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

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SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

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

     
For the fiscal year ended December 31, 2004   Commission file number: 0-12014

IMPERIAL OIL LIMITED

(Exact name of registrant as specified in its charter)
     
CANADA   98-0017682
(State or other jurisdiction of   (I.R.S. Employer
incorporation or organization)   Identification No.)
     
111 ST. CLAIR AVENUE WEST, TORONTO, ONT., CANADA   M5W 1K3
(Address of principal executive offices)   (Zip Code)

Registrant’s telephone number, including area code:

1-800-567-3776

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

     
  Name of each exchange on
Title of each class   which registered
None   None

Securities registered pursuant to Section 12(g) of the Act:
Common Shares (without par value)


(Title of Class)

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

Yesþ Noo

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

Yesþ Noo

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

Yesþ Noo

     As of the last business day of the 2004 second fiscal quarter, the aggregate market value of the voting stock held by non-affiliates of the registrant was Canadian $ 6,768,415,742 based upon the reported last sale price of such stock on the Toronto Stock Exchange on that date.

     The number of common shares outstanding, as of February 18, 2005, was 342,365,873.

 
 

 


             
        Page
           
Item 1. Business     3  
        3  
        4  
        4  
        9  
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        11  
        11  
        11  
        12  
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        13  
        13  
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        13  
        14  
        14  
Item 2. Properties     15  
Item 3. Legal Proceedings     15  
Item 4. Submission of Matters to a Vote of Security Holders     15  
           
    15  
Item 6. Selected Financial Data     16  
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation     16  
Item 7A. Quantitative and Qualitative Disclosures About Market Risk     26  
Item 8. Financial Statements and Supplementary Data     26  
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure     31  
Item 9A. Controls and Procedures     31  
           
Item 10. Directors and Executive Officers of the Registrant     32  
Item 11. Executive Compensation     35  
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters     43  
Item 13. Certain Relationships and Related Transactions     44  
Item 14. Principal Accountant Fees and Services     44  
           
Item 15. Exhibits and Financial Statement Schedules     45  
Index to Financial Statements     F-1  
Management’s Report on Internal Control over Financial Reporting     F-2  
Auditors’ Report     F-2  

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

                                         
    2004     2003     2002     2001     2000  
     
    (Dollars)  
Rate at end of period
    0.8310       0.7738       0.6329       0.6279       0.6669  
Average rate during period
    0.7702       0.7186       0.6368       0.6444       0.6725  
High
    0.8493       0.7738       0.6619       0.6697       0.6969  
Low
    0.7158       0.6349       0.6200       0.6241       0.6410  

On February 28, 2005, the noon buying rate in New York City for cable transfers in Canadian dollars as certified for customs purposes by the Federal Reserve Bank of New York was $0.8133 U.S. = $1.00 Canadian.

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     This report contains forward looking information on future production, project start ups and future capital spending. Actual results could differ materially as a result of market conditions or changes in law, government policy, operating conditions, costs, project schedules, operating performance, demand for oil and natural gas, commercial negotiations or other technical and economic factors.

PART I

Item 1. Business.
     Imperial Oil Limited was incorporated under the laws of Canada in 1880 and was continued under the Canada Business Corporations Act (the “CBCA”) by certificate of continuance dated April 24, 1978. The head and principal office of the Company is located at 111 St. Clair Avenue West, Toronto, Ontario, Canada M5W 1K3; telephone 1-800-567-3776. Exxon Mobil Corporation owns approximately 69.6 percent of the outstanding shares of the Company with the remaining shares being publicly held, with the majority of shareholders having Canadian addresses of record. In this report, unless the context otherwise indicates, reference to the ”Company” includes Imperial Oil Limited and its subsidiaries.
     The Company is Canada’s largest integrated oil company. It is active in all phases of the petroleum industry in Canada, including the exploration for, and production and sale of, crude oil and natural gas. In Canada, it is one of the largest producers of crude oil and natural gas liquids and a major producer of natural gas, and the largest refiner and marketer of petroleum products. It is also a major supplier of petrochemicals.
     The Company’s operations are conducted in three main segments: natural resources (“upstream”), petroleum products (“downstream”) and chemicals. Natural resources operations include the exploration for, and production of, crude oil and natural gas, including upgraded crude oil and crude bitumen. Petroleum products operations consist of the transportation, refining and blending of crude oil and refined products and the distribution and marketing thereof. The chemicals operations consist of the manufacturing and marketing of various petrochemicals.

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

                                         
    2004     2003     2002     2001     2000  
     
    (millions)  
External revenues (1):
                                       
Natural resources
  $ 3,734     $ 3,424     $ 2,677     $ 3,155     $ 3,262  
Petroleum products
    17,545       14,764       13,396       13,105       13,788  
Chemicals
    1,216       994       955       930       945  
Corporate and other
    (35 )     26       14       63       56  
     
 
  $ 22,460     $ 19,208     $ 17,042     $ 17,253     $ 18,051  
     
 
                                       
Intersegment sales:
                                       
Natural resources
  $ 2,891     $ 2,224     $ 2,217     $ 2,166     $ 2,638  
Petroleum products
    1,666       1,294       1,038       1,300       1,332  
Chemicals
    293       238       209       245       228  
 
                                       
Total revenues:
                                       
Natural resources
  $ 6,625     $ 5,648     $ 4,894     $ 5,321     $ 5,900  
Petroleum products
    19,211       16,058       14,434       14,405       15,120  
Chemicals
    1,509       1,232       1,164       1,175       1,173  
Corporate and other
    (35 )     26       14       63       56  
 
                                       
Net income (2):
                                       
Natural resources
  $ 1,487     $ 1,143     $ 1,042     $ 941     $ 1,165  
Petroleum products
    500       407       127       353       313  
Chemicals
    100       37       52       23       59  
Corporate and other (3) /eliminations
    (35 )     118       (7 )     (94 )     (129 )
     
 
  $ 2,052     $ 1,705     $ 1,214     $ 1,223     $ 1,408  
     
 
                                       
Identifiable assets at December 31 (4):
                                       
Natural resources
  $ 6,875     $ 6,418     $ 6,014     $ 5,390     $ 5,294  
Petroleum products
    5,570       5,290       5,127       4,425       4,829  
Chemicals
    498       440       428       384       381  
Corporate and other/eliminations
    1,084       189       434       689       762  
     
 
  $ 14,027     $ 12,337     $ 12,003     $ 10,888     $ 11,266  
     
 
                                       
Capital and exploration expenditures:
                                       
Natural resources
  $ 1,113     $ 1,007     $ 986     $ 746     $ 434  
Petroleum products
    283       478       589       339       232  
Chemicals
    15       41       25       30       13  
Corporate and other
    34       33       12              
     
 
  $ 1,445     $ 1,559     $ 1,612     $ 1,115     $ 679  
     


(1)   Export sales are reported in note 2 to the consolidated financial statements on page F-11.
(2)   These amounts are presented as if each segment were a separate business entity and, accordingly, include the financial effect of transactions between the segments. Intersegment sales are made essentially at prevailing market prices.
(3)   Includes primarily interest charges on the debt obligations of the Company, interest income on investments and intersegment consolidating adjustments.
(4)   The identifiable assets in each operating segment represent the net book value of the tangible and intangible assets attributed to such segment.

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Natural Resources

     Petroleum and Natural Gas Production
     The Company’s average daily production of crude oil and natural gas liquids during the five years ended December 31, 2004, was as follows:

                                         
    2004     2003     2002     2001     2000  
     
    (thousands a day)  
Conventional (including natural gas liquids):
                                       
Cubic metres – Gross (1)
    12.1       11.8       12.4       13.2       14.3  
–  Net (2)
    9.4       9.1       9.5       10.2       11.0  
Barrels          – Gross (1)
    76       74       78       83       90  
– Net (2)
    59       57       60       64       69  
Oil Sands (Cold Lake):
                                       
Cubic metres – Gross (1)
    20.0       20.5       17.8       20.4       18.9  
– Net (2)
    17.7       18.4       16.9       19.2       16.2  
Barrels          – Gross (1)
    126       129       112       128       119  
– Net (2)
    112       116       106       121       102  
Tar Sands (Syncrude):
                                       
Cubic metres – Gross (1)
    9.5       8.4       9.1       8.9       8.1  
– Net (2)
    9.4       8.3       9.1       8.3       6.7  
Barrels          – Gross (1)
    60       53       57       56       51  
– Net (2)
    59       52       57       52       42  
Total:
                                       
Cubic metres – Gross (1)
    41.6       40.7       39.3       42.5       41.3  
– Net (2)
    36.5       35.8       35.5       37.7       33.9  
Barrels          – Gross (1)
    262       256       247       267       260  
– Net (2)
    230       225       223       237       213  


(1)   Gross production of crude oil is the Company’s share of production from conventional wells, Syncrude tar sands and Cold Lake oil sands, and gross production of natural gas liquids is the amount derived from processing the Company’s share of production of natural gas (excluding purchased gas), in each case before deduction of the mineral owners’ or governments’ share or both.
(2)   Net production is gross production less the mineral owners’ or governments’ share or both.

     From 2000 through 2003, conventional production has declined due to the sale of oil and gas producing properties and the natural decline in the productivity of the Company’s conventional oil fields. In 2004, conventional production increased primarily due to increased natural gas liquids production from the Wizard Lake gas cap. In 2001, Cold Lake net production increased mainly due to the timing of steaming cycles and lower royalties and Syncrude production increased mainly due to the start up of the Aurora mine during the second half of 2000 and fewer disruptions in upgrading operations than the previous year. In 2002, Cold Lake production decreased mainly due to the timing of steaming cycles and Syncrude net production increased mainly due to lower royalties. In 2003, Cold Lake net production increased as a result of a full year of production of stages 11 to 13, which was offset in part by the timing of steaming cycles and higher royalties. Syncrude production decreased in 2003 due to extended maintenance of upgrading facilities. In 2004, Cold Lake production declined due to the timing of steaming cycles and higher royalty, and Syncrude production increased due to fewer disruptions in upgrading operations than in 2003.

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The Company’s average daily production and sales of natural gas during the five years ended December 31, 2004 are set forth below. All gas volumes in this report are calculated at a pressure base of, in the case of cubic metres, 101.325 kilopascals absolute at 15 degrees Celsius and, in the case of cubic feet, 14.73 pounds per square inch at 60 degrees Fahrenheit.

                                         
    2004     2003     2002     2001     2000  
     
    (millions a day)  
Sales (1):
                                       
Cubic metres
    14.7       13.0       14.1       14.2       11.9  
Cubic feet
    520       460       499       502       419  
Gross Production (2):
                                       
Cubic metres
    16.1       14.5       15.0       16.2       14.9  
Cubic feet
    569       513       530       572       526  
Net Production (2):
                                       
Cubic metres
    14.7       12.9       13.1       13.2       13.0  
Cubic feet
    518       457       463       466       459  


(1)   Sales are sales of the Company’s share of production (before deduction of the mineral owners’ and/or governments’ share) and sales of gas purchased, processed and/or resold.
(2)   Gross production of natural gas 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. Production data include amounts used for internal consumption with the exception of amounts reinjected.

          In 2001, natural gas production increased primarily due to gas production from the Sable Offshore Energy Project, which went into production at the end of 1999, and increased production from gas caps overlaying two former oil fields, both in Alberta. In 2002 and 2003, natural gas production decreased primarily due to the depletion of gas caps in Alberta and in 2003 also due to increased maintenance activity at gas processing facilities. In 2004 natural gas production increased primarily due to increased production from the Wizard Lake gas cap.
     Most of the Company’s natural gas sales are made under short term contracts.
     The Company’s average sales price and production (lifting) costs for conventional and Cold Lake crude oil and natural gas liquids and natural gas for the five years ended December 31, 2004, were as follows:

                                         
    2004     2003     2002     2001     2000  
     
Average Sales Price:
                                       
Crude oil and natural gas liquids:
                                       
Per cubic metre
  $ 207.26     $ 181.92     $ 174.72     $ 134.16     $ 190.02  
Per barrel
    32.95       28.92       27.78       21.33       30.21  
Natural gas:
                                       
Per thousand cubic metres
  $ 239.34     $ 232.99     $ 141.91     $ 201.92     $ 176.15  
Per thousand cubic feet
    6.78       6.60       4.02       5.72       4.99  
Average Production (Lifting) Costs Per Unit of Net Production (1):
                                       
Per cubic metre
  $ 60.38     $ 63.85     $ 48.81     $ 46.17     $ 47.36  
Per barrel
    9.60       10.15       7.76       7.34       7.53  


(1)   Average production (lifting) costs do not include depreciation and depletion of capitalized acquisition, exploration and development costs. Administrative expenses are included. Average production (lifting) costs per unit of net production were computed after converting gas production into equivalent units of oil on the basis of relative energy content.

     Canadian crude oil prices are mainly determined by international crude oil markets which are volatile.
     Canadian natural gas prices are determined by North American gas markets and are also volatile. Prices for Canadian natural gas increased significantly in 2000 and again in early 2001 and 2003, in line with tighter North American market conditions. Canadian natural gas prices decreased in 2002 primarily due to a weaker U.S. economy and warmer weather.
     In 2001, average production (lifting) costs decreased mainly due to higher net production at Cold Lake. In 2002, average production (lifting) costs increased mainly due to lower net production at Cold Lake. In 2003, average production (lifting) costs increased mainly due to higher costs of purchased natural gas at Cold Lake. In 2004, average production (lifting) costs decreased mainly due to higher production from the Wizard Lake gas cap.
     The Company has interests in a large number of facilities related to the production of crude oil and natural gas. Among these facilities are 27 plants that process natural gas to produce marketable gas and recover natural gas liquids or sulphur. The Company is the principal owner and operator of 11 of the plants.
     The Company’s production of conventional and Cold Lake crude oil and natural gas is derived from wells located exclusively in Canada. The total number of producing wells in which the Company had interests at December 31, 2004, is set forth in the following table. The statistics in the table are determined in part from information received from other operators.

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    Crude Oil     Natural Gas     Total  
     
    Gross (1)       Net (2)     Gross (1)       Net (2)     Gross (1)       Net (2)  
     
Conventional wells
    2,322       1,292       4,326       2,275       6,648       3,567  
Oil Sands (Cold Lake) wells
    3,815       3,815                   3,815       3,815  


(1)   Gross wells are wells in which the Company owns a working interest.
(2)   Net wells are the sum of the fractional working interests owned by the Company in gross wells, rounded to the nearest whole number.

      Conventional Oil and Gas
     The Company has major interests in the Norman Wells oil field in the Northwest Territories and the West Pembina oil field in Alberta. Together they currently account for approximately 60 percent of the Company’s net production of conventional crude oil (approximately 65 percent of gross production).
     Norman Wells is the Company’s largest producing conventional oil field. In 2004, net production of crude oil and natural gas liquids was about 2,400 cubic metres (14,800 barrels) per day and gross production was about 3,500 cubic metres (22,000 barrels) per day. The Government of Canada has a one-third carried interest and receives a production royalty of five percent in the Norman Wells oil field. The Government of Canada’s carried interest entitles it to receive payment of a one-third share of an amount based on revenues from the sale of Norman Wells production, net of operating and capital costs. Under a shipping agreement, the Company pays for the construction, operating and other costs of the 870 kilometre (540 mile) pipeline which transports the crude oil and natural gas liquids from the project. In 2004, those costs were about $35 million. Most of the larger oil fields in the Western Provinces have been in production for several decades, and the amount of oil that is produced from conventional fields is declining. In some cases, however, additional oil can be recovered by using various methods of enhanced recovery. The Company’s largest enhanced recovery projects are located at the West Pembina oil field.
     The Company produces natural gas from a large number of gas fields located in the Western Provinces, primarily in Alberta.
     The Company has a nine percent interest in a project to develop natural gas reserves in the Sable Island area off the coast of the Province of Nova Scotia. About $4 billion has been spent by the participants to the end of 2004 on the project. Production from the Sable Offshore Energy Project began at the end of 1999 and is expected to average about 12 million cubic metres (420 million cubic feet) per day of natural gas and 3,200 cubic metres (20,000 barrels) per day of natural gas liquids through the end of the decade.

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

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      The Province of Alberta, in its capacity as lessor of the Cold Lake oil sands leases, is entitled to a royalty on production from the Cold Lake production project. In late 2000, the Company entered into an agreement with the Province of Alberta, effective January 1, 2000, on a transitional royalty arrangement that will apply to all of the Company’s current and proposed operations at Cold Lake until the end of 2007, at which time the generic Alberta regulations for royalties that apply to all other oil sands development in the Province will take effect. This transition is expected to be royalty neutral. The effective royalty on gross production was 11 percent in 2004, 10 percent in 2003, five percent in 2002 and 2001, and 14 percent in 2000. The Company expects that after 2007 the royalty will be the greater of one percent of gross revenue or 25 percent of an amount based on revenue net of operating and capital costs for the Cold Lake production project and the pilot operations.

     Other Oil Sands Activity
     The Company has interests in other oil sands leases in the Athabasca and Peace River areas of northern Alberta. Evaluation wells completed on these leased areas established the presence of very heavy crude oil in place. The Company continues to evaluate these leases to determine their potential for future development.
     The Company holds varying interests in lands totalling about 68,000 leased net hectares (168,000 net acres) in the Athabasca area where the oil sands are buried too deeply to permit recovery by surface mining methods. The Company, as part of an industry consortium and several joint ventures, has been involved in recovery research and pilot studies and in evaluating the quality and extent of the oil sands.

     Syncrude Mining Operations
      The Company holds a 25 percent participating interest in Syncrude, a joint venture established to recover shallow deposits of tar sands using open-pit mining methods, to extract the crude bitumen, and to produce a high-quality, light (32 degree API), sweet, synthetic crude oil. The Syncrude operation, located near Fort McMurray, Alberta, exploits a portion of the Athabasca Oil Sands Deposit. The location is readily accessible by public road. The produced synthetic crude oil is shipped from the Syncrude site to Edmonton, Alberta by Alberta Oil Sands Pipeline Ltd. The pipeline is currently being expanded to accommodate increased Syncrude production. Since startup in 1978, Syncrude has produced about 1.5 billion barrels of synthetic crude oil.
     Syncrude has an operating license issued by the Province of Alberta which is effective until 2035. This license permits Syncrude to mine tar sands and produce synthetic crude oil from approved development areas on tar sands leases. Syncrude holds eight tar sands leases covering about 102,000 hectares (252,000 acres) in the Athabasca Oil Sands Deposit. Issued by the Province of Alberta, the leases are automatically renewable as long as tar sands operations are ongoing or the leases are part of an approved development plan. Syncrude leases 10, 12, 17, 22 and 34 (containing proven reserves) and leases 29, 30 and 31 (containing no proven reserves) are included within a development plan approved by the Province of Alberta. There were no known previous commercial operations on these leases prior to the start-up of operations in 1978.
     As of January 1, 2002, a greater of 25 percent deemed net profit royalty or one percent gross royalty applies to all Syncrude production after the deduction of new capital expenditures.
     The Government of Canada had issued an order that expired at the end of 2003 which provided for the remission of any federal income tax otherwise payable by the participants as the result of the non-deductibility from the income of the participants of amounts receivable by the Province of Alberta as a royalty or otherwise with respect to Syncrude. That remission order excluded royalty payable on production for the Aurora project.
     Operations at Syncrude involve three main processes: open pit mining, extraction of crude bitumen and upgrading of crude bitumen into synthetic crude oil. In the Base mine (lease 17), the mining and transportation system uses draglines, bucketwheel reclaimers and belt conveyors. In the North mine (leases 17 and 22) and in the Aurora mine (leases 10, 12 and 34), truck, shovel and hydrotransport systems are used. The extraction facilities, which separate crude bitumen from sand, are capable of processing approximately 495,000 tonnes (545,000 tons) of tar sands a day, producing about 18 million cubic metres (110 million barrels) of crude bitumen a year. This represents recovery capability of about 92 percent of the crude bitumen contained in the mined tar sands.

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     Crude bitumen extracted from tar sands is refined to a marketable hydrocarbon product through a combination of carbon removal in two large, high temperature, fluid coking vessels and by hydrogen addition in high temperature, high pressure, hydrocracking vessels. These processes remove carbon and sulphur and reformulate the crude into a low viscosity, low sulphur, high quality synthetic crude oil product. In 2004, the upgrading process yielded 0.855 cubic metres of synthetic crude oil per cubic metre of crude bitumen (0.855 barrels of synthetic crude oil per barrel of crude bitumen). In 2004, about 45 percent of the synthetic crude oil was processed by Edmonton area refineries and the remaining 55 percent was pipelined to refineries in eastern Canada or exported to the United States. Electricity is provided to Syncrude by a 270 megawatt electricity generating plant and a 80 megawatt electricity generating plant, both located at Syncrude. The generating plants are owned by the Syncrude participants. The Company’s 25 percent share of net investment in plant, property and equipment, including surface mining facilities, transportation equipment and upgrading facilities is about $2.8 billion.
     In 2004, Syncrude’s net production of synthetic crude oil was about 37,500 cubic metres (235,600 barrels) per day and gross production was about 37,800 cubic metres (238,000 barrels) per day. The Company’s share of net production in 2004 was about 9,400 cubic metres (58,900 barrels) per day.
     In 2000, Syncrude completed development of the first stage of the Aurora mine. The Aurora investment involved extending mining operations to a new location about 35 km from the main Syncrude site and expanding upgrading capacity. In 2001, the Syncrude owners approved another major expansion of upgrading capacity and further development of the Aurora mine. The second Aurora mining and extraction development became fully operational in 2004. The increased upgrading capacity is expected to be available in 2006. These projects are expected to lead to a total production capacity of about 56,500 cubic metres (355,000 barrels) of synthetic crude oil a day when completed. The Company’s share of project costs is expected to be about $2 billion of which about $1.6 billion has been incurred to the end of 2004.
     The following table sets forth certain operating statistics for the Syncrude operations:

                                         
    2004     2003     2002     2001     2000  
     
Total mined volume (1)
                                       
millions of cubic metres
    76.6       83.5       77.9       90.3       65.0  
millions of cubic yards
    100.3       109.2       102.0       118.3       85.1  
Mined volume to tar sands ratio (1)
    0.94       1.15       1.05       1.15       0.96  
Tar sands mined
                                       
millions of tonnes
    170.9       152.4       156.5       164.8       142.2  
millions of tons
    188.0       168.0       172.1       181.2       156.4  
Average bitumen grade (weight percent)
    11.1       11.0       11.2       11.0       11.0  
Crude bitumen in mined tar sands
                                       
millions of tonnes
    19.0       16.8       17.5       18.1       15.6  
millions of tons
    20.9       18.5       19.2       19.9       17.2  
Average extraction recovery (percent)
    87.3       88.6       89.9       87.0       89.7  
Crude bitumen production (2)
                                       
millions of cubic metres
    16.4       14.7       15.5       15.5       13.8  
millions of barrels
    103.3       92.3       97.8       97.6       86.8  
Average upgrading yield (percent)
    85.5       86.0       86.3       84.5       84.3  
Gross synthetic crude oil produced
                                       
millions of cubic metres
    14.1       12.5       13.5       13.1       11.6  
millions of barrels
    88.4       78.4       84.8       82.4       73.2  
Company’s net share (3)
                                       
millions of cubic metres
    3       3       3       3       2  
millions of barrels
    22       19       21       19       15  


(1)   Includes pre-stripping of mine areas and reclamation volumes.
(2)   Crude bitumen production is equal to crude bitumen in mined tar sands multiplied by the average extraction recovery and the appropriate conversion factor.
(3)   Reflects the Company’s 25 percent interest in production, less applicable royalties payable to the Province of Alberta.

     Other Tar Sands Activity
     The Company holds a 100 percent interest in approximately 16,500 hectares (40,700 acres) of surface mineable tar sands in the Kearl area in the Athabasca area of northern Alberta. A 400 well delineation drilling program to better define the available resource was begun in 2003 and is expected to be completed in 2005. The Company is assessing a potential phased project with another company to jointly develop mineable bitumen, which may have the potential to produce up to approximately 47,700 cubic metres (300,000 barrels) per day. The Company plans on filing a regulatory application with the Alberta Energy and Utilities Board for the Kearl oil sands project in 2005.

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

                                                                                                 
    Hectares     Acres  
    Developed     Undeveloped     Total     Developed     Undeveloped     Total  
             
    2004     2003     2004     2003     2004     2003     2004     2003     2004     2003     2004     2003  
             
    (thousands)  
Western Provinces Conventional –
                                                                                               
Gross (1)
    1,080       1,101       173       187       1,253       1,288       2,669       2,721       427       462       3,096       3,183  
Net (2)
    446       450       118       127       564       577       1,102       1,112       292       314       1,394       1,426  
Oil Sands (Cold Lake and other) –
                                                                                               
Gross (1)
    42       42       193       175       235       217       104       104       477       432       581       536  
Net (2)
    41       41       104       104       145       145       101       101       257       257       358       358  
Tar Sands (Syncrude and other) –
                                                                                               
Gross (1)
    45       41       73       77       118       118       111       101       180       190       291       291  
Net (2)
    11       10       31       32       42       42       27       25       77       79       104       104  
Canada Lands (3):
                                                                                               
Conventional –
                                                                                               
Gross (1)
    31       31       321       321       352       352       77       77       793       793       870       870  
Net (2)
    3       4       98       98       101       102       7       10       242       242       249       252  
Atlantic Offshore Conventional –
                                                                                               
Gross (1)
    17       17       2,603       1,329       2,620       1,346       42       42       6,432       3,284       6,474       3,326  
Net (2)
    2       2       832       565       834       567       5       5       2,056       1,396       2,061       1,401  
Total (4):
                                                                                               
Gross (1)
    1,215       1,232       3,363       2,089       4,578       3,321       3,003       3,045       8,309       5,161       11,312       8,206  
Net (2)
    503       507       1,183       926       1,686       1,433       1,242       1,253       2,924       2,288       4,166       3,541  


(1)   Gross hectares or acres include the interests of others.
(2)   Net hectares or acres exclude the interests of others.
(3)   Canada Lands include the Arctic Islands, Beaufort Sea/Mackenzie Delta, and Other Northwest Territories, Nunavut and the Yukon.
(4)   Certain land holdings are subject to modification under agreements whereby others may earn interests in the Company’s holdings by performing certain exploratory work (farmout) and whereby the Company may earn interests in others’ holdings by performing certain exploratory work (farmin).

     Exploration and Development
     The Company has been involved in the exploration for and development of petroleum and natural gas in the Western Provinces, in the Canada Lands (which include the Arctic Islands, the Beaufort Sea/Mackenzie Delta, and Other Northwest Territories, Nunavut and the Yukon) and in the Atlantic Offshore.

     The Company’s exploration strategy in the Western Provinces is to search for hydrocarbons on its existing land holdings and especially near established facilities. Higher risk areas are evaluated through shared ventures with other companies.
     The following table sets forth the conventional and oil sands net exploratory and development wells that were drilled or participated in by the Company during the five years ended December 31, 2004.
                                         
    2004     2003     2002     2001     2000  
     
Western and Atlantic Provinces:
                                       
Conventional
                                       
Exploratory –
                                       
Oil
                             
Gas
    2       3       1       1       3  
Dry Holes
    1       1       2             1  
Development –
                                       
Oil
    3       4       1       17       18  
Gas
    207       89       42       68       49  
Dry Holes
    1       3       3              
Oil Sands (Cold Lake and other)
                                       
Development –
                                       
Oil
    218       118       332       307       112  
     
Total
    432       218       381       393       183  
     

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

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     Western Provinces
     In 2004, the Company had a working interest in seven gross (three net) exploratory wells and 483 gross (211 net) development wells, while retaining an overriding royalty in an additional 11 gross exploratory wells drilled by others. The majority of the exploratory wells were directed toward extending reserves around existing fields.

     Beaufort Sea/Mackenzie Delta
     Substantial quantities of gas have been found by the Company and others in the Beaufort Sea/Mackenzie Delta.
     In 1999, the Company and three other companies entered into an agreement to study the feasibility of developing Mackenzie Delta gas. The four companies are participating in development planning for onshore natural gas resources totaling approximately 170 billion cubic metres (six trillion cubic feet). The Company’s share of these resources is about 50 percent
     The commercial viability of these natural gas resources, and the pipeline required to transport this natural gas to markets, is dependent on a number of factors. These factors include natural gas markets, support from northern parties, regulatory approvals, environmental considerations, pipeline participation, fiscal terms, and the cost of constructing, operating and abandoning the field production and pipeline facilities. There are complex issues to be resolved and many interested parties to be consulted, before any development could proceed.
     In October 2001, the four companies and the Aboriginal Pipeline Group (“APG”), which represents aboriginal peoples of the Northwest Territories, signed a memorandum of understanding to pursue economic and timely development of a Mackenzie Valley pipeline. In 2002, the four companies completed a preliminary study of the feasibility of developing existing discoveries of Mackenzie Delta gas and based on the results of the study announced together with the APG their intention to begin preparing the regulatory applications needed to develop the gas resources, including construction of a Mackenzie Valley pipeline. In 2003, the Preliminary Information Package for the Mackenzie Gas Project was submitted to the regulatory authorities, and funding and participation agreements between the four companies, the APG and TransCanada PipeLines Limited were reached for the proposed Mackenzie Valley pipeline. In late 2004, the four companies and the APG signed agreements covering the development and operations of the Mackenzie Valley pipeline. In October 2004, the main regulatory applications and environmental impact statement for the project were filed with the National Energy Board and other boards, panels and agencies responsible for assessing and regulating energy developments in the Northwest Territories. The regulatory review process is expected to take up to 24 months. The initial cost for the project is estimated to be about $7 billion with the Company’s share of the cost estimated to be about $3 billion.
     Other land holdings include majority interests in 20 and minority interests in six “significant discovery” licences granted by the Government of Canada as the result of previous oil and gas discoveries, all of which are managed by the Company and majority interests in two and minority interests in 16 other “significant discovery” licences and one production licence, managed by others.

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

     Atlantic Offshore
     The Company manages five “significant discovery” licences granted by the Government of Canada in the Atlantic offshore. The Company also has minority interests in 27 “significant discovery” licences, and five production licences, managed by others.
     In 2004 the Company’s nine percent working interest in an exploration licence for about 74,000 gross hectares (183,000 gross acres) in the Sable Island area off the coast of the Province of Nova Scotia expired.
     In 1998, the Company acquired a 20 percent interest in an exploration licence for about 23,500 gross hectares (58,100 gross acres) in the Sable Island area. One exploratory well was completed in 2004 in that area, without commercial success.
     In 1999, the Company acquired a 20 percent interest in six exploration licences for about 217,000 gross hectares (536,000 gross acres) in the Sable Island area. One exploratory well was completed in 2000 in that area, without commercial success. In 2004, five of these exploration licences totalling about 196,000 gross hectares (484,000 gross acres) were allowed to expire. Also in 1999, the Company acquired a 100 percent interest in two exploration licences for about 225,000 gross hectares (556,000 gross acres) farther offshore in deeper water. A 3-D seismic evaluation program was begun in 2000 in that area, and was completed in 2001, and in 2002 there were 3-D seismic and geological evaluations. In 2002, the Company signed a farmout agreement with another company whereby that company earned a 30 percent interest in these licences by participating in the first exploration well. In 2003, one exploratory well was drilled on these licences, without commercial success. In 2004, the Company allowed the undrilled licence to expire while retaining its 70 percent interest in the other exploration licence for about 113,000 gross hectares (279,000 gross acres). In early 2001, the Company acquired about a 17 percent interest in three additional deep water exploration licences for about 475,000 gross hectares (1,174,000 gross acres). In 2004, these licences were allowed to expire. The Company is not planning further exploration in these areas.

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

     Petroleum Products

      Supply
      To supply the requirements of its own refineries and condensate requirements for blending with crude bitumen, the Company supplements its own production with substantial purchases from others.
      The Company purchases domestic crude oil at freely negotiated prices from a number of sources. Domestic purchases of crude oil are generally made under 30-day contracts. There are no domestic purchases of crude oil under contracts longer than 60 days.
      Crude oil from foreign sources is purchased by the Company at competitive prices mainly through Exxon Mobil Corporation (which has beneficial access to major market sources of crude oil throughout the world).

      Refining
      The Company owns and operates four refineries. Two of these, the Sarnia refinery and the Strathcona refinery, have lubricating oil production facilities. The Strathcona refinery processes Canadian crude oil, and the Dartmouth, Sarnia and Nanticoke refineries process a combination of Canadian and foreign crude oil. In addition to crude oil, the Company purchases finished products to supplement its refinery production.
      In 2004, capital expenditures of about $159 million were made at the Company’s refineries. About 60 percent of those expenditures were on new facilities required to meet Government of Canada regulations on the sulphur level in motor fuels with the remaining expenditures being on safety and efficiency improvements, and environmental control projects.
      The approximate average daily volumes of refinery throughput during the five years ended December 31, 2004, and the daily rated capacities of the refineries at December 31, 1999 and 2004, were as follows:

                                                         
    Average Daily Volumes of     Daily Rated  
    Refinery Throughput (1)     Capacities at  
    Year Ended December 31     December 31 (2)  
    2004     2003     2002     2001     2000     2004     1999  
    (thousands of cubic metres)  
Strathcona, Alberta
    27.1       27.6       26.0       25.4       27.0       29.8       28.6  
Sarnia, Ontario
    17.2       14.7       16.5       16.5       16.2       19.2       19.2  
Dartmouth, Nova Scotia
    12.7       13.0       12.5       12.3       11.2       13.1       13.1  
Nanticoke, Ontario
    17.3       16.3       16.2       17.2       17.2       17.8       17.8  
     
Total
    74.3       71.6       71.2       71.4       71.6       79.9       78.7  
     
                                                         
    Average Daily Volumes of     Daily Rated  
    Refinery Throughput (1)     Capacities at  
    Year Ended December 31     December 31 (2)  
    2004     2003     2002     2001     2000     2004     1999  
    (thousands of barrels)  
Strathcona, Alberta
    170       174       163       160       170       187       180  
Sarnia, Ontario
    108       92       104       104       102       121       121  
Dartmouth, Nova Scotia
    80       82       78       77       70       82       82  
Nanticoke, Ontario
    109       102       102       108       108       112       112  
     
Total
    467       450       447       449       450       502       495  
     


(1)   Refinery throughput is the volume of crude oil and feedstocks that is processed in the refinery atmospheric distillation units.
(2)   Rated capacities are based on definite specifications as to types of crude oil and feedstocks that are processed in the refinery atmospheric distillation units, the products to be obtained and the refinery process, adjusted to include an estimated allowance for normal maintenance shutdowns. Accordingly, actual capacities may be higher or lower than rated capacities due to changes in refinery operation and the type of crude oil available for processing.

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

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

      Marketing
      The Company markets more than 700 petroleum products throughout Canada under well known brand names, notably Esso, to all types of customers.
      The Company sells to the motoring public through approximately 2,000 Esso service stations, of which about 720 are Company owned or leased, but none of which are Company operated. The Company continues to improve its Esso service station network, providing more customer services such as car washes and convenience stores, primarily at high volume sites in urban centres.
      The Canadian farm, residential heating and small commercial markets are served through about 100 sales facilities, of which about 40 also sell fertilizers to the western Canadian farm markets. Heating oil is provided through authorized dealers as well as through three Company operated Home Comfort facilities in urban markets. The Company also sells petroleum products to large industrial and commercial accounts as well as to other refiners and marketers.
      The approximate daily volumes of petroleum products sold during the five years ended December 31, 2004, are set out in the following table:
                                         
    2004     2003     2002     2001     2000  
    (thousands a day)  
Gasolines:
                                       
Cubic metres
    33.2       33.0       32.9       32.3       32.0  
Barrels
    209       208       207       203       201  
Heating, Diesel and Jet Fuels:
                                       
Cubic metres
    27.3       26.2       25.0       26.5       27.5  
Barrels
    172       165       157       166       173  
Heavy Fuel Oils:
                                       
Cubic metres
    5.9       5.4       4.9       5.4       5.1  
Barrels
    37       34       31       34       32  
Lube Oils and Other Products (1):
                                       
Cubic metres
    7.0       5.8       6.4       5.4       5.0  
Barrels
    44       36       41       34       31  
Net petroleum product sales:
                                       
Cubic metres
    73.4       70.4       69.2       69.6       69.6  
Barrels
    462       443       436       437       437  
 
Sales under purchase and sale agreements:
                                       
Cubic metres
    14.2       14.6       13.9       11.6       10.7  
Barrels
    89       92       87       73       67  
 
Total:
                                       
Cubic metres
    87.6       85.0       83.1       81.2       80.3  
Barrels
    551       535       523       510       504  


(1)   Includes 1.0 thousand cubic metres (6 thousand barrels) per day of butane commencing in 2002. Butane is not included in prior years.

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

                 
2004   2003   2002   2001   2000
 
93.0%
  93.3%   91.5%   93.4%   94.0%

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

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Chemicals
      The Company’s Chemicals operations manufacture and market ethylene, benzene, aromatic and aliphatic solvents, plasticizer intermediates and polyethylene resin. Its major petrochemical and polyethylene manufacturing operations are located in Sarnia, Ontario, adjacent to the Company’s petroleum refinery. There is also a heptene and octene plant located in Dartmouth, Nova Scotia.
      The Company’s average daily sales of petrochemicals during the five years ended December 31, 2004, were as follows:

                                         
    2004     2003     2002     2001     2000  
    (thousands a day)  
Petrochemicals:
                                       
Tonnes
    3.3       3.3       3.5       3.3       3.1  
Tons
    3.6       3.6       3.9       3.6       3.4  

Research
      In 2004, the Company’s research expenditures in Canada, before deduction of investment tax credits, were $40 million, as compared with $36 million in 2003 and $50 million in 2002. Those funds were used mainly for developing improved heavy crude oil recovery methods and better lubricants.
      A research facility to support the Company’s natural resources operations is located in Calgary, Alberta. Research in these laboratories is aimed at developing new technology for the production and processing of crude bitumen. About 40 people were involved in this type of research in 2004. The Company also participated in bitumen recovery and processing research for tar sands development through its interest in Syncrude, which maintains research facilities in Edmonton, Alberta and through research arrangements with others.
      In Company laboratories in Sarnia, Ontario, research is mainly conducted on the development and improvement of lubricants and fuels. About 120 people were employed in this type of research at the end of 2004. Also in Sarnia, there are about 15 people engaged in new product development for the Company’s and Exxon Mobil Corporation’s polyethylene injection and rotational molding businesses.
      The Company has scientific research agreements with affiliates of Exxon Mobil Corporation which provide for technical and engineering work to be performed by all parties, the exchange of technical information and the assignment and licensing of patents and patent rights. These agreements provide mutual access to scientific and operating data related to nearly every phase of the petroleum and petrochemical operations of the parties.

Environmental Protection
      The Company is concerned with and active in protecting the environment in connection with its various operations. The Company works in cooperation with government agencies and industry associations to deal with existing and to anticipate potential environmental protection issues. In the past five years, the Company has spent about $825 million on environmental protection and facilities. In 2004, the Company’s capital expenditures relating to environmental protection totaled approximately $130 million, and are expected to be about $350 million in 2005. The increased environmental expenditures over the past three years primarily reflect spending on two major projects. One project completed in 2004, costing $600 million, reduced sulphur in motor gasolines, meeting a requirement of the Government of Canada a year in advance. The second project underway in 2004 is to meet a new Government of Canada regulation requiring ultra-low sulphur on-road diesel fuel commencing in 2006 and which is to be fully implemented in 2007. In 2004, there were capital expenditures of about $90 million on this second project, which is expected to cost about $500 million when completed. Capital expenditures on safety related projects in 2004 were approximately $20 million.

Human Resources
      At December 31, 2004, the Company employed full-time approximately 6,100 persons compared with about 6,300 at the end of 2003 and 6,500 at the end of 2002. About eight percent of those employees are members of unions. The Company continues to maintain a broad range of benefits, including illness, disability and survivor benefits, a savings plan and pension plan.

Competition
      The Canadian petroleum, natural gas and chemical industries are highly competitive. Competition includes the search for and development of new sources of supply, the construction and operation of crude oil and refined products pipelines and the refining, distribution and marketing of petroleum products and chemicals. The petroleum industry also competes with other industries in supplying energy, fuel and other needs of consumers.

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Government Regulation

      Petroleum and Natural Gas Rights
      Most of the Company’s petroleum and natural gas rights were acquired from governments, either federal or provincial. Reservations, permits or licences are acquired from the provinces for cash and entitle the holder to obtain leases upon completing specified work. Leases may also be acquired for cash. A lease entitles the holder to produce petroleum or natural gas from the leased lands. The holder of a licence relating to Canada Lands and the Atlantic Offshore is generally required to make cash payments or to undertake specified work or amounts of exploration expenditures in order to retain the holder’s interest in the land and may become entitled to produce petroleum or natural gas from the licenced land.

      Crude Oil
      Production
      The maximum allowable gross production of crude oil from wells in Canada is subject to limitation by various regulatory authorities on the basis of engineering and conservation principles.

      Exports
      Export contracts of more than one year for light crude oil and petroleum products and two years for heavy crude oil (including crude bitumen) require the prior approval of the National Energy Board (the “NEB”) and the Government of Canada.

      Natural Gas
      Production
      The maximum allowable gross production of natural gas from wells in Canada is subject to limitation by various regulatory authorities on the basis of engineering and conservation principles. A permit is required from the Alberta Energy and Utilities Board, subject to the approval of the Province of Alberta, for the removal from Alberta of natural gas produced in that province.

      Exports
      The Government of Canada has the authority to regulate the export price for natural gas and has a gas export pricing policy which accommodates export prices for natural gas negotiated between Canadian exporters and U.S. importers.
      Exports of natural gas from Canada require approval by the NEB and the Government of Canada. The Government of Canada allows the export of natural gas by NEB order without volume limitation for terms not exceeding 24 months.

      Royalties
      The Government of Canada and the provinces in which the Company produces crude oil and natural gas impose royalties on production from lands where they own the mineral rights. Some producing provinces also receive revenue by imposing taxes on production from lands where they do not own the mineral rights.
      Different royalties are imposed by the Government of Canada and each of the producing provinces. Royalties imposed by the producing provinces on crude oil vary depending on well production volumes, selling prices, recovery methods and the date of initial production. Royalties imposed by the producing provinces on natural gas and natural gas liquids vary depending on well production volumes, selling prices and the date of initial production. For information with respect to royalty rates for Norman Wells, Cold Lake and Syncrude, see “Natural Resources – Petroleum and Natural Gas Production”.

      Investment Canada Act
      The Investment Canada Act requires Government of Canada approval, in certain cases, of the acquisition of control of a Canadian business by an entity that is not controlled by Canadians. In certain circumstances, the acquisition of natural resource properties may be considered to be a transaction that constitutes an acquisition of control of a Canadian business requiring Government of Canada approval. The Act requires notification of the establishment of new unrelated businesses in Canada by entities not controlled by Canadians, but does not require Government of Canada approval except when the new business is related to Canada’s cultural heritage or national identity. By virtue of the majority stock ownership of the Company by Exxon Mobil Corporation, the Company is considered to be an entity which is not controlled by Canadians.

The Company Online
      The Company’s website www.imperialoil.ca contains a variety of corporate and investor information which are available free of charge, including the Company’s annual report on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K and amendments to these reports. These reports are made available as soon as reasonably practicable after they are filed or furnished to the U.S. Securities and Exchange Commission.

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

Item 3. Legal Proceedings.
      Not applicable.

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

PART II

Item 5.  Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

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

Quarterly Financial and Stock Trading Data

                                                                 
    2004     2003  
    three months ended     three months ended  
    Mar. 31     June 30     Sept. 30     Dec. 31     Mar. 31     June 30     Sept. 30     Dec. 31  
     
Per-share information (dollars)
                                                               
Dividends (declared quarterly)
    0.22       0.22       0.22       0.22       0.21       0.22       0.22       0.22  
 
Share prices (dollars)
                                                               
Toronto Stock Exchange
                                                               
High
    64.45       64.25       66.76       73.65       47.80       47.40       53.49       58.22  
Low
    56.42       58.40       59.50       65.28       43.48       43.20       45.62       50.16  
Close
    58.87       62.40       65.48       71.15       47.35       47.10       50.80       57.53  
American Stock Exchange ($U.S.)
                                                               
High
    48.70       47.13       52.22       62.45       32.20       34.99       38.79       44.75  
Low
    42.34       43.17       45.50       51.43       28.25       29.94       33.04       37.24  
Close
    44.84       46.82       51.71       59.37       32.14       34.92       37.21       44.42  

      The Company’s shares are listed on the Toronto Stock Exchange and are admitted to unlisted trading on the American Stock Exchange in New York. The symbol on these exchanges for the Company’s common shares is IMO. Share prices were obtained from stock exchange records.
      As of February 28, 2005, there were 14,868 holders of record of common shares of the Company.
      During the period October 1, 2004 to December 31, 2004, the Company issued 85,925 common shares for $46.50 per share as a result of the exercise of stock options by the holders of the stock options, who are all employees or former employees of the Company, in sales of those common shares outside the U.S.A. which were not registered under the Securities Act in reliance on Regulation S thereunder.

Issuer purchases of equity securities (1)

                                             
 
        (a) Total number               (c) Total number of shares     (d) Maximum number (or approximate  
        of shares     (b) Average price     purchased as part     dollar value) or shares that  
        (or units)     paid per share     of publicly announced     may yet be purchased under  
  Period     purchased     (or unit)     plans or programs     the plans or programs  
 
October 2004
(October 1 - October 31)
      909,277       $ 69.34         909,277         12,981,800    
 
November 2004
(November 1 - November 30)
      2,043,336       $ 70.61         2,043,336         10,903,650    
 
December 2004
(December 1 - December 31)
      1,198,579       $ 70.25         1,198,579         9,670,839    
 


(1)   The purchases were pursuant to a 12 month normal course share purchase program that was renewed on June 23, 2004 under which the Company may purchase up to 17,864,398 of its outstanding common shares less any shares purchased by the employee savings plan and Company pension fund. If not previously terminated, the program will terminate on June 22, 2005.

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Item 6. Selected Financial Data.

                                         
    2004     2003     2002     2001     2000  
                    (millions)                  
Total revenues
  $ 22,460     $ 19,208     $ 17,042     $ 17,253     $ 18,051  
Net income
    2,052       1,705       1,214       1,223       1,408  
Total assets
    14,027       12,337       12,003       10,888       11,266  
Long term debt
    367       859       1,466       1,029       1,037  
Other long term obligations
    1,525       1,314       1,822       1,303       1,110  
 
                  (dollars)                
Net income/share – basic
    5.75       4.58       3.20       3.11       3.37  
Net income/share – diluted
    5.74       4.58       3.20       3.11       3.37  
Cash dividends/share
    0.88       0.87       0.84       0.83       0.78  

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

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

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

Business environment and outlook
 
Natural resources

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

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

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

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

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

Financial statistics

                                         
    2004     2003     2002     2001     2000  
                    (millions)                  
Net income
  $ 1,487     $ 1,143     $ 1,042     $ 941     $ 1,165  
Revenues
    6,625       5,648       4,894       5,321       5,900  

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

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

Average realizations and prices

                                         
    2004     2003     2002     2001     2000  
Conventional crude oil realizations (a barrel)
  $ 48.96     $ 40.10       $36.81       $35.56     $ 41.52  
Natural gas liquids realizations (a barrel)
    33.78       32.09       23.38       29.31       29.57  
Natural gas realizations (a thousand cubic feet)
    6.78       6.60       4.02       5.72       4.99  
Par crude oil price at Edmonton (a barrel)
    53.26       43.93       40.44       39.64       45.02  
Heavy crude oil price at Hardisty (Bow River, a barrel)
    37.98       33.00       31.85       25.11       34.49  

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

Crude oil and NGLs – production and sales (a)

                                                                                 
    2004     2003     2002     2001     2000  
    gross     net     gross     net     gross     net     gross     net     gross     net  
    (thousands of barrels a day)  
Conventional crude oil
    43       33       46       35       51       39       55       42       60       46  
Cold Lake
    126       112       129       116       112       106       128       121       119       102  
Syncrude
    60       59       53       52       57       57       56       52       51       42  
     
Total crude oil production
    229       204       228       203       220       202       239       215       230       190  
NGLs available for sale
    33       26       28       22       27       21       28       22       30       23  
     
Total crude oil and NGL production
    262       230       256       225       247       223       267       237       260       213  
Cold Lake sales, including diluent (b)
    167               170               145               167               156          
NGL sales
    42               39               40               43               42          

Natural gas – production and sales (a)

                                                                                 
    2004     2003     2002     2001     2000  
    gross     net     gross     net     gross     net     gross     net     gross     net  
    (millions of cubic feet a day)  
Production (c)
    569       518       513       457       530       463       572       466       526       459  
Sales
    520               460               499               502               419          


(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.

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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).

Financial statistics

                                         
    2004     2003     2002     2001     2000  
    (millions)  
Net income
  $ 500     $ 407     $ 127     $ 353     $ 313  
Revenues
    19,211       16,058       14,434       14,405       15,120  

Sales of petroleum products

                                         
    2004     2003     2002     2001     2000  
    (millions of litres a day (a))  
Gasolines
    33.2       33.0       32.9       32.3       32.0  
Heating, diesel and jet fuels
    27.3       26.2       25.0       26.5       27.5  
Heavy fuel oils
    5.9       5.4       4.9       5.4       5.1  
Lube oils and other products
    7.0       5.8       6.4       5.4       5.0  
     
Net petroleum products sales
    73.4       70.4       69.2       69.6       69.6  
Sales under purchase and sale agreements
    14.2       14.6       13.9       11.6       10.7  
     
Total sales of petroleum products
    87.6       85.0       83.1       81.2       80.3  
     
Total domestic sales of petroleum products (percent)
    93.0       93.3       91.5       93.4       94.0  

Refinery utilization

                                         
    2004     2003     2002     2001     2000  
    (millions of litres a day (a))
Total refinery throughput (b)
    74.3       71.6       71.2       71.4       71.6  
Refinery capacity at December 31
    79.9       79.9       79.4       79.1       78.7  
Utilization of total refinery capacity (percent)
    93       90       90       90       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.

      Margins were stronger in the refining segment of the industry in 2004 compared with those in 2003, as international wholesale product prices increased more than raw material costs. However, the effects of higher international margins were reduced partially by a higher Canadian dollar. Retail margins in the fuels marketing area were lower in 2004, reflecting the impact of highly competitive markets.
      Throughput at the refineries has increased with refinery capacity utilization averaging a record 93 percent during 2004, compared with 90 percent in 2003 (2002 – 90 percent).
      The Company’s total sales volumes, including those resulting from reciprocal supply agreements with other companies, were 87.6 million litres a day, compared with 85 million litres in 2003 (2002 – 83.1 million). Excluding sales resulting from reciprocal agreements, sales were 73.4 million litres a day, compared with 70.4 million litres in 2003 (2002 – 69.2 million).
      Operating costs increased by about two percent in 2004 from the previous year, mainly because of higher energy, environmental and depreciation costs.

Chemicals
      Net income from chemical operations was $100 million in 2004, compared with $37 million in 2003 (2002 – $52 million). Strong industry polyethylene and benzene margins were the main factors contributing to the improvement.

Financial statistics

                                         
    2004     2003     2002     2001     2000  
    (millions)  
Net income
  $ 100     $ 37     $ 52     $ 23     $ 59  
Revenues
    1,509       1,232       1,164       1,175       1,173  

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Sales volumes

                                         
    2004     2003     2002     2001     2000  
    (thousands of tonnes a day (a))  
Polymers & basic chemicals
    2.7       2.4       2.5       2.4       2.2  
Intermediates and other
    0.6       0.9       1.0       0.9       0.9  
     
Total chemicals
    3.3       3.3       3.5       3.3       3.1  


(a)   Volumes a day are calculated by dividing total volumes for the year by the number of days in the year.

      Total revenues from chemical operations were $1,509 million, compared with $1,232 million in 2003 (2002 – $1,164 million). Higher prices for polyethylene, intermediate chemicals and aromatics were the contributing factors.
      The average industry price of polyethylene was $1,584 a tonne in 2004, up 12 percent from $1,415 a tonne in 2003 (2002 – $1,229). Margins were higher as demand for polyethylene products grew.
      Sales of chemicals were 3,300 tonnes a day, unchanged from 2003 (2002 – 3,500 tonnes), while polyethylene and benzene sales were up three percent and 32 percent respectively over 2003.
      Operating costs in the chemicals segment for 2004 were about the same as 2003. Higher energy costs were offset by lower depreciation expense. A significant portion of the property, plant and equipment currently used in production and manufacturing, has been fully depreciated.

Corporate and other
      Net income from corporate and other accounts was negative $35 million in 2004, compared with positive $118 million in 2003 (2002 – negative $7 million). Lower net income in 2004 was mainly due to the absence of the favourable foreign exchange effects on the Company’s U.S. dollar denominated debt, which was replaced with Canadian dollar denominated debt in June and July of 2003. Net income for 2004 also included a nonrecurring after-tax write-down of $42 million on a north Toronto property, which was acquired in 1991 to be the Company’s future Toronto headquarters site. The remeasurement at fair value of this property reflected a change in its intended use and management’s commitment to sell following the announcement of the relocation of the Company’s headquarters to Calgary.

Liquidity and capital resources

Sources and uses of cash

                 
    2004     2003  
    (millions of dollars)  
Cash provided by/(used in)
               
Operating activities
    3,312       2,227  
Investing activities
    (1,306 )     (1,426 )
Financing activities
    (1,175 )     (1,119 )
     
 
               
Increase/(decrease) in cash and cash equivalents
    831       (318 )
     
 
               
Cash and cash equivalents at end of year
    1,279       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. The Company’s large and diverse portfolio of development opportunities and the complementary nature of its business segments help mitigate the overall risks of the Company and associated cash flow. Further, due to its financial strength, debt capacity and diverse portfolio of opportunities, the risk associated with failure or delay of any single project would not have a significant impact on the Company’s liquidity or ability to generate sufficient cash flows for operations and its fixed commitments.

Cash flow from operating activities
      Cash provided by operating activities was $3,312 million, up from $2,227 million in 2003 (2002 – $1,688 million). The increased cash inflow was mainly due to higher net income, timing of scheduled income tax payments and the additional funding contributions to the employee pension plan in 2003.

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Capital and exploration expenditures
     Total capital and exploration expenditures were $1,445 million in 2004, down slightly from $1,559 million in 2003 (2002 – $1,612 million).
     The funds were used mainly to invest in growth opportunities in the oil sands and the Mackenzie gas project, to upgrade refineries to meet low sulphur diesel requirements and to enhance the Company’s retail network. About $150 million was spent on projects related to reducing the environmental impact of its operations and improving safety including about $90 million on the $500 million capital project to produce low sulphur diesel.
     The following table shows the Company’s capital and exploration expenditures for natural resources during the five years ending December 31, 2004:

                                         
    2004     2003     2002     2001     2000  
     
            (millions)                  
Exploration
  $ 60     $ 57     $ 39     $ 49     $ 56  
Production
    234       181       143       109       110  
Heavy oil
    819       769       804       588       268  
     
Total
  $ 1,113     $ 1,007     $ 986     $ 746     $ 434  
     

     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:

                                         
    2004     2003     2002     2001     2000  
     
                    (millions)                  
Marketing
  $ 85     $ 91     $ 133     $ 171     $ 121  
Refining and supply
    178       369       399       118       100  
Other (a)
    20       18       57       50       11  
     
Total
  $ 283     $ 478     $ 589     $ 339     $ 232  


(a)   Consists primarily of purchases of real estate.

     For the petroleum products segment, capital expenditures decreased to $283 million in 2004, compared with $478 million in 2003 (2002 – $589 million), primarily because of the completion of the project to significantly reduce sulphur content in gasoline, which began in 2001. New investments in 2004 included about $90 million spent on the initial phases of a three year project to reduce sulphur content in diesel. In addition, $24 million was spent on other refinery projects to improve energy efficiency and increase yield. Major investments were also made to upgrade the network of Esso service stations during the year.
     Capital expenditures for the petroleum products segment in 2005 are expected to be about $550 million. Major items include additional investment in refining facilities to reduce the sulphur content in diesel to meet regulatory requirements and continued enhancements to the Company’s retail network.
     The following table shows the Company’s capital expenditures for the chemicals operations during the five years ending December 31, 2004.

                                         
    2004     2003     2002     2001     2000  
     
    (millions)  
Chemicals
  $ 15     $ 41     $ 25     $ 30     $ 13  

     Of the capital expenditures for chemicals in 2004, the major investment focused on improving energy efficiency, yields and process control technology.

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     Planned capital expenditures for chemicals in 2005 will be about $20 million.
     Total capital and exploration expenditures for the Company in 2005, which will focus mainly on growth and productivity improvements, are expected to total about $1.6 billion and will be financed from internally generated funds.

Cash flow from financing activities
     In June, the Company renewed the normal course issuer bid (share repurchase program) for another 12 months. During 2004, the Company purchased about 14 million shares for $872 million (2003 – 16 million shares for $799 million). Since the Company initiated its first share repurchase program in 1995, the Company has purchased 233 million shares – representing about 40 percent of the total outstanding at the start of the program – with resulting distributions to shareholders of $6.8 billion.
     The Company declared dividends totalling 88 cents a share in 2004, up from 87 cents in 2003 (2002 – 84 cents). Regular per share dividends paid have increased in each of the past 10 years and, since 1986, payments per share have grown by more than 65 percent.
     Total debt outstanding at the end of 2004, excluding the Company’s share of equity Company debt, was $1,443 million, compared with $1,432 million at the end of 2003 (2002 – $1,538 million). Debt represented 19 percent of the Company’s capital structure at the end of 2004, compared with 21 percent at the end of 2003 (2002 – 24 percent).
     Debt related interest incurred in 2004, before capitalization of interest, was $37 million, down from $38 million in 2003 (2002 – $40 million). The average effective interest rate on the Company’s debt was 2.8 percent in 2004, compared with 2.9 percent in 2003 (2002 – 2.1 percent).
     On May 6, 2004, the Company filed a final short form shelf prospectus in Canada in connection with the issuance of medium term notes over the 25 month period that the shelf prospectus remains valid. The unsecured notes will be issued from time to time at the discretion of the Company in an aggregate amount not to exceed $1 billion. The Company has not issued any notes under this shelf prospectus.

Financial percentages and ratios

                                         
    2004     2003     2002     2001     2000  
     
Total debt as a percentage of capital (a)
    19       21       24       26       25  
Interest coverage ratios
                                       
Earnings basis (b)
    83       64       46       26       23  
Cash flow basis (c)
    108       80       63       36       29  


(a)   Current and long term portions of debt (page F-5) divided by debt and shareholders’ equity (page F-5).
(b)   Net income (page F-3), debt related interest expense before capitalization (page F-20, note 15) and income taxes (page F-3) divided by debt related interest expense before capitalization.
(c)   Cash flow from net income adjusted for the cumulative effect of accounting change and other non-cash items (page F-4), current income tax expense (page F-12, note 4) and debt related interest expense before capitalization divided by debt related interest expense before capitalization.

Contractual obligations
     To more fully explain the Company’s financial position, the following table shows the Company’s contractual obligations outstanding at December 31, 2004. It brings together, for easier reference, data from the consolidated balance sheet and from individual notes to the consolidated financial statements.

                                         
    Financial       Payment due by period  
    statement note             2006 to     2010 and     Total  
millions of dollars   reference     2005     2009     beyond     amount  
 
Long term debt and capital leases
  note 3   $ 995     $ 334     $ 33     $ 1,362  
Company’s share of equity Company debt
            56                   56  
Operating leases
  note 12     62       181       91       334  
Unconditional purchase obligations (a)
  note 12     102       168       55       325  
Firm capital commitments (b)
  note 12     119       52             171  
Pension obligations (c)
  note 7     371       91       297       759  
Asset retirement obligations (d)
  note 8     36       116       176       328  
Other long term agreements (e)
  note 12     241       378       198       817  


(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.

(Table continued on following page)

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(c)   The amount by which accumulated benefit obligations (ABO) exceeded the fair value of fund assets at year end (page F-13, 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.

     The Company was contingently liable at December 31, 2004, for a maximum of $175 million relating to guarantees for purchasing operating equipment and other assets from its rural marketing associates upon expiry of the associate agreement or the death or resignation of the associate. The Company expects that the fair value of the operating equipment and other assets so purchased would cover the maximum potential amount of future payment under the guarantees.
     Various lawsuits are pending against Imperial Oil Limited and its subsidiaries. Based on a consideration of all relevant facts and circumstances, the Company does not believe the ultimate outcome of any currently pending lawsuits against the Company will have a material adverse effect upon the Company’s operations or financial condition. There are no events or uncertainties known to management beyond those already included in reported financial information that would indicate a material change in future operating results or financial condition.

Recently issued Statement of Financial Accounting Standards
     In December 2004, the Financial Accounting Standards Board (FASB) issued a revised Statement of Financial Accounting Standards No. 123 (SFAS 123R), Share Based Payments. SFAS 123R requires compensation costs related to share based payment arrangements to employees to be recognized in the income statement over the period that an employee provides service in exchange for the award. The amount of the compensation cost will be measured based on the grant date fair value of the instruments issued. In addition, liability awards will be remeasured each reporting period through settlement. SFAS 123R is effective as of July 1, 2005 for all awards granted or modified after that date and for those awards granted prior to that date for which the requisite employee service has not yet been rendered. SFAS 123R will have no impact on the Company because in 2003 the Company adopted a policy of expensing all share based payments that is consistent with the provisions of SFAS 123R and the requisite employee service for all prior year outstanding stock options has been rendered.

Emerging accounting and reporting issues

     Accounting for purchases and sales of inventory with the same counterparty
     At its November 2004 meeting, the Emerging Issues Task Force (EITF) of FASB began discussion of Issue 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty”. This Issue addresses the question of when it is appropriate to measure purchases and sales of inventory at fair value and record them in cost of sales and revenues and when they should be recorded as an exchange measured at the book value of the item sold. The EITF did not reach a consensus on this issue, but requested the FASB staff to further explore the alternative views.
     The Company records certain purchases and sales entered into contemporaneously with the same counterparty as cost of sales and revenues, measured at fair value as agreed upon by a willing buyer and a willing seller. These transactions occur under contractual arrangements that establish the agreement terms either jointly, in a single contract, or separately, in individual contracts. Should the EITF reach a consensus on this issue, requiring these transactions to be recorded as exchanges measured at book value, the reported amounts in “operating revenues” and “purchases of crude oil and products” on the consolidated statement of income would be lower by equal amounts with no impact on net income. The Company has not yet determined the amount by which “operating revenues” and “purchases of crude oil and products” would be lower under this interpretation. A special effort is needed to identify purchase/sale transactions from other monetary purchases and monetary sales. A best effort estimate based on this undertaking is expected to be available in the second quarter of 2005. The Company will disclose this information, if material, once it is available.

Critical accounting policies
     The Company’s financial statements have been prepared in accordance with United States generally accepted accounting principles (GAAP) and include estimates that reflect management’s best judgments. The Company’s accounting and financial reporting fairly reflect its straightforward business model. The Company does not use financing structures for the purpose of altering accounting outcomes or removing debt from the balance sheet. The following summary provides further information about the critical accounting policies and the estimates that are made by the Company to apply those policies. It should be read in conjunction with pages F-7 to F-9.

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Hydrocarbon reserves
     Proved oil, gas and synthetic crude oil reserve quantities are used as the basis of calculating unit of production rates for depreciation and evaluating for impairment. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs and deposits under existing economic and operating conditions. Estimates of synthetic crude oil reserves are based on detailed geological and engineering assessments of in place crude bitumen volume, the mining plan, historical extraction recovery and upgrading yield factors, installed plant operating capacity and operating approval limits.
     The estimation of proved reserves is controlled by the Company through long standing approval guidelines. Reserve changes are made with a well established, disciplined process driven by senior level geoscience and engineering professionals (assisted by a central reserves group with significant independent technical experience) culminating in reviews with and approval by senior management and the Company’s board of directors. Key features of the estimation include rigorous peer reviewed technical evaluations and analysis of well and field performance information, and a requirement that management make a commitment toward the development of the reserves prior to booking. Notably, technical and other professionals involved in the process are not compensated based on the levels of proved reserves bookings.
     Although the Company is reasonably certain that proved reserves will be produced, the timing and ultimate recovery can be affected by a number of factors including completion of development projects, reservoir performance and significant changes in long term oil and gas price levels.
     In compliance with the United States Securities and Exchange Commission regulatory guidance, the Company has reported 2004 reserves on the basis of the day of December 31, 2004, prices and costs (“year end prices”). Resultant changes in Cold Lake bitumen and the associated natural gas reserves from the year end 2003 estimates, which were based on long term projections of oil and gas prices consistent with those used in the Company’s investment decision-making process, are shown in the line titled “Year end price/cost revisions” on page 29. The requirement to use year end prices for reserves estimation introduces single day price focus and volatility in the valuation of reserves to be produced over the next 20 to 30 years. The Company believes that this approach is inconsistent with the long term nature of the natural resources business. The use of prices from a single date is not relevant to the investment decisions made by the Company and annual variations in reserves based on such year end prices are not of consequence in how the business is managed.
     The impact of year end prices on reserve estimation is most clearly shown at Cold Lake where proved bitumen and associated natural gas reserves were reduced by about 485 million oil equivalent barrels as a result of using December 31, 2004 prices, which were unusually low. Prices of Cold Lake bitumen were strong for most of 2004, however, they began to deteriorate in the middle of the fourth quarter and ended on December 31, 2004, 70 percent below the year’s average. Prices quickly rebounded from December 31, and through January 2005 returned to levels that have restored the reserves to the proved category.
     Performance related revisions can include upward or downward changes in previously estimated volumes of proved reserves for existing fields due to the evaluation or revaluation of (1) already available geologic, reservoir or production data, or (2) new geologic or reservoir data. Performance related revisions can also include changes associated with the performance of improved recovery projects and significant changes in either development strategy or production equipment/facility capacity.
     The Company uses the successful efforts method to account for its exploration and production activities. Under this method, costs are accumulated on a field by field basis with certain exploratory expenditures and exploratory dry holes being expensed as incurred. The Company continues to carry as an asset the cost of drilling exploratory wells that find sufficient quantities of reserves to justify their completion as producing wells if the required capital expenditure is made and drilling of additional exploratory wells is underway or firmly planned for the near future. Once exploration activities demonstrate that sufficient quantities of commercially producible reserves have been discovered, continued capitalization is dependent on project reviews, which take place at least annually, to ensure that satisfactory progress toward ultimate development of the reserves is being achieved. Exploratory well costs not meeting these criteria are charged to expense. Capitalized exploratory drilling costs pending the determination of proved reserves or the amount of suspended exploratory well costs were negligible, $2 million and $13 million at December 31, 2004, 2003 and 2002 respectively. Costs of productive wells and development dry holes are capitalized and amortized on the unit of production method for each field. The Company uses this accounting policy instead of the full cost method because it provides a more timely accounting of the success or failure of the Company’s exploration and production activities.

Impact of reserves on depreciation
     The calculation of unit of production depreciation is a critical accounting estimate that measures the depreciation of natural resources assets. It is the ratio of (1) actual volumes produced to (2) total proved developed reserves (those reserves recoverable through existing wells with existing equipment and operating methods) applied to (3) the asset cost. The volumes produced and asset cost are known and while proved developed reserves have a high probability of recoverability, they are based on estimates that are subject to some variability. This variability has generally resulted in net upward revisions of proved reserves in existing fields, as more information becomes available through research and production. Revisions have averaged 16 million oil equivalent barrels per year over the last five years and have resulted from effective reservoir

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management and the application of new technology. While the upward revisions the Company has made over the last five years are an indicator of variability, they have had little impact on the unit of production rates of depreciation because they have been small compared to the large proved reserves base.

Impact of reserves and prices on testing for impairment
     Proved oil and gas properties held and used by the Company are reviewed for impairment whenever events or circumstances indicate that the carrying amounts may not be recoverable. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets.
     The Company estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. In general, impairment analyses are based on proved reserves. Where probable reserves exist, an appropriately risk adjusted amount of these reserves may be included in the impairment evaluation. An asset would be impaired if the undiscounted cash flows were less than its carrying value. Impairments are measured by the amount by which the carrying value exceeds its fair value.
     The impairment evaluation triggers include a significant decrease in current and projected prices or reserve volumes, an accumulation of project costs significantly in excess of the amount originally expected, and historical and current negative operating losses.
     In general, the Company does not view temporarily low oil prices as a triggering event for conducting the impairment tests. The markets for crude oil and natural gas have a history of significant price volatility. Although prices will occasionally drop precipitously, the relative growth/decline in supply versus demand will determine industry prices over the long term and these cannot be accurately predicted. Accordingly, any impairment tests that the Company performs make use of the Company’s long term price assumptions for the crude oil and natural gas markets, petroleum products and chemicals. These are the same price assumptions that are used in the Company’s annual planning and budgeting processes and are also used for capital investment decisions.
     The standardized measure of discounted future cash flows on page 30 is based on the year end 2004 price applied for all future years, as required under Statement of Financial Accounting Standards No. 69 (SFAS 69). Future prices used for any impairment tests will vary from the one used in the SFAS 69 disclosure, and could be lower or higher for any given year.

Retirement benefits
     The Company’s pension plan is managed in compliance with the requirements of governmental authorities and meets funding levels as determined by independent third party actuaries. Pension accounting requires explicit assumptions regarding, among others, the discount rate for the benefit obligations, the expected rate of return on plan assets and the long term rate of future compensation increases. All pension assumptions are reviewed annually by senior management. These assumptions are adjusted only as appropriate to reflect long term changes in market rates and outlook. The long term expected rate of return on plan assets of 8.25 percent used in 2004 compares to actual returns of 10.7 percent and 10.1 percent achieved over the last 10 and 20 year periods ending December 31, 2004. If different assumptions are used, the expense and obligations could increase or decrease as a result. The Company’s potential exposure to changes in assumptions is summarized in note 7 to the consolidated financial statements on page F-13. At the Company, differences between actual returns on plan assets versus long term expected returns are not recorded in the year the differences occur, but rather are amortized in pension expense as permitted by GAAP, along with other actuarial gains and losses over the expected remaining service life of employees. The Company uses the fair value of the plan assets at year end to determine the amount of the actual gain or loss that will be amortized and does not use a moving average value of plan assets. Pension expense represented about one percent of total expenses in 2004.

Asset retirement obligations and other environmental liabilities
     Legal obligations associated with site restoration on the retirement of assets with determinable useful lives are recognized when they are incurred, which is typically at the time the assets are installed. The obligations are initially measured at fair value and discounted to present value. Over time, the discounted asset retirement obligation amount will be accreted for the change in its present value, with this effect included in operating expense. As payments to settle the obligations occur on an ongoing basis and will continue over the lives of the operating assets, which can exceed 25 years, the discount rate will be adjusted only as appropriate to reflect long term changes in market rates and outlook. For 2004, the obligations were discounted at six percent and the accretion expense was $22 million, which was significantly less than one percent of total expenses in the year. There would be no material impact on the Company’s reported financial results if a different discount rate had been used.
     Asset retirement obligations are not recognized for assets with an indeterminate useful life. For these and non-operating assets, the Company accrues provisions for environmental liabilities when it is probable that obligations have been incurred and the amount can be reasonably estimated.

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     Asset retirement obligations and other environmental liabilities are based on engineering estimated costs, taking into account the anticipated method and extent of remediation consistent with legal requirements, current technology and the possible use of the location. Since these estimates are specific to the locations involved, there are many individual assumptions underlying the Company’s total asset retirement obligations and provision for other environmental liabilities. While these individual assumptions can be subject to change, none of them is individually significant to the Company’s reported financial results.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
     The Company is exposed to a variety of financial, operating and market risks in the course of its business. Some of these risks are within the Company’s control, while others are not. For those risks that can be controlled, specific risk management strategies are employed to reduce the likelihood of loss. Other risks, such as changes in international commodity prices and currency exchange rates, are beyond the Company’s control.
     Although the Government of Canada in ratifying the Kyoto Protocol agreed to restrictions of greenhouse gas emissions by the period 2008-2012, it has not determined what measures it will impose on companies. Consequently, attempts to assess any impact on the Company can only be speculative. The Company will continue to monitor the development of legal requirements in this area.
     The Company’s size, strong financial position and the complementary nature of its natural resources, petroleum products and chemicals segments help mitigate the Company’s exposure to changes in these other risks. The Company’s potential exposure to these types of risk is summarized in the table below.
     The Company does not use derivative markets to speculate on the future direction of currency or commodity prices and does not sell forward any part of production from any business segment.
     The following table shows the estimated annual effect, under current conditions, of certain sensitivities of the Company’s after tax net income.

                 
    millions of dollars after tax  
     
Four dollars (U.S.) a barrel change in crude oil prices
    +(- )     200  
Sixty cents a thousand cubic feet change in natural gas prices
    +(- )     20  
One cent a litre change in sales margins for total petroleum products
    +(- )     170  
One cents (U.S.) a pound change in sales margins for polyethylene
    +(- )     7  
One quarter percent decrease (increase) in short term interest rates
    +(- )     2  
Eight cents decrease (increase) in the value of the Canadian dollar versus the U.S. dollar
    +(- )     260  

     The amount quoted to illustrate the impact of each sensitivity represents a change of about 10 percent in the value of the commodity or rate in question at the end of 2004. Each sensitivity calculation shows the impact on net income that results from a change in one factor, after tax and royalties and holding all other factors constant. While these sensitivities are applicable under current conditions, they may not apply proportionately to larger fluctuations.
     The sensitivity of net income to changes in the Canadian dollar versus the U.S. dollar decreased from year end 2003 by about $10 million (after tax) a year for each one cent change. This is primarily due to the unusually low year end prices for Cold Lake bitumen, which is sold in U.S. dollars.

Item 8. Financial Statements and Supplementary Data.
     Reference is made to the Index to Financial Statements on page F-1 of this report.

Syncrude Mining Operations
     Syncrude’s crude bitumen is contained within the unconsolidated sands of the McMurray Formation. Ore bodies are buried beneath 15 to 45 metres (50 to 150 feet) of overburden, have bitumen grades ranging from 4 to 14 weight percent and ore thickness of 35 to 50 metres (115 to 160 feet). Estimates of synthetic crude oil reserves are based on detailed geological and engineering assessments of in-place crude bitumen volume, the mining plan, historical extraction recovery and upgrading yield factors, installed plant operating capacity and operating approval limits. The in-place volume, depth and grade are established through extensive and closely spaced core drilling. Proven reserves include the operating Base and North mines and the Aurora mine. In accordance with the approved mining plan, there are an estimated 1,865 million tonnes (2,055 million tons) of extractable tar sands, in the Base and North mines, with an average bitumen grade of 10.6 weight percent. In addition, at the Aurora mine, there are an estimated 4,060 million tonnes (4,470 million tons) of extractable tar sands at an average bitumen grade of 11.1 weight percent. After deducting royalties payable to the Province of Alberta, the Company estimates its 25 percent net share of proven reserves is equivalent to 120 million cubic metres (757 million barrels) of synthetic crude oil.

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Table of Contents

     The following table sets forth the Company’s share of net proven reserves of Syncrude after deducting royalties payable to the Province of Alberta:

                         
    Synthetic Crude Oil  
    Base Mine and              
    North Mine     Aurora Mine     Total  
     
    (millions of cubic metres)  
Beginning of year 2002
    58       73       131  
Revision of previous estimate
                 
Production
    (3 )     (1 )     (4 )
     
End of year 2002
    55       72       127  
 
Revision of previous estimate
                 
Production
    (2 )     (1 )     (3 )
     
End of year 2003
    53       71       124  
 
Revision of previous estimate
    (16 )     16       0  
Production
    (2 )     (2 )     (4 )
     
End of year 2004
    35       85       120  
     
                         
    Synthetic Crude Oil  
    Base Mine and              
    North Mine     Aurora Mine     Total  
     
        (millions of barrels)  
Beginning of year 2002
    358       463       821  
Revision of previous estimate
                 
Production
    (14 )     (7 )     (21 )
     
End of year 2002
    344       456       800  
 
Revision of previous estimate
                 
Production
    (13 )     (6 )     (19 )
     
End of year 2003
    331       450       781  
 
Revision of previous estimate
    (103 )     100       (3 )
Production
    (11 )     (10 )     (21 )
     
End of year 2004
    217       540       757  
     

Oil and Gas Producing Activities
     The following information is provided in accordance with the United States’ Statement of Financial Accounting Standards No. 69, “Disclosures about Oil and Gas Producing Activities”.

Results of operations

                         
    2004     2003     2002  
     
    (millions of dollars)  
Sales to customers
  $ 2,160     $ 2,067     $ 1,485  
Intersegment sales
    976       665       797  
     
Total sales (1) (2)
  $ 3,136     $ 2,732     $ 2,282  
Production expenses (2)
    915       926       736  
Exploration expenses
    44       55       30  
Depreciation and depletion
    565       463       426  
Income taxes
    532       364       350  
     
Results of operations
  $ 1,080     $ 924     $ 740  
     

Capital and exploration expenditures

                         
    2004     2003     2002  
     
    (millions of dollars)  
Property costs (3)
                       
Proved
  $     $     $ 13  
Unproved
    1       2       5  
Exploration costs
    43       55       34  
Development costs
    408       339       469  
     
Total capital and exploration expenditures
  $ 452     $ 396     $ 521  
     

(Table continued on following page)

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Property, plant and equipment

                 
    2004     2003  
     
    (millions of dollars)  
Property costs (3)
               
Proved
  $ 3,328     $ 3,332  
Unproved
    141       163  
Producing assets
    6,099       5,775  
Support facilities
    122       125  
Incomplete construction
    235       200  
     
Total cost
  $ 9,925     $ 9,595  
Accumulated depreciation and depletion
    6,514       6,012  
     
Net property, plant and equipment
  $ 3,411     $ 3,583  
     


(1)   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.
(2)   Beginning in 2004, fuel consumed in operations, previously netted against total sales, has been reclassified as production expenses. Prior period amounts have been reclassified for comparative purposes. This reclassification has no impact on the results of operations.
(3)   “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.

Net proved developed and undeveloped reserves (1)

                                 
    Crude oil and natural gas liquids  
    Conventional     Cold Lake     Total     Natural Gas  
     
    (millions of cubic metres)     (billions of  
                            cubic metres)  
Beginning of year 2002
    26       128       154       40  
Revisions of previous estimates and improved recovery
          5       5        
(Sale)/purchase of reserves in place
                       
Discoveries and extensions
                       
Production
    (3 )     (6 )     (9 )     (5 )
     
End of year 2002
    23       127       150       35  
Revisions of previous estimates and improved recovery
          1       1       (1 )
(Sale)/purchase of reserves in place
                       
Discoveries and extensions
                       
Production
    (3 )     (7 )     (10 )     (5 )
     
End of year 2003
    20       121       141       29  
Performance related revisions and improved recovery
    1       (3 )     (2 )     1  
(Sale)/purchase of reserves in place
                       
Discoveries and extensions
                       
Production
    (3 )     (6 )     (9 )     (5 )
     
Total before year end price/cost revisions
    18       112       130       25  
Year end price/cost revisions
    0       (75 )     (75 )     (3 )
     
End of year 2004
    18       37       55       22  
     


(1)   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 101.325 kilopascals absolute at 15 degrees Celsius.

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Table of Contents

                                 
    Crude oil and natural gas liquids  
    Conventional     Cold Lake     Total     Natural Gas  
     
    (millions of barrels)     (billions of  
                            cubic feet)  
Beginning of year 2002
    165       807       972       1,414  
Revisions of previous estimates and improved recovery
    3       33       36       (26 )
(Sale)/purchase of reserves in place
                      2  
Discoveries and extensions
                      3  
Production
    (22 )     (39 )     (61 )     (169 )
     
End of year 2002
    146       801       947       1,224  
Revisions of previous estimates and improved recovery
    1       5       6       (40 )
(Sale)/purchase of reserves in place
                       
Discoveries and extensions
                      6  
Production
    (21 )     (43 )     (64 )     (167 )
     
End of year 2003
    126       763       889       1,023  
Performance related revisions and improved recovery
    6       (20 )     (14 )     57  
(Sale)/purchase of reserves in place
                      (13 )
Discoveries and extensions
                      3  
Production
    (22 )     (41 )     (63 )     (190 )
     
Total before year end price/cost revisions
    110       702       812       880  
Year end price/cost revisions
    5       (470 )     (465 )     (89 )
     
End of year 2004
    115       232       347       791  
     


(1)   Net reserves are the Company’s share of reserves after deducting the shares of mineral owners or governments or both. All reported reserves are located in Canada. Reserves of natural gas are calculated at a pressure of 14.73 pounds per square inch at 60°F.

     The above information describes changes during the years and balances of proved oil and gas 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 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 stages 1 through 13.
     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 reserve 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.” The requirement to use year end prices for reserves estimation introduces single day price focus and volatility in the valuation of reserves to be produced over the next 20 to 30 years. The Company believes that this approach is inconsistent with the long term nature of the natural resources business. The use of prices from a single date is not relevant to the investment decisions made by the Company and annual variations in reserves based on such year end prices are not of consequence in how the business is managed.
     The impact of year end prices on reserve estimation is most clearly shown at Cold Lake where proved bitumen and associated natural gas reserves were reduced by about 485 million oil equivalent barrels as a result of using December 31, 2004 prices, which were unusually low. Prices 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 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.

29


Table of Contents

     Reserves data do not include certain resources of crude oil and natural gas such as those discovered in the Beaufort Sea-Mackenzie Delta and the Arctic islands, or the resources contained in oil sands other than those attributable to the Cold Lake Leming plant and stages 1 through 13 of Cold Lake production operations.
     Oil equivalent barrels (OEB) may be misleading, particularly if used in isolation. An OEB conversion ratio of 6,000 cubic feet to one barrel is based on an energy-equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the well head. No independent qualified reserves evaluator or auditor was involved in the preparation of the reserves data.

Net Proved Developed and Undeveloped Reserves of Crude Oil and Natural Gas (1)

                                         
    2004     2003     2002     2001     2000  
     
    (millions)  
Crude Oil:
                                       
Conventional:
                                       
Cubic metres
    18       20       23       26       31  
Barrels
    115       126       146       165       196  
Oil Sands (Cold Lake crude bitumen):
                                       
Cubic metres
    37       121       127       128       135  
Barrels
    232       763       801       807       851  
Total:
                                       
Cubic metres
    55       141       150       154       166  
Barrels
    347       889       947       972       1,047  
Natural Gas:
                 
(billions)
               
Cubic metres
    22       29       35       40       45  
Cubic feet
    791       1,023       1,224       1,414       1,572  

Net Proved Developed Reserves of Crude Oil and Natural Gas (1)

                                         
    2004     2003     2002     2001     2000  
     
    (millions)  
Crude Oil:
                                       
Conventional:
                                       
Cubic metres
    18       19       22       25       28  
Barrels
    111       121       139       157       175  
Oil Sands (Cold Lake crude bitumen):
                                       
Cubic metres
    37       63       49       34       40  
Barrels
    232       398       308       216       250  
Total:
                                       
Cubic metres
    55       82       71       59       68  
Barrels
    343       519       447       373       425  
Natural Gas:
                 
(billions)
               
Cubic metres
    20       24       27       30       35  
Cubic feet
    704       859       959       1,060       1,233  


(1)   Net reserves are the Company’s share of reserves after deducting the shares of mineral owners or governments or both.

Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Gas Reserves
     As required by the Financial Accounting Standards Board, the standardized measure of discounted future net cash flows is computed by applying year end prices, costs and legislated tax rates and a discount factor of 10 percent to net proved reserves. The standardized measure includes costs for future dismantlement, abandonment and rehabilitation obligations. The Company believes the standardized measure does not provide a reliable estimate of the Company’s expected future cash flows to be obtained from the development and production of its oil and gas properties or of the value of its proved oil and gas reserves. The standardized measure is prepared on the basis of certain prescribed assumptions including year end prices, which represent a single point in time and therefore may cause significant variability in cash flows from year to year as prices change. The table below excludes the Company’s interest in Syncrude.

                         
    2004     2003     2002  
     
            (millions)          
Future cash flows
  $ 11,625     $ 27,611     $ 35,811  
Future production costs
    (3,123 )     (10,871 )     (8,940 )
Future development costs
    (1,492 )     (3,084 )     (3,117 )
Future income taxes
    (2,260 )     (5,543 )     (9,107 )
     
Future net cash flows
    4,750       8,113       14,647  
Annual discount of 10 percent for estimated timing of cash flows
    (1,433 )     (3,375 )     (6,446 )
     
Discounted future net cash flows
  $ 3,317     $ 4,738     $ 8,201  
     

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Table of Contents

Changes in Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Gas Reserves

                         
    2004     2003     2002  
     
    (millions)  
Balance at beginning of year
  $ 4,738     $ 8,201     $ 2,789  
Changes resulting from:
                       
Sales and transfers of oil and gas produced, net of production costs
    (2,240 )     (2,075 )     (1,645 )
Net changes in prices, development costs and production costs
    (3,692 )     (4,395 )     9,276  
Extensions, discoveries, additions and improved recovery, less related costs
    (43 )     22       34  
Purchase/(sales) of minerals in place
                4  
Development costs incurred during the year
    345       281       432  
Revisions of previous quantity estimates
    1,838       (368 )     111  
Accretion of discount
    663       1,108       423  
Net change in income taxes
    1,708       1,964       (3,223 )
     
Net change
    (1,421 )     (3,463 )     5,412  
     
Balance at end of year
  $ 3,317     $ 4,738     $ 8,201  
     


     Within the past 12 months, the Company has not filed oil and gas reserve estimates with any authority or agency of the United States.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

     None.

Item 9A. Controls and Procedures.

     As indicated in the certifications in Exhibit 31.1 and 31.2 of this report, the Company’s principal executive officer and principal financial officer have evaluated the Company’s disclosure controls and procedures as of December 31, 2004. Based on that evaluation, these officers have concluded that the Company’s disclosure controls and procedures are appropriate and effective for the purpose of ensuring that material information relating to the Company, including its consolidated subsidiaries, is made known to them by others within those entities, particularly during the period in which this annual report is being prepared.

     Reference is made to page F-2 of this report for management’s report on internal control over financial reporting.
     Reference is made to page F-2 of this report for the report of the independent registered public accounting firm on management’s assessment on internal control over financial reporting.
     There has not been any change in the Company’s internal control over financial reporting that occurred during the Company’s fourth fiscal quarter of 2004 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

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Table of Contents

PART III

Item 10. Directors and Executive Officers of the Registrant.

     The Company currently has nine directors. Each director is elected to hold office until the close of the next annual meeting.
All of the nominees, except J.M. (Jack) Mintz, are now directors and have been since the dates indicated. The following table provides information on the nominees for election as directors.

                         
      Last major                  
      position or office with the                  
Name and current principal     Company or Exxon Mobil                  
occupation or employment     Corporation     Director since     Holdings(1)(2)      
                         
B.J. (Brian) Fischer
    Senior vice-president,     September 1, 1992     Common shares of     33,963
Senior vice-president,
    Chemicals division,           Imperial Oil Limited      
products and chemicals
    Imperial Oil Limited                  
division,
                Deferred share units of     20,047
Imperial Oil Limited
                Imperial Oil Limited      
 
                       
 
                Restricted stock units of     82,600
 
                Imperial Oil Limited      
 
                       
 
                Shares of     0
 
                Exxon Mobil Corporation      
                         
T.J. (Tim) Hearn
    President,     January 1, 2002     Common shares of     25,291
Chairman, president and
    Imperial Oil Limited           Imperial Oil Limited      
chief executive officer,
                       
Imperial Oil Limited
                Deferred share units of     100
 
                Imperial Oil Limited      
 
                       
 
                Restricted stock units of     174,400
 
                Imperial Oil Limited      
 
                       
 
                Shares of     9,453
 
                Exxon Mobil Corporation      
                         
J.M. (Jack) Mintz
            Common shares of     100
President and chief
                Imperial Oil Limited      
executive officer,
                       
C.D. Howe Institute
                Deferred share units of     0
(public policy institute) and
                Imperial Oil Limited      
professor, Joseph L. Rotman
                       
School of Management,
                Restricted stock units of     0
University of Toronto
                Imperial Oil Limited      
 
                       
 
                Shares of     0
 
                Exxon Mobil Corporation      
                         
R. (Roger) Phillips
        April 23, 2002     Common shares of     3,000
Retired president and
                Imperial Oil Limited      
chief executive officer,
                       
IPSCO Inc.
                Deferred share units of     3,334
(steel manufacturing)
                Imperial Oil Limited      
 
                       
 
                Restricted stock units of     2,750
 
                Imperial Oil Limited      
 
                       
 
                Shares of     2,000
 
                Exxon Mobil Corporation      
                         
J.F. (Jim) Shepard
        October 21, 1997     Common shares of     3,000
Retired chairman and
                Imperial Oil Limited      
chief executive officer,
                       
Finning International Inc.
                Deferred share units of     5,932
(sale, lease, repair and
                Imperial Oil Limited      
financing of heavy
                       
equipment)
                Restricted stock units of     2,750
 
                Imperial Oil Limited      
 
                       
 
                Shares of     0
 
                Exxon Mobil Corporation      

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Table of Contents

                         
      Last major                  
      position or office with the                  
Name and current principal     Company or Exxon Mobil                  
occupation or employment     Corporation     Director since     Holdings(1)(2)      
                         
P.A. (Paul) Smith
    Corporate finance     February 1, 2002     Common shares of     4,302
Controller and
    manager, Exxon           Imperial Oil Limited      
senior vice-president,
    Mobil Corporation                  
finance and
                Deferred share units of     0
administration,
                Imperial Oil Limited      
Imperial Oil Limited
                       
 
                Restricted stock units of     48,500
 
                Imperial Oil Limited      
 
                       
 
                Shares of     1,190
 
                Exxon Mobil Corporation      
                         
S.D. (Sheelagh) Whittaker
        April 19, 1996     Common shares of     3,000
Vice-president, Electronic
                Imperial Oil Limited      
Data Systems
                       
Corporation (EDS)
                Deferred share units of     8,400
of Plano, Texas and
                Imperial Oil Limited      
managing director,
                       
public sector business,
                Restricted stock units of     2,750
Electronic Data Systems
                Imperial Oil Limited      
Limited
                       
(business and information
                Shares of     0
technology services)
                Exxon Mobil Corporation      
                         
J.M. (Michael) Yeager
    Vice-president, Africa,     August 1, 2004     Common shares of     5,006
Senior vice-president,
    ExxonMobil Production           Imperial Oil Limited      
resources division,
    Company                  
Imperial Oil Limited
                Deferred share units of    
 
                Imperial Oil Limited      
 
                       
 
                Restricted stock units of    
 
                Imperial Oil Limited      
 
                       
 
                Shares of     105,809
 
                Exxon Mobil Corporation      
                         
V.L. (Victor) Young
        April 23, 2002     Common shares of     3,000
Corporate director of
                Imperial Oil Limited      
several corporations
                       
 
                       
 
                Deferred share units of     1,080
 
                Imperial Oil Limited      
 
                       
 
                Restricted stock units of     2,750
 
                Imperial Oil Limited      
 
                       
 
                Shares of Exxon Mobil     0
 
                Corporation      


(1)   The information includes the beneficial ownership of common shares of Imperial Oil Limited and shares of Exxon Mobil Corporation, which information not being within the knowledge of the Company, has been provided by the nominees individually.
(2)   The Company’s plans for deferred share units and restricted stock units for selected employees and nonemployee directors are described on pages 38 and 39.

     Pierre Des Marais II is currently a director and has been a director of the Company since April 22, 1977. He holds 1,560 common shares of the Company, 5,031 deferred share units and 2,750 restricted stock units.

     The ages of the directors, nominees for election as directors, and the five senior executives of the Company are: Pierre Des Marais II 70, Brian J. Fischer 58, Timothy J. Hearn 61, Jack M. Mintz 54, Roger Phillips 65, James F. Shepard 66, Paul A. Smith 52, Sheelagh D. Whittaker 57, J. Michael Yeager 51, Victor L. Young 59, and John F. Kyle 62.

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     Jack Mintz is a director of Brascan Corporation and CHC Helicopter Corporation, Roger Phillips is a director of Canadian Pacific Railway Limited, Cleveland – Cliffs Inc., and The Toronto Dominion Bank, and Victor L. Young is a director of Royal Bank of Canada and BCE Inc., which companies are subject to reporting requirements under the U.S. Securities Exchange Act of 1934.

     All of the directors and nominees for election as directors, except for Roger Phillips, Victor L. Young and James F. Shepard, have been engaged for more than five years in their present principal occupations or in other executive capacities with the same firm or affiliated firms. During the five preceding years, Roger Phillips was president and chief executive officer of IPSCO Inc. (steel manufacturing) until he retired on January 1, 2002. During the five preceding years, Victor L. Young was chairman and chief executive officer of Fishery Products International Limited (seafood products), until May 1, 2001 and is currently a director of Royal Bank of Canada, BCE Inc., McCain Foods Limited, Aliant Inc., and Telesat Canada. James F. Shepard’s principal occupation was chairman and chief executive officer of Finning International Inc. (sale, lease, repair and financing of heavy equipment) when, in 2000, he retired.

     The following table provides information on the senior executives of the Company.

         
Name and Office   Office held since  
Timothy J. Hearn
  April 23, 2002
chairman of the board, president and
       
chief executive officer
       
 
       
Brian J. Fischer
  February 1, 1994
senior vice-president,
       
products and chemicals division
       
 
       
Paul A. Smith
  February 1, 2002
controller and senior vice-president,
       
finance and administration
       
 
       
J. Michael Yeager
  August 1, 2004
senior vice-president,
       
resources division
       
 
       
John F. Kyle
  June 1, 1991
vice-president and
       
treasurer
       

     All of the above senior executives have been engaged for more than five years at their current occupations or in other executive capacities with the Company or its affiliates. All senior executives hold office until their appointment is rescinded by the directors, or by the chief executive officer.

Audit committee

     The Company has an audit committee of the board of directors. The following directors are members of the audit committee: P. Des Marais II, R. Phillips, J.F. Shepard, S.D. Whittaker and V.L. Young.

Audit committee financial expert

     The Company’s board of directors has determined that R. Phillips, S.D. Whittaker and V.L. Young meet the definition of “audit committee financial expert” and that they and P. Des Marais II and J.F. Shepard are independent, as that term is defined by both the Securities and Exchange Commission rules and the listing standards of the American Stock Exchange and the New York Stock Exchange. The Securities and Exchange Commission has indicated that the designation of an audit committee financial expert does not make that person an expert for any purpose, or impose any duties, obligations or liability on that person that are greater than those imposed on members of the audit committee and board of directors in the absence of such designation or identification.

Code of ethics

     The Company has a code of ethics that applies to all employees, including its principal executive officer, principal financial officer and principal accounting officer. The code of ethics consists of the Company’s ethics policy, conflicts of interest policy, corporate assets policy, directorships policy and procedures and open door communication. Those documents are available at the Company’s website www.imperialoil.ca.

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Item 11. Executive Compensation.

Directors’ compensation

     Directors’ fees are paid only to nonemployee directors. For 2004, nonemployee directors were paid an annual retainer of $35,000 and 1,000 restricted stock units for their services as directors, plus an annual retainer of $4,500 for each committee on which they served, an additional $5,000 for serving as chair of a committee and $2,000 for each board and board committee meeting attended. The restricted stock units issued to nonemployee directors have the same features as the restricted stock units for selected key employees described on pages 38 and 39.
     Starting in 1999, the nonemployee directors have been able to receive all or part of their directors’ fees in the form of deferred share units for nonemployee directors. The purpose of the deferred share unit plan for nonemployee directors is to provide them with additional motivation to promote sustained improvement in the Company’s business performance and shareholder value by allowing them to have all or part of their directors’ fees tied to the future growth in value of the Company’s common shares. This plan is described on page 38.
     While serving as directors in 2004, the aggregate cash remuneration paid to nonemployee directors, as a group, was $324,875, and they received an additional 4,167 deferred share units for nonemployee directors, as a group, based on an aggregate of $265,625 of cash remuneration elected to be received as deferred share units. The nonemployee directors, as a group, received an additional 289 deferred share units granted as the equivalent to the cash dividend paid on Company shares during 2004 for previously granted deferred share units. In addition, the nonemployee directors received 5,000 restricted stock units.

Senior executive compensation
Summary compensation table

     The following table shows the compensation for the chief executive officer and the four other senior executives of the Company who were serving as senior executives at the end of 2004 and the compensation for K.C. Williams who was a senior executive of the Company until July 31, 2004. This information includes the dollar value of base salaries, cash bonus awards, and units of other long term incentive compensation and certain other compensation.

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          Annual Compensation     Long Term Compensation            
                              Awards     Payouts      
                              Securities     Shares or Units            
                              Under     Subject to Resale            
Name and                       Other Annual     Options/SARs     Restricted     LTIP     All Other
Principal           Salary     Bonus (2)     Compensation (3)     Granted (4)     (5) (6) (7)     Payouts     Compensation (9)
Position     Year     ($)     ($)     ($)     (#)     (#)     (8) ($)     ($)
                                                 
T.J. Hearn
    2004     1,000,000     872,266     246,249         64,400     750,000     30,000
Chairman, president
                                  restricted stock units            
and chief executive
                                  100            
officer
                                  deferred share units            
 
    2003     825,000     750,000     182,072         60,000     738,000     24,750
 
                      U.S. 293,450           restricted stock units            
 
                                  0            
 
                                  deferred share units            
 
    2002     668,333     442,000     71,777     65,000     50,000         20,050
 
                      U.S. 328,796     stock options     restricted stock units            
 
                                  0            
 
                                  deferred share units            
                                                 
P.A. Smith
    2004     378,333     193,600     67,022         19,300     183,000     22,700
Controller and Senior
                                  restricted stock units            
Vice-president, finance
                                  0            
and administration
                                  deferred share units            
 
    2003     357,917     183,000     11,083         16,700     204,510     21,475
 
                      U.S. 72,891           restricted stock units            
 
                                  0            
 
                                  deferred share units            
 
    2002     331,667     94,500     U.S. 100,390     25,000     12,500         19,900
 
                            stock options     restricted stock units            
 
                                  0            
 
                                  deferred share units            
                                                 
B.J. Fischer
    2004     551,667     392,775     99,744         34,200     357,000     33,100
Senior vice-president,
                                  restricted stock units            
products and
                                  275            
chemicals division
                                  deferred share units            
 
    2003     530,833     357,000     24,815         26,700     486,000     31,850
 
                                  restricted stock units            
 
                                  341            
 
                                  deferred share units            
 
    2002     505,000     216,000     0     50,000     21,700         30,300
 
                            stock options     restricted share units            
 
                                  353            
 
                                  deferred share unit            
                                                 
K.C. Williams (1)
    2004     U.S. 257,083     U.S. –     U.S. 204,682             U.S. 158,010     U.S. 17,475
                                                 
Senior vice-president resources division
    2003     U.S. 431,667     U.S. 260,900     U.S. 530,391               U.S. 197,490     U.S. 27,900
                                                 
until July 31, 2004
    2002     U.S. 412,500     U.S. 158,000     U.S. 363,932             U.S. 197,450     U.S. 26,750
                                                 
J.M. Yeager (1)
    2004     U.S. 170,833     U.S. 277,000     U.S. 48,831             U.S. 0     U.S. 10,250
Senior Vice-president, Resources division From Aug. 1, 2004
                                               
                                                 
J.F. Kyle
    2004     359,583     172,105     74,585         13,200     171,000     21,575
Vice-president
                                  restricted stock units            
and treasurer
                                  0            
 
                                  deferred share units            
 
    2003     355,000     171,000     41,391         11,400     261,000     21,300
 
                                  restricted stock units            
 
                                  0            
 
                                  deferred share units            
 
    2002     345,000     110,000     13,077     29,000     10,600         20,700
 
                            stock options     restricted stock units            
 
                                  0            
 
                                  deferred share units            

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(1)   K.C. Williams was on a loan assignment from Exxon Mobil Corporation until July 31, 2004 and J.M. Yeager is from August 1, 2004. Their compensation was paid to them directly by Exxon Mobil Corporation in United States dollars, and is disclosed in United States dollars. Also, they received employee benefits under Exxon Mobil Corporation’s employee benefit plans, and not under the Company’s employee benefit plans. The Company reimburses Exxon Mobil Corporation for the compensation paid and employee benefits provided to them.
(2)   Any part of bonus elected to be received as deferred share units is excluded.
(3)   Amounts under “Other Annual Compensation”, except for K.C. Williams and J.M. Yeager, consist of interest paid in respect of deferred payments for long term incentive compensation, other than the Company’s plan for deferred share units for selected executives, described on pages 37 to 39, dividend equivalent payments on restricted stock units, interest paid in respect of deferred payments of bonuses and reimbursement for any income tax paid as a result of use of company aircraft. The amounts also include an earned benefits allowance which in 2004 was $90,000 for T.J. Hearn, $45,000 for P.A. Smith, $45,000 for B.J. Fischer and $35,000 for J.F. Kyle. For T.J. Hearn and P.A. Smith, the U.S. dollar amounts were payments by the Company on account of U.S. income taxes incurred while on assignment in the U.S.A. For K.C. Williams and J.M. Yeager, the amounts are the net payments by Exxon Mobil Corporation on account of Canadian income taxes and other compensation for assignment outside of the United States. Each year, while on assignment, T.J. Hearn and P.A. Smith paid to the Company and K.C. Williams and J.M. Yeager paid to Exxon Mobil Corporation amounts that were approximate to the income taxes that would have been imposed if they were resident in their originating country of employment.
(4)   In 2002, the Company granted stock options which are described on page 38.
(5)   These include the number of units granted under the Company’s plan for deferred share units for selected executives described on page 38. The values and number of these units, as at the end of 2004, were $7,034 for 100 units for T.J. Hearn, nil for P.A. Smith and J.F. Kyle and $1,426,373 for 20,047 units for B.J. Fischer. These amounts include no deferred share units elected to be received in lieu of bonus for 2004, 2003 and 2002 for B.J. Fischer, P.A. Smith and J.F. Kyle, and 100 deferred share units based on $7,034 of bonus elected to be received as deferred share units for 2004 for T.J. Hearn.
(6)   These also include restricted stock units granted under the Company’s plan for restricted stock units for selected key employees and nonemployee directors described on pages 38 and 39. The values and number of these units, as at the end of 2004, were $12,408,560 for 174,400 units for T.J. Hearn, $3,450,775 for 48,500 units for P.A. Smith, $5,876,990 for 82,600 units for B.J. Fischer, and $2,504,480 for 35,200 units for J.F. Kyle. The values of these units granted for 2004, as at the end of 2004 being the date of grant, were $4,582,060 for T.J. Hearn, $1,373,195 for P.A. Smith, $2,433,330 for B.J. Fischer, and $939,180 for J.F. Kyle. The values of these units granted for 2003, as at the end of 2003 being the date of grant, were $3,451,800 for T.J. Hearn, $960,751 for P.A. Smith, $1,536,051 for B.J. Fischer, and $655,842 for J.F. Kyle. The values of these units granted for 2002, as at the end of 2002 being the date of grant, were $2,243,000 for T. J. Hearn, $560,750 for P.A. Smith, $973,462 for B.J. Fischer and $475,516 for J.F. Kyle.
(7)   K.C. Williams and J.M. Yeager participate in Exxon Mobil Corporation’s restricted stock plan which is similar to the Company’s restricted stock unit plan. The value and number of these units for K.C. Williams, as at the end of the year, were U.S. $2,398,968 for 46,800 units. The value and number of these units for J.M. Yeager, as at the end of the year, were U.S. $4,170,924 for 81,368 units. Under that plan, K.C. Williams was granted 23,400 units in 2003 whose value on the date of grant was U.S. $959,400 and 23,400 units in 2002 whose value on the date of grant was U.S. $810,576. Under that plan, J.M. Yeager was granted 31,400 units in 2004, whose value on the date of grant was U.S. $1,609,564.
(8)   Payouts were from 2003 earnings bonus units that reached maximum value of $3.00 per unit in 2004. That plan is described on page 38.
(9)   Amounts under “All Other Compensation”, except for K.C. Williams and J.M. Yeager, are the Company’s contributions to the savings plan, which is a plan available to all employees. Under one of the options of that plan to which the senior executives subscribe, except for K.C. Williams and J.M. Yeager, the Company matched employee contributions up to six percent of base salary per year; however, an employee may elect to receive an enhanced pension under the Company’s pension plan by foregoing three percent of the Company’s matching contributions. The plan is intended to be primarily for retirement savings, although employees may withdraw their contributions prior to retirement. For K.C. Williams and J.M. Yeager, the amounts are Exxon Mobil Corporation’s contributions to its employee savings plan.

Long term incentive compensation

     Consistent with the Company’s compensation philosophy of being performance driven, long term incentive compensation is granted to retain selected employees and reward them for high performance. The compensation has generally been in the form of units.

     The assessment of employee performance is conducted through the Company’s appraisal program. The appraisal program is a disciplined annual program that incorporates business performance measures relevant to eligible employees, and involves ranking of employee performance using a consistent process throughout the organization at all levels. The number of units received by each employee is tied to the performance of the employee in achieving these business performance measures. The scope of the Company program is determined by the overall performance of the Company each year.
     The Company’s incentive share units give the recipient a right to receive cash equal to the amount by which the market price of the Company’s common shares at the time of exercise exceeds the issue price of the units. These units were granted prior to 2002. The issue price of the units granted to executives was the closing price of the Company’s shares on the Toronto Stock Exchange on the grant date. Incentive share units are eligible for exercise up to 10 years from issuance.

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     In 1998, an additional form of long term incentive compensation (“deferred share units”) was made available to selected executives whereby they could elect to receive all or part of their performance bonus compensation in the form of such units. The number of units granted to an executive is determined by dividing the amount of the executive’s bonus elected to be received as deferred share units by the average of the closing prices of the Company’s shares on the Toronto Stock Exchange for the five consecutive trading days (“average closing price”) immediately prior to the date that the bonus would have been paid to the executive. Additional units will be granted to recipients of these units based on the cash dividend payable on the Company shares divided by the average closing price immediately prior to the payment date for that dividend and multiplying the resulting number by the number of deferred share units held by the recipient. An executive may not exercise these units until after termination of employment with the Company and must exercise the units no later than December 31 of the year following termination of employment with the Company. The units held must all be exercised on the same date. On the date of exercise, the cash value to be received for the units will be determined by multiplying the number of units exercised by the average closing price immediately prior to the date of exercise.

     Starting in 1999, a form of long term incentive compensation, similar to the deferred share units for executives, was made available to nonemployee directors in lieu of their receiving all or part of their directors’ fees. The main differences between the two plans are that all nonemployee directors are allowed to participate in the plan for nonemployee directors and that the number of units granted to a nonemployee director is determined at the end of each calendar quarter by dividing the amount of the directors’ fees for that calendar quarter that the nonemployee director elected to receive as deferred share units by the average closing price immediately prior to the last day of the calendar quarter.
     Starting in 2001, the earnings bonus unit plan was made available to selected executives to promote individual contribution to sustained improvement in the Company’s business performance and shareholder value. Each earnings bonus unit entitles the recipient to receive an amount equal to the Company’s cumulative net income 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.
     Under the stock option plan, adopted by the Company in April 2002, a total of 3,210,200 options were granted to selected key employees on April 30, 2002 for the purchase of the Company’s common shares at an exercise price of $46.50 per share. All of the options are exercisable. Any unexercised options expire after April 29, 2012.
     As of February 18, 2005 there have been 534,525 common shares issued upon exercise of stock options and 2,643,275 common shares are issuable upon future exercise of stock options. The common shares that were issued and those that may be issued in the future represent about 0.91 percent of the Company’s currently outstanding common shares.
     The Company’s directors, officers and vice-presidents as a group hold 7.7 percent of the unexercised stock options.
     The maximum number of common shares that any one person may receive from the exercise of stock options is 145,000 common shares, which is about 0.04 percent of the currently outstanding common shares.
     Stock options may be exercised only during employment with the Company except in the event of death, disability or retirement. Also, stock options may be forfeited if the Company believes that the employee intends to terminate employment or if during employment or during the period of 24 months after the termination of employment the employee, without the consent of the Company, engaged in any business that was in competition with the Company or otherwise engaged in any activity that was detrimental to the Company. The Company may determine that stock options will not be forfeited after the cessation of employment. Stock options cannot be assigned except in the case of death.
     The Company may amend or terminate the incentive stock option plan as it in its sole discretion determines appropriate. No such amendment or termination can be made to impair any rights of stock option holders under the incentive stock option plan unless the stock option holder consents, except that in the event of (a) any adjustments to the share capital of the Company or (b) a take-over bid, amalgamation, combination, merger or other reorganization, sale or lease of assets, or any liquidation, dissolution, or winding-up, involving the Company. Appropriate adjustments may be made by the Company to : (i) the number of common shares that may be acquired on the exercise of outstanding stock options; (ii) the exercise price of outstanding stock options, or (iii) the class of shares that may be acquired in place of common shares on the exercise of outstanding stock options in order to preserve proportionately the rights of the stock option holders and give proper effect to the event.
     In December 2002, the Company introduced a restricted stock unit plan, which will be the primary long term incentive compensation plan in future years. The purpose of the plan is to align the interests of employees and nonemployee directors directly with the interests of shareholders. Each unit entitles the recipient the conditional right to receive from the Company, upon exercise, an amount equal to the closing price of the Company’s shares on the exercise dates. Fifty percent of the units will be exercised on the third anniversary of the grant date, and the remainder will be exercised on the seventh anniversary of the grant date. The Company will pay the recipients cash with respect to each unexercised unit granted to the recipient corresponding in time and amount to the cash dividend that is paid by the Company on a common share of the Company. The restricted stock units 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. A total of 987,480 units were granted on December 31, 2004.

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     There are 927,908 common shares issuable upon future exercise of restricted stock units, which represent about 0.27 percent of the Company’s currently outstanding common shares. The Company’s directors, officers and vice-presidents have available as a group 22 percent of the common shares issuable under outstanding restricted stock units.

     The maximum number of common shares that any one person may receive from the exercise of outstanding restricted stock units is 62,200 common shares, which is about 0.02 percent of the currently outstanding common shares.
     Restricted stock units will be exercised only during employment except in the event of death, disability or retirement. Also, restricted stock units may be forfeited if the Company believes that the employee intends to terminate employment or if during employment or during the period of 24 months after the termination of employment the employee, without the consent of the Company, engaged in any business that was in competition with the Company or otherwise engaged in any activity that was detrimental to the Company. The Company may determine that restricted stock units will not be forfeited after the cessation of employment. Restricted stock units cannot be assigned.
     In the case of any subdivision, consolidation, or reclassification of the shares of the Company or other relevant change in the capitalization of the Company, the Company, in its discretion, may make appropriate adjustments in the number of common shares to be issued and the calculation of the cash amount payable per restricted stock unit.
     Effective December 31, 2004, the restricted stock unit plan was amended by the Company to provide that on retirement the Company shall determine whether the employee’s restricted stock units will not be forfeited. Shareholder approval for that change was not required by the Toronto Stock Exchange.

Earnings bonus unit plan – awards in most recently completed financial year

     The following table provides information on earnings bonus units granted in 2004 to the named senior executives.
                                                       
 
                  Performance            
        Securities       or Other       Estimated Future Payouts Under    
        Units or       Period Until       Non-Securities-Price Based Plans    
        Other Rights       Maturation or       Threshold       Target       Maximum    
  Name     (#)       Payout (1)       ($)       ($)(2)       ($)(2)    
 
T.J. Hearn
      232,000       Nov. 17, 2009       0         3.75         3.75    
 
P.A. Smith
      51,500       Nov. 17, 2009       0         3.75         3.75    
 
B.J. Fischer
      104,700       Nov. 17, 2009       0         3.75         3.75    
 
K.C. Williams
                                         
 
J.M. Yeager (3)
                                         
 
J.F. Kyle
      45,700       Nov. 17, 2009       0         3.75         3.75    
 


(1)   Payment will be made earlier when the cumulative net income per outstanding common share reach the maximum settlement value per unit prior to the fifth anniversary of the grant date.
(2)   This is the maximum settlement value payable per earnings bonus unit granted in 2004.
(3)   J.M. Yeager participates in Exxon Mobil Corporation’s earnings bonus unit plan which is similar to the Company’s earnings bonus unit plan. In 2004, J.M. Yeager was granted 85,230 units under that plan for which the maximum settlement value payable per earnings bonus unit is U.S. $3.25.

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Aggregated option/SAR exercises during the most recently completed financial year and financial year end option/SAR values
     The following table provides information on the exercise in 2004 and the aggregate holdings at the end of 2004 of incentive share units (referred to in the table as “SARs”) by the named senior executives.

                                                     
 
                                          Value of  
                          Unexercised  
                    Unexercised       in-the-Money  
      Securities     Aggregate         Options/SARs       Options/SARs  
        Acquired     Value         at Financial       at Financial  
        on Exercise     Realized         Year End       Year End  
  Name     (#)     ($)         (#)       ($)  
                        Exercisable       Unexercisable (1)     Exercisable       Unexercisable (1)  
 
T.J. Hearn
          369,375         50,000       0       1,607,500       0  
 
P.A. Smith
          686,100         67,000       0       2,571,250       0  
 
B.J. Fischer
          125,120         152,000       0       5,885,400       0  
 
K.C. Williams
                                     
 
J.M. Yeager
                                     
 
J.F. Kyle
          0         89,000       0       3,455,250       0  
 


(1)   Unexercisable units are units for which the conditions for exercise have not been met.

     The following table provides information on the exercise in 2004 and the aggregate holdings at the end of 2004 of stock options by the named senior executives.

                                                         
 
                                        Value of    
                        Unexercised    
                Unexercised       in-the-Money    
      Securities     Aggregate     Options/SARs       Options/SARs    
        Acquired     Value     at Financial       at Financial    
        on Exercise     Realized     Year End       Year End    
  Name     (#)     ($)     (#)       ($)    
                    Exercisable     Unexercisable (3)     Exercisable     Unexercisable (3)  
 
T.J. Hearn
        126,059       43,750         16,250         1,078,438         400,563    
 
P.A. Smith
        0       18,750         6,250         462,188         154,063    
 
B.J. Fischer
        0       37,500         12,500         924,375         308,125    
 
K.C. Williams (1)
                                         
 
J.M. Yeager (2)
                                         
 
J.F. Kyle
        0       21,750         7,250         536,138         178,713    
 


(1)   At the end of 2004, K.C. Williams held options to acquire 373,064 Exxon Mobil Corporation shares of which all options were exercisable. The values of K.C. Williams’s exercisable options were U.S. $5,708,941 at the end of 2004. In 2004, he exercised 49,000 options and realized an aggregate value of U.S. $1,369,859.
(2)   At the end of 2004, J.M. Yeager held options to acquire 378,176 Exxon Mobil Corporation shares of which all options were exercisable. The values of J. M. Yeager’s exercisable options were U.S. $6,383,064 at the end of 2004. In 2004, J.M. Yeager exercised 10,560 options and realized an aggregate value of U.S. $322,430.
(3)   Unexercisable units are units for which the conditions for exercise have not been met.

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Payments to employees who retire
Pension plan table

                                                       
 
             
Remuneration for   Estimated undiscounted payments    
determining payments   on retirement at the age of 65 after years of service indicated below ($)    
                                           
on retirement                                        
($)   20 Years       25 Years       30 Years       35 Years       40 Years    
 
100,000
      32,000         40,000         48,000         56,000         64,000    
 
200,000
      64,000         80,000         96,000         112,000         128,000    
 
300,000
      96,000         120,000         144,000         168,000         192,000    
 
400,000
      128,000         160,000         192,000         224,000         256,000    
 
500,000
      160,000         200,000         240,000         280,000         320,000    
 
600,000
      192,000         240,000         288,000         336,000         384,000    
 
800,000
      256,000         320,000         384,000         448,000         512,000    
 
1,000,000
      320,000         400,000         480,000         560,000         640,000    
 
1,500,000
      480,000         600,000         720,000         840,000         960,000    
 
2,000,000
      640,000         800,000         960,000         1,120,000         1,280,000    
 
2,500,000
      800,000         1,000,000         1,200,000         1,400,000         1,600,000    
 
3,000,000
      960,000         1,200,000         1,440,000         1,680,000         1,920,000    
 

     The Company’s pension plan applies to almost all employees. The plan provides an annual pension of a specific percentage of an employee’s “final three year average earnings”, multiplied by the employee’s years of service, subject to certain requirements concerning age and length of service. An employee may elect to forego three of the six percent of the Company’s contributions to the savings plan under one of the options of that plan (except for K.C. Williams and J.M. Yeager), to receive an enhanced pension equal to 0.4 percent of the employee’s “final three year average earnings”, multiplied by the employee’s years of service while foregoing such Company contributions. In addition to the pension payable under the plan, the Company has paid and may continue to pay a supplemental retirement income to employees who have earned a pension in excess of the maximum pension under the Income Tax Act. The pension plan table on this page shows estimated undiscounted annual payments, consisting of pension and supplemental retirement income, payable on retirement to employees including the senior executives in specified classifications of remuneration and years of service currently applicable to that group.
      The remuneration used to determine the payments on retirement to the individuals named in the summary compensation table on pages 36 and 37, corresponds generally to the salary, bonus compensation, and bonus compensation amount elected to be received as deferred share units in that table, and the aggregate maximum settlement value that could be paid for earnings bonus units granted shown in the table on page 39 is included in the employee’s “final three year average earnings” for the year of grant of such units. As of February 18, 2005, the number of completed years of service with Imperial Oil Limited used to determine payments on retirement were 38 for T.J. Hearn, 36 for B.J. Fischer, 25 for P.A. Smith and 28 for J.F. Kyle.
      K.C. Williams and J.M. Yeager are not members of the Company’s pension plan but are members of Exxon Mobil Corporation’s pension plan. Under that plan, J.M. Yeager has 23 years of service and he will receive a pension payable in U.S. dollars. The remuneration used to determine the payment on retirement to him also corresponds generally to his salary and bonus compensation in the summary compensation table on pages 36 and 37, which remuneration may be applied to the pension plan table above but with the dollars in that table representing U.S. rather than Canadian dollars.

Composition of the Company’s compensation committee
     The executive resources committee of the board of directors, composed of the nonemployee directors, is responsible for decisions on the compensation of senior management above the level of vice-president including all officers of the Company, and for reviewing the executive development system, including specific succession plans for senior management positions. It also reviews corporate policy on compensation. During 2004, the membership of the executive resources committee was as follows:

P. Des Marais II – Chair
R. Phillips – Vice-chair
J.F. Shepard
S.D. Whittaker
V.L. Young
T.J. Hearn periodically attends meetings at the request of the committee.

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Executive resources committee report on executive compensation
      The Company’s executive compensation policy is designed to reinforce the Company’s orientation toward career employment and its emphasis on performance as the primary determinant of advancement. This acknowledges the long term nature of the Company’s business and its philosophy that the experience, skill and motivation of its senior executives are significant determinants of future business success. The compensation program emphasizes competitive salaries and performance based incentives as the primary instruments to develop and retain key personnel.
      In establishing levels of compensation for its senior executives, the executive resources committee relies on market comparisons to other leading Canadian employers, typically in the group of major companies with revenues in excess of $1 billion a year. These market comparisons are prepared by independent external compensation consultants. On a case by case basis, depending on the scope of market coverage represented by a particular comparison, compensation is targeted to a range between the mid-point and the upper quartile of comparable employers, reflecting the Company’s emphasis on quality of management.
      The Company’s senior executive compensation policy has three main elements: base salary, short term and long term incentive compensation. While these elements are related to the extent that compensation policy is compared in total to the competitive practices of other major Canadian employers, individual decisions on base salary, short term and long term incentive compensation are made independently of each other.

     Base salary
     The Company’s salary ranges for executives were increased by three percent in 2003, two and one half percent in 2004 and one and one half percent in 2005. High performing executives, and those recently promoted, whose salaries were low relative to their level of responsibility, were given limited additional salary increases. This included senior executives.
      T.J. Hearn’s salary is currently assessed to be within the range of the competitive target for the Company’s chief executive officer which is between the median and upper quartile. The target is consistent with the executive resources committee’s view that the chief executive officer’s salary should be above the average of salaries for chief executive officers of major Canadian companies, reflecting the Company’s executive development philosophy and the significance placed on experience and judgment in leading a large, complex operation.

     Cash bonus
     Cash bonuses are typically granted to about 80 executives at the end of each year, based on individual performance. The bonuses are drawn from an aggregate bonus amount established annually by the executive resources committee based on the Company’s financial performance, and are granted in tandem with the Company’s earnings bonus units, which are described on page 38.
     In 2004, the executive resources committee increased the bonus awards including the grant of earnings bonus units to reflect the Company’s record financial results and in response to comparisons to other leading Canadian employers.
     In the case of T.J. Hearn, the committee’s approach to cash bonuses is based on the Company’s financial and operating performance and on the committee’s assessment of T.J. Hearn’s effectiveness in leading the organization. The continuing progress being made in focussing the organization on advancing key strategic interests, safety, environmental performance, productivity, cost effectiveness and asset management were primary considerations in determining a cash bonus for the chief executive officer. T.J. Hearn’s bonus including the grant of earnings bonus units was increased in 2004 to reflect his effectiveness in the position, the Company’s record financial results, and comparisons to other leading Canadian employers.

     Long term incentive compensation
     Each year, the executive resources committee has approved long term incentive awards for selected key employees. These awards were an added incentive to promote individual contribution to sustained improvement in business performance and shareholder value, and to encourage key employees to remain with the Company. Individual awards reflected both level of responsibility and performance, with an emphasis on ability to influence longer term results. In each case, including senior executives and the chief executive officer, award amounts took into account the competitive practices of other major Canadian employers and were not influenced by prior years’ results or by an individual’s holdings of unexercised long term incentive compensation units.
     Incentive awards also have been awarded selectively to the general managerial, professional and technical (non-executive) workforce as a way of delivering added financial incentive to selected high performing employees.

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     For selected executives, the executive resources committee allows cash bonus awards to be elected to be received in the form of deferred share units and also awards earnings bonus units as a means of providing additional incentive to promote the Company’s long term financial performance. Eligibility to participate in the deferred share unit and earnings bonus plans is restricted to those executives whose decisions are considered to have a direct effect on the long term financial performance of the Company. In 2004, one executive elected to receive deferred share units and 77 executives were awarded earnings bonus units.
     For many years, the Company’s long term incentive compensation programs have been cash based programs tied to earnings and share performance, and incentive awards have been reported as expenses in the consolidated statement of earnings. In 2002, to meet competitive practices, the Company introduced a stock option program. However, recognizing current concerns over stock option incentive programs and their proper accounting treatment, the Company decided to return to straightforward, cash based incentive compensation programs that will again be reported as expenses against earnings. There are no plans to issue stock options in the future.
     A total of 575 employees, including executives, were granted restricted stock units in 2004.

Submitted on behalf of the executive resources committee:
P. Des Marais II – Chair
R. Phillips – Vice-chair
J.F. Shepard
S.D. Whittaker
V.L. Young

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
     To the knowledge of the management of the Company, the only shareholder who, as of February 18, 2005, owned beneficially, or exercised control or direction over, more than five percent of the outstanding common shares of the Company is Exxon Mobil Corporation, 5959 Las Colinas Boulevard, Irving, Texas 75039-2298, which owns beneficially 242,453,672 common shares, representing 69.6 percent of the outstanding voting shares of the Company.
     Reference is made to the security ownership information under the preceding Items 10 and 11. As of February 18, 2005, John F. Kyle was the owner of 3,774 common shares of the Company and held options to acquire 29,000 common shares of the Company and restricted share units to acquire 12,300 common shares of the Company.
     The directors and the senior executives of the Company consist of 10 persons, who, as a group, own beneficially 85,896 common shares of the Company, being approximately 0.02 percent of the total number of outstanding shares of the Company, and 118,452 shares of Exxon Mobil Corporation. This information not being within the knowledge of the Company has been provided by the directors and the senior executives individually. As a group, the directors and senior executives of the Company held options to acquire 163,000 common shares of the Company and held restricted stock units to acquire 127,950 common shares of the Company, as of February 18, 2005.

Equity Compensation Plan Information as of December 31, 2004

                                   
 
                  Number of securities  
              Weighted-average     remaining available for future  
        Number of securities to     exercise price of     issuance under equity  
        be issued upon exercise     outstanding options,     compensation plans (excluding  
        of outstanding options,     warrants and rights     securities reflected in  
        warrants and rights     ($)     column (a))  
  Plan category     (a)     (b)     (c)  
 
Equity compensation
      2,854,500         46.50         0    
 
plans approved by security holders (1)
                               
 
Equity compensation
      927,908                 2,572,092    
 
plans not approved by security holders (2)
                               
 
Total
      3,782,408         46.50         2,572,092    
 


(1)   This is the stock option plan, which is described on page 38 of this report.
(2)   This is the restricted stock unit plan, which is described on pages 38 and 39 of this report.

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Item 13. Certain Relationships and Related Transactions.
     On June 23, 2003, the Company implemented another 12-month “normal course” share-purchase program under which it purchased 15,511,833 of its outstanding shares between June 23, 2003, and June 22, 2004. On June 23, 2004, another 12-month “normal course” program was implemented under which the Company may purchase up to 17,864,398 of its outstanding shares, less any shares purchased by the employee savings plan and Company pension fund. Exxon Mobil Corporation participated by selling shares to maintain its ownership at 69.6 percent. In 2004, such purchases cost $872 million, of which $594 million was received by ExxonMobil.
     During 2003, the Company borrowed $818 million from Exxon Overseas Corporation under two long term loan agreements at interest equivalent to Canadian market rates. Interest paid on the loans in 2004 was $20 million. The average effective interest rates for the loans was 2.45 percent for 2004.
     The amounts of purchases and sales by the Company and its subsidiaries for other transactions in 2004 with Exxon Mobil Corporation and affiliates of Exxon Mobil Corporation were $3,176 million and $1,580 million, respectively. These transactions were conducted on terms as favorable as they would have been with unrelated parties, and primarily consisted of the purchase and sale of crude oil, petroleum and chemical products, as well as transportation, technical and engineering services. Transactions with Exxon Mobil Corporation also include amounts paid and received in connection with the Company’s participation in a number of natural resources activities conducted jointly in Canada. The Company has agreements with affiliates of Exxon Mobil Corporation to provide computer and customer support services to the Company and to share common business and operational support services to allow the companies to consolidate duplicate work and systems.

Item 14. Principal Accountant Fees and Services.

Audit Fees
     The aggregate fees of the Company’s auditors for professional services rendered for the audit of the Company’s financial statements and other services for the fiscal years ended December 31, 2004 and December 31, 2003 were as follows:

                 
Dollars (thousands)   2004     2003  
     
Audit Fees
    1,112       767  
Audit-Related Fees
    92       62  
Tax Fees
    545       395  
All Other Fees
  Nil   Nil
     
Total Fees
    1,749       1,224  
     

     Audit fees include the audit of the Company’s annual financial statements, audit of management’s report on internal control over financial reporting and a review of the first three quarterly financial statements in 2004.
     Audit-related fees include other assurance services including the audit of the Company’s retirement plan, the Imperial Oil Foundation, and royalty statement audits for oil and gas producing entities.
     Tax fees are mainly tax services for employees on foreign loan assignments.
     The Company did not engage the auditors for any other services.
     The audit committee recommends the external auditors to be appointed by the shareholders, fixes their remuneration and oversees their work. The audit committee also approves the proposed current year audit program of the auditors, assesses the results of the program after the end of the program period and approves in advance any non-audit services to be performed by the auditors after considering the effect of such services on their independence.
     All of the services rendered by the auditors to the Company were approved by the audit committee.

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PART IV

Item 15. Exhibits and Financial Statement Schedules.
     Reference is made to the Index to Financial Statements on page F-1 of this report.
     The following exhibits numbered in accordance with Item 601 of Regulation S-K are filed as part of this report:

             
 
  (3)   (i)   Restated certificate and articles of incorporation of the Company (Incorporated herein by
 
          reference to Exhibit (3) to the Company’s Quarterly Report on Form 10-Q for the quarter ended
 
          June 30, 1998 (File No. 0-12014)).
 
      (ii)   By-laws of the Company (Incorporated herein by reference to Exhibit (3)(ii) to
 
          the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2003 (File
 
          No. 0-12014)).
             
 
    (4 )   The Company’s long term debt authorized under any instrument does not exceed 10 percent of the Company’s consolidated assets. The Company agrees to furnish to the Commission upon request a copy of any such instrument.
             
 
  (10)(ii)  (1)
  Alberta Crown Agreement, dated February 4, 1975, relating to the
 
          participation of the Province of Alberta in Syncrude (Incorporated herein by reference to
 
          Exhibit 13(a) of the Company’s Registration Statement on Form S-1, as filed with the
 
          Securities and Exchange Commission on August 21, 1979 (File No. 2-65290)).
 
    (2 )   Amendment to Alberta Crown Agreement, dated January 1, 1983 (Incorporated
 
          herein by reference to Exhibit (10)(ii)(2) of the Company’s Annual Report on
 
          Form 10-K for the year ended December 31, 1983 (File No. 2-9259)).
 
    (3 )   Syncrude Ownership and Management Agreement, dated February 4, 1975
 
          (Incorporated herein by reference to Exhibit 13(b) of the Company’s Registration
 
          Statement on Form S-1, as filed with the Securities and Exchange Commission on
 
          August 21, 1979 (File No. 2-65290)).
 
    (4 )   Letter Agreement, dated February 8, 1982, between the Government of Canada
 
          and Esso Resources Canada Limited, amending Schedule “C” to the Syncrude
 
          Ownership and Management Agreement filed as Exhibit (10)(ii)(2) (Incorporated
 
          herein by reference to Exhibit (20) of the Company’s Annual Report on Form 10-K
 
          for the year ended December 31, 1981 (File No. 2-9259)).
 
    (5 )   Norman Wells Pipeline Agreement, dated January 1, 1980, relating to the
 
          operation, tolls and financing of the pipeline system from the Norman Wells
 
          field (Incorporated herein by reference to Exhibit 10(a)(3) of the Company’s
 
          Annual Report on Form 10-K for the year ended December 31, 1981 (File No.
 
          2-9259)).
 
    (6 )   Norman Wells Pipeline Amending Agreement, dated April 1, 1982 (Incorporated
 
          herein by reference to Exhibit (10)(ii)(5) of the Company’s Annual Report on
 
          Form 10-K for the year ended December 31, 1982 (File No. 2-9259)).
 
    (7 )   Letter Agreement clarifying certain provisions to the Norman Wells Pipeline
 
          Agreement, dated August 29, 1983 (Incorporated herein by reference to Exhibit
 
          (10)(ii)(7) of the Company’s Annual Report on Form 10-K for the year ended
 
          December 31, 1983 (File No. 2-9259)).
 
    (8 )   Norman Wells Pipeline Amending Agreement, made as of February 1, 1985,
 
          relating to certain amendments ordered by the National Energy Board
 
          (Incorporated herein by reference to Exhibit (10)(ii)(8) of the Company’s Annual
 
          Report on Form 10-K for the year ended December 31, 1986 (File No. 0-12014)).
 
    (9 )   Norman Wells Pipeline Amending Agreement, made as of April 1, 1985, relating
 
          to the definition of “Operating Year” (Incorporated herein by reference to
 
          Exhibit (10)(ii)(9) of the Company’s Annual Report on Form 10-K for the year
 
          ended December 31, 1986 (File No. 0-12014)).
 
    (10 )   Norman Wells Expansion Agreement, dated October 6, 1983, relating to the
 
          prices and royalties payable for crude oil production at Norman Wells
 
          (Incorporated herein by reference to Exhibit (10)(ii)(8) of the Company’s Annual
 
          Report on Form 10-K for the year ended December 31, 1983 (File No. 2-9259)).
 
    (11 )   Alberta Cold Lake Crown Agreement, dated June 25, 1984, relating to the
 
          royalties payable and the assurances given in respect of the Cold Lake
 
          production project (Incorporated herein by reference to Exhibit (10)(ii)(11) of
 
          the Company’s Annual Report on Form 10-K for the year ended December 31, 1986
 
          (File No. 0-12014)).
 
    (12 )   Amendment to Alberta Crown Agreement, dated January 1, 1986 (Incorporated
 
          herein by reference to Exhibit (10)(ii)(12) of the Company’s Annual Report on
 
          Form 10-K for the year ended December 31, 1987 (File No. 0-12014)).
 
    (13 )   Amendment to Alberta Crown Agreement, dated November 25, 1987 (Incorporated
 
          herein by reference to Exhibit (10)(ii)(13) of the Company’s Annual Report on
 
          Form 10-K for the year ended December 31, 1987 (File No. 0-12014)).

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    (14 )   Amendment to Syncrude Ownership and Management Agreement, dated March 10, 1982
 
          (Incorporated herein by reference to Exhibit (10)(ii)(14) of the Company’s Annual Report
 
          on Form 10-K for the year ended December 31, 1989 (File No. 0-12014)).
 
    (15 )   Amendment to Alberta Crown Agreement, dated August 1, 1991 (Incorporated herein by
 
          reference to Exhibit (10)(ii)(15) of the Company’s Annual Report on Form 10-K for the
 
          year ended December 31, 1991 (File No. 0-12014)))
 
    (16 )   Norman Wells Settlement Agreement, dated July 31, 1996. (Incorporated herein by reference to Exhibit(10)(ii) (16) of the Company’s Annual Report on Form 10-K for the year ended December 31, 1996 (File No. 0‑12014)).
 
    (17 )   Amendment to Alberta Crown Agreement, dated January 1, 1997. (Incorporated herein
 
          by reference to Exhibit (10)(ii)(17) of the Company’s Annual Report on Form 10-K for the
 
          year ended December 31, 1996 (File No. 0-12014)).
 
    (18 )   Norman Wells Pipeline Amending Agreement, dated December 12, 1997. (Incorporated
 
          herein by reference to Exhibit (10)(ii)(18) of the Company’s Annual Report on Form 10-K
 
          for the year ended December 31, 1998 (File No. 0-12014)).
 
    (19 )   Norman Wells Pipeline 1999 Amending Agreement, dated May 1, 1999. (Incorporated
 
          herein by reference to Exhibit (10)(ii)(19) of the Company’s Annual Report on Form 10-K
 
          for the year ended December 31, 1999 (File No. 0-12014)).
 
    (20 )   Alberta Cold Lake Transition Agreement, effective January 1, 2000, relating to the
 
          royalties payable in respect of the Cold Lake production project and terminating the
 
          Alberta Cold Lake Crown Agreement. (Incorporated herein by reference to Exhibit
 
          (10)(ii)(20) of the Company’s Annual Report on Form 10-K for the year ended December 31,
 
          2001 (File No. 0-12014)).
 
    (21 )   Amendment to Alberta Crown Agreement effective January 1, 2001 (Incorporated herein
 
          by reference to Exhibit (10)(ii)(21) of the Company’s Quarterly Report on Form 10-Q for
 
          the quarter ended June 30, 2002 (File No. 0-12014)).
 
    (22 )   Amendment to Syncrude Ownership and Management Agreement effective January 1, 2001
 
          (Incorporated herein by reference to Exhibit (10)(ii)(22) of the Company’s Quarterly
 
          Report on Form 10-Q for the quarter ended June 30, 2002 (File No. 0-12014)).
 
    (23 )   Amendment to Syncrude Ownership and Management Agreement effective September 16,
 
          1994 (Incorporated herein by reference to Exhibit (10)(ii)(23) of the Company’s
 
          Quarterly Report on Form 10-Q for the quarter ended June 30, 2002 (File No. 0-12014)).
 
    (24 )   Amendment to Alberta Crown Agreement dated November 29, 1995 (Incorporated herein
 
          by reference to Exhibit (10)(ii)(24) of the Company’s Quarterly Report on Form 10-Q for
 
          the quarter ended June 30, 2002 (File No. 0-12014)).
 
  (iii)(A)(1)
  Form of Letter relating to Supplemental Retirement Income (Incorporated herein by reference
 
          to Exhibit (10)(c)(3) of the Company’s Annual Report on Form 10-K for the year ended
 
          December 31, 1980 (File No. 2-9259)).
 
    (2 )   Incentive Share Unit Plan and Incentive Share Units granted in 2001 are incorporated
 
          herein by reference to Exhibit (10)(iii)(A)(2) of the Company’s Annual Report on Form 10-K for the
 
          year ended December 31, 2001. Units granted in 2000 are incorporated herein by reference to Exhibit
 
          (10)(iii)(A)(2) of the Company’s Annual Report on Form 10-K for the year ended December 31, 2000
 
          (File No. 0-12014); units granted in 1999 are incorporated herein by reference to Exhibit
 
          (10)(iii)(A)(3) of the Company’s Annual Report on Form 10-K for the year ended December 31, 1999
 
          (File No. 0-12014); units granted in 1998 are incorporated herein by reference to Exhibit
 
          (10)(iii)(A)(3) of the Company’s Annual Report on Form 10-K for the year ended December 31, 1998
 
          (File No. 0-12014); units granted in 1997 are incorporated herein by reference to Exhibit
 
          (10)(iii)(A)(3) of the Company’s Annual Report on Form 10-K for the year ended December 31, 1997
 
          (File No. 0-12014); units granted in 1996 are incorporated herein by reference to Exhibit
 
          (10)(iii)(A)(3) of the Company’s Annual Report on Form 10-K for the year ended December 31, 1996
 
          (File No. 0-12014); units granted in 1995 are incorporated herein by reference to Exhibit (10)(iii)(A)(3) of
 
          the Company’s Annual Report on Form 10-K for the year ended December 31, 1995 (File No. 0-12014); and
 
          units granted in 1994 are incorporated herein by reference to Exhibit (10)(iii)(A)(3) of the Company’s
 
          Annual Report on Form 10-K for the year ended December 31, 1994 (File No. 0-12014).
 
    (3 )   Deferred Share Unit Plan. (Incorporated herein by reference to
 
          Exhibit(10)(iii)(A)(5) of the Company’s Annual Report on Form 10-K for the year ended
 
          December 31, 1998 (File No. 0-12014)).

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Table of Contents

             
 
    (4 )   Deferred Share Unit Plan for Nonemployee Directors. (Incorporated herein by reference to Exhibit (10)(iii)(A)(6) of the Company’s Annual Report on Form 10-K for the year ended December 31, 1998 (File No. 0‑12014)).
 
    (5 )   Form of Earnings Bonus Units (Incorporated herein by reference to Exhibit (10)(iii)(A)(5) of the Company’s Annual Report on Form 10-K for the year ended December 31, 2003 (File No. 0-12014)) and Earnings Bonus Unit Plan (Incorporated herein by reference to Exhibit (10)(iii)(A)(5) of the Company’s Annual Report on Form 10-K for the year ended December 31, 2002 (File No. 0-12014)).
 
    (6 )   Incentive Stock Option Plan and Incentive Stock Options granted in 2002 (Incorporated herein by reference to Exhibit (10)(iii)(A)(6) of the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2002 (File No. 0-12014)).
 
    (7 )   Restricted Stock Unit Plan and Restricted Stock Units granted in 2002 (Incorporated herein by reference to Exhibit (10)(iii)(A)(7) of the Company’s Annual Report on Form 10-K for the year ended December 31, 2002 (File No. 0-12014)).
 
    (8 )   Restricted Stock Unit Plan and Restricted Stock Units granted in 2003 (Incorporated herein by reference to Exhibit (10)(iii)(A)(8) of the Company’s Annual Report on Form 10-K for the year ended December 31, 2003 (File No. 0-12014)).
 
    (9 )   Restricted Stock Unit Plan and general form for Restricted Stock Unites, as amended effective December 31, 2004 (Incorporated herein by reference to Exhibit 99.1 of the Company’s Form 8-K dated December 31, 2004 (File No. 0-12014)).
             
 
    (21 )   Imperial Oil Resources Limited, McColl-Frontenac Petroleum Inc., Imperial Oil Resources N.W.T. Limited and Imperial Oil Resources Ventures Limited, all incorporated in Canada, are wholly-owned subsidiaries of the Company. The names of all other subsidiaries of the Company are omitted because, considered in the aggregate as a single subsidiary, they would not constitute a significant subsidiary as of December 31, 2004.
         
 
  (23)(ii)   (A)   Consent of PricewaterhouseCoopers LLP.
 
      (B)   Consent of Chief Engineering Officer.
 
  (31.1)   Certification by principal executive officer of Periodic Financial Report pursuant to Rule 13a-14(a).
 
  (31.2)   Certification by principal financial officer of Periodic Financial Report pursuant to Rule 13a-14(a).
 
  (32.1)   Certification by chief executive officer of Periodic Financial Report pursuant to Rule 13a-14(b) and 18 U.S.C. Section 1350.
 
  (32.2)   Certification by chief financial officer of Periodic Financial Report pursuant to Rule 13a-14(b) and 18 U.S.C. Section 1350.

     Copies of Exhibits may be acquired upon written request of any shareholder to the investor relations manager, Imperial Oil Limited, 111 St. Clair Avenue West, Toronto, Ontario, Canada M5W 1K3, and payment of processing and mailing costs.

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SIGNATURES

     Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf on March 9, 2005 by the undersigned, thereunto duly authorized.

         
    Imperial Oil Limited  
       
       
  By   /s/ T. J. Hearn  
    (Timothy J. Hearn, Chairman of the Board,    
    President and Chief Executive Officer)   
 

     Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on March 9, 2005 by the following persons on behalf of the registrant and in the capacities indicated.

     
Signature   Title
  Chairman of the Board, President,
/s/ T. J. Hearn   Chief Executive Officer and Director

  (Principal Executive Officer)
(Timothy J. Hearn)    
     
  Controller and Senior Vice-President,
/s/ Paul A. Smith   Finance and Administration and Director

  (Principal Accounting Officer and Principal Financial Officer)
(Paul A. Smith)    
     
/s/ Pierre Des Marais II   Director

   
(Pierre Des Marais II)    
     
/s/ Brian J. Fischer   Director

   
(Brian J. Fischer)    
     
/s/ Roger Phillips   Director

   
(Roger Phillips)    
     
/s/ J. Shepard   Director

   
(James F. Shepard)    
     
/s/ Sheelagh D. Whittaker   Director

   
(Sheelagh D. Whittaker)    
     
/s/ J. Michael Yeager   Director

   
(J. Michael Yeager)    
     
/s/ Victor L. Young   Director

   
(Victor L. Young)    

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INDEX TO FINANCIAL STATEMENTS

     
    Pages in this
    Report
  F-2
  F-2
Financial statements:
   
  F-3
  F-4
  F-5
  F-6
  F-7 – F20

F-1


Table of Contents

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management, including the Company’s chief executive officer and principal accounting officer and principal financial officer, is responsible for establishing and maintaining adequate internal control over the Company’s financial reporting. Management conducted an evaluation of the effectiveness of internal control over financial reporting based on the Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that Imperial Oil Limited’s internal control over financial reporting was effective as of December 31, 2004.

Management’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2004, was audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.

     
/s/ T. J. Hearn
  /s/ Paul A. Smith
Timothy J. Hearn
  Paul A. Smith
Chairman of the Board,
  Controller and Senior Vice-President,
President and Chief Executive Officer
  Finance and Administration
  (Principal Accounting Officer and Principal Financial Officer)

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders of Imperial Oil Limited:

     We have completed an integrated audit of Imperial Oil Limited’s 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2004, and audits of its 2003 and 2002 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.

     Consolidated financial statements
     In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, shareholders’ equity and cash flows appearing on pages F-3 through F-20 of this Annual Report present fairly, in all material respects, the financial position of Imperial Oil Limited and its subsidiaries at December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

     Internal control over financial reporting
     Also, in our opinion, management ’s assessment, included in the accompanying Management’ s Report on Internal Control Over Financial Reporting, that the Company maintained effective internal control over financial reporting as of December 31, 2004 based on criteria established in Internal Control — Integrated Frame work issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control — Integrated Framework issued by the COSO. The Company’ s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’ s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects . An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’ s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

     A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
     Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP
Chartered Accountants
Toronto, Ontario, Canada
March 9, 2005

F-2


Table of Contents

Consolidated statement of income

                         
millions of Canadian dollars                  
For the years ended December 31   2004     2003     2002  
 
Revenues
                       
Operating revenues (a)
    22 408       19 094       16 890  
Investment and other income (note 11)
    52       114       152  
 
Total revenues
    22 460       19 208       17 042  
 
 
                       
Expenses
                       
Exploration
    59       55       30  
Purchases of crude oil and products
    13 094       10 823       9 723  
Production and manufacturing
    2 883       2 782       2 320  
Selling and general
    1 218       1 269       1 222  
Federal excise tax (a)
    1 264       1 254       1 231  
Depreciation and depletion
    908       755       708  
Financing costs (note 15)
    7       (120 )     20  
 
Total expenses
    19 433       16 818       15 254  
 
 
                       
Income before income taxes
    3 027       2 390       1 788  
 
                       
Income taxes
    975       689       574  
 
Income before cumulative effect of accounting change
    2 052       1 701       1 214  
Cumulative effect of accounting change, after income tax
            4        
 
 
                       
Net income
    2 052       1 705       1 214  
 
 
                       
Per-share information (dollars)
                       
Net income per common share – basic (note 13)
                       
Income before cumulative effect of accounting change
    5.75       4.57       3.20  
Cumulative effect of accounting change, after income tax
          0.01        
 
Net income
    5.75       4.58       3.20  
 
 
                       
Net income per common share – diluted (note 13)
                       
Income before cumulative effect of accounting change
    5.74       4.57       3.20  
Cumulative effect of accounting change, after income tax
          0.01        
 
Net income
    5.74       4.58       3.20  
 
 
                       
Dividends
    0.88       0.87       0.84  
 


(a)   Operating revenues include federal excise tax of $1,264 million (2003 – $1,254 million, 2002 – $1,231 million).

The information on pages F-7 through F-20 is part of these consolidated financial statements. Certain figures for prior years have been reclassified in the financial statements to conform with the current year’s presentation.

F-3


Table of Contents

Consolidated statement of cash flows

                         
millions of Canadian dollars, inflow/(outflow)                  
For the years ended December 31   2004     2003     2002  
 
Operating activities
                       
Net income
    2 052       1 705       1 214  
Cumulative effect of accounting change, after tax
          (4 )      
Adjustments for non-cash items:
                       
Depreciation and depletion
    908       755       708  
(Gain)/loss on asset sales, after tax
    (32 )     (10 )     (4 )
Deferred income taxes and other
    (90 )     (59 )     (148 )
Changes in operating assets and liabilities:
                       
Accounts receivable
    (311 )     33       (356 )
Inventories and prepaids
    (32 )     31       51  
Income taxes payable
    462       38       (225 )
Accounts payable
    308       74       323  
All other items – net (a)
    47       (336 )     125  
 
Cash from operating activities (note 14)
    3 312       2 227       1 688  
 
 
                       
Investing activities
                       
Additions to property, plant and equipment and intangibles
    (1 376 )     (1 482 )     (1 564 )
Proceeds from asset sales
    102       56       61  
Loans to equity company
    (32 )            
 
Cash from/(used in) investing activities
    (1 306 )     (1 426 )     (1 503 )
 
 
                       
Financing activities
                       
Short-term debt – net
    9             (388 )
Long-term debt issued
          818       500  
Repayment of long-term debt
    (8 )     (818 )     (71 )
Issuance of common shares under stock option plan
    13       2        
Common shares purchased (note 13)
    (872 )     (799 )     (13 )
Dividends paid
    (317 )     (322 )     (319 )
 
Cash from/(used in) financing activities
    (1 175 )     (1 119 )     (291 )
 
 
                       
Increase/(decrease) in cash
    831       (318 )     (106 )
Cash at beginning of year
    448       766       872  
 
Cash at end of year (b)
    1 279       448       766  
 


(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 F-7 through F-20 is part of these consolidated financial statements. Certain figures for prior years have been reclassified in the financial statements to conform with the current year’s presentation.

F-4


Table of Contents

Consolidated balance sheet

                 
millions of Canadian dollars            
At December 31   2004     2003  
 
Assets
               
Current assets
               
Cash
    1 279       448  
Accounts receivable, less estimated doubtful amounts
    1 626       1 315  
Inventories of crude oil and products (note 14)
    432       407  
Materials, supplies and prepaid expenses
    112       105  
Deferred income tax assets (note 4)
    448       353  
 
Total current assets
    3 897       2 628  
Investments and other long-term assets
    130       97  
Property, plant and equipment, less accumulation, depreciation and depletion (note 2)
    9 647       9 267  
Goodwill (note 2)
    204       204  
Other intangible assets, net
    149       141  
 
Total assets (note 2)
    14 027       12 337  
 
 
               
Liabilities
               
Current liabilities
               
Short-term debt
    81       72  
Accounts payable and accrued liabilities (note 16)
    2 525       2 222  
Income taxes payable
    1 057       595  
Current portion of long-term debt
    995       501  
 
Total current liabilities
    4 658       3 390  
Long-term debt (note 3)
    367       859  
Other long-term obligations (note 8)
    1 525       1 314  
Deferred income tax liabilities (note 4)
    1 155       1 229  
Commitments and contingent liabilities (note 12)
               
 
Total liabilities
    7 705       6 792  
 
 
               
Shareholders’ equity
               
Common shares at stated value (note 13)
    1 801       1 859  
Earnings reinvested
    4 889       3 952  
Accumulated other nonowner changes in equity
    (368 )     (266 )
 
Total shareholders’ equity
    6 322       5 545  
 
 
               
Total liabilities and shareholders’ equity
    14 027       12 337  
 

The information on pages F-7 through F-20 is part of these consolidated financial statements. Certain figures for prior years have been reclassified in the financial statements to conform with the current year’s presentation.

     
Approved by the directors
   
 
   
/s/ T. J. Heam
  /s/ P. A. Smith
Chairman, president and
  Controller and senior vice-president,
chief executive officer
  finance and administration

F-5


Table of Contents

Consolidated statement of shareholders’ equity

                         
millions of Canadian dollars                  
At December 31   2004     2003     2002  
 
Common shares at stated value (note 13)
                       
At beginning of year
    1 859       1 939       1 941  
Issued under the stock option plan
    13       2        
Share purchases at stated value
    (71 )     (82 )     (2 )
 
At end of year
    1 801       1 859       1 939  
 
 
                       
Earnings reinvested
                       
At beginning of year
    3 952       3 287       2 402  
Net income for the year
    2 052       1 705       1 214  
Share purchases in excess of stated value
    (801 )     (717 )     (11 )
Dividends
    (314 )     (323 )     (318 )
 
At end of year
    4 889       3 952       3 287  
 
 
                       
Accumulated other nonowner changes in equity
                       
At beginning of year
    (266 )     (315 )     (77 )
Minimum pension liability adjustment (note 7)
    (102 )     49       (238 )
 
At end of year
    (368 )     (266 )     (315 )
 
 
                       
Shareholders’ equity at end of year
    6 322       5 545       4 911  
 
 
                       
Nonowner changes in equity for the year
                       
Net income for the year
    2 052       1 705       1 214  
Other nonowner changes in equity (note 7)
    (102 )     49       (238 )
 
Total nonowner changes in equity for the year
    1 950       1 754       976  
 

The information on pages F-7 through F-20 is part of these consolidated financial statements. Certain figures for prior years have been reclassified in the financial statements to conform with the current year’s presentation.

F-6


Table of Contents

Notes to consolidated financial statements

1. Summary of significant accounting policies

The company’s principal business is energy, involving the exploration, production, transportation and sale of crude oil and natural gas and the manufacture, transportation and sale of petroleum products. Imperial is also a major manufacturer and marketer of petrochemicals.
The consolidated financial statements have been prepared in accordance with generally accepted accounting principles (GAAP) in the United States of America. The financial statements include certain estimates that reflect management’s best judgment. All amounts are in Canadian dollars unless otherwise indicated.

Principles of 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.

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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.

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Notes to consolidated financial statements (continued)
 
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.
 
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. 02-03”. While Issue 03-11 addresses the issue of gross versus net classification for derivative instruments, it also provides guidance for purchase/sale transaction 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   2004     2003     2002  
 
Net income as shown in financial statements
    2 052       1 705       1 214  
Add: stock-based compensation expense as reported, net of tax
    84       76       24  
Deduct: stock-based compensation expense, net of tax, determined under fair-value-based method
    (86 )     (81 )     (41 )
 
Pro forma net income
    2 050       1 700       1 197  
 
 
                       
Net income per share (dollars)
                       
As reported – basic
    5.75       4.58       3.20  
                    – diluted
    5.74       4.58       3.20  
Pro forma – basic
    5.74       4.57       3.16  
                 – diluted
    5.73       4.57       3.16  
 

Consumer taxes
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.

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2. Business segments

                                                                         
    Natural resources (a)     Petroleum products     Chemicals  
millions of dollars   2004     2003     2002     2004     2003     2002     2004     2003     2002  
 
Revenues
                                                                       
External sales (c)
    3 689       3 390       2 573       17 503       14 710       13 362       1 216       994       955  
Intersegment sales
    2 891       2 224       2 217       1 666       1 294       1 038       293       238       209  
Investment and other income
    45       34       104       42       54       34                    
 
Total revenues
    6 625       5 648       4 894       19 211       16 058       14 434       1 509       1 232       1 164  
 
Expenses
                                                                       
Exploration
    59       55       30                                      
Purchases of crude oil and products
    2 110       1 873       1 599       14 769       11 822       10 781       1 064       882       806  
Production and manufacturing
    1 608       1 577       1 228       1 092       1 054       954       184       153       139  
Selling and general (d)
    27       28       21       1 098       1 123       1 076       93       118       115  
Federal excise tax
                      1 264       1 254       1 231                    
Depreciation and depletion
    633       517       477       257       211       203       13       22       23  
Financing costs (note 15)
    1       1       1       2       2       1                    
 
Total expenses
    4 438       4 051       3 356       18 482       15 466       14 246       1 354       1 175       1 083  
 
Income before income taxes
    2 187       1 597       1 538       729       592       188       155       57       81  
Income taxes (note 4)
                                                                       
Current
    763       535       517       299       66       172       59       13       40  
Deferred
    (63 )     (77 )     (21 )     (70 )     119       (111 )     (4 )     7       (11 )
 
Total income tax expense
    700       458       496       229       185       61       55       20       29  
 
Income before cumulative effect of accounting change
    1 487       1 139       1 042       500       407       127       100       37       52  
Cumulative effect of accounting change, after income tax
          4                                            
 
Net income
    1 487       1 143       1 042       500       407       127       100       37       52  
 
Capital and exploration expenditures (e)
    1 113       1 007       986       283       478       589       15       41       25  
 
Property, plant and equipment
                                                                       
Cost
    13 538       12 610       11 612       6 078       6 069       5 827       682       609       579  
Accumulated depreciation and depletion
    7 337       6 813       6 269       2 959       2 856       2 867       459       401       383  
 
Net property, plant and equipment (f) (g)
    6 201       5 797       5 343       3 119       3 213       2 960       223       208       196  
 
Total assets (h)
    6 875       6 418       6 013       5 570       5 290       5 127       498       440       428  
 
                                                 
    Corporate and other     Consolidated (b)  
millions of dollars   2004     2003     2002     2004     2003     2002  
 
Revenues
                                               
External sales (c)
                      22 408       19 094       16 890  
Intersegment sales
                                   
Investment and other income
    (35 )     26       14       52       114       152  
 
Total revenues
    (35 )     26       14       22 460       19 208       17 042  
 
Expenses
                                               
Exploration
                      59       55       30  
Purchases of crude oil and products
                      13 094       10 823       9 723  
Production and manufacturing
                      2 883       2 782       2 320  
Selling and general (d)
                10       1 218       1 269       1 222  
Federal excise tax
                      1 264       1 254       1 231  
Depreciation and depletion
    5       5       5       908       755       708  
Financing costs (note 15)
    4       (123 )     18       7       (120 )     20  
 
Total expenses
    9       (118 )     33       19 433       16 818       15 254  
 
Income before income taxes
    (44 )     144       (19 )     3 027       2 390       1 788  
Income taxes (note 4)
                                               
Current
    (18 )     (4 )     (11 )     1 103       610       718  
Deferred
    9       30       (1 )     (128 )     79       (144 )
 
Total income tax expense
    (9 )     26       (12 )     975       689       574  
 
Income before cumulative effect of accounting change
    (35 )     118       (7 )     2 052       1 701       1 214  
Cumulative effect of accounting change, after income tax
                            4        
 
Net income
    (35 )     118       (7 )     2 052       1 705       1 214  
 
Capital and exploration expenditures (e)
    34       33       12       1 445       1 559       1 612  
 
Property, plant and equipment
                                               
Cost
    205       145       112       20 503       19 433       18 130  
Accumulated depreciation and depletion
    101       96       91       10 856       10 166       9 610  
 
Net property, plant and equipment (f) (g)
    104       49       21       9 647       9 267       8 520  
 
Total assets (h)
    1 382       497       787       14 027       12 337       12 003  
 

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Notes to consolidated financial statements (continued)

  (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   2004     2003     2002  
 
Total revenues
    2 744       2 494       2 357  
Total expenses
    1 598       1 577       1 520  
Net income, after income tax
    780       664       557  
 
                       
Total current assets
    367       302       321  
Long-term assets
    4 140       3 553       3 038  
Total current liabilities
    948       913       669  
Other long-term obligations
    330       322       293  
 
                       
Cash flow from operating activities
    1 188       883       615  
Cash (used in) investing activities
    (858 )     (754 )     (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   2004     2003     2002  
 
Purchases of crude oil and products
    4 849       3 754       3 463  
Operating expenses
    1       2       1  
 
Total intersegment sales
    4 850       3 756       3 464  
 
Intersegment receivables and payables
    298       308       352  
 

  (c)   Includes export sales to the United States, as follows:
                         
millions of dollars   2004     2003     2002  
 
Natural resources
    1360       1304       942  
Petroleum products
    1074       792       723  
Chemicals
    678       567       520  
 
Total export sales
    3112       2663       2185  
 

  (d)   Consolidated production and manufacturing and 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.

3. Long-term debt

                         
              2004       2003  
issued   maturity date interest rate     millions of dollars  
 
2003
  $250 million due May 26, 2005, and                    
 
  $250 million due August 26, 2005 (a)   Variable           500  
2003
  January 19, 2006 (a)   Variable     318       318  
 
Long-term debt (b)
            318       818  
Capital leases (c)
            49       41  
 
Total long-term debt (d) (e)
            367       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.

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4. Income taxes

                         
millions of dollars   2004     2003     2002  
 
Current income tax expense
    1 103       610       718  
Deferred income tax expense (a)
    (128 )     79       (144 )
 
Total income tax expense (b)
    975       689       574  
 
Statutory corporate tax rate (percent)
    37.0       38.5       42.0  
Increase/(decrease) resulting from:
                       
Non-deductible royalty payments to governments
    3.9       5.0       5.4  
Resource allowance in lieu of royalty deduction
    (7.0 )     (7.5 )     (11.8 )
Manufacturing and processing credit
          0.2       (0.3 )
Enacted tax-rate and tax-law changes
    (1.8 )     (3.1 )     (0.9 )
Other
    0.1       (4.3 )     (2.3 )
 
Effective income tax rate
    32.2       28.8       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).

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   2004     2003  
 
Depreciation and amortization
    1 287       1 233  
Successful drilling and land acquisitions
    403       495  
Pension and benefits (a)
    (343 )     (286 )
Site restoration
    (158 )     (167 )
Net tax loss carryforwards (b)
    (57 )     (57 )
Capitalized interest
    26       16  
Other
    (3 )     (5 )
 
Deferred income tax liabilities
    1 155       1 229  
 
 
               
LIFO inventory valuation
    (343 )     (268 )
Other
    (105 )     (85 )
 
Deferred income tax assets
    (448 )     (353 )
Valuation allowance
           
 
Net deferred income tax liabilities
    707       876  
 


  (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.

5. 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.

6. 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.

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Table of Contents

Notes to consolidated financial statements (continued)

7.  Employee retirement benefits

Retirement benefits, which cover almost all retired employees and their surviving spouses, include pension-income and certain health-care and life-insurance benefits. They are met through funded registered retirement plans and through unfunded supplementary benefits that are paid directly to recipients. Funding of registered retirement plans complies with federal and provincial pension regulations, and the company makes contributions to the plans based upon an independent actuarial valuation.

Pension-income benefits consist mainly of company-paid defined benefit plans that are based on years of service and final average earnings. The company shares in the cost of health-care and life-insurance benefits. The company’s benefit obligations are based on the projected benefit method of valuation that includes employee service to date and present compensation levels as well as a projection of salaries and service to retirement.

The expense and obligations for both funded and unfunded benefits are determined in accordance with United States generally accepted accounting principles and actuarial procedures. The process for determining retirement-income expense and related obligations includes making certain long-term assumptions regarding the discount rate, rate of return on plan assets and rate of compensation increases.

The total obligation for retirement benefits exceeded the fair value of plan assets at December 31, 2004, by $1,712 million (2003 — $1,357 million), $1,276 million (2003 — $975 million) of which was related to pension benefits and $436 million (2003 — $382 million) to other post-retirement benefits. The obligation and pension expense can vary significantly with changes in the assumptions used to estimate the obligation and the expected return on plan assets.

Details of the employee retirement benefits plans are as follows:

                                                 
                            Other post-retirement  
    Pension benefits     benefits  
millions of dollars   2004     2003     2002     2004     2003     2002  
 
Components of net benefit cost:
                                               
Current service cost
    76       71       64       6       5       4  
Interest cost
    237       219       222       24       22       21  
Expected return on plan assets
    (223 )     (179 )     (191 )                  
Amortization of prior service cost
    27       25       25                    
Recognized actuarial loss/(gain)
    68       69       34       4       3       1  
 
Net benefit cost(a)
    185       205       154       34       30       26  
 
                                                 
Change in benefit obligation
                                               
Benefit obligation at January 1
    3 761       3 530               382       354          
Current service cost
    76       71               6       5          
Interest cost
    237       219               24       22          
Amendments
    37                                    
Actuarial loss/(gain)
    405       171               47       19          
Benefits paid
    (256 )     (230 )             (23 )     (18 )        
         
Benefit obligation at December 31
    4 260       3 761               436       382          
         
                                                 
Accumulated benefit obligation at December 31
    3 743       3 347                              
                                                 
Change in plan assets
                                               
Fair value of plan assets at January 1
    2 786       2 104                                  
Actual return on plan assets
    315       377                                  
Company contributions
    114       511                                  
Payments directly to participants
    25       24                                  
Benefits paid
    (256 )     (230 )                                
                                 
Fair value of plan assets at December 31
    2 984       2 786                                  
                                 
                                                 
Excess/(deficiency) of plan assets over benefit obligation
    (1276 )     (975 )             (436 )     (382 )        
Unrecognized net actuarial (gain)/loss (b)
    1073       829               95       52          
Unrecognized prior service cost (b)
    99       89                              
         
Net amount recognized
    (104 )     (57 )             (341 )     (330 )        
         
                                                 
Amount recognized in the consolidated balance sheet consists of:
                                               
Accrued benefit cost (note 8)
    (759 )     (561 )             (341 )     (330 )        
Intangible assets
    97       89                              
Accumulated other nonowner changes in equity, minimum pension liability adjustment
    558       415                              
         
Net amount recognized
    (104 )     (57 )             (341 )     (330 )        
         

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Table of Contents

                                                 
Assumptions                           Other post-retirement  
    Pension benefits     benefits  
millions of dollars   2004     2003     2002     2004     2003     2002  
 
Assumptions used to determine benefit obligations at December 31 (percent)
                                               
         
Discount rate
    5.75       6.25               5.75       6.25          
Long-term rate of compensation increase
    3.50       3.50               3.50       3.50          
 
         
Assumptions used to determine net benefit cost for years ended December 31 (percent)
                                               
 
Discount rate
    6.25       6.25       6.75       6.25       6.25       6.75  
Long-term rate of compensation increase
    3.50       3.50       3.50       3.50       3.50       3.50  
Long-term rate of return on funded assets
    8.25       8.25       8.25                    
 


(a)   A summary of net benefit costs with elements of employee future benefit cost before and after adjustments to recognize the long-term nature of employee benefit cost is shown in the table below:
                                                 
    Pension benefits     Other post-retirement benefits  
millions of dollars   2004     2003     2002     2004     2003     2002  
 
 
Components of net benefit cost:
                                               
Current service cost
    76       71       64       6       5       4  
Interest cost
    237       219       222       24       22       21  
Actual return on plan assets
    (315 )     (377 )     107                    
Plan amendments for prior service
    37             27                    
Actuarial loss/(gain)
    405       171       196       47       19       25  
 
Elements of employee future benefit costs before adjustments to recognize the long-term nature of employee future benefit costs
    440       84       616       77       46       50  
 
 
Adjustments to recognize the long-term nature of employee future benefit costs:
                                               
 
Difference between expected return and actual return on plan assets for the year
    92       198       (298 )                  
 
Difference between amortization of prior service costs for the year and actual plan amendments for the year
    (10 )     25       (2 )                  
 
Difference between actuarial (gain)/loss recognized for the year and actuarial (gain)/loss on accrued benefit obligation for the year
    (337 )     (102 )     (162 )     (43 )     (16 )     (24 )
 
 
Net benefit cost
    185       205       154       34       30       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:

                         
    Target     Percentage of plan assets  
    allocation     at December 31  
Asset category (percent)   2005     2004     2003  
 
Equities
    50 — 75       62       62  
Bonds
    25 — 50       38       38  
Other
    0 — 10              
 
Total
            100       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.

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Notes to consolidated financial statements (continued)

     
 
    Cash flows
The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:
                 
            Other  
    Pension     post-retirement  
millions of dollars   benefits     benefits  
 
2005
    230       20  
2006
    234       22  
2007
    238       24  
2008
    244       26  
2009
    251       28  
Years 2010 — 2014
    1398       161  
 

    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.
                         
    Pension benefits  
millions of dollars   2004     2003     2002  
 
Increase/(decrease) in accumulated other nonowner changes in equity, before tax
    (143 )     106       (393 )
Deferred income tax (charge)/credit (note 4)
    41       (57 )     155  
 
Increase/(decrease) in accumulated other nonowner changes in equity, after tax
    (102 )     49       (238 )
 

    A summary of pension plans with accumulated benefit obligations in excess of plan assets is shown in the table below:
                 
    Pension benefits  
millions of dollars   2004     2003  
 
For funded pension plans with accumulated benefit obligations in excess of plan assets:
               
Projected benefit obligation
    3 876       3 464  
Accumulated benefit obligation
    3 430       3 126  
Fair value of plan assets
    2 984       2 786  
Accumulated benefit obligation less fair value of plan assets
    446       340  
 
For unfunded plans covered by book reserves:
               
Projected benefit obligation
    384       297  
Accumulated benefit obligation
    313       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)   One-percent     One-percent  
millions of dollars   increase     decrease  
 
Rate of return on plan assets:
               
Effect on net benefit costs
    (30 )     30  
 
Discount rate:
               
Effect on net benefit costs
    (45 )     50  
Effect on benefit obligations
    (525 )     645  
 
Rate of pay increases:
               
Effect on net benefit costs
    30       (25 )
Effect on benefit obligations
    160       (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)   One-percent     One-percent  
millions of dollars   increase     decrease  
 
Effect on service and interest cost components
    4       (3 )
Effect on other post-retirement benefits obligations
    45       (40 )
 

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Table of Contents

8.  Other long-term obligations

                 
millions of dollars   2004     2003  
 
Employee retirement benefits (note 7) (a)
    1 052       847  
Asset retirement obligations and other environmental liabilities (b)
    380       393  
Other obligations
    93       74  
 
Total other long-term obligations
    1 525       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   2004     2003          
           
Asset retirement obligations liability at January 1
    327       341          
Additions
    16                
Accretion
    22       20          
Settlement
    (37 )     (34 )        
         
Asset retirement obligations liability at December 31
    328       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.

F-16


Table of Contents

Notes to consolidated financial statements (continued)

    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 F-9. 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     Expensed in     Obligations
outstanding at
 
                    Cancelled     Outstanding at     period     December 31  
    Granted     Exercised     or adjusted     December 31     (millions of dollars)     (millions of dollars)  
 
Incentive share units
                                               
2004
          (1 619 907 )     (3 000 )     5 266 423       94       245  
2003
          (1 142 145 )     19 225       6 889 330       109       216  
2002
    7 000       (812 550 )     (5 325 )     8 012 250       39       142  
Deferred share units
                                               
2004
    4 899                   48 810       1       4  
2003
    8 253       (49 486 )     (379 )     43 911       1       3  
2002
    7 479       (9 853 )           85 523             4  
Earnings bonus units
                                               
2004
    1 889 740       (1 139 160 )           3 984 830       7       6  
2003
    2 221 580       (1 156 370 )           3 234 250       3       3  
2002
    1 036 500                   2 169 040       3       3  
Incentive stock options
                                               
2004
          (274 250 )     (7 400 )     2 854 500              
2003
          (49 050 )     (11 500 )     3 136 150              
2002
    3 210 200             (13 500 )     3 196 700              
Restricted stock units
                                               
2004
    987 480             (5 710 )     2 642 325       31       41  
2003
    872 085       (3 300 )     (120 )     1 660 555       11       11  
2002
    791 890                   791 890              
 

F-17


Table of Contents

11. Investment and other income

    Investment and other income includes gains and losses on asset sales as follows:
                         
millions of dollars   2004     2003     2002  
 
Proceeds from asset sales
    102       56       61  
Book value of assets sold
    59       44       56  
 
Gain/(loss) on asset sales, before tax
    43       12       5  
 
Gain/(loss) on asset sales, after tax
    32       10       4  
 

    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 2. 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:
                                                 
                                            After  
millions of dollars   2005     2006     2007     2008     2009     2009  
 
Operating leases (a)
    62       55       47       41       38       91  
Unconditional purchase obligations(b)
    102       42       42       42       42       55  
Firm capital commitments (c)
    119       24       8       13       7        
Other long-term agreements (d)
    241       196       62       61       59       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 F-8). 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.
                 
    Purchased     Millions of  
Year   shares     dollars  
 
1995 to 2002
    202 661 201       5 169  
2003
    16 259 538       799  
2004
    13 606 712       872  
 
 
Cumulative purchases to date
    232 527 451       6 840  
 

    Exxon Mobil Corporation’s participation in the above maintained its ownership interest in Imperial at 69.6 percent.

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Table of Contents

Notes to consolidated financial statements (continued)

    The company’s common share activities are summarized below:
                 
            At stated value,  
    Thousands     millions  
    of shares     of dollars  
 
Balance as at January 1, 2002
    379 159       1 941  
Issued for cash under the stock option plan
           
Purchases
    (296 )     (2 )
 
Balance as at December 31, 2002
    378 863       1 939  
Issued for cash under the stock option plan
    49       2  
Purchases
    (16 259 )     (82 )
 
Balance as at December 31, 2003
    362 653       1 859  
Issued for cash under the stock option plan
    274       13  
Purchases
    (13 607 )     (71 )
 
Balance as at December 31, 2004
    349 320       1 801  
 

    The following table provides the calculation of basic and diluted earnings per share:
                         
    2004     2003     2002  
 
Net income per common share – basic
                       
Income before cumulative effect of accounting change (millions of dollars)
    2 052       1 701       1 214  
Net income (millions of dollars)
    2 052       1 705       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
    5.75       4.57       3.20  
Cumulative effect of accounting change, after income tax
          0.01        
 
Net income
    5.75       4.58       3.20  
 
Net income per common share – diluted
                       
Income before cumulative effect of accounting change (millions of dollars)
    2 052       1 701       1 214  
Net income (millions of dollars)
    2 052       1 705       1 214  
Weighted average number of common shares outstanding (thousands of shares)
    356 834       372 011       378 875  
Effect of employee stock-based awards (thousands of shares)
    818       143       1  
 
Weighted average number of common shares outstanding,
                       
assuming dilution (thousands of shares)
    357 652       372 154       378 876  
Net income per common share (dollars)
                       
Income before cumulative effect of accounting change
    5.74       4.57       3.20  
Cumulative effect of accounting change, after income tax
          0.01        
 
Net income
    5.74       4.58       3.20  
 

14.  Miscellaneous financial information

    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   2004     2003  
 
Crude oil
    165       161  
Petroleum products
    190       175  
Chemical products
    59       57  
Natural gas and other
    18       14  
 
Total inventories of crude oil and products
    432       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).

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Table of Contents

15. Financing costs

                         
millions of dollars   2004     2003     2002  
 
Debt-related interest
    37       38       40  
Capitalized interest
    (34 )     (33 )     (12 )
 
Net interest expense
    3       5       28  
Other interest
    4       4       2  
 
Total interest expense (a)
    7       9       30  
Foreign-exchange expense/(gain) on long-term debt
          (129 )     (10 )
 
Total financing costs
    7       (120 )     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   2004     2003     2002  
 
Total revenues
    1 580       950       1 036  
Purchases of crude oil and products
    3 133       2 464       2 134  
Total expenses
    43       14       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   2004     2003     2002  
 
Current income tax expense (note 4)
    1 103       610       718  
Federal excise tax
    1 264       1 254       1 231  
Property taxes included in expenses
    85       80       85  
Payroll and other taxes included in expenses
    50       52       51  
GST/QST/HST collected (a)
    2 297       2 015       1 717  
GST/QST/HST input tax credits (a)
    (1 948 )     (1705 )     (1368 )
Other consumer taxes collected for governments
    1 670       1 662       1 589  
Crown royalties
    472       418       314  
 
Total paid or payable to governments
    4 993       4 386       4 337  
Less investment tax credits and other receipts
    14       30       12  
 
Net paid or payable to governments
    4 979       4 356       4 325  
 
Net payments to:
                       
Federal government
    2 472       2 061       2 171  
Provincial governments
    2 422       2 215       2 069  
Local governments
    85       80       85  
 
Net paid or payable to governments
    4 979       4 356       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.

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