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IMPERIAL OIL LTD - Annual Report: 2003 (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, 2002 Commission file number: 0-12014

IMPERIAL OIL LIMITED
(Exact name of registrant as specified in its charter)

CANADA
(State or other jurisdiction of
incorporation or organization)
      98-0017682
(I.R.S. Employer
Identification No.)

111 ST. CLAIR AVENUE WEST, TORONTO, ONT., CANADA
(Address of principal executive offices)

 

 

 

M5W 1K3
(Zip Code)

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

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

 

 

 

 

 
Title of each class

None
      Name of each exchange on
which registered
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.

        Yes ý No o

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

        Yes ý No o

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

        Yes ý No o

        As of the last business day of the 2002 second fiscal quarter, the aggregate market value of the voting stock held by non-affiliates of the registrant was Canadian $5,446,609,246 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 28, 2003, was 377,338,757.

        The Index to Exhibits is located on page E-1





TABLE OF CONTENTS

PART I

 
 
  Page
Item 1. Business   3
      Financial Information by Operating Segments   3
      Natural Resources   4
          Petroleum and Natural Gas Production   4
          Land Holdings   10
          Exploration and Development   10
      Petroleum Products   12
          Supply   12
          Refining   12
          Distribution   12
          Marketing   13
      Chemicals   14
      Research   14
      Environmental Protection   14
      Human Resources   14
      Competition   14
      Government Regulation   15
      The Company Online   15
Item 2. Properties   16
Item 3. Legal Proceedings   16
Item 4. Submission of Matters to a Vote of Security Holders   16

PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters   16
Item 6. Selected Financial Data   16
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operation   20
Item 7A. Quantitative and Qualitative Disclosures About Market Risk   25
Item 8. Financial Statements and Supplementary Data   25
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure   29

PART III
Item 10. Directors and Executive Officers of the Registrant   30
Item 11. Executive Compensation   32
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters   40
Item 13. Certain Relationships and Related Transactions   41

PART IV
Item 14. Controls and Procedures   41
Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K   42

Index to Financial Statements

 

F-1
Report of Independent Accountants   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.

 
  2002
  2001
  2000
  1999
  1998
   
Rate at end of period   $ 0.6329   $ 0.6279   $ 0.6669   $ 0.6925   $ 0.6504
Average rate during period     0.6368     0.6444     0.6725     0.6744     0.6714
High     0.6619     0.6697     0.6969     0.6925     0.7105
Low     0.6200     0.6241     0.6410     0.6535     0.6341

        On February 28, 2003, 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 $0.6720 U.S. = $1.00 Canadian.

2


        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, the majority by shareholders with 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 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

 
  2002
  2001
  2000
  1999
  1998
 
   
 
 
  (millions)

 
External revenues:                                
  Natural resources   $ 2,677   $ 3,155   $ 3,262   $ 2,216   $ 1,246  
  Petroleum products     13,396     13,105     13,788     9,885     8,975  
  Chemicals     955     930     945     717     831  
  Corporate and other     14     63     56     35     34  
   
 
    $ 17,042   $ 17,253   $ 18,051   $ 12,853   $ 11,086  
   
 
Intersegment sales:                                
  Natural resources   $ 2,217   $ 2,166   $ 2,638   $ 1,688   $ 1,146  
  Petroleum products     1,038     1,300     1,332     780     767  
  Chemicals     209     245     228     155     141  
Total revenues:                                
  Natural resources   $ 4,894   $ 5,321   $ 5,900   $ 3,904   $ 2,392  
  Petroleum products     14,434     14,405     15,120     10,665     9,742  
  Chemicals     1,164     1,175     1,173     872     972  
  Corporate and other     14     63     56     35     34  
Net earnings (1):                                
  Natural resources   $ 1,042   $ 941   $ 1,165   $ 560   $ 249  
  Petroleum products     127     353     313     15     244  
  Chemicals     52     23     59     43     87  
  Corporate and other (2) /eliminations     (11 )   (78 )   (139 )   3     (136 )
   
 
    $ 1,210   $ 1,239   $ 1,398   $ 621   $ 444  
   
 
Identifiable assets at December 31 (3):                                
  Natural resources   $ 5,988   $ 5,365   $ 5,288   $ 5,375   $ 5,206  
  Petroleum products     5,060     4,348     4,812     4,549     4,428  
  Chemicals     406     373     379     347     319  
  Corporate and other/eliminations     414     675     743     533     480  
   
 
    $ 11,868   $ 10,761   $ 11,222   $ 10,804   $ 10,433  
   
 
Capital and exploration expenditures:                                
  Natural resources   $ 986   $ 746   $ 434   $ 430   $ 398  
  Petroleum products     589     339     232     203     197  
  Chemicals     25     30     13     20     17  
   
 
    $ 1,600   $ 1,115   $ 679   $ 653   $ 612  
   
 

(continued on following page)

3


(1)
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.

(2)
Includes primarily interest charges on the debt obligations of the Company, interest income on investments and intersegment consolidating adjustments.

(3)
The identifiable assets in each operating segment represent the net book value of the tangible and intangible assets attributed to such segment.

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, 2002, was as follows:

 
   
   
  2002
  2001
  2000
  1999
  1998
           
 
   
   
  (thousands per day)

Conventional (including natural gas liquids):                    
  Cubic metres     Gross (1)   12.4   13.2   14.3   15.3   14.3
      Net (2)   9.5   10.2   11.0   11.9   11.6
  Barrels     Gross (1)   78   83   90   96   90
      Net (2)   60   64   69   75   73
Oil Sands (Cold Lake):                            
  Cubic metres     Gross (1)   17.8   20.4   18.9   21.0   21.8
      Net (2)   16.9   19.2   16.2   17.1   20.0
  Barrels     Gross (1)   112   128   119   132   137
      Net (2)   106   121   102   107   126
Tar Sands (Syncrude):                            
  Cubic metres     Gross (1)   9.1   8.9   8.1   8.9   8.3
      Net (2)   9.1   8.3   6.7   8.7   8.3
  Barrels     Gross (1)   57   56   51   56   52
      Net (2)   57   52   42   55   52
Total:                            
  Cubic metres     Gross (1)   39.3   42.5   41.3   45.2   44.4
      Net (2)   35.5   37.7   33.9   37.7   39.9
  Barrels     Gross (1)   247   267   260   284   279
      Net (2)   223   237   213   237   251

(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 1998, 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. The increase in conventional production in 1999 was due to a reduction in the injection of natural gas liquids to enhance crude oil production which allowed more natural gas liquids to be available for sale. The reduction in net production at Cold Lake in 1999 resulted mainly from the increase in the effective royalty rate on gross production at Cold Lake, which depends in part on profitability. In 2000, Cold Lake production declined due to the timing of steaming cycles and Syncrude production decreased because of operating difficulties and extended maintenance to heavy crude oil upgrading equipment. In 2001, Cold Lake net production increased mainly due to the timing of steaming cycles and lower royalties and Syncrude production increased mainly due to the start up of the Aurora mine during the second half of 2000 and fewer disruptions in upgrading operations than the previous year. In 2002, Cold Lake production decreased mainly due to the timing of steaming cycles and Syncrude net production increased mainly due to lower royalties.

4


        The Company's average daily production and sales of natural gas during the five years ended December 31, 2002 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.

 
  2002
  2001
  2000
  1999
  1998
   
 
  (millions per day)

Sales (1):                    
  Cubic metres   14.1   14.2   11.9   11.1   10.1
  Cubic feet   499   502   419   393   356
Gross Production (2):                    
  Cubic metres   15.0   16.2   14.9   13.3   12.4
  Cubic feet   530   572   526   469   439
Net Production (2):                    
  Cubic metres   13.1   13.2   13.0   11.7   10.7
  Cubic feet   463   466   459   413   379
Gross Production available for sale (3):                    
  Cubic metres   13.1   13.7   9.8   8.5   8.1
  Cubic feet   463   482   345   300   287
Net Production available for sale (3):                    
  Cubic metres   11.2   10.7   7.8   6.9   6.4
  Cubic feet   396   376   277   244   227

(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.

(3)
Gross production available for sale is the Company's share of production available for sale (excluding purchases) before deducting the shares of mineral owners or governments or both. Net production available for sale excludes those shares. Production available for sale data exclude amounts used for internal consumption and amounts reinjected. Production available for sale in 2001 reflects a change in the supply of natural gas to Company operations from Company produced natural gas to purchased natural gas.

        In 1999, production of natural gas increased mainly due to new natural gas field developments and increased compressor capacity at two gas fields. In 2000 and 2001, natural gas production increased primarily due to gas production from the Sable Offshore Energy Project, which went into production at the end of 1999, and increased production from gas caps overlaying two former oil fields, both in Alberta. In 2002, natural gas production decreased primarily due to the depletion of one of the gas caps in Alberta.

        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, 2002, were as follows:

 
  2002
  2001
  2000
  1999
  1998
   
Average Sales Price:                              
  Crude oil and natural gas liquids:                              
    Per cubic metre   $ 174.72   $ 134.16   $ 190.02   $ 120.82   $ 69.10
    Per barrel     27.78     21.33     30.21     19.21     10.99
  Natural gas:                              
    Per thousand cubic metres   $ 141.91   $ 201.92   $ 176.15   $ 93.90   $ 70.95
    Per thousand cubic feet     4.02     5.72     4.99     2.66     2.01
Average Production (Lifting) Costs Per Unit of Net Production (1):                              
    Per cubic metre   $ 48.81   $ 46.17   $ 47.36   $ 37.54   $ 32.58
    Per barrel     7.76     7.34     7.53     5.97     5.18

(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.

5


        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. Improved access to U.S. markets for natural gas, resulting from expanded export pipeline capacity from the Province of Alberta in late 1998, allowed Canadian natural gas prices to increase in 1999 and to attain parity with U.S. natural gas markets. Prices for Canadian natural gas increased significantly in 2000 and again in early 2001, 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 1999, increased steam injections at Cold Lake were the main cause for the increase in average production (lifting) costs. In 2000, average production (lifting) costs increased mainly due to higher costs for purchased natural gas at Cold Lake. In 2001, average production (lifting) costs decreased mainly due to higher net production at Cold Lake. In 2002, average production (lifting) costs increased mainly due to lower net production at Cold Lake.

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

        The Company's production of conventional and Cold Lake crude oil and natural gas is derived from wells located exclusively in Canada. The total number of producing wells in which the Company had interests at December 31, 2002, is set forth in the following table. The statistics in the table are determined in part from information received from other operators.

 
  Crude Oil
  Natural Gas
  Total
 
  Gross (1)
  Net (2)
  Gross (1)
  Net (2)
  Gross (1)
  Net (2)
   
Conventional wells   2,421   1,389   3,995   2,174   6,416   3,563
Oil Sands (Cold Lake) wells   3,139   3,139       3,139   3,139

(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 2002, net production of crude oil and natural gas liquids was about 2,700 cubic metres (17,100 barrels) per day and gross production was about 4,000 cubic metres (25,200 barrels) per day. The Government of Canada has a one-third carried interest and receives a production royalty of five percent in the Norman Wells oil field. The Government of Canada's carried interest entitles it to receive payment of a one-third share of an amount based on revenues from the sale of Norman Wells production, net of operating and capital costs. Under a shipping agreement, the Company pays for the construction, operating and other costs of the 870 kilometre (540 mile) pipeline which transports the crude oil and natural gas liquids from the project. In 2002, those costs were about $40 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 $3 billion has been spent by the participants to the end of 2002 on the project. Production from the Sable Offshore Energy Project began at the end of 1999 and is expected to average about 14 million cubic metres (500 million cubic feet) per day of natural gas and 3,200 cubic metres (20,000 barrels) per day of natural gas liquids over a 20 year period.

6


    Cold Lake

        The Company holds about 78,000 leased hectares (192,000 acres) of oil sands near Cold Lake, Alberta. This oil sands deposit contains a very heavy crude oil (crude bitumen). To develop the technology necessary to produce this oil commercially, the Company has conducted experimental pilot operations since 1964 to recover the crude bitumen from wells by means of new drilling and production techniques including steam injection. During 2002, net production from the pilots averaged about 2,100 cubic metres (13,400 barrels) per day and gross production was about 2,240 cubic metres (14,100 barrels) per day. Research at, and operation of, the Cold Lake pilots is continuing.

        In late 1983, the Company commenced the development, in stages, of its oil sands resources at Cold Lake. The initial six stages of this production project were completed by 1986. In 1987, the Company received approval from the Alberta Energy Resources Conservation Board ("AERCB") to increase the production of the existing six stages from 9,000 cubic metres (57,000 barrels) to 12,000 cubic metres (76,000 barrels) of crude bitumen per day. Also in 1987, the Company received an amended approval from the AERCB for four additional stages (stages seven to ten) of development at Cold Lake. During 2002, average net production from those ten stages was about 14,100 cubic metres (88,700 barrels) per day and gross production was about 14,900 cubic metres (93,400 barrels) per day.

        In 2002, the Company spent $81 million to drill 332 development wells. To maintain production at Cold Lake, capital expenditures for additional production wells and associated equipment will be required periodically. The Company plans to spend about $92 million in 2003 on such facilities.

        Construction began in 2000 on stages 11 to 13 of development. Total capital investment for the development was about $650 million with the project being completed in late 2002. The new stages are expected to provide, on average, an additional 4,800 cubic metres (30,000 barrels) per day of crude bitumen production by the second half of 2003. To improve overall energy efficiency, the project includes a 170 megawatt cogeneration facility that will provide steam for the new stages and generate enough electricity to supply all of the Company's other Cold Lake operations. Any surplus electricity is sold into the Province of Alberta power pool.

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

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

        The Province of Alberta, in its capacity as lessor of the Cold Lake oil sands leases, is entitled to a royalty on production from the Cold Lake production project, as defined in an agreement with the Province. Near the beginning of 1996, the royalty increased from five percent of production to the greater of five percent of production or 30 percent of an amount based on revenue net of operating and capital costs for the project. The effective royalty on gross production was five percent in 2002 and 2001, 14 percent in 2000, 18 percent in 1999 and eight percent in 1998. In late 2000, the Company entered into an agreement with the Province of Alberta, effective January 1, 2000, on a transitional royalty arrangement that will apply to all of the Company's current and proposed operations at Cold Lake until the end of 2007, at which time the generic Alberta regulations for royalties that apply to all other oil sands development in the Province will take effect. This transition is expected to be royalty neutral. The Company expects that after 2007 the royalty will be the greater of one percent of gross revenue or 25 percent of an amount based on revenue net of operating and capital costs for the Cold Lake production project and the pilot operations.

    Other Oil Sands Activity

        The Company has interests in other oil sands leases in the Athabasca and Peace River areas of northern Alberta. Evaluation wells completed on these leased areas established the presence of very heavy crude oil in place. The Company continues to evaluate these leases to determine their potential for future development.

        The Company holds varying interests in lands totalling about 78,000 leased net hectares (192,000 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.

7


    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 1.4 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's Department of Resource Development. There were no known previous commercial operations on these leases prior to the start-up of operations in 1978.

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

        The Government of Canada has issued an order that expires at the end of 2003 which provides 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. This remission order excludes royalty payable on production for the Aurora project.

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

        Crude bitumen extracted from tar sands is refined to a marketable hydrocarbon product through a combination of carbon removal in two large, high temperature, fluid coking vessels and by hydrogen addition in high temperature, high pressure, hydrocracking vessels. These processes remove carbon and sulphur and reformulate the crude into a low viscosity, low sulphur, high quality synthetic crude oil product. In 2002, the upgrading process yielded 0.863 cubic metres of synthetic crude oil per cubic metre of crude bitumen (0.863 barrels of synthetic crude oil per barrel of crude bitumen). In 2002, about 60 percent of the synthetic crude oil was processed by Edmonton area refineries and the remaining 40 percent was pipelined to refineries in eastern Canada and the mid-western United States. Electricity is provided to Syncrude by a 270 megawatt electricity generating plant and a 80 megawatt electricity generating plant, both located at Syncrude. The generating plants are owned by the Syncrude participants. The Company's 25 percent share of net investment in plant, property and equipment, including surface mining facilities, transportation equipment and upgrading facilities is about $1.6 billion.

8


        In 2002, Syncrude's net production of synthetic crude oil was about 36,100 cubic metres (227,000 barrels) per day and gross production was about 36,500 cubic metres (229,000 barrels) per day. The Company's share of net production in 2002 was about 9,000 cubic metres (56,800 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. The first stage of the Aurora mine is expected to increase the Company's share of Syncrude's gross production to about 9,500 cubic metres (60,000 barrels) per day in 2003.

        In 2001, the Syncrude owners approved another major expansion of upgrading capacity to convert crude bitumen into synthetic crude oil. This project, when combined with further development of the Aurora deposits, is expected to increase the Company's share of Syncrude's gross production to more than about 14,200 cubic metres (89,000 barrels) per day. Startup of production is expected in early 2005, and the Company's share of the project costs is expected to be about $1.2 billion.

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

 
  2002
  2001
  2000
  1999
  1998
   
Total mined volume (1)                    
  millions of cubic metres   77.9   90.3   65.0   76.5   75.2
  millions of cubic yards   102.0   118.3   85.1   100.1   98.4

Mined volume to tar sands ratio (1)

 

1.05

 

1.15

 

0.96

 

0.99

 

1.05

Tar sands mined

 

 

 

 

 

 

 

 

 

 
  millions of tonnes   156.5   164.8   142.2   162.1   150.5
  millions of tons   172.1   181.2   156.4   178.7   165.9

Average bitumen grade (weight percent)

 

11.2

 

11.0

 

11.0

 

10.8

 

10.7

Crude bitumen in mined tar sands

 

 

 

 

 

 

 

 

 

 
  millions of tonnes   17.5   18.1   15.6   17.5   16.1
  millions of tons   19.2   19.9   17.2   19.3   17.8

Average extraction recovery (percent)

 

89.9

 

87.0

 

89.7

 

91.4

 

91.6

Crude bitumen production (2)

 

 

 

 

 

 

 

 

 

 
  millions of cubic metres   15.5   15.5   13.8   15.8   14.6
  millions of barrels   97.8   97.6   86.8   99.6   92.1

Average upgrading yield (percent)

 

86.3

 

84.5

 

84.3

 

83.9

 

84.6

Gross synthetic crude oil produced

 

 

 

 

 

 

 

 

 

 
  millions of cubic metres   13.5   13.1   11.6   13.3   12.4
  millions of barrels   84.8   82.4   73.2   83.6   77.9

Company's net share (3)

 

 

 

 

 

 

 

 

 

 
  millions of cubic metres   3   3   2   3   3
  millions of barrels   21   19   15   20   19

(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

        Prior to October, 2002, the Company held a 75 percent interest in approximately 13,600 leased hectares (33,800 acres) and a 20 percent interest in about 13,900 leased hectares (34,800 acres) in the Kearl Lake area in the Athabasca area of northern Alberta containing tar sands. In October 2002, the Company completed transactions that resulted in the Company obtaining a 100 percent interest in approximately 16,500 hectares (40,700 acres) of surface mineable tar sands. The Company continues to evaluate these leases to determine their potential for future development.

9


Land Holdings

        At December 31, 2002 and 2001, the Company held the following oil and gas rights, and tar sands leases:

 
  Hectares
  Acres
 
 
 
 
  Developed
  Undeveloped
  Total
  Developed
  Undeveloped
  Total
 
 
 
 
  2002
  2001
  2002
  2001
  2002
  2001
  2002
  2001
  2002
  2001
  2002
  2001
 
 
 
 
  (thousands)

Western Provinces                                                
  Conventional —                                                
    Gross (1)   1,109   1,035   205   303   1,314   1,338   2,740   2,557   507   749   3,247   3,306
    Net (2)   454   427   139   182   593   609   1,122   1,055   343   450   1,465   1,505
  Oil Sands (Cold Lake and other) —                                                
    Gross (1)   41   41   200   211   241   252   101   101   494   521   595   622
    Net (2)   41   41   114   125   155   166   101   101   282   309   383   410
  Tar Sands (Syncrude and other) —                                                
    Gross (1)   20   20   98   110   118   130   49   49   242   272   291   321
    Net (2)   10   5   32   34   42   39   25   12   79   84   104   96
Canada Lands (3):                                                
  Conventional —                                                
    Gross (1)   31   1   396   427   427   428   77   2   979   1,055   1,056   1,057
    Net (2)   4   1   150   151   154   152   10   2   371   373   381   375
Atlantic Offshore:                                                
  Conventional —                                                
    Gross (1)   17   17   1,329   1,417   1,346   1,434   42   42   3,284   3,501   3,326   3,543
    Net (2)   2   2   565   654   567   656   5   5   1,396   1,617   1,401   1,622
Total (4):                                                
    Gross (1)   1,218   1,114   2,228   2,468   3,446   3,582   3,009   2,751   5,506   6,098   8,515   8,849
    Net (2)   511   476   1,000   1,146   1,511   1,622   1,263   1,175   2,471   2,833   3,734   4,008

(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, 2002.

 
  2002
  2001
  2000
  1999
  1998
   
Western and Atlantic Provinces:                    
  Conventional                    
    Exploratory —                    
      Oil          
      Gas   1   1   3   3   4
      Dry Holes   2     1   1   1
    Development —                    
      Oil   1   17   18   3   5
      Gas   42   68   49   33   31
      Dry Holes   3         1
  Oil Sands (Cold Lake and other)                    
    Development —                    
      Oil   332   307   112   211   63
   
Total   381   393   183   251   105
   

        The oil sands development wells in 2002 include 267 wells related to the development of stages 11 to 13 at Cold Lake with the balance for productivity maintenance in existing stages and prior to 2001 also reflect drilling for stages 9 and 10 at Cold Lake, and the addition of productivity maintenance wells.

        At December 31, 2002, the Company was participating in the drilling of 44 gross (35 net) exploratory and development wells.

10


    Western Provinces

        In 2002, the Company had a working interest in four gross (three net) exploratory wells and 491 gross (378 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 Mackenzie Valley Aboriginal Pipeline Corporation ("MVAPC"), 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 MVAPC their intention to begin preparing the regulatory applications needed to develop the gas resources, including construction of a Mackenzie Valley pipeline.

        The Company retains an 86 percent interest in a petroleum and natural gas lease with the Inuvialuit Land Corporation. 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 four production licences, managed by others.

        The Company has a 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. An exploratory well was completed in 2001 in this area, without commercial success.

        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. 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. 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, which 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 will earn a 30 percent interest in these licenses by participating in the first exploration well. 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). The Company's share of proposed exploration spending in these areas is about $125 million.

11



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 2002, capital expenditures of about $370 million were made at the Company's refineries. About 80 percent of those expenditures were on new facilities required to meet Government of Canada regulations on the sulphur level in motor gasoline 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, 2002, and the daily rated capacities of the refineries at December 31, 1997 and 2002, were as follows:

 
  Average Daily Volumes of
Refinery Throughput (1)
Year Ended December 31

  Daily Rated
Capacities at
December 31 (2)

 
  2002
  2001
  2000
  1999
  1998
  2002
  1997
 
 
 
 
  (thousands of cubic metres)

Strathcona, Alberta   26.0   25.4   27.0   26.2   25.3   29.3   28.0
Sarnia, Ontario   16.5   16.5   16.2   17.0   16.2   19.2   18.9
Dartmouth, Nova Scotia   12.5   12.3   11.2   11.9   12.3   13.1   13.1
Nanticoke, Ontario   16.2   17.2   17.2   15.0   16.9   17.8   17.8
   
Total   71.2   71.4   71.6   70.1   70.7   79.4   77.8
   

 


 

Average Daily Volumes of
Refinery Throughput (1)
Year Ended December 31


 

Daily Rated
Capacities at
December 31 (2)

 
  2002
  2001
  2000
  1999
  1998
  2002
  1997
 
 
 
 
  (thousands of barrels)

Strathcona, Alberta   163   160   170   165   159   184   176
Sarnia, Ontario   104   104   102   107   102   121   119
Dartmouth, Nova Scotia   78   77   70   75   78   82   82
Nanticoke, Ontario   102   108   108   94   106   112   112
   
Total   447   449   450   441   445   499   489
   

(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 90 percent of capacity in 2002, the same as for the previous year.

    Distribution

        The Company maintains a nation-wide distribution system, including 29 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, 2002, the Company owned and operated two barges. These vessels are used primarily for domestic transportation of refined petroleum products.

12


    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 2,100 Esso retail outlets, of which about 870 are Company owned or leased, but none of which are Company operated. The Company continues to improve its Esso retail outlet 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 110 sales facilities, of which about 40 also sell fertilizers to the western Canadian farm markets under the brand name Engro. A major program to improve the productivity of the Company's rural agency marketing network was largely completed in 2002. The three year $50 million project transformed the rural network from more than 300 bulk fuel locations to less than 100 sites supplied by a more efficient transportation system. The final component of the new network, a centralized order management process to better meet customer needs, is expected to be completed in 2003.

        Heating oil and related equipment services are 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, 2002 are set out in the following table:

 
   
   
   
   
   
 
  2002
  2001
  2000
  1999
  1998
   
 
  (thousands per day)

Gasolines:                    
  Cubic metres   32.9   32.3   32.0   31.9   31.8
  Barrels   207   203   201   201   200
Heating, Diesel and Jet Fuels:                    
  Cubic metres   25.0   26.5   27.5   26.9   25.4
  Barrels   157   166   173   169   160
Heavy Fuel Oils:                    
  Cubic metres   4.9   5.4   5.1   4.6   6.2
  Barrels   31   34   32   29   39
Lube Oils and Other Products (1):                    
  Cubic metres   6.4   5.4   5.0   5.8   5.2
  Barrels   41   34   31   36   33
Net petroleum product sales:                    
  Cubic metres   69.2   69.6   69.6   69.2   68.6
  Barrels   436   437   437   435   432
Sales under purchase and sale agreements:                    
  Cubic metres   13.9   11.6   10.7   10.8   9.6
  Barrels   87   73   67   68   60
Total:                    
  Cubic metres   83.1   81.2   80.3   80.0   78.2
  Barrels   523   510   504   503   492

(1)
Includes 1.0 thousand cubic metres (6.4 thousand barrels) per day of butane for 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, 2002, were as follows:

 
   
   
   
   
   
   
 
  2002
  2001
  2000
  1999
  1998
   
   
   
    91.5%   93.4%   94.0%   95.6%   96.0%    

        The Company continues to evaluate and adjust its Esso retail outlet and distribution system to increase productivity and efficiency.

        During 2002, the Company closed or debranded about 140 Esso retail sites, about 60 of which were Company owned, and added about 70 sites. The Company's average annual throughput per Esso retail outlet was 3.3 million litres, an increase of 0.3 million litres from 2001. Average throughput per Company owned Esso retail outlet was 4.9 million litres in 2002, an increase of about 0.5 million litres from 2001.

13


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, 2002, were as follows:

 
   
   
   
   
   
 
  2002
  2001
  2000
  1999
  1998
   
 
  (thousands per day)

Petrochemicals:                    
Tonnes   3.5   3.3   3.1   3.0   3.5
Tons   3.9   3.6   3.4   3.3   3.9

Research

        In 2002, the Company's research expenditures in Canada, before deduction of investment tax credits, were $50 million, as compared with $37 million in 2001 and $31 million in 2000. 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 2002. 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. About 130 people were employed in this type of research at the end of 2002. 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 $510 million on environmental protection and facilities. In 2002, the Company's capital expenditures relating to environmental protection totalled approximately $360 million, and are expected to be about $275 million in 2003. Increased environmental expenditures over the past two years primarily reflect spending on a project to reduce sulphur in motor gasolines, a requirement of the Government of Canada. The total cost of that project is expected to be about $575 million. In 2002, the Government of Canada adopted a new regulation requiring ultra-low sulphur on-road diesel fuel commencing in 2006 and which is to be fully implemented in 2007. Capital expenditures on safety related projects in 2002 were approximately $15 million.

Human Resources

        At December 31, 2002, the Company employed full-time approximately 6,500 persons compared with about 6,700 at the end of 2001 and 2000. About seven 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.

14


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 Web site www.imperialoil.ca contains a variety of corporate and investor information which are available free of charge, including the Company's Form 10-K and quarterly reports on Form 10-Q. The Company's current reports on Form 8-K will also be made available on the Web site for reports filed during and after 2003.

15



Item 2.    Properties.

        Reference is made to Item 1 above, and for the reserves of the Syncrude mining operations, 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 and Related Stockholder Matters.

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.

        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

 
  2002
three months ended

  2001
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)   0.21   0.21   0.21   0.21   0.195   0.21   0.21   0.21

Share prices (dollars)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
Toronto Stock Exchange                                
  High   47.85   49.38   47.10   46.10   40.10   43.50   46.50   46.15
  Low   41.13   43.76   38.51   41.55   34.05   37.50   38.00   39.90
  Close   47.45   47.29   45.90   44.86   38.45   38.85   42.75   44.31
American Stock Exchange ($U.S.)                                
  High   30.33   31.85   31.09   29.31   26.40   28.20   29.25   29.45
  Low   25.83   28.15   24.00   26.61   22.59   23.65   24.73   25.08
  Close   29.84   31.19   29.00   28.70   24.42   25.75   27.21   27.88

        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, 2003, there were 15,920 holders of record of common shares of the Company.


Item 6.    Selected Financial Data.

 
  2002
  2001
  2000
  1999
  1998
   
 
  (millions)

Total revenues   $ 17,042   $ 17,253   $ 18,051   $ 12,853   $ 11,086
Net earnings     1,210     1,239     1,398     621     444
Total assets     11,868     10,761     11,222     10,804     10,433
Long-term debt     1,466     1,029     1,037     1,352     1,583
Other long-term obligations     1,187     1,063     1,044     1,091     1,042

Net earnings/share — basic

 

$

3.19

 

$

3.15

 

$

3.35

 

$

1.44

 

$

1.01
Net earnings/share — diluted     3.19     3.15     3.35     1.44     1.01
Cash dividends/share     0.84     0.83     0.78     0.75     0.74

        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.

16


Presentation of Financial Statements

        The financial statements of the Company have been prepared in accordance with generally accepted accounting principles (GAAP) in Canada. These principles conform in all material respects to those in the United States except for the following:

 
  2002
  2001
  2000
  1999
  1998
 
   
 
 
  (millions)

 
Net earnings as shown in financial statements (restated) (a)   $ 1,210   $ 1,239   $ 1,398   $ 621   $ 444  
Impact of U.S. accounting principles:                                
  Capitalized interest (1)     4     (3 )   (3 )   (3 )   (3 )
  Enacted tax rate difference (2)         (13 )   13          
   
 
Net earnings under U.S. GAAP (6) (a)   $ 1,214   $ 1,223   $ 1,408   $ 618   $ 441  
Other comprehensive income (expense), net of tax (7):                                
  Minimum pension liability adjustment (net of tax benefit of $155 million in 2002; 2001 — $34 million benefit; 2000 — $9 million benefit)     (238 )   (52 )   (16 )   22     (31 )
   
 
Comprehensive income under U.S. GAAP   $ 976   $ 1,171   $ 1,392   $ 640   $ 410  
   
 

(a)
Net earnings/share

Under accounting principles of:                    
Canada                    
   — basic   $3.19   $3.15   $3.35   $1.44   $1.01
   — diluted   $3.19   $3.15   $3.35   $1.44   $1.01
United States                    
   — basic   $3.20   $3.11   $3.37   $1.43   $1.01
   — diluted   $3.20   $3.11   $3.37   $1.43   $1.01

Notes (1) through (12) found on pages 18 to 20 apply to the above and following tables.

        The adjustments under United States GAAP result in changes to the consolidated balance sheet of the Company as follows:

 
  As at
December 31, 2002
(millions)

  As at
December 31, 2001
(millions)

 
 
  As Reported
  U.S. GAAP
  As Reported
  U.S. GAAP
 
   
 
 
Current assets (5)   $ 2,657   $ 2,657   $ 2,458   $ 2,458  
Future income tax assets (4)     323     530     227     277  
Investments and other long term assets (5)     134     134     139     139  
Property, plant and equipment — cost (1) (4)     18,045     18,157     16,756     16,857  
Property, plant and equipment — accumulated depreciation
    and depletion (1) (4)
    (9,519 )   (9,610 )   (9,047 )   (9,133 )
Goodwill (8)     204     204     204     204  
Other intangible assets                          
   — cost (3) (8)     54     168     49     161  
   — accumulated amortization     (30 )   (30 )   (25 )   (25 )
   
 
Total Assets   $ 11,868   $ 12,210   $ 10,761   $ 10,938  
   
 
Current liabilities (5)   $ 2,743   $ 2,743   $ 3,025   $ 3,025  
Long term debt (5)     1,466     1,466     1,029     1,029  
Other long term obligations (3)     1,187     1,823     1,063     1,303  
Future income tax liabilities (4)     1,260     1,267     1,311     1,315  
Shareholders' equity     5,212     4,911     4,333     4,266  
   
 
Total liabilities, deferred income taxes and shareholders' equity   $ 11,868   $ 12,210   $ 10,761   $ 10,938  
   
 
Shareholders Equity:                          
Common shares at stated value                          
  At beginning of year   $ 1,941   $ 1,941   $ 2,039   $ 2,039  
  Share purchases at stated value     (2 )   (2 )   (98 )   (98 )
   
 
  At end of year   $ 1,939   $ 1,939   $ 1,941   $ 1,941  
   
 

(continued on following page)

17


 
  As at
December 31, 2002
(millions)

  As at
December 31, 2001
(millions)

 
 
  As Reported
  U.S. GAAP
  As Reported
  U.S. GAAP
 
   
 
 
Retained earnings                          
  At beginning of year   $ 2,392   $ 2,402   $ 2,191   $ 2,217  
  Net earnings for the year     1,210     1,214     1,239     1,223  
  Share purchases in excess of stated value     (11 )   (11 )   (714 )   (714 )
  Dividends     (318 )   (318 )   (324 )   (324 )
   
 
  At end of year   $ 3,273   $ 3,287   $ 2,392   $ 2,402  
   
 
Accumulated other comprehensive income                          
  At beginning of year         (77 )       (25 )
  Other comprehensive income for the year         (238 )       (52 )
   
 
  At end of year         (315 )       (77 )
   
 
Total shareholders' equity   $ 5,212   $ 4,911   $ 4,333   $ 4,266  
   
 

    (1)
    Interest expense related to major construction projects is not required to be capitalized in Canada, as it is in the United States. Total debt related interest expense in 2002 was $40 million of which $11 million was capitalized under U.S. GAAP. The Company's financing costs including debt related expense are reported in note 13 to the financial statements on page F-17. At December 31, 2002, the unamortized balance of capitalized interest under U.S. GAAP was $21 million (2001 — $14 million). This was offset in future (deferred) income taxes and shareholders' equity.

    (2)
    Under Canadian GAAP enacted income tax rates are recognized by the introduction of the enacting legislation in the Canadian federal parliament or provincial legislatures. Under U.S. GAAP income tax rates are "enacted" when proclaimed into law. There was no enacted tax rate difference for 2002.

    (3)
    Disclosures required under Statement of Financial Accounting Standards (SFAS) No. 132 "Employers Disclosures about Pensions and Other Postretirement Benefits" that are not in note 6 to the financial statements on pages F-13 and F-14 are as follows:

 
  Pension Benefits
 
 
  2002
  2001
 
   
 
Net liability recognized under Canadian GAAP   $ (388 ) $ (285 )
Intangible asset     (114 )   (112 )
Accumulated other comprehensive income (before tax)     (521 )   (128 )
   
 
Net liability recognized under U.S. GAAP   $ (1,023 ) $ (525 )
   
 

      An adjustment required by SFAS No. 130 remains a Canadian-U.S. GAAP difference (see note 7).

    (4)
    Differences from the adjustments described in notes (1) and (7) result in future (deferred) income taxes that are $200 million lower at December 31, 2002 than reported under Canadian GAAP (2001 — $46 million lower).

    (5)
    SFAS No. 107 "Disclosures about Fair Value of Financial Instruments" and SFAS No. 133 "Accounting for Derivative Instruments and Hedging Activities" requires a summary table of the fair value and related carrying amounts of financial instruments. The estimated fair values of the Company's financial instruments and derivatives are as follows:

 
  2002
  2001
 
 
 
 
 
  Carrying Amount
  Fair Value
  Carrying Amount
  Fair Value
 
 
 
 
 
  (millions)

 
Assets                          
  Cash   $ 766   $ 766   $ 872   $ 872  
  Accounts receivable     1,348     1,348     992     992  
  Other long term assets (receivable)     60     59     67     61  

Liabilities:

 

 

 

 

 

 

 

 

 

 

 

 

 
  Current     (2,743 )   (2,743 )   (3,025 )   (3,025 )
  Current portion of long term debt                  
  Long-term debt     (1,466 )   (1,466 )   (1,029 )   (1,030 )

      The fair values of cash, marketable securities, promissory notes, accounts receivable and current liabilities approximate recorded amounts because of the short period to receipt or payment of cash. The fair value of the Company's long-term debt is estimated based on quoted market prices for the same or similar issues or on the current rates offered to the Company for debt of the same duration to maturity. The fair values of other financial instruments held by the Company are estimated primarily by discounting future cash flows using current rates for similar financial instruments under similar credit risk and maturity conditions.

      No significant energy derivatives, foreign exchange forward contracts or currency and interest rate swaps were transacted by the Company in the past three years.

18


      Letters of credit and guarantees that are outstanding have not been included in the above table because the fair value of these commitments, determined either by the fees charged to enter into similar agreements or the expected amount required to settle these instruments, is not material.

      Additional disclosures required by SFAS No. 133 are included in the financial statements, as part of the Summary of Significant Accounting Policies on page F-8 and Notes to the Consolidated Financial Statements (primarily notes 4 and 8) on pages F-12 and F-15.

    (6)
    As of January 1, 2001, the Company adopted SFAS No. 133 "Accounting for Derivative Instruments and Hedging Activities" as amended by Statements No. 137 and 138. This statement requires that all derivatives be recognized as either assets or liabilities in the financial statements and be measured at fair value. Since the Company makes limited use of derivatives, the effect of adoption of SFAS No. 133 on the Company's operations or financial condition was negligible.

    (7)
    SFAS No. 130, "Reporting Comprehensive Income", adopted for U.S. GAAP reporting, requires that changes in the balances of items in equity from non-shareholder sources be reported in a financial statement as other comprehensive income (loss). The item of comprehensive income (loss) that applies to the Company is the equity adjustment for minimum pension liability as required by SFAS No. 87. The $238 million loss recognized in 2002 (2001 — $52 million loss; 2000 — $16 million loss) represents that portion of the additional pension liability not yet recognized as a net periodic cost under U.S. GAAP.

    (8)
    As of January 1, 2002, the Company adopted SFAS No. 142 "Goodwill and Other Intangible Assets". SFAS No. 142 addresses financial accounting and reporting for acquired goodwill and other intangible assets. Goodwill and certain intangibles with indefinite lives are no longer amortized but are subject to annual impairment tests. Intangible assets that have finite useful lives continue to be amortized over their useful lives. The Canadian Institute of Chartered Accountants (CICA) adopted a similar standard that harmonizes Canadian GAAP with U.S. GAAP. Disclosures required by the new U.S. and Canadian accounting standards are described in note 2 to the financial statements on page F-12.

    (9)
    As of January 1, 2002 the Company adopted SFAS No. 144 "Accounting for the Impairment or Disposal of Long-Lived Assets". The new standard retains the requirements of existing U.S. GAAP to recognize an impairment loss if the carrying amount exceeds undiscounted cash flows and to measure the impairment loss as the difference between the carrying amount and fair value of the asset. SFAS No. 144 also retains the existing U.S. GAAP requirement to report separately discontinued operations, but extends that reporting to a component of the Company that has been disposed of or is classified as held for sale. Adoption of SFAS No. 144 did not have a material effect on the Company's operations or financial condition.

    (10)
    In June 2001, SFAS No. 143, "Accounting for Asset Retirement Obligations" was issued. Its primary impact will be to change the method of accruing for natural resources site restoration costs. These costs are currently accrued ratably over the productive lives of the assets. Under SFAS No. 143, the fair value of asset retirement obligations will be recorded as liabilities when they are incurred, which are typically at the time the assets are installed. Amounts recorded for the related assets will be increased by the amount of these obligations. Over time the liabilities will be accreted for the change in their present value and the initial capitalized costs will be depreciated over the useful lives of the related assets. The Company will be adopting SFAS No. 143 effective January 1, 2003. The effect of adopting the new standard will be to reduce the site restoration expense in the near term and to increase site restoration expense in the longer term as a result of the accretion of the asset retirement obligation over time. Site restoration expense is expected to decrease in 2003, thereby increasing net earnings by about $33 million. CICA issued a similar standard that harmonizes Canadian GAAP with U.S. GAAP.

    (11)
    SFAS No. 146 "Accounting for Costs Associated with Exit or Disposal Activities" applies to exit and disposal activities initiated after December 31, 2002. The standard requires the fair value of a liability for a cost associated with an exit or disposal activity be recognized in the period in which the liability is incurred. The Company is not engaged in any significant current exit or disposal activities.

    (12)
    SFAS No. 148 "Accounting for Stock-Based Compensation Transition and Disclosure" provides alternative methods of transition for a voluntary change to the fair value based method of accounting for stock based employee compensation. In addition, the disclosure requirements under SFAS No. 148 require more prominent disclosures in the financial statements about the method of accounting for stock based employee compensation and the effect of the method used on reported results.

      Effective January 1, 2003, the Company will adopt for all stock-based compensation granted after that date the fair value based recognition provisions as prescribed by SFAS No. 123 "Accounting for Stock Based Compensation". The following information on stock based compensation meets the new disclosure requirements under SFAS No. 148.

      Stock based compensation

      The Company accounts for its stock based compensation programs, except for the stock option plan, under the fair value based recognition provisions of SFAS No. 123. Under the fair value based method, compensation expense related to the units of these programs is recorded in the consolidated statement of earnings over the vesting period. The Company accounts for its stock option plan by using the intrinsic value method as permitted by SFAS No. 123, and does not recognize compensation expense on the issuance of stock options because the exercise price is equal to the market value at date of grant. The Company's incentive compensation programs are described in note 9 to the financial statements on page F-15.

19


      If the provisions of SFAS No. 123 had been adopted for all prior years, the impact on compensation expense, net earnings and earnings per share would have been as follows:

 
  2002
  2001
  2000
 
   
 
 
  (millions)

 
Net earnings as shown in financial statements   $ 1,210   $ 1,239   $ 1,398  
Stock-based compensation expense as reported, net of tax     24     30     38  
Stock-based compensation expense, net of tax, determined under fair value based method     (40 )   (30 )   (38 )
   
 
Pro forma net earnings   $ 1,194   $ 1,239   $ 1,398  
   
 
Net earnings/share:                    
  As reported — basic and diluted   $ 3.19   $ 3.15   $ 3.35  
  Pro forma — basic and diluted   $ 3.15   $ 3.15   $ 3.35  

      Effective January 1, 2003, the Company will adopt for all stock based compensation granted after that date the recognition provisions as prescribed by SFAS No. 123.

Additional Financial Statement Disclosures

        The Company's policy regarding the provision for site restoration costs is described on page F-8. Amounts recorded to date are shown in note 7 to the financial statements on page F-15. In Natural Resources, additional costs for site restoration that are to be accrued over future years are estimated to be about $585 million (2002 — $525 million).

        These additional costs will be accounted for as part of the transitional adoption provisions of SFAS No. 143 (see note 10 above). The transitional provisions require that the present value of a liability be recognized as if SFAS No.143 had been in effect at the time the natural resources assets were originally installed. The Company is then required to recognize a cumulative accretion for the change in the present value of the liability to adoption date, as well as a cumulative depreciation measurement to adoption date. Any resulting adjustment to the current recorded liability is to be recognized as a cumulative effect adjustment in the statement of earnings.


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

        Net earnings in 2002 were $1,210 million or $3.19 a share, compared with $1,239 million or $3.15 a share in 2001 (2000 — $1,398 million, or $3.35 a share). Higher prices for bitumen largely offset lower prices for natural gas, reduced production of crude oil and weak markets for petroleum products.

        Earnings in 2002 included after tax gains of $4 million on asset sales, compared with gains of $7 million in 2001 (2000 — gains of $96 million).

        Compared to 2001, the positive factors affecting 2002 earnings were: higher resource prices by $265 million; higher product volumes by $48 million; lower expenses by $34 million and favourable foreign exchange effects on U.S. dollar debt by $64 million.

        Compared to 2001, the negative factors affecting 2002 earnings were: lower product margins by $300 million and reduced production of oil and gas by $140 million.

        The following table shows the Company's net earnings by segment for the five years ending December 31, 2002:

 
  2002
  2001
  2000
  1999
  1998
 
   
 
 
  (millions)

 
Natural resources   $ 1,042   $ 941   $ 1,165   $ 560   $ 249  
Petroleum products     127     353     313     15     244  
Chemicals     52     23     59     43     87  
Corporate and other     (11 )   (78 )   (139 )   3     (136 )
   
 
Net earnings   $ 1,210   $ 1,239   $ 1,398   $ 621   $ 444  
   
 

Natural Resources

        Earnings from natural resources were $1,042 million — the second best year on record — up from $941 million in 2001 (2000 — $1,165 million). Higher prices for blended bitumen more than offset the effects of lower prices for natural gas and decreased production of crude oil. Included in the earnings were gains of $3 million from the sale of assets, unchanged from 2001 (2000 — gains of $86 million).

        Compared to 2001, the positive factors affecting 2002 earnings were higher prices by $265 million.

        Compared to 2001, the negative factors affecting 2002 earnings were: reduced production of oil and gas by $140 million and higher project related and other expenses by $24 million.

20


        Resource revenues were $4.9 billion, down from $5.3 billion in 2001 (2000 — $5.9 billion). The main reasons for the decline were lower natural gas prices and decreased production of crude oil.

        World prices for light crude oil were slightly higher in 2002 than 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 $25 (U.S.) a barrel in 2002, compared with $24.50 in 2001 (2000 — $28.40). Prices strengthened considerably as the year progressed, beginning 2002 much lower than the previous year, but ending the year higher.

        The Company's realizations on sales of conventional Canadian crude mirrored the same trends as world prices. Average realizations during the year were $36.81 (Cdn) a barrel versus $35.56 in 2001 (2000 — $41.52).

        In contrast, world markets for heavy oil were tighter throughout the year, reflecting reduced global supplies. This contributed to a strengthening of prices for Canadian heavy oil, including blended bitumen from Cold Lake. The price of Bow River, a benchmark Canadian heavy crude oil, increased by more than 25 percent in 2002, compared with a two percent increase in prices for Canadian light crude oil.

        Prices for Canadian natural gas in 2002, while strong by historical standards, were lower on average than in the previous year. The average of 30 day spot prices for natural gas at the AECO hub in Alberta was about $4.10 a thousand cubic feet in 2002, down from $6.30 a thousand in 2001 (2000 — $5.00).

        The Company's average realizations on natural gas sales decreased to $4.02 a thousand cubic feet from $5.72 a thousand in 2001 (2000 — $4.99).

        Gross production of crude oil and natural gas liquids (NGLs) decreased to 247,000 barrels a day from 267,000 barrels in 2001 (2000 — 260,000). Net production decreased to 223,000 barrels a day from 237,000 barrels in 2001 (2000 — 213,000).

        Net bitumen production at the Company's Cold Lake operation was 106,000 barrels a day, down from 121,000 barrels in 2001 (2000 — 102,000). The decline resulted from the timing of steam injections associated with the recovery process used at Cold Lake. The effective royalty rate on Cold Lake production was unchanged from 2001.

        Production from the Syncrude operation, in which the Company has a 25 percent interest, increased in the year as a result of greater operating reliability. Gross production of upgraded crude oil rose to 229,000 barrels a day from 223,000 barrels in 2001 (2000 — 203,000). The Company's share of average net production increased to 57,000 barrels a day from 52,000 barrels in 2001 (2000 — 42,000).

        Net production of conventional oil decreased to 39,000 barrels a day from 42,000 barrels in 2001 (2000 — 46,000) as a result of the natural decline in western Canadian reservoirs.

        Net production of natural gas was 463 million cubic feet a day in 2002, largely unchanged from 466 million in 2001 (2000 — 459 million).

        Net production available for sale increased to 396 million cubic feet a day from 376 million in 2001 (2000 — 277 million). The primary reason for the increase was a reduction in the Company's natural gas used in its own operations.

        Operating costs, including exploration expenses, increased by about one percent in 2002. The main factor was increased costs associated with planned expenses for the start up of the Cold Lake expansion and other growth projects.

        Proceeds from divestments and property sales in natural resources were $34 million in 2002, up from $8 million in 2001 (2000 — $234 million).

        The following table shows the Company's capital and exploration expenditures for natural resources during the five years ending December 31, 2002:

 
  2002
  2001
  2000
  1999
  1998
   
 
  (millions)

Exploration   $ 39   $ 49   $ 56   $ 29   $ 51
Production     143     109     110     138     185
Heavy Oil     804     588     268     263     162
   
Total   $ 986   $ 746   $ 434   $ 430   $ 398
   

        About 90 percent of the capital and exploration expenditures in 2002 was focused on growth opportunities. The largest single investment during the year was the Company's share of the Syncrude expansion. Significant expenditures were also made to complete development of Cold Lake stages 11 to 13. The remainder of 2002 investment was directed to East Coast development and exploration, advancing the Mackenzie gas project and drilling for conventional oil and gas in Western Canada.

21


        Planned capital and exploration expenditures in natural resources are expected to total about $1 billion in 2003, 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 Mackenzie gas project, continued maintenance at Cold Lake, development of a second tier of the Sable Offshore Energy Project, as well as on further development drilling in Western Canada. Planned expenditures for exploration and development drilling, as well as for capacity additions in conventional oil and gas operations, are expected to be about $140 million.

Petroleum Products

        Net earnings from petroleum products were $127 million or 0.4 cents a litre in 2002, down from a record $353 million or 1.2 cents a litre in 2001 (2000 — $313 million or 1.1 cents a litre). The decline was caused by reduced industry refining and marketing margins.

        Compared to 2001, the positive factors affecting 2002 earnings were: lower expenses by $60 million and higher volumes by $20 million.

        Compared to 2001, the negative factors affecting 2002 earnings were lower refining and marketing margins by $306 million.

        Revenues were $14.4 billion, unchanged from the previous year (2000 — $15.1 billion).

        Margins were lower in both the refining and marketing segments of the industry, reflecting high inventories and strong competition. Although refining margins improved late in the year, as North American product inventories returned to more normal levels, average margins for the year as a whole were significantly lower than in 2001. Average marketing margins were also lower than the previous year.

        The Company's total sales volumes, including those resulting from reciprocal supply agreements with other companies, were 83.1 million litres a day, compared with 81.2 million litres in 2001 (2000 — 80.3 million). Excluding sales resulting from reciprocal agreements, sales were 69.2 million litres a day, compared with 69.6 million litres in 2001 (2000 — 69.6 million).

        Operating costs decreased by about three percent in 2002 from the previous year.

        The following table shows the Company's capital expenditures for petroleum products during the five years ending December 31, 2002:

 
  2002
  2001
  2000
  1999
  1998
   
 
  (millions)

Marketing   $ 133   $ 171   $ 121   $ 80   $ 102
Refining and supply     399     118     100     114     78
Other (1)     57     50     11     9     17
   
Total   $ 589   $ 339   $ 232   $ 203   $ 197
   

(1)
Consists primarily of purchases of real estate.

        Capital expenditures increased to $589 million in 2002, compared with $339 million in 2001 (2000 — $232 million). The Company invested more than $300 million in refining operations during the year as part of a $575-million project to eliminate virtually all sulphur from Esso gasoline. In addition, almost $100 million was invested in a variety of refinery projects to improve energy efficiency and increase yield.

        Major investments were also made to upgrade the network of Esso retail outlets in 2002.

        Capital expenditures in 2003 are expected to be about $500 million. Major items include additional investment in refining facilities to complete the sulphur reduction project and continued enhancements to the Company's retail network. There will also be significant expenditures on a 95 megawatt cogeneration facility in Sarnia, slated for completion in 2004, which will improve energy efficiency and reduce emissions at the Company's Sarnia based petroleum product and chemical operations.

Chemicals

        Earnings from chemical operations were $52 million in 2002, up from $23 million in 2001 (2000 — $59 million). Increased margins on sales of polyethylene and a full year of production from an expansion of the polyethylene plant, which was completed in late 2001, were the main reasons for the improvement.

        Compared to 2001, the positive factors affecting 2002 earnings were: higher volumes by $28 million and higher margins by $6 million.

        Compared to 2001, the negative factors affecting 2002 earnings were higher volume related expenses by $5 million.

        Increased sales of intermediate products, which include solvents, plasticizers and industrial alcohols, also contributed to the higher earnings.

        Total revenues from chemical operations were $1,164 million, compared with $1,175 million in 2001 (2000 — $1,173 million). Prices for both polyethylene and intermediate chemicals were lower in the year, offsetting gains from increased sales volumes.

22


        The average industry price of polyethylene was $1,229 a tonne in 2002, down four percent from $1,284 a tonne in 2001 (2000 — $1,368). However, margins improved because of lower feedstock costs, reflecting reduced prices for natural gas.

        Sales of chemicals increased to 3,500 tonnes a day from 3,300 tonnes a day in 2001 (2000 — 3,100 tonnes), following the fifth expansion of the Sarnia polyethylene plant.

        Operating costs in the chemical segment increased by four percent in 2002, largely because of a seven-percent increase in total production volumes.

        The following table shows the Company's capital expenditures for chemicals during the five years ending December 31, 2002:

 
  2002
  2001
  2000
  1999
  1998
   
   
   
 
  (millions)

   
    $ 25   $ 30   $ 13   $ 20   $ 17    

        Of the capital expenditures in 2002, the major investment was the Sarnia cogeneration project, a joint development between the petroleum product and chemical operations at the site.

        Planned expenditures in 2003 will increase to more than $40 million, with the majority of the investment relating to the Sarnia cogeneration project.

Financial Review

        Earnings from corporate and other accounts were negative $11 million in 2002, compared with negative $78 million in 2001 (2000 — negative $139 million). The improvement was mainly attributable to favourable foreign exchange effects on the Company's U.S. dollar denominated debt.

        Cash flow from earnings was $1,758 million, down from $1,991 million in 2001 (2000 — $1,844 million), mainly because of the timing of income tax payments. Cash provided from operating activities was $1,676 million, compared with $2,004 million in 2001 (2000 — $2,089 million). The main reasons for the reduction were the effects of higher commodity prices on accounts receivable, partly offset by changes to accounts payable, and the timing of income tax payments.

        At the beginning of 2002, the Company purchased 296,000 shares for $13 million, essentially completing the normal course issuer bid (share buyback program) that had begun in June 2001. In June 2002, the Company renewed the buyback program for another 12 months. No shares were purchased under the program during the balance of the year. Since the Company initiated its first buyback program in 1995, the Company has purchased 202.7 million shares — representing about 35 percent of the total outstanding at the start of the program — with resulting distributions to shareholders of $5,169 million.

        The Company declared dividends totalling 84 cents a share in 2002, up from 83 cents in 2001 (2000 — 78 cents). Regular dividends per share have increased in each of the past eight years and, since 1986, payments have grown by more than 50 percent a share.

        At year-end, the balance of cash and marketable securities was $766 million, compared with $872 million at the end of 2001 (2000 — $1,020 million).

        In 2002, the Company retired the remaining $45 million (U.S.) of its 83/4-percent sinking fund debentures due in 2019 for $71 million (Cdn), replacing this long term debt with short term Canadian commercial paper. The Company also issued $500 million of floating rate notes under its $1 billion medium term notes program. They have an initial term of two years and are extendable up to five years at the discretion of noteholders.

        Total debt outstanding at the end of 2002 was $1,538 million, compared with $1,489 million at the end of 2001 (2000 — $1,412 million).

        Debt related interest expense paid in 2002 was $40 million, down from $77 million in 2001 (2000 — $106 million). Generally lower interest rates and the retirement of the Company's long term, fixed rate debt during the past few years were the reasons for the reduction. The average effective interest rate on the Company's debt was 2.1 percent in 2002, compared with 5.1 percent in 2001 (2000 — 7.3 percent).

        Capital and exploration expenditures increased to $1,600 million in 2002 from $1,115 million in 2001 (2000 — $679 million). The funds were used mainly to maintain and expand crude oil and natural gas production capacity, to upgrade refineries to meet low sulphur gasoline requirements and to enhance the Company's retail outlets and rural agency network.

        Capital and exploration expenditures in 2003, which will focus mainly on growth and productivity improvement, are expected to total about $1.5 billion and will be financed primarily from internally generated funds.

23


        Expenditures in Canada on research and development were $50 million in 2002, up from $37 million in 2001 (2000 — $31 million). These funds were used mainly to develop improved methods for recovering heavy oil and manufacturing polyethylene, as well as developing higher quality lubricants.

        During 2002, the Company spent more than $375 million on projects related to reducing the environmental impact of operations and improving safety. This included investments of more than $300 million in the Company's four refineries as part of its $575 million capital project to produce lower sulphur gasolines.

        The following table shows the Company's cash provided from operating activities during the five years ending December 31, 2002:

 
  2002
  2001
  2000
  1999
  1998
   
   
   
 
  (millions)

   
    $ 1,676   $ 2,004   $ 2,089   $ 1,470   $ 779    

        In 2003, the Company's employee retirement benefit plan will be subject to an actuarial valuation that is required every three years. At the time of the last required valuation in 2000, the Company's registered pension plan was fully funded. Given the downturn in financial markets that has occurred since 2000, the upcoming valuation is expected to result in a requirement for the Company to contribute funds to the plan. The size of any required contribution will not be known until the valuation is completed. However, the Company does not expect the funding requirement to affect its existing capital investment plans or its ability to take advantage of new investment opportunities.

        The following table shows the Company's long term contractual obligations:

 
   
  Payment due by period
millions of dollars
  Financial statement note reference
  2003
  2004 to 2007
  2008 and beyond
  Total amount

Long term debt   Note 4     1,462   4   1,466
Operating leases   Note 10   64   168   128   360
Unconditional purchase obligations (1)   Note 10   93   187   117   397
Firm capital commitments (2)   Note 10   254   30     284
Other long term agreements (3)   Note 10   214   592   272   1,078

Total       625   2,439   521   3,585

(1)
Unconditional purchase obligations mainly pertain to pipeline throughput agreements.

(2)
Firm capital commitments related to capital projects, shown on an undiscounted basis, totalled approximately $284 million at the end of 2002, compared with $342 million at year-end 2001. The largest commitment outstanding at year-end 2002 was associated with the Company's share of capital projects at Syncrude ($99 million).

(3)
Other long term agreements include primarily raw material supply and transportation services agreements.

Critical Accounting Policies

        The Company's financial statements have been prepared in accordance with Canadian generally accepted accounting principles and include estimates that reflect management's best judgments. The Company's accounting and financial reporting fairly reflects 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.

Oil and gas and synthetic crude oil reserves

        Proved oil and gas and synthetic crude oil reserves quantities are used as the basis of calculating the unit of production rates for depreciation and evaluating for impairment. These reserves are the estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs and deposits under existing economic and operating conditions. The estimation of reserves is an ongoing process based on rigorous technical evaluations and extrapolations of appropriate information. While proved reserves have a reasonable certainty of recovery, they are based on estimates that are subject to some variability. This variability has, however, generally resulted in net upward revisions of proved reserves for the Company through effective reservoir management and the application of new technology. Over the last five years, the Company's net revisions of previous estimates and improved recovery have averaged an increase of 23 million oil equivalent barrels per year including 10 million oil equivalent barrels of synthetic crude oil. While revisions the Company has made in the past are an indicator of variability, they have had a very small impact on the unit of production rates of depreciation and in impairment testing because the revisions have been small compared to the large proved reserves base.

24


Site restoration costs

        Provision for site restoration costs is recorded when it is probable that obligations have been incurred and the amounts can be reasonably determined. This provision is based on engineering estimates of costs, taking into account the anticipated method and extent of remediation consistent with legal requirements, industry practices, current technology and the possible use of the site. Changes in these factors may result in material changes to the provision.

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, rate of return on plan assets and the long term rate for future pay increases. All pension assumptions are reviewed annually by senior financial management and at least once every three years by independent third party actuaries. 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 81/4 percent used in 2002 compares to actual returns of 9.8 percent and 10.1 percent actually achieved over the last 10 and 20 year periods ending December 31, 2002. If different assumptions are used, the expense and obligations could increase or decrease as a result. The Company's potential exposure to change in assumptions is summarized in footnote (e) of note 6 to the financial statements. At the Company, differences between actual returns on plan assets versus the long term expected return are amortized in pension expense, along with other actuarial gains and losses. Pension expense represented about one percent of total expenses in 2002.


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. The Company's potential exposure to these types of risks is summarized in the table on earnings sensitivities. 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 2002.

        Each sensitivity calculation shows the impact on earnings that results from a change in one factor, after tax and royalties and holding all other factors constant. While these sensitivities are applicable under current conditions, they may not apply proportionately to larger fluctuations.

        The 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. Interest and currency swaps may be used within limits to manage the interest rate or currency exposure of the Company's debt, but no such swap contracts have been used in the past three years.

        The following table shows the estimated annual effect, under current conditions, of certain sensitivities of the Company's after tax earnings.

 
  millions of dollars after tax
Three dollars (U.S.) a barrel change in crude oil prices   +(-)   $ 180
Sixty cents (Canadian) a thousand cubic feet change in natural gas prices   +(-)   $ 40
One cent (Canadian) a litre change in sales margins for total petroleum products   +(-)   $ 175
Two cents (U.S.) a pound change in sales margins for polyethylene   +(-)   $ 15
One quarter percent decrease (increase) in short term interest rates   +(-)   $ 3
Six cents decrease (increase) in the value of the Canadian dollar versus the U.S. dollar   +(-)   $ 185

        The sensitivity to changes in the value of the Canadian dollar versus the U.S. dollar has increased from the year 2001 by about $15 million after tax per year for each one Canadian cent difference. This is a result of the higher prices for crude oil, bitumen, natural gas and petroleum products denominated in U.S. dollars at year end 2002 compared to year end 2001. The sensitivity to changes in interest rates reflects a change in both U.S. and Canadian short term interest rates, which reflects the Company's current funding arrangements. Per unit sensitivities for other factors are generally unchanged from the year 2001.


Item 8.    Financial Statements and Supplementary Data.

        Reference is made to the Index to Financial Statements on page F-1 of this report. The reconciliation to U.S. GAAP is in Item 6 of this report.

25


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 2,990 million tonnes (3,295 million tons) of extractable tar sands, in the Base and North mines, with an average bitumen grade of 10.4 weight percent. In addition, at the Aurora mine, there are an estimated 3,665 million tonnes (4,050 million tons) of extractable tar sands at an average bitumen grade of 11.3 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 127 million cubic metres (800 million barrels) of synthetic crude oil.

        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 2000   62   30   92  
Revision of previous estimate     7   7  
Production   (2 )   (2 )
 
 
 
End of year 2000   60   37   97  
Revision of previous estimate     37   37  
Production   (2 ) (1 ) (3 )
 
 
 
End of year 2001   58   73   131  
Revision of previous estimate        
Production   (3 ) (1 ) (4 )
 
 
 
End of year 2002   55   72   127  
 
 
 

 


 

Synthetic Crude Oil


 
 
  Base Mine and North Mine
  Aurora Mine
  Total
 
 
 
 
 
  (millions of barrels)

 
Beginning of year 2000   387   190   577  
Revision of previous estimate     48   48  
Production   (14 ) (1 ) (15 )
 
 
 
End of year 2000   373   237   610  
Revision of previous estimate     230   230  
Production   (15 ) (4 ) (19 )
 
 
 
End of year 2001   358   463   821  
Revision of previous estimate        
Production   (14 ) (7 ) (21 )
 
 
 
End of year 2002   344   456   800  
 
 
 

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

 
  2002
  2001
  2000
   
 
  (millions of dollars)

Sales to customers   $ 1,381   $ 1,306   $ 1,427
Intersegment sales     741     767     971
   
Total sales (1)     2,122     2,073     2,398
Production expenses     599     551     515
Exploration expenses     30     45     35
Depreciation and depletion     424     409     419
Income taxes     343     333     550
   
Results of operations   $ 726   $ 735   $ 879
   

26


Capital and exploration expenditures

 
  2002
  2001
  2000
   
 
  (millions of dollars)

Property costs (2)                  
  Proved   $ 13   $   $ 2
  Unproved     5     5     15
Exploration costs     34     44     41
Development costs     469     489     250
 
 
Total capital and exploration expenditures   $ 521   $ 538   $ 308
 
 

Property, plant and equipment

 
  2002
  2001
   
 
  (millions of dollars)

Property costs (2)            
  Proved   $ 3,338   $ 3,325
  Unproved     155     157
Producing assets     5,371     4,699
Support facilities     126     117
Incomplete construction     227     458
   
Total cost     9,217     8,756
Accumulated depreciation and depletion     5,528     5,130
   
Net property, plant and equipment   $ 3,689   $ 3,626
   

(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)
"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 2000   36   139   175   48  
Revisions of previous estimates and improved recovery     2   2   1  
(Sale)/purchase of reserves in place   (1 )   (1 )  
Discoveries and extensions         1  
Production   (4 ) (6 ) (10 ) (5 )
 
 
 
End of year 2000   31   135   166   45  
Revisions of previous estimates and improved recovery   (1 )   (1 )  
(Sale)/purchase of reserves in place          
Discoveries and extensions          
Production   (4 ) (7 ) (11 ) (5 )
 
 
 
End of year 2001   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  
 
 
 

(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.

27


 
  Crude oil and natural gas liquids

   
 
 
  Conventional
  Cold Lake
  Total
  Natural Gas
 
 
 
 
 
  (millions of barrels)


  (billions of cubic feet)

 
Beginning of year 2000   225   878   1,103   1,692  
Revisions of previous estimates and improved recovery   1   10   11   26  
(Sale)/purchase of reserves in place   (5 )   (5 ) (5 )
Discoveries and extensions   1     1   27  
Production   (26 ) (37 ) (63 ) (168 )
 
 
 
End of year 2000   196   851   1,047   1,572  
Revisions of previous estimates and improved recovery   (8 )   (8 ) 9  
(Sale)/purchase of reserves in place         1  
Discoveries and extensions         2  
Production   (23 ) (44 ) (67 ) (170 )
 
 
 
End of year 2001   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  
 
 
 

(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.

        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 existing experimental pilot plants and commercial stages 1 through 13.

        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.

        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 pilot area and stages 1 through 13 of Cold Lake production operations.

        In 2002, the Company's net proved reserves of crude oil and natural gas liquids decreased by about four million cubic metres (25 million barrels), while the proved reserves of natural gas decreased by about five billion cubic metres (190 billion cubic feet). Production in 2002 totaled about nine million cubic metres (61 million barrels) of crude oil and natural gas liquids and about five billion cubic metres (169 billion cubic feet) of natural gas. Revisions of previous estimates and improved recovery increased reserves of crude oil and natural gas liquids by about five million cubic metres (36 million barrels) and decreased reserves of natural gas by less than one billion cubic metres (26 billion cubic feet). Purchases of reserves accounted for an increase of less than one billion cubic metres (two billion cubic feet) of natural gas. Discoveries and extensions in 2002 totaled less than one billion cubic metres (three billion cubic feet) of natural gas.

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

 
  2002
  2001
  2000
  1999
  1998
   
 
  (millions)

Crude Oil:                    
  Conventional:                    
    Cubic metres   23   26   31   36   37
    Barrels   146   165   196   225   235
  Oil Sands (Cold Lake crude bitumen):                    
    Cubic metres   127   128   135   139   106
    Barrels   801   807   851   878   667
  Total:                    
    Cubic metres   150   154   166   175   143
    Barrels   947   972   1,047   1,103   902
Natural Gas:   (billions)
    Cubic metres   35   40   45   48   50
    Cubic feet   1,224   1,414   1,572   1,692   1,752

28


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

 
  2002
  2001
  2000
  1999
  1998
   
 
  (millions)

Crude Oil:                    
  Conventional:                    
    Cubic metres   22   25   28   32   33
    Barrels   139   157   175   200   205
  Oil Sands (Cold Lake crude bitumen):                    
    Cubic metres   49   34   40   36   36
    Barrels   308   216   250   229   230
  Total:                    
    Cubic metres   71   59   68   68   69
    Barrels   447   373   425   429   435
Natural Gas:   (billions)
    Cubic metres   27   30   35   36   35
    Cubic feet   959   1,060   1,233   1,264   1,224

(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 (1)

 
  2002
  2001
  2000
 
   
 
 
  (millions)

 
Future cash flows   $ 35,811   $ 17,936   $ 28,618  
Future production costs     (8,940 )   (7,107 )   (8,445 )
Future development costs     (3,117 )   (2,641 )   (2,342 )
Future income taxes     (9,107 )   (3,285 )   (8,371 )
   
 
Future net cash flows     14,647     4,903     9,460  
Annual discount of 10 percent for estimated timing of cash flows     (6,446 )   (2,114 )   (3,473 )
   
 
Discounted future net cash flows   $ 8,201   $ 2,789   $ 5,987  
   
 

Changes in Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Gas Reserves (1)

 
  2002
  2001
  2000
 
   
 
 
  (millions)

 
Balance at beginning of year   $ 2,789   $ 5,987   $ 6,064  
Changes resulting from:                    
Sales and transfers of oil and gas produced, net of production costs     (1,645 )   (1,698 )   (1,987 )
Net changes in prices, development costs and production costs     9,276     (6,477 )   1,179  
Extensions, discoveries, additions and improved recovery, less related costs     34     31     (259 )
Purchase/(sales) of minerals in place     4     5     (306 )
Development costs incurred during the year     432     504     299  
Revisions of previous quantity estimates     111     88     715  
Accretion of discount     423     1,030     826  
Net change in income taxes     (3,223 )   3,319     (544 )
   
 
Net Change     5,412     (3,198 )   (77 )
   
 
Balance at end of year   $ 8,201   $ 2,789   $ 5,987  
   
 

(1)
The schedules above are calculated using year-end prices, costs, statutory tax rates and existing proved oil and gas reserves. The value of exploration properties and probable reserves, future exploration costs and the Company's interest in Syncrude are excluded, as are future changes in oil and gas prices and in production and development costs. The Company does not agree that these calculations necessarily represent an accurate estimate of the fair market value of the Company's crude oil and gas properties or of their future cash flows. In the Company's opinion, this method of calculating the data is not reliable and the values may not provide a basis for meaningful analysis. The Company cautions readers about its use.

        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.

29



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 are now directors and have been since the dates indicated.

        The following table provides information on the nominees for election as directors.

Name and current principal occupation or employment
  Last major
position or office with the Company or Exxon Mobil Corporation

  Director since
  Holdings(1)(2)
   

P. (Pierre) Des Marais II
President, Gestion PDM Inc. (management company)
    April 22, 1977   Common shares of Imperial Oil Limited   1,560
            Deferred share units of Imperial Oil Limited   3,232
            Restricted stock units of Imperial Oil Limited   750
            Shares of Exxon Mobil Corporation   0


B.J. (Brian) Fischer
Senior vice-president, products and chemicals division, Imperial Oil Limited

 

Senior vice-president, chemicals division, Imperial Oil Limited

 

September 1, 1992

 

Common shares of Imperial Oil Limited

 

33,354

 

 

 

 

 

 

Deferred share units of Imperial Oil Limited

 

19,716

 

 

 

 

 

 

Restricted stock units of Imperial Oil Limited

 

21,700

 

 

 

 

 

 

Shares of Exxon Mobil Corporation

 

0



T.J. (Tim) Hearn
Chairman, president and chief executive officer, Imperial Oil Limited

 

President, Imperial Oil Limited

 

January 1, 2002

 

Common shares of Imperial Oil Limited

 

20,601

 

 

 

 

 

 

Deferred share units of Imperial Oil Limited

 

0

 

 

 

 

 

 

Restricted stock units of Imperial Oil Limited

 

50,000

 

 

 

 

 

 

Shares of Exxon Mobil Corporation

 

9,069



R. (Roger) Phillips
Retired president and chief executive officer, IPSCO Inc. (steel manufacturing)

 


 

April 23, 2002

 

Common shares of Imperial Oil Limited

 

3,000

 

 

 

 

 

 

Deferred share units of Imperial Oil Limited

 

1,038

 

 

 

 

 

 

Restricted stock units of Imperial Oil Limited

 

750

 

 

 

 

 

 

Shares of Exxon Mobil Corporation

 

2,000



J.F. (Jim) Shepard
Retired chairman and chief executive officer, Finning International Inc. (sale, lease, repair and financing of heavy equipment)

 


 

October 21, 1997

 

Common shares of Imperial Oil Limited

 

3,000

 

 

 

 

 

 

Deferred share units of Imperial Oil Limited

 

3,556

 

 

 

 

 

 

Restricted stock units of Imperial Oil Limited

 

750

 

 

 

 

 

 

Shares of Exxon Mobil Corporation

 

0


(Table continued on following page)

30


Name and current principal occupation or employment
  Last major
position or office with the Company or Exxon Mobil Corporation

  Director since
  Holdings(1)(2)
   

P.A. (Paul) Smith
Controller and senior vice-president, finance and administration, Imperial Oil Limited
  Corporate finance manager, Exxon Mobil Corporation   February 1, 2002   Common shares of Imperial Oil Limited   3,887
            Deferred share units of Imperial Oil Limited   0
            Restricted stock units of Imperial Oil Limited   12,500
            Shares of Exxon Mobil Corporation   1,190

S.D. (Sheelagh) Whittaker
Executive vice-president, EDS (Australia) Pty Limited (business and information technology services)
    April 19, 1996   Common shares of Imperial Oil Limited   3,000
            Deferred share units of Imperial Oil Limited   5,949
            Restricted stock units of Imperial Oil Limited   750
            Shares of Exxon Mobil Corporation   0

K.C. (K.C.) Williams
Senior vice-president, resources division, Imperial Oil Limited
  Vice-president, production, Exxon Company, International   January 1, 1999   Common shares of Imperial Oil Limited   11,600
            Deferred share units of Imperial Oil Limited  
            Restricted stock units of Imperial Oil Limited  
            Shares of Exxon Mobil Corporation   70,162

V.L. (Victor) Young
Corporate director of several corporations
    April 23, 2002   Common shares of Imperial Oil Limited   3,000
            Deferred share units of Imperial Oil Limited   259
            Restricted stock units of Imperial Oil Limited   750
            Shares of Exxon Mobil Corporation   100

(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 35 and 36.

        The ages of the directors, nominees for election as directors, and the five senior executives of the Company are: Pierre Des Marais II 68, Brian J. Fischer 56, Timothy J. Hearn 59, Roger Phillips 63, James F. Shepard 64, Paul A. Smith 50, Sheelagh D. Whittaker 55, K.C. Williams 53, Victor L. Young 57, and John F. Kyle 60.

        Roger Phillips is a director of Canadian Pacific Railways Limited, Cleveland — Cliffs Inc., Fording 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 Pierre Des Marais II, 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. For more than five years before 1999, Pierre Des Marais II's principal occupation was president and chief executive officer of UniMédia Inc., (holding company: newspaper publishing, commercial printing and distribution) following which in 1999 he became president of Gestion PDM Inc. (management company). During the five preceding years, Roger Phillips

31


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. For more than five years before 2000, James F. Shepard's principal occupation was successively president and chief executive officer, and from April 1996, chairman and chief executive officer of Finning International Inc. (sale, lease, repair and financing of heavy equipment) following which, 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
chairman of the board, president and chief executive officer
  April 23, 2002

Brian J. Fischer
senior vice-president, products and chemicals division

 

February 1, 1994

Paul A. Smith
controller and senior vice-president, finance and administration

 

February 1, 2002

K.C. Williams
senior vice-president, resources division

 

January 1, 1999

John F. Kyle
vice-president and treasurer

 

June 1, 1991

        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.


Item 11.    Executive Compensation.

Directors' compensation

        Directors' fees are paid only to nonemployee directors. For 2002, nonemployee directors were paid an annual retainer of $35,000 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. Effective December 31, 2002, the annual board retainer was increased by the issuance of 750 restricted stock units to each nonemployee director. The restricted stock units issued to nonemployee directors have the same features as the restricted stock units for selected employees described on page 36.

        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 36.

32


        While serving as directors in 2002, the aggregate cash remuneration paid to nonemployee directors, as a group, was $628,919, and they received an additional 5,946 deferred share units for nonemployee directors, as a group, based on an aggregate of $272,135 of cash remuneration elected to be received as deferred share units. The nonemployee directors, as a group, received an additional 302 deferred share units granted as the equivalent to the cash dividend paid on Company shares during 2002 for previously granted deferred share units.

Senior executive compensation

Summary compensation table

        The following table shows the compensation for the current chief executive officer, a former chief executive officer and the four other senior executives of the Company who were serving as senior executives at the end of 2002. This information includes the dollar value of base salaries, cash bonus awards, the number of stock options and units of other long-term incentive compensation and certain other compensation.

33


 
   
  Annual Compensation
  Long-Term Compensation
   
 
   
 
   
 
   
   
   
   
  Awards
  Payouts
   
 
   
   
   
   
 
   
Name and
Principal
Position

  Year
  Salary
($)

  Bonus (3)
($)

  Other Annual
Compensation (4)
($)

  Securities
Under
Options/SARs
Granted (5)
(#)

  Restricted
Shares or
Restricted
Share Units
(6)(7)(8)
(#)

  LTIP
Payouts
($)

  All Other
Compensation (9)
($)


T.J. Hearn
Chairman, president and chief executive officer
  2002   668,333   442,000   71,777
U.S. 328,796
  65,000
stock
options
  50,000
restricted
stock units
0
deferred share units
    20,050
    2001   475,000   300,000   19,888
U.S. (163,873)
  50,000
incentive
share units
  0
deferred
share units
    9,500
    2000   445,000   300,000   U.S. 210,672   50,000
incentive
share units
  0
deferred
share units
    8,900


R.B. Peterson (1)
Former chairman and chief executive officer

 

2002

 

343,333

 

400,000

 

102,595

 

145,000
stock
options

 


restricted
stock units
701
deferred share units

 


 

215,045

 

 

2001

 

990,000

 

750,000

 

233,034

 

145,000
incentive
share units

 

756
deferred
share units

 


 

19,800

 

 

2000

 

933,333

 

502,500

 

193,795

 

145,000
incentive
share units

 

13,480
deferred
share units

 


 

18,677



B.J. Fischer
Senior vice-president, products and chemicals division

 

2002

 

505,000

 

216,000

 

0

 

50,000
stock
options

 

21,700
restricted
stock units
358
deferred share units

 


 

30,300

 

 

2001

 

475,000

 

67,500

 

2,935

 

50,000
incentive
share units

 

5,168
deferred
share units

 


 

23,750

 

 

2000

 

448,333

 

75,000

 

0

 

50,000
incentive
share units

 

5,983
deferred
share units

 


 

22,417



P.A. Smith
Controller and senior vice-president, finance and administration

 

2002

 

331,667

 

94,500

 

U.S. 100,390

 

25,000
stock
options

 

12,500
restricted
stock units
0
deferred share units

 


 

19,900

 

 

2001

 

291,666

 

110,000

 

U.S. 30,908

 

25,000
incentive
share units

 

0
deferred
share units

 


 

14,583

 

 

2000

 

272,000

 

125,000

 

U.S. 3,050

 

20,000
incentive
share units

 

0
deferred
share units

 


 

13,600



K.C. Williams (2)
Senior vice-president, resources division

 

2002

 

U.S. 412,500

 

U.S. 158,000

 

U.S. 363,932

 


 


 


 

U.S. 26,750

 

 

2001

 

U.S. 382,750

 

U.S. 197,500

 

U.S. 144,175

 


 


 


 

U.S. 24,665

 

 

2000

 

U.S. 357,000

 

U.S. 197,500

 

U.S. 32,372

 


 


 


 

U.S. 21,845



J.F. Kyle
Vice-president and treasurer

 

2002

 

345,000

 

110,000

 

13,077

 

29,000
stock
options

 

10,600
restricted
stock units
0
deferred share units

 


 

20,700

 

 

2001

 

325,000

 

150,000

 

15,107

 

29,000
incentive
share units

 

0
deferred
share units

 


 

16,250

 

 

2000

 

305,000

 

150,000

 

20,430

 

29,000
incentive
share units

 

0
deferred
share units

 


 

15,250


34


(1)
R.B. Peterson retired from the Company effective May 1, 2002.

(2)
K.C. Williams is on a loan assignment from Exxon Mobil Corporation to the Company. His compensation was paid to him directly by Exxon Mobil Corporation in United States dollars, and is disclosed in United States dollars. Also, he 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 him.

(3)
Any part of bonus elected to be received as deferred share units is excluded.

(4)
Amounts under "Other Annual Compensation", except for K.C. Williams, 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 35 and 36 and interest paid in respect of deferred payments of bonuses. For T.J. Hearn and R.B. Peterson, the amounts also include partial reimbursement for certain income taxes, a leased automobile and financial counselling. For T.J. Hearn and P.A. Smith the U.S. dollar amounts are the net payments by the Company on account of U.S. income taxes while on assignment in the U.S.A. For K.C. Williams, 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 T.J. Hearn and P.A. Smith paid to the Company and K.C. Williams 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. For T.J. Hearn for 2001, the negative amount was a net payment to the Company as a result of differences in timing of the amounts paid by the Company on account of U.S. income taxes and the amounts he paid to the Company to approximate the income taxes that would have been imposed if he was resident in Canada.

(5)
For 2001 and 2000, these are the number of units granted under the Company's plan for incentive share units described on page 35. In 2002, the Company granted instead stock options which are described on page 36.

(6)
These include the number of units granted under the Company's plan for deferred share units for selected executives described on pages 35 and 36. The values and number of these units, as at the end of 2002, were nil for T.J. Hearn, $1,730,093 for 38,567 units for R.B. Peterson, $884,478 for 19,716 units for B.J. Fischer, and nil for P.A. Smith and J.F. Kyle. These amounts include no deferred share units elected to be received in lieu of bonus for 2002 and 2001 and 12,951 share units based on $502,500 of bonus elected to be received as deferred share units for 2000 for R.B. Peterson and no deferred share units elected to be received in lieu of bonus for 2002, 4,880 share units based on $202,500 of bonus elected to be received as deferred share units for 2001 and 5,799 share units based on $225,000 of bonus for 2000 for B.J. Fischer.

(7)
These also include restricted stock units granted under the Company's plan for restricted stock units for selected employees and nonemployee directors described on page 36. The values of these units, as at the end of 2002, which units were all granted at the end of 2002, were $2,243,000 for T.J. Hearn, $973,462 for B.J. Fischer, $560,750 for P.A. Smith and $475,516 for J.F. Kyle.

(8)
K.C. Williams participates in Exxon Mobil Corporation's restricted stock plan which is similar to the Company's restricted stock unit plan. In 2002, K.C. Williams was granted 23,400 units under that plan whose value at the end of 2002 was U.S. $817,596.

(9)
Amounts under "All Other Compensation", except for K.C. Williams, 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, the Company matched employee contributions up to five percent (six percent after 2001) 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, the amounts are Exxon Mobil Corporation's contributions to its employee savings plan. For R.B. Peterson the amount also includes $204,745 in vacation allowance for vacation earned but not taken.

Long-term incentive compensation

        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 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, if exercised within the periods of eligibility. 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. The periods of eligibility for the exercise of the units are as follows: no units may be exercised before one year after the grant date; up to 50 percent of the units may be exercised on or after one year following the grant date; an additional 25 percent of the units may be exercised on or after two years following the grant date; and the remaining 25 percent of the units may be exercised on or after three years following the grant date.

        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

35


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 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.

        Under the new stock option plan, adopted by the Company in April 2002, a total of 3,210,200 options were granted on April 30, 2002 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. Shares authorized for granting under the incentive stock option plan were 20 million at December 31, 2002.

        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. A total of 791,890 units were granted on December 31, 2002. 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.

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

        The following table provides information on earnings bonus units granted in 2002 to the named senior executives.

 
   
   
  Estimated Future Payouts Under Non-Securities-Price Based Plans
 
   
  Performance
or Other
Period Until
Maturation or
Payout (1)

 
  Securities
Units or
Other Rights
(#)

Name
  Threshold
($)

  Target
($) (2)

  Maximum
($) (2)


T.J. Hearn   146,000   Nov. 20, 2007   0   3.00   3.00
R.B. Peterson          
B.J. Fischer   72,000   Nov. 20, 2007   0   3.00   3.00
P.A. Smith   31,500   Nov. 20, 2007   0   3.00   3.00
K.C. Williams (3)          
J.F. Kyle   37,000   Nov. 20, 2007   0   3.00   3.00
(1)
Payment will be made earlier when the cumulative net earnings 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 2002.

(3)
K.C. Williams participates in Exxon Mobil Corporation's earnings bonus unit plan which is similar to the Company's earnings bonus unit plan. In 2002, K.C. Williams was granted 52,760 units under that plan for which the maximum settlement value payable per earnings bonus unit is U.S. $3.00.

36


Option/SAR grants during the most recently completed financial year

        The following table provides information on stock options granted in 2002 to the named senior executives.

Name
  Securities
Under
Options/SARs
Granted
(#)

  % of Total
Options/SARs
Granted to
Employees in
Financial Year (1)

  Exercise
or
Base Price
($/Security)

  Market Value
of Securities
Underlying
Options/SARs
on the Date of
Grant
($/Security)

  Expiration
Date (2)


T.J. Hearn   65,000   2.0   46.50   46.50   April 30, 2012
R.B. Peterson   145,000   4.5   46.50   46.50   April 30, 2012
B.J. Fischer   50,000   1.6   46.50   46.50   April 30, 2012
P.A. Smith   25,000   0.8   46.50   46.50   April 30, 2012
K.C. Williams          
J.F. Kyle   29,000   0.9   46.50   46.50   April 30, 2012
(1)
There were 3,210,200 stock options issued to selected employees in 2002.

(2)
The stock options may expire before April 30, 2012, if employment is terminated other than by retirement, death or disability. If a recipient dies before the expiration date of the stock options, the stock options may be exercised by the recipient's estate.

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 2002 and the aggregate holdings at the end of 2002 of incentive share units (referred to in the table as "SARs") by the named senior executives.

 
   
   
  Unexercised Options/SARs at Financial Year-End (#)
  Value of Unexercised in-the-Money Options/SARs at Financial Year-End
($)

 
  Securities
Acquired
on Exercise
(#)

  Aggregate
Value
Realized
($)

 
Name
  Exercisable
  Unexercisable (2)
  Exercisable
  Unexercisable (2)

T.J. Hearn     583,125   32,500   102,500   272,950   321,000
R.B. Peterson     0   267,250   253,750   3,392,960   930,900
B.J. Fischer     0   118,500   87,500   1,640,560   321,000
P.A. Smith     378,768   61,500   42,500   1,522,430   143,050
K.C. Williams (1)            
J.F. Kyle     496,275   74,250   50,750   1,402,320   186,180
(1)
At the end of 2002, K.C. Williams held options to acquire 501,508 Exxon Mobil Corporation shares of which all options were exercisable. The values of K.C. Williams's exercisable options were U.S. $3,252,557 at the end of 2002. In 2002, K.C. Williams exercised 6,000 options and realized an aggregate value of U.S. $118,423.

(2)
Unexercisable units are units for which the conditions for exercise have not been met.

37


Payments to employees who retire

        Pension plan table

 
  Estimated undiscounted payments
on retirement at the age of 65 after years of service indicated below ($)

Remuneration for
determining payments
on retirement
($)

  20 Years
  25 Years
  30 Years
  35 Years
  40 Years
  45 Years

300,000   96,000   120,000   144,000   168,000   192,000   216,000
400,000   128,000   160,000   192,000   224,000   256,000   288,000
500,000   160,000   200,000   240,000   280,000   320,000   360,000
600,000   192,000   240,000   288,000   336,000   384,000   432,000
700,000   224,000   280,000   336,000   392,000   448,000   504,000
800,000   256,000   320,000   384,000   448,000   512,000   576,000
900,000   288,000   360,000   432,000   504,000   576,000   648,000
1,000,000   320,000   400,000   480,000   560,000   640,000   720,000
1,100,000   352,000   440,000   528,000   616,000   704,000   792,000
1,200,000   384,000   480,000   576,000   672,000   768,000   864,000
1,300,000   416,000   520,000   624,000   728,000   832,000   936,000
1,400,000   448,000   560,000   672,000   784,000   896,000   1,008,000
1,500,000   480,000   600,000   720,000   840,000   960,000   1,080,000
1,600,000   512,000   640,000   768,000   896,000   1,024,000   1,152,000
1,700,000   544,000   680,000   816,000   952,000   1,088,000   1,224,000
1,800,000   576,000   720,000   864,000   1,008,000   1,152,000   1,296,000
1,900,000   608,000   760,000   912,000   1,064,000   1,216,000   1,368,000
2,000,000   640,000   800,000   960,000   1,120,000   1,280,000   1,440,000
2,100,000   672,000   840,000   1,008,000   1,176,000   1,344,000   1,512,000
2,200,000   704,000   880,000   1,056,000   1,232,000   1,408,000   1,584,000
2,300,000   736,000   920,000   1,104,000   1,288,000   1,472,000   1,656,000

        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 to which the senior executives subscribe, except for K.C. Williams, 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 selected executives. The pension plan table on this page shows estimated undiscounted annual payments, consisting of pension and supplemental retirement income, payable on retirement to 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 34 and 35, except for R.B. Peterson, 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 36 is included in the employee's "final three year average earnings" for the year of grant of such units. R.B. Peterson's remuneration used to determine payment on retirement on May 1, 2002 was $1,972,389. As of February 19, 2003, the number of completed years of service used to determine payments on retirement were 36 for T.J. Hearn, 34 for B.J. Fischer, 22 for P.A. Smith and 26 for J.F. Kyle. R.B. Peterson had 42 years of service on retirement.

        K.C. Williams is not a member of the Company's pension plan but is a member of Exxon Mobil Corporation's pension plan. Under that plan, K.C. Williams has 30 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 34, and 35, 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.

38


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 and for reviewing the executive development system, including specific succession plans for senior management positions. It also reviews corporate policy on compensation. During most of 2002, the membership of the executive resources committee was as follows:

P. Des Marais II — Chair
R. Phillips — Vice-chair
T.J. Hearn
J.F. Shepard
S.D. Whittaker
V.L. Young

        As of January 23, 2003, T.J. Hearn was no longer a member of the executive resources committee. Instead he will attend meetings at the request of the committee and bring forward recommendations on compensation or succession planning.

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 four and one-half percent in 2001 and 2002 and by three percent in 2003. 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 below the median of peer salaries for his level of responsibility, experience, and personal contribution. This reflects his new responsibilities but is below 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 100 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 36.

        In 2002, the executive resources committee reduced the bonus awards including the grant of earnings bonus units to reflect the Company's 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 almost exclusively on the Company's financial performance and on the committee's assessment of T.J. Hearn's effectiveness in leading the organization toward improved financial performance. The continuing progress being made in focussing the organization on advancing key strategic interests, productivity, cost effectiveness and asset management has been a primary consideration in awarding cash bonuses to the chief executive officer. T.J. Hearn's bonus including the grant of earnings bonus units was increased in 2002 to reflect his new responsibilities, effectiveness in the position, and comparisons to other leading Canadian employers.

39


    Long-term incentive compensation

        Each year, the executive resources committee has approved long-term incentive awards for selected executives and other 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. Following approval at the 2002 annual general meeting of shareholders, the Company adopted an incentive stock option plan for this purpose. A total of 766 employees, including executives, were granted incentive stock options in 2002.

        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 2002, no executives elected to receive deferred share units and 75 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 690 employees, including executives, were granted restricted stock units in 2002.

        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 19, 2003, 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 263,014,882 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 19, 2003, Robert B. Peterson was the beneficial owner of 25,606 common shares of the Company and held options to acquire 145,000 common shares of the Company and John F. Kyle was the owner of 3,263 common shares of the Company and held options to acquire 29,000 common shares of the Company.

        The directors and the senior executives of the Company consist of 10 persons, who, as a group, own beneficially 86,265 common shares of the Company, being approximately 0.02 percent of the total number of outstanding shares of the Company, and 82,521shares 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 314,000 common shares of the Company as of February 19, 2003.

40


Equity Compensation Plan Information as of December 31, 2002

Plan category
  Number of securities to
be issued upon exercise
of outstanding options,
warrants and rights
(a)

  Weighted-average
exercise price of
outstanding options,
warrants and rights
(b)

  Number of securities
remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
(c)


Equity compensation plans approved by security holders (1)   3,210,200   $46.50   16,789,800

Equity compensation plans not approved by security holders   nil   nil   nil

Total   3,210,200   $46.50   16,789,800

(1)
This is the stock option plan adopted by the Company in April 2002.


Item 13.    Certain Relationships and Related Transactions.

        On June 21, 2001, the Company implemented another 12-month "normal course" share-purchase program under which it purchased 19,400,280 of its outstanding shares between June 21, 2001, and June 20, 2002. On June 21, 2002, another 12-month "normal course" program was implemented under which the Company may purchase up to 18,943,154 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 2002, such purchases cost $13 million, of which $9 million was received by ExxonMobil.

        The amounts of purchases and sales by the Company and its subsidiaries for other transactions in 2002 with Exxon Mobil Corporation and affiliates of Exxon Mobil Corporation were $2,191 million and $1,036 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 joint venture operations in Canada and the Company entering into an agreement with ExxonMobil Canada Ltd., effective November 15, 2000, to share common business and operational support services that allow the companies to consolidate duplicate work and systems.


PART IV

Item 14.    Controls and Procedures.

    (a)
    Evaluation of disclosure controls and procedures

      As indicated in the certification on pages 46 and 47 of this report, the Company's principal executive officer and principal financial officer have evaluated the Company's disclosure controls and procedures as of a date within 90 days prior to the filing of this report. 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.

    (b)
    Changes in internal controls

      There have not been significant changes in the Company's internal controls or in other factors that could significantly affect those controls subsequent to the date of the evaluation.

41



Item 15.    Exhibits, Financial Statement Schedules, and Reports on Form 8-K.

        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 B to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1979 (File No. 2-9259)).

(4)

 

Term Loan Agreement, dated as of July 13, 1989, relating to the borrowing of $2 billion (U.S.) (Incorporated herein by reference to Exhibit (4) of the Company's Annual Report on Form 10-K for the year ended December 31, 1989 (File No. 0-12014)). The Company's other long-term debt authorized under any other 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)).

42


            (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)).
            (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

43


                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); 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); and units granted in 1993 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, 1993 (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)).
            (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)   Earnings Bonus Unit Plan and Earnings Bonus Units granted in 2002. Units granted in 2001 are incorporated herein by reference to Exhibit (10)(iii)(5) of the Company's Annual Report on Form 10-K for the year ended December 31, 2000 (File No. 0-12014).
            (6)   Incentive Stock Option Plan and Incentive Stock Option 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.
(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, 2002.
(23)   (ii)   (A)   Consent of PricewaterhouseCoopers LLP.
        (B)   Consent of Chief Engineering Officer.

        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.

        Except for a report on Form 8-K dated November 6, 2002, the Company did not file any other reports on Form 8-K during the fourth quarter of 2002. By the report on Form 8-K dated November 6, 2002, the Company submitted to the Securities and Exchange Commission written certification by each of the chief executive officer and the chief financial officer of the Company for purposes of 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, of the Company's report on Form 10-Q for the quarter ended September 30, 2002.

44



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 26, 2003 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 26, 2003 by the following persons on behalf of the registrant and in the capacities indicated.

Signature
  Title

 

 

 
/s/  T.J. Hearn      
(Timothy J. Hearn)
  Chairman of the Board, President,
Chief Executive Officer and Director
(Principal Executive Officer)

/s/  Paul A. Smith      

(Paul A. Smith)

 

Controller and Senior Vice-President,
Finance and Administration and Director
(Principal Accounting Officer and Principal Financial Officer)

/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 Whittaker      

 

Director

(Sheelagh D. Whittaker)
   

/s/  K.C. Williams      

 

Director

(K.C. Williams)
   

/s/  Victor L. Young      

 

Director

(Victor L. Young)
   

45


Certifications

I, Timothy J. Hearn, certify that:

1.
I have reviewed this annual report on Form 10-K of Imperial Oil Limited;

2.
Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3.
Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4.
The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

a)
designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

b)
evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and

c)
presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5.
The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

a)
all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and

b)
any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

6.
The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: March 26, 2003

/s/  T.J. Hearn      

Timothy J. Hearn
Chairman of the Board, President and
Chief Executive Officer
(Principal Executive Officer)

46


Certifications

I, Paul A. Smith, certify that:

1.
I have reviewed this annual report on Form 10-K of Imperial Oil Limited;

2.
Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3.
Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this annual report;

4.
The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

a)
designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

b)
evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and

c)
presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5.
The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

a)
all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and

b)
any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and

6.
The registrant's other certifying officers and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: March 26, 2003

/s/  Paul A. Smith      

Paul A. Smith
Controller and Senior Vice-President,
Finance and Administration
(Principal Financial Officer)

47



INDEX TO FINANCIAL STATEMENTS

        The following are incorporated in this report from the Company's Annual Report to Shareholders for the year ended December 31, 2002:

 
  Pages in this Report
Auditors' report   F-3
Financial statements:    
  Consolidated statement of earnings for the years 1998, 1999, 2000, 2001 and 2002   F-4
  Consolidated statement of cash flows for the years 1998, 1999, 2000, 2001 and 2002   F-5
  Consolidated balance sheet as at December 31,1998, 1999, 2000, 2001 and 2002   F-6
  Summary of significant accounting policies   F-7–F-9
  Notes to the consolidated financial statements   F-10–F-17
Glossary of financial terms   F-18

F-1



REPORT OF INDEPENDENT ACCOUNTANTS

        Our audits of the consolidated financial statements referred to in our report dated February 19, 2003 on page F-3 also included audits of the information under the caption "Presentation of Financial Statements" in Item 6 of this Form 10-K, and were conducted in accordance with auditing standards generally accepted in the United States of America. In our opinion, the information presented under the caption "Presentation of Financial Statements" in Item 6 is presented fairly, in all material respects, when read in conjunction with the related consolidated financial statements.

/s/  PricewaterhouseCoopers LLP     
PricewaterhouseCoopers LLP
Chartered Accountants
Toronto, Ontario
February 19, 2003

F-2



AUDITORS' REPORT

To the shareholders of Imperial Oil Limited

        We have audited the consolidated statements of earnings and of cash flows of Imperial Oil Limited for each of the three years in the period ended December 31, 2002, and the consolidated balance sheets as at December 31, 2002, and 2001. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

        We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.

        In our opinion, these consolidated financial statements present fairly, in all material respects, the results of operations and cash flows of the Company for each of the three years in the period ended December 31, 2002, and its financial position as at December 31, 2002, and 2001, in accordance with Canadian generally accepted accounting principles.

/s/  PricewaterhouseCoopers LLP     
Chartered Accountants
Toronto, Ontario
February 19, 2003

F-3



CONSOLIDATED STATEMENT OF EARNINGS (a)

millions of dollars
   
   
   
   
   
For the years ended December 31
  2002
  2001
  2000
  1999
  1998

 
Revenues                    
Operating revenues   16,890   17,153   17,829   12,763   10,949
Investment and other income (note 3)   152   100   222   90   137
   
Total revenues   17,042   17,253   18,051   12,853   11,086
   
Expenses                    
Exploration   30   45   35   28   37
Purchases of crude oil and products   10,155   10,134   10,772   7,091   5,663
Operating, selling and general   3,110   3,135   2,846   2,776   2,722
Federal excise tax   1,231   1,180   1,194   1,188   1,190
Depreciation and depletion   703   716   724   734   704
Financing costs (note 13)   32   152   163   38   250
   
Total expenses   15,261   15,362   15,734   11,855   10,566
   
Earnings before income taxes   1,781   1,891   2,317   998   520
Income taxes (note 5)   571   652   919   377   76
   
Net earnings   1,210   1,239   1,398   621   444
   
Per-share information (dollars)                    
Net earnings — basic (note 11)   3.19   3.15   3.35   1.44   1.01
Net earnings — diluted (note 11)   3.19   3.15   3.35   1.44   1.01
Dividends   0.84   0.83   0.78   0.75   0.74
   

    (a)
    Business segments are reported in note 1.

        The information on pages F-7 through F-17 is part of these consolidated financial statements. Certain figures for prior years have been reclassified in the financial statements to conform with the current year's presentation. The effects of new accounting standards on the consolidated statement of earnings and balance sheet are described in note 2.

F-4



CONSOLIDATED STATEMENT OF CASH FLOWS

millions of dollars
   
   
   
   
   
 
inflow (outflow)
   
   
   
   
   
 
For the years ended December 31
  2002
  2001
  2000
  1999
  1998
 

 
 
Operating activities                      
Net earnings   1,210   1,239   1,398   621   444  
Depreciation and depletion   703   716   724   734   704  
(Gain)/loss on asset sales, after tax (note 3)   (4 ) (7 ) (96 ) (17 ) (47 )
Future income taxes and other   (151 ) 43   (182 ) (329 ) 28  
   
 
Cash flow from earnings (a)   1,758   1,991   1,844   1,009   1,129  
Accounts receivable   (356 ) 504   (358 ) (124 ) 76  
Inventories and prepaids   51   (11 ) (6 ) (16 ) 8  
Income taxes payable   (225 ) (408 ) 503   225   (178 )
Accounts payable and other   448   (72 ) 106   376   (256 )
   
 
Change in operating assets and liabilities   (82 ) 13   245   461   (350 )
   
 
Cash from operating activities   1,676   2,004   2,089   1,470   779  
   
 
Investing activities                      
Additions to property, plant and equipment   (1,552 ) (1,070 ) (644 ) (625 ) (575 )
Proceeds from asset sales (note 3)   61   46   274   88   213  
Proceeds from marketable securities       116   59   79  
Additions to marketable securities       (58 ) (88 ) (87 )
   
 
Cash from (used in) investing activities   (1,491 ) (1,024 ) (312 ) (566 ) (370 )
   
 
Cash flow before financing activities   185   980   1,777   904   409  
Financing activities                      
Short-term debt — net   (388 ) 385   75      
Long-term debt issued   500          
Repayment of long-term debt   (71 ) (379 ) (68 ) (379 )  
Common shares purchased (note 11)   (13 ) (812 ) (1,208 )   (434 )
Dividends paid   (319 ) (322 ) (331 ) (319 ) (326 )
   
 
Cash from (used in) financing activities   (291 ) (1,128 ) (1,532 ) (698 ) (760 )
   
 
Increase (decrease) in cash   (106 ) (148 ) 245   206   (351 )
Cash at beginning of year   872   1,020   775   569   920  
   
 
Cash at end of year (b)   766   872   1,020   775   569  
   
 

    (a)
    Includes dividends received from equity investments of $18 million (2001 — $10 million; 2000 — $14 million).

    (b)
    Cash is composed of cash in bank and cash equivalents at cost.

        The information on pages F-7 through F-17 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-5



CONSOLIDATED BALANCE SHEET

millions of dollars
   
   
   
   
   
 
At December 31
  2002
  2001
  2000
  1999
  1998
 

 
 
Assets                      
  Current assets                      
    Cash   766   872   1,020   775   569  
    Marketable securities         59   30  
    Accounts receivable (note 12)   1,348   992   1,496   1,138   1,014  
    Inventories of crude oil and products (note 12)   433   478   421   451   438  
    Materials, supplies and prepaid expenses   110   116   162   125   122  
    Future income tax assets (note 5)   323   227   377   285   128  
   
 
  Total current assets   2,980   2,685   3,476   2,833   2,301  
  Investments and other long-term assets   134   139   127   172   167  
  Property, plant and equipment (note 1)   8,526   7,709   7,369   7,525   7,667  
  Goodwill (notes 1 and 2)   204   204   232   260   288  
  Other intangible assets (note 1)   24   24   18   14   10  
   
 
Total assets (note 1)   11,868   10,761   11,222   10,804   10,433  
   
 
Liabilities                      
  Current liabilities                      
    Short-term debt   72   460   75      
    Accounts payable and accrued liabilities (note 14)   2,114   1,791   1,866   1,731   1,417  
    Income taxes payable   557   774   1,182   666   441  
    Current portion of long-term debt       300     215  
   
 
  Total current liabilities   2,743   3,025   3,423   2,397   2,073  
  Long-term debt (note 4)   1,466   1,029   1,037   1,352   1,583  
  Other long-term obligations (note 7)   1,187   1,063   1,044   1,091   1,042  
  Future income tax liabilities (note 5)   1,260   1,311   1,488   1,599   1,667  
  Commitments and contingent liabilities (note 10)                      
   
 
Total liabilities   6,656   6,428   6,992   6,439   6,365  
   
 
Shareholders' equity                      
  Common shares at stated value (note 11)   1,939   1,941   2,039   2,209   2,209  
  Net earnings retained and used in the business                      
    At beginning of year   2,392   2,191   2,156   1,859   2,088  
    Net earnings for the year   1,210   1,239   1,398   621   444  
    Share purchases (note 11)   (11 ) (714 ) (1,038 )   (350 )
    Dividends   (318 ) (324 ) (325 ) (324 ) (323 )
   
 
    At end of year   3,273   2,392   2,191   2,156   1,859  
   
 
Total shareholders' equity   5,212   4,333   4,230   4,365   4,068  
   
 
Total liabilities and shareholders' equity   11,868   10,761   11,222   10,804   10,433  
   
 

        The information on pages F-7 through F-17 is part of these consolidated financial statements. Certain figures for prior years have been reclassified in the financial statements to conform with the current year's presentation. The effects of new accounting standards on the consolidated statement of earnings and balance sheet are described in note 2.

Approved by the directors

/s/  T.J. Hearn         /s/  P.A. Smith      
T.J. Hearn   P.A. Smith
Chairman, president and
chief executive officer
  Controller and senior vice-president,
finance and administration

F-6



Summary of significant accounting policies

Principles of consolidation

        The consolidated financial statements include the accounts of Imperial Oil Limited and its subsidiaries. Intercompany accounts and transactions are eliminated. Subsidiaries include those companies in which Imperial has both an equity interest and the continuing ability to unilaterally determine strategic operating, investing and financing policies. Significant subsidiaries included in the consolidated financial statements include Imperial Oil Resources Limited, Imperial Oil Resources N.W.T. Limited, Imperial Oil Resources Ventures Limited and McColl-Frontenac Petroleum Inc. All of the above companies are wholly owned. A significant portion of the Company's activities in natural resources is conducted jointly with other companies. The accounts reflect the Company's proportionate interest in such activities, including its 25-percent interest in the Syncrude joint venture and its nine-percent interest in the Sable Offshore Energy Project.

Segment reporting

        The Company operates its business in Canada in the following segments:

        Natural resources includes the exploration for and production of crude oil and natural gas.

        Petroleum products comprises the refining of crude oil into petroleum products and the distribution and marketing of these products.

        Chemicals includes the manufacturing and marketing of various hydrocarbon-based chemicals and chemical products.

        Corporate and other includes assets and liabilities that do not specifically relate to business segments — primarily cash, marketable securities and long-term debt. Net earnings in this category primarily include debt-related charges and interest income.

        Segment accounting policies are the same as those described in this summary of significant accounting policies. Natural resources, petroleum products and chemicals operating expenses include amounts allocated from the "corporate and other" segment. The allocation is based on a combination of fee for service, proportional segment operating expenses and a three-year average of capital expenditures. Transfers of assets between segments are recorded at book amounts. Items included in capital employed that are not identifiable by segment are allocated according to their nature.

Accounts receivable

        Accounts receivable arise mainly from customer purchases of the Company's products. Interest is accrued on overdue accounts (generally those over 30 days) and is reported in "investment and other income" in the consolidated statement of earnings. Interest accrual will be suspended if collection becomes doubtful. An allowance for doubtful accounts is established based upon an assessment of the collectability of individual larger account balances and upon historical experience, economic and judgmental factors collectively for groups of smaller homogeneous accounts. Accounts are written off when judged to be uncollectable.

Inventories

        Inventories are recorded at the lower of cost or net realizable value. The cost of crude oil and products is determined primarily using the last-in, first-out (LIFO) method. LIFO was selected over the alternative first-in, first-out and average cost methods because it provides a better matching of current costs with the revenues generated in the period.

        Costs include purchase costs and other applicable operating expenses. Selling and general administrative expenses are excluded.

Investments

        The principal investments in companies other than subsidiaries are accounted for using the equity method. They are recorded at the original cost of the investment plus Imperial's share of earnings since the investment was made, less dividends received. Imperial's share of the after-tax earnings of these companies is included in "investment and other income" in the consolidated statement of earnings. Other investments are recorded at cost. Dividends from these other investments are recorded as 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.

F-7


Property, plant and equipment

        Property, plant and equipment are recorded at cost.

        The Company follows the successful-efforts method of accounting for its exploration and development activities. Under this method, costs of exploration acreage are capitalized and amortized over the period of exploration or until a discovery is made. Costs of exploration wells are capitalized until their success can be determined. If the well is successful, the costs remain capitalized; otherwise they are expensed. Capitalized exploration costs are reevaluated annually. All other exploration costs are expensed as incurred. Development costs, including the cost of natural gas and natural gas liquids used as injectants in enhanced (tertiary) oil-recovery projects, are capitalized.

        Imperial selected the successful-efforts method over the alternative full-cost method of accounting because it provides a more timely accounting of the success or failure of exploration and production activities.

        Oil, gas and other 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. The Company estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts.

        Maintenance and repair costs are expensed as incurred. Improvements that increase or prolong the service life or capacity of an asset are capitalized.

        Investment tax credits and other similar grants are treated as a reduction of the capitalized cost of the asset to which they apply.

        Depreciation and depletion (the allocation of the cost of assets to expense over the period of their useful lives) are calculated using the unit-of-production method for producing properties. 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.

        Gains or losses on assets sold are included in "investment and other income" in the consolidated statement of earnings.

Goodwill and other intangible assets

        Goodwill and intangible assets with indefinite lives are not subject to amortization. These assets are tested for impairment annually or more frequently if events or circumstances indicate the assets might be impaired. Impairment losses are recognized in current period earnings. The evaluation for impairment of goodwill is based on a comparison of the carrying values of goodwill and associated operating assets with the estimated present value of net cash flows from those operating assets.

        Intangible assets with determinable useful lives are amortized over a maximum of 10 years. The amortization is included in "depreciation and depletion" in the consolidated statement of earnings.

Site-restoration costs

        Provision for site-restoration costs (net of any expected recoveries) is made if they can be reasonably determined. This provision is based on engineering estimates of costs, taking into account the anticipated method and extent of remediation consistent with legal requirements, industry practices, current technology and the possible use of the site. For natural resources assets, accruals are made over the useful life of the asset using the unit-of-production method. For other assets, a provision is made at the time management approves the sale or closure of a facility.

Foreign currency translation

        Monetary assets and liabilities receivable or payable in foreign currencies have been translated at the rates of exchange prevailing on December 31. Any exchange gains or losses are recognized in earnings.

Financial instruments

        Financial instruments are initially recorded at historical cost. If subsequent circumstances indicate that a decline in the fair value of a financial asset is other than temporary, the financial asset is written down to its fair value. Unless otherwise indicated, the fair values of financial instruments approximate their recorded amounts.

        The fair values of cash, marketable securities, accounts receivable and current liabilities approximate recorded amounts because of the short period to receipt or payment of cash. The fair value of the Company's long-term debt is estimated based on quoted market prices for the same or similar issues or on the current rates offered to the Company for debt of the same duration to maturity. The fair values of other financial instruments held by the Company are estimated primarily by discounting future cash flows, using current rates for similar financial instruments under similar credit risk and maturity conditions.

F-8


        The Company does not use financing structures for the purpose of altering accounting outcomes or removing debt from the balance sheet. The Company's use of and method of accounting for derivative financial instruments are described in note 8 to the consolidated financial statements.

Revenues

        Revenues associated with sales of crude oil, natural gas, petroleum and chemical products and other items are recorded when title passes to the customer. The Company does not enter into ongoing arrangements whereby it is required to repurchase its products, nor does the Company provide the customer with a right of return.

        Revenues include amounts billed to customers for shipping and handling. Shipping and handling costs incurred up to the point of final storage prior to delivery to a customer are included in "purchases of crude oil and products" in the consolidated statement of earnings. Delivery costs from final storage to customers are recorded as a marketing expense in operating, selling and general expenses.

Consumer taxes

        Taxes levied on the consumer and collected by the Company are excluded from the consolidated statement of earnings. These are primarily provincial taxes on motor fuels and the federal goods and services tax.

Interest costs

        Interest costs are expensed as incurred and included in "financing costs" in the consolidated statement of earnings.

Accounting principles

        The consolidated financial statements have been prepared in accordance with generally accepted accounting principles (GAAP) in Canada. Form 10-K, filed with the United States Securities and Exchange Commission, includes a description of the differences between GAAP in Canada and in the United States as they apply to the Company.

        The Canadian Institute of Chartered Accountants (CICA) is expected to issue a standard on accounting for asset retirement obligations in 2003. The Company plans to adopt the new CICA standard early if permitted.

F-9



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Business segments

 
  Natural resources (a)

  Petroleum products

  Chemicals

 
millions of dollars
  2002
  2001
  2000
  2002
  2001
  2000
  2002
  2001
  2000
 

 
Revenues                                      
External sales (c)   2,573   3,144   3,124   13,362   13,079   13,760   955   930   945  
Intersegment sales   2,217   2,166   2,638   1,038   1,300   1 332   209   245   228  
Investment and other income (note 3)   104   11   138   34   26   28        

 
Total revenues   4,894   5,321   5,900   14,434   14,405   15,120   1,164   1,175   1,173  

 
Expenses                                      
Exploration   30   45   35              
Purchases of crude oil and products   1,814   2,444   2,586   10,974   10,505   11,511   830   895   871  
Operating, selling and general (d)   1,034   1,007   921   1,837   1,889   1,710   230   221   184  
Federal excise tax         1,231   1,180   1,194        
Depreciation and depletion (e) (f)   477   455   467   203   238   235   23   23   22  
Financing costs (note 13)   1   2   1   1   2   3        

 
Total expenses   3,356   3,953   4,010   14,246   13,814   14,653   1,083   1,139   1,077  

 
Earnings before income taxes   1,538   1,368   1,890   188   591   467   81   36   96  
Income taxes (note 5)                                      
Current   517   556   815   172   125   281   40   11   44  
Future   (21 ) (129 ) (90 ) (111 ) 113   (127 ) (11 ) 2   (7 )

 
Total income tax expense   496   427   725   61   238   154   29   13   37  

 
Net earnings   1,042   941   1,165   127   353   313   52   23   59  

 
Cash flow from earnings   1,503   1,262   1,422   216   700   417   63   49   74  

 
Capital and exploration expenditures (g)   986   746   434   589   339   232   25   30   13  

 
Property, plant and equipment                                      
Cost   11,612   10,733   10,067   5,854   5,469   5,287   579   554   525  
Accumulated depreciation and depletion   6,269   5,839   5,412   2,867   2,842   2,748   383   366   350  

 
Net property, plant and equipment (h)   5,343   4,894   4,655   2,987   2,627   2,539   196   188   175  

 
Total assets (f)   5,988   5,365   5,288   5,060   4,348   4,812   406   373   379  

 
Total capital employed   3,321   2,590   2,168   2,435   2,119   2,261   178   195   140  

 

Business segments

 
  Corporate and other

  Consolidated (b)

 
millions of dollars
  2002
  2001
  2000
  2002
  2001
  2000
 

 
Revenues                          
External sales (c)         16,890   17,153   17,829  
Intersegment sales              
Investment and other income (note 3)   14   63   56   152   100   222  

 
Total revenues   14   63   56   17,042   17,253   18,051  

 
Expenses                          
Exploration         30   45   35  
Purchases of crude oil and products         10,155   10,134   10,772  
Operating, selling and general (d)   10   19   33   3,110   3,135   2,846  
Federal excise tax         1,231   1,180   1,194  
Depreciation and depletion (e) (f)         703   716   724  
Financing costs (note 13)   30   148   159   32   152   163  

 
Total expenses   40   167   192   15,261   15,362   15,734  

 
Earnings before income taxes   (26 ) (104 ) (136 ) 1,781   1,891   2,317  
Income taxes (note 5)                          
Current   (11 ) (13 ) (18 ) 718   679   1,122  
Future   (4 ) (13 ) 21   (147 ) (27 ) (203 )

 
Total income tax expense   (15 ) (26 ) 3   571   652   919  

 
Net earnings   (11 ) (78 ) (139 ) 1,210   1,239   1,398  

 
Cash flow from earnings   (24 ) (20 ) (69 ) 1,758   1,991   1,844  

 
Capital and exploration expenditures (g)         1,600   1,115   679  

 
Property, plant and equipment                          
Cost         18,045   16,756   15,879  
Accumulated depreciation and depletion         9,519   9,047   8,510  

 
Net property, plant and equipment (h)         8,526   7,709   7,369  

 
Total assets (f)   766   873   1,022   11,868   10,761   11,222  

 
Total capital employed   816   918   1,072   6,750   5,822   5,641  

 

(continued on following page)

F-10


(a)
A significant portion of activities in the natural resources segment is conducted jointly with other companies. The segment includes the Company's proportionate share of joint-venture activities, as follows:

millions of dollars
  2002
  2001
  2000
 

 
Total revenues   2,357   2,689   2,851  
Total expenses   1,520   1,733   1,691  
Net earnings, after income taxes   557   637   716  
               
Total current assets   321   232   378  
Long-term assets   3,038   2,750   2,705  
Total current liabilities   669   919   1,023  
Other long-term obligations   268   262   247  
               
Cash flow from earnings   767   828   833  
Cash flow from operating activities   615   850   912  
Cash (used in) investing activities   (601 ) (301 ) (224 )

 
(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
  2002
  2001
  2000

Purchases of crude oil and products   3,463   3,710   4,196
Operating, selling and general expenses   1   1   2

Total intersegment sales   3,464   3,711   4,198

Intersegment receivables and payables   352   198   279

(c)
Includes export sales to the United States, as follows:

millions of dollars
  2002
  2001
  2000

Natural resources   942   1,018   1,212
Petroleum products   723   770   781
Chemicals   520   503   522

Total export sales   2,185   2,291   2,515

(d)
Consolidated operating, selling and general expenses include delivery costs from final storage to customers of $216 million (2001 — $244 million; 2000 — $238 million).

(e)
Goodwill was not amortized in 2002 (amortization expense in 2001 — $28 million; 2000 — $28 million). All goodwill has been assigned to the petroleum products segment. There have been no goodwill acquisitions, impairment losses or write-offs due to sales in the past three years.

(f)
Total assets include amortized intangible assets, consisting primarily of acquired customer lists, as follows:

millions of dollars
  2002
  2001
  2000

Cost   54   49   39
Accumulated amortization   30   25   21

Net intangible assets   24   24   18

Amortization expense   5   5   3
Customer lists acquired   5   11   6

    Customer lists disposed of or retired in 2002 were $1 million (2001 — $1 million; 2000 — $1 million). No gain or loss was recognized. The estimated annual amortization expenses for intangible assets in each of the next five years is $5 million.

(g)
Capital and exploration expenditures of the petroleum products segment include non-cash capital leases of $18 million in 2002.

(h)
Includes property, plant and equipment under construction of $1,275 million (2001 — $813 million).

F-11


2. Reporting changes

        Effective January 1, 2002, the Company implemented reporting changes to reflect the new accounting standards of the Canadian Institute of Chartered Accountants (CICA) dealing with accounting for foreign currency translation, accounting for goodwill and other intangible assets and on stock-based compensation and other stock-based payments.

Foreign currency translation

        The new CICA standard dealing with accounting for foreign currency translation eliminates the deferral and amortization of translation gains or losses. The new standard has been applied retroactively, and financial statements of prior periods have been restated. The impact of adopting the new foreign currency translation standard on the consolidated balance sheet and statement of earnings is:

        Changes in consolidated balance sheet

millions of dollars — increase/(decrease)
  2002
  2001
 

 
Long-term debt   61   121  
Future income tax liabilities   (13 ) (25 )
Retained earnings   (48 ) (96 )

 
Total liabilities and shareholders' equity      

 

        Changes in consolidated statement of earnings

millions of dollars — increase/(decrease)
  2002
  2001
  2000
 

 
Total expenses   (60 ) 6   4  
Income taxes   12   (1 ) 18  

 
Net earnings   48   (5 ) (22 )

 
Earnings per share — basic and diluted (dollars)   0.13   (0.01 ) (0.05 )

Goodwill and other intangible assets

        The new CICA standard dealing with accounting for goodwill and other intangible assets eliminates the amortization of goodwill.

        The standard does not permit retroactive application. On a pro forma basis, the impact of adopting the new goodwill accounting standard on prior period earnings is:

millions of dollars
  2002
  2001
  2000

Net earnings   1,210   1,239   1,398
Add: goodwill amortization     28   28

Adjusted net earnings   1,210   1,267   1,426

Per share — basic and diluted (dollars)            
Net earnings   3.19   3.15   3.35
Add: goodwill amortization     0.07   0.07

Net earnings   3.19   3.22   3.42

Stock-based compensation and other stock-based payments

        The Company's accounting policy for its incentive compensation programs complies with the new CICA standard. Consequently, there was no impact on the recorded expense or liability upon adoption of the new accounting standard on January 1, 2002.

3. Divestments

        Investment and other income includes gains and losses on asset sales as follows:

millions of dollars
  2002
  2001
  2000

Proceeds from sale of assets   61   46   274
Book value of assets sold (a)   56   36   135

Gain/(loss) on asset sales, before tax (b)   5   10   139

Gain/(loss) on asset sales, after tax (b)   4   7   96

    (a)
    Assets sold did not include cash.

    (b)
    Gains on asset sales in 2000 included an $81-million ($60 million after tax) gain from the sale of the Company's 50-percent interest in Federated Pipe Lines Ltd. and its wholly owned Cynthia pipeline in Alberta. The Company also realized a gain of $44 million ($25 million after tax) on the sale of its interest in the Mitsue and Pembina producing properties in Alberta.

4. Long-term debt

 
   
   
  2002
  2001

issued
  maturity date
  interest rate
  millions of dollars

Sinking-fund debentures            
1989   October 15, 2019 (2001 — $45 million (U.S.)) (a)   83/4     71
Other debentures and notes (b)            
1989   September 1, 2004 (2002 — $600 million (U.S.); 2001 — $600 million (U.S.)) (c)   Variable   946   956
2002   May 7, 2004 (a) (d)   Variable   500  

Long-term debt (at period-end exchange rates) (e)       1,446   1,027
Capital leases (f)           20   2

Total long-term debt           1,466   1,029

    (a)
    In 2002, the Company retired the remaining balance of its 83/4-percent sinking-fund debentures of $45 million (U.S.) for $71 million (Cdn) and issued $500 million (Cdn) variable-rate medium-term notes. In 2001, the Company redeemed $45 million (U.S.) of its 83/4-percent sinking-fund debentures for $71 million (Cdn) and $200 million (U.S.) of its maturing 8.3-percent debt for $308 million (Cdn).

    (b)
    Principal payments on debentures and notes of $600 million (U.S.) and $500 million (Cdn) are due in 2004. The $500-million (Cdn) medium-term notes are extendable up to May 7, 2007, after the initial maturity date, at noteholders' discretion.

    (c)
    This debt bears interest based primarily on U.S. commercial paper interest rates and may be repaid in part or in full at any time before maturity without premium. The average effective rate for 2002 was 1.9 percent (2001 — 4.2 percent).

F-12


    (d)
    These medium-term notes bear interest primarily based on the bid rates of interest for three-month Canadian dollar bankers' acceptance plus a spread of 10 basis points. The average effective rate for 2002 was 2.8 percent.

    (e)
    The estimated fair value of the long-term debt at December 31, 2002, was $1,446 million (2001 — $1,030 million).

    (f)
    These obligations primarily relate to the capital lease for marine services, which are to be provided by the lessor commencing in 2004 for a period of 10 years, extendable for an additional five years. The obligations recorded to date represent the costs incurred by the lessor for the construction of the related marine assets.

5. Income taxes

millions of dollars
  2002
  2001
  2000
 

 
Current income tax expense   718   679   1,122  
Future income tax expense (a)   (147 ) (27 ) (203 )

 
Total income tax expense (b)   571   652   919  

 
Statutory corporate tax rate (percent)   42.0   42.7   44.6  
Increase/(decrease) resulting from:              
  Non-deductible royalty payments to governments   5.4   7.9   8.1  
  Resource allowance in lieu of royalty deduction   (11.8 ) (11.4 ) (11.4 )
  Manufacturing and processing credit   (0.3 ) (1.3 ) (1.6 )
  Non-deductible depreciation and amortization     0.6   0.5  
  Enacted tax rate change   (0.9 ) (2.1 )  
  Other   (2.2 ) (2.0 ) (1.4 )

 
Effective income tax rate   32.2   34.4   38.8  

 

        Components of future income tax liabilities and assets as at December 31 are:

millions of dollars
  2002
  2001
 

 
Depreciation and amortization   1,092   1,021  
Successful drilling and land acquisitions   660   760  
Pension and benefits   (229 ) (195 )
Site restoration   (182 ) (191 )
Net tax loss carryforwards (c)   (37 ) (32 )
Other   (44 ) (52 )

 
Total future income tax liabilities   1,260   1,311  

 
LIFO inventory valuation   (271 ) (177 )
Other   (52 ) (50 )

 
Total future income tax assets   (323 ) (227 )

 
Net future income tax liabilities   937   1,084  

 
    (a)
    The future income tax expense for the year is the difference in net future income tax liabilities at the beginning and end of the year.

    (b)
    Cash outflow from income taxes, plus investment credits earned, were $935 million in 2002 (2001 — $1,086 million; 2000 — $606 million).

    (c)
    The 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.

6. 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 that require an actuarial valuation of the pension funds at least once every three years. The Company makes contributions to the plans as required by those valuations.

        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 pay levels, as well as a projection of salaries and service to retirement.

        The expense and obligations for both funded and unfunded benefits are determined in accordance with generally accepted Canadian accounting principles and actuarial procedures. The process for determining retirement-income expense and related obligations includes making certain long-term assumptions regarding the discount rate, rate of return on plan assets and rate of pay increases. The discount rate is based on the year-end rate of interest on high-quality bonds.

        The total obligation for employee retirement benefits exceeded the fair value of plan assets at December 31, 2002, by $1,780 million (2001 — $1,181 million). 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:

 
  Pension benefits

  Other post-retirement benefits

millions of dollars
  2002
  2001
  2000
  2002
  2001
  2000

Components of net benefit expense:                        
Current service cost   64   57   45   4   4   4
Interest cost   222   215   201   21   21   22
Expected return on plan assets   (191 ) (257 ) (259 )    
Amortization of prior service cost   25   23   25      
Recognized actuarial loss/(gain)   34     (20 ) 1     1

Net expense (a) (e)   154   38   (8 ) 26   25   27

F-13


 
  Pension benefits

  Other
post-
retirement
benefits

 
millions of dollars
  2002
  2001
  2002
  2001
 

 
Change in benefit obligation:                  
Benefit obligation at January 1   3,248   3,065   323   302  
Current service cost   64   57   4   4  
Interest cost   222   215   21   21  
Amendments   27   30      
Actuarial loss/(gain)   196   104   25   14  
Benefits paid   (227 ) (223 ) (19 ) (18 )

 
Benefit obligation at December 31 (e)   3,530   3,248   354   323  

 
Change in plan assets:                  
Fair value of plan assets at January 1   2,390   2,674          
Actual return on plan assets   (107 ) (95 )        
Company contributions (b)   19   6          
Payments directly to participants   29   28          
Benefits paid   (227 ) (223 )        

         
Fair value of plan assets at December 31 (b)   2,104   2,390          

         
Excess (deficiency) of plan assets over benefit obligations   (1,426 ) (858 ) (354 ) (323 )
Unrecognized net actuarial (gain)/loss (c)   924   461   36   12  
Unrecognized prior service cost (c)   114   112      

 
Net liability recognized (note 7)   (388 ) (285 ) (318 ) (311 )

 

        The benefit obligation at year-end includes funded and unfunded plans, as follows:

 
  Pension benefits

  Other post-retirement benefits

millions of dollars
  2002
  2001
  2000
  2002
  2001
  2000

Funded plans   3,230   2,972   2,790      
Unfunded plans   300   276   275   354   323   302

Benefit obligation at end of year   3,530   3,248   3,065   354   323   302


Assumptions as at December 31 (percent)

 

 

 

 

 

 

 

 

 

 

 

 
  Discount rate   6.25   6.75   7.00   6.25   6.75   7.00
  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 (d)   8.25   8.25   10.00      
    (a)
    Additional expenses include contributions to defined contribution plans, primarily the employee savings plan, of $30 million in 2002 (2001 — $23 million; 2000 — $22 million).

    (b)
    Company contributions to the retirement plans are based on independent actuarial valuations and are made in accordance with government regulations. Pension fund assets are held primarily in equity, fixed-income and money-market securities.

    (c)
    Unrecorded assets/(liabilities) are amortized over the average remaining service life of employees, which for 2003 and subsequent years is 13.5 years (2002 — 13.5 years; 2001 — 13.5 years).

    (d)
    The long-term rate of return on plan assets used to determine 2000 and 2001 pension expense was assumed to be 10 percent, and the assumed long-term rate of return on plan assets used to calculate 2002 pension expense was 8.25 percent. The change in assumption increased 2002 pension expenses by $25 million after tax.

    (e)
    A one-percent change in the assumptions at which retirement liabilities could be effectively settled is as follows:

millions of dollars
  One-percent increase
  One-percent decrease
 

 
Rate of return on plan assets:          
Effect on net benefit expense   (20 ) 20  
           
Discount rate:          
Effect on net benefit expense   (30 ) 40  
Effect on benefit obligation   (415 ) 510  
           
Rate of pay increases:          
Effect on net benefit expense   25   (20 )
Effect on benefit obligation   155   (135 )

        For measurement purposes, a five-percent health-care cost trend rate was assumed for 2002 and thereafter. A one-percent change in the assumed health-care cost trend rate would have the following effects:

millions of dollars
  One-percent increase
  One-percent decrease
 

 
Effect on service and interest cost components   2   (2 )
Effect on other post-retirement benefit obligation   30   (25 )

F-14


7. Other long-term obligations

millions of dollars
  2002
  2001

Employee retirement benefits (note 6) (a)   671   560
Site restoration (b)   434   415
Other obligations   82   88

Total other long-term obligations   1,187   1,063

    (a)
    Total recorded employee retirement benefits obligations also include $35 million in current liabilities (2001 — $36 million).

    (b)
    Total site restoration also includes $71 million in current liabilities (2001 — $92 million).

8. Derivative financial instruments

        The impact of price and foreign-exchange fluctuations on purchases and sales may be mitigated by selling and buying energy derivatives (primarily futures contracts and natural gas price swaps) and foreign-exchange forward contracts. These transactions are conducted on recognized commodities exchanges or with banks of the highest credit standing and are normally settled in less than one year. Gains or losses on these contracts are recognized in earnings as a component of the related physical transaction.

        No significant energy derivative, foreign-exchange forward contracts or currency and interest-rate swaps were transacted in the past three years.

9. Incentive compensation programs

        Incentive compensation programs are designed to retain selected employees, reward them for high performance and promote individual contribution to sustained improvement in the Company's future business performance and shareholder value.

    Incentive share units, deferred share units and earnings bonus units

        All units require settlement by cash payments. For deferred share units, a charge is made to expense in the year of grant equal to the cash performance bonus payment foregone. The Company records expense for incentive share and deferred share 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 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.

        In 1998, the deferred share unit plan was made available to selected executives whereby they could elect to receive all or part of their performance bonus compensation in units. The number of units granted 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. Additional units are granted 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.

        Starting in 1999, a similar deferred share unit plan was made available to nonemployee directors in lieu of receiving all or part of their directors' fees. 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 immediately prior to the last day of the calendar quarter.

        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 exercise date, the cash value to be received for the units will be determined based on the average closing price of the Company shares immediately prior to the date of exercise.

        Starting in 2001, the earnings bonus unit plan was made available to selected employees. 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.

        A summary of the incentive share units, deferred share units and earnings bonus units is as follows:

 
 
  Granted in period
   
   
   
 
 
  Number of units outstanding at December 31
   
   
 
 
  Number of units
  To number of employees
  To number of nonemployees
  Expensed in period
(millions of dollars)

  Obligations outstanding at December 31
(millions of dollars)


Incentive share units — 2002   7,000   3     8,012,250   39   142
    — 2001   2,752,700   744     6,623,125   51   129
    — 2000   2,731,200   756     7,071,265   67   110
Deferred share units — 2002   7,479   6   7   85,523     4
    — 2001   15,222   2   5   87,897   1   4
    — 2000   29,861   4   5   72,675   2   3
Earnings bonus units — 2002   1,036,500   75     2,169,040   3   3
    — 2001   1,132,540   21     1,132,540    

Incentive stock options

        In April 2002, shareholders approved an incentive stock option plan. Under the new stock option plan, a total of 3,210,200 options were granted on April 30, 2002, 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. Shares authorized for granting under the incentive stock option plan were 20 million at December 31, 2002.

F-15


        The Company does not recognize compensation expense on the issuance of stock options because the exercise price is equal to the market value at the date of grant. If the fair-value-based method of accounting had been adopted, net income and earnings per share (on both a basic and diluted basis) of 2002 would have been reduced by $16 million or $0.04 per share. The average fair value of each option granted during 2002 was $12.70. The fair value was estimated at the grant date using an option-pricing model with the following weighted average assumptions: risk-free interest rate of 5.7 percent; expected life of five years; volatility of 25 percent and a dividend yield of 1.9 percent.

        The Company expects to purchase shares on the market to fully offset the dilutive effects from the exercise of stock options.

Restricted stock units

        In December 2002, the Company introduced a restricted stock unit plan, which will be the primary long-term incentive compensation plan in future years. Under this plan, a total of 791,890 units were issued on December 31, 2002, to 690 employees and five nonemployee directors. 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 common shares on the Toronto Stock Exchange on the exercise dates. Fifty percent of the units will be exercised on December 31, 2005, and the remainder will be exercised on December 31, 2009. Compensation expense is recorded in the consolidated statement of earnings over the period in which the units vest. The impact of this plan on expense and liability in 2002 was not material.

10. Commitments and contingent liabilities

        At December 31, 2002, the Company had commitments for non-cancellable operating leases and other long-term agreements that require the following minimum future payments:

millions of dollars
  2003
  2004
  2005
  2006
  2007
  After 2007

Operating leases (a)   64   55   45   36   32   128
Unconditional purchase obligations (b)   93   66   46   37   38   117
Firm capital commitments (c)   254   30        
Other long-term agreements (d)   214   212   192   141   47   272

    (a)
    Total rental expense incurred for operating leases in 2002 was $124 million (2001 — $122 million; 2000 — $115 million). Operating lease commitments related to joint-venture activities are not material.

    (b)
    Unconditional purchase obligations are those long-term commitments that are noncancelable or cancelable only under certain conditions. These mainly pertain to pipeline throughput agreements. Total payments under unconditional purchase obligations were $115 million in 2002 (2001 — $179 million; 2000 — $285 million).

    (c)
    Firm capital commitments related to capital projects, shown on an undiscounted basis, totalled approximately $284 million at the end of 2002 (2001 — $342 million). The largest commitment outstanding at year-end 2002 was associated with the Company's share of capital projects at Syncrude of $99 million.

    (d)
    Other long-term agreements include primarily raw material supply and transportation services agreements. Total payments under other long-term agreements were $288 million in 2002 (2001 — $264 million; 2000 — $295 million). Payments under other long-term agreements related to joint-venture activities are approximately $45 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, 2002, for a maximum of $152 million relating to guarantees of purchasing operating equipment and other assets from its rural marketing agents upon expiry of the agency agreement or the death or resignation of the agent. The Company expects that the fair value of the operating equipment and other assets so purchased would cover the maximum potential amount of future payment under the guarantees.

        The Company provides in its financial statements for site-restoration costs (see accounting policy on page F-8). Provision is not made with respect to those manufacturing, distribution and marketing facilities for which estimates of these future costs cannot be reasonably determined. These are primarily currently operated sites. These costs (net of any expected recoveries) are not expected to have a material effect on the Company's consolidated financial position.

        Various lawsuits are pending against Imperial Oil Limited and its subsidiaries. The actual liability with respect to these lawsuits is not determinable, but management believes, based on the opinion of counsel, that any liability will not materially affect the Company's consolidated financial position.

11. Common shares

number of shares
  2002
  2001
  2000

Authorized   450,000,000   450,000,000   450,000,000
Issued at December 31   376,663,095   379,159,147   398,263,375

        In 1995 through 2001, the Company purchased shares under seven 12-month normal course share purchase programs, as well as an auction tender. On June 21, 2002, another 12-month normal course program was implemented with an allowable purchase of 18.9 million shares (five percent of the total at June 19, 2002), less any shares purchased by the employee savings plan and Company pension fund.

        The results of these activities are shown below.

Year
  Purchased
shares

  Millions of
dollars


1995-1999   150,049,063   3,136
2000   33,211,858   1,208
2001   19,104,228   812
2002   296,052   13

Cumulative purchases to date   202,661,201   5,169

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

        The excess of the purchase cost over the stated value of shares purchased has been recorded as a distribution of retained earnings.

        The following table provides the calculation of basic and diluted earnings per share:

 
  2002
  2001
  2000

Net earnings (millions of dollars)   1,210   1,239   1,398
Average number of common shares outstanding, weighted monthly (thousands)   378,875   393,121   417,753
Plus: Issued on assumed exercise of stock options (thousands)      

Weighted average number of diluted common shares (thousands)   378,875   393,121   417,753

Earnings per share — basic (dollars)   3.19   3.15   3.35
Earnings per share — diluted (dollars)   3.19   3.15   3.35

F-16


12. Miscellaneous financial information

        In 2002, net earnings included an after-tax loss of $2 million (2001 — $18 million gain; 2000 — $25 million gain) attributable to the effect of changes in LIFO inventories. The replacement cost of inventories was estimated to exceed their LIFO carrying values at December 31, 2002, by $941 million (2001 — $506 million).

        Research and development costs in 2002 were $64 million (2001 — $71 million; 2000 — $55 million) before investment tax credits earned on these expenditures of $10 million (2001 — $6 million; 2000 — $6 million). The net costs are included in expenses, due to the uncertainty of future benefits.

        Accounts receivable included allowance for doubtful accounts of $13 million in 2002 (2001 — $12 million).

13. Financing costs

millions of dollars
  2002
  2001
  2000

Debt-related interest   40   77   106
Other interest   2   4   4

Total interest expense (a)   42   81   110
Foreign-exchange expense on long-term debt   (10 ) 71   53

Total financing costs   32   152   163

    (a)
    Cash interest payments in 2002 were $41 million (2001 — $99 million; 2000 — $111 million). The weighted-average interest rate on short-term debt in 2002 was 2.4 percent (2001 — 3.9 percent). The average effective interest rate on the Company's debt was 2.1 percent in 2002 (2001 — 5.1 percent).

14. Transactions with Exxon Mobil Corporation and affiliated companies (ExxonMobil)

        Revenues and expenses of the Company also include the results of transactions with ExxonMobil in the normal course of operations. These were conducted on terms as favourable as they would have been with unrelated parties and primarily consisted of the purchase and sale of crude oil, petroleum and chemical products, as well as transportation, technical and engineering services. Effective November 15, 2000, the Company entered into an agreement with ExxonMobil Canada to share common business and operational support services that allow the companies to consolidate duplicate work and systems. Transactions with ExxonMobil also include amounts paid and received in connection with the Company's participation in a number of natural resources joint-venture operations in Canada. The amounts paid or received have been reflected in the statement of earnings as shown in the following table.

        Throughout 2000, the Company purchased in the short-term money market Canadian-dollar commercial paper of an Exxon Mobil Corporation subsidiary. The notes were guaranteed by ExxonMobil. These promissory notes matured less than three months from purchase date and were replaced by similar short-term notes upon their maturity. The notes were replaced with Canadian-dollar commercial paper of non-related parties prior to December 31, 2000. Interest on the notes was at competitive Canadian interest rates. Interest earned on the notes in 2000 was $23 million.

        Accounts payable due to Exxon Mobil Corporation at December 31, 2002, with respect to the above transactions were $146 million (2001 — $27 million).

millions of dollars
  2002
  2001
  2000

Operating revenues   1,036   664   578
Investment and other income       24
Purchases of crude oil and products   2,134   1,873   1,483
Operating, selling and general expenses   57   47   67

15. Net payments to governments

millions of dollars
  2002
  2001
  2000
 

 
Current income tax expense (note 5)   718   679   1,122  
Federal excise tax   1,231   1,180   1,194  
Property taxes included in expenses   85   86   93  
Payroll and other taxes included in expenses   51   47   41  
GST/QST/HST collected (a)   1,717   1,749   1,818  
GST/QST/HST input tax credits (a)   (1,368 ) (1,384 ) (1,376 )
Other consumer taxes collected for governments   1,589   1,585   1,524  
Crown royalties   314   460   623  

 
Total paid or payable to governments   4,337   4,402   5,039  
Less investment tax credits and other receipts   12   7   9  

 
Net payments to governments   4,325   4,395   5,030  

 
Net payments to:              
  Federal government   2,171   2,160   2,455  
  Provincial governments   2,069   2,149   2,482  
  Local governments   85   86   93  

 
Net payments to governments   4,325   4,395   5,030  

 
    (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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Glossary of financial terms

Capital employed is short-term and long-term debt and shareholders' equity. Average capital employed is the average of the beginning-of-year and end-of-year amounts.

Cash represents cash as recorded in the books of account and cash equivalents at cost. Cash equivalents are all highly liquid securities with a maturity of three months or less when purchased.

Debt represents amounts borrowed from external sources.

Marketable securities are securities of the governments of Canada and the provinces, banks and other corporations, with a maturity of longer than three months when purchased.

Net realizable value is the estimated selling price of an asset, less estimated costs of completion and disposal.

Future income taxes are based on differences between the book 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 settled in the future. The largest source is the difference between book and tax depreciation and amortization, where deductions are made earlier for tax purposes than for accounting purposes.

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INDEX TO EXHIBITS

 
   
   
   
   
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(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 B to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 1979 (File No. 2-9259)).    
(4)   Term Loan Agreement, dated as of July 13, 1989, relating to the borrowing of $2 billion (U.S.) (Incorporated herein by reference to Exhibit (4) of the Company's Annual Report on Form 10-K for the year ended December 31, 1989 (File No. 0-12014)). The Company's other long-term debt authorized under any other 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)).    

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            (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)).    
            (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    

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                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); 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); and units granted in 1993 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, 1993 (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)).    
            (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)   Earnings Bonus Unit Plan and Earnings Bonus Units granted in 2002. Units granted in 2001 are incorporated herein by reference to Exhibit (10)(iii)(5) of the Company's Annual Report on Form 10-K for the year ended December 31, 2000 (File No. 0-12014).   E-4
            (6)   Incentive Stock Option Plan and Incentive Stock Option 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.   E-7
(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, 2002.    
(23)   (ii)   (A)   Consent of PricewaterhouseCoopers LLP.   E-18
        (B)   Consent of Chief Engineering Officer.   E-19

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QuickLinks

TABLE OF CONTENTS PART I
PART I
PART II
PART III
PART IV
SIGNATURES
INDEX TO FINANCIAL STATEMENTS
REPORT OF INDEPENDENT ACCOUNTANTS
AUDITORS' REPORT
CONSOLIDATED STATEMENT OF EARNINGS (a)
CONSOLIDATED STATEMENT OF CASH FLOWS
CONSOLIDATED BALANCE SHEET
Summary of significant accounting policies
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
INDEX TO EXHIBITS