Imperial Oil
Annual Report 2004

Plain-text annual report

125 years of energy leadership 125Annual report to shareholders 2004 The importance of energy • Energy is essential for world economic and social development. • Hydrocarbons will remain a dominant source of the world’s energy for a long time to come. • Energy demand is rising worldwide, and new supplies of petroleum are required to meet this demand. • Canada is uniquely positioned to participate in this growing market. The International Energy Agency (IEA) has stated that oil and gas currently account for about 60 percent of all the energy consumed worldwide and, given the projected growth in demand, that is not expected to change significantly over the next few decades. Contents Letter to shareholders 2 4 Year in review 6 Natural resources 10 13 Chemicals 14 16 Caring for our communities Petroleum products Principled people and practices Financial section 19 20 Management’s discussion and analysis Frequently used financial terms 32 36 Management and auditors’ reports 37 Financial statements, accounting policies and notes 57 Natural resources segment – supplemental information 60 Share ownership, trading and performance 61 Quarterly financial and stock-trading data 62 Information for investors Directors, senior management and officers 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. Annual report 2004 5010015020025035030001971OilGasCoalOther**Other energy sources include solar, wind, nuclear, hydro, biomass and waste Source: International Energy Agency2020201020022030World energy demand grows 1.7 percent a year millions of oil-equivalent barrels a dayThe Imperial Oil advantage • The leading resource position in Canada with a diverse asset base • A consistent management approach and a disciplined investment strategy • A record of continually improving base operations • Financial strength unparalleled in the industry • A leader in the development and use of technology • High-performing, principled employees • Industry-leading return on capital employed • Imperial has provided superior returns to shareholders – in 2004, the total return was more than 25 percent and has averaged almost 20 percent a year for the past 10 years. Financial highlights Net income (millions of dollars) Net income per share (dollars) (a) – diluted Return on average shareholders’ equity (percent) (b) Return on average capital employed (percent) (c) Annual shareholders’ return (percent) (d) 2004 2 052 5.74 34.6 27.7 25.3 2003 1 705 4.58 32.6 25.3 30.5 2002 1 214 3.20 26.5 20.0 3.2 2001 1 223 3.11 28.8 22.3 14.5 2000 1 408 3.37 32.7 26.5 30.2 (a) Calculated by reference to the average number of shares outstanding, weighted monthly (page 60). (b) Net income divided by average shareholders’ equity (page 39). (c) A definition of return on average capital employed can be found on page 33. (d) Includes share appreciation and dividends. Imperial Oil Limited 1 Value of $100 invested on December 31, 1993Source: Bloomberg600500400300200100094959697989900S&P/TSX CompositeS&P/TSX EnergyImperial Oil01020304Sustained increase in shareholder value 10-year cumulative total returns2004 increase121086420Production* Before year-end price/cost revisionsProved reserves*Non- proved resources• Significant resource base• Long-life reserves• Non-proved resource of 11.5 billion oil-equivalent barrels• 2004 net increase in oil-sands resourceResource base an enabler for growth billions of oil-equivalent barrels – 2004Tim J. Hearn, chairman, president and chief executive officer Letter to shareholders Imperial’s ongoing strategy is to increase long-term shareholder value by continually improving base operations while investing in attractive growth opportunities. The company had another excellent year in 2004. A new record was set for earnings at $2,052 million or $5.74 a share, return on average capital employed was 28 percent and return on shareholders’ equity was 35 percent. Regular per-share dividend payments increased for the 10th year in a row, and almost $1.2 billion was returned to shareholders through dividend payments and the share- buyback program. The total return to shareholders including dividends paid and share-price appreciation was 25 percent. Higher commodity prices and strong refining and petrochemical margins were major factors in Imperial’s improved earnings. The company’s operations were also solid. Safety performance was the best on record, operating reliability improved and record volumes were achieved in several areas. Looking ahead, because of the cyclical nature of the business, which is strongly influenced by the changing fundamentals of supply and demand, it would not be prudent to expect 2004 prices and margins to be sustained over a long period. For this reason, Imperial’s business model remains focused on sound financial management, a disciplined investment strategy and improving those things we can control. The company maintained its strong financial position while making capital and exploration expenditures of more than $1.4 billion. Major natural resources opportunities were advanced. A significant development drilling program was undertaken at our oil-sands operations at Cold Lake, Alberta; work on the major upgrader expansion at Syncrude was advanced; the main regulatory applications for the Mackenzie gas project were filed; and delineation drilling proceeded at the Kearl oil-sands site in northeastern Alberta. In petroleum products, work began on modifying refineries to produce low-sulphur diesel fuel to meet future regulatory requirements and further reduce smog-forming emissions. 2 Annual report 2004 Overall, Imperial is well positioned for long-term earnings growth. The company’s diverse base of oil and gas resources in Canada, which exceeds 13 billion oil-equivalent barrels, is the largest in this country, and we have access to world-leading research, technology and project expertise. With these advantages, together with excellent financial strength, a consistent management approach and a disciplined investment strategy, I believe Imperial will remain an industry leader in both downstream and upstream operations for many years to come. Moving our head office to Calgary in 2005 will further strengthen the company’s strategic focus, while improving organizational effectiveness and productivity. Imperial’s resources and capabilities will be key in producing new Canadian supplies of oil and gas. In the coming decades, economic and population growth are projected to increase significantly both global and Canadian demand for all forms of energy. Hydrocarbons will remain the dominant source of energy as well as the main feedstock for countless chemical products that are vital to modern life. Canada has abundant oil and gas resources, but developing them at acceptable costs and with minimal impact on the environment present challenges that must be addressed. We are determined to continue to meet the evolving energy needs of Canadians while remaining committed to safety, environmental responsibility and the highest standards of ethics and integrity. This year marks the 125th anniversary of Imperial’s founding, and those commitments have remained constant throughout the company’s history. Ensuring that nobody gets hurt governs all operations. And the company is committed to delivering superior environmental performance – to drive environmental incidents with real impact to zero, through the continuous raising of standards and improvements to our operations. Imperial is also committed to maintaining the long-standing tradition of ethical business behaviour, including clear and straightforward reporting of operating and financial results. In particular, we remain fully confident in the integrity of our process for assessing and reporting oil and gas reserves. We will continue to make operating and investment decisions based on internal assessments of resources and their potential to provide future growth in production and earnings. The company remains deeply committed to Canada and Canadians, and this is reflected in many of our initiatives. For example, we believe the key to the economic and environmentally responsible development of Canada’s oil sands is to turn the best scientific minds to the challenge of developing new, innovative technologies. For this reason, in 2004 Imperial committed to contribute $10 million over five years to the University of Alberta to support oil-sands research. Another major cornerstone of the company’s success over its long history has been the collective talents, capability, dedication and extraordinary performance of our employees. For their steadfast willingness to meet the challenges of a difficult and competitive industry, they deserve the gratitude of shareholders for a job well done, every year. I would also note that one of the longest-standing nonemployee members of Imperial’s board of directors will not stand for re-election this spring. Pierre Des Marais II joined the board in April 1977. On behalf of his fellow directors, shareholders and employees, I want to express our appreciation for his many years of outstanding service to the company and wish him well for the future. For the last 125 years, Imperial has grown and prospered by pursuing excellence in all operations, while meeting both the needs of Canadians for secure energy supplies and their expectations for good corporate citizenship. These considerations remain in the forefront as we move into a future of long-term growth for shareholders. Tim J. Hearn February 16, 2005 For the last 125 years, Imperial has grown and prospered by meeting the evolving energy needs of Canadians. We were here yesterday, and we will be here for the long term. Imperial Oil Limited 3 Year in review Operating highlights • The best recorded safety performance for both employees and contractors was achieved; the results showed improvement over the company’s industry-leading record performance in 2003. • Reliability in the company’s operations was excellent. By actively managing those aspects under its direct control, Imperial continued to improve its base operations. • Increased volumes were achieved in upstream and downstream business segments. • Production records were set at the company’s refineries and its polyethylene and aromatics plants in Sarnia. • Substantial progress was made on major upstream projects, which are focused on developing oil-sands leases in Alberta, natural gas in the Mackenzie Delta region of the Northwest Territories and offshore resources on Canada’s East Coast. • Relentless pursuit of lower costs continued to be a priority. All key Imperial business units have either achieved industry-leading unit costs or are within first-quartile ranking for their cost structures. • The company continues to maintain an industry-leading research program at its two research facilities in Sarnia and Calgary. Total research expenditures in Canada were $38 million in 2004; three patents were awarded and 180 new or reformulated products were commercialized during the year. In addition, through its relationship with Exxon Mobil Corporation, Imperial had access to more than $800 million of leading-edge research worldwide. • In October, $10 million was committed over the next five years to fund the Imperial Oil Centre for Oil Sands Innovation at the University of Alberta. The centre is dedicated to finding more efficient, economically viable and environmentally responsible ways to develop Canada’s oil-sands resources. From left to right: Working at the Dartmouth, N.S., refinery; the company’s oil-sands research facility in Calgary; delineation drilling at the Kearl oil-sands lease in northeastern Alberta; performing field work for the Mackenzie gas project. 4 Annual report 2004 Financial highlights • The highest earnings in the • Regular per-share dividend • Capital and exploration company’s history were achieved, $2,052 million, up from the record $1,705 million in 2003. Earnings per share were $5.74. • Return on average capital employed continued at its pace-setting level in the industry – 28 percent, up from 25 percent in 2003. • In 2004, the total return on shares, including capital appreciation and dividends, was more than 25 percent (TSX), exceeding the returns of Standard & Poor’s (S&P) TSX composite index. Over the past 10 years, the total return on Imperial shares has averaged almost 20 percent a year. payments increased for the 10th consecutive year. • In 2004, total distributions to shareholders were almost $1.2 billion, including $872 million to buy back about 14 million shares. • An exceptionally strong balance sheet was maintained. Debt as a percentage of total capital was below 20 percent; interest coverage was 83 times earnings and more than 100 times cash flow. The “AAA” rating on Canadian debt from S&P was maintained; Imperial remains the only Canadian industrial company with this rating. At year- end, the balance of cash was $1,279 million. expenditures for 2004 were $1,445 million. Investments included advancing major upstream projects and funding significant refinery upgrades to reduce sulphur levels in diesel fuel, thereby further reducing smog-forming emissions. For the fourth consecutive year, more than $1 billion was spent on capital expenditures and exploration. In 2005, the company expects to spend about $1.6 billion, financed entirely from internally generated funds, with about $1 billion to be spent in the upstream. Imperial Oil Limited 5 Net earnings millions of dollars Return on average capital employed (ROCE) percent1 7502 0002 2501 0001 2501 5007505002500253035%10152050Net earningsReturn on average capital employed (ROCE) (%)ROCE of Canadian integrated oil companies (%)0001020304 Investing in growth opportunities millions of dollars1 4001 6002004006008001 0001 2000Capital and exploration expendituresOutlook000102030405Long-term use of cash five-year total (2000-2004), $10.9 billion$3.7 billion$1.6 billion$5.6 billionInvestments (net)DividendsShare purchasesThe company’s Cold Lake development is one of the largest thermal heavy-oil-recovery operations in the world. Natural resources Imperial has a leading resource position with diversified holdings in Northern, Western and Eastern Canada. The company’s total resource base, which includes reserves of oil, natural gas and natural gas liquids, was 13 billion oil-equivalent barrels at the end of 2004. These assets will provide the source for Imperial’s future growth. The upstream business continued its record of superior performance in 2004. Strong operations and excellent reliability contributed to a four-percent increase in production volumes for a total of 357,000 oil-equivalent barrels a day before royalties. Earnings after tax were a record $1,487 million, and return on average capital employed was 39 percent. Cash flow from operating activities and asset sales was $2.4 billion, of which about $1.1 billion was reinvested in the business. Expenditures for 2005 are again expected to be more than $1 billion, most of which will be directed to investment in the oil sands. Oil-sands operations With more than 460,000 acres of developed and undeveloped land holdings, the company has a significant lease position in the Alberta oil sands. More than $800 million was invested in the oil sands in 2004 to increase production from existing operations and advance new projects. In addition, activities on the oil-sands leases, most notably delineation 6 Annual report 2004 enhance the capacity of the operation, reduce unit operating costs and allow for additional development within the existing infrastructure before significant new investment is made at the site. In 2004, following U.S. Security and Exchange Commission guidelines, oil and gas reserves were assessed using year-end pricing, which resulted in a downward adjustment in Cold Lake reserves. This was solely because heavy-oil prices were considerably lower on the last day of 2004 than they had been during most of the year. The company believes that the method of assessing reserves using a single price point does not accurately reflect the long- term production potential of the resource. Imperial does not use this single-price-point assessment in any of its operating or investment decisions. Bitumen values are highly variable due to a number of factors. Using either 2004 year-average pricing or average prices in early 2005, there would have been no downward adjustment to Cold Lake reserves. Production from Imperial’s 25-percent share in Syncrude operations was a record 60,000 barrels of synthetic crude oil a day before royalties in 2004, up from 53,000 barrels a day in 2003. This included production from the Aurora 2 mine, which was completed in 2003. Disappointingly, the cost estimates for the current upgrader expansion project were substantially increased in 2004, and the construction schedule was extended. A new coker, used to convert heavy oils into lighter drilling at the company’s leases at Kearl, will increase Imperial’s non- proved resources by almost 2.5 billion barrels, bringing the company’s total resource base to 13 billion oil-equivalent barrels. Operations at Cold Lake contributed production of 126,000 barrels a day before royalties from about 3,800 wells. The production process for this thermal operation is cyclic by nature. At the beginning of a cycle, steam is injected into the subterranean reservoir to heat the bitumen until it flows. After a “soaking” period, the bitumen is produced. When production decreases, the cycle is repeated. Cycle times range from six months for new wells to 36 months for mature wells. On average, annual production has increased about four percent a year since 1992, but variations in year-to-year production occur depending on the cycles. In the last quarter of 2004, production at Cold Lake averaged 144,000 barrels a day. A development drilling program of more than 200 new wells from new pads was completed in 2004 at Cold Lake within the existing operating areas. In March, regulatory approval was received for operations in two new expansion areas, and drilling will begin in 2005 in one of these areas. Work was also completed in 2004 to Natural resources at a glance Net income (millions of dollars) Cash flow from operating activities and asset sales (millions of dollars) Gross crude oil and NGL production (thousands of barrels a day) Gross natural gas production (millions of cubic feet a day) Capital employed at December 31 (millions of dollars) Return on average capital employed (percent) 2004 1 487 2 364 262 569 3 839 39.3 2003 1 143 1 668 256 513 3 725 32.8 2002 1 042 1 258 247 530 3 252 35.8 2001 941 1 226 267 572 2 573 39.7 2000 1 165 1 911 260 526 2 162 49.9 Imperial Oil Limited 7 Crude oil and NGL gross production by source thousands of barrels a day3002001000Cold LakeSyncrudeConventional and NGLs0001020304Natural gas gross production millions of cubic feet a day6005004003002001000In 2004, gross natural gas production was 569 million cubic feet a day, up 11 percent from 2003. 0001020304Natural resources components, is expected to start operating in late 2005, with production of higher-quality synthetic crude oil to begin by mid-2006. Once complete, this expansion is expected to add an additional 27,000 barrels a day to Imperial’s volumes. A team of experts from the project owners and Syncrude has taken intervention steps to ensure the remaining project work is adequately managed to achieve the updated cost target and schedule. At year-end, the project was tracking to the revised cost and construction schedule. The company continued to evaluate its oil-sands opportunity at Kearl, 70 km north of Fort McMurray, Alberta. An initial drilling program was completed in early 2004. A second program began in December to further evaluate this high-quality resource. Imperial would hold a 70-percent interest and, if development is pursued, would act as operator in the potential joint project with ExxonMobil Canada. The property would be developed using a phased approach, with projected initial bitumen production of 100,000 barrels a day. Drilling results indicate that the combined leases hold the potential for up to 300,000 barrels a day, with production estimated to last in excess of 40 years. A regulatory filing is planned for 2005. A decision to fund and construct the project would be made after all approvals are received and project plans are finalized. Mackenzie gas project The Mackenzie gas project includes the development of three anchor natural gas fields (Taglu, Parsons Lake and Niglintgak) in the Mackenzie Delta region of the Northwest Territories, a gas-gathering pipeline system, a gas- processing plant and a 1,220-km pipeline system to link northern producing wells to southern markets. The project is proposed by Imperial, ConocoPhillips Canada, Shell Canada, ExxonMobil Canada and the Aboriginal Pipeline Group (APG). The APG was formed in 2000 to represent the ownership interest of the Aboriginal Peoples of the Northwest Territories in the proposed Mackenzie Valley natural gas pipeline. In October, Imperial, on behalf of the project co-venturers, filed the main regulatory applications and environmental impact statement for the proposed project with the National Energy Board and other boards, panels and agencies responsible for assessing and regulating energy developments in the Northwest Territories. The regulatory review process is currently underway and is expected to take up to 24 months. A decision to proceed with the project will be made by the co-venturers after approvals are received and any conditions attached to the approvals are assessed. Construction would then take three to four years. The project would bring to market natural gas from three previously discovered onshore anchor fields, including Imperial’s wholly owned Taglu field. Taglu covers an area of 32 km2 and is estimated to have a recoverable resource of about three trillion cubic feet, with a projected initial production rate of 400 million cubic feet a day. This field represents about one-half of the discovered onshore gas that the Mackenzie gas project would develop. The project would use conventional, proven technology and construction methods that minimize environmental impact. The proposed pipeline would run along the Mackenzie Valley from Inuvik, N.W.T., and link with an existing pipeline in northern Alberta. A separate natural gas liquids line, with a capacity of 24,000 barrels a day, would run from Inuvik to Norman Wells, N.W.T., where it would join an existing liquids line. Based on discussions with potential shippers, the pipeline was proposed with an initial design capacity of 1.2 billion cubic feet a day and is expandable to 1.9 billion cubic feet a day with additional compression facilities. The initial cost for the project is estimated to be about $7 billion, which includes $3.8 billion for the main pipeline system. The gas- gathering system, including a gas- processing plant at Inuvik, would cost about $1.6 billion, and the development of the three anchor Proved reserves of crude oil and natural gas (a) year ended 2000 2001 2002 2003 2004 (b) Crude oil and NGLs millions of barrels Natural gas Synthetic crude oil billions of cubic feet millions of barrels Conventional Cold Lake Total Syncrude gross 233 197 175 151 134 net 196 165 146 126 110 gross net gross net gross net gross 972 926 895 853 783 851 807 801 763 702 1 205 1 123 1 070 1 004 917 1 047 972 947 889 812 1 852 1 670 1 445 1 204 1 034 1 572 1 414 1 224 1 023 880 679 914 893 874 835 net 610 821 800 781 757 (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. (b) Before year-end price/cost revisions. 8 Annual report 2004 The company also holds an interest in exploration leases in the area offshore of Nova Scotia in the vicinity of the Sable project. In 2004, Imperial participated in the drilling of an exploration well on the Scotian Shelf, which was non-commercial. During 2004, Imperial relinquished its interests in nine of 13 licences. Remaining opportunities on the Scotian Shelf appear to be small and high-risk, but industry activity in the region will continue to be monitored. In early 2004, a 25-percent interest was acquired in the exploration rights for eight deepwater parcels in the Orphan Basin region off the east coast of Newfoundland. This is a large, unexplored frontier basin with favourable attributes for hydrocarbons. A 3-D seismic program was conducted from July to September on three of the eight parcels, and assessment of the data acquired will continue through early 2005. More 3-D seismic is planned on three additional blocks for the summer of 2005. fields is estimated to cost about $1.6 billion. Imperial’s share of the cost, including development of the Taglu field and the company’s share of the gas-gathering and processing system, is estimated to be about $3 billion. The company is working to advance the project in four key areas: • continuing the regulatory process, with applications for required land- and water-use licences to be filed in early 2005 • working on commercial agreements with potential shippers • completing benefits and access agreements with landowners and Aboriginal groups across whose land the pipeline would run • continuing engineering work on the technical aspects of the project. Conventional Western Canada Production from conventional operations, centred in Western Canada, accounted for 43 percent of the company’s total production before royalties. The company maintains a diligent focus on costs, and in 2004 unit operating costs were held flat. These assets, while mature, are highly profitable and deliver excellent returns. In 2004, gross natural gas production was 569 million cubic feet a day, up 11 percent from 2003. A significant gas development drilling program began in 2004 near Medicine Hat in southeastern Alberta, resulting in additional production to Imperial of nine million cubic feet a day at year-end. The program will continue in 2005. In addition, the company is selectively producing accumulated natural gas caps from oil reservoirs that have been economically depleted. In 2004, production of natural gas from these “blowdowns” reached 220 million cubic feet a day and is expected to continue through 2006. East Coast Imperial’s nine-percent interest in the Sable offshore energy project, which produces natural gas offshore of Nova Scotia, contributed volumes of 37 million cubic feet a day before royalties. The project produces from five fields, with the newest field, called South Venture, coming onstream in late 2004 to help maintain production. In 2005, drilling on two additional production wells is planned at the South Venture field, and construction will begin on compression facilities that will increase production from all fields. These facilities are expected to be complete by 2006 and will bring volumes to 44 million cubic feet a day. THENANDNOW Production 1947 2005 On February 13, 1947, in a farmer’s field about 30 km south of Edmonton, an exploratory oil well was brought into production in the presence of more than 500 invited guests. Imperial’s historic discovery of oil at Leduc marked the beginning of Canada’s role as a major oil producer. Imperial remains a leader in liquids production, most notably at its wholly owned Cold Lake bitumen-recovery operation, shown here, where more than 200 new wells were completed in 2004. The company is advancing projects on many fronts to develop Canada’s vast natural resources and meet energy needs. A delineation drilling program at Kearl, about 70 km north of Fort McMurray, Alberta, will help evaluate this high-quality oil- sands resource. Work is progressing on the Mackenzie gas project, and opportunities on Canada’s East Coast are continually assessed. Imperial Oil Limited 9 Imperial processes more than 74 million litres of crude oil a day in its four refineries across Canada, including the Dartmouth refinery, shown here. Petroleum products Imperial continued to be the largest producer and marketer of petroleum products in Canada, with the leading market share position in every major market segment it serves. Increased sales of petroleum products during a period of strong industry margins, coupled with sound cost management, were key to delivering record earnings in 2004. Downstream operations performed very well in 2004, with improved refinery reliability. Refinery utilization in 2004 was at 93 percent, total refinery throughput was up four percent, and total petroleum product sales were 87.6 million litres a day, up three percent from 2003. The company’s petroleum products operations achieved record earnings in 2004 of $500 million after tax, up from a record year in 2003 ($407 million), reflecting improved refining margins and higher volumes, as well as sound cost management. Return on average capital employed was 20 percent, and cash flow from operating activities and asset sales was $901 million, of which $283 million was reinvested in the business. Generally stronger economic conditions in Canada and worldwide created growing demand for petroleum products and higher refining margins. 10 Annual report 2004 The majority of these sites provide an expanded service offer to customers, including a one-stop shopping convenience store, car wash and Tim Hortons outlet. The network of about 400 car-wash facilities remains the largest in the industry. In 2004, total convenience-store sales were up 4.6 percent from 2003, and same- store sales were up 7.8 percent. For convenience, customers can pay at the pump with credit or debit cards, or use the popular Speedpass. Also in 2004, the company expanded the number of sites with pump-mounted television screens from five pilot locations to more than 100 sites. These provide news headlines, weather information, stock reports and in-store specials. Plans are in place to introduce these in more markets in 2005. The Esso customer loyalty program was enhanced in 2004 with the introduction of Aeroplan. Customers can now choose to collect Aeroplan Miles or Esso Extra points. The Esso loyalty offer is now the most comprehensive program available in Canada, offering a choice of immediate rewards such as car washes and convenience products, or longer-term travel rewards through Aeroplan. Imperial is committed to having the lowest unit costs in all its key business segments. The retail gasoline business achieved this in 2002 and maintained this position in 2004. The company’s primary distribution terminal operations In addition to a strong operating performance and solid reliability, earnings growth and operating improvements in the downstream businesses were achieved with a relentless focus on three areas: • providing customers with their lowest total cost offer • having industry-leading unit costs, benchmarked against competitors • ensuring the efficient and effective use of capital. In the retail gasoline business, the focus is on providing customers with the products they want quickly and conveniently. The company continued its program of upgrading its network of service stations in major urban markets, which has contributed to increased site productivity. In 2004, five new sites were built, 10 were rebuilt and 14 were upgraded. The company now operates a network of 720 company-owned sites across Canada with an average productivity of 5.6 million litres a year, up almost eight percent from 2003. Petroleum products at a glance Net income (millions of dollars) Cash flow from operating activities and asset sales (millions of dollars) Refinery throughput (millions of litres a day) Petroleum product sales (millions of litres a day) Capital employed at December 31 (millions of dollars) Return on average capital employed (percent) 2004 500 901 74.3 87.6 2 410 20.0 2003 407 567 71.6 85.0 2 601 16.7 2002 127 409 71.2 83.1 2 266 5.8 2001 353 834 71.4 81.2 2 095 16.2 2000 313 521 71.6 80.3 2 263 14.0 Imperial Oil Limited 1 1 Esso service stationsaverage number25002000150010005000Company-owned or leasedDealer-owned orleased0001020304Throughput – company-owned and leased service stations millions of litres per site6543210Average productivity at company- owned and leased service stations was 5.6 million litres a year in 2004, upalmost eight percent from 2003.0001020304Petroleum products reached this goal in 1998 and have sustained that position to date. Refining, lubricants and specialties, and other fuels marketing businesses continued to improve during 2004 and now rank well within the best quartile. Solid plans are in place for each of these units to reach industry-leading cost performance in 2005. A relentless focus on cost management has reduced unit costs (excluding inflation) over the past 10 years by 22 percent. This has resulted in favourable earnings while unit margins continually declined, decreasing 12 percent over the same period. As part of ongoing efforts to improve capital productivity, a focus on the efficient and effective use of working capital as well as on capital additions continued. The number of days that product is held in inventory was reduced by a further four percent in 2004. Since 1992, reductions in working capital have released about $1.5 billion of cash for more productive use. Efforts to reduce energy use in all operations continued in 2004. The company’s Energy Intensity Index (EII), an internationally recognized metric for energy efficiency for petroleum refineries, improved by four percent over 2003. During the past 10 years, Imperial’s EII value has improved by 16 percent, as a result of applying best operating practices and targeted capital spending. Capital investment in the company’s petroleum products operations totalled about $283 million in 2004, about a third of which was directed to projects to further reduce sulphur levels in diesel fuel, thereby reducing smog-forming emissions. In 2005, Imperial plans to invest about $550 million in its petroleum products operations, which, in addition to completing the low- sulphur diesel project, will be used to improve the company’s customer offer and incrementally increase refinery capacity at low capital cost. THENANDNOW Service stations 1916 2005 Customers fill-up a Ford at this 1916 service station. Demand for gasoline, once a minor byproduct of the refining process, increased exponentially with the growing popularity of automobiles. The first motorists bought gasoline in cans or open buckets from grocery or hardware stores. Imperial opened Canada’s first service station in 1907 in Vancouver. Imperial operates a network of 1,978 Esso service stations across Canada. The majority of company- owned sites provide a range of services to customers, including a one-stop shopping convenience store, car wash and Tim Hortons outlet. Imperial has the largest network of car washes in the industry. The Esso Extra loyalty program was enhanced in 2004 to introduce Aeroplan – customers can now choose between collecting Aeroplan Miles or Esso Extra points. 12 Annual report 2004 Refinery utilizationpercent95859075800Refinery utilization in 2004 was a record 93 percent, up from 90 percent during the past three years.0001020304Chemicals The focus for many years has been on increasing the integration of the Sarnia and Dartmouth chemicals plants within the refineries. This reduces costs and maximizes value for both operations. The strategy has proven effective in making Imperial’s chemicals business a leader in cost and productivity. The company also benefits from its integration within ExxonMobil’s North American chemicals businesses, which has resulted in a leadership position in the key market segments served. The polyethylene plant in Sarnia has been expanded five times since it began operations in 1983, with innovative technology applied to all stages of the operation to increase output at a small fraction of the cost of a new facility. Annual capacity is now 450,000 tonnes, up about 230 percent since 1983. In 2004, the business ran with excellent reliability and achieved an all-time production record in August. This plant remains one of the most cost- competitive in the world. Record production levels of benzene were also achieved in the aromatics business, in a period of record-high industry margins. In 2004, the business cycles for two main products – polyethylene and benzene – were quite favourable, with increased demand for products and strong margins. Chemicals earnings after tax were $100 million, up 170 percent from 2003. Cash flow from operating activities and asset sales was $126 million, $15 million of which was reinvested in the business. Average return on capital employed was almost 47 percent. Imperial remains one of Canada’s leading producers of chemical products, with the largest market share in domestic solvents in Canada, the largest market share in North America for polyethylene used in rotational molding and the second- largest market share in injection molding. The company’s Sarnia chemicals plant is located within one day’s trucking of 70 percent of the demand for polyethylene in North America. Total sales of petrochemical products were 3,300 tonnes a day, unchanged from 2003. Chemicals at a glance Net income (millions of dollars) Cash flow from operating activities and asset sales (millions of dollars) Chemicals sales volumes (thousands of tonnes a day) Capital employed at December 31 (millions of dollars) Return on average capital employed (percent) 2004 100 126 3.3 205 46.8 2003 37 22 3.3 222 19.9 2002 52 93 3.5 150 30.8 2001 23 9 3.3 188 14.1 2000 59 (6) 3.1 138 54.1 Imperial Oil Limited 1 3 Polyethylene sales volumes thousands of tonnes6005004003002001000Sales of purchased polyethyleneSales from our own production0001020304Imperial’s cash balance at the end of 2004 was almost $1.3 billion and is managed by treasurer’s department employees in the cash operations group. Principled people and practices Imperial has a long tradition of sound corporate governance and high ethical standards, which ensure the integrity of its businesses and operations. The company’s formula for maintaining this tradition is simple: strong leadership, along with discipline and commitment by employees at all levels of the organization. For more than 30 years, the company has had a comprehensive business ethics policy, which applies to directors and all employees and guides how all business is conducted. Governance practices are fully disclosed in the proxy circular and meet the requirements of both the Toronto Stock Exchange and the American Stock Exchange. In addition, governance practices meet the corporate governance guidelines in the proposed National Policy 58-201, published by the Ontario Securities Commission in October 2004. Sound governance practices are evident throughout the organization. Imperial has a straightforward capital structure and consistently reports results using transparent accounting practices. It does not use special- purpose entities, special adjustments or pro forma reporting. Neither does it use derivatives to speculate or hedge on the future direction of commodity prices, nor sell forward future production. 14 Annual report 2004 The company’s method of reporting reserves meets all regulatory requirements, including those of the U.S. and Canadian securities commissions and of Canadian National Instrument NI 51-101. Rigorous internal reserves management processes include disciplined and regular technical assessments, which are performed by qualified professionals and are subject to management review and endorsement, consistent with all asset management decisions. Notably, technical and other professionals involved in the process are not compensated based on the levels of proved reserves bookings. All requirements of the U.S. Sarbanes- Oxley Act have been met since it was introduced in 2002. The fact that the company was able to do so with minimal changes to its controls procedures and processes testifies to the high standard of Imperial’s governance systems. Chief among them is the long-standing Controls Integrity Management System (CIMS), which provides a structured approach for assessing financial control risks and procedures for mitigating concerns, monitoring conformance with standards and reporting results to management. CIMS is consistent with the internal controls framework recommended by the Committee of Sponsoring Organizations of the Treadway Commission, a voluntary private- sector organization dedicated to improving the quality of financial reporting. The majority of the company’s board are nonemployee directors. All board committees are made up solely of these independent directors. All directors and committees have the right to engage an outside adviser at the company’s expense, and nonemployee directors meet regularly in the absence of the company’s management. Full disclosure of all corporate governance practices is made in the proxy circular. High-performing, principled employees The people Imperial employs provide a competitive advantage. High- performing, principled people from diverse backgrounds are hired and developed. At year-end 2004, the company had 6,083 employees, 183 of whom were hired during the year. Every employee is involved in a structured development process, which includes rigorous training in business ethics. The company’s association with ExxonMobil gives it a considerable training advantage, providing an opportunity for employees to work with business units around the world to gain valuable global experience. The company seeks to be the employer of choice for the most capable and highest-performing graduates of Canadian universities and community colleges. In 2004, 69 graduates were hired through the company’s campus recruitment program. Employees Number of full-time employees at December 31 Total payroll and benefits (millions of dollars) (a) 2004 6 083 1 200 2003 6 256 1 188 2002 6 460 1 034 2001 6 740 902 2000 6 704 814 (a) Includes both the company’s payroll and benefits costs and its share of the Syncrude joint-venture payroll and benefits costs. From left to right: Employees performing a leak-detection assessment; monitoring a control panel at Cold Lake; working safely at the Nanticoke refinery. Imperial Oil Limited 1 5 Training, jobs and environmental protection are discussed at an open house in Yellowknife for residents to learn more about the Mackenzie gas project. Caring for our communities Founded on principles of integrity and community responsibility, Imperial has a long-standing record of good corporate citizenship. Throughout the past 125 years, the company has been fulfilling its primary responsibility to supply Canadians and others with reliable, affordable energy, as well as petroleum and petrochemical products. These products provide heat, light and mobility to Canadians and are vital to the manufacture of a multitude of items key to daily life, from computer components and health-care equipment to fertilizers and packaging. The demand for energy will continue to grow as populations and standards of living increase. Imperial is committed to meeting the growing demand for energy in an environmentally, economically and socially responsible manner. Nothing is more important than operating our facilities safely and protecting employees, contractors, customers, the public and the environment. The company works to drive environmental incidents with real impact to zero through a process of continuous improvement, and to have a workplace where nobody gets hurt. The Operations Integrity Management System (OIMS) is the primary tool the company uses to manage its operations and assess and improve its safety, health and environmental performance. Lloyd’s Register Quality Assurance, a respected international 16 Annual report 2004 information is available) by more than seven percent over 2002, reflecting the company’s focus on continuous improvement in all areas of its operations. The company tracks and works to reduce the greenhouse-gas intensity of its operations by improving energy efficiency, reducing flaring and investing in cogeneration facilities. In 2003 (the most recent year for which information is available), greenhouse-gas emissions from operations were 0.5 percent lower than in 2002, despite increased volumes of crude oil production and petroleum- product sales. Engaging communities Imperial places great value on its relationships with Canadian communities. From working with Pollution Probe to help develop future environmental managers to working with Aboriginal groups to share ideas about protecting the land, these relationships take many forms. But the goal remains the same – to work with communities today to build a better tomorrow. The company meets regularly with community leaders, governmental and non-governmental organizations and others interested in Imperial’s operations, including local residents, businesses and schools. For example, in developing the Mackenzie gas project, the company is working with Aboriginal communities in the Northwest Territories to understand and address the concerns of residents. More than 1,000 meetings with community members have been held to date throughout the Mackenzie Valley. Community input has enabled the project team to better understand the traditional knowledge of the Aboriginal peoples and has also resulted in changes to the proposed pipeline route. authority, has attested that OIMS meets the ISO 14001 Environmental Management Systems Standard. Lloyd’s also stated: “We further believe Imperial Oil to be among the industry leaders in the extent to which environmental management considerations have been integrated into its business processes for ongoing operations and for the planning and development of new projects.” Safety performance continues to be among the best in Canadian industry; Imperial’s 2004 performance surpassed that of 2003, which had been the best on record. In 2004, seven environmental incidents occurred with associated costs of more than $65,000, up from five in 2003. The most serious of these involved the accidental release of ketone into the St. Clair River from the Sarnia refinery. A preventive measures action plan was submitted to the Ontario Ministry of the Environment and has been implemented. All operating incidents are rigorously investigated, and measures are instituted to prevent similar incidents in the future. In 2004, $150 million was invested in projects related to further improving safety and environmental performance. These included $90 million as part of a $500-million investment that will enable Imperial’s refineries across Canada to produce ultra low-sulphur diesel fuel. This follows a $650-million refinery investment, completed in 2003, that reduced sulphur levels in gasoline by more than 90 percent a year ahead of regulated requirements. In conjunction with 2007 vehicle engines, these initiatives will reduce smog-causing nitrogen oxides and particulate-matter emissions by almost 90 percent. Examples of other 2004 environmental initiatives include a project at the Nanticoke, Ont., refinery to improve the quality of water effluent, and another at the Norman Wells operations to install an improved liquid-waste handling facility. Each year since 1993, Environment Canada has collected information from industries on releases of substances for its National Pollutant Release Inventory (NPRI). Imperial’s releases of NPRI substances decreased in 2003 (the most recent year for which Imperial Oil Limited 1 7 Employee and contractor safety leadership total recordable incidents per 200,000 work hours3210EmployeesContractors0001020304Upstream flaringmillions of cubic feet of gas a day43210Imperial continues to reduceemissions by recovering natural gas associated with crude oil production that would otherwise be flared or vented into the air.0001020304Imperial and the community Supporting the evolving needs of Canadian communities In 2004, more than $10.4 million was contributed to help Canadian communities meet important needs. Focusing on areas across Canada where it has a presence, the company gives the majority of its contributions through the Imperial Oil Foundation. In 2004, the foundation contributed more than $6 million to about 415 organizations, with the largest portion being directed toward programs that support youth and education. For example, the company is providing: • $500,000 over five years to the University of Manitoba to support the development of the Imperial Oil Academy for the Learning of Math, Science and Technology • $250,000 over five years to the St. Joseph Health Centre in Toronto to build a children’s health centre • $125,000 over five years to Halifax’s St. Mary’s University to fund Cosmic Rays in the Classroom, a program aimed at piquing elementary school students’ interest in science • $140,000 over four years to the Nature Conservancy of Canada in Quebec to support the educational component of its St. Lawrence River conservation project. Imperial contributes significantly to research at Canadian universities. In 2004, through its University Research Awards program, the company awarded 30 grants totalling $650,000 to 15 universities to fund research into areas of interest to Imperial, including engineering, chemical, physical, computing, social and environmental science. This program has been maintained continuously for more than 50 years. Also in 2004, the company announced that it would contribute $10 million over five years to the University of Alberta to fund the Imperial Oil Centre for Oil Sands Innovation. The centre will be dedicated to finding more efficient, economically viable and environmentally responsible ways to develop Canada’s vast oil-sands resources. In addition, Imperial contributed $200,000 over five years to Petroleum Research Atlantic Canada for research and technology development in this region. More information on Imperial’s corporate citizenship activities can be found in the corporate citizenship section of the company’s Web site, www.imperialoil.ca. Imperial’s 2003 corporate citizenship report, A partner in the Canadian community, is also available on-line. From left to right: The University of Alberta in Edmonton, to which the company announced it would donate $10 million over five years to fund the Imperial Oil Centre for Oil Sands Innovation; an Imperial employee from Norman Wells, N.W.T., answers questions on the Mackenzie gas project during a call-in show on local radio; the Nature Conservancy of Canada will receive $140,000 over four years from Imperial to support education on its St. Lawrence River conservation project. 18 Annual report 2004 Community investment$3 779 000$984 000$472 000$278 000$4 927 000Community services*EducationOther*includes contributions to community investment programs at Syncrude and SableArts and cultureHockeyFinancial section 20 Management’s discussion and analysis 32 Frequently used financial terms 36 Management and auditors’ reports 37 Financial statements, accounting policies and notes 57 Natural resources segment – supplemental information 60 61 62 Share ownership, trading and performance Quarterly financial and stock-trading data Information for investors Directors, senior management and officers Imperial Oil Limited 1 9 Financial summary (under U.S. GAAP) millions of dollars Revenues Net income by segment: Natural resources Petroleum products Chemicals Corporate and other Net income Total assets Long-term debt Total debt Other long-term obligations Capital employed Cash flow from operating activities and asset sales Per-share information (dollars) Net income per share – basic Net income per share – diluted Dividends 2004 22 460 1 487 500 100 (35) 2 052 2003 19 208 1 143 407 37 118 1 705 2002 17 042 1 042 127 52 (7) 1 214 2001 17 253 941 353 23 (94) 1 223 2000 18 051 1 165 313 59 (129) 1 408 14 027 12 337 12 003 10 888 11 266 367 1 443 1 525 7 821 3 414 5.75 5.74 0.88 859 1 432 1 314 7 029 2 283 4.58 4.58 0.87 1 466 1 538 1 822 6 498 1 749 3.20 3.20 0.84 1 029 1 489 1 303 5 784 2 050 3.11 3.11 0.83 1 037 1 412 1 110 5 662 2 363 3.37 3.37 0.78 Management’s discussion and analysis of financial condition and results of operations Overview The following discussion and analysis of Imperial’s financial results, as well as the accompanying financial statements and related notes to consolidated financial statements to which they refer, are the responsibility of the management of Imperial Oil Limited. Beginning in 2004, the company reported its financial results based on generally accepted accounting principles (GAAP) in the United States. The differences between U.S. and Canadian GAAP are small for Imperial and an explanation of them as they apply to the company, including a tabular reconciliation of net income reported under U.S. GAAP and under Canadian GAAP, is included as a note to the financial statements on page 46. Supplemental financial information based on Canadian GAAP pertaining to management’s discussion and analysis of Imperial’s financial results is also provided, on page 34. The company’s accounting and financial reporting fairly reflect its straightforward business model involving the extracting, refining and marketing of hydrocarbons and hydrocarbon-based products. The company’s business involves the production (or purchase), manufacture and sale of physical products, and all commercial activities are directly in support of the underlying physical movement of goods. This straightforward approach extends to the financing of the business. In evaluating business or investment opportunities, the company views as economically equivalent any debt obligation, whether included on the face of the consolidated balance sheet or disclosed as other debt-like obligations in the notes to the financial statements. The company does not use financial structures for the purpose of removing debt from the balance sheet. Nor does it use derivative markets to speculate on the future direction of currency or commodity prices or sell forward any part of production from any business segment. This consistent, conservative approach to financial management has helped Imperial to sustain its high credit quality. With its extensive resource base in Canada, financial strength, disciplined investment approach and technology portfolio, Imperial is well positioned to participate in substantial investments to develop new energy supplies. While commodity prices remain volatile on a short-term basis depending upon supply and demand, Imperial’s investment decisions are based on long-term outlooks, using a disciplined approach in selecting and pursuing the most attractive investment opportunities. The corporate plan is a fundamental annual management process that is the basis for setting near-term operating and capital objectives in addition to providing the longer-term economic assumptions used for investment evaluation purposes. Annual plan volumes are based on individual field production profiles that are updated annually. Prices for natural gas and other products used for investment evaluation purposes are based on corporate plan assumptions that are developed annually. Potential investment opportunities are tested over a wide range of economic scenarios to establish the resiliency of each opportunity. Once investments are made, a reappraisal process is 20 Annual report 2004 completed to ensure relevant lessons are learned and improvements are incorporated into future projects. Imperial views return on capital employed as the best measure of historical capital productivity. Business environment and outlook Natural resources Imperial produces crude oil and natural gas for sale into large North American markets. Economic and population growth are expected to remain the primary drivers of energy demand. The company expects the global economy to grow at an average rate of about three percent per year through 2030. World energy demand should grow by about two percent per year, and oil and gas are expected to account for about 60 percent of world energy supply by 2030. Over the same period, the Canadian economy is expected to grow at an average rate of two percent per year, and Canadian demand for energy at a rate of about one percent per year. Oil and gas are expected to continue to supply two-thirds of Canadian energy demand. It is expected that Canada will also be a growing supplier of energy to U.S. markets through this period. Oil products are the transportation fuel of choice for the world’s fleet of cars, trucks, trains, ships and airplanes. Primarily because of increased demand in developing countries, oil production will increase by 50 percent or nearly 30 million barrels per day over the next three decades. Canada’s oil sands represent an important additional source of supply. Natural gas is expected to be the fastest-growing primary energy source globally, capturing about one-third of all incremental energy growth and approaching one-quarter of global energy supplies. Natural gas production from mature established regions in the United States and Canada is not expected to meet increasing demand, strengthening the market opportunities for new gas supply from Canada’s frontier areas. Crude oil and natural gas prices are determined by global and North American markets and are subject to changing supply and demand conditions. These can be influenced by a wide range of factors including economic conditions, international political developments and weather. In the past, crude oil and natural gas prices have been volatile, and the company expects that volatility to continue. Imperial has a large and diverse portfolio of oil and gas resources in Canada, both developed and undeveloped, which helps reduce the risks of dependence on potentially limited supply sources in the upstream. With the relative maturity of conventional production in the established producing areas of Western Canada, Imperial’s production is expected to come increasingly from frontier and unconventional sources, particularly oil sands and natural gas from the Far North, where Imperial has large undeveloped resource opportunities. Petroleum products The downstream continues to experience ongoing volatility in industry margins. Refining margins are the difference between what a refinery pays for its raw materials (primarily crude oil) and the wholesale market prices for the range of products produced (primarily gasoline, diesel fuel, heating oil, jet fuel and fuel oil). Crude oil and many products are widely traded with published international prices. Prices for those commodities are determined by the marketplace, often an international marketplace, and are affected by many factors, including global and regional supply/demand balances, inventory levels, refinery operations, import/export balances, seasonality and weather. Canadian wholesale prices in particular are largely determined by wholesale prices in adjacent U.S. regions. These prices and factors are continually monitored and provide input to operating decisions about which raw materials to buy, facilities to operate and products to make. However, there are no reliable indicators of future market factors that accurately predict changes in margins from period to period. Imperial’s downstream strategies are to provide customers with quality service at the lowest total cost offer, have the lowest unit costs among our competitors, ensure efficient and effective use of capital and capitalize on integration with the company’s other businesses. Imperial owns and operates four refineries in Canada, with distillation capacity of 502,000 barrels a day and lubricant manufacturing capacity of 9,000 barrels a day. Imperial’s fuels marketing business includes retail operations across Canada serving customers through about 2,000 Esso-branded service stations, of which about 720 are company-owned or leased, and wholesale and industrial operations through a network of 30 distribution terminals. Chemicals Although the current business environment is favourable, the North American petrochemical industry is cyclical. The company’s strategy for its chemicals business is to reduce costs and maximize value by continuing to increase the integration of its chemicals plants at Sarnia and Dartmouth with the refineries. The company also benefits from its integration within ExxonMobil’s North American chemicals businesses, enabling Imperial to maintain a leadership position in its key market segments. Imperial Oil Limited 2 1 Management’s discussion and analysis of financial condition and results of operations (continued) Results of operations Net income in 2004 was $2,052 million or $5.74 a share – the best year on record – compared with $1,705 million or $4.58 a share in 2003 (2002 – $1,214 million or $3.20 a share). Higher realizations for crude oil, stronger industry refining and petrochemical margins, and higher volumes of Syncrude production, natural gas and petroleum products contributed positively to net income, partly offset by lower marketing margins. Compared with 2003, these favourable operating results were partly offset by the combined negative effects of a higher Canadian dollar on resource and product prices of about $260 million, the absence of favourable foreign-exchange effects on the company’s U.S.-dollar-denominated debt of about $110 million, and lower benefits from tax matters of about $100 million. Total revenues were $22.5 billion, up about 17 percent from 2003. The return on average capital employed was 28 percent, compared with 25 percent in 2003 (2002 – 20 percent). Natural resources Net income from natural resources was a record $1,487 million, up from $1,143 million in 2003 (2002 – $1,042 million). The positive earnings effects of improved realizations for crude oil and natural gas, combined with higher Syncrude, natural gas and natural gas liquids (NGLs) volumes, were partly offset by lower Cold Lake bitumen production, lower benefits from tax matters and the negative effects of a higher Canadian dollar. Resource revenues were $6.6 billion, up from $5.6 billion in 2003 (2002 – $4.9 billion). The main reasons for the increase were higher prices for crude oil and increased natural gas and Syncrude volumes. Return on average capital employed was 39 percent for the natural resources segment, compared with 33 percent in 2003 (2002 – 36 percent), reflecting higher net income. Financial statistics millions of dollars Net income Revenues Cash flow from operating activities and asset sales Capital employed at December 31 Return on average capital employed (percent) 2004 1 487 6 625 2 364 3 839 39.3 2003 1 143 5 648 1 668 3 725 32.8 2002 1 042 4 894 1 258 3 252 35.8 2001 941 5 321 1 226 2 573 39.7 2000 1 165 5 900 1 911 2 162 49.9 22 Annual report 2004 Factors affecting Imperial’s 2004 net incomemillions of dollars1705200320042052Higher resource realizationsHigher product marginsHigher volumesHigher Canadian dollarLower tax benefits and otherHigher volume- related costs, energy prices and other expenses560260175(370)(180)(98)U.S.-dollar world oil prices were considerably higher in 2004 than in the previous year. The annual average price of Brent crude oil, the most actively traded North Sea crude and a common benchmark of world oil markets, was $38 (U.S.) a barrel in 2004, a more than 30-percent increase over the average price of $29 in 2003 (2002 – $25). However, increases in the company’s Canadian-dollar realizations for conventional crude oil and Cold Lake bitumen were dampened by the effects of a higher Canadian dollar. Average realizations for conventional crude oil during the year were $48.96 (Cdn) a barrel, an increase of 22 percent from $40.10 in 2003 (2002 – $36.81). Average prices for Canadian heavy crude oil were higher in 2004, but by less than the relative increase in light crude oil prices, as increased supply of heavy crude oil widened the average spread between light and heavy crude. The price of Bow River, a benchmark Canadian heavy crude oil, increased by 15 percent in 2004, much less than the increase in prices for Canadian light crude oil. Cold Lake bitumen realizations in U.S. dollars averaged 19 percent higher in 2004 than in 2003. Average realizations for Cold Lake bitumen were only about 10 percent higher than the previous year, reflecting the effect of the higher Canadian dollar. Prices for Canadian natural gas in 2004 were essentially unchanged from the previous year. The average of 30-day spot prices for natural gas at the AECO hub in Alberta was about $6.80 a thousand cubic feet in 2004, compared with $6.70 in 2003 (2002 – $4.10). The company’s average realizations on natural gas sales were $6.78 a thousand cubic feet, compared with $6.60 in 2003 (2002 – $4.02). Average realizations and prices Canadian dollars Conventional crude oil realizations (a barrel) Natural gas liquids 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) 2004 48.96 33.78 6.78 53.26 37.98 2003 40.10 32.09 6.60 43.93 33.00 2002 36.81 23.38 4.02 40.44 31.85 2001 35.56 29.31 5.72 39.64 25.11 2000 41.52 29.57 4.99 45.02 34.49 Gross production of crude oil and NGLs increased to 262,000 barrels a day from 256,000 barrels in 2003 (2002 – 247,000). Gross bitumen production at the company’s wholly owned facilities at Cold Lake decreased to 126,000 barrels a day from 129,000 barrels in 2003 (2002 – 112,000), due to the cyclic nature of production at Cold Lake. Production from the Syncrude operation, in which the company has a 25-percent interest, increased during 2004 as a result of reduced turnaround activities. Gross production of upgraded crude oil increased to a record 238,000 barrels a day from 211,000 barrels in 2003 (2002 – 229,000). Imperial’s share of average gross production increased to 60,000 barrels a day from 53,000 barrels in 2003 (2002 – 57,000). Gross production of conventional oil decreased to 43,000 barrels a day from 46,000 barrels in 2003 (2002 – 51,000) as a result of the natural decline in Western Canadian reservoirs. Gross production of NGLs available for sale averaged 33,000 barrels a day in 2004, up from 28,000 barrels in 2003 (2002 – 27,000). Gross production of natural gas increased to 569 million cubic feet a day from 513 million in 2003 (2002 – 530 million). Higher natural gas and NGL volumes were mainly a result of the full-year production of natural gas from the Wizard Lake gas cap in Alberta, which began in the third quarter of 2003. Imperial Oil Limited 2 3 Crude oil prices U.S. dollars a barrel – quarterly averageBrent crudeCanadian heavy oil (Bow River)504030201002515453550001020304Natural gas average prices dollars a thousand cubic feet – AECO hub 30-day spot121086420Prices for Canadian natural gas in 2004 were essentially unchanged from the previous year.0001020304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 Total crude oil and NGL production Cold Lake sales, including diluent (b) NGL sales Natural gas – production and sales (a) millions of cubic feet a day Production (c) Sales 2004 2003 2002 2001 2000 net 33 112 59 204 26 230 gross 43 126 60 229 33 262 167 42 net 35 116 52 203 22 225 gross 46 129 53 228 28 256 170 39 net 39 106 57 202 21 223 gross 51 112 57 220 27 247 145 40 gross 55 128 56 239 28 267 167 43 net 42 121 52 215 22 237 gross 60 119 51 230 30 260 156 42 2004 2003 2002 2001 2000 gross 569 520 net 518 gross 513 460 net 457 gross 530 499 net 463 gross 572 502 net 466 gross 526 419 net 46 102 42 190 23 213 net 459 (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) Includes natural gas condensate added to the Cold Lake bitumen to facilitate transportation to market by pipeline. (c) Production of natural gas includes amounts used for internal consumption with the exception of amounts reinjected. Operating costs increased by seven percent in 2004. The main factor was higher depreciation and depletion expenses in line with higher production volumes. Petroleum products Net income from petroleum products was a record $500 million or 1.6 cents a litre in 2004, up from $407 million or 1.3 cents a litre in 2003 (2002 – $127 million or 0.4 cents a litre). Improved earnings were mainly due to stronger international refining margins, partly offset by lower fuels marketing margins and the negative impact of a higher Canadian dollar. Sales volumes of petroleum products were higher, due in part to higher industry demand. Revenues were $19.2 billion, up from $16.1 billion in 2003 (2002 – $14.4 billion). Return on average capital employed was 20 percent for the petroleum products segment, compared with 17 percent in 2003 (2002 – six percent). Financial statistics millions of dollars Net income Revenues Cash flow from operating activities and asset sales 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) 2004 500 19 211 901 2 410 20.0 2004 33.2 27.3 5.9 7.0 73.4 14.2 87.6 93.0 2004 74.3 79.9 93 2003 407 16 058 567 2 601 16.7 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 14 434 409 2 266 5.8 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 14 405 834 2 095 16.2 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 15 120 521 2 263 14.0 2000 32.0 27.5 5.1 5.0 69.6 10.7 80.3 94.0 2000 71.6 78.7 91 (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. 24 Annual report 2004 Margins were stronger in the refining segment of the industry in 2004 compared with those in 2003, as international wholesale product prices increased more than raw material costs. However, the effects of higher international margins were reduced partially by a higher Canadian dollar. Retail margins in the fuels marketing area were lower in 2004, reflecting the impact of highly competitive markets. Operating performance of the company’s four refineries was solid. Throughput at the refineries has increased, with refinery capacity utilization averaging a record 93 percent in 2004, compared with 90 percent in 2003 (2002 – 90 percent). The company’s total sales volumes, including those resulting from reciprocal supply agreements with other companies, were 87.6 million litres a day, compared with 85 million litres in 2003 (2002 – 83.1 million). Excluding sales resulting from reciprocal agreements, sales were 73.4 million litres a day, compared with 70.4 million litres in 2003 (2002 – 69.2 million). Operating costs increased by about two percent in 2004 from the previous year, mainly because of higher energy, environmental and depreciation costs. Chemicals Net income from chemicals operations was $100 million in 2004, compared with $37 million in 2003 (2002 – $52 million). Strong industry polyethylene and benzene margins were the main factors contributing to the improvement. Financial statistics millions of dollars Net income Revenues Cash flow from operating activities and asset sales 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 2004 100 1 509 126 205 46.8 2004 2.7 0.6 3.3 2003 37 1 232 22 222 19.9 2003 2.4 0.9 3.3 2002 52 1 164 93 150 30.8 2002 2.5 1.0 3.5 2001 23 1 175 9 188 14.1 2001 2.4 0.9 3.3 2000 59 1 173 (6) 138 54.1 2000 2.2 0.9 3.1 (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. Total revenues from chemical operations were $1,509 million, compared with $1,232 million in 2003 (2002 – $1,164 million). Higher prices for polyethylene, intermediate chemicals and aromatics were the contributing factors. Return on average capital employed was 47 percent for the chemicals segment, compared with 20 percent in 2003 (2002 – 31 percent). The average industry price of polyethylene was $1,584 a tonne in 2004, up 12 percent from $1,415 a tonne in 2003 (2002 – $1,229). Margins were higher as demand for polyethylene products grew. Sales of chemicals were 3,300 tonnes a day, unchanged from 2003 (2002 – 3,500 tonnes), while polyethylene and benzene sales were up three percent and 32 percent respectively over 2003. Operating costs in the chemicals segment for 2004 were about the same as 2003. Higher energy costs were offset by lower depreciation expense. A significant portion of the property, plant and equipment currently used in production and manufacturing has been fully depreciated. Imperial Oil Limited 2 5 Average refining margins Canadian cents a litreNewYork Harbor product prices minus Brent crude; reflects Imperial’s product mix.781234560Management’s discussion and analysis of financial condition and results of operations (continued) Corporate and other Net income from corporate and other accounts was negative $35 million in 2004, compared with positive $118 million in 2003 (2002 – negative $7 million). Lower net income in 2004 was mainly due to the absence of the favourable foreign-exchange effects on the company’s U.S.-dollar-denominated debt, which was replaced with Canadian-dollar-denominated debt in June and July of 2003. Net income for 2004 also included a non-recurring after-tax writedown of $42 million on a north Toronto property, which was acquired in 1991 to be the company’s future Toronto headquarters site. The remeasurement at fair value of this property reflected a change in its intended use and management’s commitment to sell following the announcement of the relocation of the company’s headquarters to Calgary. Liquidity and capital resources Sources and uses of cash millions of dollars Cash provided by/(used in) Operating activities Investing activities Financing activities Increase/(decrease) in cash and cash equivalents Cash and cash equivalents at end of year 2004 3 312 (1 306) (1 175) 831 1 279 2003 2 227 (1 426) (1 119) (318) 448 Although the company issues long-term debt from time to time, internally generated funds cover the majority of its financial requirements. The management of cash that may be temporarily available as surplus to the company’s immediate needs is carefully controlled, both to ensure that it is secure and readily available to meet the company’s cash requirements as they arise and to optimize returns on cash balances. Cash flows from operating activities are highly dependent on crude oil and natural gas prices and product margins. In addition, the company will need to continually find and develop new resources, and continue to develop and apply new technologies and recovery processes to existing fields, in order to maintain or increase production and resulting cash flows in future periods. Projects are in place or underway to increase production capacity. However, these volume increases are subject to a variety of risks including project execution, operational outages, reservoir performance and regulatory changes. The company’s financial strength enables it to make large, long-term capital expenditures. Imperial’s large and diverse portfolio of development opportunities and the complementary nature of its business segments help mitigate the overall risks of the company and associated cash flow. Further, due to its financial strength, debt capacity and diverse portfolio of opportunities, the risk associated with failure or delay of any single project would not have a significant impact on the company’s liquidity or ability to generate sufficient cash flows for operations and its fixed commitments. Cash flow from operating activities Cash provided by operating activities was $3,312 million, up from $2,227 million in 2003 (2002 – $1,688 million). The increased cash inflow was mainly due to higher net income, timing of scheduled income-tax payments and the additional funding contributions to the employee pension plan in 2003. Capital and exploration expenditures Total capital and exploration expenditures were $1,445 million in 2004, down slightly from $1,559 million in 2003 (2002 – $1,612 million). The funds were used mainly to invest in growth opportunities in the oil sands and the Mackenzie gas project, to upgrade refineries to meet low-sulphur diesel requirements and to enhance the company’s retail network. About $150 million was spent on projects related to reducing the environmental impact of its operations and improving safety, including about $90 million on the $500-million capital project to produce low-sulphur diesel. The following table shows the company’s capital and exploration expenditures for natural resources during the five years ending December 31, 2004: millions of dollars Exploration Production Heavy oil Total capital and exploration expenditures 2004 60 234 819 1 113 2003 57 181 769 1 007 2002 39 143 804 986 2001 49 109 588 746 2000 56 110 268 434 26 Annual report 2004 For the natural resources segment, about 90 percent of the capital and exploration expenditures in 2004 was focused on growth opportunities. The single largest investment during the year was the company’s share of the Syncrude expansion. Construction on the upgrader expansion made good progress since the first quarter of 2004, when cost estimates were substantially increased and the construction schedule was extended. At year-end, the project was tracking to the revised cost and construction schedule. The remainder of 2004 investment was directed to advancing the Mackenzie gas project and drilling at Cold Lake and in conventional fields in Eastern and Western Canada. For the Mackenzie gas project, in October 2004, the main regulatory applications and environmental impact statement were filed with the National Energy Board and other boards, panels and agencies responsible for assessing and regulating energy developments in the Northwest Territories. The regulatory review process is expected to take up to 24 months. A decision to proceed with the project will be made by the co-venturers of the project after approvals are received and any conditions attached to the approvals are assessed. Planned capital and exploration expenditures in natural resources are expected to be about $1 billion in 2005, with nearly 90 percent of the total focused on growth opportunities. Much of the expenditure will be directed to the expansion now underway at Syncrude. Investments are also planned for the ongoing development drilling at Cold Lake, the Mackenzie gas project and further development drilling in Western Canada. Planned expenditures for exploration and development drilling, as well as capacity additions in conventional oil and gas operations, are expected to be about $355 million. The following table shows the company’s capital expenditures in the petroleum products segment during the five years ending December 31, 2004: millions of dollars Marketing Refining and supply Other (a) Total capital expenditures (a) Consists primarily of real estate purchases. 2004 85 178 20 283 2003 91 369 18 478 2002 133 399 57 589 2001 171 118 50 339 2000 121 100 11 232 For the petroleum products segment, capital expenditures decreased to $283 million in 2004, compared with $478 million in 2003 (2002 – $589 million), primarily because of the completion of the project to significantly reduce sulphur content in gasoline, which began in 2001. New investments in 2004 included about $90 million spent on the initial phases of a three-year project to reduce sulphur content in diesel. In addition, $24 million was spent on other refinery projects to improve energy efficiency and increase yield. Major investments were also made to upgrade the network of Esso service stations during the year. Capital expenditures for the petroleum products segment in 2005 are expected to be about $550 million. Major items include additional investment in refining facilities to reduce the sulphur content in diesel to meet regulatory requirements and continued enhancements to the company’s retail network. The following table shows the company’s capital expenditures for its chemicals operations during the five years ending December 31, 2004: millions of dollars Capital expenditures 2004 15 2003 41 2002 25 2001 30 2000 13 Of the capital expenditures for chemicals in 2004, the major investment focused on improving energy efficiency, yields and process control technology. Planned capital expenditures for chemicals in 2005 will be about $20 million. Total capital and exploration expenditures for the company in 2005, which will focus mainly on growth and productivity improvements, are expected to total about $1.6 billion and will be financed from internally generated funds. Cash flow from financing activities In June, the company renewed the normal course issuer bid (share-repurchase program) for another 12 months. During 2004, the company purchased about 14 million shares for $872 million (2003 – 16 million shares for $799 million). Since Imperial initiated its first share-repurchase program in 1995, the company has purchased 233 million shares – representing about 40 percent of the total outstanding at the start of the program – with resulting distributions to shareholders of $6.8 billion. Imperial Oil Limited 2 7 Management’s discussion and analysis of financial condition and results of operations (continued) The company declared dividends totalling 88 cents a share in 2004, up from 87 cents in 2003 (2002 – 84 cents). Regular per-share dividends paid have increased in each of the past 10 years and, since 1986, payments per share have grown by more than 65 percent. Total debt outstanding at the end of 2004, excluding the company’s share of equity company debt, was $1,443 million, compared with $1,432 million at the end of 2003 (2002 – $1,538 million). Debt represented 19 percent of the company’s capital structure at the end of 2004, compared with 21 percent at the end of 2003 (2002 – 24 percent). Debt-related interest incurred in 2004, before capitalization of interest, was $37 million, down from $38 million in 2003 (2002 – $40 million). The average effective interest rate on the company’s debt was 2.8 percent in 2004, compared with 2.9 percent in 2003 (2002 – 2.1 percent). On May 6, 2004, the company filed a final short-form shelf prospectus in Canada in connection with the issuance of medium-term notes over the 25-month period that the shelf prospectus remains valid. The unsecured notes will be issued from time to time at the discretion of the company in an aggregate amount not to exceed $1 billion. The company has not issued any notes under this shelf prospectus. Financial percentages, 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 Local currency (DBRS / S&P) (d) 2004 19 83 108 2003 21 64 80 2002 24 46 63 2001 26 26 36 2000 25 23 29 AA/AAA AA/AAA AA/AAA AA/AAA AA/AAA (a) Current and long-term portions of debt (page 39), divided by debt and shareholders’ equity (page 39). (b) Net income (page 37), debt-related interest before capitalization (page 56, note 15) and income taxes (page 37) divided by debt-related interest before capitalization. (c) Cash flow from net income adjusted for the cumulative effect of accounting change and other non-cash items (page 38), current income tax expense (page 47, note 4) and debt-related interest before capitalization (page 56, note 15) divided by debt-related interest before capitalization. (d) Dominion Bond Rating Service (DBRS) and Standard & Poor’s Corporation (S&P) are debt-rating agencies. The company’s financial strength, as evidenced by the above financial ratios, represents a competitive advantage of strategic importance. The company’s sound financial position gives it the opportunity to access the world’s capital markets in the full range of market conditions and enables the company to take on large, long-term capital commitments in the pursuit of maximizing shareholder value. Contractual obligations To more fully explain Imperial’s financial position, the following table shows the company’s contractual obligations outstanding at December 31, 2004. It brings together, for easier reference, data from the consolidated balance sheet and from individual notes to the consolidated financial statements. 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) Financial statement note reference Note 3 Note 12 Note 12 Note 12 Note 7 Note 8 Note 12 Payment due by period 2006 to 2009 334 – 181 168 52 91 116 378 2010 and beyond 33 – 91 55 – 297 176 198 Total amount 1 362 56 334 325 171 759 328 817 2005 995 56 62 102 119 371 36 241 (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 $171 million at the end of 2004, compared with $189 million at year-end 2003. The largest commitment outstanding at year-end 2004 was associated with the company’s share of upstream capital projects of $112 million at Syncrude and offshore Canada’s East Coast. (c) The amount by which accumulated benefit obligations (ABO) exceeded the fair value of fund assets at year-end (page 48, note 7). For funded pension plans, this difference was $446 million at December 31, 2004. For unfunded plans, this was the ABO amount of $313 million. The payments by period include expected contributions to funded pension plans in 2005 and estimated benefit payments for unfunded plans in all years. (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. 28 Annual report 2004 The company was contingently liable at December 31, 2004, for a maximum of $175 million relating to guarantees for purchasing operating equipment and other assets from its rural marketing associates upon expiry of the associate agreement or the death or resignation of the associate. The company expects that the fair value of the operating equipment and other assets so purchased would cover the maximum potential amount of future payments under the guarantees. Various lawsuits are pending against Imperial Oil Limited and its subsidiaries. Based on a consideration of all relevant facts and circumstances, the company does not believe the ultimate outcome of any currently pending lawsuits against the company will have a material, adverse effect upon the company’s operations or financial condition. There are no events or uncertainties known to management beyond those already included in reported financial information that would indicate a material change in future operating results or financial condition. Recently issued Statement of Financial Accounting Standards In December 2004, the Financial Accounting Standards Board (FASB) issued a revised Statement of Financial Accounting Standards No. 123 (SFAS 123R), Share-based Payments. SFAS 123R requires compensation costs related to share-based payment arrangements to employees to be recognized in the income statement over the period that an employee provides service in exchange for the award. The amount of the compensation cost will be measured based on the grant-date fair value of the instruments issued. In addition, liability awards will be remeasured each reporting period through settlement. SFAS 123R is effective as of July 1, 2005, for all awards granted or modified after that date and for those awards granted prior to that date for which the requisite employee service has not yet been rendered. SFAS 123R will have no impact on the company because in 2003 the company adopted a policy of expensing all share-based payments that is consistent with the provisions of SFAS 123R and the requisite employee service for all prior year outstanding stock options has been rendered. Emerging accounting and reporting issues Accounting for purchases and sales of inventory with the same counterparty At its November 2004 meeting, the Emerging Issues Task Force (EITF) of FASB began discussion of Issue 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty.” This Issue addresses the question of when it is appropriate to measure purchases and sales of inventory at fair value and record them in cost of sales and revenues and when they should be recorded as an exchange measured at the book value of the item sold. The EITF did not reach a consensus on this issue, but requested the FASB staff to further explore the alternative views. The company records certain purchases and sales entered into contemporaneously with the same counterparty as cost of sales and revenues, measured at fair value as agreed upon by a willing buyer and a willing seller. These transactions occur under contractual arrangements that establish the agreement terms either jointly, in a single contract, or separately, in individual contracts. Should the EITF reach a consensus on this issue requiring these transactions to be recorded as exchanges measured at book value, the reported amounts in “operating revenues” and “purchases of crude oil and products” on the consolidated statement of income would be lower by equal amounts with no impact on net income. The company has not yet determined the amount by which “operating revenues” and “purchases of crude oil and products” would be lower under this interpretation. A special effort is needed to identify purchase/sale transactions from other monetary purchases and monetary sales. A best effort estimate based on this undertaking is expected to be available in the second quarter of 2005. The company will disclose this information, if material, once it is available. Critical accounting policies The company’s financial statements have been prepared in accordance with United States generally accepted accounting principles (GAAP) and include estimates that reflect management’s best judgments. The company’s accounting and financial reporting fairly reflect its straightforward business model. 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 41 to 43. Imperial Oil Limited 2 9 Management’s discussion and analysis of financial condition and results of operations (continued) Hydrocarbon reserves Proved oil, gas and synthetic crude oil reserve quantities are used as the basis of calculating unit-of-production rates for depreciation and evaluating for impairment. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs and deposits under existing economic and operating conditions. Estimates of synthetic crude oil reserves are based on detailed geological and engineering assessments of in-place crude bitumen volume, the mining plan, historical extraction recovery and upgrading yield factors, installed plant operating capacity and operating approval limits. The estimation of proved reserves is controlled by the company through long-standing approval guidelines. Reserve changes are made with a well-established, disciplined process driven by senior-level geoscience and engineering professionals (assisted by a central reserves group with significant independent technical experience), culminating in reviews with and approval by senior management and the company’s board of directors. Key features of the estimation include rigorous peer-reviewed technical evaluations and analysis of well and field performance information, and a requirement that management make a commitment toward the development of the reserves prior to booking. Notably, technical and other professionals involved in the process are not compensated based on the levels of proved reserves bookings. Although the company is reasonably certain that proved reserves will be produced, the timing and ultimate recovery can be affected by a number of factors, including completion of development projects, reservoir performance and significant changes in long-term oil and gas price levels. In compliance with the United States Securities and Exchange Commission regulatory guidance, the company has reported 2004 reserves on the basis of the day of December 31, 2004, prices and costs (”year-end prices”). Resultant changes in Cold Lake bitumen and the associated natural gas reserves from the year-end 2003 estimates, which were based on long-term projections of oil and gas prices consistent with those used in the company’s investment decision-making process, are shown in the line titled ”Year-end price/cost revisions” on page 59. The requirement to use year-end prices for reserves estimation introduces single-day price focus and volatility in the valuation of reserves to be produced over the next 20 to 30 years. The company believes that this approach is inconsistent with the long-term nature of the natural resources business. The use of prices from a single date is not relevant to the investment decisions made by the company, and annual variations in reserves based on such year-end prices are not of consequence in how the business is managed. The impact of year-end prices on reserves estimation is most clearly shown at Cold Lake, where proved bitumen and associated natural gas reserves were reduced by about 485 million oil-equivalent barrels as a result of using December 31, 2004, prices, which were unusually low. Prices of Cold Lake bitumen were strong for most of 2004, however, they began to deteriorate in the middle of the fourth quarter and ended on December 31, 2004, 70 percent below the year’s average. Prices quickly rebounded from December 31, and through January 2005 returned to levels that have restored the reserves to the proved category. Performance-related revisions can include upward or downward changes in previously estimated volumes of proved reserves for existing fields due to the evaluation or revaluation of (1) already available geologic, reservoir or production data, or (2) new geologic or reservoir data. Performance-related revisions can also include changes associated with the performance of improved recovery projects and significant changes in either development strategy or production equipment/facility capacity. The company uses the successful-efforts method to account for its exploration and production activities. Under this method, costs are accumulated on a field-by-field basis with certain exploratory expenditures and exploratory dry holes being expensed as incurred. The company continues to carry as an asset the cost of drilling exploratory wells that find sufficient quantities of reserves to justify their completion as producing wells if the required capital expenditure is made and drilling of additional exploratory wells is underway or firmly planned for the near future. Once exploration activities demonstrate that sufficient quantities of commercially producible reserves have been discovered, continued capitalization is dependent on project reviews, which take place at least annually, to ensure that satisfactory progress toward ultimate development of the reserves is being achieved. Exploratory well costs not meeting these criteria are charged to expense. Capitalized exploratory drilling costs pending the determination of proved reserves or the amount of suspended exploratory well costs were negligible, $2 million and $13 million at December 31, 2004, 2003 and 2002 respectively. Costs of productive wells and development dry holes are capitalized and amortized on the unit-of-production method for each field. The company uses this accounting policy instead of the full-cost method because it provides a more timely accounting of the success or failure of the company’s exploration and production activities. Impact of reserves on depreciation The calculation of unit-of-production depreciation is a critical accounting estimate that measures the depreciation of natural resources assets. It is the ratio of (1) actual volumes produced to (2) total proved developed reserves (those reserves recoverable through existing wells with existing equipment and operating methods) applied to (3) the asset cost. The volumes produced and asset cost are known and, while proved developed reserves have a high probability of recoverability, they are based on estimates 30 Annual report 2004 that are subject to some variability. This variability has generally resulted in net upward revisions of proved reserves in existing fields, as more information becomes available through research and production. Revisions have averaged 16 million oil-equivalent barrels per year over the last five years and have resulted from effective reservoir management and the application of new technology. While the upward revisions the company has made over the last five years are an indicator of variability, they have had little impact on the unit-of-production rates of depreciation because they have been small compared to the large proved reserves base. Impact of reserves and prices on testing for impairment Proved oil and gas properties held and used by the company are reviewed for impairment whenever events or circumstances indicate that the carrying amounts may not be recoverable. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. The company estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. In general, impairment analyses are based on proved reserves. Where probable reserves exist, an appropriately risk-adjusted amount of these reserves may be included in the impairment evaluation. An asset would be impaired if the undiscounted cash flows were less than its carrying value. Impairments are measured by the amount by which the asset’s carrying value exceeds its fair value. The impairment evaluation triggers include a significant decrease in current and projected prices or reserve volumes, an accumulation of project costs significantly in excess of the amount originally expected, and historical and current negative operating losses. In general, the company does not view temporarily low oil prices as a triggering event for conducting impairment tests. The markets for crude oil and natural gas have a history of significant price volatility. Although prices will occasionally drop precipitously, the relative growth/decline in supply versus demand will determine industry prices over the long term and these cannot be accurately predicted. Accordingly, any impairment tests that the company performs make use of the company’s long-term price assumptions for crude oil and natural gas markets, petroleum products and chemicals. These are the same price assumptions that are used in the company’s annual planning and budgeting processes and are also used for capital investment decisions. The standardized measure of discounted future cash flows on page 58 is based on the year-end 2004 price applied for all future years, as required under Statement of Financial Accounting Standards No. 69 (SFAS 69). Future prices used for any impairment tests will vary from the one used in the SFAS 69 disclosure and could be lower or higher for any given year. Retirement benefits The company’s pension plan is managed in compliance with the requirements of governmental authorities and meets funding levels as determined by independent third-party actuaries. Pension accounting requires explicit assumptions regarding, among others, the discount rate for the benefit obligations, the expected rate of return on plan assets and the long-term rate of future compensation increases. All pension assumptions are reviewed annually by senior management. These assumptions are adjusted only as appropriate to reflect long-term changes in market rates and outlook. The long-term expected rate of return on plan assets of 8.25 percent used in 2004 compares to actual returns of 10.7 percent and 10.1 percent achieved over the last 10- and 20-year periods ending December 31, 2004. If different assumptions are used, the expense and obligations could increase or decrease as a result. The company’s potential exposure to changes in assumptions is summarized in note 7 to the consolidated financial statements on page 51. 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 2004. Asset retirement obligations and other environmental liabilities Legal obligations associated with site restoration on the retirement of assets with determinable useful lives are recognized when they are incurred, which is typically at the time the assets are installed. The obligations are initially measured at fair value and discounted to present value. Over time, the discounted asset retirement obligation amount will be accreted for the change in its present value, with this effect included in operating expense. As payments to settle the obligations occur on an ongoing basis and will continue over the lives of the operating assets, which can exceed 25 years, the discount rate will be adjusted only as appropriate to reflect long-term changes in market rates and outlook. For 2004, the obligations were discounted at six percent and the accretion expense was $22 million, which was significantly less than one percent of total expenses in the year. There would be no material impact on the company’s reported financial results if a different discount rate had been used. Asset retirement obligations are not recognized for assets with an indeterminate useful life. For these and non-operating assets, the company accrues provisions for environmental liabilities when it is probable that obligations have been incurred and the amount can be reasonably estimated. Imperial Oil Limited 3 1 Management’s discussion and analysis of financial condition and results of operations (continued) 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. Although the government of Canada in ratifying the Kyoto Protocol agreed to restrictions of greenhouse-gas emissions by the period 2008-2012, it has not determined what measures it will impose on companies. Consequently, attempts to assess impact on Imperial can only be speculative. The company will continue to monitor the development of legal requirements in this area. The company’s size, strong financial position and the complementary nature of its natural resources, petroleum products and chemicals segments help mitigate the company’s exposure to changes in these other risks. The company’s potential exposure to these types of risk is summarized in the table below. The company does not use derivative markets to speculate on the future direction of currency or commodity prices and does not sell forward any part of production from any business segment. The following table shows the estimated annual effect, under current conditions, of certain sensitivities of the company’s after-tax net income. Earnings sensitivities (a) millions of dollars after tax Four 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 + (–) + (–) + (–) + (–) + (–) + (–) $ 200 $ 20 $ 170 7 $ $ 2 $ 260 (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 2004. Each sensitivity calculation shows the impact on net income that results from a change in one factor, after tax and royalties and holding all other factors constant. While these sensitivities are applicable under current conditions, they may not apply proportionately to larger fluctuations. The sensitivity of net income to changes in the Canadian dollar versus the U.S. dollar decreased from year-end 2003 by about $10 million (after tax) a year for each one-cent change. This is primarily due to the unusually low year-end prices for Cold Lake bitumen, which is sold in U.S. dollars. Frequently used financial terms 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. 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 whole 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 equity company debt Total capital employed 2004 2003 2002 14 027 12 337 12 003 (3 582) (2 680) 56 7 821 (2 817) (2 543) 52 7 029 (2 671) (2 883) 49 6 498 32 Annual report 2004 millions of dollars Total company sources: debt and equity perspective Short-term debt and current portion of long-term debt Long-term debt Shareholders’ equity Add: Imperial’s share of equity company debt Total capital employed 2004 1 076 367 6 322 56 7 821 2003 573 859 5 545 52 7 029 2002 72 1 466 4 911 49 6 498 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 net income divided by average business-segment capital employed (an average of the beginning- and end-of-year amounts). Segment net income includes Imperial’s share of segment net income of equity companies, consistent with the definition used for capital employed, and excludes the cost of financing. The company’s total ROCE is net income 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 in a capital-intensive, long-term industry to both evaluate management’s performance and demonstrate to shareholders that capital has been used wisely over the long term. millions of dollars Net income Financing costs (after tax), including Imperial’s share of equity companies Net income excluding financing costs Average capital employed Return on average capital employed (percent) 2004 2 052 3 2 055 7 425 27.7 2003 1 705 3 1 708 6 764 25.3 2002 1 214 15 1 229 6 141 20.0 Operating costs Operating costs are the combined total of production, manufacturing, selling, general, exploration, depreciation and depletion expenses from the consolidated statement of income 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 energy costs, 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 income, operating costs, as defined below, represent the expenses most directly under management’s control. millions of dollars Expenses (from page 37) Exploration Production and manufacturing Selling and general Depreciation and depletion Subtotal Imperial’s share of equity company expenses Total operating costs 2004 59 2 883 1 218 908 5 068 52 5 120 2003 55 2 782 1 269 755 4 861 56 4 917 2002 30 2 320 1 222 708 4 280 49 4 329 Cash flow from operating activities and asset sales Cash flow from operating activities and asset sales is the sum of the net cash provided by operating activities and proceeds from asset sales reported in the consolidated statement of cash flows. This cash flow is the total source of cash both from operating the company’s assets and from the divesting of assets. The company employs a long-standing, disciplined regular review process to ensure that all assets are contributing to the company’s strategic and financial objectives. Assets are divested when they no longer meet these objectives or are worth considerably more to others. Because of the regular nature of this activity, management believes it is useful for investors to consider sales proceeds together with cash provided by operating activities when evaluating cash available for investment in the business and financing activities, including shareholder distributions. millions of dollars Cash from operating activities Proceeds from asset sales Total cash flow from operating activities and asset sales 2004 3 312 102 3 414 2003 2 227 56 2 283 2002 1 688 61 1 749 Imperial Oil Limited 3 3 Management’s discussion and analysis of financial condition and results of operations (continued) Supplemental information based on generally accepted accounting principles (GAAP) in Canada The company’s financial summary and management’s discussion and analysis, under Canadian GAAP, are not materially different from those reported under U.S. GAAP as shown on pages 20 to 33, except for the following: Financial summary millions of dollars Net income by segment: Natural resources Petroleum products Chemicals Corporate and other Net income Total assets Other long-term obligations Capital employed Cash flow from operating activities and asset sales Per-share information (dollars) Net income per share – basic Net income per share – diluted 2004 1 487 500 100 (54) 2 033 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 13 992 12 361 11 894 10 781 11 244 1 010 8 137 3 380 5.70 5.69 972 7 262 2 250 4.52 4.52 1 207 6 803 1 737 3.23 3.23 1 098 5 841 2 050 3.19 3.19 1 104 5 635 2 363 3.38 3.38 Results of operations Net income in 2004 was $2,033 million or $5.69 a share – the best year on record – compared with $1,682 million or $4.52 a share in 2003 (2002 – $1,224 million or $3.23 a share). Higher realizations for crude oil, stronger industry refining and petrochemical margins, and higher volumes of Syncrude production, natural gas and petroleum products contributed positively to net income, partly offset by lower marketing margins. Compared with 2003, these favourable operating results were partly offset by the combined negative effects of a higher Canadian dollar on resource and product prices of about $260 million, the absence of favourable foreign-exchange effects on the company’s U.S.-dollar-denominated debt of about $110 million and lower benefits from tax matters of about $100 million. The return on average capital employed was 26 percent, compared with 24 percent in 2003 (2002 – 20 percent). Natural resources Net income from natural resources was $1,487 million, up from $1,139 million in 2003 (2002 – $1,056 million). The positive earnings effects of improved realizations for crude oil and natural gas, combined with higher Syncrude, natural gas and natural gas liquids (NGLs) volumes, were partly offset by lower Cold Lake bitumen production, lower benefits from tax matters and the negative effects of a higher Canadian dollar. Return on average capital employed was 39 percent for the natural resources segment, compared with 32 percent in 2003 (2002 – 36 percent), reflecting higher net income. Financial statistics millions of dollars Net income Capital employed at December 31 Return on average capital employed (percent) 2004 1 487 3 920 38.6 2003 1 139 3 784 32.0 2002 1 056 3 325 35.8 2001 957 2 580 40.5 2000 1 177 2 142 51.0 34 Annual report 2004 Petroleum products Return on average capital employed was 18 percent for the petroleum products segment, compared with 16 percent in 2003 (2002 – six percent). Financial statistics millions of dollars Capital employed at December 31 Return on average capital employed (percent) 2004 2 660 18.4 2003 2 784 15.5 2002 2 484 5.5 2001 2 148 15.9 2000 2 280 13.9 Chemicals Return on average capital employed was 41 percent for the chemicals segment, compared with 18 percent in 2003 (2002 – 28 percent). Financial statistics millions of dollars Capital employed at December 31 Return on average capital employed (percent) 2004 242 41.0 2003 246 17.5 2002 178 27.9 2001 195 13.7 2000 140 53.4 Corporate and other Net income from corporate and other accounts was negative $54 million in 2004, compared with positive $99 million in 2003 (2002 – negative $11 million). Lower net income in 2004 was mainly due to the absence of the favourable foreign-exchange effects on the company’s U.S.-dollar-denominated debt, which was replaced with Canadian-dollar-denominated debt in June and July of 2003. Net income for 2004 also included a non-recurring after-tax writedown of $42 million on a north Toronto property, which was acquired in 1991 to be the company’s future Toronto headquarters site. The remeasurement at fair value of this property reflected a change in intended use of the property and management’s commitment to sell following the announcement of the relocation of the company’s headquarters to Calgary. Capital and exploration expenditures Total capital and exploration expenditures were $1,411 million in 2004, down slightly from $1,526 million in 2003 (2002 – $1,600 million). Imperial Oil Limited 3 5 Management 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 accounting principles generally accepted in the United States of America and Canada and include certain estimates that reflect management’s best judgments. Financial information contained throughout this annual report is consistent with the financial statements prepared under United States generally accepted accounting principles. Supplemental information based on Canadian generally accepted accounting principles is provided on page 34. 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 Auditors’ report To the shareholders of Imperial Oil Limited We have audited the consolidated balance sheets of Imperial Oil Limited as at December 31, 2004 and 2003 and the consolidated statements of income, cash flows and shareholders’ equity for each of the three years in the period ended December 31, 2004. 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. 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. T.J. Hearn P.A. Smith February 16, 2005 In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the company as at December 31, 2004 and 2003 and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004 in accordance with accounting principles generally accepted in the United States of America and Canada. Chartered Accountants Toronto, Ontario February 16, 2005 36 Annual report 2004 Consolidated statement of income millions of Canadian dollars For the years ended December 31 Revenues Operating revenues (a) Investment and other income (note 11) Total revenues Expenses Exploration Purchases of crude oil and products Production and manufacturing Selling and general Federal excise tax (a) Depreciation and depletion Financing costs (note 15) Total expenses Under United States GAAP 2004 2002 2003 Under Canadian GAAP 2003 2004 2002 22 408 52 22 460 59 13 094 2 883 1 218 1 264 908 7 19 433 19 094 114 19 208 55 10 823 2 782 1 269 1 254 755 (120) 16 818 16 890 152 17 042 30 9 723 2 320 1 222 1 231 708 20 15 254 22 408 52 22 460 59 13 094 2 883 1 218 1 264 903 41 19 462 19 094 114 19 208 55 10 823 2 782 1 269 1 254 750 (87) 16 846 16 890 152 17 042 30 9 723 2 297 1 222 1 231 705 32 15 240 Income before income taxes 3 027 2 390 1 788 2 998 2 362 1 802 Income taxes (note 4) Income before cumulative effect of accounting change Cumulative effect of accounting change, after income tax 975 689 574 965 680 578 2 052 1 701 1 214 2 033 1 682 1 224 4 – – – Net income (note 2) 2 052 1 705 1 214 2 033 1 682 1 224 (a) Operating revenues include federal Per-share information (dollars) Net income per common share – basic (note 13) Income before cumulative effect of accounting change Cumulative effect of accounting change, after income tax Net income (note 2) Net income per common share – diluted (note 13) Income before cumulative effect of accounting change Cumulative effect of accounting change, after income tax Net income (note 2) Dividends 5.75 – 5.75 5.74 – 5.74 0.88 4.57 0.01 4.58 4.57 0.01 4.58 0.87 3.20 – 3.20 3.20 – 3.20 0.84 5.70 5.70 5.69 5.69 0.88 4.52 – 4.52 4.52 – 4.52 0.87 3.23 – 3.23 3.23 – 3.23 0.84 excise tax of $1,264 million (2003 – $1,254 million, 2002 – $1,231 million). The information on pages 41 through 56 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. Imperial Oil Limited 3 7 Consolidated statement of cash flows millions of Canadian dollars, inflow/(outflow) For the years ended December 31 Operating activities Net income Cumulative effect of accounting change, after tax Adjustments for non-cash items: Depreciation and depletion (Gain)/loss on asset sales, after tax Deferred income taxes and other Changes in operating assets and liabilities: Accounts receivable Inventories and prepaids Income taxes payable Accounts payable All other items – net (a) Cash from operating activities (note 2) Investing activities Additions to property, plant and equipment and intangibles Proceeds from asset sales Loans to equity company Cash from/(used in) investing activities (note 2) 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 13) Dividends paid Cash from/(used in) financing activities Increase/(decrease) in cash Cash at beginning of year Cash at end of year (b) (a) Includes contribution to registered pension plans of $114 million (2003 – $511 million, 2002 – $19 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 41 through 56 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. Under United States GAAP 2004 2002 2003 Under Canadian GAAP 2002 2003 2004 2 052 – 908 (32) (90) (311) (32) 462 308 47 3 312 (1 376) 102 (32) (1 306) 9 – (8) 13 (872) (317) (1 175) 831 448 1 279 1 705 (4) 755 (10) (59) 33 31 38 74 (336) 2 227 (1 482) 56 – (1 426) – 818 (818) 2 (799) (322) (1 119) (318) 766 448 1 214 – 708 (4) (148) (356) 51 (225) 323 125 1 688 (1 564) 61 – (1 503) (388) 500 (71) – (13) (319) (291) (106) 872 766 2 033 – 903 (32) (100) (311) (32) 462 308 47 3 278 (1 342) 102 (32) (1 272) 9 – (8) 13 (872) (317) (1 175) 831 448 1 279 1 682 – 750 (10) (68) 33 31 38 74 (336) 2 194 (1 449) 56 – (1 393) – 818 (818) 2 (799) (322) (1 119) (318) 766 448 1 224 – 705 (4) (144) (356) 51 (225) 323 102 1 676 (1 552) 61 – (1 491) (388) 500 (71) – (13) (319) (291) (106) 872 766 38 Annual report 2004 Consolidated balance sheet millions of Canadian dollars At December 31 Assets Current assets Cash Accounts receivable, less estimated doubtful amounts Inventories of crude oil and products (note 14) Materials, supplies and prepaid expenses Deferred income tax assets (note 4) Total current assets Investments and other long-term assets (note 2) Property, plant and equipment, less accumulation, depreciation and depletion (notes 1, 2) Goodwill (note 1) Other intangible assets, net (note 2) Total assets (notes 1, 2) Liabilities Current liabilities Short-term debt Accounts payable and accrued liabilities (note 16) Income taxes payable Current portion of long-term debt Total current liabilities Long-term debt (note 3) Other long-term obligations (notes 2, 8) Deferred income tax liabilities (notes 2, 4) Commitments and contingent liabilities (note 12) Total liabilities Shareholders’ equity Common shares at stated value (note 13) Earnings reinvested (note 2) Accumulated other nonowner changes in equity (note 2) Total shareholders’ equity Under United States GAAP 2004 2003 Under Canadian GAAP 2003 2004 1 279 1 626 432 112 448 3 897 130 9 647 204 149 14 027 81 2 525 1 057 995 4 658 367 1 525 1 155 448 1 315 407 105 353 2 628 97 9 267 204 141 12 337 72 2 222 595 501 3 390 859 1 314 1 229 1 279 1 626 432 112 448 3 897 270 9 569 204 52 13 992 81 2 525 1 057 995 4 658 367 1 010 1 319 448 1 315 407 105 353 2 628 259 9 218 204 52 12 361 72 2 222 595 501 3 390 859 972 1 362 7 705 6 792 7 354 6 583 1 801 4 889 (368) 6 322 1 859 3 952 (266) 5 545 1 801 4 837 – 6 638 1 859 3 919 – 5 778 Total liabilities and shareholders’ equity (note 2) 14 027 12 337 13 992 12 361 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 41 through 56 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. Imperial Oil Limited 3 9 Consolidated statement of shareholders’ equity millions of Canadian dollars At December 31 Common shares at stated value (note 13) At beginning of year Issued under the stock option plan Share purchases at stated value At end of year Earnings reinvested At beginning of year Net income for the year Share purchases in excess of stated value Dividends At end of year Accumulated other nonowner changes in equity At beginning of year Minimum pension liability adjustment (note 7) At end of year Under United States GAAP 2004 2002 2003 Under Canadian GAAP 2003 2004 2002 1 859 13 (71) 1 801 3 952 2 052 (801) (314) 4 889 (266) (102) (368) 1 939 2 (82) 1 859 3 287 1 705 (717) (323) 3 952 (315) 49 (266) 1 941 – (2) 1 939 2 402 1 214 (11) (318) 3 287 (77) (238) (315) 1 859 13 (71) 1 801 3 919 2 033 (801) (314) 4 837 – – – 1 939 2 (82) 1 859 3 277 1 682 (717) (323) 3 919 – – – 1 941 – (2) 1 939 2 382 1 224 (11) (318) 3 277 – – – Shareholders’ equity at end of year 6 322 5 545 4 911 6 638 5 778 5 216 The information on pages 41 through 56 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. Nonowner changes in equity for the year Net income for the year Other nonowner changes in equity (note 7) Total nonowner changes in equity for the year 2 052 (102) 1 950 1 705 49 1 754 1 214 (238) 976 40 Annual report 2004 Summary of significant accounting policies The company’s principal business is energy, involving the exploration, production, transportation and sale of crude oil and natural gas and the manufacture, transportation and sale of petroleum products. Imperial is also a major manufacturer and marketer of petrochemicals. The consolidated financial statements have been prepared in accordance with generally accepted accounting principles (GAAP) in the United States of America. A description of the differences between GAAP in Canada and in the United States as they apply to the company, including a reconciliation of net income, cash flows and impacted balance sheet line items, is provided in note 2. The financial statements include certain estimates that reflect management’s best judgment. All amounts are in Canadian dollars unless otherwise indicated. 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 share of undivided interest in such activities, including its 25-percent interest in the Syncrude joint venture and its nine-percent interest in the Sable offshore energy project. Segment 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. The above functions have been defined as the operating segments of the company because they are the segments (a) that engage in business activities from which revenues are earned and expenses are incurred; (b) whose operating results are regularly reviewed by the company’s chief operating decision-maker to make decisions about resources to be allocated to the segment and assess its performance; and (c) for which discrete financial information is available. Corporate and other includes assets and liabilities that do not specifically relate to business segments – primarily cash and long-term debt. Net income in this segment primarily includes financing costs and interest income. Segment accounting policies are the same as those described in this summary of significant accounting policies. Natural resources, petroleum products and chemicals expenses include amounts allocated from the ”corporate and other” segment. The allocation is based on a combination of fee for service, proportional segment expenses and a three-year average of capital expenditures. Transfers of assets between segments are recorded at book amounts. Items included in capital employed that are not identifiable by segment are allocated according to their nature. 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 income. Other investments are recorded at cost. Dividends from these other investments are included in ”investment and other income.” These investments represent interests in non-publicly traded pipeline companies that facilitate the sale and purchase of crude oil and natural gas in the conduct of company operations. Other parties who also have an equity interest in these companies share in the risks and rewards according to their percentage of ownership. Imperial does not invest in these companies in order to remove liabilities from its balance sheet. Property, plant and equipment Property, plant and equipment is recorded at cost. Investment tax credits and other similar grants are treated as a reduction of the capitalized cost of the asset to which they apply. The company uses the successful-efforts method to account for its exploration and production activities. Under this method, costs are accumulated on a field-by-field basis with certain exploratory expenditures and exploratory dry holes being expensed as incurred. The company continues to carry as an asset the cost of drilling exploratory wells that find sufficient quantities of reserves to justify their completion as producing wells if the required capital expenditure is made and drilling of additional exploratory wells is underway or firmly planned for the near future. Once exploration activities demonstrate that sufficient quantities of commercially producible reserves have been discovered, continued capitalization is dependent on project reviews, which take place at least annually, to ensure that satisfactory progress toward ultimate development of the reserves is being achieved. Exploratory well costs not meeting these criteria are charged to expense. Costs of productive wells and development dry holes are capitalized and amortized on the unit-of-production method for each field. The company uses this accounting policy instead of the full-cost method because it provides a more timely accounting of the success or failure of the company’s exploration and production activities. Imperial Oil Limited 4 1 Summary of significant accounting policies (continued) Maintenance and repair costs, including planned major maintenance, are expensed as incurred. Improvements that increase the capacity or prolong the service life 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. These costs, sometimes referred to as lifting costs, include such items as labour costs to operate the wells and related equipment; repair and maintenance costs on the wells and equipment; materials, supplies and energy costs required to operate the wells and related equipment; and administrative expenses related to the production activity. 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 based on proved developed reserves. 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 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 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 that are developed annually and also used for investment evaluation purposes. In general, impairment analyses are based on proved reserves. Where probable reserves exist, an appropriately risk-adjusted amount of these reserves may be included in the impairment evaluation. An asset would be impaired if the undiscounted cash flows were less than its carrying value. Impairments are measured by the amount by which the asset’s carrying value exceeds its fair value. Gains or losses on assets sold are included in ”investment and other income” in the consolidated statement of income. Interest capitalization Interest costs relating to major capital projects under construction are capitalized as part of property, plant and equipment. Capitalization of interest ceases when the property, plant and equipment is substantially complete and ready for its intended use. 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 income. 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, because such potential obligations cannot be measured since it is not possible to estimate the settlement dates. 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. These liabilities are not discounted. 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 net income. Financial instruments The fair values of cash, 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 the company’s other financial instruments, which are mainly long-term receivables, are estimated primarily by discounting future cash flows, using current rates for similar financial instruments under similar credit risk and maturity conditions. 42 Annual report 2004 The company does not use financing structures for the purpose of altering accounting outcomes or removing debt from the balance sheet. The company does not use derivative instruments to speculate on the future direction of currency or commodity prices and does not sell forward any part of production from any business segment. 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 income. Delivery costs from final storage to customer are recorded as a marketing expense in selling and general expenses. Revenues include the sales portion of certain transactions where the company contemporaneously negotiates purchases with the same counterparty under contractual arrangements that establish the agreement terms either jointly, in a single contract, or separately in individual contracts. The purchases are recorded in “purchases of crude oil and products.” These transactions are commonly called purchase/sale transactions. Together with non-monetary exchanges as well as independently transacted purchases and sales, purchase/sale transactions are used to ensure that the right crude oil is at the appropriate refineries at the right time and the appropriate products are available to meet consumer demands. Each purchase/sale transaction is composed of a separate purchase and a separate sale transaction and therefore is accounted for as any other independently transacted monetary purchase or sale, measured at fair value as agreed upon by a willing buyer and a willing seller. They are entered into with our normal suppliers and customers for substantive business purposes and physical delivery is required. The characteristics of these transactions are indistinguishable from those of any other monetary sales transaction. This accounting practice has recently been addressed in EITF Issue 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not Held for Trading Purposes as Defined in Issue No. 02-3.” While Issue 03-11 addresses the issue of gross versus net classification for derivative instruments, it also provides guidance for purchase/sale transactions that are not accounted for as derivative instruments. In Issue 03-11, the EITF concluded that the determination of whether contracts not held for trading purposes should be reported in the income statement on a gross or net basis is a matter of judgment that depends on the relevant facts and circumstances. In the judgment of management, the relevant facts and circumstances support accounting for these transactions in revenues, measured at fair value. 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 liabilities incurred and is recorded in the consolidated statement of income over the vesting period. The fair value of liabilities is remeasured at the end of each reporting period through settlement. As permitted by the Statement of Financial Accounting Standards No.123 (SFAS 123), 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. If the provisions of SFAS 123 had been adopted for all prior years, net income and net income per share would have been as follows: millions of dollars Net income as shown in financial statements Add: stock-based compensation expense as reported, net of tax Deduct: stock-based compensation expense, net of tax, determined under fair-value-based method Pro forma net income Net income per share (dollars) As reported – basic Pro forma – diluted – basic – diluted Consumer taxes 2004 2 052 84 (86) 2 050 5.75 5.74 5.74 5.73 2003 1 705 76 (81) 1 700 4.58 4.58 4.57 4.57 2002 1 214 24 (41) 1 197 3.20 3.20 3.16 3.16 Taxes levied on the consumer and collected by the company are excluded from the consolidated statement of income. These are primarily provincial taxes on motor fuels and the federal goods and services tax. Imperial Oil Limited 4 3 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 Production and manufacturing Selling and general (d) Federal excise tax Depreciation and depletion Financing costs (note 15) Total expenses Income before income taxes Income taxes (note 4) Current Deferred Total income tax expense Income before cumulative effect of accounting change Cumulative effect of accounting change, after income tax Net income Capital and exploration expenditures (e) Property, plant and equipment Cost Accumulated depreciation and depletion Net property, plant and equipment (f) (g) Total assets (h) millions of dollars Revenues External sales (c) Intersegment sales Investment and other income Total revenues Expenses Exploration Purchases of crude oil and products Production and manufacturing Selling and general (d) Federal excise tax Depreciation and depletion Financing costs (note 15) Total expenses Income before income taxes Income taxes (note 4) Current Deferred Total income tax expense Income before cumulative effect of accounting change Cumulative effect of accounting change, after income tax Net income Capital and exploration expenditures (e) Property, plant and equipment Cost Accumulated depreciation and depletion Net property, plant and equipment (f) (g) Total assets (h) Natural resources (a) 2002 2003 2004 Petroleum products 2004 2003 2002 3 689 2 891 45 6 625 59 2 110 1 608 27 – 633 1 4 438 2 187 3 390 2 224 34 5 648 55 1 873 1 577 28 – 517 1 4 051 1 597 2 573 2 217 104 4 894 30 1 599 1 228 21 – 477 1 3 356 1 538 763 (63) 700 535 (77) 458 517 (21) 496 1 487 1 139 1 042 – 1 487 1 113 13 538 7 337 6 201 6 875 4 1 143 1 007 12 610 6 813 5 797 6 418 – 1 042 986 11 612 6 269 5 343 6 013 17 503 1 666 42 19 211 – 14 769 1 092 1 098 1 264 257 2 18 482 729 299 (70) 229 500 – 500 283 14 710 1 294 54 16 058 – 11 822 1 054 1 123 1 254 211 2 15 466 592 66 119 185 407 – 407 478 13 362 1 038 34 14 434 – 10 781 954 1 076 1 231 203 1 14 246 188 172 (111) 61 127 – 127 589 6 078 2 959 3 119 5 570 6 069 2 856 3 213 5 290 5 827 2 867 2 960 5 127 Corporate and other 2004 2003 2002 Chemicals 2003 994 238 – 1 232 – 882 153 118 – 22 – 1 175 57 13 7 20 37 – 37 41 609 401 208 440 2002 955 209 – 1 164 – 806 139 115 – 23 – 1 083 81 40 (11) 29 52 – 52 25 579 383 196 428 2004 1 216 293 – 1 509 – 1 064 184 93 – 13 – 1 354 155 59 (4) 55 100 – 100 15 682 459 223 498 Consolidated (b) 2003 2002 2004 – – (35) (35) – – – – – 5 4 9 (44) (18) 9 (9) (35) – (35) 34 205 101 104 1 382 – – 26 26 – – – – – 5 (123) (118) 144 (4) 30 26 118 – 118 33 145 96 49 497 – – 14 14 – – – 10 – 5 18 33 (19) (11) (1) (12) (7) – (7) 12 112 91 21 787 22 408 – 52 22 460 59 13 094 2 883 1 218 1 264 908 7 19 433 3 027 1 103 (128) 975 2 052 – 2 052 1 445 19 094 – 114 19 208 55 10 823 2 782 1 269 1 254 755 (120) 16 818 2 390 610 79 689 1 701 4 1 705 1 559 16 890 – 152 17 042 30 9 723 2 320 1 222 1 231 708 20 15 254 1 788 718 (144) 574 1 214 – 1 214 1 612 20 503 10 856 9 647 14 027 19 433 10 166 9 267 12 337 18 130 9 610 8 520 12 003 44 Annual report 2004 (a) A significant portion of activities in the natural resources segment is conducted jointly with other companies. The segment includes the company’s share of undivided interest in such activities as follows: millions of dollars Total revenues Total expenses Net income, after income tax Total current assets Long-term assets Total current liabilities Other long-term obligations Cash flow from operating activities Cash (used in) investing activities 2004 2 744 1 598 780 367 4 140 948 330 1 188 (858) 2003 2 494 1 577 664 302 3 553 913 322 883 (754) 2002 2 357 1 520 557 321 3 038 669 293 615 (601) (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 expenses 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 2004 4 849 1 4 850 298 2004 1 301 360 791 01 074 56678 3 112 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 (d) Consolidated operating, selling and general expenses include delivery costs from final storage areas to customers of $307 million (2003 – $285 million, 2002 – $216 million). (e) Capital and exploration expenditures of the petroleum products segment include non-cash capital leases of $11 million in 2004 (2003 – $22 million). (f) Includes property, plant and equipment under construction of $1,983 million (2003 – $1,426 million). (g) With the announcement of the relocation of the company’s headquarters to Calgary, management has committed to a plan to sell a piece of property in north Toronto, Ontario, acquired in 1991 to be the future Toronto headquarters site. Consistent with the commitment to sell and considering its unique nature, this property, previously reported in the petroleum products segment, is now shown in the corporate and other segment. This change is effective in 2004. Prior periods have not been revised. (h) Goodwill was not amortized in the past three years. 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. Imperial Oil Limited 4 5 Notes to consolidated financial statements (continued) 2. Differences between United States and Canadian generally accepted accounting principles Effective 2004, the company prepares its financial statements in accordance with the generally accepted accounting principles (GAAP) of the United States. Prior to 2004, the company’s financial statements were prepared in conformity with Canadian GAAP. A reconciliation of the differences between GAAP in Canada and in the United States as they apply to the company is provided below: Consolidated statement of income Net income for 2004 (millions of dollars) Net income per common share (dollars) Basic Diluted Net income for 2003 (millions of dollars) Net income per common share (dollars) Basic Diluted Net income for 2002 (millions of dollars) Net income per common share (dollars) Basic Diluted Consolidated statement of cash flows millions of dollars Cash from operating activities for 2004 Cash from/(used in) investing activities for 2004 Cash from operating activities for 2003 Cash from/(used in) investing activities for 2003 Cash from operating activities for 2002 Cash from/(used in) investing activities for 2002 Consolidated balance sheet millions of dollars As at December 31, 2004 Investments and other long-term assets Property, plant and equipment Other intangible assets Total assets Other long-term obligations Deferred income tax liabilities Earnings reinvested Accumulated other nonowner changes in equity Total liabilities and shareholders’ equity As at December 31, 2003 Investments and other long-term assets Property, plant and equipment Other intangible assets Total assets Other long-term obligations Deferred income tax liabilities Earnings reinvested Accumulated other nonowner changes in equity Total liabilities and shareholders’ equity Reported under U.S. GAAP 2 052 Increase/(decrease) due to Capitalized interest (19) Accounting change – Reported under Canadian GAAP 2 033 5.75 5.74 1 705 4.58 4.58 1 214 3.20 3.20 Reported under U.S. GAAP 3 312 (1 306) 2 227 (1 426) 1 688 (1 503) Reported under U.S. GAAP 130 9 647 149 14 027 1 525 1 155 4 889 (368) 14 027 97 9 267 141 12 337 1 314 1 229 3 952 (266) 12 337 (0.05) (0.05) (19) (0.05) (0.05) (4) (0.01) (0.01) – – (4) (0.01) (0.01) 14 0.04 0.04 Increase/(decrease) due to Capitalized interest (34) 34 (33) 33 (12) 12 Increase/(decrease) due to Capitalized interest Minimum pension liabilities – (78) – (78) – (26) (52) – (78) – (49) – (49) – (16) (33) – (49) 140 – (97) 43 (515) 190 – 368 43 162 – (89) 73 (342) 149 – 266 73 5.70 5.69 1 682 4.52 4.52 1 224 3.23 3.23 Reported under Canadian GAAP 3 278 (1 272) 2 194 (1 393) 1 676 (1 491) Reported under Canadian GAAP 270 9 569 52 13 992 1 010 1 319 4 837 – 13 992 259 9 218 52 12 361 972 1 362 3 919 – 12 361 46 Annual report 2004 Under U.S. GAAP, interest costs related to major capital projects under construction are required to be capitalized as part of property, plant and equipment. Under Canadian GAAP, the company did not capitalize interest costs for the same projects. Under U.S. GAAP, the cumulative effect of accounting change for the adoption of the standard on accounting for asset retirement obligations in 2003 was reflected in the consolidated net income for 2003. Under Canadian GAAP, financial statements of prior periods were restated to reflect the effect of the same accounting change. Under U.S. GAAP, the accumulated benefit obligation (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. Since the amount by which the ABO less the fair value of plan assets was greater than the liability previously recognized in the consolidated balance sheet, an additional minimum pension liability was required. The minimum pension liability has no impact on net income and because this adjustment was non-cash, its effect has been excluded from the accompanying consolidated statement of cash flows. No such adjustment is required under Canadian GAAP. 3. Long-term debt issued 2003 2003 Long-term debt (b) Capital leases (c) Total long-term debt (d) (e) maturity date $250 million due May 26, 2005, and $250 million due August 26, 2005 (a) January 19, 2006 (a) interest rate Variable Variable 2004 2003 millions of dollars – 318 318 49 367 500 318 818 41 859 (a) These are long-term variable-rate loans from Exxon Overseas Corporation, an affiliated company of Exxon Mobil Corporation. (b) Average effective interest rate was 2.5 percent for 2004 (2003 – 2.7 percent). (c) These obligations primarily relate to the capital lease for marine services, which are provided by the lessor commencing in 2004 for a period of 10 years, extendable for an additional five years. The average imputed interest rate was 10.3 percent in 2004 (2003 – 12.7 percent). (d) Principal payments on long-term loans of $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. (e) These amounts exclude that portion of long-term debt, totalling $995 million (2003 – $501 million), which matures within one year and is included in current liabilities. On May 6, 2004, the company filed a final short-form shelf prospectus in Canada in connection with the issuance of medium-term notes over the 25-month period that the shelf prospectus remains valid. The unsecured notes will be issued from time to time at the discretion of the company in an aggregate amount not to exceed $1 billion. The company has not issued any notes under this shelf prospectus. 4. Income taxes millions of dollars Current income tax expense Deferred 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 Enacted tax-rate and tax-law changes Other Effective income tax rate 2004 1 103 (128) 975 37.0 3.9 (7.0) – (1.8) 0.1 32.2 2003 610 79 689 38.5 5.0 (7.5) 0.2 (3.1) (4.3) 28.8 2002 718 (144) 574 42.0 5.4 (11.8) (0.3) (0.9) (2.3) 32.1 (a) The deferred income tax expense for the year is the difference in net deferred income tax liabilities at the beginning and end of the year. The provisions for deferred income taxes include net (charges)/credits for the effect of changes in tax laws and rates of $25 million in 2004 (2003 – $72 million; 2002 – $15 million). (b) Cash outflow from income taxes, plus investment credits earned, was $641 million in 2004 (2003 – $573 million; 2002 – $935 million). Imperial Oil Limited 4 7 Notes to consolidated financial statements (continued) Deferred income taxes are based on differences between the accounting and tax values of assets and liabilities. These differences in value are remeasured at each period-end using the tax rates and tax laws expected to apply when those differences are realized or settled in the future. Components of deferred income tax liabilities and assets as at December 31 were: millions of dollars Depreciation and amortization Successful drilling and land acquisitions Pension and benefits (a) Site restoration Net tax loss carryforwards (b) Capitalized interest Other Deferred income tax liabilities LIFO inventory valuation Other Deferred income tax assets Valuation allowance Net deferred income tax liabilities 2004 1 287 403 (343) (158) (57) 26 (3) 1 155 (343) (105) (448) – 707 2003 1 233 495 (286) (167) (57) 16 (5) 1 229 (268) (85) (353) – 876 5. 6. 7. (a) Income taxes charged directly to shareholders’ equity related to minimum pension liability adjustment were $41 million benefit in 2004 (2003 – $57 million expense; 2002 – $155 million benefit). (b) 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. Reporting of fuel consumed in operations Beginning in 2004, fuel consumed in operations, previously included in purchases of crude oil and products, has been reclassified as production and manufacturing expenses in the consolidated statement of income. Prior period amounts have been reclassified for comparative purposes. This reclassification has no impact on total expenses and net income or on the cash-flow profile of the company. Headquarters relocation On September 29, 2004, the company announced its intention to relocate its head office from Toronto, Ontario, to Calgary, Alberta. Completion of the move is expected by August 2005. Severance, relocation and other costs associated with the relocation are expected to be recorded in 2005, consistent with management decisions and the spending profile of these costs. Employee retirement benefits Retirement benefits, which cover almost all retired employees and their surviving spouses, include pension-income and certain health- care and life-insurance benefits. They are met through funded registered retirement plans and through unfunded supplementary benefits that are paid directly to recipients. Funding of registered retirement plans complies with federal and provincial pension regulations, and the company makes contributions to the plans based upon an independent actuarial valuation. Pension-income benefits consist mainly of company-paid defined benefit plans that are based on years of service and final average earnings. The company shares in the cost of health-care and life-insurance benefits. The company’s benefit obligations are based on the projected benefit method of valuation that includes employee service to date and present compensation levels as well as a projection of salaries and service to retirement. The expense and obligations for both funded and unfunded benefits are determined in accordance with United States generally accepted accounting principles and actuarial procedures. The process for determining retirement-income expense and related obligations includes making certain long-term assumptions regarding the discount rate, rate of return on plan assets and rate of compensation increases. The total obligation for retirement benefits exceeded the fair value of plan assets at December 31, 2004, by $1,712 million (2003 – $1,357 million), $1,276 million (2003 – $975 million) of which was related to pension benefits and $436 million (2003 – $382 million) to other post-retirement benefits. The obligation and pension expense can vary significantly with changes in the assumptions used to estimate the obligation and the expected return on plan assets. 48 Annual report 2004 Details of the employee retirement benefits plans are as follows: millions of dollars Components of net benefit cost: Current service cost Interest cost Expected return on plan assets Amortization of prior service cost Recognized actuarial loss/(gain) Net benefit cost (a) 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 Pension benefits 2003 2004 2002 64 222 (191) 25 34 154 76 237 (223) 27 68 185 3 761 76 237 37 405 (256) 4 260 71 219 (179) 25 69 205 3 530 71 219 – 171 (230) 3 761 Accumulated benefit obligation at December 31 3 743 3 347 Change in plan assets Fair value of plan assets at January 1 Actual return on plan assets Company contributions Payments directly to participants Benefits paid Fair value of plan assets at December 31 Excess/(deficiency) of plan assets over benefit obligation Unrecognized net actuarial (gain)/loss (b) Unrecognized prior service cost (b) Net amount recognized Amount recognized in the consolidated balance sheet consists of: Accrued benefit cost (note 8) Intangible assets Accumulated other nonowner changes in equity, minimum pension liability adjustment Net amount recognized Assumptions 2 786 315 114 25 (256) 2 984 (1 276) 1 073 99 (104) (759) 97 558 (104) 2 104 377 511 24 (230) 2 786 (975) 829 89 (57) (561) 89 415 (57) Other post-retirement benefits 2003 2004 2002 4 21 – – 1 26 6 24 – – 4 34 382 6 24 – 47 (23) 436 – (436) 95 – (341) (341) – – (341) 5 22 – – 3 30 354 5 22 – 19 (18) 382 – (382) 52 – (330) (330) – – (330) Assumptions used to determine benefit obligations at December 31 (percent) Discount rate Long-term rate of compensation increase 5.75 3.50 6.25 3.50 5.75 3.50 6.25 3.50 Assumptions used to determine net benefit cost for years ended December 31 (percent) Discount rate Long-term rate of compensation increase Long-term rate of return on funded assets 6.25 3.50 8.25 6.25 3.50 8.25 6.75 3.50 8.25 6.25 3.50 – 6.25 3.50 – 6.75 3.50 – Imperial Oil Limited 4 9 Notes to consolidated financial statements (continued) (a) A summary of net benefit cost with elements of employee future benefit costs before and after adjustments to recognize the long-term nature of employee benefit cost is shown in the table below: millions of dollars Components of net benefit cost: Current service cost Interest cost Actual return on plan assets Plan amendments for prior service Actuarial loss/(gain) Elements of employee future benefit costs before adjustments to recognize the long-term nature of employee future benefit costs Adjustments to recognize the long-term nature of employee future benefit costs: Pension benefits 2003 71 219 (377) – 171 2004 76 237 (315) 37 405 2002 64 222 107 27 196 440 84 616 Difference between expected return and actual return on plan assets for the year Difference between amortization of prior service costs for the year and actual plan amendments for the year Difference between actuarial (gain)/loss recognized for the year and actuarial (gain)/loss on accrued benefit obligation for the year Net benefit cost 92 (10) (337) 185 198 25 (102) 205 (298) (2) (162) 154 Other post-retirement benefits 2003 2004 2002 6 24 – – 47 77 – – 5 22 – – 19 46 – – 4 21 – – 25 50 – – (43) 34 (16) 30 (24) 26 (b) Unrecorded assets/(liabilities) are amortized over the average remaining service life of employees, which for 2005 and subsequent years is 13 years (2004 – 13 years; 2003 – 13.5 years). Plan assets The company’s pension plan asset allocation at December 31, 2003 and 2004, and target allocation for 2005 are as follows: Asset category (percent) Equities Bonds Other Total Target allocation 2005 50 – 75 25 – 50 0 – 10 Percentage of plan assets at December 31 2004 62 38 – 100 2003 62 38 – 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 2004 long-term expected return of 8.25 percent used in the calculations of pension expense compares to an actual rate of return over the past decade of 10.7 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. Cash flows The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid: millions of dollars 2005 2006 2007 2008 2009 Years 2010 – 2014 Pension benefits 230 234 238 244 251 1 398 Other post-retirement benefits 20 22 24 26 28 161 50 Annual report 2004 In 2005, the company expects to make cash contributions of about $350 million to its pension plan. A summary of the change in other nonowner changes in equity related to the minimum pension liability adjustment is shown in the table below. millions of dollars Increase/(decrease) in accumulated other nonowner changes in equity, before tax Deferred income tax (charge)/credit (note 4) Increase/(decrease) in accumulated other nonowner changes in equity, after tax 2004 (143) 41 (102) Pension benefits 2003 106 (57) 49 2002 (393) 155 (238) A summary of pension plans with accumulated benefit obligations in excess of plan assets is shown in the table below: millions of dollars For funded pension plans with accumulated benefit obligations in excess of plan assets: Projected benefit obligation Accumulated benefit obligation Fair value of plan assets Accumulated benefit obligation less fair value of plan assets For unfunded plans covered by book reserves: Projected benefit obligation Accumulated benefit obligation Pension benefits 2004 2003 3 876 3 430 2 984 446 384 313 3 464 3 126 2 786 340 297 221 Additional expenses include contributions to defined contribution plans, primarily the employee savings plan, of $32 million in 2004 (2003 – $31 million; 2002 – $30 million). The most recent independent actuarial valuation was as of June 30, 2004, and the next required valuation will be as of June 30, 2005. The measurement date used to determine the fair value of plan assets and the benefit obligations was December 31, 2004. A one-percent change in the assumptions at which retirement liabilities could be effectively settled is shown as follows: increase/(decrease) millions of dollars Rate of return on plan assets: Effect on net benefit costs Discount rate: Effect on net benefit costs Effect on benefit obligations Rate of pay increases: Effect on net benefit costs Effect on benefit obligations One-percent increase One-percent decrease (30) (45) (525) 30 160 30 50 645 (25) (140) For measurement purposes, a five-percent health-care cost trend rate was assumed for 2004 and thereafter. A one-percent change in the assumed health-care cost trend rate would have the following effects: increase/(decrease) millions of dollars Effect on service and interest cost components Effect on other post-retirement benefit obligations One-percent increase 4 45 One-percent decrease (3) (40) Imperial Oil Limited 5 1 Notes to consolidated financial statements (continued) 8. Other long-term obligations millions of dollars Employee retirement benefits (note 7) (a) Asset retirement obligations and other environmental liabilities (b) Other obligations Total other long-term obligations 2004 1 052 380 93 1 525 2003 847 393 74 1 314 (a) Total recorded employee retirement benefits obligations also include $48 million in current liabilities (2003 – $44 million). (b) Total asset retirement obligations and other environmental liabilities also include $76 million in current liabilities (2003 – $69 million). The estimated cash flows of asset retirement obligations have been discounted at six percent. The total undiscounted amount of the estimated cash flows required to settle the obligations is $970 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. The change in asset retirement obligations liability is as follows: millions of dollars Asset retirement obligations liability at January 1 Additions Accretion Settlement Asset retirement obligations liability at December 31 2004 327 16 22 (37) 328 2003 341 – 20 (34) 327 9. Derivatives and 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. The fair value of the company’s financial instruments is determined by reference to various market data and other appropriate valuation techniques. There are no material differences between the fair values of the company’s financial instruments and the recorded book value. 10. Incentive compensation programs Incentive compensation programs are designed to retain selected employees, reward them for high performance and promote individual contributions 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. 52 Annual report 2004 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. The units may be exercised early in the event of death or disability. 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. The maximum number of common shares that may be issued under the restricted stock unit plan is 3.5 million. 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 has not issued incentive stock options since 2002 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, the impact on net income and earnings per share would be as shown in the summary of significant accounting policies on page 43. 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. This practice is expected to continue. A summary of the incentive compensation programs is as follows: Number of units Granted Exercised Cancelled or adjusted Outstanding at Expensed in period December 31 (millions of dollars) Obligations outstanding at December 31 (millions of dollars) Incentive share units 2004 2003 2002 Deferred share units 2004 2003 2002 Earnings bonus units 2004 2003 2002 Incentive stock options 2004 2003 2002 Restricted stock units 2004 2003 2002 – – 7 000 4 899 8 253 7 479 1 889 740 2 221 580 1 036 500 – – 3 210 200 987 480 872 085 791 890 (1 619 907) (1 142 145) (812 550) – (49 486) (9 853) (1 139 160) (1 156 370) – (274 250) (49 050) – – (3 300) – (3 000) 19 225 (5 325) – (379) – – – – (7 400) (11 500) (13 500) (5 710) (120) – 11. Investment and other income Investment and other income includes gains and losses on asset sales as follows: millions of dollars Proceeds from asset sales Book value of assets sold Gain/(loss) on asset sales, before tax Gain/(loss) on asset sales, after tax 5 266 423 6 889 330 8 012 250 48 810 43 911 85 523 3 984 830 3 234 250 2 169 040 2 854 500 3 136 150 3 196 700 2 642 325 1 660 555 791 890 2004 102 59 43 32 94 109 39 1 1 – 7 3 3 – – – 31 11 – 2003 56 44 12 10 245 216 142 4 3 4 6 3 3 – – – 41 11 – 2002 61 56 5 4 Imperial Oil Limited 5 3 Notes to consolidated financial statements (continued) Investment and other income also includes a non-recurring loss of $53 million ($42 million after income taxes) from the remeasurement at fair value of the north Toronto, Ontario, property described in note 1. The change in intended use of the property, together with management’s commitment to sell, led to the remeasurement. The fair value of the property was determined using valuation techniques consistent with a market approach, adjusted as appropriate for differences. 12. Commitments and contingent liabilities At December 31, 2004, 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) 2005 62 102 119 241 2006 55 42 24 196 2007 47 42 8 62 2008 41 42 13 61 2009 38 42 7 59 After 2009 91 55 – 198 (a) Total rental expense incurred for operating leases in 2004 was $104 million (2003 – $124 million; 2002 – $124 million), which included minimum rental expenditures of $77 million (2003 – $93 million; 2002 – $91 million). Related rental income was 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 $117 million in 2004 (2003 – $114 million; 2002 – $115 million). (c) Firm capital commitments related to capital projects, shown on an undiscounted basis, totalled approximately $171 million at the end of 2004 (2003 – $189 million). The largest commitment outstanding at year-end 2004 was associated with the company’s share of upstream capital projects of $112 million at Syncrude and offshore Canada’s East Coast. (d) Other long-term agreements include primarily raw material supply and transportation services agreements. Total payments under other long-term agreements were $355 million in 2004 (2003 – $332 million; 2002 – $288 million). Payments under other long-term agreements related to the company’s share of undivided interest in activities conducted jointly with other companies are approximately $37 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, 2004, for a maximum of $175 million relating to guarantees for purchasing operating equipment and other assets from its rural marketing associates upon expiry of the associate agreement or the death or resignation of the associate. The company expects that the fair value of the operating equipment and other assets so purchased would cover the maximum potential amount of future payments under the guarantees. The company provides in its financial statements for asset retirement obligations and other environmental liabilities (see accounting policies on page 42). Provision is not made with respect to those manufacturing, distribution and marketing facilities with indeterminate useful lives, because such potential obligations cannot be measured since it is not possible to estimate the settlement dates. These are primarily currently operated sites. These costs are not expected to have a material effect on the company’s current consolidated financial position. Various lawsuits are pending against Imperial Oil Limited and its subsidiaries. Based on a consideration of all relevant facts and circumstances, the company does not believe the ultimate outcome of any currently pending lawsuits against the company will have a material adverse effect upon the company’s operations or financial condition. There are no events or uncertainties known to management beyond those already included in reported financial information that would indicate a material change in future operating results or financial condition. 13. Common shares The number of authorized common shares of the company as at December 31, 2004, was 450,000,000, unchanged from January 1, 2003. From 1995 to 2003, the company purchased shares under nine 12-month normal course share-purchase programs, as well as an auction tender. On June 23, 2004, another 12-month normal course share-purchase program was implemented with an allowable purchase of 17.9 million shares (five percent of the total at June 21, 2004), less any shares purchased by the employee savings plan and company pension fund. The results of these activities are shown below. Year 1995 to 2002 2003 2004 Cumulative purchases to date Purchased shares 202 661 201 16 259 538 13 606 712 232 527 451 Millions of dollars 5 169 799 872 6 840 Exxon Mobil Corporation’s participation in the above maintained its ownership interest in Imperial at 69.6 percent. 54 Annual report 2004 The company’s common share activities are summarized below: Balance as at January 1, 2002 Issued for cash under the stock option plan Purchases Balance as at December 31, 2002 Issued for cash under the stock option plan Purchases Balance as at December 31, 2003 Issued for cash under the stock option plan Purchases Balance as at December 31, 2004 Thousands of shares 379 159 – (296) 378 863 49 (16 259) 362 653 274 (13 607) 349 320 At stated value, millions of dollars 1 941 – (2) 1 939 2 (82) 1 859 13 (71) 1 801 The following table provides the calculation of basic and diluted earnings per share: Net income per common share – basic Income before cumulative effect of accounting change (millions of dollars) Net income (millions of dollars) 2004 2 052 2 052 2003 1 701 1 705 2002 1 214 1 214 Weighted average number of common shares outstanding (thousands of shares) 356 834 372 011 378 875 Net income per common share (dollars) Income before cumulative effect of accounting change Cumulative effect of accounting change, after income tax Net income Net income per common share – diluted Income before cumulative effect of accounting change (millions of dollars) Net income (millions of dollars) Weighted average number of common shares outstanding (thousands of shares) Effect of employee stock-based awards (thousands of shares) Weighted average number of common shares outstanding, assuming dilution (thousands of shares) Net income per common share (dollars) Income before cumulative effect of accounting change Cumulative effect of accounting change, after income tax Net income 14. Miscellaneous financial information 5.75 – 5.75 2 052 2 052 356 834 818 4.57 0.01 4.58 1 701 1 705 372 011 143 3.20 – 3.20 1 214 1 214 378 875 1 357 652 372 154 378 876 5.74 – 5.74 4.57 0.01 4.58 3.20 – 3.20 In 2004, net income included an after-tax gain of $23 million (2003 – $9 million gain; 2002 – $2 million loss) 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, 2004, by $1,013 million (2003 – $797 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 2004 165 190 59 18 432 2003 161 175 57 14 407 Research and development costs in 2004 were $70 million (2003 – $63 million; 2002 – $64 million) before investment tax credits earned on these expenditures of $7 million (2003 – $10 million; 2002 – $10 million). The net costs are included in expenses due to the uncertainty of future benefits. Cash flow from operating activities included dividends of $18 million received from equity investments in 2004 (2003 – $15 million; 2002 – $18 million). Imperial Oil Limited 5 5 Notes to consolidated financial statements (continued) 15. Financing costs millions of dollars Debt-related interest Capitalized interest Net interest expense Other interest Total interest expense (a) Foreign-exchange expense/(gain) on long-term debt Total financing costs 2004 37 (34) 3 4 7 – 7 2003 38 (33) 5 4 9 (129) (120) 2002 40 (12) 28 2 30 (10) 20 (a) Cash interest payments in 2004 were $41 million (2003 – $38 million; 2002 – $41 million). The weighted-average interest rate on short-term borrowings in 2004 was 2.3 percent (2003 – 3.1 percent). 16. Transactions with related parties Revenues and expenses of the company also include the results of transactions with Exxon Mobil Corporation and affiliated companies (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 resource activities conducted jointly in Canada. The company has agreements with affiliates of Exxon Mobil Corporation to provide computer and customer support services to the company and to share common business and operational support services to allow the companies to consolidate duplicate work and systems. The amounts paid or received have been reflected in the statement of income as shown below. millions of dollars Total revenues Purchases of crude oil and products Total expenses 2004 1 580 3 133 43 2003 950 2 464 14 2002 1 036 2 134 57 Accounts payable due to Exxon Mobil Corporation at December 31, 2004, with respect to the above transactions were $67 million (2003 – $167 million). Certain charges from ExxonMobil have been capitalized; they are not material in the aggregate. During 2003, the company borrowed $818 million (Cdn) from Exxon Overseas Corporation under two long-term loan agreements as presented in note 3. Interest paid on the loans in 2004 was $20 million (2003 – $14 million). During 2004, the company extended loans of $32 million to Montreal Pipe Line Limited, in which the company has an equity interest, for financing of the equity company’s capital expenditure programs and working capital requirements. 17. Net payments/payables 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 for governments Crown royalties Total paid or payable to governments Less investment tax credits and other receipts Net paid or payable to governments Net payments to: Federal government Provincial governments Local governments Net paid or payable to governments 2004 1 103 1 264 85 50 2 297 (1 948) 1 670 472 4 993 14 4 979 2 472 2 422 85 4 979 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 (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. 56 Annual report 2004 Natural resources segment – supplemental information Pages 57 to 59 provide information about the natural resources segment (see note 1, page 44). 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. In addition to proved oil and gas reserves, the company has a 25-percent interest in proved synthetic crude oil reserves in the Syncrude project. For internal management purposes, the company views these reserves and their development as an integral part of its total natural resources operations. However, for financial reporting purposes, these reserves are required to be reported separately from the oil and gas reserves as shown on page 59. The synthetic crude oil reserves are not considered in the standardized measure of discounted future cash flows for oil and gas reserves on page 58. The company’s share of Syncrude’s results of operations, capital and exploration expenditures and property, plant and equipment is also excluded from the following tables on this page. 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 2002 1 485 797 2 282 736 30 426 350 740 2002 13 5 34 469 521 Oil and gas 2003 2 067 665 2 732 926 55 463 364 924 Oil and gas 2003 Oil and gas – 2 55 339 396 2003 3 332 163 5 775 125 200 9 595 6 012 3 583 2004 2 160 976 3 136 915 44 565 532 1 080 2004 – 1 43 408 452 2004 3 328 141 6 099 122 235 9 925 6 514 3 411 (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. Imperial Oil Limited 5 7 Natural resources segment – supplemental information (continued) Standardized measure of discounted future cash flows As required by the Financial Accounting Standards Board, the standardized measure of discounted future net cash flows is computed by applying year-end prices, costs and legislated tax rates and a discount factor of 10 percent to net proved reserves. The standardized measure includes costs for future dismantlement, abandonment and rehabilitation obligations. The company believes the standardized measure does not provide a reliable estimate of the company’s expected future cash flows to be obtained from the development and production of its oil and gas properties or of the value of its proved oil and gas reserves. The standardized measure is prepared on the basis of certain prescribed assumptions including year-end prices, which represent a single point in time and therefore may cause significant variability in cash flows from year to year as prices change. The table below excludes the company’s interest in Syncrude. Standardized measure of discounted future net cash flows related to proved oil and gas reserves millions of dollars Future cash flows Future production costs Future development costs Future income taxes Future net cash flows Annual discount of 10 percent for estimated timing of cash flows Discounted future cash flows 2004 11 625 (3 123) (1 492) (2 260) 4 750 (1 433) 3 317 Oil and gas 2003 27 611 (10 871) (3 084) (5 543) 8 113 (3 375) 4 738 Changes in standardized measure of discounted future net cash flows related to proved oil and gas reserves millions of dollars Balance at beginning of year Changes resulting from: Sales and transfers of oil and gas produced, net of production costs Net changes in prices, development costs and production costs Extensions, discoveries, additions and improved recovery, less related costs Purchases/(sales) of minerals in place Development costs incurred during the year Revisions of previous quantity estimates Accretion of discount Net change in income taxes Net change Balance at end of year 2004 4 738 (2 240) (3 692) (43) – 345 1 838 663 1 708 (1 421) 3 317 Oil and gas 2003 8 201 (2 075) (4 395) 22 – 281 (368) 1 108 1 964 (3 463) 4 738 2002 35 811 (8 940) (3 117) (9 107) 14 647 (6 446) 8 201 2002 2 789 (1 645) 9 276 34 4 432 111 423 (3 223) 5 412 8 201 58 Annual report 2004 Net proved developed and undeveloped reserves (a) Beginning of year 2002 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 Performance-related revisions and improved recovery (Sale)/purchase of reserves in place Discoveries and extensions Production Total before year-end price/cost revisions Year-end price/cost revisions End of year 2004 Crude oil and NGLs millions of barrels Cold Lake 807 Conventional 165 3 – – (22) 146 1 – – (21) 126 6 – – (22) 110 5 115 33 – – (39) 801 5 – – (43) 763 (20) – – (41) 702 (470) 232 Natural gas billions of cubic feet 1 414 (26) 2 3 (169) 1 224 (40) – 6 (167) 1 023 57 (13) 3 (190) 880 (89) 791 Total 972 36 – – (61) 947 6 – – (64) 889 (14) – – (63) 812 (465) 347 Synthetic crude oil millions of barrels Syncrude 821 – – – (21) 800 – – – (19) 781 (3) – – (21) 757 – 757 (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 degrees Fahrenheit. The above information describes changes during the years and balances of proved oil and gas and synthetic crude oil reserves at year-end 2002, 2003 and 2004. The definitions used for oil and gas reserves are in accordance with the U.S. Securities and Exchange Commission’s (SEC) Rule 4-10 (a) of Regulation S-X, paragraphs (2), (3) and (4). 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 Leming plant and commercial phases 1 through 13. Estimates of synthetic crude oil reserves are based on detailed geological and engineering assessments of in-place crude bitumen volumes, the mining plan, historical extraction recovery and upgrading yield factors, installed plant operating capacity and operating approval limits. In compliance with SEC regulatory guidance, the company has reported 2004 reserves on the basis of the day of December 31, 2004, prices and costs (”year-end prices”). Resultant changes in Cold Lake bitumen and the associated natural gas reserves from the year-end 2003 reserves estimates, which were based on long-term projections of oil and gas prices consistent with those used in the company’s investment decision-making process, are shown in the line ”Year-end price/cost revisions.” The requirement to use year-end prices for reserves estimation introduces single-day price focus and volatility in the valuation of reserves to be produced over the next 20 to 30 years. The company believes that this approach is inconsistent with the long-term nature of the natural resources business. The use of prices from a single date is not relevant to the investment decisions made by the company and annual variations in reserves based on such year-end prices are not of consequence in how the business is managed. The impact of year-end prices on reserves estimation is most clearly shown at Cold Lake where proved bitumen and associated natural gas reserves were reduced by about 485 million oil-equivalent barrels as a result of using December 31, 2004, prices, which were unusually low. Prices quickly rebounded from December 31, and through January 2005 returned to levels that have restored the reserves to the proved category. Performance-related revisions can include upward or downward changes in previously estimated volumes of proved reserves for existing fields due to the evaluation or revaluation of (1) already available geologic, reservoir or production data, or (2) new geologic or reservoir data. Performance-related revisions can also include changes associated with the performance of improved recovery projects and significant changes in either development strategy or production equipment/facility capacity. During the past five years, performance-related revisions averaged an upward adjustment of 16 million oil- equivalent barrels per year. 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 Leming plant and phases 1 through 13 of Cold Lake production operations. Oil-equivalent barrels (OEB) may be misleading, particularly if used in isolation. An OEB conversion ratio of 6,000 cubic feet to one barrel is based on an energy-equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the well head. No independent qualified reserves evaluator or auditor was involved in the preparation of the reserves data. Imperial Oil Limited 5 9 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) Toronto Stock Exchange High Low Close at December 31 American Stock Exchange ($U.S.) High Low Close at December 31 Net income per share, under U.S. GAAP (dollars) – basic – diluted Price ratios at December 31 Share price to net earnings (b) Dividends declared (c) Total (millions of dollars) Per share (dollars) 2004 2003 2002 2001 2000 356 834 349 320 14.6 14 953 13 088 93 778 73.65 56.42 71.15 62.45 42.34 59.38 5.75 5.74 12.4 314 0.88 372 011 378 875 393 121 417 753 362 653 15.2 15 516 13 601 94 063 58.22 43.20 57.53 44.75 28.25 44.42 4.58 4.58 12.6 323 0.87 378 863 15.8 15 988 14 014 379 159 15.9 16 483 14 358 398 263 16.6 17 104 14 873 83 019 129 285 117 980 49.38 38.51 44.86 31.85 24.00 28.70 3.20 3.20 14.0 318 0.84 46.50 34.05 44.31 29.45 22.59 27.88 3.11 3.11 14.2 324 0.83 42.25 26.50 39.45 27.81 17.94 26.30 3.37 3.37 11.7 325 0.78 (a) Exxon Mobil Corporation owns 69.6 percent of Imperial’s shares. (b) Closing share price at December 31 at the Toronto Stock Exchange, 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 the company. Imperial Oil Limited is a qualified foreign corporation for purposes of the reduced U.S. capital gains tax rates (15 percent and five percent for certain individuals) that are applicable to dividends paid by U.S. domestic corporations and qualified foreign corporations. There is no Canadian tax on gains from selling shares 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 $15.29 on February 22, 1994. Both amounts are restated for the 1998 three-for-one share split. 60 Annual report 2004 Quarterly financial and stock-trading data (a) 2004 three months ended Sept. 30 June 30 Mar. 31 Dec. 31 Mar. 31 2003 three months ended Sept. 30 June 30 Financial data, under U.S. GAAP (millions of dollars) Total revenues Total expenses Income before income taxes Income taxes Cumulative effect of accounting change Net income 5 067 4 347 720 (254) – 466 Segmented net income, under U.S. GAAP (millions of dollars) 319 135 12 – 466 Natural resources Petroleum products Chemicals Corporate and other Net income 5 466 4 767 699 (195) – 504 368 108 29 (1) 504 5 814 4 986 828 (284) – 544 411 99 31 3 544 Segmented cash flows from operating activities, under U.S. GAAP (millions of dollars) Natural resources Petroleum products Chemicals Corporate and other Cash flows from operating activities Per share information, under U.S. GAAP (dollars) Net income – basic Net income – diluted Dividends (declared quarterly) Share prices (dollars) (b) Toronto Stock Exchange High Low Close American Stock Exchange ($U.S.) High Low Close 395 (4) 3 4 398 1.29 1.29 0.22 64.45 56.42 58.87 48.70 42.34 44.84 438 204 45 3 690 1.40 1.40 0.22 64.25 58.40 62.40 47.13 43.17 46.82 738 309 55 7 1 109 1.53 1.53 0.22 66.76 59.50 65.48 52.22 45.50 51.71 6 113 5 333 780 (242) – 538 389 158 28 (37) 538 729 354 23 9 1 115 1.53 1.52 0.22 73.65 65.28 71.15 62.45 51.43 59.38 5 478 4 685 793 (253) 4 544 343 139 6 56 544 531 172 (1) 2 704 1.44 1.44 0.21 47.80 43.48 47.35 32.20 28.25 32.14 4 510 3 888 622 (162) – 460 292 102 7 59 460 418 217 50 (4) 681 1.23 1.23 0.22 47.40 43.20 47.10 34.99 29.94 34.92 4 626 4 057 569 (189) – 380 257 115 8 – 380 441 63 (11) 1 494 1.03 1.03 0.22 53.49 45.62 50.80 38.79 33.04 37.21 Dec. 31 4 594 4 188 406 (85) – 321 251 51 16 3 321 269 68 (16) 27 348 0.88 0.88 0.22 58.22 50.16 57.53 44.75 37.24 44.42 Shares traded (thousands) (c) 26 559 21 640 22 132 23 447 21 350 23 171 21 434 28 108 (a) Quarterly data has not been audited or reviewed 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 both of the above stock exchanges. Dividend and share-purchase information Declaration date Dividend record date Dividend payment date 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) 2nd quarter, 2005 May 26, 2005 June 8, 2005 July 1, 2005 3rd quarter, 2005 4th quarter, 2005 August 17, 2005 November 16, 2005 December 1, 2005 January 1, 2006 September 1, 2005 October 1, 2005 1st quarter, 2006 February 15, 2006 March 3, 2006 April 1, 2006 June 16, 2005 September 16, 2005 December 14, 2005 March 17, 2006 July 4, 2005 October 3, 2005 January 3, 2006 April 3, 2006 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. Imperial Oil Limited 6 1 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 Thursday, April 21, 2005, 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: 1-800-387-0825 (from Canada or U.S.A.) or 416-643-5500 416-643-5660 or -5661 inquiries@cibcmellon.com Fax: E-mail: www.cibcmellon.com 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 Telephone: 1-800-526-0801 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: 416-968-8145 Telephone: 416-968-5345 Fax: Other contact numbers Customer and other inquiries: Telephone: Fax: 1-800-567-3776 1-800-367-0585 Corporate secretary Telephone: Fax: 416-968-4966 416-968-5407 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: Jean Becq, Bernard Bohn, J. Christopher Lawson, Alan Marsh/First Light, Prisma Productions, Imperial Oil archives Printing: Quebecor World MIL Inc. 62 Annual report 2004 Directors, senior management and officers Board of directors (from left to right) Other officers John F. Kyle Vice-president and treasurer Brian W. Livingston Vice-president, general counsel and corporate secretary Paul A. Smith Controller and senior vice-president, finance and administration Imperial Oil Limited Toronto, Ontario Jim F. Shepard Retired chairman and chief executive officer Finning International Inc. Vancouver, British Columbia Brian J. Fischer Senior vice-president, products and chemicals division Imperial Oil Limited Toronto, Ontario J. Michael Yeager Senior vice-president, resources division Imperial Oil Limited Calgary, Alberta Pierre Des Marais II President Gestion PDM Inc. Montreal, Quebec Roger Phillips Retired president and chief executive officer IPSCO Inc. Regina, Saskatchewan Victor L. Young Corporate director of several corporations St. John’s, Newfoundland and Labrador Sheelagh D. Whittaker Managing director, Public Sector Business Electronic Data Systems Limited London, England Tim J. Hearn Chairman, president and chief executive officer Imperial Oil Limited Toronto, Ontario Imperial Oil Limited Corporate profile Imperial on-line Imperial Oil Limited has been a leading member of the Canadian energy industry for 125 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 Canada’s largest refiner and marketer of petroleum products – sold primarily under the Esso brand name – and a major producer of petrochemicals. 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. Imperial Oil Limited 111 St. Clair Avenue West Toronto, Ontario Canada M5W 1K3 www.imperialoil.ca This report has been printed and bound to facilitate recycling. Cover photos, from left to right: Scientists conduct research in a 1940s lab in Sarnia; the company now operates two industry-leading research facilities, in Sarnia and Calgary; the Sarnia manufacturing site opens its petrochemical plant in 1950; today, the site is the most integrated fuels, lubricating oil and chemicals manufacturing facility in Canada; Imperial’s association with hockey dates from the 1930s; the company continues to sponsor Canada’s national winter sport at all levels; Imperial’s Leduc discovery in 1947 signals the beginning of Canada’s role as a major oil producer; the company drills new wells at its Cold Lake heavy-oil operations; customers fill-up with gasoline at a 1916 service station; today Esso service stations offer fast, friendly service, quality products and one-stop convenience for busy customers on the go. l i o f 1 2 5 y e a r s e n e r g y e a d e r s h p 125 s h a r e h o d e r s A n n u a r e p o r t 2 0 0 4 t o l l 

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