year-end 2003 was associated with the company’s share of capital projects at Syncrude ($56 million). (c) Pension obligations represent the amount by which accumulated benefit obligations (ABO) exceeded the fair value of plan assets. The ABO is the actuarial present value of benefits attributed to employee service rendered up to the end of the year and is based on current compensation levels. The ABO is less than the (projected) benefit obligation shown in note 5 to the consolidated financial statements because it does not take into account future compensation levels. It is used instead of the projected benefit obligation because it more truly reflects the actual benefit obligation at the end of the year. The payments by period include expected contributions to the company’s registered pension plan in 2004 and estimated benefit payments for unfunded plans in all years. The term ABO used here is consistent with the definition under Statement of Financial Accounting Standards No. 87 issued by the Financial Accounting Standards Board. (d) Asset retirement obligations represent the discounted present value of legal obligations associated with site restoration on the retirement of assets with determinable useful lives. (e) Other long-term agreements include primarily raw material supply and transportation services agreements. CRITICAL ACCOUNTING POLICIES The company’s financial statements have been prepared in accordance with Canadian generally accepted accounting principles (GAAP) and include estimates that reflect management’s best judgments. The company’s accounting and financial reporting fairly reflect its straightforward business model. Imperial 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 32 to 33. Oil and gas reserves Proved oil and gas reserves quantities are used as the basis of calculating unit-of-production rates for depreciation and evaluating for impairment. These reserves are the estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs and deposits under existing economic and operating conditions. The estimation of reserves is an ongoing process based on rigorous technical evaluations and extrapolations of appropriate information. While proved reserves have a reasonable certainty of recovery, they are based on estimates that are subject to some variability. The variability can result in upward or downward revisions in the previously estimated volumes of proved reserves for existing fields due to initial study or restudy of (1) already available geologic, reservoir or production data, or (2) new geologic or reservoir data obtained from wells. Revisions can also include changes associated with improved recovery projects, fiscal terms and significant changes in development strategy, oil and gas prices or production equipment/facility capacity. Over time, revisions of proved reserves for the company have generally resulted in net upward experience- based changes through effective reservoir management and the application of new technology. While revisions are an indicator of variability, they have had little impact on the unit-of-production rates of depreciation and on impairment testing because the revisions have been small compared to the large proved reserves base. Annual report 2003 2 7 Retirement benefits The company’s pension plan is managed in compliance with the requirements of governmental authorities and meets funding levels as determined by independent third-party actuaries. Pension accounting requires explicit assumptions regarding, among others, the discount rate for the benefit obligations, the expected rate of return on plan assets and the long-term rate of future compensation increases. All pension assumptions are reviewed annually by senior financial management. These assumptions are adjusted only as appropriate to reflect long-term changes in market rates and outlook. The long-term expected rate of return on plan assets of 8.25 percent used in 2003 compares to actual returns of 9.5 percent and 10 percent achieved over the last 10- and 20-year periods ending December 31, 2003. If different assumptions are used, the expense and obligations could increase or decrease as a result. The company’s potential exposure to change in assumptions is summarized in footnote (e) of note 5 to the consolidated financial statements. At Imperial, differences between actual returns on plan assets versus long-term expected returns are not recorded in the year the differences occur, but rather are amortized in pension expense as permitted by GAAP, along with other actuarial gains and losses over the expected remaining service life of employees. The company uses the fair value of the plan assets at year-end to determine the amount of the actual gain or loss that will be amortized and does not use a moving average value of plan assets. Pension expense represented about one percent of total expenses in 2003. Asset retirement obligations and other environmental liabilities Legal obligations associated with site restoration on the retirement of assets with determinable useful lives are recognized when they are incurred, which is typically at the time the assets are installed. The obligations are initially measured at fair value and discounted to present value. Over time the discounted asset retirement obligation amount will be accreted for the change in its present value, with this effect included in operating expense. As payments to settle the obligations occur on an ongoing basis and will continue over the lives of the operating assets, which can exceed 25 years, the discount rate will be adjusted only as appropriate to reflect long-term changes in market rates and outlook. In 2003, the obligations have been discounted at six percent and the accretion expense was $20 million, which was significantly less than one percent of total expenses in the year. There would be no material impact on the company’s reported financial results if a different discount rate had been used. Asset retirement obligations are not recognized for assets with an indeterminate useful life. For these and non-operating assets, the company accrues provisions for environmental liabilities when it is probable that obligations have been incurred and the amount can be reasonably estimated. Asset retirement obligations and other environmental liabilities are based on engineering estimated costs, taking into account the anticipated method and extent of remediation consistent with legal requirements, current technology and the possible use of the location. Since these estimates are specific to the locations involved, there are many individual assumptions underlying the company’s total asset retirement obligations and provision for other environmental liabilities. While these individual assumptions can be subject to change, none of them is individually significant to the company’s reported financial results. MARKET RISKS AND OTHER UNCERTAINTIES The company is exposed to a variety of financial, operating and market risks in the course of its business. Some of these risks are within the company’s control, while others are not. For those risks that can be controlled, specific risk-management strategies are employed to reduce the likelihood of loss. Other risks, such as changes in international commodity prices and currency-exchange rates, are beyond the company’s control. The company’s size, strong financial position and the complementary nature of its natural resources, petroleum products and chemicals segments help mitigate the company’s exposure to changes in these other risks. The company’s potential exposure to these types of risk is summarized in the table below. The company does not use derivative markets to speculate on the future direction of currency or commodity prices and does not sell forward any part of production from any business segment. The following table shows the estimated annual effect, under current conditions, of certain sensitivities of the company’s after-tax earnings. Earnings sensitivities (a) millions of dollars after tax Three dollars (U.S.) a barrel change in crude oil prices Sixty cents a thousand cubic feet change in natural gas prices One cent a litre change in sales margins for total petroleum products One cent (U.S.) a pound change in sales margins for polyethylene One-quarter percent decrease (increase) in short-term interest rates Eight cents decrease (increase) in the value of the Canadian dollar versus the U.S. dollar +(–) +(–) +(–) +(–) +(–) +(–) 140 40 180 8 2 340 (a) The amount quoted to illustrate the impact of each sensitivity represents a change of about 10 percent in the value of the commodity or rate in question at the end of 2003. Each sensitivity calculation shows the impact on annual earnings that results from a change in one factor, after tax and royalties and holding all other factors constant. While these sensitivities are applicable under current conditions, they may not apply proportionately to larger fluctuations. The sensitivity to changes in the Canadian dollar versus the U.S. dollar increased from 2002 by about $12 million (after tax) a year for each one-cent change. This is primarily a result of the retirement of the U.S.-dollar-denominated debt, which had previously moderated the impact of foreign-exchange rate changes on commodity prices and product margins. The sensitivity to changes in crude oil prices decreased from 2002 by about $13 million (after tax) for each one U.S.-dollar difference. An increase in the value of the Canadian dollar has lessened the impact of U.S.-dollar-denominated crude oil prices on the company’s revenues and earnings. 2 8 Imperial Oil Limited Management report Auditors’ report The accompanying consolidated financial statements and all information in this annual report are the responsibility of management. The financial statements have been prepared in accordance with Canadian generally accepted accounting principles and include certain estimates that reflect management’s best judgments. Financial information contained throughout this annual report is consistent with these financial statements. Management has established and maintains a system of internal controls that provides reasonable assurance that all transactions are accurately recorded, that the financial statements fairly report the company’s operating and financial results and that the company’s assets are safeguarded. The company’s internal audit unit reviews and evaluates the adequacy of and compliance with the company’s internal control standards. It is also the company’s policy to maintain the highest standard of ethics in all its activities. Imperial’s board of directors has approved the information contained in the financial statements. The board fulfills its responsibility regarding the financial statements mainly through its audit committee, which is composed of the nonemployee directors. The audit committee reviews the company’s annual and quarterly financial statements, accounting practices, business and financial controls, and internal audit program and its findings. It also recommends the external auditors to be appointed by the shareholders at each annual meeting, reviews their audit work plan and approves their fees. PricewaterhouseCoopers LLP, an independent firm of chartered accountants, was appointed by a vote of shareholders at the company’s last annual meeting to examine the consolidated financial statements and provide an independent professional opinion. To the shareholders of Imperial Oil Limited We have audited the consolidated balance sheets of Imperial Oil Limited as at December 31, 2003 and 2002 and the consolidated statements of earnings and cash flows for each of the three years in the period ended December 31, 2003. These financial statements are the responsibility of the company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the company as at December 31, 2003 and 2002 and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2003 in accordance with Canadian generally accepted accounting principles. Chartered Accountants Toronto, Ontario February 18, 2004 T.J. Hearn P.A. Smith February 18, 2004 Annual report 2003 Annual report 2003 2 9 Consolidated statement of earnings (a) millions of dollars For the years ended December 31 Revenues Operating revenues (b) Investment and other income Total revenues Expenses Exploration Purchases of crude oil and products Operating Selling and general Federal excise tax (b) Depreciation and depletion Financing costs (note 12) Total expenses 2003 2002 2001 2000 1999 19 094 114 19 208 55 11 580 2 025 1 269 1 254 750 (87) 16 846 16 890 152 17 042 30 10 155 1 865 1 222 1 231 705 32 15 240 17 153 100 17 253 45 10 134 1 830 1 280 1 180 718 152 15 339 17 829 222 18 051 35 10 772 1 554 1 271 1 194 726 163 15 715 12 763 90 12 853 28 7 091 1 511 1 251 1 188 736 38 11 843 Earnings before income taxes 2 362 1 802 1 914 2 336 1 010 Income taxes (note 4) 680 578 659 926 Net earnings 1 682 1 224 1 255 1 410 Per-share information (dollars) Net earnings – basic and diluted (note 10) Dividends 4.52 0.87 3.23 0.84 3.19 0.83 3.38 0.78 382 628 1.46 0.75 (a) Business segments are reported in note 1. (b) Operating revenues include federal excise tax of $1,254 million (2002 – $1,231 million; 2001 – $1,180 million). The information on pages 32 through 43 is part of these consolidated financial statements. Certain figures for prior years have been reclassified in the financial statements to conform with the current year’s presentation. The effects of new accounting standards on the consolidated statement of earnings and balance sheet are described in note 2. 3 0 Imperial Oil Limited Consolidated statement of cash flows millions of dollars inflow (outflow) For the years ended December 31 Operating activities Net earnings Depreciation and depletion (Gain)/loss on asset sales, after tax Future income taxes and other Cash flow from earnings (note 11) Accounts receivable Inventories and prepaids Income taxes payable Accounts payable and other (a) Change in operating assets and liabilities Cash from operating activities Investing activities Additions to property, plant and equipment and intangibles Proceeds from asset sales Proceeds from marketable securities Additions to marketable securities Cash from (used in) investing activities Financing activities Short-term debt – net Long-term debt issued Repayment of long-term debt Issuance of common shares under stock option plan Common shares purchased (note 10) Dividends paid Cash from (used in) financing activities Increase (decrease) in cash Cash at beginning of year Cash at end of year (b) 2003 2002 2001 2000 1999 1 682 750 (10) (68) 2 354 33 31 38 (262) (160) 2 194 (1 449) 56 – – (1 393) – 818 (818) 2 (799) (322) (1 119) (318) 766 448 1 224 705 (4) (144) 1 781 (356) 51 (225) 425 (105) 1 676 (1 552) 61 – – (1 491) (388) 500 (71) – (13) (319) (291) (106) 872 766 1 255 718 (7) 50 2 016 504 (11) (408) (97) (12) 2 004 (1 070) 46 – – (1 024) 385 – (379) – (812) (322) (1 128) (148) 1 020 872 1 410 726 (96) (175) 1 865 (358) (6) 503 85 224 2 089 (644) 274 116 (58) (312) 75 – (68) – (1 208) (331) (1 532) 245 775 1 020 628 736 (17) (324) 1 023 (124) (16) 225 362 447 1 470 (625) 88 59 (88) (566) – – (379) – – (319) (698) 206 569 775 (a) Includes contribution to registered pension plans of $511 million (2002 – $19 million; 2001 – $6 million). (b) Cash is composed of cash in bank and cash equivalents at cost. Cash equivalents are all highly liquid securities with a maturity of three months or less when purchased. The information on pages 32 through 43 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. Annual report 2003 3 1 Consolidated balance sheet millions of dollars At December 31 Assets Current assets 2003 2002 2001 2000 1999 Cash 448 Marketable securities – Accounts receivable (note 11) 1 315 Inventories of crude oil and products (note 11) 407 Materials, supplies and prepaid expenses 105 Future income tax assets (note 4) 353 2 628 Total current assets Investments and other long-term assets (note 5) Property, plant and equipment (note 1) Goodwill (note 1) Other intangible assets (note 1) Total assets (note 1) Liabilities Current liabilities 259 9 218 204 52 12 361 72 2 222 595 501 3 390 859 972 1 362 6 583 Short-term debt Accounts payable and accrued liabilities (note 13) Income taxes payable Current portion of long-term debt Total current liabilities Long-term debt (note 3) Other long-term obligations (note 6) Future income tax liabilities (note 4) Commitments and contingent liabilities (note 9) Total liabilities Shareholders’ equity Common shares at stated value (note 10) Net earnings retained and used in the business At beginning of year Net earnings for the year Share purchases (note 10) Dividends At end of year Total shareholders’ equity 766 – 1 348 433 110 323 2 980 134 8 525 204 51 11 894 72 2 114 557 – 2 743 1 466 1 207 1 262 6 678 872 – 992 478 116 227 2 685 139 7 722 204 31 10 781 460 1 791 774 – 3 025 1 029 1 098 1 306 6 458 1 020 – 1 496 421 162 377 3 476 127 7 391 232 18 11 244 75 1 866 1 182 300 3 423 1 037 1 104 1 476 7 040 775 59 1 138 451 125 285 2 833 172 7 549 260 14 10 828 – 1 731 666 – 2 397 1 352 1 172 1 580 6 501 1 859 1 939 1 941 2 039 2 209 3 277 1 682 (717) (323) 3 919 5 778 2 382 1 224 (11) (318) 3 277 5 216 2 165 1 255 (714) (324) 2 382 4 323 2 118 1 410 (1 038) (325) 2 165 4 204 1 814 628 – (324) 2 118 4 327 Total liabilities and shareholders’ equity 12 361 11 894 10 781 11 244 10 828 Approved by the directors T.J. Hearn Chairman, president and chief executive officer P.A. Smith Controller and senior vice-president, finance and administration The information on pages 32 through 43 is part of these consolidated financial statements. Certain figures for prior years have been reclassified in the financial statements to conform with the current year’s presentation. The effects of new accounting standards on the consolidated statement of earnings and balance sheet are described in note 2. 3 2 Imperial Oil Limited Summary of significant accounting policies Principles of consolidation The 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 proportionate interest in such activities, including its 25-percent interest in the Syncrude joint venture and its nine-percent interest in the Sable offshore energy project. Segment reporting The company operates its business in Canada in the following segments: Natural resources includes the exploration for and production of crude oil and natural gas. Petroleum products comprises the refining of crude oil into petroleum products and the distribution and marketing of these products. Chemicals includes the manufacturing and marketing of various hydrocarbon-based chemicals and chemical products. Corporate and other includes assets and liabilities that do not specifically relate to business segments – primarily cash, marketable securities and long-term debt. Net earnings in this category primarily include debt-related charges and interest income. Segment accounting policies are the same as those described in this summary of significant accounting policies. Natural resources, petroleum products and chemicals expenses include amounts allocated from the “corporate and other” segment. The allocation is based on a combination of fee for service, proportional segment expenses and a three-year average of capital expenditures. Transfers of assets between segments are recorded at book amounts. Items included in capital employed that are not identifiable by segment are allocated according to their nature. Accounts receivable Accounts receivable arise mainly from customer purchases of the company’s products. Interest is accrued on overdue accounts (generally those over 30 days) and is reported in “investment and other income” in the consolidated statement of earnings. Interest accrual will be suspended if collection becomes doubtful. An allowance for doubtful accounts is established based upon an assessment of the collectibility of individual larger account balances and upon historical experience, economic and judgmental factors collectively for groups of smaller homogeneous accounts. Accounts are written off when judged to be uncollectable. Inventories Inventories are recorded at the lower of cost or net realizable value. The cost of crude oil and products is determined primarily using the last-in, first-out (LIFO) method. LIFO was selected over the alternative first-in, first-out and average cost methods because it provides a better matching of current costs with the revenues generated in the period. Inventory costs include expenditures and other charges, including depreciation, directly or indirectly incurred in bringing the inventory to its existing condition and final storage prior to delivery to a customer. Selling and general expenses are reported as period costs and excluded from inventory costs. Investments The principal investments in companies other than subsidiaries are accounted for using the equity method. They are recorded at the original cost of the investment plus 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 earnings. Other investments are recorded at cost. Dividends from these other investments are included in “investment and other income.” These investments represent interests in non-publicly traded pipeline companies that facilitate the sale and purchase of crude oil and natural gas in the conduct of 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 equipment Property, plant and equipment are recorded at cost. Investment tax credits and other similar grants are treated as a reduction of the capitalized cost of the asset to which they apply. If the well is successful, the costs remain capitalized; otherwise they are expensed. Capitalized exploration costs are re-evaluated annually. All other exploration costs are expensed as incurred. Development costs, including the cost of natural gas and natural gas liquids used as injectants in enhanced (tertiary) oil-recovery projects, are capitalized. Imperial selected the successful-efforts method over the alternative full-cost method of accounting because it provides a more timely accounting of the success or failure of exploration and production activities. Maintenance and repair costs, including planned major maintenance, are expensed as incurred. Improvements that increase or prolong the service life or capacity of an asset are capitalized. Production costs are expensed as incurred. Production involves lifting the oil and gas to the surface and gathering, treating, field processing and field storage of the oil and gas. The production function normally terminates at the outlet valve on the lease or field production storage tank. Production costs are those incurred to operate and maintain the company’s wells and related equipment and facilities. They become part of the cost of oil and gas produced. Depreciation and depletion for assets associated with producing properties begin at the time when production commences on a regular basis. Depreciation for other assets begins when the asset is in place and ready for its intended use. Assets under construction are not depreciated or depleted. Depreciation and depletion are calculated using the unit-of-production method for producing properties, including capitalized exploratory drilling and development costs. Depreciation of other plant and equipment is calculated using the straight-line method, based on the estimated service life of the asset. In general, refineries are depreciated over 25 years; other major assets, including chemical plants and service stations, are depreciated over 20 years. Proved oil and gas properties held and used by the company are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. The company follows the successful-efforts method of accounting for its exploration and development activities. Under this method, costs of exploration acreage are capitalized and amortized over the period of exploration or until a discovery is made. Costs of exploration wells are capitalized until their success can be determined. The company estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. Cash flows used in impairment evaluations are developed using annually updated corporate plan investment evaluation assumptions for crude oil commodity prices and foreign-currency exchange rates. Annual report 2003 3 3 Annual volumes are based on individual field production profiles, which are also updated annually. Prices for natural gas and other products sold under contract are based on corporate plan assumptions developed annually by major contracts and also for investment evaluation purposes. Gains or losses on assets sold are included in “investment and other income” in the consolidated statement of earnings. Goodwill and other intangible assets Goodwill and intangible assets with indefinite lives are not subject to amortization. These assets are tested for impairment annually or more frequently if events or circumstances indicate the assets might be impaired. Impairment losses are recognized in current period earnings. The evaluation for impairment of goodwill is based on a comparison of the carrying values of goodwill and associated operating assets with the estimated present value of net cash flows from those operating assets. Intangible assets with determinable useful lives are amortized over the estimated service lives of the assets. Computer software development costs are amortized over a maximum of 15 years and customer lists are amortized over a maximum of 10 years. The amortization is included in “depreciation and depletion” in the consolidated statement of earnings. Asset retirement obligations and other environmental liabilities 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. A corresponding amount equal to that of the initial obligation is added to the capitalized costs of the related asset. Over time the discounted asset retirement obligation amount will be accreted for the change in its present value, and the initial capitalized costs will be depreciated over the useful lives of the related assets. No asset retirement obligations are set up for assets with an indeterminate useful life. Provision for environmental liabilities of these and non-operating assets is made when it is probable that obligations have been incurred and the amount can be reasonably estimated. The fair values of asset retirement obligations and other provisions for environmental liabilities are determined based on engineering estimated costs, taking into account the anticipated method and extent of remediation consistent with legal requirements, current technology and the possible use of the location. Foreign-currency translation Monetary assets and liabilities in foreign currencies have been translated at the rates of exchange prevailing on December 31. Any exchange gains or losses are recognized in earnings. Financial instruments Financial instruments are initially recorded at historical cost. If subsequent circumstances indicate that a decline in the fair value of a financial asset is other than temporary, the financial asset is written down to its fair value. Unless otherwise indicated, the fair values of financial instruments approximate their recorded amounts. The fair values of cash, marketable securities, accounts receivable and current liabilities approximate recorded amounts because of the short period to receipt or payment of cash. The fair value of the company’s long-term debt is estimated based on quoted market prices for the same or similar issues or on the current rates offered to the company for debt of the same duration to maturity. The fair values of other financial instruments held by the company are estimated primarily by discounting future cash flows, using current rates for similar financial instruments under similar credit risk and maturity conditions. The company does not use financing structures for the purpose of altering accounting outcomes or removing debt from the balance sheet. The company makes limited use of derivatives. Derivative instruments are not held for trading purposes. Revenues Revenues associated with sales of crude oil, natural gas, petroleum and chemical products and other items are recorded when the products are delivered. Delivery occurs when the customer has taken title and has assumed the risks and rewards of ownership, prices are fixed or determinable and collectibility is reasonably assured. The company does not enter into ongoing arrangements whereby it is required to repurchase its products, nor does the company provide the customer with a right of return. Revenues include amounts billed to customers for shipping and handling. Shipping and handling costs incurred up to the point of final storage prior to delivery to a customer are included in “purchases of crude oil and products” in the consolidated statement of earnings. Delivery costs from final storage to customer are recorded as a marketing expense in selling and general expenses. Stock-based compensation The company accounts for its stock-based compensation programs, except for the incentive stock options granted in April 2002, by using the fair-value-based method. Under this method, compensation expense related to the units of these programs is measured by the fair value of the unit and is recorded in the consolidated statement of earnings over the vesting period. As permitted by the new Canadian Institute of Chartered Accountants (CICA) standard on accounting for stock-based compensation, the company continues to apply the intrinsic-value- based method of accounting for the incentive stock options granted in April 2002. Under this method, compensation expense is not recognized on the issuance of stock options as long as the exercise price is equal to the market value at the date of grant. Consumer taxes Taxes levied on the consumer and collected by the company are excluded from the consolidated statement of earnings. These are primarily provincial taxes on motor fuels and the federal goods and services tax. Interest costs Interest costs are expensed as incurred and included in “financing costs” in the consolidated statement of earnings. Accounting principles The consolidated financial statements have been prepared in accordance with generally accepted accounting principles (GAAP) in Canada. Form 10-K, filed with the United States Securities and Exchange Commission, includes a description of the differences between GAAP in Canada and in the United States as they apply to the company. Effective January 1, 2003, the company has adopted the new CICA standards on accounting for asset retirement obligations. The impact of adopting this new standard is described in note 2 to the consolidated financial statements on page 35. The company has early adopted the additional disclosure requirements by the CICA on employee future benefits, as shown in note 5 on page 37. The company has also early adopted the new CICA standard on stock-based compensation with no impact on its accounting or reporting. 3 4 Imperial Oil Limited Notes to consolidated financial statements 1. Business segments millions of dollars Revenues External sales (c) Intersegment sales Investment and other income Total revenues Expenses Exploration Purchases of crude oil and products Operating Selling and general (d) Federal excise tax Depreciation and depletion (e) (f) Financing costs (note 12) Total expenses Earnings before income taxes Income taxes (note 4) Current Future Total income tax expense Net earnings Cash flow from earnings Capital and exploration expenditures (g) Property, plant and equipment Cost Accumulated depreciation and depletion Net property, plant and equipment (h) Total assets (f) Total capital employed millions of dollars Revenues External sales (c) Intersegment sales Investment and other income Total revenues Expenses Exploration Purchases of crude oil and products Operating Selling and general (d) Federal excise tax Depreciation and depletion (e) (f) Financing costs (note 12) Total expenses Earnings before income taxes Income taxes (note 4) Current Future Total income tax expense Net earnings Cash flow from earnings Capital and exploration expenditures (g) Property, plant and equipment Cost Accumulated depreciation and depletion Net property, plant and equipment (h) Total assets (f) Total capital employed Natural resources (a) 2002 2003 2001 Petroleum products 2002 2001 2003 3 390 2 224 34 5 648 55 2 357 1 093 28 – 517 1 4 051 1 597 535 (77) 458 1 139 1 576 1 007 2 573 2 217 104 4 894 30 1 814 990 21 – 479 1 3 335 1 559 517 (14) 503 1 056 1 526 986 3 144 2 166 11 5 321 45 2 444 952 30 – 457 2 3 930 1 391 556 (122) 434 957 1 287 746 12 610 6 813 5 797 6 434 3 784 11 672 6 303 5 369 6 014 3 325 10 785 5 871 4 914 5 385 2 580 14 710 1 294 54 16 058 – 12 066 810 1 123 1 254 211 2 15 466 592 66 119 185 407 719 478 6 069 2 856 3 213 5 341 2 784 13 362 1 038 34 14 434 13 079 1 300 26 14 405 – 10 974 761 1 076 1 231 203 1 14 246 188 172 (111) 61 127 216 589 5 827 2 867 2 960 5 048 2 484 – 10 505 755 1 134 1 180 238 2 13 814 591 125 113 238 353 700 339 5 462 2 842 2 620 4 348 2 148 Corporate and other 2002 2001 2003 – – 26 26 – – – – – – (90) (90) 116 (4) 21 17 99 (7) – – – – 448 448 – – 14 14 – – – 10 – – 30 40 (26) (11) (4) (15) (11) (24) – – – – 766 816 – – 63 63 – – – 19 – – 148 167 (104) (13) (13) (26) (78) (20) – – – – 873 918 2003 994 238 – 1 232 – 911 124 118 – 22 – 1 175 57 13 7 20 37 66 41 609 401 208 446 246 Chemicals 2002 2001 955 209 – 1 164 – 830 115 115 – 23 – 1 083 81 40 (11) 29 52 63 25 579 383 196 418 178 930 245 – 1 175 – 895 124 97 – 23 – 1 139 36 11 2 13 23 49 30 554 366 188 373 195 Consolidated (b) 2002 2001 2003 19 094 – 114 19 208 55 11 580 2 025 1 269 1 254 750 (87) 16 846 2 362 610 70 680 1 682 2 354 1 526 19 288 10 070 9 218 12 361 7 262 16 890 – 152 17 042 30 10 155 1 865 1 222 1 231 705 32 15 240 1 802 17 153 – 100 17 253 45 10 134 1 830 1 280 1 180 718 152 15 339 1 914 718 (140) 578 1 224 1 781 1 600 679 (20) 659 1 255 2 016 1 115 18 078 9 553 8 525 11 894 6 803 16 801 9 079 7 722 10 781 5 841 Annual report 2003 3 5 (a) A significant portion of activities in the natural resources segment is conducted jointly with other companies. The segment includes the company’s proportionate share of joint- venture activities, as follows: millions of dollars Total revenues Total expenses Net earnings, after income taxes Total current assets Long-term assets Total current liabilities Other long-term obligations Cash flow from earnings Cash flow from operating activities Cash from (used in) investing activities 2003 2 494 1 577 664 302 3 553 913 302 868 883 (754) 2002 2 357 1 520 557 321 3 038 669 268 767 615 (601) 2001 2 689 1 733 637 232 2 750 919 262 828 850 (301) (b) Information is presented as though each segment were a separate business activity. Intersegment sales are made essentially at prevailing market prices. Consolidated amounts exclude intersegment transactions, as follows: millions of dollars Purchases of crude oil and products Operating expense Total intersegment sales Intersegment receivables and payables (c) Includes export sales to the United States, as follows: millions of dollars Natural resources Petroleum products Chemicals Total export sales 2003 3 754 2 3 756 308 2003 1 304 792 567 2 663 2002 3 463 1 3 464 352 2002 942 723 520 2 185 2001 3 710 1 3 711 198 2001 1 018 770 503 2 291 (d) Consolidated selling and general expenses include delivery costs from final storage to customers of $285 million (2002 – $216 million; 2001 – $244 million). (e) Goodwill was not amortized in 2003 and 2002 (amortization expense in 2001 – $28 million). All goodwill has been assigned to the petroleum products segment. There have been no goodwill acquisitions, impairment losses or write-offs due to sales in the past three years. (f) Total assets include amortized intangible assets, consisting primarily of acquired customer lists and capitalized computer-software development costs, as follows: millions of dollars Cost Accumulated amortization Net intangible assets 2003 87 35 52 2002 81 30 51 Customer lists acquired in 2003 were $1 million (2002 – $5 million), those disposed of or retired were $1 million (2002 – $1 million) and no gain or loss was recognized. Capitalized computer-software development costs in 2003 were $6 million (2002 – $20 million). The estimated annual amortization expense for intangible assets in each of the next five years is $8 million. (g) Capital and exploration expenditures of the petroleum products segment include non-cash capital leases of $22 million in 2003 (2002 – $18 million). (h) Includes property, plant and equipment under construction of $1,426 million (2002 – $1,275 million). 2. Reporting changes Effective January 1, 2003, the company implemented reporting changes to reflect the new accounting standard of the Canadian Institute of Chartered Accountants (CICA) dealing with accounting for asset retirement obligations. The new CICA standard changes the method of accruing for certain site-restoration costs. Under the new standard, the fair values of asset retirement obligations are recorded as liabilities on a discounted basis when they are incurred, which is typically at the time the related assets are installed. Amounts recorded for the related assets are increased by the amount of these obligations. Over time the liabilities will be accreted for the change in their present value, and the initial capitalized costs will be depreciated over the useful lives of the related assets. There are no asset retirement liabilities set up for those assets that have an indeterminate useful life. 3 6 Imperial Oil Limited Notes to consolidated financial statements (continued) Reporting changes (continued) Estimated cash flows have been discounted at six percent. Implementation of the new standard has reduced environmental liabilities by $28 million to $462 million as of December 31, 2003. The total undiscounted amount of the estimated cash flows required to settle the obligations is $895 million. Payments to settle the obligations occur on an ongoing basis and will continue over the lives of the operating assets, which can exceed 25 years. This change in accounting standard has no impact on the cash flow profile of the company. The new standard has been applied retroactively, and the financial statements of prior periods have been restated. The impact of adopting the new standard of accounting for asset retirement obligations on the consolidated balance sheet and statement of earnings is: Changes in consolidated balance sheet millions of dollars – increase/(decrease) Property, plant and equipment Total assets Other long-term obligations Future income tax liabilities Retained earnings Total liabilities and shareholders’ equity Changes in consolidated statement of earnings millions of dollars – increase/(decrease) Operating expense Depreciation and depletion expense Total expenses Income taxes Net earnings Earnings per share – basic and diluted (dollars) The change in asset retirement obligations liability is as follows: millions of dollars Asset retirement obligations liability at January 1 Additions Accretion Settlements Asset retirement obligations liability at December 31 3. Long-term debt issued 1989 2002 2003 maturity date September 1, 2004 (2002 – $600 million (U.S.)) (a) May 7, 2004 (b) $250 million due May 26, 2005 and $250 million due August 26, 2005 (a) January 19, 2006 (a) 2003 Long-term debt (at period-end exchange rates) (c) Capital leases (d) Total long-term debt (e) 2003 24 24 (28) 18 34 24 2003 (48) 2 (46) 16 30 0.08 2003 341 – 20 (34) 327 2002 26 26 20 2 4 26 2002 (23) 2 (21) 7 14 0.04 2002 334 8 20 (21) 341 2001 (25) 2 (23) 7 16 0.04 interest rate Variable Variable Variable Variable 2002 2003 millions of dollars 946 500 – – 500 318 818 41 859 – – 1 446 20 1 466 (a) During the first half of 2003, the company redeemed the $600-million (U.S.) variable-rate debt for $818 million (Cdn) and replaced it with long-term variable-rate loans of $818 million (Cdn) from Exxon Overseas Corporation at interest equivalent to Canadian market rates. The average effective interest rate for the loans was 3.1 percent for 2003. (b) Principal payments on medium-term notes of $500 million, which have been reclassified to current portion of long-term debt in the balance sheet, are due in 2004. These notes are extendable up to May 7, 2007, at note holders’ discretion. (c) The estimated fair value of the long-term debt at December 31, 2003, was $818 million (2002 – $1,446 million). (d) These obligations primarily relate to the capital lease for marine services, which are to be provided by the lessor commencing in 2004 for a period of 10 years, extendable for an additional five years. The obligations recorded to date represent the costs incurred by the lessor for the construction of the related marine assets. (e) Principal payments on long-term loans of $500 million are due in 2005 and $318 million are due in 2006. Principal payments on capital leases of approximately $4 million a year are due in each of the next five years. Annual report 2003 3 7 4. Income taxes millions of dollars Current income tax expense Future income tax expense (a) Total income tax expense (b) Statutory corporate tax rate (percent) Increase/(decrease) resulting from: Non-deductible royalty payments to governments Resource allowance in lieu of royalty deduction Manufacturing and processing credit Non-deductible depreciation and amortization Enacted tax rate change Other Effective income tax rate 2003 610 70 680 38.5 5.0 (7.5) 0.2 – (3.1) (4.3) 28.8 2002 718 (140) 578 42.0 5.4 (11.8) (0.3) – (0.9) (2.3) 32.1 2001 679 (20) 659 42.7 7.9 (11.4) (1.3) 0.6 (2.1) (2.0) 34.4 Future income taxes are based on differences between the accounting and tax values of assets and liabilities. These differences in value are remeasured at each period-end using the tax rates and tax laws expected to apply when those differences are realized or settled in the future. Components of future income tax liabilities and assets as at December 31 were: millions of dollars Depreciation and amortization Successful drilling and land acquisitions Pension and benefits Site restoration Net tax loss carryforwards (c) Other Total future income tax liabilities LIFO inventory valuation Other Total future income tax assets Net future income tax liabilities 2003 1 233 495 (137) (167) (57) (5) 1 362 (268) (85) (353) 1 009 2002 1 098 660 (229) (186) (37) (44) 1 262 (271) (52) (323) 939 (a) The future income tax expense for the year is the difference in net future income tax liabilities at the beginning and end of the year. (b) Net cash outflow from income taxes, plus investment credits earned, were $573 million in 2003 (2002 – $935 million; 2001 – $1,086 million). (c) Tax losses can be carried forward indefinitely. The operations of the company are complex, and related tax interpretations, regulations and legislation are continually changing. As a result, there are usually some tax matters in question. The company believes the provision made for income taxes is adequate. 5. Employee retirement benefits Retirement benefits, which cover almost all retired employees and their surviving spouses, include pension-income and certain health- care and life-insurance benefits. They are met through funded registered retirement plans and through unfunded supplementary benefits that are paid directly to recipients. Funding of registered retirement plans complies with federal and provincial pension regulations, and the company makes contributions to the plans based upon an independent actuarial valuation. Pension-income benefits consist mainly of company-paid defined benefit plans that are based on years of service and final average earnings. The company shares in the cost of health-care and life-insurance benefits. The company’s benefit obligations are based on the projected-benefit method of valuation, which includes employee service to date and present compensation levels as well as a projection of salaries and service to retirement. The expense and obligations for both funded and unfunded benefits are determined in accordance with generally accepted Canadian accounting principles and actuarial procedures. The process for determining retirement-income expense and related obligations includes making certain long-term assumptions regarding the discount rate, rate of return on plan assets and rate of compensation increases. The total obligation for employee retirement benefits exceeded the fair value of plan assets at December 31, 2003, by $1,357 million (2002 – $1,780 million), $975 million (2002 – $1,426 million) of which was related to pension benefits and $382 million (2002 – $354 million) was related to other post-retirement benefits. The obligation and pension expense can vary significantly with changes in the assumptions used to estimate the obligation and the expected return on plan assets. 3 8 Imperial Oil Limited Notes to consolidated financial statements (continued) Employee retirement benefits (continued) Details of the employee retirement benefits plans are as follows: millions of dollars Components of net benefit expense Current service cost Interest cost Expected return on plan assets Amortization of prior service cost Recognized actuarial loss/(gain) Net benefit expense (a) (e) Change in benefit obligation Benefit obligation at January 1 Current service cost Interest cost Amendments Actuarial loss/(gain) Benefits paid Benefit obligation at December 31 (b) (e) Change in plan assets Fair value of plan assets at January 1 Actual return on plan assets Company contributions (b) Payments directly to participants Benefits paid Fair value of plan assets at December 31 (b) Excess/(deficiency) of plan assets over benefit obligation Unrecognized net actuarial (gain)/loss (c) Unrecognized prior service cost (c) Total net liability Less: Prepaid benefit cost (d) Liability recognized (note 6) The benefit obligation at year-end includes funded and unfunded plans, as follows: Funded plans Unfunded plans Benefit obligation at December 31 2001 57 215 (257) 23 – 38 2003 71 219 (179) 25 69 205 3 530 71 219 – 171 (230) 3 761 2 104 377 511 24 (230) 2 786 (975) 829 89 (57) 162 (219) 3 464 297 3 761 Pension benefits 2002 64 222 (191) 25 34 154 3 248 64 222 27 196 (227) 3 530 2 390 (107) 19 29 (227) 2 104 (1 426) 924 114 (388) – (388) 3 230 300 3 530 Other post-retirement benefits 2002 2003 2001 4 21 – – – 25 5 22 – – 3 30 354 5 22 – 19 (18) 382 (382) 52 – (330) – (330) – 382 382 4 21 – – 1 26 323 4 21 – 25 (19) 354 (354) 36 – (318) – (318) – 354 354 Assumptions The discount rate used for year-end employee retirement liabilities reflects the rate at which employee retirement liabilities could be effectively settled and is based on the year-end rate of interest on a portfolio of high-quality bonds. Assumptions used to determine benefit obligations at December 31 (percent) Discount rate Long-term rate of compensation increase Assumptions used to determine net benefit expense for years ended December 31 (percent) Discount rate Long-term rate of compensation increase Long-term rate of return on plan assets 6.25 3.50 6.25 3.50 8.25 6.25 3.50 6.75 3.50 8.25 7.00 3.50 10.00 6.25 3.50 6.25 3.50 – 6.25 3.50 6.75 3.50 – 7.00 3.50 – Annual report 2003 3 9 Plan assets Imperial’s pension plan asset allocation at December 31, 2002 and 2003, and target allocation for 2004, are as follows: Asset category (percent) Equities Fixed income Other Total Target allocation 2004 50 – 75 25 – 50 0 – 10 Percentage of plan assets at December 31 2003 62 38 – 100 2002 60 40 – 100 The company establishes the long-term expected rate of return by developing a forward-looking long-term return assumption for each asset class, taking into account factors such as the expected real return for the specific asset class and inflation. A single, long-term rate of return is then calculated as the weighted average of the target asset allocation and the long-term return assumption for each asset class. The 2003 long-term expected rate of return of 8.25 percent used in the calculations of pension expense compares to an actual rate of return over the past decade of 9.5 percent. The company’s investment strategy for benefit plan assets reflects a long-term view, a careful assessment of the risks inherent in various asset classes and broad diversification to reduce the risk of the total portfolio. The company primarily invests in funds that follow an index-based strategy to achieve its objectives of diversifying risk while minimizing costs. The fund holds Imperial Oil Limited common shares only to the extent necessary to replicate the relevant equity index. Asset-liability studies, or simulations of the interaction of cash flows associated with both assets and liabilities, are periodically used to establish the preferred target asset allocation. The target asset allocation for equity securities reflects the long-term nature of the liability. The balance of the fund is targeted to debt securities. (a) Additional expenses include contributions to defined contribution plans, primarily the employee savings plan, of $31 million in 2003 (2002 – $30 million; 2001 – $23 million). (b) The most recent independent actuarial valuation was as at June 30, 2003. The measurement date used to determine the plan assets and the benefit obligations was December 31, 2003. (c) Unrecorded assets/(liabilities) are amortized over the average remaining service life of employees, which for 2004 and subsequent years is 13 years (2003 – 13.5 years; 2002 – 13.5 years). (d) Prepaid benefit costs are included in investments and other long-term assets on the consolidated balance sheet. (e) A one-percent change in the assumptions at which retirement liabilities could be effectively settled is as follows: millions of dollars Rate of return on plan assets: Effect on net benefits expenses Discount rate: Effect on net benefits expenses Effect on benefits obligations Rate of compensation increases: Effect on net benefits expenses Effect on benefits obligations One-percent increase One-percent decrease (20) (35) (440) 25 130 20 40 540 (25) (115) For measurement purposes, a five-percent health-care cost trend rate was assumed for 2003 and thereafter. A one-percent change in the assumed health-care cost trend rate would have the following effects: millions of dollars Effect on service and interest cost components Effect on other post-retirement benefit obligation 6. Other long-term obligations millions of dollars Employee retirement benefits (note 5) (a) Asset retirement obligations and other environmental liabilities (b) Other obligations Total other long-term obligations One-percent increase 3 35 One-percent decrease (2) (30) 2003 505 393 74 972 2002 671 454 82 1 207 (a) Total recorded employee retirement benefits obligations also include $44 million in current liabilities (2002 – $35 million). (b) Total asset retirement obligations and other environmental liabilities also include $69 million in current liabilities (2002 – $71 million). 4 0 Imperial Oil Limited Notes to consolidated financial statements (continued) 7. 8. Derivative financial instruments No significant energy derivatives, foreign-exchange forward contracts or currency and interest-rate swaps were transacted in the past three years. The company maintains a system of controls that includes a policy covering the authorization, reporting and monitoring of derivative activity. Incentive compensation programs Incentive compensation programs are designed to retain selected employees, reward them for high performance and promote individual contribution to sustained improvement in the company’s future business performance and shareholder value. Incentive share units, deferred share units, earnings bonus units and restricted stock units Incentive share units have value if the market price of the company’s common shares when the unit is exercised exceeds the market value when the unit was issued. The issue price of incentive share units is the closing price of the company’s shares on the Toronto Stock Exchange on the grant date. Up to 50 percent of the units may be exercised after one year from issuance; an additional 25 percent may be exercised after two years; and the remaining 25 percent may be exercised after three years. Incentive share units are eligible for exercise up to 10 years from issuance. The units may expire earlier if employment is terminated other than by retirement, death or disability. The deferred share unit plan is made available to selected executives and nonemployee directors. The selected executives can elect to receive all or part of their performance bonus compensation in units and the nonemployee directors can elect to receive all or part of their directors’ fees in units. The number of units granted to executives is determined by dividing the amount of the bonus elected to be received as deferred share units by the average of the closing prices of the company’s shares on the Toronto Stock Exchange for the five consecutive trading days immediately prior to the date that the bonus would have been paid. The number of units granted to a nonemployee director is determined at the end of each calendar quarter by dividing the amount of directors’ fees for the calendar quarter that the nonemployee director elected to receive as deferred share units by the average closing price of the company’s shares for the five consecutive trading days immediately prior to the last day of the calendar quarter. Additional units are granted based on the cash dividend payable on the company’s shares divided by the average closing price immediately prior to the payment date for that dividend and multiplying the resulting number by the number of deferred share units held by the recipient. Deferred share units cannot be exercised until after termination of employment with the company or resignation as a director and must be exercised no later than December 31 of the year following termination or resignation. On the exercise date, the cash value to be received for the units is determined based on the average closing price of the company’s shares for the five consecutive trading days immediately prior to the date of exercise. The earnings bonus unit plan is available to selected executives. Each earnings bonus unit entitles the recipient to receive an amount equal to the company’s cumulative net earnings per common share as announced each quarter beginning after the grant. Payout occurs on the fifth anniversary of the grant or when the maximum settlement value per unit is reached, if earlier. Earnings bonus units may expire if employment is terminated other than by death or disability. Under the restricted stock unit plan, each unit entitles the recipient to the conditional right to receive from the company, upon exercise, an amount equal to the closing price of the company’s common shares on the Toronto Stock Exchange on the exercise dates. Fifty percent of the units are exercised three years following the grant date, and the remainder are exercised seven years following the grant date. All units require settlement by cash payments with one exception. The restricted stock unit plan was amended for units granted in 2003 and future years by providing that the recipient may receive one common share of the company per unit or elect to receive the cash payment for the units to be exercised on the seventh anniversary of the grant date. For deferred share units, a charge is made to expense in the year of grant equal to the cash performance bonus payment and directors’ fees foregone. The company records expense for incentive share, deferred share and restricted stock units based on changes in the price of common shares in the year. Expense for earnings bonus units is recorded based on the cumulative net earnings per outstanding common share from issue date, up to the maximum settlement value for the units. Incentive stock options In April 2002, incentive stock options were granted for the purchase of the company’s common shares at an exercise price of $46.50 per share. Up to 50 percent of the options may be exercised on or after January 1, 2003, a further 25 percent may be exercised on or after January 1, 2004, and the remaining 25 percent may be exercised on or after January 1, 2005. Any unexercised options expire after April 29, 2012. The company did not issue incentive stock options in 2003 and has no plans to issue incentive stock options in the future. The company does not recognize compensation expense on the issuance of stock options because the exercise price is equal to the market value at the date of grant. If the fair-value-based method of accounting had been adopted, net income and earnings per share (on both a basic and diluted basis) for 2003 would have been reduced by $5 million or $0.01 per share (2002 – $16 million or $0.04 per Annual report 2003 4 1 share). The average fair value of each option granted during 2002 was $12.70. The fair value was estimated at the grant date using an option-pricing model with the following weighted average assumptions: risk-free interest rate of 5.7 percent, expected life of five years, volatility of 25 percent and a dividend yield of 1.9 percent. The company has purchased shares on the market to fully offset the dilutive effects from the exercise of stock options. The practice is expected to continue. A summary of the incentive compensation is as follows: Incentive share units 2003 2002 2001 Deferred share units 2003 2002 2001 Earnings bonus units 2003 2002 2001 Incentive stock options 2003 2002 Restricted stock units 2003 2002 Granted in period To number of employees To number of nonemployees Number of units outstanding at December 31 Expensed in period (millions of dollars) Obligations outstanding at December 31 (millions of dollars) – 3 744 5 6 2 84 75 21 – 765 613 690 – – – 6 7 5 – – – – – 5 5 6 889 330 8 012 250 8 823 125 43 911 85 523 87 897 3 234 250 2 169 040 1 132 540 3 136 150 3 196 700 1 660 555 791 890 109 39 51 1 – 1 3 3 – – – 11 – 216 142 129 3 4 4 3 3 – – – 11 – Number of units – 7 000 2 752 700 8 253 7 479 15 222 2 221 580 1 036 500 1 132 540 – 3 210 200 872 085 791 890 9. Commitments and contingent liabilities At December 31, 2003, the company had commitments for noncancellable operating leases and other long-term agreements that require the following minimum future payments: millions of dollars Operating leases (a) Unconditional purchase obligations (b) Firm capital commitments (c) Other long-term agreements (d) 2004 72 90 176 260 2005 59 47 8 235 2006 49 38 5 151 2007 43 38 – 57 2008 34 38 – 57 After 2008 114 98 – 277 (a) Total rental expense incurred for operating leases in 2003 was $124 million (2002 – $124 million; 2001 – $122 million). Operating lease commitments related to joint-venture activities are not material. (b) Unconditional purchase obligations are those long-term commitments that are noncancellable or cancellable only under certain conditions. These mainly pertain to pipeline throughput agreements. Total payments under unconditional purchase obligations were $114 million in 2003 (2002 – $115 million; 2001 – $179 million). (c) Firm capital commitments related to capital projects, shown on an undiscounted basis, totalled approximately $189 million at the end of 2003 (2002 – $284 million). The largest commitments outstanding at year-end 2003 were associated with the company’s share of capital projects at Syncrude of $56 million and offshore East Coast of $50 million. (d) Other long-term agreements include primarily raw material supply and transportation services agreements. Total payments under other long-term agreements were $332 million in 2003 (2002 – $288 million; 2001 – $264 million). Payments under other long-term agreements related to joint-venture activities are approximately $44 million per year. Other commitments arising in the normal course of business for operating and capital needs do not materially affect the company’s consolidated financial position. The company was contingently liable at December 31, 2003, for a maximum of $163 million relating to guarantees for purchasing operating equipment and other assets from its rural marketing agents upon expiry of the agency agreement or the death or resignation of the agent. The company expects that the fair value of the operating equipment and other assets so purchased would cover the maximum potential amount of future payment under the guarantees. The company provides in its financial statements for asset retirement obligations and other environmental liabilities (see accounting policies on page 33). Provision is not made with respect to those manufacturing, distribution and marketing facilities with indeterminate useful lives for which estimates of these future costs cannot be reasonably determined. These are primarily currently operated sites. These costs are not expected to have a material effect on the company’s current consolidated financial position. 4 2 Imperial Oil Limited Notes to consolidated financial statements (continued) Commitments and contingent liabilities (continued) Various lawsuits are pending against Imperial Oil Limited and its subsidiaries. The actual liability with respect to these lawsuits is not determinable, but management believes, based on the opinion of counsel, that any liability will not materially affect the company’s consolidated financial position. 10. Common shares The number of authorized common shares of the company as at December 31, 2003 was 450,000,000, unchanged from December 31, 2002, and December 31, 2001. From 1995 to 2002, the company purchased shares under eight 12-month normal course share purchase programs, as well as an auction tender. On June 23, 2003, another 12-month normal course share purchase program was implemented with an allowable purchase of 18.6 million shares (five percent of the total at June 19, 2003), less any shares purchased by the employee savings plan and company pension fund. The results of these activities are shown below. Year 1995 to 2001 2002 2003 Cumulative purchases to date Purchased shares 202 365 149 296 052 16 259 538 218 920 739 Millions of dollars 5 156 13 799 5 968 Exxon Mobil Corporation’s participation in the above maintained its ownership interest in Imperial at 69.6 percent. The excess of the purchase cost over the stated value of shares purchased has been recorded as a distribution of retained earnings. The company’s common share activity is summarized below: Balance as at December 31, 2001 Issued for cash under stock option plan Purchases Balance as at December 31, 2002 Issued for cash under stock option plan Purchases Balance as at December 31, 2003 The following table provides the calculation of basic and diluted earnings per share: Net earnings (millions of dollars) Average number of common shares outstanding, weighted monthly (thousands) Plus: average number of shares issued on assumed exercise of stock options (thousands) Weighted average number of diluted common shares (thousands) Earnings per share – basic (dollars) Earnings per share – diluted (dollars) 11. Miscellaneous financial information Thousands of shares 379 159 – (296) 378 863 49 (16 260) 362 652 At stated value, millions of dollars 1 941 – (2) 1 939 2 (82) 1 859 2003 1 682 372 011 143 372 154 4.52 4.52 2002 1 224 378 875 1 378 876 3.23 3.23 2001 1 255 393 121 – 393 121 3.19 3.19 In 2003, net earnings included an after-tax gain of $9 million (2002 – $2 million loss; 2001 – $18 million gain) attributable to the effect of changes in last-in, first-out (LIFO) inventories. The replacement cost of inventories was estimated to exceed their LIFO carrying values at December 31, 2003, by $797 million (2002 – $941 million). Inventories of crude oil and products at year-end consisted of the following: millions of dollars Crude oil Petroleum products Chemical products Natural gas and other Total inventories of crude oil and products 2003 161 175 57 14 407 2002 148 198 70 17 433 Annual report 2003 4 3 Research and development costs in 2003 were $63 million (2002 – $64 million; 2001 – $71 million) before investment tax credits earned on these expenditures of $10 million (2002 – $10 million; 2001 – $6 million). The net costs are included in expenses due to the uncertainty of future benefits. Cash flow from earnings included dividends of $15 million received from equity investments in 2003 (2002 – $18 million; 2001 – $10 million). Accounts receivable included allowance for doubtful accounts of $13 million in 2003 (2002 – $13 million). 12. Financing costs millions of dollars Debt-related interest Other interest Total interest expense (a) Foreign-exchange expense (gain) on long-term debt Total financing costs 2003 38 4 42 (129) (87) 2002 40 2 42 (10) 32 2001 77 4 81 71 152 (a) Cash interest payments in 2003 were $38 million (2002 – $41 million; 2001 – $99 million). The weighted-average interest rate on short-term debt in 2003 was 3.1 percent (2002 – 2.4 percent). The average effective interest rate on the company’s debt was 2.9 percent in 2003 (2002 – 2.1 percent). 13. Transactions with Exxon Mobil Corporation and affiliated companies (ExxonMobil) Revenues and expenses of the company also include the results of transactions with ExxonMobil in the normal course of operations. These were conducted on terms as favourable as they would have been with unrelated parties and primarily consisted of the purchase and sale of crude oil, petroleum and chemical products, as well as transportation, technical and engineering services. Transactions with ExxonMobil also included amounts paid and received in connection with the company’s participation in a number of natural resources joint-venture operations in Canada. The company has an existing agreement with ExxonMobil Canada to share common business and operational support services that allow the companies to consolidate duplicate work and systems. The amounts paid or received have been reflected in the statement of earnings as shown in the table below. millions of dollars Operating revenues Purchases of crude oil and products Operating expense 2003 950 2 464 14 2002 1 036 2 134 57 2001 664 1 873 47 Accounts payable due to Exxon Mobil Corporation at December 31, 2003, with respect to the above transactions, were $167 million (2002 – $146 million). During 2003, the company borrowed $818 million (Cdn) from Exxon Overseas Corporation under two long-term loan agreements as described in note 3. Interest paid on the loans in 2003 was $14 million. 14. Net payments to governments millions of dollars Current income tax expense (note 4) Federal excise tax Property taxes included in expenses Payroll and other taxes included in expenses GST/QST/HST collected (a) GST/QST/HST input tax credits (a) Other consumer taxes collected Crown royalties Total paid or payable to governments Less investment tax credits and other receipts Net payments to governments Net payments to: Federal government Provincial governments Local governments Net payments to governments 2003 610 1 254 80 52 2 015 (1 705) 1 662 418 4 386 30 4 356 2 061 2 215 80 4 356 2002 718 1 231 85 51 1 717 (1 368) 1 589 314 4 337 12 4 325 2 171 2 069 85 4 325 2001 679 1 180 86 47 1 749 (1 384) 1 585 460 4 402 7 4 395 2 160 2 149 86 4 395 (a) The abbreviations refer to the federal goods and services tax, the Quebec sales tax and the federal/provincial harmonized sales tax, respectively. The HST is applicable in the provinces of Nova Scotia, New Brunswick and Newfoundland and Labrador. 4 4 Imperial Oil Limited Natural resources segment – supplemental information Pages 44 and 45 provide information about the natural resources segment (see note 1, page 34). The information excludes items not related to oil and natural gas extraction such as administrative and general expenses, pipeline operations, gas plant processing fees and gains or losses on asset sales. Results of operations millions of dollars Sales to customers Intersegment sales Total sales (a) Production expenses Exploration expenses Depreciation and depletion Income taxes Results of operations Capital and exploration expenditures millions of dollars Property costs (b) Proved Unproved Exploration costs Development costs Total capital and exploration expenditures Property, plant and equipment millions of dollars Property costs (b) Proved Unproved Producing assets Support facilities Incomplete construction Total cost Accumulated depreciation and depletion Net property, plant and equipment Oil and gas 2002 1 381 741 2 122 576 30 426 350 740 2001 1 306 767 2 073 526 45 411 340 751 2003 1 816 584 2 400 594 55 463 364 924 Syncrude 2002 – 838 838 388 – 53 124 273 2001 – 741 741 395 – 46 92 208 2003 – 817 817 449 – 54 97 217 2003 1 816 1 401 3 217 1 043 55 517 461 1 141 Oil and gas 2002 2003 2001 2003 Syncrude 2002 2001 2003 – 2 55 339 396 13 5 34 469 521 – 5 44 489 538 – – – 609 609 – – – 465 465 – – – 208 208 – 2 55 948 1 005 Total 2002 1 381 1 579 2 960 964 30 479 474 1 013 Total 2002 13 5 34 934 986 2001 1 306 1 508 2 814 921 45 457 432 959 2001 – 5 44 697 746 Oil and gas 2003 2002 Syncrude 2003 2002 3 332 163 5 775 125 200 9 595 6 012 3 583 3 338 155 5 371 126 227 9 217 5 528 3 689 3 5 1 657 226 990 2 881 714 2 167 3 5 1 474 201 578 2 261 657 1 604 Total 2003 2002 3 335 168 7 432 351 1 190 12 476 6 726 5 750 3 341 160 6 845 327 805 11 478 6 185 5 293 (a) Sales of crude oil to consolidated affiliates are at market value, using posted field prices. Sales of natural gas liquids to consolidated affiliates are at prices estimated to be obtainable in a competitive, arm’s-length transaction. Total sales exclude the sale of natural gas and natural gas liquids purchased for resale, as well as royalty payments. These items are reported gross in note 1 in “Total revenues” and in “Purchases of crude oil and products.” (b) “Property costs” are payments for rights to explore for petroleum and natural gas and for purchased reserves (acquired tangible and intangible assets such as gas plants, production facilities and producing-well costs are included under “Producing assets”). “Proved” represents areas where successful drilling has delineated a field capable of production. “Unproved” represents all other areas. Annual report 2003 4 5 Net proved developed and undeveloped reserves (a) Beginning of year 2001 Revisions of previous estimates and improved recovery (Sale)/purchase of reserves in place Discoveries and extensions Production End of year 2001 Revisions of previous estimates and improved recovery (Sale)/purchase of reserves in place Discoveries and extensions Production End of year 2002 Revisions of previous estimates and improved recovery (Sale)/purchase of reserves in place Discoveries and extensions Production End of year 2003 Conventional 196 Crude oil and NGLs millions of barrels Cold Lake 851 Syncrude 610 (8) – – (23) 165 3 – – (22) 146 1 – – (21) 126 – – – (44) 807 33 – – (39) 801 5 – – (43) 763 – – 230 (19) 821 – – – (21) 800 – – – (19) 781 Natural gas billions of cubic feet 1 572 9 1 2 (170) 1 414 (26) 2 3 (169) 1 224 (40) – 6 (167) 1 023 Total 1 657 (8) – 230 (86) 1 793 36 – – (82) 1 747 6 – – (83) 1 670 (a) Net reserves are the company’s share of reserves after deducting the shares of mineral owners or governments or both. All reported reserves are located in Canada. Reserves of natural gas are calculated at a pressure of 14.73 pounds per square inch at 60°F. Crude oil and natural gas reserve estimates, excluding Syncrude, are based on geological and engineering data, which have demonstrated with reasonable certainty that these reserves are recoverable in future years from known reservoirs under existing economic and operating conditions; i.e., prices and costs as of the date the estimate is made. Reserves of crude oil at Cold Lake are those estimated to be recoverable from the existing experimental pilot plants and commercial phases 1 through 13. The calculation of reserves of crude oil at Syncrude is based on the company’s participating interest in the production permit granted in October 1979 and as subsequently amended by the Province of Alberta. Net proved reserves are determined by deducting the estimated future share of mineral owners or governments or both. For conventional crude oil (excluding enhanced oil-recovery projects) and natural gas, net proved reserves are based on estimated future royalty rates representative of those existing as of the date the estimate is made. Actual future royalty rates may vary with production and price. For enhanced oil-recovery projects, Syncrude and Cold Lake, net proved reserves are based on the company’s best estimate of average royalty rates over the life of each project. Actual future royalty rates may vary with production, price and costs. Reserves data do not include certain resources of crude oil and natural gas such as those discovered in the Beaufort Sea-Mackenzie Delta and the Arctic islands, or the resources contained in oil sands other than those attributable to Syncrude, the Cold Lake pilot area and phases 1 through 13 of Cold Lake production operations. In 2003, Imperial’s net proved reserves of crude oil and NGLs decreased by 77 million barrels, while the net proved reserves of natural gas decreased by 201 billion cubic feet. Production in 2003 totalled 83 million barrels of crude oil and NGLs and 167 billion cubic feet of natural gas. Revision of previous estimates and improved recovery increased reserves of crude oil and NGLs by six million barrels and decreased reserves of natural gas by 40 billion cubic feet. Discoveries and extensions in 2003 totalled six billion cubic feet of natural gas. 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. 4 6 Imperial Oil Limited Share ownership, trading and performance Share ownership Average number outstanding, weighted monthly (thousands) Number of shares outstanding at December 31 (thousands) Shares held in Canada at December 31 (percent) Number of registered shareholders at December 31 (a) Number of shareholders registered in Canada Shares traded (thousands) Share prices (dollars) High Low Close at December 31 Net earnings per share – basic and diluted (dollars) Price ratios at December 31 Share price to net earnings (b) Dividends declared (c) Total (millions of dollars) Per share (dollars) 2003 2002 2001 2000 1999 372 011 378 875 393 121 417 753 431 475 362 653 378 863 379 159 398 263 431 475 15.2 15.8 15.9 16.6 17.6 15 516 15 988 16 483 17 104 17 941 13 601 14 014 14 358 14 873 15 650 94 063 83 019 129 285 117 980 74 151 58.22 43.20 57.53 4.52 49.38 38.51 44.86 3.23 46.50 34.05 44.31 3.19 42.25 26.50 39.45 3.38 36.00 21.70 31.00 1.46 12.7 13.9 13.9 11.7 21.2 323 0.87 318 0.84 324 0.83 325 0.78 324 0.75 (a) Exxon Mobil Corporation owns 69.6 percent of Imperial’s shares. (b) Closing share price at December 31, divided by net earnings per share – basic and diluted. (c) The fourth-quarter dividend is paid on January 1 of the succeeding year. 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 Imperial. Imperial Oil Limited is a qualified foreign corporation for purposes of the new reduced U.S. capital gains tax rates (15 percent and five 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. Valuation day price For capital gains purposes, Imperial’s common shares were quoted at $10.50 a share on December 31, 1971, and $15.29 on February 22, 1994. Both amounts are restated for the 1998 three-for-one share split. Annual report 2003 4 7 Quarterly financial and stock trading data (a) Financial data (millions of dollars) Total revenues Total expenses Earnings before income taxes Income taxes Net earnings Segmented earnings (millions of dollars) Natural resources Petroleum products Chemicals Corporate and other Net earnings Per-share information (dollars) Net earnings – basic and diluted Dividends (declared quarterly) Share prices (dollars) (b) Toronto Stock Exchange High Low Close American Stock Exchange ($U.S.) High Low Close 2003 three months ended Mar. 31 June 30 Sept. 30 Dec. 31 2002 three months ended Mar. 31 June 30 Sept. 30 Dec. 31 5 478 4 688 790 252 538 4 510 3 895 615 101 514 4 626 4 066 560 185 375 4 594 4 197 397 142 255 339 139 6 54 538 351 102 7 54 514 257 115 8 (5) 375 192 51 16 (4) 255 3 485 3 316 169 59 110 144 (37) 9 (6) 110 4 195 3 811 384 74 310 251 15 11 33 310 4 532 3 970 562 215 347 346 21 22 (42) 347 4 830 4 143 687 230 457 315 128 10 4 457 1.42 0.21 1.38 0.22 1.01 0.22 0.71 0.22 0.29 0.21 0.82 0.21 0.91 0.21 1.21 0.21 47.80 43.48 47.35 32.20 28.25 32.14 47.40 43.20 47.10 34.99 29.94 34.92 53.49 45.62 50.80 38.79 33.04 37.21 58.22 50.16 57.53 44.75 37.24 44.42 47.85 41.13 47.45 30.33 25.83 29.84 49.38 43.76 47.29 31.85 28.15 31.19 47.10 38.51 45.90 31.09 24.00 29.00 46.10 41.55 44.86 29.31 26.61 28.70 Shares traded (thousands) (c) 21 350 23 171 21 434 28 108 21 316 23 057 21 377 17 269 (a) Quarterly data has not been audited by the company’s independent auditors. (b) Imperial’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 Imperial’s common shares is IMO. Share prices were obtained from stock exchange records. (c) The number of shares traded is based on transactions on the above stock exchanges. 4 8 Imperial Oil Limited Directors, senior management and officers Other officers J.F. (John) Kyle Vice-president and treasurer B.W. (Brian) Livingston Vice-president and general counsel J. (John) Zych Corporate secretary Board of directors P. (Pierre) Des Marais II President Gestion PDM Inc. Montreal, Quebec B.J. (Brian) Fischer Senior vice-president, products and chemicals division Imperial Oil Limited Toronto, Ontario T.J. (Tim) Hearn Chairman, president and chief executive officer Imperial Oil Limited Toronto, Ontario R. (Roger) Phillips Retired president and chief executive officer IPSCO Inc. Regina, Saskatchewan J.F. (Jim) Shepard Retired chairman and chief executive officer Finning International Inc. Vancouver, British Columbia P.A. (Paul) Smith Controller and senior vice-president, finance and administration Imperial Oil Limited Toronto, Ontario S.D. (Sheelagh) Whittaker Managing Director, Public Sector Business Electronic Data Systems Limited London, England K.C. (K.C.) Williams Senior vice-president, resources division Imperial Oil Limited Calgary, Alberta V.L. (Victor) Young Corporate director of several corporations St. John’s, Newfoundland and Labrador Dividend and share purchase information 2nd quarter, 2004 3rd quarter, 2004 4th quarter, 2004 1st quarter, 2005 Declaration date May 27, 2004 August 17, 2004 November 17, 2004 February 17, 2005 Dividend record date June 8, 2004 September 1, 2004 December 1, 2004 March 3, 2005 Dividend payment date July 1, 2004 October 1, 2004 January 1, 2005 April 1, 2005 Share purchase cutoff date (cheques for share purchase must be dated and received no later than) Investment date (dividend reinvestment and share purchase funds are invested by the company on) June 16, 2004 September 17, 2004 December 15, 2004 March 17, 2005 July 2, 2004 October 4, 2004 January 4, 2005 April 4, 2005 The declaration of dividends and the dates shown are subject to change by the board of directors. The company reserves the right to amend, suspend or terminate the dividend reinvestment and share purchase plan at any time. Share purchase cheques should be made payable to CIBC Mellon Trust Company. Dividend cheques are normally mailed three to five days prior to payment dates. Quarterly statements for dividend reinvestment and share purchase plan participants are normally mailed two weeks after the investment dates. Annual report 2003 4 9 Information for investors Head office Imperial Oil Limited 111 St. Clair Avenue West Toronto, Ontario, Canada M5W 1K3 Annual meeting The annual meeting of shareholders will be held on Wednesday, April 21, 2004, at 10:30 a.m. local time at the Metro Toronto Convention Centre, 255 Front Street West, Toronto, Ontario, Canada. Shareholder account matters To change your address, transfer shares, eliminate multiple mailings, elect to receive dividends in U.S. funds or have dividends deposited directly into accounts at financial institutions in Canada that provide electronic fund-transfer services, enrol in the dividend reinvestment and share purchase plan or enrol for electronic delivery of shareholder reports, please contact CIBC Mellon Trust Company. CIBC Mellon Trust Company P.O. Box 7010 Adelaide Street Postal Station Toronto, Ontario, Canada M5C 2W9 Telephone: Fax: E-mail: inquiries@cibcmellon.com www.cibcmellon.com 1-800-387-0825 (from Canada or U.S.A.) or 416-643-5500 416-643-5660 or -5661 United States resident shareholders may transfer their shares through Mellon Investor Services LLC. Mellon Investor Services LLC 85 Challenger Road Ridgefield Park, New Jersey, U.S.A. 07660 1-800-526-0801 Telephone: Dividend reinvestment and share purchase plan This plan provides shareholders with two ways to add to their shareholdings at a reduced cost. The plan enables shareholders to reinvest their cash dividends in additional shares at an average market price. Shareholders can also invest between $50 and $5,000 each calendar quarter in additional shares at an average market price. Funds directed to the dividend reinvestment and share purchase plan are used to buy existing shares on a stock exchange rather than newly issued shares. Imperial on-line Imperial’s Web site contains a variety of corporate and investor information, including: • current stock prices • annual and interim reports • Form 10-K • Information for Investors (a factbook that describes the company and its operations in detail) • investor presentations • earnings and other news releases • historical dividend information • corporate citizenship practices www.imperialoil.ca Investor information Information is also available by writing to the investor relations manager at Imperial’s head office or by: Telephone: Fax: 416-968-8145 416-968-5345 Other contact numbers Customer and other inquiries: 1-800-567-3776 Telephone: 1-800-367-0585 Fax: Corporate secretary Telephone: Fax: 416-968-4713 416-968-4095 Version française du rapport Pour obtenir la version française du rapport de la Compagnie Pétrolière Impériale Ltée, veuillez écrire à la division des Relations avec les investisseurs, Compagnie Pétrolière Impériale Ltée, 111 St. Clair Avenue West, Toronto, Ontario, Canada M5W 1K3. Design: Smith-Boake Designwerke Inc. Photography: Laura Arsie; J. Christopher Lawson; Imperial Oil archives Printing: Quebecor World MIL Inc. Cover photos: Front Kearl oil sands (top left), Dartmouth low-sulphur gasoline unit (centre left), filling up with low- sulphur gasoline (bottom left), Cold Lake operations (top right), Syncrude expansion (bottom right) Back Supporting literacy programs in the Northwest Territories (left), Mackenzie Delta (centre), community consultations on the Mackenzie gas project (right) This report is printed on 50-percent recycled paper that includes 20-percent post-consumer waste, and has been printed and bound to facilitate recycling. Imperial Oil Limited 111 St. Clair Avenue West Toronto, Ontario Canada M5W 1K3 www.imperialoil.ca