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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, 2003 |  | Commission file number: 0-12014

IMPERIAL OIL LIMITED

(Exact name of registrant as specified in its charter)

|                                                 |  |                    
|------------------------------------------------ |  | -------------------
|CANADA                                           |  | 98-0017682         
|(State or other jurisdiction of                  |  | (I.R.S. Employer   
|incorporation or organization)                   |  | Identification No.)
|                                                 |  |                    
|111 ST. CLAIR AVENUE WEST, TORONTO, ONT., CANADA |  | M5W 1K3            
|(Address of
principal executive officers)        |  | (Zip Code)         

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

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

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

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

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

Yes     þ     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
    þ    
No     o

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

Yes     þ     No     o

As of the last business day of the 2003 second fiscal quarter, the
aggregate market value of the voting stock held by non-affiliates of the
registrant was Canadian $5,327,412,752 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 27, 2004, was
361,316,496.





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TABLE OF CONTENTS



|                              |                                                                                                                      |                                             |                                      |  |  |  |  | 
|----------------------------- | -------------------------------------------------------------------------------------------------------------------- | ------------------------------------------- | ------------------------------------ |  |  |  |  | 
|PART I                       
|                              | Item 1. Business                                                                                                    
|                              |                                                                                                                      | Financial Information by Operating Segments
|                              |                                                                                                                      | Natural Resources                          
|                              |                                                                                                                      |                                             | Petroleum and Natural Gas Production
|                              |                                                                                                                      |                                             | Land Holdings                       
|                              |                                                                                                                      |                                             | Exploration and Development         
|                              |                                                                                                                      | Petroleum Products                         
|                              |                                                                                                                      |                                             | Supply                              
|                              |                                                                                                                      |                                             | Refining                            
|                              |                                                                                                                      |                                             | Distribution                        
|                              |                                                                                                                      |                                             | Marketing                           
|                              |                                                                                                                      | Chemicals                                  
|                              |                                                                                                                      | Research                                   
|                              |                                                                                                                      | Environmental Protection                   
|                              |                                                                                                                      | Human Resources                            
|                              |                                                                                                                      | Competition                                
|                              |                                                                                                                      | Government Regulation                      
|                              |                                                                                                                      | The Company Online                         
|                              | Item 2. Properties                                                                                                  
|                              | Item 3. Legal Proceedings                                                                                           
|                              | Item 4. Submission of Matters to a Vote of Security Holders                                                         
|PART II                      
|                              | Item 5. Market for Registrants Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
|                              | Item 6. Selected Financial Data                                                                                     
|                              | Item 7. Managements Discussion and Analysis of Financial Condition and Results of Operation                        
|                              | Item 7A. Quantitative and Qualitative Disclosures About Market Risk                                                 
|                              | Item 8. Financial Statements and Supplementary Data                                                                 
|                              | Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure                        
|                              | Item 9A. Controls and Procedures                                                                                    
|PART III                     
|                              | Item 10. Directors and Executive Officers of the Registrant                                                         
|                              | Item 11. Executive Compensation                                                                                     
|                              | Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters             
|                              | Item 13. Certain Relationships and Related Transactions                                                             
|                              | Item 14. Principal Accountant Fees and Services                                                                     
|PART IV                      
|                              | Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K                                           
|SIGNATURES                   
|INDEX TO FINANCIAL STATEMENTS
|Auditors Report             
|                              | Consolidated statement of earnings                                                                                  
|                              | Consolidated statement of cash flows                                                                                
|                              | Consolidated balance sheet                                                                                          
|                              | Summary of significant accounting policies                                                                          
|                              | Notes to consolidated financial statements                                                                          
|INDEX TO EXHIBITS            
|EX-10(iii)(A)(5)             
|EX-10(iii)(A)(8)             
|EX-23(ii)(A)                 
|EX-23(ii)(B)                 
|EX-31.1                      
|EX-31.2                      
|EX-32.1                      
|EX-32.2                      



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##### Table of Contents



TABLE OF CONTENTS

|                                                                                                                    |                                             |                                      |     |      |    | 
|------------------------------------------------------------------------------------------------------------------- | ------------------------------------------- | ------------------------------------ | --- | ---- | -- | 
|                                                                                                                    |                                             |                                      |     | Page
|PART I                                                                                                              |                                             |                                      |     |     
|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                         |     |      | 13 | 
|                                                                                                                    |                                             | 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, Related Stockholder
Matters and Issuer
Purchases of Equity Securities |                                             |                                      | 16  |     
|Item 6.Selected Financial Data                                                                                      |                                             |                                      | 17  |     
|Item 7.Managements Discussion and Analysis of Financial Condition
and Results of Operation                         |                                             |                                      | 21  |     
|Item 7A.Quantitative and Qualitative Disclosures About Market Risk                                                  |                                             |                                      | 29  |     
|Item 8.Financial Statements and Supplementary Data                                                                  |                                             |                                      | 30  |     
|Item 9.Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure                         |                                             |                                      | 33  |     
|Item 9A.Controls and Procedures                                                                                     |                                             |                                      | 34  |     
|PART III                                                                                                            |                                             |                                      |     |     
|Item 10.Directors and Executive Officers of the Registrant                                                          |                                             |                                      | 35  |     
|Item 11.Executive Compensation                                                                                      |                                             |                                      | 38  |     
|Item 12.Security Ownership of Certain Beneficial Owners and
Management and
Related Stockholder Matters              |                                             |                                      | 45  |     
|Item 13.Certain Relationships and Related Transactions                                                              |                                             |                                      | 46  |     
|Item 14.Principal Accountant Fees and Services                                                                      |                                             |                                      | 46  |     
|PART IV                                                                                                             |                                             |                                      |     |     
|Item 15.Exhibits, Financial Statement Schedules, and Reports on Form 8-K                                            |                                             |                                      | 47  |     
|Index to Financial Statements                                                                                       |                                             |                                      | F-1 |     
|Auditors Report                                                                                                    |                                             |                                      | F-2 |     

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

|                           |  |      |        |      |  |      |        |      |  |           |        |  |  |  |        |  |  |  |        | 
|-------------------------- |  | ---- | ------ | ---- |  | ---- | ------ | ---- |  | --------- | ------ |  |  |  | ------ |  |  |  | ------ | 
|                           |  | 2003 |        | 2002 |  | 2001 |        | 2000 |  | 1999     
|                           |  |      |        |      |  |      |        |      |  |          
|                           |  |      |        |      |  |      |        |      |  | (Dollars) |        |  |  |  |        |  |  | 
|Rate at end of period      |  |      | 0.7738 |      |  |      | 0.6329 |      |  |           | 0.6279 |  |  |  | 0.6669 |  |  |  | 0.6925 | 
|Average rate during period |  |      | 0.7186 |      |  |      | 0.6368 |      |  |           | 0.6444 |  |  |  | 0.6725 |  |  |  | 0.6744 | 
|High                       |  |      | 0.7738 |      |  |      | 0.6619 |      |  |           | 0.6697 |  |  |  | 0.6969 |  |  |  | 0.6925 | 
|Low                        |  |      | 0.6349 |      |  |      | 0.6200 |      |  |           | 0.6241 |  |  |  | 0.6410 |  |  |  | 0.6535 | 

On February 27, 2004, 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 $0.7460 U.S. = $1.00 Canadian.

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




PART I




Item 1. Business.

Imperial Oil Limited was incorporated under the laws of Canada in 1880 and
was continued under the Canada Business Corporations Act (the CBCA) by
certificate of continuance dated April 24, 1978. The head and principal office
of the Company is located at 111 St. Clair Avenue West, Toronto, Ontario,
Canada M5W 1K3; telephone 1-800-567-3776. Exxon Mobil Corporation owns
approximately 69.6 percent of the outstanding shares of the Company with the
remaining shares being publicly held, with the majority of shareholders having
Canadian addresses of record. In this report, unless the context otherwise
indicates, reference to the Company includes Imperial Oil Limited and its
subsidiaries.

The Company is Canadas largest integrated oil company. It is active in
all phases of the petroleum industry in Canada, including the exploration for,
and production and sale of, crude oil and natural gas. In Canada, it is one of
the largest producers of crude oil and natural gas liquids and a major producer
of natural gas, and the largest refiner and marketer of petroleum products. It
is also a major supplier of petrochemicals.

The Companys operations are conducted in three main segments: natural
resources (upstream), petroleum products (downstream) and chemicals.
Natural resources operations include the exploration for, and production of,
crude oil and natural gas, including upgraded crude oil and crude bitumen.
Petroleum products operations consist of the transportation, refining and
blending of crude oil and refined products and the distribution and marketing
thereof. The chemicals operations consist of the manufacturing and marketing of
various petrochemicals.




Financial Information by Operating Segments

|                                        |                   |                                       |        |            |        |      |        |      |        |      |        |      |        |   |        |   |        |   |        |   |        | 
|--------------------------------------- | ----------------- | ------------------------------------- | ------ | ---------- | ------ | ---- | ------ | ---- | ------ | ---- | ------ | ---- | ------ | - | ------ | - | ------ | - | ------ | - | ------ | 
|                                        |                   |                                       |        | 2003       |        | 2002 |        | 2001 |        | 2000 |        | 1999
|                                        |                   |                                       |        |            |        |      |        |      |        |      |        |     
|                                        |                   |                                       |        | (millions)
|External revenues:                      |                   |                                       |        |            |        |      |        |      |        |      |        |      |        |   |        |   |        |   |        |  
|                                        |                   | Natural resources                     |        | $          | 3,424  |      |        | $    | 2,677  |      |        | $    | 3,155  |   |        | $ | 3,262  |   |        | $ | 2,216  | 
|                                        |                   | Petroleum products                    |        |            | 14,764 |      |        |      | 13,396 |      |        |      | 13,105 |   |        |   | 13,788 |   |        |   | 9,885  | 
|                                        |                   | Chemicals                             |        |            | 994    |      |        |      | 955    |      |        |      | 930    |   |        |   | 945    |   |        |   | 717    | 
|                                        |                   | Corporate and other                   |        |            | 26     |      |        |      | 14     |      |        |      | 63     |   |        |   | 56     |   |        |   | 35     | 
|                                        |                   |                                       |        |            |        |      |        |      |        |      |        |      |        |   |        |   |        |   |        |   |        | 
|                                        |                   | $                                     | 19,208 |            |        | $    | 17,042 |      |        | $    | 17,253 |      |        | $ | 18,051 |   |        | $ | 12,853 |  
|                                        |                   |                                       |        |            |        |      |        |      |        |      |        |      |        |   |        |   |        |   |        |   |        | 
|Intersegment sales:                     |                   |                                       |        |            |        |      |        |      |        |      |        |      |        |   |        |   |        |   |        |  
|                                        |                   | Natural resources                     |        | $          | 2,224  |      |        | $    | 2,217  |      |        | $    | 2,166  |   |        | $ | 2,638  |   |        | $ | 1,688  | 
|                                        |                   | Petroleum products                    |        |            | 1,294  |      |        |      | 1,038  |      |        |      | 1,300  |   |        |   | 1,332  |   |        |   | 780    | 
|                                        |                   | Chemicals                             |        |            | 238    |      |        |      | 209    |      |        |      | 245    |   |        |   | 228    |   |        |   | 155    | 
|Total revenues:                         |                   |                                       |        |            |        |      |        |      |        |      |        |      |        |   |        |   |        |   |        |  
|                                        |                   | Natural resources                     |        | $          | 5,648  |      |        | $    | 4,894  |      |        | $    | 5,321  |   |        | $ | 5,900  |   |        | $ | 3,904  | 
|                                        |                   | Petroleum products                    |        |            | 16,058 |      |        |      | 14,434 |      |        |      | 14,405 |   |        |   | 15,120 |   |        |   | 10,665 | 
|                                        |                   | Chemicals                             |        |            | 1,232  |      |        |      | 1,164  |      |        |      | 1,175  |   |        |   | 1,173  |   |        |   | 872    | 
|                                        |                   | Corporate and other                   |        |            | 26     |      |        |      | 14     |      |        |      | 63     |   |        |   | 56     |   |        |   | 35     | 
|                                        | Net earnings (1): |                                       |        |            |        |      |        |      |        |      |        |      |        |   |        |   |        |   |        |   |       
|                                        |                   | Natural resources                     |        | $          | 1,139  |      |        | $    | 1,056  |      |        | $    | 957    |   |        | $ | 1,177  |   |        | $ | 567    | 
|                                        |                   | Petroleum products                    |        |            | 407    |      |        |      | 127    |      |        |      | 353    |   |        |   | 313    |   |        |   | 15     | 
|                                        |                   | Chemicals                             |        |            | 37     |      |        |      | 52     |      |        |      | 23     |   |        |   | 59     |   |        |   | 43     | 
|                                        |                   | Corporate and other (2) /eliminations |        |            | 99     |      |        |      | (11    | )    |        |      | (78    | ) |        |   | (139   | ) |        |   | 3      | 
|                                        |                   |                                       |        |            |        |      |        |      |        |      |        |      |        |   |        |   |        |   |        |   |        | 
|                                        |                   | $                                     | 1,682  |            |        | $    | 1,224  |      |        | $    | 1,255  |      |        | $ | 1,410  |   |        | $ | 628    |  
|                                        |                   |                                       |        |            |        |      |        |      |        |      |        |      |        |   |        |   |        |   |        |   |        | 
|Identifiable assets at December 31 (3): |                   |                                       |        |            |        |      |        |      |        |      |        |      |        |   |        |   |        |   |        |  
|                                        |                   | Natural resources                     |        | $          | 6,434  |      |        | $    | 6,014  |      |        | $    | 5,385  |   |        | $ | 5,310  |   |        | $ | 5,399  | 
|                                        |                   | Petroleum products                    |        |            | 5,341  |      |        |      | 5,048  |      |        |      | 4,348  |   |        |   | 4,812  |   |        |   | 4,549  | 
|                                        |                   | Chemicals                             |        |            | 446    |      |        |      | 418    |      |        |      | 373    |   |        |   | 379    |   |        |   | 347    | 
|                                        |                   | Corporate and other/eliminations      |        |            | 140    |      |        |      | 414    |      |        |      | 675    |   |        |   | 743    |   |        |   | 533    | 
|                                        |                   |                                       |        |            |        |      |        |      |        |      |        |      |        |   |        |   |        |   |        |   |        | 
|                                        |                   | $                                     | 12,361 |            |        | $    | 11,894 |      |        | $    | 10,781 |      |        | $ | 11,244 |   |        | $ | 10,828 |  
|                                        |                   |                                       |        |            |        |      |        |      |        |      |        |      |        |   |        |   |        |   |        |   |        | 
|Capital and exploration expenditures:   |                   |                                       |        |            |        |      |        |      |        |      |        |      |        |   |        |   |        |   |        |  
|                                        |                   | Natural resources                     |        | $          | 1,007  |      |        | $    | 986    |      |        | $    | 746    |   |        | $ | 434    |   |        | $ | 430    | 
|                                        |                   | Petroleum products                    |        |            | 478    |      |        |      | 589    |      |        |      | 339    |   |        |   | 232    |   |        |   | 203    | 
|                                        |                   | Chemicals                             |        |            | 41     |      |        |      | 25     |      |        |      | 30     |   |        |   | 13     |   |        |   | 20     | 
|                                        |                   |                                       |        |            |        |      |        |      |        |      |        |      |        |   |        |   |        |   |        |   |        | 
|                                        |                   | $                                     | 1,526  |            |        | $    | 1,600  |      |        | $    | 1,115  |      |        | $ | 679    |   |        | $ | 653    |  
|                                        |                   |                                       |        |            |        |      |        |      |        |      |        |      |        |   |        |   |        |   |        |   |        | 

(continued on following page)



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| | (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, 2003, was as follows:

|                                              |              |  |   |   |  |         |           |  |      |      |                     |  |      |      |      |  |      |      |      |  |      |      |  |  |      |      |  |  | 
|--------------------------------------------- | ------------ |  | - | - |  | ------- | --------- |  | ---- | ---- | ------------------- |  | ---- | ---- | ---- |  | ---- | ---- | ---- |  | ---- | ---- |  |  | ---- | ---- |  |  | 
|                                              |              |  |   |   |  |         |           |  |      |      | 2003                |  | 2002 |      | 2001 |  | 2000 |      | 1999
|                                              |              |  |   |   |  |         |           |  |      |      |                     |  |      |      |      |  |      |      |     
|                                              |              |  |   |   |  |         |           |  |      |      | (thousands per day)
|Conventional (including
natural gas liquids): |              |  |   |   |  |         |           |  |      |      |                     |  |      |      |      |  |      |      |      | 
|                                              | Cubic metres |  |   |  |  |         | Gross (1) |  |      | 11.8 |                     |  |      | 12.4 |      |  |      | 13.2 |      |  |      | 14.3 |  |  |      | 15.3 | 
|                                              |              |  |  |   |  | Net (2) |           |  | 9.1  |      |                     |  | 9.5  |      |      |  | 10.2 |      |      |  | 11.0 |      |  |  | 11.9 |     
|                                              | Barrels      |  |   |  |  |         | Gross (1) |  |      | 74   |                     |  |      | 78   |      |  |      | 83   |      |  |      | 90   |  |  |      | 96   | 
|                                              |              |  |  |   |  | Net (2) |           |  | 57   |      |                     |  | 60   |      |      |  | 64   |      |      |  | 69   |      |  |  | 75   |     
|Oil Sands (Cold Lake):                        |              |  |   |   |  |         |           |  |      |      |                     |  |      |      |      |  |      |      |      |  |      |      |  |  |      |      |  | 
|                                              | Cubic metres |  |   |  |  |         | Gross (1) |  |      | 20.5 |                     |  |      | 17.8 |      |  |      | 20.4 |      |  |      | 18.9 |  |  |      | 21.0 | 
|                                              |              |  |  |   |  | Net (2) |           |  | 18.4 |      |                     |  | 16.9 |      |      |  | 19.2 |      |      |  | 16.2 |      |  |  | 17.1 |     
|                                              | Barrels      |  |   |  |  |         | Gross (1) |  |      | 129  |                     |  |      | 112  |      |  |      | 128  |      |  |      | 119  |  |  |      | 132  | 
|                                              |              |  |  |   |  | Net (2) |           |  | 116  |      |                     |  | 106  |      |      |  | 121  |      |      |  | 102  |      |  |  | 107  |     
|Tar Sands (Syncrude):                         |              |  |   |   |  |         |           |  |      |      |                     |  |      |      |      |  |      |      |      |  |      |      |  |  |      |      |  | 
|                                              | Cubic metres |  |   |  |  |         | Gross (1) |  |      | 8.4  |                     |  |      | 9.1  |      |  |      | 8.9  |      |  |      | 8.1  |  |  |      | 8.9  | 
|                                              |              |  |  |   |  | Net (2) |           |  | 8.3  |      |                     |  | 9.1  |      |      |  | 8.3  |      |      |  | 6.7  |      |  |  | 8.7  |     
|                                              | Barrels      |  |   |  |  |         | Gross (1) |  |      | 53   |                     |  |      | 57   |      |  |      | 56   |      |  |      | 51   |  |  |      | 56   | 
|                                              |              |  |  |   |  | Net (2) |           |  | 52   |      |                     |  | 57   |      |      |  | 52   |      |      |  | 42   |      |  |  | 55   |     
|Total:                                        |              |  |   |   |  |         |           |  |      |      |                     |  |      |      |      |  |      |      |      |  |      |      |  |  |      |      |  | 
|                                              | Cubic metres |  |   |  |  |         | Gross (1) |  |      | 40.7 |                     |  |      | 39.3 |      |  |      | 42.5 |      |  |      | 41.3 |  |  |      | 45.2 | 
|                                              |              |  |  |   |  | Net (2) |           |  | 35.8 |      |                     |  | 35.5 |      |      |  | 37.7 |      |      |  | 33.9 |      |  |  | 37.7 |     
|                                              | Barrels      |  |   |  |  |         | Gross (1) |  |      | 256  |                     |  |      | 247  |      |  |      | 267  |      |  |      | 260  |  |  |      | 284  | 
|                                              |              |  |  |   |  | Net (2) |           |  | 225  |      |                     |  | 223  |      |      |  | 237  |      |      |  | 213  |      |  |  | 237  |     



---

|(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 1999, conventional production has declined due to the sale of oil and
gas producing properties and the natural decline in the productivity of the
Companys conventional oil fields. In 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. In 2003, Cold Lake net
production increased as a result of a full year of production of stages 11 to
13, which was offset in part by the timing of steaming cycles and higher
royalties. Syncrude production decreased in 2003 due to extended maintenance of
upgrading facilities.

4



---



##### Table of Contents



The Companys average daily production and sales of natural gas during the
five years ended December 31, 2003 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.

|                                         |              |  |      |      |      |  |                    |      |      |  |      |      |  |  |  |      |  |  |  |      | 
|---------------------------------------- | ------------ |  | ---- | ---- | ---- |  | ------------------ | ---- | ---- |  | ---- | ---- |  |  |  | ---- |  |  |  | ---- | 
|                                         |              |  | 2003 |      | 2002 |  | 2001               |      | 2000 |  | 1999
|                                         |              |  |      |      |      |  |                    |      |      |  |     
|                                         |              |  |      |      |      |  | (millions per day) |      |      |  |     
|Sales (1):                               |              |  |      |      |      |  |                    |      |      |  |      |      |  |  |  |      |  |  |  |     
|                                         | Cubic metres |  |      | 13.0 |      |  |                    | 14.1 |      |  |      | 14.2 |  |  |  | 11.9 |  |  |  | 11.1 | 
|                                         | Cubic feet   |  |      | 460  |      |  |                    | 499  |      |  |      | 502  |  |  |  | 419  |  |  |  | 393  | 
|Gross Production (2):                    |              |  |      |      |      |  |                    |      |      |  |      |      |  |  |  |      |  |  |  |     
|                                         | Cubic metres |  |      | 14.5 |      |  |                    | 15.0 |      |  |      | 16.2 |  |  |  | 14.9 |  |  |  | 13.3 | 
|                                         | Cubic feet   |  |      | 513  |      |  |                    | 530  |      |  |      | 572  |  |  |  | 526  |  |  |  | 469  | 
|Net Production (2):                      |              |  |      |      |      |  |                    |      |      |  |      |      |  |  |  |      |  |  |  |     
|                                         | Cubic metres |  |      | 12.9 |      |  |                    | 13.1 |      |  |      | 13.2 |  |  |  | 13.0 |  |  |  | 11.7 | 
|                                         | Cubic feet   |  |      | 457  |      |  |                    | 463  |      |  |      | 466  |  |  |  | 459  |  |  |  | 413  | 
|Gross Production available for sale (3): |              |  |      |      |      |  |                    |      |      |  |      |      |  |  |  |      |  |  |  |     
|                                         | Cubic metres |  |      | 12.6 |      |  |                    | 13.1 |      |  |      | 13.7 |  |  |  | 9.8  |  |  |  | 8.5  | 
|                                         | Cubic feet   |  |      | 446  |      |  |                    | 463  |      |  |      | 482  |  |  |  | 345  |  |  |  | 300  | 
|Net Production available for sale (3):   |              |  |      |      |      |  |                    |      |      |  |      |      |  |  |  |      |  |  |  |     
|                                         | Cubic metres |  |      | 11.0 |      |  |                    | 11.2 |      |  |      | 10.7 |  |  |  | 7.8  |  |  |  | 6.9  | 
|                                         | Cubic feet   |  |      | 390  |      |  |                    | 396  |      |  |      | 376  |  |  |  | 277  |  |  |  | 244  | 



---

|(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 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 and 2003, natural gas production
decreased primarily due to the depletion of gas caps in Alberta and in 2003
also due to increased maintenance activity at gas processing facilities.

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, 2003, were as follows:

|                                                                   |                                    |                           |  |      |        |      |  |      |        |      |  |      |        |  |  |   |        |  |  |   |        | 
|------------------------------------------------------------------ | ---------------------------------- | ------------------------- |  | ---- | ------ | ---- |  | ---- | ------ | ---- |  | ---- | ------ |  |  | - | ------ |  |  | - | ------ | 
|                                                                   |                                    |                           |  | 2003 |        | 2002 |  | 2001 |        | 2000 |  | 1999
|                                                                   |                                    |                           |  |      |        |      |  |      |        |      |  |     
|Average Sales Price:                                               |                                    |                           |  |      |        |      |  |      |        |      |  |      |        |  |  |   |        |  |  |  
|                                                                   | Crude oil and natural gas liquids: |                           |  |      |        |      |  |      |        |      |  |      |        |  |  |   |        |  |  |   |       
|                                                                   |                                    | Per cubic metre           |  | $    | 181.92 |      |  | $    | 174.72 |      |  | $    | 134.16 |  |  | $ | 190.02 |  |  | $ | 120.82 | 
|                                                                   |                                    | Per barrel                |  |      | 28.92  |      |  |      | 27.78  |      |  |      | 21.33  |  |  |   | 30.21  |  |  |   | 19.21  | 
|                                                                   | Natural gas:                       |                           |  |      |        |      |  |      |        |      |  |      |        |  |  |   |        |  |  |   |       
|                                                                   |                                    | Per thousand cubic metres |  | $    | 232.99 |      |  | $    | 141.91 |      |  | $    | 201.92 |  |  | $ | 176.15 |  |  | $ | 93.90  | 
|                                                                   |                                    | Per thousand cubic feet   |  |      | 6.60   |      |  |      | 4.02   |      |  |      | 5.72   |  |  |   | 4.99   |  |  |   | 2.66   | 
|Average Production (Lifting) Costs Per
Unit of Net Production (1): |                                    |                           |  |      |        |      |  |      |        |      |  |      |        |  |  |   |        |  |  |  
|                                                                   |                                    | Per cubic metre           |  | $    | 63.85  |      |  | $    | 48.81  |      |  | $    | 46.17  |  |  | $ | 47.36  |  |  | $ | 37.54  | 
|                                                                   |                                    | Per barrel                |  |      | 10.15  |      |  |      | 7.76   |      |  |      | 7.34   |  |  |   | 7.53   |  |  |   | 5.97   | 



---

|(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



---



##### Table of Contents



Canadian crude oil prices are mainly determined by international crude oil
markets which are volatile.

Canadian natural gas prices are determined by North
American gas markets and are also volatile. Prices for Canadian natural gas
increased significantly in 2000 and again in early 2001 and 2003, in line with
tighter North American market conditions. Canadian natural gas prices decreased
in 2002 primarily due to a weaker U.S. economy and warmer weather.

In 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. In 2003, average production (lifting) costs increased
mainly due to higher costs of purchased natural gas 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,
2003, 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          |  |           | 2,334 |             |  |           | 1,321 |         |  |           | 4,033 |         |  |  | 2,187 |  |  |  | 6,367 |  |  |  | 3,508 | 
|Oil Sands (Cold Lake) wells |  |           | 3,524 |             |  |           | 3,524 |         |  |           |      |         |  |  |      |  |  |  | 3,524 |  |  |  | 3,524 | 



---

| | (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
2003, net production of crude oil and natural gas liquids was about 2,500 cubic
metres (15,900 barrels) per day and gross production was about 3,700 cubic
metres (23,200 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 2003, those costs were about $35
million.

Most of the larger oil fields in the Western Provinces have been in
production for several decades, and the amount of oil that is produced from
conventional fields is declining. In some cases, however, additional oil can be
recovered by using various methods of enhanced recovery. The Companys largest
enhanced recovery projects are located at the West Pembina oil field.

The Company produces natural gas from a large number of gas fields located
in the Western Provinces, primarily in Alberta.

The Company has a nine percent interest in a project to develop natural
gas reserves in the Sable Island area off the coast of the Province of Nova
Scotia. About $4 billion has been spent by the participants to the end of 2003
on the project. Production from the Sable Offshore Energy Project began at the
end of 1999 and is expected to average about 13 million cubic metres (450
million cubic feet) per day of natural gas and 2,900 cubic metres (18,000
barrels) per day of natural gas liquids through the end of the decade.

6



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##### Table of Contents



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 2003, net production
from the pilots averaged about 1,700 cubic metres (10,800 barrels) per day and
gross production was about 1,900 cubic metres (12,000 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 2003, average net production
from those ten stages was about 13,000 cubic metres (81,800 barrels) per day
and gross production was about 14,500 cubic metres (91,000 barrels) per day.

To maintain production at Cold Lake, capital expenditures for additional
production wells and associated facilities will be required periodically. In
2003, the Company spent $93 million on a development drilling program of 118
wells on existing stages. In 2004, a significant development drilling program
of more than 300 wells is planned within the currently approved development
area to enhance productivity from existing Cold Lake stages. In addition,
opportunities are also being evaluated to improve utilization of the existing
infrastructure.

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. 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, from extended stages 9 and 10
and from stages 14 to 16 by the end of the decade. 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 ten percent in 2003, five percent in 2002 and
2001, 14 percent in 2000 and 18 percent in 1999. 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.

7



---



##### Table of Contents



The Company holds varying interests in lands totalling about 68,000 leased
net hectares (168,000 net acres) in the Athabasca area where the oil sands are
buried too deeply to permit recovery by surface mining methods. The Company, as
part of an industry consortium and several joint ventures, has been involved in
recovery research and pilot studies and in evaluating the quality and extent of
the oil sands.

Syncrude Mining Operations

The Company holds a 25 percent participating interest in Syncrude, a joint
venture established to recover shallow deposits of tar sands using open-pit
mining methods, to extract the crude bitumen, and to produce a high-quality,
light (32 degree API), sweet, synthetic crude oil. The Syncrude operation,
located near Fort McMurray, Alberta, exploits a portion of the Athabasca Oil
Sands Deposit. The location is readily accessible by public road. The produced
synthetic crude oil is shipped from the Syncrude site to Edmonton, Alberta by
Alberta Oil Sands Pipeline Ltd. The pipeline is currently being expanded to
accommodate increased Syncrude production. Since startup in 1978, Syncrude has
produced about 1.5 billion barrels of synthetic crude oil.

Syncrude has an operating license issued by the Province of Alberta which
is effective until 2035. This license permits Syncrude to mine tar sands and
produce synthetic crude oil from approved development areas on tar sands
leases. Syncrude holds eight tar sands leases covering about 102,000 hectares
(252,000 acres) in the Athabasca Oil Sands Deposit. Issued by the Province of
Alberta, the leases are automatically renewable as long as tar sands operations
are ongoing or the leases are part of an approved development plan. Syncrude
leases 10, 12, 17, 22 and 34 (containing proven reserves) and leases 29, 30 and
31 (containing no proven reserves) are included within a development plan
approved by the Province of Alberta. There were no known previous commercial
operations on these leases prior to the start-up of operations in 1978.

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 had issued an order that expired at the end of
2003 which provided for the remission of any federal income tax otherwise
payable by the participants as the result of the non-deductibility from the
income of the participants of amounts receivable by the Province of Alberta as
a royalty or otherwise with respect to Syncrude. That remission order excluded
royalty payable on production for the Aurora project.

Operations at Syncrude involve three main processes: open pit mining,
extraction of crude bitumen and upgrading of crude bitumen into synthetic crude
oil. In the Base mine (lease 17), the mining and transportation system uses
draglines, bucketwheel reclaimers and belt conveyors. In the North mine (leases
17 and 22) and in the Aurora mine (leases 10, 12 and 34), 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 2003, the upgrading process yielded 0.860 cubic
metres of synthetic crude oil per cubic metre of crude bitumen (0.860 barrels
of synthetic crude oil per barrel of crude bitumen). In 2003, about 55 percent
of the synthetic crude oil was processed by Edmonton area refineries and the
remaining 45 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 $2.2 billion.

In 2003, Syncrudes net production of synthetic crude oil was about 33,300
cubic metres (209,400 barrels) per day and gross production was about 33,600
cubic metres (211,500 barrels) per day. The Companys share of net production
in 2003 was about 8,300 cubic metres (52,300 barrels) per day.

8



---



##### Table of Contents



In 2000, Syncrude completed development of the first stage of the Aurora
mine. The Aurora investment involved extending mining operations to a new
location about 35 km from the main Syncrude site and expanding upgrading
capacity. In 2001, the Syncrude owners approved another major expansion of
upgrading capacity and further development of the Aurora mine. This project is
expected to lead to a total production capacity of about 55,600 cubic metres
(350,000 barrels) of synthetic crude oil a day with expected completion in
mid-2006. The Companys share of project costs is expected to be about $2
billion.

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

|                                       |                          |  |      |       |      |  |      |       |      |  |      |       |  |  |      |       |  |  |      |       | 
|-------------------------------------- | ------------------------ |  | ---- | ----- | ---- |  | ---- | ----- | ---- |  | ---- | ----- |  |  | ---- | ----- |  |  | ---- | ----- | 
|                                       |                          |  | 2003 |       | 2002 |  | 2001 |       | 2000 |  | 1999
|                                       |                          |  |      |       |      |  |      |       |      |  |     
|Total mined volume (1)                 |                          |  |      |       |      |  |      |       |      |  |      |       |  |  |      |       |  |  |      |      
|                                       | millions of cubic metres |  |      | 83.5  |      |  |      | 77.9  |      |  |      | 90.3  |  |  |      | 65.0  |  |  |      | 76.5  | 
|                                       | millions of cubic yards  |  |      | 109.2 |      |  |      | 102.0 |      |  |      | 118.3 |  |  |      | 85.1  |  |  |      | 100.1 | 
|Mined volume to tar sands ratio (1)    |                          |  | 1.15 |       |      |  | 1.05 |       |      |  | 1.15 |       |  |  | 0.96 |       |  |  | 0.99 |      
|Tar sands mined                        |                          |  |      |       |      |  |      |       |      |  |      |       |  |  |      |       |  |  |      |      
|                                       | millions of tonnes       |  |      | 152.4 |      |  |      | 156.5 |      |  |      | 164.8 |  |  |      | 142.2 |  |  |      | 162.1 | 
|                                       | millions of tons         |  |      | 168.0 |      |  |      | 172.1 |      |  |      | 181.2 |  |  |      | 156.4 |  |  |      | 178.7 | 
|Average bitumen grade (weight percent) |                          |  | 11.0 |       |      |  | 11.2 |       |      |  | 11.0 |       |  |  | 11.0 |       |  |  | 10.8 |      
|Crude bitumen in mined tar sands       |                          |  |      |       |      |  |      |       |      |  |      |       |  |  |      |       |  |  |      |      
|                                       | millions of tonnes       |  |      | 16.8  |      |  |      | 17.5  |      |  |      | 18.1  |  |  |      | 15.6  |  |  |      | 17.5  | 
|                                       | millions of tons         |  |      | 18.5  |      |  |      | 19.2  |      |  |      | 19.9  |  |  |      | 17.2  |  |  |      | 19.3  | 
|Average extraction recovery (percent)  |                          |  | 88.6 |       |      |  | 89.9 |       |      |  | 87.0 |       |  |  | 89.7 |       |  |  | 91.4 |      
|Crude bitumen production (2)           |                          |  |      |       |      |  |      |       |      |  |      |       |  |  |      |       |  |  |      |      
|                                       | millions of cubic metres |  |      | 14.7  |      |  |      | 15.5  |      |  |      | 15.5  |  |  |      | 13.8  |  |  |      | 15.8  | 
|                                       | millions of barrels      |  |      | 92.3  |      |  |      | 97.8  |      |  |      | 97.6  |  |  |      | 86.8  |  |  |      | 99.6  | 
|Average upgrading yield (percent)      |                          |  | 86.0 |       |      |  | 86.3 |       |      |  | 84.5 |       |  |  | 84.3 |       |  |  | 83.9 |      
|Gross synthetic crude oil produced     |                          |  |      |       |      |  |      |       |      |  |      |       |  |  |      |       |  |  |      |      
|                                       | millions of cubic metres |  |      | 12.5  |      |  |      | 13.5  |      |  |      | 13.1  |  |  |      | 11.6  |  |  |      | 13.3  | 
|                                       | millions of barrels      |  |      | 78.4  |      |  |      | 84.8  |      |  |      | 82.4  |  |  |      | 73.2  |  |  |      | 83.6  | 
|Companys net share (3)                |                          |  |      |       |      |  |      |       |      |  |      |       |  |  |      |       |  |  |      |      
|                                       | millions of cubic metres |  |      | 3     |      |  |      | 3     |      |  |      | 3     |  |  |      | 2     |  |  |      | 3     | 
|                                       | millions of barrels      |  |      | 19    |      |  |      | 21    |      |  |      | 19    |  |  |      | 15    |  |  |      | 20    | 



---

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

Other Tar Sands Activity

The Company holds a 100 percent interest in approximately 16,500 hectares
(40,700 acres) of surface mineable tar sands in the Kearl area in the Athabasca
area of northern Alberta. The Company is assessing a potential project with
another company to jointly develop mineable bitumen. A 200 well delineation
drilling program was begun in 2003 to better define the available resource. A
phased project is being assessed which may have the potential to produce up to
a total of 31,800 cubic metres (200,000 barrels) per day.

9



---



##### Table of Contents






Land Holdings

At December 31, 2003 and 2002, the Company held the following oil and gas
rights, and tar sands leases:

|                                  |  |  |  |           |  |           |       |             |  |       |       |           |  |             |       |       |  |      |       |      |  |      |       |      |  |      |       |      |  |  |       |  |  |  |       |  |  |  |       |  |  |  |       |  |  |  |       |  |  |  |       | 
|--------------------------------- |  |  |  | --------- |  | --------- | ----- | ----------- |  | ----- | ----- | --------- |  | ----------- | ----- | ----- |  | ---- | ----- | ---- |  | ---- | ----- | ---- |  | ---- | ----- | ---- |  |  | ----- |  |  |  | ----- |  |  |  | ----- |  |  |  | ----- |  |  |  | ----- |  |  |  | ----- | 
|                                  |  |  |  |           |  | Hectares  |       | Acres      
|                                  |  |  |  |           |  |           |       |            
|                                  |  |  |  |           |  | Developed |       | Undeveloped |  | Total |       | Developed |  | Undeveloped |       | Total
|                                  |  |  |  |           |  |           |       |             |  |       |       |           |  |             |       |      
|                                  |  |  |  |           |  | 2003      |       | 2002        |  | 2003  |       | 2002      |  | 2003        |       | 2002  |  | 2003 |       | 2002 |  | 2003 |       | 2002 |  | 2003 |       | 2002
|                                  |  |  |  |           |  |           |       |             |  |       |       |           |  |             |       |       |  |      |       |      |  |      |       |      |  |      |       |     
|                                  |  |  |  |           |  |           |       |             |  |       |       |           |  | (thousands) |       |       |  |      |       |      |  |      |       |      |  |      |       |      |  |  |       |  |  |  |       |  |  |  |       |  |  |  |       |  |  | 
|Western Provinces Conventional   |  |  |  |           |  |           |       |             |  |       |       |           |  |             |       |       |  |      |       |      |  |      |       |      |  |      |       |      |  |  |       |  |  |  |       |  |  |  |       |  |  |  |       |  |  |  |       | 
|                                  |  |  |  | Gross (1) |  |           | 1,101 |             |  |       | 1,109 |           |  |             | 187   |       |  |      | 205   |      |  |      | 1,288 |      |  |      | 1,314 |      |  |  | 2,721 |  |  |  | 2,740 |  |  |  | 462   |  |  |  | 507   |  |  |  | 3,183 |  |  |  | 3,247 | 
|                                  |  |  |  | Net (2)   |  |           | 450   |             |  |       | 454   |           |  |             | 127   |       |  |      | 139   |      |  |      | 577   |      |  |      | 593   |      |  |  | 1,112 |  |  |  | 1,122 |  |  |  | 314   |  |  |  | 343   |  |  |  | 1,426 |  |  |  | 1,465 | 
|Oil Sands (Cold Lake and other)  |  |  |  |           |  |           |       |             |  |       |       |           |  |             |       |       |  |      |       |      |  |      |       |      |  |      |       |      |  |  |       |  |  |  |       |  |  |  |       |  |  |  |       |  |  |  |       | 
|                                  |  |  |  | Gross (1) |  |           | 42    |             |  |       | 41    |           |  |             | 175   |       |  |      | 200   |      |  |      | 217   |      |  |      | 241   |      |  |  | 104   |  |  |  | 101   |  |  |  | 432   |  |  |  | 494   |  |  |  | 536   |  |  |  | 595   | 
|                                  |  |  |  | Net (2)   |  |           | 41    |             |  |       | 41    |           |  |             | 104   |       |  |      | 114   |      |  |      | 145   |      |  |      | 155   |      |  |  | 101   |  |  |  | 101   |  |  |  | 257   |  |  |  | 282   |  |  |  | 358   |  |  |  | 383   | 
|Tar Sands (Syncrude and other)   |  |  |  |           |  |           |       |             |  |       |       |           |  |             |       |       |  |      |       |      |  |      |       |      |  |      |       |      |  |  |       |  |  |  |       |  |  |  |       |  |  |  |       |  |  |  |       | 
|                                  |  |  |  | Gross (1) |  |           | 41    |             |  |       | 20    |           |  |             | 77    |       |  |      | 98    |      |  |      | 118   |      |  |      | 118   |      |  |  | 101   |  |  |  | 49    |  |  |  | 190   |  |  |  | 242   |  |  |  | 291   |  |  |  | 291   | 
|                                  |  |  |  | Net (2)   |  |           | 10    |             |  |       | 10    |           |  |             | 32    |       |  |      | 32    |      |  |      | 42    |      |  |      | 42    |      |  |  | 25    |  |  |  | 25    |  |  |  | 79    |  |  |  | 79    |  |  |  | 104   |  |  |  | 104   | 
|Canada Lands (3): Conventional   |  |  |  |           |  |           |       |             |  |       |       |           |  |             |       |       |  |      |       |      |  |      |       |      |  |      |       |      |  |  |       |  |  |  |       |  |  |  |       |  |  |  |       |  |  |  |       | 
|                                  |  |  |  | Gross (1) |  |           | 31    |             |  |       | 31    |           |  |             | 321   |       |  |      | 396   |      |  |      | 352   |      |  |      | 427   |      |  |  | 77    |  |  |  | 77    |  |  |  | 793   |  |  |  | 979   |  |  |  | 870   |  |  |  | 1,056 | 
|                                  |  |  |  | Net (2)   |  |           | 4     |             |  |       | 4     |           |  |             | 98    |       |  |      | 150   |      |  |      | 102   |      |  |      | 154   |      |  |  | 10    |  |  |  | 10    |  |  |  | 242   |  |  |  | 371   |  |  |  | 252   |  |  |  | 381   | 
|Atlantic Offshore: Conventional  |  |  |  |           |  |           |       |             |  |       |       |           |  |             |       |       |  |      |       |      |  |      |       |      |  |      |       |      |  |  |       |  |  |  |       |  |  |  |       |  |  |  |       |  |  |  |       | 
|                                  |  |  |  | Gross (1) |  |           | 17    |             |  |       | 17    |           |  |             | 1,329 |       |  |      | 1,329 |      |  |      | 1,346 |      |  |      | 1,346 |      |  |  | 42    |  |  |  | 42    |  |  |  | 3,284 |  |  |  | 3,284 |  |  |  | 3,326 |  |  |  | 3,326 | 
|                                  |  |  |  | Net (2)   |  |           | 2     |             |  |       | 2     |           |  |             | 565   |       |  |      | 565   |      |  |      | 567   |      |  |      | 567   |      |  |  | 5     |  |  |  | 5     |  |  |  | 1,396 |  |  |  | 1,396 |  |  |  | 1,401 |  |  |  | 1,401 | 
|Total (4):                        |  |  |  |           |  |           |       |             |  |       |       |           |  |             |       |       |  |      |       |      |  |      |       |      |  |      |       |      |  |  |       |  |  |  |       |  |  |  |       |  |  |  |       |  |  |  |       | 
|                                  |  |  |  | Gross (1) |  |           | 1,232 |             |  |       | 1,218 |           |  |             | 2,089 |       |  |      | 2,228 |      |  |      | 3,321 |      |  |      | 3,446 |      |  |  | 3,045 |  |  |  | 3,009 |  |  |  | 5,161 |  |  |  | 5,506 |  |  |  | 8,206 |  |  |  | 8,515 | 
|                                  |  |  |  | Net (2)   |  |           | 507   |             |  |       | 511   |           |  |             | 926   |       |  |      | 1,000 |      |  |      | 1,433 |      |  |      | 1,511 |      |  |  | 1,253 |  |  |  | 1,263 |  |  |  | 2,288 |  |  |  | 2,471 |  |  |  | 3,541 |  |  |  | 3,734 | 



---

|(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, 2003.

|                                |                                                |                |           |  |      |     |      |  |      |     |      |  |      |     |     |  |  |     |     |  |  |     | 
|------------------------------- | ---------------------------------------------- | -------------- | --------- |  | ---- | --- | ---- |  | ---- | --- | ---- |  | ---- | --- | --- |  |  | --- | --- |  |  | --- | 
|                                |                                                |                |           |  | 2003 |     | 2002 |  | 2001 |     | 2000 |  | 1999
|                                |                                                |                |           |  |      |     |      |  |      |     |      |  |     
|Western and Atlantic Provinces: |                                                |                |           |  |      |     |      |  |      |     |      |  |      |     |     |  |  |     |     | 
|                                | Conventional                                   |                |           |  |      |     |      |  |      |     |      |  |      |     |     |  |  |     |     |  | 
|                                |                                                | Exploratory   |           |  |      |     |      |  |      |     |      |  |      |     |     |  |  |     |     |  |  |    
|                                |                                                |                | Oil       |  |      |    |      |  |      |    |      |  |      |    |     |  |  |    |     |  |  |    | 
|                                |                                                |                | Gas       |  |      | 3   |      |  |      | 1   |      |  |      | 1   |     |  |  | 3   |     |  |  | 3   | 
|                                |                                                |                | Dry Holes |  |      | 1   |      |  |      | 2   |      |  |      |    |     |  |  | 1   |     |  |  | 1   | 
|                                |                                                | Development   |           |  |      |     |      |  |      |     |      |  |      |     |     |  |  |     |     |  |  |    
|                                |                                                |                | Oil       |  |      | 4   |      |  |      | 1   |      |  |      | 17  |     |  |  | 18  |     |  |  | 3   | 
|                                |                                                |                | Gas       |  |      | 89  |      |  |      | 42  |      |  |      | 68  |     |  |  | 49  |     |  |  | 33  | 
|                                |                                                |                | Dry Holes |  |      | 3   |      |  |      | 3   |      |  |      |    |     |  |  |    |     |  |  |    | 
|                                | Oil Sands (Cold Lake and other)
Development   |                |           |  |      |     |      |  |      |     |      |  |      |     |     |  |  |     |     |  | 
|                                |                                                |                | Oil       |  |      | 118 |      |  |      | 332 |      |  |      | 307 |     |  |  | 112 |     |  |  | 211 | 
|                                |                                                |                |           |  |      |     |      |  |      |     |      |  |      |     |     |  |  |     |     | 
|Total                           |                                                |                | 218       |  |      |     | 381  |  |      |     | 393  |  |      |     | 183 |  |  |     | 251 | 
|                                |                                                |                |           |  |      |     |      |  |      |     |      |  |      |     |     |  |  |     |     | 

The 118 oil sands development wells in 2003 were related to productivity
maintenance in existing stages at Cold Lake.

At December 31, 2003, the Company was participating in the drilling of 144
gross (90 net) exploratory and development wells.

10



---



##### Table of Contents



Western Provinces In 2003, the Company had a working interest in eight gross (three net)
exploratory wells and 361 gross (214 net) development wells, while retaining an
overriding royalty in an additional nine 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
totalling approximately 170 billion cubic metres (six trillion cubic feet). The
Companys share of these resources is about 50 percent. The commercial
viability of these natural gas resources, and the pipeline required to
transport this natural gas to markets, is dependent on a number of factors.
These factors include natural gas markets, support from northern parties,
regulatory approvals, environmental considerations, pipeline participation,
fiscal terms, and the cost of constructing, operating and abandoning the field
production and pipeline facilities. There are complex issues to be resolved and
many interested parties to be consulted, before any development could proceed.
In October 2001, the four companies and the Aboriginal Pipeline Group (APG),
which represents aboriginal peoples of the Northwest Territories, signed a
memorandum of understanding to pursue economic and timely development of a
Mackenzie Valley pipeline. In 2002, the four companies completed a preliminary
study of the feasibility of developing existing discoveries
of Mackenzie Delta gas and based on the results of the study announced
together with the APG their intention to begin preparing the regulatory
applications needed to develop the gas resources, including construction of a
Mackenzie Valley pipeline. In 2003, the Preliminary Information Package for the
Mackenzie Gas Project was submitted to the regulatory authorities, and funding
and participation agreements between the four companies, the APG and
TransCanada PipeLines Limited were reached for the proposed Mackenzie Valley
pipeline. In late 2003, the application for Commercial Discovery Declaration
for the Taglu field was filed with the National Energy Board. This filing was
the next regulatory step towards bringing natural gas from the Taglu field into
production. Filing of the main regulatory applications for the project, the
next major step in the process, is expected to take place in 2004. In 2003, the Company relinquished its 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 licences by participating in the first exploration
well. In 2003, one exploratory well was drilled on these licences, without
commercial success. 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




---



##### Table of Contents



In early 2004, the Company and two other companies acquired a 25 percent
interest in eight deep water exploration licences offshore Newfoundland in the
Orphan Basin for about 2,125,000 gross hectares (5,251,000 gross acres). The
Companys share of proposed exploration spending is about $170 million with a
minimum commitment of about $40 million. 
 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 2003, capital expenditures of about $336 million were made at the
Companys refineries. About 75 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, 2003, and the daily rated capacities of the
refineries at December 31, 1998 and 2003, were as follows: Average Daily Volumes of
    
    Daily RatedRefinery Throughput (1)
    
    Capacities atYear Ended December 31
    
    December 31 (2)2003
    
    2002
    
    2001
    
    2000
    
    1999
    
    2003
    

    1998(thousands of cubic metres)Strathcona, Alberta
    
    
    27.6
    
    
    
    26.0
    
    
    
    25.4
    
    
    
    27.0
    
    
    
    26.2
    
    
    
    29.8
    
    
    
    28.0Sarnia, Ontario
    
    
    14.7
    
    
    
    16.5
    
    
    
    16.5
    
    
    
    16.2
    
    
    
    17.0
    
    
    
    19.2
    
    
    
    18.9Dartmouth, Nova Scotia
    
    
    13.0
    
    
    
    12.5
    
    
    
    12.3
    
    
    
    11.2
    
    
    
    11.9
    
    
    
    13.1
    
    
    
    13.1Nanticoke, Ontario
    
    
    16.3
    
    
    
    16.2
    
    
    
    17.2
    
    
    
    17.2
    
    
    
    15.0
    
    
    
    17.8
    
    
    
    17.8Total
    
    
    71.6
    
    
    
    71.2
    
    
    
    71.4
    
    
    
    71.6
    
    
    
    70.1
    
    
    
    79.9
    
    
    
    77.8
 Average Daily Volumes of
    
    Daily RatedRefinery Throughput (1)
    
    Capacities atYear Ended December 31
    
    December 31 (2)2003
    
    2002
    
    2001
    
    2000
    
    1999
    
    2003
    
    1998(thousands of barrels)Strathcona, Alberta
    
    
    174
    
    
    
    163
    
    
    
    160
    
    
    
    170
    
    
    
    165
    
    
    
    187
    
    
    
    176Sarnia, Ontario
    
    
    92
    
    
    
    104
    
    
    
    104
    
    
    
    102
    
    
    
    107
    
    
    
    121
    
    
    
    119Dartmouth, Nova Scotia
    
    
    82
    
    
    
    78
    
    
    
    77
    
    
    
    70
    
    
    
    75
    
    
    
    82
    
    
    
    82Nanticoke, Ontario
    
    
    102
    
    
    
    102
    
    
    
    108
    
    
    
    108
    
    
    
    94
    
    
    
    112
    
    
    
    112Total
    
    
    450
    
    
    
    447
    
    
    
    449
    
    
    
    450
    
    
    
    441
    
    
    
    502
    
    
    
    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 2003, the same as for the
previous year. 12




---



##### Table of Contents



Distribution The Company maintains a nation-wide distribution system, including 29
primary terminals, to handle bulk and packaged petroleum products moving from
refineries to market by pipeline, tanker, rail and road transport. The Company
owns and operates crude oil, natural gas liquids and products pipelines in
Alberta, Manitoba and Ontario and has interests in the capital stock of two
products and three crude oil pipeline companies. At December 31, 2003, the Company owned and operated two barges. These
vessels are used primarily for domestic transportation of refined petroleum
products. 
 Marketing The Company markets more than 700 petroleum products throughout Canada
under well known brand names, notably Esso, to all types of customers. The Company sells to the motoring public through approximately 2,100 Esso
retail outlets, of which about 820 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 100 sales facilities, of which about 40 also sell
fertilizers to the western Canadian farm markets. 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
was completed in 2003. Heating oil is provided through authorized dealers as well as through
three Company operated Home Comfort facilities in urban markets. The Company
also sells petroleum products to large industrial and commercial accounts as
well as to other refiners and marketers. The approximate daily volumes of petroleum products sold during the five
years ended December 31, 2003 are set out in the following table: 2003
    
    2002
    
    2001
    
    2000
    
    1999(thousands per day)Gasolines:Cubic metres
    
    
    33.0
    
    
    
    32.9
    
    
    
    32.3
    
    
    
    32.0
    
    
    
    31.9Barrels
    
    
    208
    
    
    
    207
    
    
    
    203
    
    
    
    201
    
    
    
    201Heating, Diesel and Jet Fuels:Cubic metres
    
    
    26.2
    
    
    
    25.0
    
    
    
    26.5
    
    
    
    27.5
    
    
    
    26.9Barrels
    
    
    165
    
    
    
    157
    
    
    
    166
    
    
    
    173
    
    
    
    169Heavy Fuel Oils:Cubic metres
    
    
    5.4
    
    
    
    4.9
    
    
    
    5.4
    
    
    
    5.1
    
    
    
    4.6Barrels
    
    
    34
    
    
    
    31
    
    
    
    34
    
    
    
    32
    
    
    
    29Lube Oils and Other Products (1):Cubic metres
    
    
    5.8
    
    
    
    6.4
    
    
    
    5.4
    
    
    
    5.0
    
    
    
    5.8Barrels
    
    
    36
    
    
    
    41
    
    
    
    34
    
    
    
    31
    
    
    
    36Net petroleum product sales:Cubic metres
    
    
    70.4
    
    
    
    69.2
    
    
    
    69.6
    
    
    
    69.6
    
    
    
    69.2Barrels
    
    
    443
    
    
    
    436
    
    
    
    437
    
    
    
    437
    
    
    
    435Sales under purchase and sale agreements:Cubic metres
    
    
    14.6
    
    
    
    13.9
    
    
    
    11.6
    
    
    
    10.7
    
    
    
    10.8Barrels
    
    
    92
    
    
    
    87
    
    
    
    73
    
    
    
    67
    
    
    
    68Total:Cubic metres
    
    
    85.0
    
    
    
    83.1
    
    
    
    81.2
    
    
    
    80.3
    
    
    
    80.0Barrels
    
    
    535
    
    
    
    523
    
    
    
    510
    
    
    
    504
    
    
    
    503
    (1)
    
    Includes 1.0 thousand cubic metres (6 thousand barrels) per day of
butane commencing in 2002. Butane is not included in prior years. The total domestic sales of petroleum products as a percentage of total
sales of petroleum products during the five years ended December 31, 2003, were
as follows: 2003
    
    2002
    
    2001
    
    2000
    
    199993.3
    %

    
    
    91.5
    %
    
    
    93.4
    %
    
    
    94.0
    %
    
    
    95.6
    %
 The Company continues to evaluate and adjust its Esso retail outlet and
distribution system to increase productivity and efficiency. During 2003, the Company closed or debranded about 130 Esso retail sites,
about 70 of which were Company owned, and added about 80
sites. The Companys average annual throughput per Esso retail outlet was
3.4 million litres, an increase of 0.1 million litres from 2002. Average
throughput per Company owned Esso retail outlet was 5.2 million litres in 2003,
an increase of about 0.3 million litres from 2002. 13




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##### Table of Contents



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, 2003, were as follows: 2003
    
    2002
    
    2001
    
    2000
    
    1999(thousands per day)Petrochemicals:Tonnes
    
    
    3.3
    
    
    
    3.5
    
    
    
    3.3
    
    
    
    3.1
    
    
    
    3.0Tons
    
    
    3.6
    
    
    
    3.9
    
    
    
    3.6
    
    
    
    3.4
    
    
    
    3.3
 
 Research In 2003, the Companys research expenditures in Canada, before deduction
of investment tax credits, were $36 million, as compared with $50 million in
2002 and $37 million in 2001. 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 2003. 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 2003. 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 $775 million on environmental protection and
facilities. In 2003, the Companys capital expenditures relating to
environmental protection totalled approximately $290 million, and are expected
to be about $195 million in 2004. 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 $600 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 2003 were approximately $20 million. 
 Human Resources At December 31, 2003, the Company employed full-time approximately 6,300
persons compared with about 6,500 at the end of 2002 and 6,700 at the end of
2001. 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




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##### Table of Contents



Government Regulation Petroleum and Natural Gas Rights Most of the Companys petroleum and natural gas rights were acquired from
governments, either federal or provincial. Reservations, permits or licences
are acquired from the provinces for cash and entitle the holder to obtain
leases upon completing specified work. Leases may also be acquired for cash. A
lease entitles the holder to produce petroleum or natural gas from the leased
lands. The holder of a licence relating to Canada Lands and the Atlantic
Offshore is generally required to make cash payments or to undertake specified
work or amounts of exploration expenditures in order to retain the holders
interest in the land and may become entitled to produce petroleum or natural
gas from the licenced land. Crude Oil Production The maximum allowable gross production of crude oil from wells in Canada
is subject to limitation by various regulatory authorities on the basis of
engineering and conservation principles. Exports Export contracts of more than one year for light crude oil and petroleum
products and two years for heavy crude oil (including crude bitumen) require
the prior approval of the National Energy Board (the NEB) and the Government
of Canada. Natural Gas Production The maximum allowable gross production of natural gas from wells in Canada
is subject to limitation by various regulatory authorities on the basis of
engineering and conservation principles. A permit is required from the Alberta
Energy and Utilities Board, subject to the approval of the Province of Alberta,
for the removal from Alberta of natural gas produced in that province. Exports The Government of Canada has the authority to regulate the export price
for natural gas and has a gas export pricing policy which accommodates export
prices for natural gas negotiated between Canadian exporters and U.S.
importers. Exports of natural gas from Canada require approval by the NEB and the
Government of Canada. The Government of Canada allows the export of natural gas
by NEB order without volume limitation for terms not exceeding 24 months. Royalties The Government of Canada and the provinces in which the Company produces
crude oil and natural gas impose royalties on production from lands where they
own the mineral rights. Some producing provinces also receive revenue by
imposing taxes on production from lands where they do not own the mineral
rights. Different royalties are imposed by the Government of Canada and each of
the producing provinces. Royalties imposed by the producing provinces on crude
oil vary depending on well production volumes, selling prices, recovery methods
and the date of initial production. Royalties imposed by the producing
provinces on natural gas and natural gas liquids vary depending on well
production volumes, selling prices and the date of initial production. For
information with respect to royalty rates for Norman Wells, Cold Lake and
Syncrude, see Natural Resources  Petroleum and Natural Gas Production. Investment Canada Act The Investment Canada Act requires Government of Canada approval, in
certain cases, of the acquisition of control of a Canadian business by an
entity that is not controlled by Canadians. In certain circumstances, the
acquisition of natural resource properties may be considered to be a
transaction that constitutes an acquisition of control of a Canadian business
requiring Government of Canada approval. The Act requires notification of the
establishment of new unrelated businesses in Canada by entities not controlled
by Canadians, but does not require Government of Canada approval except when
the new business is related to Canadas cultural heritage or national identity.
By virtue of the majority stock ownership of the Company by Exxon Mobil
Corporation, the Company is considered to be an entity which is not controlled
by Canadians. 
 The Company Online The Companys website www.imperialoil.cacontains a variety of corporate
and investor information which are available free of charge, including the
Companys annual report on Form 10-K, quarterly reports on Form 10-Q and
current reports on Form 8-K and amendments to these reports. These reports are
made available as soon as reasonably practicable after they are filed or
furnished to the U.S. Securities and Exchange Commission. 15




---



##### Table of Contents



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, Related Stockholder Matters and
Issuer Purchases of Equity Securities. Information for Security Holders Outside Canada Cash dividends paid to shareholders resident in countries with which
Canada has an income tax convention are usually subject to a Canadian
nonresident withholding tax of 15 percent. The withholding tax is reduced to five percent on dividends paid to a
corporation resident in the United States that owns at least 10 percent of the
voting shares of the Company. The Company is a qualified foreign corporation for purposes of the new
reduced U.S. capital gains tax rates (15% and 5% for certain individuals) which
are applicable to dividends paid by U.S. domestic corporations and qualified
foreign corporations. There is no Canadian tax on gains from selling shares or debt instruments
owned by nonresidents not carrying on business in Canada. Quarterly Financial and Stock Trading Data 2003
    
    2002three months ended
    
    three months endedMar. 31
    
    June 30
    
    Sept. 30
    
    Dec. 31
    
    Mar. 31
    
    June 30
    
    Sept. 30
    
    Dec. 31Per-share information(dollars)Dividends (declared quarterly)
    
    
    0.21
    
    
    
    0.22
    
    
    
    0.22
    
    
    
    0.22
    
    
    
    0.21
    
    
    
    0.21
    
    
    
    0.21
    
    
    
    0.21Share prices(dollars)Toronto Stock ExchangeHigh
    
    
    47.80
    
    
    
    47.40
    
    
    
    53.49
    
    
    
    58.22
    
    
    
    47.85
    
    
    
    49.38
    
    
    
    47.10
    
    
    
    46.10Low
    
    
    43.48
    
    
    
    43.20
    
    
    
    45.62
    
    
    
    50.16
    
    
    
    41.13
    
    
    
    43.76
    
    
    
    38.51
    
    
    
    41.55Close
    
    
    47.35
    
    
    
    47.10
    
    
    
    50.80
    
    
    
    57.53
    
    
    
    47.45
    
    
    
    47.29
    
    
    
    45.90
    
    
    
    44.86American Stock Exchange ($U.S.)High
    
    
    32.20
    
    
    
    34.99
    
    
    
    38.79
    
    
    
    44.75
    
    
    
    30.33
    
    
    
    31.85
    
    
    
    31.09
    
    
    
    29.31Low
    
    
    28.25
    
    
    
    29.94
    
    
    
    33.04
    
    
    
    37.24
    
    
    
    25.83
    
    
    
    28.15
    
    
    
    24.00
    
    
    
    26.61Close
    
    
    32.14
    
    
    
    34.92
    
    
    
    37.21
    
    
    
    44.42
    
    
    
    29.84
    
    
    
    31.19
    
    
    
    29.00
    
    
    
    28.70
 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 27, 2004, there were 15,422 holders of record of common shares
of the Company. Issuer purchases of equity securities (1) (c) Total number of shares
    
    (d) Maximum number (or appropriate(a) Total number
    
    
    
    
    
    purchased as part
    
    dollar value) or shares thatof shares
    
    (b) Average price
    
    of publicly announced
    
    may yet be purchased underPeriod
    
    purchased
    
    paid per share
    
    plans or programs
    
    the plans or programsOctober 2003
(October 1 - October 31)
    
    
    1,088,546
    
    
    $
    51.94
    
    
    
    1,088,546
    
    
    
    12,971,885November 2003
(November 1 -November 30)
    
    
    2,343,788
    
    
    $
    52.08
    
    
    
    2,343,788
    
    
    
    10,628,097December 2003
(December 1 - December 31)
    
    
    1,864,647
    
    
    $
    54.49
    
    
    
    1,864,647
    
    
    
    8,763,450
  (1)
    
    The purchases were pursuant to a 12 month normal course share
purchase program that was renewed on June 23, 2003 under which the
Company may purchase up to 18,632,218 of its outstanding common share
less any shares purchased by the employee savings plan and Company
pension fund. If not previously terminated, the program will terminate
on June 22, 2004. 16




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##### Table of Contents



Item 6. Selected Financial Data. 2003
    
    2002
    
    2001
    
    2000
    
    1999(millions)Total revenues
    
    $
    19,208
    
    
    $
    17,042
    
    
    $
    17,253
    
    
    $
    18,051
    
    
    $
    12,853Net earnings
    
    
    1,682
    
    
    
    1,224
    
    
    
    1,255
    
    
    
    1,410
    
    
    
    628Total assets
    
    
    12,361
    
    
    
    11,894
    
    
    
    10,781
    
    
    
    11,244
    
    
    
    10,828Long term debt
    
    
    859
    
    
    
    1,466
    
    
    
    1,029
    
    
    
    1,037
    
    
    
    1,352Other long term obligations
    
    
    972
    
    
    
    1,207
    
    
    
    1,098
    
    
    
    1,104
    
    
    
    1,172
 (dollars)Net earnings/share  basic
    
    
    4.52
    
    
    
    3.23
    
    
    
    3.19
    
    
    
    3.38
    
    
    
    1.46Net earnings/share  diluted
    
    
    4.52
    
    
    
    3.23
    
    
    
    3.19
    
    
    
    3.38
    
    
    
    1.46Cash dividends/share
    
    
    0.87
    
    
    
    0.84
    
    
    
    0.83
    
    
    
    0.78
    
    
    
    0.75
 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. Reconciliation of Canadian and United States generally accepted accounting
principles 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: 2003
    
    2002
    
    2001
    
    2000
    
    1999(millions)Net earnings as shown in
financial statements (a)
    
    $
    1,682
    
    
    $
    1,224
    
    
    $
    1,255
    
    
    $
    1,410
    
    
    $
    628Impact of U.S. accounting principles:Capitalized interest (1)
    
    
    19
    
    
    
    4
    
    
    
    (3
    )
    
    
    (3
    )
    
    
    (3
    )Enacted tax rate difference (2)
    
    
    
    
    
    
    
    
    
    
    (13
    )
    
    
    13
    
    
    
    Restatement to reflect accounting
changes (3)
    
    
    
    
    
    
    (14
    )
    
    
    (16
    )
    
    
    (12
    )
    
    
    (7
    )Net earnings under U.S. GAAP before
cumulative effect of accounting change
    
    $
    1,701
    
    
    $
    1,214
    
    
    $
    1,223
    
    
    $
    1,408
    
    
    $
    618Cumulative effect of accounting change
    
    
    4
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Net earnings under U.S. GAAP (a)
    
    $
    1,705
    
    
    $
    1,214
    
    
    $
    1,223
    
    
    $
    1,408
    
    
    $
    618Other comprehensive income (expense), net of
tax (7):Minimum pension liability adjustment
(net of tax expense of $57 million
in 2003;
2002  $155 million benefit; 2001 
$34 million benefit;
    
    
    49
    
    
    
    (238
    )
    
    
    (52
    )
    
    
    (16
    )
    
    
    22Comprehensive income under U.S. GAAP
    
    $
    1,754
    
    
    $
    976
    
    
    $
    1,171
    
    
    $
    1,392
    
    
    $
    640
    (a) Net earnings/share
    
    (dollars)Under accounting principles of:Canada  basic
    
    
    4.52
    
    
    
    3.23
    
    
    
    3.19
    
    
    
    3.38
    
    
    
    1.46 diluted
    
    
    4.52
    
    
    
    3.23
    
    
    
    3.19
    
    
    
    3.38
    
    
    
    1.46United States  basic
    
    
    4.58
    
    
    
    3.20
    
    
    
    3.11
    
    
    
    3.37
    
    
    
    1.43 diluted
    
    
    4.58
    
    
    
    3.20
    
    
    
    3.11
    
    
    
    3.37
    
    
    
    1.43
 Notes (1) through (9) 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
    
    As atDecember 31, 2003
    
    December 31, 2002(millions)
    
    (millions)As
    
    U.S.
    
    As
    
    U.S.Reported
    
    GAAP
    
    Reported
    
    GAAPCurrent assets (6)
    
    $
    2,275
    
    
    $
    2,275
    
    
    $
    2,657
    
    
    $
    2,657Future income tax assets (5)
    
    
    353
    
    
    
    502
    
    
    
    323
    
    
    
    530Investments and other long term assets (4) (6)
    
    
    259
    
    
    
    97
    
    
    
    134
    
    
    
    134Property, plant and equipment  cost (1)
    
    
    19,288
    
    
    
    19,433
    
    
    
    18,078
    
    
    
    18,130Property, plant and equipment 
accumulated depreciation and depletion (1)
    
    
    (10,070
    )
    
    
    (10,166
    )
    
    
    (9,553
    )
    
    
    (9,610
    )Goodwill
    
    
    204
    
    
    
    204
    
    
    
    204
    
    
    
    204Other intangible assets  cost (4)
    
    
    87
    
    
    
    176
    
    
    
    81
    
    
    
    195 accumulated depreciation
and depletion
    
    
    (35
    )
    
    
    (35
    )
    
    
    (30
    )
    
    
    (30
    )$
    12,361
    
    
    $
    12,486
    
    
    $
    11,894
    
    
    $
    12,210(continued on the following page)
 17




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##### Table of Contents



As at
    
    As atDecember 31, 2003
    
    December 31, 2002(millions)
    
    (millions)As
    
    U.S.
    
    As
    
    U.S.Reported
    
    GAAP
    
    Reported
    
    GAAPCurrent liabilities (6)
    
    $
    2,889
    
    
    $
    2,889
    
    
    $
    2,743
    
    
    $
    2,743Current portion of long term debt
    
    
    501
    
    
    
    501
    
    
    
    
    
    
    
    Long term debt (6)
    
    
    859
    
    
    
    859
    
    
    
    1,466
    
    
    
    1,466Other long term obligations (4)
    
    
    972
    
    
    
    1,314
    
    
    
    1,207
    
    
    
    1,823Future income tax liabilities (5)
    
    
    1,362
    
    
    
    1,378
    
    
    
    1,262
    
    
    
    1,267Shareholders equity
    
    
    5,778
    
    
    
    5,545
    
    
    
    5,216
    
    
    
    4,911Total liabilities, deferred income taxes and
shareholders equity
    
    $
    12,361
    
    
    $
    12,486
    
    
    $
    11,894
    
    
    $
    12,210Shareholders Equity:Common shares at stated valueAt beginning of year
    
    $
    1,939
    
    
    $
    1,939
    
    
    $
    1,941
    
    
    $
    1,941Share purchases at stated value (net)
    
    
    (80
    )
    
    
    (80
    )
    
    
    (2
    )
    
    
    (2
    )At end of year
    
    $
    1,859
    
    
    $
    1,859
    
    
    $
    1,939
    
    
    $
    1,939Retained earningsAt beginning of year
    
    $
    3,277
    
    
    $
    3,287
    
    
    $
    2,382
    
    
    $
    2,402Net earnings for the year
    
    
    1,682
    
    
    
    1,705
    
    
    
    1,224
    
    
    
    1,214Share purchases in excess of stated value
    
    
    (717
    )
    
    
    (717
    )
    
    
    (11
    )
    
    
    (11
    )Dividends
    
    
    (323
    )
    
    
    (323
    )
    
    
    (318
    )
    
    
    (318
    )At end of year
    
    $
    3,919
    
    
    $
    3,952
    
    
    $
    3,277
    
    
    $
    3,287Accumulated other comprehensive income/(loss)At beginning of year
    
    
    
    
    
    
    (315
    )
    
    
    
    
    
    
    (77
    )Other comprehensive income for the period
    
    
    
    
    
    
    49
    
    
    
    
    
    
    
    (238
    )At end
    
    
    
    
    
    
    (266
    )
    
    
    
    
    
    
    (315
    )Total shareholders equity
    
    $
    5,778
    
    
    $
    5,545
    
    
    $
    5,216
    
    
    $
    4,911
   (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 2003 was $38 million of which $34
million was capitalized under U.S. GAAP. The Companys financing costs
including debt related expense are reported in note 12 to the financial
statements on page F-17. At December 31, 2003, the unamortized balance
of capitalized interest under U.S. GAAP was $49 million (2002  $21
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 2003.(3)
    
    When a change in accounting policy is applied retroactively, Canadian GAAP
require the restatement of all prior periods presented to give effect to the
new accounting policy for comparative purposes. Under U.S. GAAP, the cumulative
effect, based on a retroactive computation, is recognized in net earnings for
the period of the change.Net earnings as shown in the financial statements have been restated to reflect
the adoption of the new standard of accounting for asset retirement obligations
(ARO). The adjustment is to remove the restatement effect on earnings for all
prior periods presented. Under Canadian GAAP, the following balance sheet
accounts (as reported) have also been restated: property, plant and equipment,
other long term obligations, future income tax liabilities and retained
earnings.(4)
    
    Disclosures required under revised Statement of Financial Accounting
Standards (SFAS) No. 132 Employers Disclosures about Pensions and Other
Postretirement Benefits that are not in note 5 to the financial
statements on pages F-12 and F-13 are as follows: Pension Benefits2003
    
    2002(millions)Liability recognized under Canadian GAAP
    
    $
    (219
    )
    
    $
    (388
    )Prepaid benefit cost recognized under Canadian GAAP
    
    
    162
    
    
    
    Intangible asset
    
    
    (89
    )
    
    
    (114
    )Accumulated other comprehensive income (before tax)
    
    
    (415
    )
    
    
    (521
    )Net liability recognized under U.S. GAAP
    
    $
    (561
    )
    
    $
    (1,023
    )
  Under Canadian GAAP, a prepaid benefit cost was recognized as funding exceeded
the book liability for the registered pension plan. Under U.S. GAAP, a minimum
pension liability adjustment was required resulting in book liability exceeding
funding and no prepaid benefit cost existed. As a result, a reclassification of
the prepaid benefit cost from investments and other long term assets to other
long term obligation was required under U.S. GAAP.An adjustment required by SFAS No. 130 remains a CanadianU.S. GAAP difference
(see note 7). (Continued on following page) 18




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The accumulated benefit obligation for all the defined
pension plans was $3,347
million and $3,127 million at December 31, 2003 and 2002 respectively.A summary of pension plans with accumulated benefit obligation in excess of
plan assets is shown in the table below: Pension Benefits2003
    
    2002(millions)For funded pension plans with accumulated benefit obligations
in excess of plan assets:Projected benefit obligations
    
    $
    3,464
    
    
    $
    3,230Accumulated benefit obligation
    
    
    3,126
    
    
    
    2,895Fair value of plan assets
    
    
    2,786
    
    
    
    2,104Accumulated benefit obligation less fair value of plan assets
    
    
    340
    
    
    
    791For unfunded plans covered by book reserves:Projected benefit obligation
    
    
    297
    
    
    
    300Accumulated benefit obligation
    
    
    221
    
    
    
    232
  In 2004, the Company expects to make cash contributions of about $110 million
to the pension plans.(5)
    
    Differences from the adjustments described in notes (1) and (7) result in
future (deferred) income tax liabilities (net of future income tax assets) that
are $133 million lower at December 31, 2003 than reported under Canadian GAAP
(2002  $202 million lower).(6)
    
    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 are as follows: 2003
    
    2002Carrying
    
    Fair
    
    Carrying
    
    FairAmount
    
    Value
    
    Amount
    
    Value(millions)AssetsCash
    
    $
    448
    
    
    $
    448
    
    
    $
    766
    
    
    $
    766Accounts receivable
    
    
    1,315
    
    
    
    1,315
    
    
    
    1,348
    
    
    
    1,348Other long term assets (receivable)
    
    
    20
    
    
    
    18
    
    
    
    60
    
    
    
    59Liabilities:Current
    
    
    (2,889
    )
    
    
    (2.889
    )
    
    
    (2,743
    )
    
    
    (2,743
    )Current portion of long term debt
    
    
    (501
    )
    
    
    (501
    )
    
    
    
    
    
    
    Long term debt
    
    
    (859
    )
    
    
    (859
    )
    
    
    (1,466
    )
    
    
    (1,466
    )
  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.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.(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 $49 million gain recognized in 2003 (2002 
$238 million loss; 2001  $52 million loss) represents a reduction of the
additional pension liability under U.S. GAAP in the current period.(8)
    
    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. (Continued on following page) 19




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Effective January 1, 2003, the Company adopted 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 compensationThe 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 as long as the
exercise price is equal to the market value at date of grant. The Companys
incentive compensation programs are described in note 8 to the financial
statements on page F-15.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: 2003
    
    2002
    
    2001(millions)Net earnings as shown in financial statements
    
    $
    1,682
    
    
    $
    1,224
    
    
    $
    1,255Stock-based compensation expense as reported, net of tax
    
    
    78
    
    
    
    24
    
    
    
    30Stock-based compensation expense, net of tax,
determined under fair value based method
    
    
    (83
    )
    
    
    (40
    )
    
    
    (30
    )Pro forma net earnings
    
    $
    1,677
    
    
    $
    1,208
    
    
    $
    1,255Net earnings/share:
    
    
    
    
    
    (dollars)As reported  basic and diluted
    
    
    4.52
    
    
    
    3.23
    
    
    
    3.19Pro forma  basic and diluted
    
    
    4.51
    
    
    
    3.19
    
    
    
    3.19
  (9)
    
    In December 2003, the Financial Accounting Standards Board issued a
revised interpretation No. 46 (FIN 46), Consolidation of Variable
Interest Entities, replacing the original interpretation issued in
January 2003. FIN 46 provides guidance on when certain entities should
be consolidated or the interests in those entities should be disclosed
by enterprises that do not control them through majority voting
interest. Under FIN 46, entities are required to be consolidated by
enterprises that lack majority voting interest when equity investors of
those entities have insignificant capital at risk or they lack voting
rights, the obligation to absorb expected losses, or the right to
receive expected returns. Entities identified with these characteristics
are called variable interest entities and the interests that enterprises
have in these entities are called variable interests. These interests
can derive from certain guarantees, leases, loans, or other arrangements
that result in risks and rewards that are disproportionate to the voting
interests in the entities.The provisions of FIN 46 must be immediately applied for variable interest
entities created after January 31, 2003 and for variable interests in
entities commonly referred to as special purpose entities. For all other
variable interest entities, implementation is required by March 31, 2004.This interpretation does not have an impact on the Company as the Company
does not have a variable interest in any variable interest entities created
before or after January 31, 2003. Frequently used financial terms Listed below are definitions of three of the Companys frequently used
financial performance measures. The definitions are provided to facilitate
understanding of the terms and how they are calculated. These terms do not have
any standardized meaning prescribed by Canadian generally accepted accounting
principles (GAAP) and may not be calculated in the same way as similar measures
are by other companies. Capital employed Capital employed is a measure of net investment. When viewed from the
perspective of how capital is used by the business, it includes the Companys
property, plant and equipment and other assets, less liabilities, excluding
both short term and long term debt. When viewed from the perspective of the
sources of capital employed for the total company, it includes total debt and
shareholders equity. Both of these views include the Companys share of
amounts applicable to equity companies. 2003
    
    2002
    
    2001(millions)Business uses: asset and liability perspective
Total assets
    
    $
    12,361
    
    
    $
    11,894
    
    
    $
    10,781Less: total current liabilities excluding short-term debt and
current portion of long-term debt
    
    
    (2,817
    )
    
    
    (2,671
    )
    
    
    (2,565
    )Less: total long-term liabilities excluding long-term debt
    
    
    (2,334
    )
    
    
    (2,469
    )
    
    
    (2,404
    )Add: Imperials share of debt-financed equity company net
assets
    
    
    52
    
    
    
    49
    
    
    
    29Total capital employed
    
    $
    7,262
    
    
    $
    6,803
    
    
    $
    5,841
 (Continued on following page) 20




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##### Table of Contents



2003
    
    2002
    
    2001(millions)Total company sources: debt and equity perspectiveShort-term debt
    
    $
    72
    
    
    $
    72
    
    
    $
    460Current portion of long-term debt
    
    
    501
    
    
    
    
    
    
    
    Long-term debt
    
    
    859
    
    
    
    1,466
    
    
    
    1,029Shareholders equity
    
    
    5,778
    
    
    
    5,216
    
    
    
    4,323Add: Imperials share of equity company debt
    
    
    52
    
    
    
    49
    
    
    
    29Total capital employed
    
    $
    7,262
    
    
    $
    6,803
    
    
    $
    5,841
 Operating costs Operating costs are the combined total of operating, selling, general,
exploration, depreciation and depletion expenses from the consolidated
statement of earnings and the Companys share of similar costs for equity
companies. Operating costs are the costs incurred during the period to produce,
manufacture and otherwise prepare the Companys products for sale  including
staffing, maintenance, and other costs to explore for and produce oil and gas
and operate refining and chemical plants. Delivery costs to customers and
marketing expenses are also included. Operating costs exclude the cost of raw
materials and those costs incurred in bringing inventory to its existing
condition and final storage prior to delivery to a customer. These expenses are
on a before tax basis. While the Companys management is responsible for all
revenue and expense elements of net earnings, particular focus is placed on
managing the controllable aspects of this group of expenses. 2003
    
    2002
    
    2001(millions)Expenses (from page F-3)Exploration
    
    $
    55
    
    
    $
    30
    
    
    $
    45Operating
    
    
    2,025
    
    
    
    1,865
    
    
    
    1,830Selling and general
    
    
    1,269
    
    
    
    1,222
    
    
    
    1,280Depreciation and depletion
    
    
    750
    
    
    
    705
    
    
    
    718Subtotal
    
    $
    4,099
    
    
    $
    3,822
    
    
    $
    3,873Imperials share of equity company expenses
    
    
    56
    
    
    
    49
    
    
    
    42Total operating costs
    
    $
    4,155
    
    
    $
    3,871
    
    
    $
    3,915
 Cash flow from earnings Cash flow from earnings is determined by adjusting net earnings for the
effects of non cash items. It measures the extent of cash generated from the
business before the effects of changes in non cash working capital and before
any investing and financing activities by the Company. Cash flow from earnings
is a measure used by the Companys management for analysis and evaluation of
operating performance and liquidity of each business segment and for future
investment decisions. A reconciliation of net earnings to cash flow from
earnings is provided in the consolidated statement of cash flows on page F-4. 
 Item 7. Managements Discussion and Analysis of Financial Condition and Results of Operation. Financial Summary 2003
    
    2002
    
    2001
    
    2000
    
    1999(millions)Revenues
    
    $
    19,208
    
    
    $
    17,042
    
    
    $
    17,253
    
    
    $
    18,051
    
    
    $
    12,853Net earnings by segmentNatural resources
    
    
    1,139
    
    
    
    1,056
    
    
    
    957
    
    
    
    1,177
    
    
    
    567Petroleum products
    
    
    407
    
    
    
    127
    
    
    
    353
    
    
    
    313
    
    
    
    15Chemicals
    
    
    37
    
    
    
    52
    
    
    
    23
    
    
    
    59
    
    
    
    43Corporate and other
    
    
    99
    
    
    
    (11
    )
    
    
    (78
    )
    
    
    (139
    )
    
    
    3Net earnings
    
    $
    1,682
    
    
    $
    1,224
    
    
    $
    1,255
    
    
    $
    1,410
    
    
    $
    628Total assets
    
    $
    12,361
    
    
    $
    11,894
    
    
    $
    10,781
    
    
    $
    11,244
    
    
    $
    10,828Long term debt
    
    
    859
    
    
    
    1,466
    
    
    
    1,029
    
    
    
    1,037
    
    
    
    1,352Other long term obligations
    
    
    972
    
    
    
    1,207
    
    
    
    1,098
    
    
    
    1,104
    
    
    
    1,172Per share information (dollars)Earnings per share  basic and diluted
    
    
    4.52
    
    
    
    3.23
    
    
    
    3.19
    
    
    
    3.38
    
    
    
    1.46Dividends
    
    
    0.87
    
    
    
    0.84
    
    
    
    0.83
    
    
    
    0.78
    
    
    
    0.75
 21




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##### Table of Contents



Results of operations Net earnings in 2003 were $1,682 million or $4.52 a share  the best year
on record  compared with $1,224 million or $3.23 a share in 2002 (2001 
$1,255 million or $3.19 a share). Higher realizations for natural gas and crude
oil and higher industry margins for petroleum products, partly offset by the
negative impact of a higher Canadian dollar, were the main reasons for the
increased earnings. Total revenues were $19.2 billion, up about 13 percent from 2002. Natural Resources Earnings from natural resources were $1,139 million, up from $1,056
million in 2002 (2001  $957 million). Higher realizations for natural gas and
crude oil and higher production of Cold Lake bitumen were largely offset by the
negative impact of a higher Canadian dollar. Resource revenues were $5.6 billion, up from $4.9 billion in 2002 (2001 
$5.3 billion). The main reasons for the increase were higher prices for natural
gas and crude oil and increased production from Cold Lake. Financial statistics 2003
    
    2002
    
    2001
    
    2000
    
    1999(millions)Net earnings
    
    $
    1,139
    
    
    $
    1,056
    
    
    $
    957
    
    
    $
    1,177
    
    
    $
    567Revenues
    
    
    5,648
    
    
    
    4,894
    
    
    
    5,321
    
    
    
    5,900
    
    
    
    3,904
 World oil prices strengthened considerably in early 2003 and remained
relatively strong due to a combination of world supply concerns and increased
world demand. The annual average price of Brent crude oil, the most actively
traded North Sea crude and a common benchmark of world oil markets, was $29
(U.S.) a barrel in 2003, compared with $25 in 2002 (2001  $24.50). The increase in the Companys realizations on sales of conventional
Canadian crude oil was diminished by the strengthening of the Canadian dollar.
Average realizations during the year were $40.10 (Cdn) a barrel versus $36.81
in 2002 (2001  $35.56). Average prices for Canadian heavy crude oil were higher in 2003, but not
as high as those for lighter crude oil, as increased supply of Canadian heavy
crude oil widened the average spread between light and heavy crude. The price
of Bow River, a benchmark Canadian heavy crude oil, increased by four percent
in 2003, compared with a nine percent increase in prices for Canadian light
crude oil. Average realizations for Cold Lake bitumen were about two percent
lower than the previous year, as the stronger Canadian dollar offset any price
increases. Prices for Canadian natural gas in 2003 were higher on average than in the
previous year. The average of 30 day spot prices for natural gas at the AECO
hub in Alberta was about $6.70 a thousand cubic feet in 2003, up from $4.10 in
2002 (2001  $6.30). The Companys average realizations on natural gas sales increased to $6.60
a thousand cubic feet from $4.02 in 2002 (2001  $5.72). Average realizations and
prices 2003
    
    2002
    
    2001
    
    2000
    
    1999Conventional crude oil realizations (a barrel)
    
    $
    40.10
    
    
    $
    36.81
    
    
    $
    35.56
    
    
    $
    41.52
    
    
    $
    24.75Natural gas realizations (a thousand cubic feet)
    
    
    6.60
    
    
    
    4.02
    
    
    
    5.72
    
    
    
    4.99
    
    
    
    2.66Par crude oil price at Edmonton (a barrel)
    
    
    43.93
    
    
    
    40.44
    
    
    
    39.64
    
    
    
    45.02
    
    
    
    27.80Heavy crude oil price at Hardisty
(Bow River, a barrel)
    
    
    33.00
    
    
    
    31.85
    
    
    
    25.11
    
    
    
    34.49
    
    
    
    23.51
 Gross production of crude oil and natural gas liquids (NGLs) increased to
256,000 barrels a day from 247,000 barrels in 2002 (2001  267,000). Net
production increased slightly to 225,000 barrels a day from 223,000 barrels in
2002 (2001  237,000). Net bitumen production at the Companys wholly owned facilities at Cold
Lake increased to 116,000 barrels a day from 106,000 barrels in 2002 (2001 
121,000). The higher volume was a result of the initial production cycles from
phases 11  13, which began operation in December 2002. This was offset in part
by lower production from existing operations, due to the cyclic nature of
production at Cold Lake. The effective royalty rate on Cold Lake production increased in 2003, as
capital expenditures were lower upon the completion of phases 11  13. The rate
increased to 10 percent of production from five percent in 2002 (2001  five
percent). 22




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##### Table of Contents



Production from the Syncrude operation, in which the Company has a 25
percent interest, decreased during 2003 as increased unplanned maintenance
affected production through much of the year. Gross production of upgraded
crude oil dropped to 211,000 barrels a day from 229,000 barrels in 2002 (2001 
223,000). The Companys share of average net production decreased to 52,000
barrels a day from 57,000 barrels in 2002 (2001  52,000). Net production of conventional oil decreased to 35,000 barrels a day from
39,000 barrels in 2002 (2001  42,000) as a result of the natural decline in
western Canadian reservoirs. Gross production of natural gas decreased to 513 million cubic feet a day
from 530 million in 2002 (2001  572 million). Net production was 457 million
cubic feet a day in 2003, down from 463 million in 2002 (2001  466 million).
Net production available for sale decreased to 390 million cubic feet a day
from 396 million in 2002 (2001  376 million). Lower production as a result of
reservoir decline was mostly offset by production from the new facilities at
Wizard Lake in Alberta, which were completed in the third quarter of 2003. Crude oil and NGLs 
production and sales (a) 2003
    
    2002
    
    2001
    
    2000
    
    1999gross
    
    net
    
    gross
    
    net
    
    gross
    
    net
    
    gross
    
    net
    
    gross
    
    net(thousands of barrels a day)Conventional crude oil
    
    
    46
    
    
    
    35
    
    
    
    51
    
    
    
    39
    
    
    
    55
    
    
    
    42
    
    
    
    60
    
    
    
    46
    
    
    
    65
    
    
    
    51Cold Lake
    
    
    129
    
    
    
    116
    
    
    
    112
    
    
    
    106
    
    
    
    128
    
    
    
    121
    
    
    
    119
    
    
    
    102
    
    
    
    132
    
    
    
    107Syncrude
    
    
    53
    
    
    
    52
    
    
    
    57
    
    
    
    57
    
    
    
    56
    
    
    
    52
    
    
    
    51
    
    
    
    42
    
    
    
    56
    
    
    
    55Total crude oil production
    
    
    228
    
    
    
    203
    
    
    
    220
    
    
    
    202
    
    
    
    239
    
    
    
    215
    
    
    
    230
    
    
    
    190
    
    
    
    253
    
    
    
    213NGLs available for sale (b)
    
    
    28
    
    
    
    22
    
    
    
    27
    
    
    
    21
    
    
    
    28
    
    
    
    22
    
    
    
    30
    
    
    
    23
    
    
    
    31
    
    
    
    24Total crude oil and NGL production
    
    
    256
    
    
    
    225
    
    
    
    247
    
    
    
    223
    
    
    
    267
    
    
    
    237
    
    
    
    260
    
    
    
    213
    
    
    
    284
    
    
    
    237Cold Lake sales,including diluent (c)
    
    
    170
    
    
    
    
    
    
    
    145
    
    
    
    
    
    
    
    167
    
    
    
    
    
    
    
    156
    
    
    
    
    
    
    
    173NGL sales
    
    
    39
    
    
    
    
    
    
    
    40
    
    
    
    
    
    
    
    43
    
    
    
    
    
    
    
    42
    
    
    
    
    
    
    
    43
 Natural gas  production and sales (a) 2003
    
    2002
    
    2001
    
    2000
    
    1999gross
    
    net
    
    gross
    
    net
    
    gross
    
    net
    
    gross
    
    net
    
    gross
    
    net(millions of cubic feet a day)Production (d)
    
    
    513
    
    
    
    457
    
    
    
    530
    
    
    
    463
    
    
    
    572
    
    
    
    466
    
    
    
    526
    
    
    
    459
    
    
    
    469
    
    
    
    413Production available for sale (b)
    
    
    446
    
    
    
    390
    
    
    
    463
    
    
    
    396
    
    
    
    482
    
    
    
    376
    
    
    
    345
    
    
    
    277
    
    
    
    300
    
    
    
    244Sales
    
    
    460
    
    
    
    
    
    
    
    499
    
    
    
    
    
    
    
    502
    
    
    
    
    
    
    
    419
    
    
    
    
    
    
    
    393
   (a)
    
    Daily volumes are calculated by dividing total volumes for the year by the
number of days in the year. Gross production is the Companys share of
production (excluding purchases) before deducting the shares of mineral owners
or governments or both. Net production excludes those shares.(b)
    
    Production available for sale excludes amounts used for internal
consumption and amounts reinjected. Starting in 2001, production available for
sale reflects a change in the supply of natural gas to Company operations from
Company produced gas to third party purchased gas.(c)
    
    Includes natural gas condensate added to the Cold Lake bitumen to
facilitate transportation to market by pipeline.(d)
    
    Production of natural gas
includes amounts used for internal consumption with the exception of amounts
reinjected. Operating costs increased by 11 percent in 2003. The main factors were
increased costs associated with the newly completed phases 11  13 and
cogeneration facilities at Cold Lake, unplanned maintenance at Syncrude and
increased exploration costs. Petroleum Products Net earnings from petroleum products were a record $407 million or 1.3
cents a litre in 2003, up from $127 million or 0.4 cents a litre in 2002 (2001
 $353 million or 1.2 cents a litre). Earnings improved mainly as a result of
the strengthening of industry petroleum product margins and increased sales
volumes, partly offset by the negative impact of a higher Canadian dollar. Revenues were $16.1 billion, up from $14.4 billion in 2002 (2001  $14.4
billion). 23




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##### Table of Contents



Financial statistics 2003
    
    2002
    
    2001
    
    2000
    
    1999(millions)Net earnings
    
    $
    407
    
    
    $
    127
    
    
    $
    353
    
    
    $
    313
    
    
    $
    15Revenues
    
    
    16,058
    
    
    
    14,434
    
    
    
    14,405
    
    
    
    15,120
    
    
    
    10,665
 Sales of petroleum products 2003
    
    2002
    
    2001
    
    2000
    
    1999(millions of litres a day (a))Gasolines
    
    
    33.0
    
    
    
    32.9
    
    
    
    32.3
    
    
    
    32.0
    
    
    
    31.9Heating,diesel and jet fuels
    
    
    26.2
    
    
    
    25.0
    
    
    
    26.5
    
    
    
    27.5
    
    
    
    26.9Heavy fuel oils
    
    
    5.4
    
    
    
    4.9
    
    
    
    5.4
    
    
    
    5.1
    
    
    
    4.6Lube oils and other products
    
    
    5.8
    
    
    
    6.4
    
    
    
    5.4
    
    
    
    5.0
    
    
    
    5.8Net petroleum products sales
    
    
    70.4
    
    
    
    69.2
    
    
    
    69.6
    
    
    
    69.6
    
    
    
    69.2Sales under purchase and sale agreements
    
    
    14.6
    
    
    
    13.9
    
    
    
    11.6
    
    
    
    10.7
    
    
    
    10.8Total sales of petroleum products
    
    
    85.0
    
    
    
    83.1
    
    
    
    81.2
    
    
    
    80.3
    
    
    
    80.0Total domestic sales of petroleum
products (percent)
    
    
    93.3
    
    
    
    91.5
    
    
    
    93.4
    
    
    
    94.0
    
    
    
    95.6
 Refinery utilization 2003
    
    2002
    
    2001
    
    2000
    
    1999(millions of litres a day (a))Total refinery throughput (b)
    
    
    71.6
    
    
    
    71.2
    
    
    
    71.4
    
    
    
    71.6
    
    
    
    70.1Refinery capacity at December 31
    
    
    79.9
    
    
    
    79.4
    
    
    
    79.1
    
    
    
    78.7
    
    
    
    78.7Utilization of total refinery capacity (percent)
    
    
    90
    
    
    
    90
    
    
    
    90
    
    
    
    91
    
    
    
    89
   (a)
    
    Volumes a day are calculated by dividing total volumes for the year by
the number of days in the year.(b)
    
    Crude oil and feedstocks sent directly to
atmospheric distillation units One thousand litres is approximately 6.3 barrels. Margins were higher in the refining segment of the industry in 2003
compared with those in 2002, as international wholesale product prices
increased more than raw material costs. However, the effects of higher
international margins were reduced partially by a higher Canadian dollar. The Companys total sales volumes, including those resulting from
reciprocal supply agreements with other companies, were 85 million litres a
day, compared with 83.1 million litres in 2002 (2001  81.2 million). Excluding
sales resulting from reciprocal agreements, sales were 70.4 million litres a
day, compared with 69.2 million litres in 2002 (2001  69.6 million). Operating costs increased by about five percent in 2003 from the previous
year, mainly because of higher energy costs and expenses related to increased
sales volumes. Chemicals Earnings from chemical operations were $37 million in 2003, down from $52
million in 2002 (2001 $23 million). Reduced industry margins on sales of
polyethylene as a result of higher feedstock costs and weaker industry demand
were the main reasons for the decrease in earnings. Total revenues from chemical operations were $1,232 million, compared with
$1,164 million in 2002 (2001  $1,175 million). Gains from higher prices for
polyethylene, intermediate chemicals and aromatics during 2003 more than offset
lower sales volumes. Financial statistics 2003
    
    2002
    
    2001
    
    2000
    
    1999(millions)Net earnings
    
    $
    37
    
    
    $
    52
    
    
    $
    23
    
    
    $
    59
    
    
    $
    43Revenues
    
    
    1,232
    
    
    
    1,164
    
    
    
    1,175
    
    
    
    1,173
    
    
    
    872
 The average industry price of polyethylene was $1,415 a tonne in 2003, up
15 percent from $1,229 a tonne in 2002 (2001  $1,284). However, margins were
reduced because of higher feedstock costs, reflecting increased prices for
natural gas. 24




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##### Table of Contents



Sales of chemicals decreased to 3,300 tonnes a day from 3,500 tonnes in
2002 (2001  3,300 tonnes) as a result of reduced demand. Sales volumes 2003
    
    2002
    
    2001
    
    2000
    
    1999(thousands of tonnes a day (a)Polymers & basic chemicals
    
    
    2.4
    
    
    
    2.5
    
    
    
    2.4
    
    
    
    2.2
    
    
    
    2.0Intermediates and other
    
    
    0.9
    
    
    
    1.0
    
    
    
    0.9
    
    
    
    0.9
    
    
    
    1.0Total chemicals
    
    
    3.3
    
    
    
    3.5
    
    
    
    3.3
    
    
    
    3.1
    
    
    
    3.0
   (a)
    
    Volumes a day are calculated by dividing total volumes for the year by
the number of days in the year. One tonne is approximately 1.1 short tons or
0.98 long tons. Operating costs in the chemicals segment increased by about four percent
in 2003 mainly because of higher planned capital project related expenses. Corporate and other Earnings from corporate and other accounts were positive $99 million in
2003, compared with negative $11 million in 2002 (2001  negative $78 million).
The improvement was mainly attributable to favourable foreign exchange effects
on the Companys U.S. dollar denominated debt. The Company retired the
remaining balance of its U.S. dollar denominated debt in 2003. Liquidity and capital resources Cash flow from earnings was $2,354 million, up from $1,781 million in 2002
(2001  $2,016 million), mainly because of increased earnings. Cash provided
from operating activities was $2,194 million, compared with $1,676 million in
2002 (2001  $2,004 million). The increased cash inflow was mainly due to
higher earnings, timing of scheduled income tax payments and the effects of
commodity prices on receivable and payable balances, partly offset by
additional funding contributions to the Companys registered pension plan. In June, the Company renewed the normal course issuer bid (share buyback
program) for another 12 months. During 2003, the Company purchased more than 16
million shares for $799 million. Since the Company initiated its first buyback
program in 1995, the Company has purchased 219 million shares  representing
about 38 percent of the total outstanding at the start of the program  with
resulting distributions to shareholders of $5,968 million. The Company declared dividends totalling 87 cents a share in 2003, up from
84 cents in 2002 (2001 83 cents). Regular per share dividends paid have
increased in each of the past nine years and, since 1986, payments a share have
grown by more than 55 percent. Following one of the largest capital investment programs in the Companys
history as well as funding contributions to the Companys registered pension
plan, the cash balance was $448 million at year end, compared with $766 million
at the end of 2002 (2001  $872 million). In 2003, the Company retired its $600 million U.S. variable rate debt, due
in 2004, for $818 million (Cdn) and replaced it with $818 million of Canadian
dollar denominated variable rate loans from Exxon Overseas Corporation at
interest equivalent to Canadian market rates. Total debt outstanding, excluding the Companys share of equity company
debt, at the end of 2003 was $1,432 million, compared with $1,538 million at
the end of 2002 (2001  $1,489 million). Debt represented 20 percent of the
Companys capital structure at the end of 2003, compared with 23 percent at the
end of 2002 (2001  26 percent). Debt related interest expense paid in 2003 was $38 million, down from $40
million in 2002 (2001  $77 million). The retirement of the Companys long term
fixed rate debt during the past few years was the main reason for the
reduction. The average effective interest rate on the Companys debt was 2.9
percent in 2003, compared with 2.1 percent in 2002 (2001  5.1 percent). 25




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##### Table of Contents



Financial percentages, ratios and credit rating 2003
    
    2002
    
    2001
    
    2000
    
    1999Total debt as a percentage of capital (a)
    
    
    20
    
    
    
    23
    
    
    
    26
    
    
    
    25
    
    
    
    24Interest coverage ratios
Earnings basis (b)
    
    
    63
    
    
    
    46
    
    
    
    26
    
    
    
    23
    
    
    
    9Cash flow basis (c)
    
    
    79
    
    
    
    63
    
    
    
    36
    
    
    
    29
    
    
    
    14
   (a)
    
    Current and long term portions of debt (page F-5) divided by debt and
shareholders equity (page F-5).(b)
    
    Net earnings (page F-3), debt related interest expense (page F-17, note 12)
and income taxes (page F-3) divided by debt related interest expense.(c)
    
    Cash flow from earnings (page F-4), current income tax expense (page F-12,
note 4) and debt related interest expense divided by debt related interest
expense. Capital and exploration expenditures Total capital and exploration expenditures were $1,526 million in 2003,
down slightly from $1,600 million in 2002 (2001  $1,115 million). The funds were used mainly to maintain and expand crude oil and natural
gas production capacity, to upgrade refineries to meet low sulphur gasoline
requirements and to enhance the Companys retail network. The following table shows the Companys capital and exploration
expenditures for natural resources during the five years ending December 31,
2003: 2003
    
    2002
    
    2001
    
    2000
    
    1999(millions)Exploration
    
    $
    57
    
    
    $
    39
    
    
    $
    49
    
    
    $
    56
    
    
    $
    29Production
    
    
    181
    
    
    
    143
    
    
    
    109
    
    
    
    110
    
    
    
    138Heavy oil
    
    
    769
    
    
    
    804
    
    
    
    588
    
    
    
    268
    
    
    
    263Total
    
    $
    1,007
    
    
    $
    986
    
    
    $
    746
    
    
    $
    434
    
    
    $
    430
 For the natural resources segment, about 90 percent of the capital and
exploration expenditures in 2003 was focused on growth opportunities. The
single largest investment during the year was the Companys share of the
Syncrude expansion. The remainder of 2003 investment was directed to advancing
the Mackenzie gas project, drilling for conventional oil and gas in Western
Canada, and East Coast development and deepwater exploration. Planned capital and exploration expenditures in natural resources are
expected to total about $1 billion in 2004, with nearly 90 percent of the total
focused on growth opportunities. Much of the expenditure will be directed to
the expansion now underway at Syncrude. Investments are also planned for the
ongoing development drilling at Cold Lake, the Mackenzie gas project,
development of the Sable South Venture field and the Sable compression
platform, as well as further development drilling in Western Canada. Planned
expenditures for exploration and development drilling, as well as capacity
additions in conventional oil and gas operations, are expected to be about $320
million. The following table shows the Companys capital expenditures in the
petroleum products segment during the five years ending December 31, 2003: 2003
    
    2002
    
    2001
    
    2000
    
    1999(millions)Marketing
    
    $
    91
    
    
    $
    133
    
    
    $
    171
    
    
    $
    121
    
    
    $
    80Refining and supply
    
    
    368
    
    
    
    399
    
    
    
    118
    
    
    
    100
    
    
    
    114Other (a)
    
    
    19
    
    
    
    57
    
    
    
    50
    
    
    
    11
    
    
    
    9Total
    
    $
    478
    
    
    $
    589
    
    
    $
    339
    
    
    $
    232
    
    
    $
    203
   (a)
    
    Consists primarily of purchases of real estate. For the petroleum product segment, capital expenditures decreased to $478
million in 2003, compared with $589 million in 2002 (2001  $339 million),
primarily because of the completion of the project to significantly reduce
sulphur content in gasoline, which began in 2001. New investments in 2003
included the products segments $32 million share of capital expenditures on a
95 megawatt cogeneration facility to improve energy efficiency and reduce
emissions at the petroleum products and chemicals operations in Sarnia. In
addition, almost $60 million was spent on other refinery projects to improve
energy efficiency and increase yield. Major investments were also made to
upgrade the network of Esso retail outlets during the year. 26




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##### Table of Contents



Capital expenditures for the petroleum products segment in 2004 are
expected to be about $450 million. Major items include investment in refining
facilities to reduce the sulphur content in diesel to meet regulatory
requirement and continued enhancements to the Companys retail network. The following table shows the Companys capital expenditures for the
chemicals operations during the five years ending December 31, 2003. 2003
    
    2002
    
    2001
    
    2000
    
    1999(millions)Chemicals
    
    $
    41
    
    
    $
    25
    
    
    $
    30
    
    
    $
    13
    
    
    $
    20
 Of the capital expenditures for chemicals in 2003, the major investment
was the Sarnia cogeneration project, a joint development between the petroleum
products and chemicals operations at the site. Planned capital expenditures for chemicals in 2004 will be about $20
million. Funds will be used largely to improve energy efficiency and yields. Total capital and exploration expenditures for the Company in 2004, which
will focus mainly on growth and productivity improvements, are expected to
total about $1.5 billion and will be financed primarily from internally
generated funds. During 2003, the Company spent more than $310 million on projects related
to reducing the environmental impact of its operations and improving safety.
This included investments of more than $260 million in the Companys four
refineries as part of the capital project to produce low sulphur gasoline and
diesel fuels. Reporting investments in mineral interests in oil and gas properties The accounting standards for business combinations and goodwill and other
intangible assets issued by the Canadian Institute of Chartered Accountants
(CICA) became effective for the Company of July 1, 2001, and January 1, 2002,
respectively. These Canadian standards are harmonized with specific U.S.
standards in these areas. Currently, the Emerging Issues Task Force (EITF) of
the Financial Accounting Standards Board (FASB) is considering the issue of
whether the U.S. standards require interests held under oil, gas and mineral
leases to be separately classified as intangible assets on the balance sheets
of companies in the extractive industries. If such interests were deemed to be
intangible assets by the EITF, mineral rights to extract oil and gas for both
undeveloped and developed leaseholds would be classified separately from oil
and gas properties as intangible assets on the Companys balance sheet. The
EITF interpretation could potentially have an impact on the Canadian standards
and the Companys financial reporting. Historically, in accordance with
Canadian generally accepted accounting principles (GAAP), the Company has
capitalized the cost of oil and gas leasehold interests and reported these
assets as part of tangible oil and gas property, plant and equipment. This interpretation of the current U.S. standards would only affect the
classification of oil and gas leaseholds on the Companys balance sheet and
would not affect total assets, net worth or cash flows. The Companys results
of operations would not be affected, since these leasehold costs would continue
to be amortized in accordance with GAAP. The amount that is subject to
reclassification as of December 31, 2003, was $935 million and $1,109 million
as of December 31, 2002. Pension An independent actuarial valuation of the Companys registered pension
plan was completed in 2003. As a result of the valuation, the Company
contributed $500 million to the registered pension plan. While equity markets
improved in 2003 and the Companys contribution levels increased, the Company
plans to take a measured approach to the pace of funding, within the
requirements of pension regulations. However, pension liabilities need to be
assessed in light of the Companys strong credit position and prudent financial
management. The Company has in the past and expects to continue to use its
strong balance sheet to effectively manage pension liabilities. Future funding
requirements are not expected to affect the Companys existing capital
investment plans or its ability to pursue new investment opportunities. Contractual obligations To more fully explain the Companys financial position, the following
table shows the Companys contractual obligations outstanding at December 31,
2003. It brings together, for easier reference, data from the consolidated
balance sheet and from individual notes to consolidated financial statements. 27




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##### Table of Contents



Financial
    
    Payment due by periodstatement note
    
    
    
    
    
    2005 to
    
    2009 and
    
    Totalmillions of dollars
    
    reference
    
    2004
    
    2008
    
    beyond
    
    amountLong term debt & capital leases
    
    note 3
    
    $
    501
    
    
    $
    834
    
    
    $
    25
    
    
    $
    1,360Companys share of equity company debt
    
    
    
    
    
    
    52
    
    
    
    
    
    
    
    
    
    
    
    52Operating leases
    
    note 9
    
    
    72
    
    
    
    185
    
    
    
    114
    
    
    
    371Unconditional purchase obligations (a)
    
    note 9
    
    
    90
    
    
    
    161
    
    
    
    98
    
    
    
    349Firm capital commitments (b)
    
    note 9
    
    
    176
    
    
    
    13
    
    
    
    
    
    
    
    189Pension obligations (c)
    
    note 5
    
    
    138
    
    
    
    100
    
    
    
    318
    
    
    
    556Asset retirement obligations (d)
    
    note 6
    
    
    34
    
    
    
    112
    
    
    
    181
    
    
    
    327Other long term agreements (e)
    
    note 9
    
    
    260
    
    
    
    500
    
    
    
    277
    
    
    
    1,037Total
    
    
    
    
    
    $
    1,323
    
    
    $
    1,905
    
    
    $
    1,013
    
    
    $
    4,241
   (a)
    
    Unconditional purchase obligations mainly pertain to pipeline throughput
agreements.(b)
    
    Firm capital commitments related to capital projects, shown on an
undiscounted basis, totalled approximately $189 million at the end of 2003,
compared with $284 million at year end 2002. The largest commitment outstanding
at year end 2003 was associated with the Companys share of capital projects at
Syncrude ($56 million).(c)
    
    Pension obligations represent the amount by which
accumulated benefit obligations (ABO) exceeded the fair value of plan assets.
The ABO is less than the (projected) benefit obligation shown in note 5 to the
consolidated financial statements because it does not take into account future
compensation levels. It is used instead of the projected benefit obligation
because it more truly reflects the actual benefit obligation at the end of the
year. The payments by period include expected contributions to the Companys
registered pension plan in 2004 and estimated benefit payments for unfunded
plans in all years. The term ABO used here is consistent with the definition
under Statement of Financial Accounting Standards No. 87 issued by the
Financial Accounting Standards Board.(d)
    
    Asset retirement obligations represent the discounted present value of
legal obligations associated with site restoration on the retirement of assets
with determinable useful lives.(e)
    
    Other long term agreements include primarily raw material supply and
transportation services agreements. Critical accounting policies The Companys financial statements have been prepared in accordance with
Canadian generally accepted accounting principles (GAAP) and include estimates
that reflect managements best judgments. The Companys accounting and
financial reporting fairly reflect its straightforward business model. 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-6 to F-8. 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 unit of production rates for depreciation and
evaluating for impairment. These reserves are the estimated quantities of crude
oil, natural gas and natural gas liquids that geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from
known reservoirs and deposits under existing economic and operating conditions.
The estimation of reserves is an ongoing process based on rigorous technical
evaluations and extrapolations of appropriate information. While proved reserves have a reasonable certainty of recovery, they are
based on estimates that are subject to some variability. The variability can
result in upward or downward revisions in the previously estimated volumes of
proved reserves for existing fields due to initial
study or restudy of (1) already available geologic, reservoir or
production data, or (2) new geologic or reservoir data obtained from wells.
Revisions can also include changes associated with improved recovery projects,
fiscal terms and significant changes in development strategy, oil and gas
prices or production equipment/facility capacity. Over time, revisions of
proved reserves for the Company have generally resulted in net upward
experience based changes through effective reservoir management and the
application of new technology. While revisions are an indicator of variability,
they have had little impact on the unit of production rates of depreciation and
on impairment testing because the revisions have been small compared to the
large proved reserves base. Retirement benefits The Companys pension plan is managed in compliance with the requirements
of governmental authorities and meets funding levels as determined by
independent third party actuaries. Pension accounting requires explicit
assumptions regarding, among others, the discount rate for the benefit
obligations, the expected rate of return on plan assets and the long term rate
of future compensation increases. All pension assumptions are reviewed annually
by senior financial management. These assumptions are adjusted only as
appropriate to reflect long term changes in market rates and outlook. The long
term expected rate of return on plan assets of 8.25 percent used in 2003
compares to actual returns of 9.5 percent and 10 percent achieved over the last
10 and 20 year periods ending December 31, 2003. If different assumptions are
used, the expense and obligations could increase or decrease as a result. The
Companys potential exposure to change in assumptions is summarized in footnote
(e) 28




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##### Table of Contents



of note 5 to the consolidated financial statements. At the Company, differences
between actual returns on plan assets versus long term expected returns are not
recorded in the year the differences occur, but rather are amortized in pension
expense as permitted by GAAP, along with other actuarial gains and losses over
the expected remaining service life of employees. The Company uses the fair
value of the plan assets at year end to determine the amount of the actual gain
or loss that will be amortized and does not use a moving average value of plan
assets. Pension expense represented about one percent of total expenses in
2003. Asset retirement obligations and other environmental liabilities Legal obligations associated with site restoration on the retirement of
assets with determinable useful lives are recognized when they are incurred,
which is typically at the time the assets are installed. The obligations are
initially measured at fair value and discounted to present value. Over time the
discounted asset retirement obligation amount will be accreted for the change
in its present value, with this effect included in operating expense. As
payments to settle the obligations occur on an ongoing basis and will continue
over the lives of the operating assets, which can exceed 25 years, the discount
rate will be adjusted only as appropriate to reflect long term changes in
market rates and outlook. In 2003, the obligations have been discounted at six
percent and the accretion expense was $20 million, which was significantly less
than one percent of total expenses in the year. There would be no material
impact on the Companys reported financial results if a different discount rate
had been used. Asset retirement obligations are not recognized for assets with an
indeterminate useful life. For these and non-operating assets, the Company
accrues provisions for environmental liabilities when it is probable that
obligations have been incurred and the amount can be reasonably estimated. Asset retirement obligations and other environmental liabilities are based
on engineering estimated costs, taking into account the anticipated method and
extent of remediation consistent with legal requirements, current technology
and the possible use of the location. Since these estimates are specific to the
locations involved, there are many individual assumptions underlying the
Companys total asset retirement obligations and provision for other
environmental liabilities. While these individual assumptions can be subject to
change, none of them is individually significant to the Companys reported
financial results. 
 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 size, strong financial position and the complementary nature of its
natural resources, petroleum products and chemicals segments help mitigate the
Companys exposure to changes in these other risks. The Companys potential
exposure to these types of risk is summarized in the table below. The Company does not use derivative markets to speculate on the future
direction of currency or commodity prices and does not sell forward any part of
production from any business segment. The following table shows the estimated annual effect, under current
conditions, of certain sensitivities of the Companys after tax earnings. millions of dollars after taxThree dollars (U.S.) a barrel change in crude oil prices
    
    
    +(-
    )
    
    
    140Sixty cents a thousand cubic feet change in natural gas prices
    
    
    +(-
    )
    
    
    40One cent a litre change in sales margins for total petroleum products
    
    
    +(-
    )
    
    
    180One cents (U.S.) a pound change in sales margins for polyethylene
    
    
    +(-
    )
    
    
    8One quarter percent decrease (increase) in short term interest rates
    
    
    +(-
    )
    
    
    2Eight cents decrease (increase) in the value of the Canadian dollar versus the U.S. dollar
    
    
    +(-
    )
    
    
    340
 The amount quoted to illustrate the impact of each sensitivity represents
a change of about 10 percent in the value of the commodity or rate in question
at the end of 2003. Each sensitivity calculation shows the impact on annual
earnings that results from a change in one factor, after tax and royalties and
holding all other factors constant. While these sensitivities are applicable
under current conditions, they may not apply proportionately to larger
fluctuations. The sensitivity to changes in the Canadian dollar versus the U.S.dollar
increased from 2002 by about $12 million (after tax) a year for each one cent
change. This is primarily a result of the retirement of the U.S. dollar
denominated debt which had previously moderated the impact of foreign exchange
rate changes on commodity prices and product margins. The sensitivity to changes in crude oil prices decreased from 2002 by
about $13 million (after tax) for each one U.S. dollar difference. An increase
in the value of the Canadian dollar has lessened the impact of U.S. dollar
denominated crude oil prices on the Company s revenues and earnings. 29




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##### Table of Contents



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. 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
124 million cubic metres (781 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 OilBase Mine andNorth Mine
    
    Aurora Mine
    
    Total(millions of cubic metres)Beginning of year 2001
    
    
    60
    
    
    
    37
    
    
    
    97Revision of previous estimate
    
    
    
    
    
    
    37
    
    
    
    37Production
    
    
    (2
    )
    
    
    (1
    )
    
    
    (3
    )End of year 2001
    
    
    58
    
    
    
    73
    
    
    
    131Revision of previous estimate
    
    
    
    
    
    
    
    
    
    
    Production
    
    
    (3
    )
    
    
    (1
    )
    
    
    (4
    )End of year 2002
    
    
    55
    
    
    
    72
    
    
    
    127Revision of previous estimate
    
    
    
    
    
    
    
    
    
    
    Production
    
    
    (2
    )
    
    
    (1
    )
    
    
    (3
    )End of year 2003
    
    
    53
    
    
    
    71
    
    
    
    124
 Synthetic Crude OilBase Mine andNorth Mine
    
    Aurora Mine
    
    Total(millions of barrels)Beginning of year 2001
    
    
    373
    
    
    
    237
    
    
    
    610Revision of previous estimate
    
    
    
    
    
    
    230
    
    
    
    230Production
    
    
    (15
    )
    
    
    (4
    )
    
    
    (19
    )End of year 2001
    
    
    358
    
    
    
    463
    
    
    
    821Revision of previous estimate
    
    
    
    
    
    
    
    
    
    
    Production
    
    
    (14
    )
    
    
    (7
    )
    
    
    (21
    )End of year 2002
    
    
    344
    
    
    
    456
    
    
    
    800Revision of previous estimate
    
    
    
    
    
    
    
    
    
    
    Production
    
    
    (13
    )
    
    
    (6
    )
    
    
    (19
    )End of year 2003
    
    
    331
    
    
    
    450
    
    
    
    781
 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. 30




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##### Table of Contents



Results of operations 2003
    
    2002
    
    2001(millions of dollars)Sales to customers
    
    $
    1,816
    
    
    $
    1,381
    
    
    $
    1,306Intersegment sales
    
    
    584
    
    
    
    741
    
    
    
    767Total sales (1)
    
    $
    2,400
    
    
    $
    2,122
    
    
    $
    2,073Production expenses
    
    
    594
    
    
    
    576
    
    
    
    526Exploration expenses
    
    
    55
    
    
    
    30
    
    
    
    45Depreciation and depletion
    
    
    463
    
    
    
    426
    
    
    
    411Income taxes
    
    
    364
    
    
    
    350
    
    
    
    340Results of operations
    
    $
    924
    
    
    $
    740
    
    
    $
    751
 Capital and exploration expenditures 2003
    
    2002
    
    2001(millions of dollars)Property costs (2)Proved
    
    $
    
    
    
    $
    13
    
    
    $
    Unproved
    
    
    2
    
    
    
    5
    
    
    
    5Exploration costs
    
    
    55
    
    
    
    34
    
    
    
    44Development costs
    
    
    339
    
    
    
    469
    
    
    
    489Total capital and exploration expenditures
    
    $
    396
    
    
    $
    521
    
    
    $
    538
 Property, plant and equipment 2003
    
    2002(millions of dollars)Property costs (2)Proved
    
    $
    3,332
    
    
    $
    3,338Unproved
    
    
    163
    
    
    
    155Producing assets
    
    
    5,775
    
    
    
    5,371Support facilities
    
    
    125
    
    
    
    126Incomplete construction
    
    
    200
    
    
    
    227Total cost
    
    $
    9,595
    
    
    $
    9,217Accumulated depreciation and depletion
    
    
    6,012
    
    
    
    5,528Net property, plant and equipment
    
    $
    3,583
    
    
    $
    3,689
   (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 liquidsConventional
    
    Cold Lake
    
    Total
    
    Natural Gas(millions of cubic metres)
    
    (billions of cubic meters)Beginning of year 2001
    
    
    31
    
    
    
    135
    
    
    
    166
    
    
    
    45Revisions 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
    
    
    
    40Revisions 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
    
    
    
    151
    
    
    
    35Revisions of previous estimates and improved recovery
    
    
    
    
    
    
    1
    
    
    
    1
    
    
    
    (1
    )(Sale)/purchase of reserves in place
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Discoveries and extensions
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Production
    
    
    (3
    )
    
    
    (7
    )
    
    
    (10
    )
    
    
    (5
    )End of year 2003
    
    
    20
    
    
    
    121
    
    
    
    141
    
    
    
    29
   (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. 31




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##### Table of Contents



Crude oil and natural gas liquidsConventional
    
    Cold Lake
    
    Total
    
    Natural Gas(millions of barrels)
    
    (billions of cubic feet)Beginning of year 2001
    
    
    196
    
    
    
    851
    
    
    
    1,047
    
    
    
    1,572Revisions of previous estimates and improved recovery
    
    
    (8
    )
    
    
    
    
    
    
    (8
    )
    
    
    9(Sale)/purchase of reserves in place
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1Discoveries and extensions
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2Production
    
    
    (23
    )
    
    
    (44
    )
    
    
    (67
    )
    
    
    (170
    )End of year 2001
    
    
    165
    
    
    
    807
    
    
    
    972
    
    
    
    1,414Revisions of previous estimates and improved recovery
    
    
    3
    
    
    
    33
    
    
    
    36
    
    
    
    (26
    )(Sale)/purchase of reserves in place
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2Discoveries and extensions
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    3Production
    
    
    (22
    )
    
    
    (39
    )
    
    
    (61
    )
    
    
    (169
    )End of year 2002
    
    
    146
    
    
    
    801
    
    
    
    947
    
    
    
    1,224Revisions of previous estimates and improved recovery
    
    
    1
    
    
    
    5
    
    
    
    6
    
    
    
    (40
    )(Sale)/purchase of reserves in place
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Discoveries and extensions
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    6Production
    
    
    (21
    )
    
    
    (43
    )
    
    
    (64
    )
    
    
    (167
    )End of year 2003
    
    
    126
    
    
    
    763
    
    
    
    889
    
    
    
    1,023
   (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 2003, the Companys net proved reserves of crude oil and natural gas
liquids decreased by about nine million cubic metres (58 million barrels),
while the proved reserves of natural gas decreased by about six billion cubic
metres (201 billion cubic feet). Production in 2003 totalled about 10 million
cubic metres (64 million barrels) of crude oil and natural gas liquids and
about five billion cubic metres (167 billion cubic feet) of natural gas.
Revisions of previous estimates and improved recovery increased reserves of
crude oil and natural gas liquids by about one million cubic metres (six
million barrels) and decreased reserves of natural gas by about one billion
cubic metres (40 billion cubic feet). Discoveries and extensions in 2003
totalled less than one billion cubic metres (six billion cubic feet) of natural
gas. Net Proved Developed and Undeveloped Reserves of Crude Oil and Natural Gas (1) 2003
    
    2002
    
    2001
    
    2000
    
    1999(millions)Crude Oil:Conventional:Cubic metres
    
    
    20
    
    
    
    23
    
    
    
    26
    
    
    
    31
    
    
    
    36Barrels
    
    
    126
    
    
    
    146
    
    
    
    165
    
    
    
    196
    
    
    
    225Oil Sands (Cold Lake crude bitumen):Cubic metres
    
    
    121
    
    
    
    127
    
    
    
    128
    
    
    
    135
    
    
    
    139Barrels
    
    
    763
    
    
    
    801
    
    
    
    807
    
    
    
    851
    
    
    
    878Total:Cubic metres
    
    
    141
    
    
    
    151
    
    
    
    154
    
    
    
    166
    
    
    
    175Barrels
    
    
    889
    
    
    
    947
    
    
    
    972
    
    
    
    1,047
    
    
    
    1,103Natural Gas:
    
    (billions)Cubic metres
    
    
    29
    
    
    
    35
    
    
    
    40
    
    
    
    45
    
    
    
    48Cubic feet
    
    
    1,023
    
    
    
    1,224
    
    
    
    1,414
    
    
    
    1,572
    
    
    
    1,692
 32




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##### Table of Contents



Net Proved Developed Reserves of Crude Oil and Natural Gas (1) 2003
    
    2002
    
    2001
    
    2000
    
    1999(millions)Crude Oil:Conventional:Cubic metres
    
    
    19
    
    
    
    22
    
    
    
    25
    
    
    
    28
    
    
    
    32Barrels
    
    
    121
    
    
    
    139
    
    
    
    157
    
    
    
    175
    
    
    
    200Oil Sands (Cold Lake crude bitumen):Cubic metres
    
    
    63
    
    
    
    49
    
    
    
    34
    
    
    
    40
    
    
    
    36Barrels
    
    
    398
    
    
    
    308
    
    
    
    216
    
    
    
    250
    
    
    
    229Total:Cubic metres
    
    
    82
    
    
    
    71
    
    
    
    59
    
    
    
    68
    
    
    
    68Barrels
    
    
    519
    
    
    
    447
    
    
    
    373
    
    
    
    425
    
    
    
    429Natural Gas:
    
    (billions)Cubic metres
    
    
    24
    
    
    
    27
    
    
    
    30
    
    
    
    35
    
    
    
    36Cubic feet
    
    
    859
    
    
    
    959
    
    
    
    1,060
    
    
    
    1,233
    
    
    
    1,264
   (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) 2003
    
    2002
    
    2001(millions)Future cash flows
    
    $
    27,611
    
    
    $
    35,811
    
    
    $
    17,936Future production costs
    
    
    (10,871
    )
    
    
    (8,940
    )
    
    
    (7,107
    )Future development costs
    
    
    (3,084
    )
    
    
    (3,117
    )
    
    
    (2,641
    )Future income taxes
    
    
    (5,543
    )
    
    
    (9,107
    )
    
    
    (3,285
    )Future net cash flows
    
    $
    8,113
    
    
    $
    14,647
    
    
    $
    4,903Annual discount of 10 percent for estimated
timing of cash flows
    
    
    (3,375
    )
    
    
    (6,446
    )
    
    
    (2,114
    )Discounted future net cash flows
    
    $
    4,738
    
    
    $
    8,201
    
    
    $
    2,789
 Changes in Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and
Gas Reserves (1) 2003
    
    2002
    
    2001(millions)Balance at beginning of year
    
    $
    8,201
    
    
    $
    2,789
    
    
    $
    5,987Changes resulting from:Sales and transfers of oil and gas produced, net of
production costs
    
    
    (2,075
    )
    
    
    (1,645
    )
    
    
    (1,698
    )Net changes in prices, development costs and
production costs
    
    
    (4,395
    )
    
    
    9,276
    
    
    
    (6,477
    )Extensions, discoveries, additions and improved recovery,
less related costs
    
    
    22
    
    
    
    34
    
    
    
    31Purchase/(sales) of minerals in place
    
    
    
    
    
    
    4
    
    
    
    5Development costs incurred during the year
    
    
    281
    
    
    
    432
    
    
    
    504Revisions of previous quantity estimates
    
    
    (368
    )
    
    
    111
    
    
    
    88Accretion of discount
    
    
    1,108
    
    
    
    423
    
    
    
    1,030Net change in income taxes
    
    
    1,964
    
    
    
    (3,223
    )
    
    
    3,319Net Change
    
    $
    (3,463
    )
    
    $
    5,412
    
    
    $
    (3,198
    )Balance at end of year
    
    $
    4,738
    
    
    $
    8,201
    
    
    $
    2,789
   (1)
    
    The schedules above are calculated using year-end prices, costs,
statutory tax rates and existing proved oil and gas reserves excluding
the Companys interest in Syncrude. The standardized measure includes
costs for future dismantlement, abandonment and rehabilitation
obligations. The Company
believes the standardized measure does not provide a reliable estimate of
the Companys expected future cash flows to be obtained from the
development and production of its oil and gas properties or of the value of
its proved oil and gas reserves. The standardized measure is prepared on
the basis of certain prescribed assumptions including year-end prices,
which represent a single point in time and therefore may cause significant
variability in cash flows from year to year as prices change. 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. 33




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##### Table of Contents



Item 9A. Controls and Procedures.  As indicated in the certifications in Exhibit 31.1 and 31.2 of this report,
the Companys principal executive officer and principal financial officer
have evaluated the Companys disclosure controls and procedures as of
December 31, 2003. 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.There has not been any change in the Companys internal control over
financial reporting that occurred during the Companys fourth fiscal quarter
of 2003 that has materially affected, or is reasonably likely to materially
affect, the Companys internal control over financial reporting. 34




---



##### Table of Contents



PART III 
 Item 10. Directors and Executive Officers of the Registrant. The Company currently has nine directors. Each director is elected to hold
office until the close of the next annual meeting. All of the nominees are now directors and have been since the dates
indicated. The following table provides information on the nominees
for election as directors. Last majorposition or office with theName and current principal
    
    Company or Exxon Mobiloccupation or employment
    
    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 LimitedDeferred share units of
    
    
    1,560Imperial Oil Limited
    
    
    4,234Restricted stock units of
Imperial Oil Limited
    
    
    1,750Shares of
Exxon Mobil Corporation
    
    
    0B.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
    
    
    33,698Deferred share units of
Imperial Oil Limited
    
    
    19,773Restricted stock units of
Imperial Oil Limited
    
    
    48,400Shares of
Exxon Mobil Corporation
    
    
    0T.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
    
    
    23,095Deferred share units of
Imperial Oil Limited
    
    
    0Restricted stock units of
Imperial Oil Limited
    
    
    110,000Shares of
Exxon Mobil Corporation
    
    
    9,274R. (Roger) Phillips
Retired president and
chief executive officer,
IPSCO Inc.
(steel manufacturing)
    
    
    
    April 23, 2002
    
    Common shares of
Imperial Oil Limited
    
    
    3,000Deferred share units of
Imperial Oil Limited
    
    
    2,316Restricted stock units of
Imperial Oil Limited
    
    
    1,750Shares of
Exxon Mobil Corporation
    
    
    2,000J.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
    
    
    3,000Deferred share units of
Imperial Oil Limited
    
    
    4,878Restricted stock units of
Imperial Oil Limited
    
    
    1,750Shares of
Exxon Mobil Corporation
    
    
    0
 35




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##### Table of Contents



Last majorposition or office with theName and current principal
    
    Company or Exxon Mobiloccupation or employment
    
    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
    
    
    4,120Deferred share units of
Imperial Oil Limited
    
    
    0Restricted stock units of
Imperial Oil Limited
    
    
    29,200Shares of
Exxon Mobil Corporation
    
    
    1,190S.D. (Sheelagh) Whittaker
Managing Director,
public sector business
Electronic Data Systems Limited
(business and information
technology services)
    
    
    
    April 19, 1996
    
    Common shares of
Imperial Oil Limited
    
    
    3,000Deferred share units of
Imperial Oil Limited
    
    
    7,313Restricted stock units of
Imperial Oil Limited
    
    
    1,750Shares of
Exxon Mobil Corporation
    
    
    0K.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
    
    
    12,000Deferred share units of
Imperial Oil Limited
    
    
    Restricted stock units of
Imperial Oil Limited
    
    
    Shares of
Exxon Mobil Corporation
    
    
    73,045V.L. (Victor) Young
Corporate director
of several corporations
    
    
    
    April 23, 2002
    
    Common shares of
Imperial Oil Limited
    
    
    3,000Deferred share units of
Imperial Oil Limited
    
    
    579Restricted stock units of
Imperial Oil Limited
    
    
    1,750Shares of
Exxon Mobil Corporation
    
    
    0
  (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 40 and 41. The ages of the directors, nominees for election as directors, and the
five senior executives of the Company are: Pierre Des Marais II 69, Brian J.
Fischer 57, Timothy J. Hearn 60, Roger Phillips 64, James F. Shepard 65, Paul
A. Smith 51, Sheelagh D. Whittaker 56, K.C. Williams 54, Victor L. Young 58,
and John F. Kyle 61. Roger Phillips is a director of Canadian Pacific Railway Limited, Cleveland 
Cliffs Inc., Inco Limited, 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. 36




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##### Table of Contents



All of the directors and nominees for election as directors, except for
Roger Phillips, Victor L. Young and James F. Shepard, have been engaged for
more than five years in their present principal occupations or in other
executive capacities with the same firm or affiliated firms. During the five
preceding years, Roger Phillips was president and chief executive officer of
IPSCO Inc. (steel manufacturing) until he retired on January 1, 2002. During
the five preceding years, Victor L. Young was chairman and chief executive
officer of Fishery Products International Limited (seafood products), until May
1, 2001 and is currently a director of Royal Bank of Canada, BCE Inc., McCain
Foods Limited, Aliant Inc., and Telesat Canada. 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 sinceTimothy J. Hearn
    
    April 23, 2002chairman of the board, presidentand chief executive officerBrian J. Fischer
    
    February 1, 1994senior vice-president,products and chemicals divisionPaul A. Smith
    
    February 1, 2002controller and senior vice-president,finance and administrationK.C. Williams
    
    January 1, 1999senior vice-president,resources divisionJohn F. Kyle
    
    June 1, 1991vice-president andtreasurer
 All of the above senior executives have been engaged for more than five
years at their current occupations or in other executive capacities with the
Company or its affiliates. All senior executives hold office until their
appointment is rescinded by the directors, or by the chief executive officer. Audit committee The Company has an audit committee of the board of directors. The
following directors are members of the audit committee: P. Des Marais II, R.
Phillips, J.F. Shepard, S.D. Whittaker and V.L. Young. Audit committee financial expert The Companys board of directors has determined that P. Des Marais II, R.
Phillips, S.D. Whittaker and V. L. Young meet the definition of audit
committee financial expert and are independent, as that term is defined by
both the Securities and Exchange Commission rules and the listing standards of
the American Stock Exchange and the New York Stock Exchange. The Securities and
Exchange Commission has indicated that the designation of an audit committee
financial expert does not make that person an expert for any purpose, or impose
any duties, obligations or liability on that person that are greater than those
imposed on members of the audit committee and board of directors in the absence
of such designation or identification. Code of ethics The Company has a code of ethics and conflict-of-interest guidelines that
apply to all employees, including its principal executive officer, principal
financial officer and principal accounting officer. The code of ethics and
conflict-of-interest guidelines are available at the Companys website
www.imperialoil.ca. 37




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##### Table of Contents



Item 11. Executive Compensation. Directors compensation Directors fees are paid only to nonemployee directors. For 2003,
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, 2003, the annual board retainer was increased by the issuance of 1,000
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 41. 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 pages 40 and 41. While serving as directors in 2003, the aggregate cash remuneration paid
to nonemployee directors, as a group, was $346,500, and they received an
additional 5,006 deferred share units for nonemployee directors, as a group,
based on an aggregate of $250,000 of cash remuneration elected to be received
as deferred share units. The nonemployee directors, as a group, received an
additional 279 deferred share units granted as the equivalent to the cash
dividend paid on Company shares during 2003 for previously granted deferred
share units. Senior executive compensation Summary compensation table The following table shows the compensation for the chief executive officer
and the four other senior executives of the Company who were serving as senior
executives at the end of 2003. This information includes the dollar value of
base salaries, cash bonus awards, and units of other long term incentive
compensation and certain other compensation. 38




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##### Table of Contents



Annual Compensation
    
    Long-Term CompensationAwards
    
    PayoutsSecurities
    
    RestrictedUnder
    
    Shares orName and
    
    
    
    
    
    
    
    
    
    
    
    
    
    Other Annual
    
    Options/SARs
    
    Restricted
    
    LTIP
    
    All OtherPrincipal
    
    
    
    
    
    Salary
    
    Bonus (2)
    
    Compensation (3)
    
    Granted (4)
    
    Share Units (5) (6) (7)
    
    Payouts
    
    Compensation (9)Position
    
    Year
    
    ($)
    
    ($)
    
    ($)
    
    (#)
    
    (#)
    
    (8) ($)
    
    ($)T.J. Hearn
    
    
    2003
    
    
    
    825,000
    
    
    
    750,000
    
    
    
    182,072
    
    
    
    
    
    
    
    60,000
    
    
    
    738,000
    
    
    
    24,750Chairman, president and chief executive officer
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    U.S. 293,450
    
    
    
    
    
    
    restrictedstock units0deferred share units2002
    
    
    
    668,333
    
    
    
    442,000
    
    
    
    71,777
    
    
    
    65,000
    
    
    
    50,000
    
    
    
    
    
    
    
    20,050U.S. 328,796
    
    
    stock
    
    restrictedoptions
    
    stock units0deferred share units2001
    
    
    
    475,000
    
    
    
    300,000
    
    
    
    19,888
    
    
    
    50,000
    
    
    
    0
    
    
    
    
    
    
    
    9,500U.S. (163,873
    )
    
    incentive
    
    deferredshare units
    
    share unitsB.J. Fischer
    
    
    2003
    
    
    
    530,833
    
    
    
    357,000
    
    
    
    24,815
    
    
    
    
    
    
    
    26,700
    
    
    
    486,000
    
    
    
    31,850Senior
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    restrictedvice-president,
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    stock unitsproducts and
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    341chemicals division
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    deferred share units2002
    
    
    
    505,000
    
    
    
    216,000
    
    
    
    0
    
    
    
    50,000
    
    
    
    21,700
    
    
    
    
    
    
    
    30,300stock
    
    restrictedoptions
    
    share units358deferred share units2001
    
    
    
    475,000
    
    
    
    67,500
    
    
    
    2,935
    
    
    
    50,000
    
    
    
    5,039
    
    
    
    
    
    
    
    23,750incentive
    
    deferredshare units
    
    share unitsP.A. Smith
    
    
    2003
    
    
    
    357,917
    
    
    
    183,000
    
    
    
    11,083
    
    
    
    
    
    
    
    16,700
    
    
    
    204,510
    
    
    
    21,475Controller and
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    U.S. 72,891
    
    
    
    
    
    
    restrictedsenior vice-president,
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    stock unitsfinance and
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    0administration
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    deferred share units2002
    
    
    
    331,667
    
    
    
    94,500
    
    
    
    U.S. 100,390
    
    
    
    25,000
    
    
    
    12,500
    
    
    
    
    
    
    
    19,900stock
    
    restrictedoptions
    
    stock units0deferred share units2001
    
    
    
    291,666
    
    
    
    110,000
    
    
    
    U.S. 30,908
    
    
    
    25,000
    
    
    
    0
    
    
    
    
    
    
    
    14,583incentive
    
    deferredshare units
    
    share unitsK.C. Williams (1)
    
    
    2003
    
    
    
    U.S. 431,667
    
    
    
    U.S. 260,900
    
    
    
    U.S. 530,391
    
    
    
    
    
    
    
    
    
    
    
    U.S. 197,490
    
    
    
    U.S. 27,900Senior
vice-president,
resources division
    
    
    2002
    
    
    
    U.S. 412,500
    
    
    
    U.S. 158,000
    
    
    
    U.S. 363,932
    
    
    
    
    
    
    
    
    
    
    
    U.S.
    
    
    
    U.S.197,450
    
    
    
    26,7502001
    
    
    
    U.S. 382,750
    
    
    
    U.S. 197,500
    
    
    
    U.S. 144,175
    
    
    
    
    
    
    
    
    
    
    
    U.S.
    
    
    
    U.S.97,515
    
    
    
    24,665J.F. Kyle
    
    
    2003
    
    
    
    355,000
    
    
    
    171,000
    
    
    
    41,391
    
    
    
    
    
    
    
    11,400
    
    
    
    261,000
    
    
    
    21,300Vice-president
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    restrictedand treasurer
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    stock units0deferred share units2002
    
    
    
    345,000
    
    
    
    110,000
    
    
    
    13,077
    
    
    
    29,000
    
    
    
    10,600
    
    
    
    
    
    
    
    20,700stock
    
    restrictedoptions
    
    stock units0deferred share units2001
    
    
    
    325,000
    
    
    
    150,000
    
    
    
    15,107
    
    
    
    29,000
    
    
    
    0
    
    
    
    
    
    
    
    16,250incentive
    
    deferredshare units
    
    share units
 39




---



##### Table of Contents



(1)
    
    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.(2)
    
    Any part of bonus elected to be received as deferred share units is
excluded.(3)
    
    Amounts under Other Annual Compensation, except for K.C. Williams,
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 40 and 41, dividend equivalent
payments on restricted stock units, interest paid in respect of deferred
payments of bonuses and reimbursement for any income tax paid as a result of
use of Company aircraft. For T.J. Hearn the amounts also include a leased
automobile which in 2003 was $44,010 and financial counselling. For T.J. Hearn
and P.A. Smith, the U.S. dollar amounts are payments by the Company on account
of U.S. income taxes incurred 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, while on assignment, 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.(4)
    
    For 2001, these are the number of units granted under the Companys plan
for incentive share units described on page 40. In 2002, the Company granted
instead stock options which are described on page 41.(5)
    
    These include the number of units granted under the Companys plan for
deferred share units for selected executives described on pages 40 and 41. The
values and number of these units, as at the end of 2003, were nil for T.J.
Hearn, $1,137,541 for 19,773 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 2003 and 2002, and 4,880 share units based on $202,500 of
bonus elected to be received as deferred share units for 2001 for B.J. Fischer.(6)
    
    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 41. The values and number of these units, as at the end of
2003, were $6,328,300 for 110,000 units for T.J. Hearn, $2,784,452 for 48,400
units for B.J. Fischer, $1,679,876 for 29,200 units for P.A. Smith and
$1,265,660 for 22,000 units for J.F. Kyle. The values of these units granted
for 2003, as at the end of 2003, were $3,451,800 for T.J. Hearn, $1,536,051 for
B.J. Fischer, $960,751 for P.A. Smith and $655,842 for J.F. Kyle. The values of
these units granted for 2002, as 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.(7)
    
    K.C. Williams participates in Exxon Mobil Corporations restricted stock
plan which is similar to the Companys restricted stock unit plan. The value
and number of these units for K.C. Williams, as at the end of the year, were
U.S. $1,918,800 for 46,800 units. Under that plan, K.C. Williams was granted 23
400 units in 2003 whose value on the date of grant was U.S. $959,400 and 23 400
units in 2002 whose value on the date of grant was U.S. $810,576.(8)
    
    Payouts
were from 2001 and 2002 earnings bonus units that reached maximum value of
$3.00 per unit in 2003. That plan is described on page 41.(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 six percent of base salary per year; however, an employee may elect to
receive an enhanced pension under the Companys pension plan by foregoing three
percent of the Companys matching contributions. The plan is intended to be
primarily for retirement savings, although employees may withdraw their
contributions prior to retirement. For K.C. Williams, the amounts are Exxon
Mobil Corporations contributions to its employee savings plan. 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. Incentive
share units are eligible for exercise up to 10 years from issuance. 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 40




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##### Table of Contents



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 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 75
percent of the options were exercisable 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. In December 2002, the Company introduced a restricted stock unit plan,
which will be the primary long term incentive compensation plan in future
years. The purpose of the plan is to align the interests of employees and
nonemployee directors directly with the interests of shareholders. Each unit
entitles the recipient the conditional right to receive from the Company, upon
exercise, an amount equal to the closing price of the Companys shares on the
exercise dates. Fifty percent of the units will be exercised on the third
anniversary of the grant date, and the remainder will be exercised on the
seventh anniversary of the grant date. The Company will pay the recipients cash
with respect to each unexercised unit granted to the recipient corresponding in
time and amount to the cash dividend that is paid by the Company on a common
share of the Company. The restricted stock units plan was amended for units
granted in 2003 and future years by providing that the recipient may receive
one common share of the Company per unit or elect to receive the cash payment
for the units to be exercised on the seventh anniversary of the grant date. A
total of 872,085 units were granted on December 31, 2003. Earnings bonus unit plan  awards in most recently completed financial year The following table provides information on earnings bonus units granted
in 2003 to the named senior executives. Performance
    
    Estimated Future Payouts UnderSecuritiesUnits or
    
    or OtherPeriod Until
    
    Non-Securities-Price Based PlansOther Rights
    
    Maturation or
    
    Threshold
    
    Target
    
    MaximumName
    
    (#)
    
    Payout (1)
    
    ($)
    
    ($) (2)
    
    ($)(2)T.J. Hearn
    
    
    250,000
    
    
    Nov. 20, 2008
    
    
    0
    
    
    
    3.00
    
    
    
    3.00B.J. Fischer
    
    
    119,000
    
    
    Nov. 20, 2008
    
    
    0
    
    
    
    3.00
    
    
    
    3.00P.A. Smith
    
    
    61,000
    
    
    Nov. 20, 2008
    
    
    0
    
    
    
    3.00
    
    
    
    3.00K.C. Williams (3)
    
    
    
    
    
    
    
    
    
    
    
    
    

    
    
    
    
    
    J.F. Kyle
    
    
    57,000
    
    
    Nov. 20, 2008
    
    
    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 2003, K.C.
Williams was granted 86,960 units under that plan for which the maximum
settlement value payable per earnings bonus unit is U.S. $3.00. 41




---



##### Table of Contents



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 2003 and the
aggregate holdings at the end of 2003 of incentive share units (referred to in
the table as SARs) by the named senior executives. Value ofUnexercisedUnexercised
    
    in-the-MoneyOptions/SARs
    
    Options/SARsat Financial
    
    at FinancialSecurities
    
    Aggregate
    
    Year-End
    
    Year-EndAcquiredon Exercise
    
    ValueRealized
    
    (#)
    
    ($)Name
    
    (#)
    
    ($)
    
    Exercisable
    
    Unexercisable (1)
    
    Exercisable
    
    Unexercisable (1)T.J. Hearn
    
    
    
    
    
    
    181,350
    
    
    
    50,000
    
    
    
    12,500
    
    
    
    1,027,750
    
    
    
    231,625B.J. Fischer
    
    
    
    
    
    
    
    
    
    
    139,5000
    
    
    
    25,000
    
    
    
    3,583,535
    
    
    
    564,500P.A. Smith
    
    
    
    
    
    
    503,100
    
    
    
    66,750
    
    
    
    6,250
    
    
    
    2,176,438
    
    
    
    115,813K.C. Williams
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    J.F. Kyle
    
    
    
    
    
    
    626,570
    
    
    
    81,750
    
    
    
    7,250
    
    
    
    2,108,728
    
    
    
    134,343
  (1)
    
    Unexercisable units are units for which the conditions for exercise
have not been met. The following table provides information on the exercise in 2003 and the
aggregate holdings at the end of 2003 of stock options by named senior
executives. Value ofUnexercisedUnexercised
    
    in-the-MoneyOptions/SARs
    
    Options/SARsat Financial
    
    at FinancialSecurities
    
    Aggregate
    
    Year-End
    
    Year-EndAcquiredon Exercise
    
    ValueRealized
    
    (#)
    
    ($)Name
    
    (#)
    
    ($)
    
    Exercisable
    
    Unexercisable (2)
    
    Exercisable
    
    Unexercisable (2)T.J. Hearn
    
    
    
    
    
    
    
    
    
    
    32,500
    
    
    
    32,500
    
    
    
    358,475
    
    
    
    358,475B.J. Fischer
    
    
    
    
    
    
    
    
    
    
    25,000
    
    
    
    25,000
    
    
    
    275,750
    
    
    
    275,750P.A. Smith
    
    
    
    
    
    
    
    
    
    
    12,500
    
    
    
    12,500
    
    
    
    137,875
    
    
    
    137,875K.C. Williams (1)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    J.F. Kyle
    
    
    
    
    
    
    
    
    
    
    14,500
    
    
    
    14,500
    
    
    
    159,935
    
    
    
    159,935
  (1)
    
    At the end of 2003, K.C. Williams held options to acquire 475,000 Exxon
Mobil Corporation shares of which all options were exercisable. The values of
K.C. Williamss exercisable options were U.S. $4,617,084 at the end of 2003. In
2003, K.C. Williams exercised 26,508 options and realized an aggregate value of
U.S. $573,059.(2)
    
    Unexercisable units are units for which the conditions for
exercise have not been met. 42




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##### Table of Contents



Payments to employees who retire Pension plan table Remuneration for
    
    Estimated undiscounted paymentsdetermining paymentson retirement
    
    on retirement at the age of 65 after years of service indicated below ($)($)
    
    20 Years
    
    25 Years
    
    30 Years
    
    35 Years
    
    40 Years100,000
    
    
    32,000
    
    
    
    40,000
    
    
    
    48,000
    
    
    
    56,000
    
    
    
    64,000200,000
    
    
    64,000
    
    
    
    80,000
    
    
    
    96,000
    
    
    
    112,000
    
    
    
    128,000300,000
    
    
    96,000
    
    
    
    120,000
    
    
    
    144,000
    
    
    
    168,000
    
    
    
    192,000400,000
    
    
    128,000
    
    
    
    160,000
    
    
    
    192,000
    
    
    
    224,000
    
    
    
    256,000500,000
    
    
    160,000
    
    
    
    200,000
    
    
    
    240,000
    
    
    
    280,000
    
    
    
    320,000600,000
    
    
    192,000
    
    
    
    240,000
    
    
    
    288,000
    
    
    
    336,000
    
    
    
    384,000700,000
    
    
    224,000
    
    
    
    280,000
    
    
    
    336,000
    
    
    
    392,000
    
    
    
    448,000800,000
    
    
    256,000
    
    
    
    320,000
    
    
    
    384,000
    
    
    
    448,000
    
    
    
    512,000900,000
    
    
    288,000
    
    
    
    360,000
    
    
    
    432,000
    
    
    
    504,000
    
    
    
    576,0001,000,000
    
    
    320,000
    
    
    
    400,000
    
    
    
    480,000
    
    
    
    560,000
    
    
    
    640,0001,100,000
    
    
    352,000
    
    
    
    440,000
    
    
    
    528,000
    
    
    
    616,000
    
    
    
    704,0001,200,000
    
    
    384,000
    
    
    
    480,000
    
    
    
    576,000
    
    
    
    672,000
    
    
    
    768,0001,300,000
    
    
    416,000
    
    
    
    520,000
    
    
    
    624,000
    
    
    
    728,000
    
    
    
    832,0001,400,000
    
    
    448,000
    
    
    
    560,000
    
    
    
    672,000
    
    
    
    784,000
    
    
    
    896,0001,500,000
    
    
    480,000
    
    
    
    600,000
    
    
    
    720,000
    
    
    
    840,000
    
    
    
    960,0001,600,000
    
    
    512,000
    
    
    
    640,000
    
    
    
    768,000
    
    
    
    896,000
    
    
    
    1,024,0001,700,000
    
    
    544,000
    
    
    
    680,000
    
    
    
    816,000
    
    
    
    952,000
    
    
    
    1,088,0001,800,000
    
    
    576,000
    
    
    
    720,000
    
    
    
    864,000
    
    
    
    1,008,000
    
    
    
    1,152,0001,900,000
    
    
    608,000
    
    
    
    760,000
    
    
    
    912,000
    
    
    
    1,064,000
    
    
    
    1,216,0002,000,000
    
    
    640,000
    
    
    
    800,000
    
    
    
    960,000
    
    
    
    1,120,000
    
    
    
    1,280,0002,100,000
    
    
    672,000
    
    
    
    840,000
    
    
    
    1,008,000
    
    
    
    1,176,000
    
    
    
    1,344,0002,200,000
    
    
    704,000
    
    
    
    880,000
    
    
    
    1,056,000
    
    
    
    1,232,000
    
    
    
    1,408,0002,300,000
    
    
    736,000
    
    
    
    920,000
    
    
    
    1,104,000
    
    
    
    1,288,000
    
    
    
    1,472,0002,400,000
    
    
    768,000
    
    
    
    960,000
    
    
    
    1,152,000
    
    
    
    1,344,000
    
    
    
    1,536,0002,500,000
    
    
    800,000
    
    
    
    1,000,000
    
    
    
    1,200,000
    
    
    
    1,400,000
    
    
    
    1,600,000
 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 employees who have earned a pension in excess of the
maximum pension under the Income Tax Act. The pension plan table on this page
shows estimated undiscounted annual payments, consisting of pension and
supplemental retirement income, payable on retirement to employees including
the senior executives in specified classifications of remuneration and years of
service currently applicable to that group. The remuneration used to determine the payments on retirement to the
individuals named in the summary compensation table on pages 39 and 40,
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 41 is included in the employees final
three year average earnings for the year of grant of such units. As of
February 18, 2004, the number of completed years of service with Imperial Oil
Limited used to determine payments on retirement were 37 for T.J. Hearn, 35 for
B.J. Fischer, 24 for P.A. Smith and 27 for J.F. Kyle. 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 31 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 39, and 40, 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. 43




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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
2003, the membership of the executive resources committee was as follows: P. Des Marais II - Chair
R. Phillips - Vice-chair
J.F. Shepard
S.D. Whittaker
V.L. Young
T.J. Hearn periodically attends meetings at the request of the committee. 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 2002, and three percent in 2003 and two and one half percent in
2004. 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 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 90 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 41. In 2003, the executive resources committee increased the bonus awards
including the grant of earnings bonus units to reflect the Companys record
financial results and in response to comparisons to other leading Canadian
employers. In the case of T.J. Hearn, the committees approach to cash bonuses is
based on the Companys financial and operating performance and on the
committees assessment of T.J. Hearns effectiveness in leading the
organization. The continuing progress being made in focussing the organization
on advancing key strategic interests, safety, environmental performance,
productivity, cost effectiveness and asset management were primary
considerations in determining a cash bonus for the chief executive officer.
T.J. Hearns bonus including the grant of earnings bonus units was increased in
2003 to reflect his effectiveness in the position, the Companys record
financial results, and comparisons to other leading Canadian employers. 44




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Long
term incentive compensation Each year, the executive resources committee has approved long term
incentive awards for selected key employees. These awards were an added
incentive to promote individual contribution to sustained improvement in
business performance and shareholder value, and to encourage key employees to
remain with the Company. Individual awards reflected both level of
responsibility and performance, with an emphasis on ability to influence longer
term results. In each case, including senior executives and the chief executive
officer, award amounts took into account the competitive practices of other
major Canadian employers and were not influenced by prior years results or by
an individuals holdings of unexercised long term incentive compensation units. Incentive awards also have been awarded selectively to the general
managerial, professional and technical (non-executive) workforce as a way of
delivering added financial incentive to selected high performing employees. 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 2003, no
executives elected to receive deferred share units and 83 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 618 employees, including executives, were granted restricted stock
units in 2003. Submitted on behalf of the executive resources committee:  P.Des Marais II - Chair
R. Phillips - Vice-chair
J.F. ShepardS.D. Whittaker
V.L. Young 
 Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters. To the knowledge of the management of the Company, the only shareholder
who, as of February 18, 2004, 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 251,464,070 common shares, representing
69.6 percent of the outstanding voting shares of the Company. Reference is made to the security ownership information under the
preceding Items 10 and 11. As of February 18, 2004, John F. Kyle was the owner
of 3,551 common shares of the Company and held options to acquire 29,000 common
shares of the Company and restricted share units to acquire 5,700 common shares
of the Company. The directors and the senior executives of the Company consist of 10
persons, who, as a group, own beneficially 90,024 common shares of the Company,
being approximately 0.02 percent of the total number of outstanding shares of
the Company, and 85,509 shares of Exxon Mobil Corporation. This information not
being within the knowledge of the Company has been provided by the directors
and the senior executives individually. As a group, the directors and senior
executives of the Company held options to acquire 314,000 common shares of the
Company and held restricted stock units to acquire 109,175 common shares of the
Company, as of February 18, 2004. 45




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##### Table of Contents



Equity Compensation Plan Information as of December 31, 2003 Number of securitiesremaining available for futureNumber of securities to
    
    Weighted-average
    
    issuance under equitybe issued upon exercise
    
    excercise price of
    
    compensation plans (excludingof outstanding options,
    
    outstanding options,
    
    securities reflected inwarrants and rights
    
    warrants and rights
    
    column (a))Plan category
    
    (a)
    
    (b)
    
    (c)Equity
compensation plans approved by
security holders (1)
    
    
    3,210,200
    
    
    $
    46.50
    
    
    
    13,289,800Equity compensation plans not approved
by security holders (2)
    
    
    321,162
    
    
    not applicable
    
    
    3,178,838Total
    
    
    3,531,362
    
    
    
    
    
    
    
    16,468,638
  (1)
    
    This is the stock option plan, which is described on page
41 of this report.(2)
    
    This is the restricted stock unit plan,
which is described on page 41 of this report. 
 Item 13. Certain Relationships and Related Transactions. On June 21, 2002, the Company implemented another 12-month normal course
share-purchase program under which it purchased 6,390,770 of its outstanding
shares between June 21, 2002, and June 20, 2003. On June 23, 2003, another
12-month normal course program was implemented under which the Company may
purchase up to 18,632,218 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
2003, such purchases cost $799 million, of which $555 million was received by
ExxonMobil. During 2003, the Company borrowed $818 million from Exxon Overseas
Corporation under two long term loan agreements at interest equivalent to
Canadian market rates. Interest paid on the loans in 2003 was $14 million. The
average effective interest rates for the loans was 3.1 percent for 2003. 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 $2,478 million and $950 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.The Company has
an existing agreement with ExxonMobil Canada Ltd., to share common business and
operational support services that allow the companies to consolidate duplicate
work and systems. 
 Item 14. Principal Accountant Fees and Services. The aggregate fees of the Companys auditors for professional services
rendered for the audit of the Companys financial statements and other services
for the fiscal years ended December 31, 2003 and December 31, 2002 were as
follows: Dollars (thousands)
    
    2003
    
    2002Audit Fees
    
    
    767
    
    
    
    747Audit-Related Fees
    
    
    62
    
    
    
    111Tax Fees
    
    
    395
    
    
    
    255All Other Fees
    
    
    Nil
    
    
    
    NilTotal Fees
    
    
    1,224
    
    
    
    1,113
 Audit fees include the audit of the Companys annual financial statements
and a review of the first three quarterly financial statements in 2003. Audit-related fees include other assurance services including the audit of
the Companys retirement plan, the Imperial Oil Foundation, and royalty
statement audits for oil and gas producing entities. Tax fees are mainly tax services for employees on foreign loan assignments. All other fees would include other services including financial systems
consulting and implementation. The Company did not engage the auditors for
these types of services. 46




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##### Table of Contents



The audit committee recommends the external auditors to be appointed by
the shareholders, fixes their remuneration and oversees their work. The audit
committee also approves the proposed current year audit program of the
auditors, assesses the results of the program after the end of the program
period and approves in advance any non-audit services to be performed by the
auditors after considering the effect of such services on their independence. All of the services rendered by the auditors to the Company were approved by
the audit committee. 
 PART IV 
 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
(3)(ii) to the Companys Quarterly Report on Form 10-Q for the quarter ended
March 31, 2003 (File No. 0-12014)).(4)
    
    
    
    The Companys long term debt authorized under any instrument does not
exceed 10 percent of the Companys consolidated assets. The Company agrees to
furnish to the Commission upon request a copy of any such instrument.
 (10)
    
    (ii)
    
    
    (1
    )
    
    Alberta Crown Agreement, dated February 4, 1975, relating to the
participation of the Province of Alberta in Syncrude (Incorporated herein by
reference to Exhibit 13(a) of the Companys Registration Statement on Form S-1,
as filed with the Securities and Exchange Commission on August 21, 1979 (File
No. 2-65290)).
  (2)
    
    Amendment to Alberta Crown Agreement, dated January 1, 1983
(Incorporated herein by reference to Exhibit (10)(ii)(2) of the Companys
Annual Report on Form 10-K for the year ended December 31, 1983 (File No.
2-9259)).(3)
    
    Syncrude Ownership and Management Agreement, dated February 4, 1975
(Incorporated herein by reference to Exhibit 13(b) of the Companys
Registration Statement on Form S-1, as filed with the Securities and Exchange
Commission on August 21, 1979 (File No. 2-65290)).(4)
    
    Letter Agreement, dated
February 8, 1982, between the Government of Canada and Esso Resources Canada
Limited, amending Schedule C to the Syncrude Ownership and Management
Agreement filed as Exhibit (10)(ii)(2) (Incorporated herein by reference to
Exhibit (20) of the Companys Annual Report on Form 10-K for the year ended
December 31, 1981 (File No. 2-9259)).(5)
    
    Norman Wells Pipeline Agreement, dated January 1, 1980, relating to the
operation, tolls and financing of the pipeline system from the Norman Wells
field (Incorporated herein by reference to Exhibit 10(a)(3) of the Companys
Annual Report on Form 10-K for the year ended December 31, 1981 (File No.
2-9259)).(6)
    
    Norman Wells Pipeline Amending Agreement, dated April 1, 1982
(Incorporated herein by reference to Exhibit (10)(ii)(5) of the Companys
Annual Report on Form 10-K for the year ended December 31, 1982 (File No.
2-9259)).(7)
    
    Letter Agreement clarifying certain provisions to the Norman Wells Pipeline
Agreement, dated August 29, 1983 (Incorporated herein by reference to Exhibit
(10)(ii)(7) of the Companys Annual Report on Form 10-K for the year ended
December 31, 1983 (File No. 2-9259)).(8)
    
    Norman Wells Pipeline Amending
Agreement, made as of February 1, 1985, relating to certain amendments ordered
by the National Energy Board (Incorporated herein by reference to Exhibit
(10)(ii)(8) of the Companys Annual Report on Form 10-K for the year ended
December 31, 1986 (File No. 0-12014)). 47




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##### Table of Contents



(9)
    
    Norman Wells Pipeline Amending Agreement, made as of April 1, 1985,
relating to the definition of Operating Year (Incorporated herein by
reference to Exhibit (10)(ii)(9) of the Companys Annual Report on Form 10-K
for the year ended December 31, 1986 (File No. 0-12014)).(10)
    
    Norman Wells
Expansion Agreement, dated October 6, 1983, relating to the prices and
royalties payable for crude oil production at Norman Wells (Incorporated herein
by reference to Exhibit (10)(ii)(8) of the Companys Annual Report on Form 10-K
for the year ended December 31, 1983 (File No. 2-9259)).(11)
    
    Alberta Cold Lake Crown Agreement, dated June 25, 1984, relating to the
royalties payable and the assurances given in respect of the Cold Lake
production project (Incorporated herein by reference to Exhibit (10)(ii)(11)
of the Companys Annual Report on Form 10-K for the year ended December 31,
1986 (File No. 0-12014)).(12)
    
    Amendment to Alberta Crown Agreement, dated January 1, 1986
(Incorporated herein by reference to Exhibit (10)(ii)(12) of the Companys
Annual Report on Form 10-K for the year ended December 31, 1987 (File No.
0-12014)).(13)
    
    Amendment to Alberta Crown Agreement, dated November 25, 1987
(Incorporated herein by reference to Exhibit (10)(ii)(13) of the Companys
Annual Report on Form 10-K for the year ended December 31, 1987 (File No.
0-12014)).(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)).
 48




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##### Table of Contents



(2)
    
    Incentive Share Unit Plan and Incentive Share Units granted in 2001
are incorporated herein by reference to Exhibit (10)(iii)(A)(2) of the
Companys Annual Report on Form 10-K for the year ended December 31,
2001. Units granted in 2000 are incorporated herein by reference to
Exhibit (10)(iii)(A)(2) of the Companys Annual Report on Form 10-K for
the year ended December 31, 2000 (File No. 0-12014); units granted in
1999 are incorporated herein by reference to Exhibit (10)(iii)(A)(3) of
the Companys Annual Report on Form 10-K for the year ended December 31,
1999 (File No. 0-12014); units granted in 1998 are incorporated herein by
reference to Exhibit (10)(iii)(A)(3) of the Companys Annual Report on
Form 10-K for the year ended December 31, 1998 (File No. 0-12014); units
granted in 1997 are incorporated herein by reference to Exhibit
(10)(iii)(A)(3) of the Companys Annual Report on Form 10-K for the year
ended December 31, 1997 (File No. 0-12014); units granted in 1996 are
incorporated herein by reference to Exhibit (10)(iii)(A)(3) of the
Companys Annual Report on Form 10-K for the year ended December 31, 1996
(File No. 0-12014); units granted in 1995 are incorporated herein by
reference to Exhibit (10)(iii)(A)(3) of the Companys Annual Report on
Form 10-K for the year ended December 31, 1995 (File No. 0-12014); and
units granted in 1994 are incorporated herein by reference to Exhibit
(10)(iii)(A)(3) of the Companys Annual Report on Form 10-K for the year
ended December 31, 1994 (File No. 0-12014).(3)
    
    Deferred Share Unit Plan. (Incorporated herein by reference to
Exhibit(10)(iii)(A)(5) of the Companys Annual Report on Form 10-K for the
year ended December 31, 1998 (File No. 0-12014)).(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 Units granted in 2003; Earnings Bonus Unit Plan and
units granted in 2002 are (incorporated herein by reference to Exhibit
(10)(iii)(A)(5) of the Companys Annual Report on Form 10-K for the year
ended December 31, 2002 (File No. 0-12014)) and Earnings Bonus Unit Plan
and units granted in 2001 are 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, 2000 (File No. 0-12014).(6)
    
    Incentive Stock Option Plan and Incentive Stock Options granted in
2002 (Incorporated herein by reference to Exhibit (10)(iii)(A)(6) of the
Companys Quarterly Report on Form 10-Q for the quarter ended June 30,
2002 (File No. 0-12014)).(7)
    
    Restricted Stock Unit Plan and Restricted Stock Units granted in 2002
(incorporated herein by reference to Exhibit (10)(iii)(A)(7) of the
Companys Annual Report on Form 10-K for the year ended December 31, 2002
(File No. 0-12014)).(8)
    
    Restricted Stock Unit Plan and Restricted Stock Units granted in 2003. (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, 2003.(23)
    
    (ii)
    
    (A)
    
    Consent of PricewaterhouseCoopers LLP.(B)
    
    Consent of Chief Engineering Officer.
  (31.1)
    
    Certification by principal executive officer of Periodic Financial
Report pursuant to Rule 13a-14(a)(31.2)
    
    Certification by principal financial
officer of Periodic Financial Report pursuant to Rule 13a-14(a).(32.1)
    
    Certification by chief executive officer of Periodic Financial Report pursuant
to Rule 13a-14(b) and 18 U.S.C. Section 1350.(32.2)
    
    Certification by chief financial officer of Periodic Financial Report
pursuant to Rule 13a-14(b) and 18 U.S.C. Section 1350. Copies of Exhibits may be acquired upon written request of any shareholder
to the investor relations manager, Imperial Oil Limited, 111 St. Clair Avenue
West, Toronto, Ontario, Canada M5W 1K3, and payment of processing and mailing
costs. Except for a report on Form 8-K dated October 28, 2003, the Company did
not file any other reports on Form 8-K during the fourth quarter of 2003. By
the report on Form 8-K dated October 28, 2003, the Company submitted to the
Securities and Exchange Commission a press release of the Company on October
23, 2003 disclosing information relating to the Companys financial condition
and results of operations for the fiscal quarter ended September 30, 2003. 49




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##### Table of Contents



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 11, 2004 by the undersigned, thereunto duly authorized. IMPERIAL OIL LIMITEDBy
    
    /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 11, 2004 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(Pierre Des Marais II)
    
    Director/s/ Brian J. Fischer(Brian J. Fischer)
    
    Director/s/ Roger Phillips(Roger Phillips)
    
    Director/s/ J. Shepard(James F. Shepard)
    
    Director/s/ Sheelagh D. Whittaker(Sheelagh D. Whittaker)
    
    Director/s/ K. C. Williams(K.C. Williams)
    
    Director/s/ Victor L. Young(Victor L. Young)
    
    Director
 50




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##### Table of Contents



INDEX TO FINANCIAL STATEMENTS Pages in thisReportAuditors report
    
    F-2Financial statements:Consolidated statement of earnings for the years 1999,
2000, 2001, 2002 and 2003
    
    F-3Consolidated statement of cash flows for the years 1999,
2000, 2001, 2002 and 2003
    
    F-4Consolidated balance sheet as at December 31, 1999, 2000,
2001, 2002 and 2003
    
    F-5Summary of significant accounting policies
    
    F-6  F-8Notes to the consolidated financial statements
    
    F-9  F18
 F-1




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##### Table of Contents



Auditors Report To the Directors of
Imperial Oil Limited We have audited the consolidated balance sheets of Imperial Oil Limited as at
December 31, 2003 and 2002 and the consolidated statements of earnings and cash
flows for each of the three years in the period ended December 31, 2003. These
financial statements are the responsibility of the Companys management. Our
responsibility is to express an opinion on these financial statements based on
our audits. We conducted our audits in accordance with auditing standards generally
accepted in Canada and the United States. Those standards require that we plan
and perform an audit to obtain reasonable assurance whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. In our opinion, these consolidated financial statements present fairly, in all
material respects, the financial position of the Company as at December 31,
2003 and 2002 and the results of its operations and its cash flows for each of
the three years in the period ended December 31, 2003 in accordance with
Canadian generally accepted accounting principles. We have also audited the Reconciliation of Canadian and United States
generally accepted accounting principles in Item 6 of this 10-K as at December
31, 2003 and 2002 and for each of the three years in the period ended December
31, 2003. In our opinion, the Reconciliation of Canadian and United States
generally accepted accounting principles 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 18, 2004 F-2




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##### Table of Contents



Consolidated statement of earnings (a) millions of dollarsFor the years ended December 31
    
    2003
    
    2002
    
    2001
    
    2000
    
    1999RevenuesOperating revenues (b)
    
    
    19,094
    
    
    
    16,890
    
    
    
    17,153
    
    
    
    17,829
    
    
    
    12,763Investment and other income
    
    
    114
    
    
    
    152
    
    
    
    100
    
    
    
    222
    
    
    
    90Total revenues
    
    
    19,208
    
    
    
    17,042
    
    
    
    17,253
    
    
    
    18,051
    
    
    
    12,853ExpensesExploration
    
    
    55
    
    
    
    30
    
    
    
    45
    
    
    
    35
    
    
    
    28Purchases of crude oil and products
    
    
    11,580
    
    
    
    10,155
    
    
    
    10,134
    
    
    
    10,772
    
    
    
    7,091Operating
    
    
    2,025
    
    
    
    1,865
    
    
    
    1,830
    
    
    
    1,554
    
    
    
    1,511Selling and general
    
    
    1,269
    
    
    
    1,222
    
    
    
    1,280
    
    
    
    1,271
    
    
    
    1,251Federal excise tax (b)
    
    
    1,254
    
    
    
    1,231
    
    
    
    1,180
    
    
    
    1,194
    
    
    
    1,188Depreciation and depletion
    
    
    750
    
    
    
    705
    
    
    
    718
    
    
    
    726
    
    
    
    736Financing costs (note 12)
    
    
    (87
    )
    
    
    32
    
    
    
    152
    
    
    
    163
    
    
    
    38Total expenses
    
    
    16,846
    
    
    
    15,240
    
    
    
    15,339
    
    
    
    15,715
    
    
    
    11,843Earnings before income taxes
    
    
    2,362
    
    
    
    1,802
    
    
    
    1,914
    
    
    
    2,336
    
    
    
    1,010Income taxes(note 4)
    
    
    680
    
    
    
    578
    
    
    
    659
    
    
    
    926
    
    
    
    382Net earnings
    
    
    1,682
    
    
    
    1,224
    
    
    
    1,255
    
    
    
    1,410
    
    
    
    628Per-share information(dollars)Net earnings
 basic and diluted (note 10)

    
    
    4.52
    
    
    
    3.23
    
    
    
    3.19
    
    
    
    3.38
    
    
    
    1.46Dividends
    
    
    0.87
    
    
    
    0.84
    
    
    
    0.83
    
    
    
    0.78
    
    
    
    0.75
  (a)
    
    Business segments are reported in note 1.(b)
    
    Operating revenues include
federal excise tax of $1,254 million (2002 
$1,231 million; 2001  $1,180
million). The information on pages F-6
through F-18 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-3




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##### Table of Contents



Consolidated statement of cash flows millions of dollarsinflow (outflow)For the years ended December 31
    
    2003
    
    2002
    
    2001
    
    2000
    
    1999Operating activitiesNet earnings
    
    
    1,682
    
    
    
    1,224
    
    
    
    1,255
    
    
    
    1,410
    
    
    
    628Depreciation and depletion
    
    
    750
    
    
    
    705
    
    
    
    718
    
    
    
    726
    
    
    
    736(Gain)/loss on asset sales, after tax
    
    
    (10
    )
    
    
    (4
    )
    
    
    (7
    )
    
    
    (96
    )
    
    
    (17
    )Future income taxes and other
    
    
    (68
    )
    
    
    (144
    )
    
    
    50
    
    
    
    (175
    )
    
    
    (324
    )Cash flow from earnings (note 11)
    
    
    2,354
    
    
    
    1,781
    
    
    
    2,016
    
    
    
    1,865
    
    
    
    1,023Accounts receivable
    
    
    33
    
    
    
    (356
    )
    
    
    504
    
    
    
    (358
    )
    
    
    (124
    )Inventories and prepaids
    
    
    31
    
    
    
    51
    
    
    
    (11
    )
    
    
    (6
    )
    
    
    (16
    )Income taxes payable
    
    
    38
    
    
    
    (225
    )
    
    
    (408
    )
    
    
    503
    
    
    
    225Accounts payable and other (a)
    
    
    (262
    )
    
    
    425
    
    
    
    (97
    )
    
    
    85
    
    
    
    362Change in operating assets and liabilities
    
    
    (160
    )
    
    
    (105
    )
    
    
    (12
    )
    
    
    224
    
    
    
    447Cash from operating activities
    
    
    2,194
    
    
    
    1,676
    
    
    
    2,004
    
    
    
    2,089
    
    
    
    1,470Investing activitiesAdditions to property, plant
and equipment and intangibles
    
    
    (1,449
    )
    
    
    (1,552
    )
    
    
    (1,070
    )
    
    
    (644
    )
    
    
    (625
    )Proceeds from asset sales
    
    
    56
    
    
    
    61
    
    
    
    46
    
    
    
    274
    
    
    
    88Proceeds from marketable securities
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    116
    
    
    
    59Additions to marketable securities
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    (58
    )
    
    
    (88
    )Cash from (used in) investing activities
    
    
    (1,393
    )
    
    
    (1,491
    )
    
    
    (1,024
    )
    
    
    (312
    )
    
    
    (566
    )Financing activitiesShort-term
debt  net
    
    
    
    
    
    
    (388
    )
    
    
    385
    
    
    
    75
    
    
    
    Long-term debt issued
    
    
    818
    
    
    
    500
    
    
    
    
    
    
    
    
    
    
    
    Repayment of long-term debt
    
    
    (818
    )
    
    
    (71
    )
    
    
    (379
    )
    
    
    (68
    )
    
    
    (379
    )Issuance of common shares
under stock option plan
    
    
    2
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Common shares purchased (note 10)
    
    
    (799
    )
    
    
    (13
    )
    
    
    (812
    )
    
    
    (1,208
    )
    
    
    Dividends paid
    
    
    (322
    )
    
    
    (319
    )
    
    
    (322
    )
    
    
    (331
    )
    
    
    (319
    )Cash from (used in) financing activities
    
    
    (1,119
    )
    
    
    (291
    )
    
    
    (1,128
    )
    
    
    (1,532
    )
    
    
    (698
    )Increase (decrease) in cash
    
    
    (318
    )
    
    
    (106
    )
    
    
    (148
    )
    
    
    245
    
    
    
    206Cash at beginning of year
    
    
    766
    
    
    
    872
    
    
    
    1,020
    
    
    
    775
    
    
    
    569Cash at end of year(b)
    
    
    448
    
    
    
    766
    
    
    
    872
    
    
    
    1,020
    
    
    
    775
  (a)
    
    Includes contribution to
registered pension plans of $511
million (2002  $19 million; 2001
 $6 million).  (b)
    
    Cash is composed of cash in
bank and cash equivalents at cost.
Cash equivalents are all highly
liquid securities with a
maturity of three months or less
when purchased. The information on pages F-6
through F-18 is part of these
consolidated financial
statements. Certain figures for
prior years have been
reclassified in the financial
statements to conform with the
current years presentation. F-4




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##### Table of Contents



Consolidated balance sheet millions of dollarsAt December 31
    
    2003
    
    2002
    
    2001
    
    2000
    
    1999AssetsCurrent assetsCash
    
    
    448
    
    
    
    766
    
    
    
    872
    
    
    
    1,020
    
    
    
    775Marketable securities
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    59Accounts receivable (note 11)
    
    
    1,315
    
    
    
    1,348
    
    
    
    992
    
    
    
    1,496

    
    
    
    1,138Inventories of crude oil and products (note 11)
    
    
    407
    
    
    
    433
    
    
    
    478
    
    
    
    421
    
    
    
    451Materials, supplies and prepaid expenses
    
    
    105
    
    
    
    110
    
    
    
    116
    
    
    
    162
    
    
    
    125Future income tax assets (note 4)
    
    
    353
    
    
    
    323
    
    
    
    227
    
    
    
    377
    
    
    
    285Total current assets
    
    
    2,628
    
    
    
    2,980
    
    
    
    2,685
    
    
    
    3,476
    
    
    
    2,833Investments and other
long-term assets (note 5)
    
    
    259
    
    
    
    134
    
    
    
    139
    
    
    
    127
    
    
    
    172Property, plant and equipment (note 1)
    
    
    9,218
    
    
    
    8,525
    
    
    
    7,722
    
    
    
    7,391
    
    
    
    7,549Goodwill (note 1)
    
    
    204
    
    
    
    204
    
    
    
    204
    
    
    
    232
    
    
    
    260Other intangible assets (note 1)
    
    
    52
    
    
    
    51
    
    
    
    31
    
    
    
    18
    
    
    
    14Total assets(note 1)
    
    
    12,361
    
    
    
    11,894
    
    
    
    10,781
    
    
    
    11,244
    
    
    
    10,828LiabilitiesCurrent liabilitiesShort-term debt
    
    
    72
    
    
    
    72
    
    
    
    460
    
    
    
    75
    
    
    
    Accounts payable and accrued
liabilities (note 13)
    
    
    2,222
    
    
    
    2,114
    
    
    
    1,791
    
    
    
    1,866
    
    
    
    1,731Income taxes payable
    
    
    595
    
    
    
    557
    
    
    
    774
    
    
    
    1,182
    
    
    
    666Current portion of long-term debt
    
    
    501
    
    
    
    
    
    
    
    
    
    
    
    300
    
    
    
    Total current liabilities
    
    
    3,390
    
    
    
    2,743
    
    
    
    3,025
    
    
    
    3,423
    
    
    
    2,397Long-term debt (note 3)
    
    
    859
    
    
    
    1,466
    
    
    
    1,029
    
    
    
    1,037
    
    
    
    1,352Other long-term obligations (note 6)
    
    
    972
    
    
    
    1,207
    
    
    
    1,098
    
    
    
    1,104
    
    
    
    1,172Future income tax liabilities (note 4)
    
    
    1,362
    
    
    
    1,262
    
    
    
    1,306
    
    
    
    1,476
    
    
    
    1,580Commitments and contingent liabilities (note 9)Total liabilities
    
    
    6,583
    
    
    
    6,678
    
    
    
    6,458
    
    
    
    7,040
    
    
    
    6,501Shareholders equityCommon shares at stated value (note 10)
    
    
    1,859
    
    
    
    1,939
    
    
    
    1,941
    
    
    
    2,039
    
    
    
    2,209Net earnings retained and
used in the businessAt beginning of year
    
    
    3,277
    
    
    
    2,382
    
    
    
    2,165
    
    
    
    2,118
    
    
    
    1,814Net earnings for the year
    
    
    1,682
    
    
    
    1,224
    
    
    
    1,255
    
    
    
    1,410
    
    
    
    628Share purchases (note 10)
    
    
    (717
    )
    
    
    (11
    )
    
    
    (714
    )
    
    
    (1,038
    )
    
    
    Dividends
    
    
    (323
    )
    
    
    (318
    )
    
    
    (324
    )
    
    
    (325
    )
    
    
    (324
    )At end of year
    
    
    3,919
    
    
    
    3,277
    
    
    
    2,382
    
    
    
    2,165
    
    
    
    2,118Total shareholders equity
    
    
    5,778
    
    
    
    5,216
    
    
    
    4,323
    
    
    
    4,204
    
    
    
    4,327Total liabilities and shareholders equity
    
    
    12,361
    
    
    
    11,894
    
    
    
    10,781
    
    
    
    11,244
    
    
    
    10,828
 The information on pages F-6
through F-18 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. SmithChairman, president and
    
    Controller and senior vice-president,chief executive officer
    
    finance and administration
 F-5




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##### Table of Contents



Summary of significant accounting policies Principles of consolidation The consolidated financial statements include the accounts of the Company
and its subsidiaries. Intercompany accounts and transactions are eliminated.
Subsidiaries include those companies in which the Company 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 resourcesincludes the exploration for and production of crude oil
and natural gas. Petroleum productscomprises the refining of crude oil into petroleum
products and the distribution and marketing of these products. Chemicalsincludes the manufacturing and marketing of various
hydrocarbon-based chemicals and chemical products. Corporate and otherincludes
assets and liabilities that do not specifically relate to business
segments 
primarily cash, marketable securities and long-term debt. Net earnings in this
category primarily include debt-related charges and interest income. Segment accounting policies are the same as those described in this
summary of significant accounting policies. Natural resources, petroleum
products and chemicals expenses include amounts allocated from the corporate
and other segment. The allocation is based on a combination of fee for
service, proportional segment expenses and a three-year average of capital
expenditures. Transfers of assets between segments are recorded at book
amounts. Items included in capital employed that are not identifiable by
segment are allocated according to their nature. Accounts receivable Accounts receivable arise mainly from customer purchases of the Companys
products. Interest is accrued on overdue accounts (generally those over 30
days) and is reported in investment and other income in the consolidated
statement of earnings. Interest accrual will be suspended if collection becomes
doubtful. An allowance for doubtful accounts is established based upon an
assessment of the 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. Inventory costs include expenditures and other charges, including
depreciation, directly or indirectly incurred in bringing the inventory to its
existing condition and final storage prior to delivery to a customer. Selling
and general expenses are reported as period costs and excluded from inventory
cost. 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 the Companys share of earnings since the investment was
made, less dividends received. The Companys share of the after-tax earnings of
these companies is included in investment and other income in the
consolidated statement of earnings. Other investments are recorded at cost.
Dividends from these other investments are included in investment and other
income. These investments represent interests in non-publicly traded pipeline
companies that facilitate the sale and purchase of crude oil and natural gas in
the conduct of the 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. The Companys does not invest in these companies in
order to remove liabilities from its balance sheet. F-6




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##### Table of Contents



Property, plant and equipment Property, plant and equipment are recorded at cost. Investment tax credits and other similar grants are treated as a reduction
of the capitalized cost of the asset to which they apply. 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
re-evaluated annually. All other exploration costs are expensed as incurred.
Development costs, including the cost of natural
gas and natural gas liquids used as injectants in enhanced (tertiary)
oil-recovery projects, are capitalized. The Company selected the successful-efforts method over the alternative
full-cost method of accounting because it provides a more timely accounting of
the success or failure of exploration and production activities. Maintenance and repair costs, including planned major maintenance, are
expensed as incurred. Improvements that increase or prolong the service life or
capacity of an asset are capitalized. Production costs are expensed as incurred. Production involves lifting the
oil and gas to the surface and gathering, treating, field processing and field
storage of the oil and gas. The production function normally terminates at the
outlet valve on the lease or field production storage tank. Production costs
are those incurred to operate and maintain the Companys wells and related
equipment and facilities. They become part of the cost of oil and gas produced. Depreciation and depletion for assets associated with producing properties
begins at the time when production commences on a regular basis. Depreciation
for other assets begin when the asset is in place and ready for its intended
use. Assets under construction are not depreciated or depleted. Depreciation
and depletion are calculated using the unit-of-production method for producing
properties, including capitalized exploratory drilling and development costs.
Depreciation of other plant and equipment is calculated using the straight-line
method, based on the estimated service life of the asset. In general,
refineries are depreciated over 25 years; other major assets, including
chemical plants and service stations, are depreciated over 20 years. Proved oil and gas properties held and used by the Company are reviewed
for impairment whenever events or changes in circumstances indicate that the
carrying amounts may not be recoverable. Assets are grouped at the lowest level
for which there are identifiable cash flows that are largely independent of the
cash flows of other groups of assets. The Company estimates the future undiscounted cash flows of the affected
properties to judge the recoverability of carrying amounts. Cash flows used in
impairment evaluations are developed using annually updated corporate plan
investment evaluation assumptions for crude oil commodity prices and
foreign-currency exchange rates. Annual volumes are based on individual field
production profiles, which are also updated annually. Prices for natural gas
and other products sold under contract are based on corporate plan assumptions
developed annually by major contracts and also for investment evaluation
purposes. Gains or losses on assets sold are included in investment and other income
in the consolidated statement of earnings. Goodwill and other intangible assets Goodwill and intangible assets with indefinite lives are not subject to
amortization. These assets are tested for impairment annually or more
frequently if events or circumstances indicate the assets might be impaired.
Impairment losses are recognized in current period earnings. The evaluation for
impairment of goodwill is based on a comparison of the carrying values of
goodwill and associated operating assets with the estimated present value of
net cash flows from those operating assets. Intangible assets with determinable useful lives are amortized over the
estimated service lives of the assets. Computer software development costs are
amortized over a maximum of 15 years and customer lists are amortized over a
maximum of 10 years. The amortization is included in depreciation and
depletion in the consolidated statement of earnings. Asset retirement obligations and other environmental liabilities Legal obligations associated with site restoration on the retirement of
assets with determinable useful lives are recognized when they are incurred,
which is typically at the time the assets are installed. The obligations are
initially measured at fair value and discounted to present value. A
corresponding amount equal to that of the initial obligation is added to the
capitalized costs of the related asset. Over time the discounted asset
retirement obligation amount will be accreted for the change in its present
value, and the initial capitalized costs will be depreciated over the useful
lives of the related assets. No asset retirement obligations are set up for assets with an
indeterminate useful life. Provision for environmental liabilities of these and
non-operating assets is made when it is probable that obligations have been
incurred and the amount can be reasonably estimated. The fair values of asset
retirement obligations and other provisions for environmental liabilities are
determined based on engineering estimated costs, taking into account the
anticipated method and extent of remediation consistent with legal
requirements, current technology and the possible use of the location. Foreign-currency translation Monetary assets and liabilities in foreign currencies have been translated
at the rates of exchange prevailing on December 31. Any exchange gains or
losses are recognized in earnings. F-7




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##### Table of Contents



Financial instruments Financial instruments are initially recorded at historical cost. If
subsequent circumstances indicate that a decline in the fair value of a
financial asset is other than temporary, the financial asset is written down to
its fair value. Unless otherwise indicated, the fair values of financial
instruments approximate their recorded amounts. The fair values of cash, marketable securities, accounts receivable and
current liabilities approximate recorded amounts because of the short period to
receipt or payment of cash. The fair value of the Companys long-term debt is
estimated based on quoted market prices for the same or similar issues or on
the current rates offered to the Company for debt of the same duration to
maturity. The fair values of other financial instruments held by the Company
are estimated primarily by discounting future cash flows, using current rates
for similar financial instruments under similar credit risk and maturity
conditions. The Company does not use financing structures for the purpose of altering
accounting outcomes or removing debt from the balance sheet. The Company makes
limited use of derivatives. Derivative instruments are not held for trading
purposes. Revenues Revenues associated with sales of crude oil, natural gas, petroleum and
chemical products and other items are recorded when the products are delivered.
Delivery occurs when the customer has taken title and has assumed the risks and
rewards of ownership, prices are fixed or determinable and collectability is
reasonably assured. The Company does not enter into ongoing arrangements
whereby it is required to repurchase its products, nor does the Company provide
the customer with a right of return. Revenues include amounts billed to customers for shipping and handling.
Shipping and handling costs incurred up to the point of final storage prior to
delivery to a customer are included in purchases of crude oil and products in
the consolidated statement of earnings. Delivery costs from final storage to
customers are recorded as a marketing expense in selling and general expenses. Stock-based compensation The Company accounts for its stock-based compensation programs, except for
the incentive stock options granted in April 2002, by using the
fair-value-based method. Under this method, compensation expense related to the
units of these programs is measured by the fair value of the unit and is
recorded in the consolidated statement of earnings over the vesting period. As permitted by the new Canadian Institute of Chartered Accountants (CICA)
standard on accounting for stock-based compensation, the Company continues to
apply the intrinsic-value-based method of accounting for the incentive stock
options granted in April 2002. Under this method, compensation expense is not
recognized on the issuance of stock options as long as the exercise price is
equal to the market value at the date of grant. Consumer taxes Taxes levied on the consumer and collected by the Company are excluded
from the consolidated statement of earnings. These are primarily provincial
taxes on motor fuels and the federal goods and services tax. Interest costs Interest costs are expensed as incurred and included in financing costs in
the consolidated statement of earnings. Accounting principles The consolidated financial statements have been prepared in accordance
with generally accepted accounting principles (GAAP) in Canada. Form 10-K,
filed with the United States Securities and Exchange Commission, includes a
description of the differences between GAAP in Canada and in the United States
as they apply to the Company. Effective January 1, 2003, the Company has adopted the new CICA standards
on accounting for asset retirement obligations. The impact of adopting this new
standard is described in note 2 to the consolidated financial statements on
page F-10. The Company has early adopted the additional disclosure requirements
by the CICA on employee future benefits, as shown in note 5 on page F-12. The
Company has also early adopted the new CICA standard on stock-based
compensation with no impact on its accounting or reporting. F-8




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##### Table of Contents



Notes to consolidated financial statements  1.
    
    Business segments Natural resources (a)
    
    Petroleum products
    
    Chemicalsmillions of dollars
    
    2003
    
    2002
    
    2001
    
    2003
    
    2002
    
    2001
    
    2003
    
    2002
    
    2001RevenuesExternal sales (c)
    
    
    3,390
    
    
    
    2,573
    
    
    
    3,144
    
    
    
    14,710
    
    
    
    13,362
    
    
    
    13,079
    
    
    
    994
    
    
    
    955
    
    
    
    930Intersegment sales
    
    
    2,224
    
    
    
    2,217
    
    
    
    2,166
    
    
    
    1,294
    
    
    
    1,038
    
    
    
    1,300
    
    
    
    238
    
    
    
    209
    
    
    
    245Investment and other income
    
    
    34
    
    
    
    104
    
    
    
    11
    
    
    
    54
    
    
    
    34
    
    
    
    26
    
    
    
    
    
    
    
    
    
    
    
    Total revenues
    
    
    5,648
    
    
    
    4,894
    
    
    
    5,321
    
    
    
    16,058
    
    
    
    14,434
    
    
    
    14,405
    
    
    
    1,232
    
    
    
    1,164
    
    
    
    1,175ExpensesExploration
    
    
    55
    
    
    
    30
    
    
    
    45
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Purchases of crude oil and products
    
    
    2,357
    
    
    
    1,814
    
    
    
    2,444
    
    
    
    12,066
    
    
    
    10,974
    
    
    
    10,505
    
    
    
    911
    
    
    
    830
    
    
    
    895Operating
    
    
    1,093
    
    
    
    990
    
    
    
    952
    
    
    
    810
    
    
    
    761
    
    
    
    755
    
    
    
    124
    
    
    
    115
    
    
    
    124Selling and general (d)
    
    
    28
    
    
    
    21
    
    
    
    30
    
    
    
    1,123
    
    
    
    1,076
    
    
    
    1,134
    
    
    
    118
    
    
    
    115
    
    
    
    97Federal excise tax
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1,254
    
    
    
    1,231
    
    
    
    1,180
    
    
    
    
    
    
    
    
    
    
    
    Depreciation and depletion (e) (f)
    
    
    517
    
    
    
    479
    
    
    
    457
    
    
    
    211
    
    
    
    203
    
    
    
    238
    
    
    
    22
    
    
    
    23
    
    
    
    23Financing costs (note 12)
    
    
    1
    
    
    
    1
    
    
    
    2
    
    
    
    2
    
    
    
    1
    
    
    
    2
    
    
    
    
    
    
    
    
    
    
    
    Total expenses
    
    
    4,051
    
    
    
    3,335
    
    
    
    3,930
    
    
    
    15,466
    
    
    
    14,246
    
    
    
    13,814
    
    
    
    1,175
    
    
    
    1,083
    
    
    
    1,139Earnings before income taxes
    
    
    1,597
    
    
    
    1,559
    
    
    
    1,391
    
    
    
    592
    
    
    
    188
    
    
    
    591
    
    
    
    57
    
    
    
    81
    
    
    
    36Income taxes(note 4)Current
    
    
    535
    
    
    
    517
    
    
    
    556
    
    
    
    66
    
    
    
    172
    
    
    
    125
    
    
    
    13
    
    
    
    40
    
    
    
    11Future
    
    
    (77
    )
    
    
    (14
    )
    
    
    (122
    )
    
    
    119
    
    
    
    (111
    )
    
    
    113
    
    
    
    7
    
    
    
    (11
    )
    
    
    2Total income tax expense
    
    
    458
    
    
    
    503
    
    
    
    434
    
    
    
    185
    
    
    
    61
    
    
    
    238
    
    
    
    20
    
    
    
    29
    
    
    
    13Net earnings
    
    
    1,139
    
    
    
    1,056
    
    
    
    957
    
    
    
    407
    
    
    
    127
    
    
    
    353
    
    
    
    37
    
    
    
    52
    
    
    
    23Cash flow from earnings
    
    
    1,576
    
    
    
    1,526
    
    
    
    1,287
    
    
    
    719
    
    
    
    216
    
    
    
    700
    
    
    
    66
    
    
    
    63
    
    
    
    49Capital and exploration expenditures(g)
    
    
    1,007
    
    
    
    986
    
    
    
    746
    
    
    
    478
    
    
    
    589
    
    
    
    339
    
    
    
    41
    
    
    
    25
    
    
    
    30Property, plant and equipmentCost
    
    
    12,610
    
    
    
    11,672
    
    
    
    10,785
    
    
    
    6,069
    
    
    
    5,827
    
    
    
    5,462
    
    
    
    609
    
    
    
    579
    
    
    
    554Accumulated depreciation and depletion
    
    
    6,813
    
    
    
    6,303
    
    
    
    5,871
    
    
    
    2,856
    
    
    
    2,867
    
    
    
    2,842
    
    
    
    401
    
    
    
    383
    
    
    
    366Net property, plant and equipment(h)
    
    
    5,797
    
    
    
    5,369
    
    
    
    4,914
    
    
    
    3,213
    
    
    
    2,960
    
    
    
    2,620
    
    
    
    208
    
    
    
    196
    
    
    
    188Total assets(f)
    
    
    6,434
    
    
    
    6,014
    
    
    
    5,385
    
    
    
    5,341
    
    
    
    5,048
    
    
    
    4,348
    
    
    
    446
    
    
    
    418
    
    
    
    373Total capital employed
    
    
    3,784
    
    
    
    3,325
    
    
    
    2,580
    
    
    
    2,784
    
    
    
    2,484
    
    
    
    2,148
    
    
    
    246
    
    
    
    178
    
    
    
    195
 Corporate and other
    
    Consolidated (b)millions of dollars
    
    2003
    
    2002
    
    2001
    
    2003
    
    2002
    
    2001RevenuesExternal sales (c)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    19,094
    
    
    
    16,890
    
    
    
    17,153Intersegment sales
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Investment and other income
    
    
    26
    
    
    
    14
    
    
    
    63
    
    
    
    114
    
    
    
    152
    
    
    
    100Total revenues
    
    
    26
    
    
    
    14
    
    
    
    63
    
    
    
    19,208
    
    
    
    17,042
    
    
    
    17,253ExpensesExploration
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    55
    
    
    
    30
    
    
    
    45Purchases of crude oil and products
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    11,580
    
    
    
    10,155
    
    
    
    10,134Operating
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    2,025
    
    
    
    1,865
    
    
    
    1,830Selling and general (d)
    
    
    
    
    
    
    10
    
    
    
    19
    
    
    
    1,269
    
    
    
    1,222
    
    
    
    1,280Federal excise tax
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1,254
    
    
    
    1,231
    
    
    
    1,180Depreciation and depletion (e) (f)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    750
    
    
    
    705
    
    
    
    718Financing costs (note 12)
    
    
    (90
    )
    
    
    30
    
    
    
    148
    
    
    
    (87
    )
    
    
    32
    
    
    
    152Total expenses
    
    
    (90
    )
    
    
    40
    
    
    
    167
    
    
    
    16,846
    
    
    
    15,240
    
    
    
    15,339Earnings before income taxes
    
    
    116
    
    
    
    (26
    )
    
    
    (104
    )
    
    
    2,362
    
    
    
    1,802
    
    
    
    1,914Income taxes(note 4)Current
    
    
    (4
    )
    
    
    (11
    )
    
    
    (13
    )
    
    
    610
    
    
    
    718
    
    
    
    679Future
    
    
    21
    
    
    
    (4
    )
    
    
    (13
    )
    
    
    70
    
    
    
    (140
    )
    
    
    (20
    )Total income tax expense
    
    
    17
    
    
    
    (15
    )
    
    
    (26
    )
    
    
    680
    
    
    
    578
    
    
    
    659Net earnings
    
    
    99
    
    
    
    (11
    )
    
    
    (78
    )
    
    
    1,682
    
    
    
    1,224
    
    
    
    1,255Cash flow from earnings
    
    
    (7
    )
    
    
    (24
    )
    
    
    (20
    )
    
    
    2,354
    
    
    
    1,781
    
    
    
    2,016Capital and exploration expenditures(g)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    1,526
    
    
    
    1,600
    
    
    
    1,115Property, plant and equipmentCost
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    19,288
    
    
    
    18,078
    
    
    
    16,801Accumulated depreciation and depletion
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    10,070
    
    
    
    9,553
    
    
    
    9,079Net property, plant and equipment(h)
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    9,218
    
    
    
    8,525
    
    
    
    7,722Total assets(f)
    
    
    448
    
    
    
    766
    
    
    
    873
    
    
    
    12,361
    
    
    
    11,894
    
    
    
    10,781Total capital employed
    
    
    448
    
    
    
    816
    
    
    
    918
    
    
    
    7,262
    
    
    
    6,803
    
    
    
    5,841
 (Continued on following page) F-9




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##### Table of Contents



(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
    
    2003
    
    2002
    
    2001Total revenues
    
    
    2,494
    
    
    
    2,357
    
    
    
    2,689Total expenses
    
    
    1,577
    
    
    
    1,520
    
    
    
    1,733Net earnings, after income taxes
    
    
    664
    
    
    
    557
    
    
    
    637Total current assets
    
    
    302
    
    
    
    321
    
    
    
    232Long-term assets
    
    
    3,553
    
    
    
    3,038
    
    
    
    2,750Total current liabilities
    
    
    913
    
    
    
    669
    
    
    
    919Other long-term obligations
    
    
    302
    
    
    
    268
    
    
    
    262Cash flow from earnings
    
    
    868
    
    
    
    767
    
    
    
    828Cash flow from operating activities
    
    
    883
    
    
    
    615
    
    
    
    850Cash from (used in) investing activities
    
    
    (754
    )
    
    
    (601
    )
    
    
    (301
    )
  (b)
    
    Information is presented as though each segment were a separate business activity. Intersegment sales are made essentially at prevailing market prices.
Consolidated amounts exclude intersegment transactions, as follows: millions of dollars
    
    2003
    
    2002
    
    2001Purchases of crude oil and products
    
    
    3,754
    
    
    
    3,463
    
    
    
    3,710Operating expense
    
    
    2
    
    
    
    1
    
    
    
    1Total intersegment sales
    
    
    3,756
    
    
    
    3,464
    
    
    
    3,711Intersegment receivables and payables
    
    
    308
    
    
    
    352
    
    
    
    198
  (c)
    
    Includes export sales to the United States, as follows: millions of dollars
    
    2003
    
    2002
    
    2001Natural resources
    
    
    1,304
    
    
    
    942
    
    
    
    1,018Petroleum products
    
    
    792
    
    
    
    723
    
    
    
    770Chemicals
    
    
    567
    
    
    
    520
    
    
    
    503Total export sales
    
    
    2,663
    
    
    
    2,185
    
    
    
    2,291
  (d)
    
    Consolidated selling and general expenses include delivery
costs from final storage to customers of $285 million (2002
 $216 million; 2001  $244 million).(e)
    
    Goodwill was not amortized in 2003 and 2002 (amortization
expense in 2001  $28 million). All goodwill has been assigned to the petroleum products segment. There
have been no goodwill acquisitions, impairment losses or write-offs due to sales in the past three years.(f)
    
    Total assets include amortized intangible assets, consisting primarily of acquired customer lists and capitalized computer-software development costs, as follows: millions of dollars
    
    2003
    
    2002Cost
    
    
    87
    
    
    
    81Accumulated amortization
    
    
    35
    
    
    
    30Net intangible assets
    
    
    52
    
    
    
    51
  Customer lists acquired in 2003 were $1 million (2002
 $5 million), those
disposed of or retired were $1 million (2002  $1 million) and no gain or loss
was recognized. Capitalized computer-software development costs in 2003 were $6
million (2002  $20 million). The estimated annual amortization expense for
intangible assets in each of the next five years is $8 million.(g)
    
    Capital and exploration expenditures of the petroleum products segment
include non-cash capital leases of $22 million in 2003 (2002
 $18 million).(h)
    
    Includes property, plant and equipment under construction of $1,426
million (2002  $1,275 million).  2.
    
    Reporting changes Effective January 1, 2003, the Company implemented reporting changes to
reflect the new accounting standard of the Canadian Institute of Chartered
Accountants (CICA) dealing with accounting for asset retirement obligations.
The new CICA standard changes the method of accruing for certain
site-restoration costs. Under the new standard, the fair values of asset
retirement obligations are recorded as liabilities on a discounted basis when
they are incurred, which is typically at the time the related assets are
installed. Amounts recorded for the related assets are increased by the amount
of these obligations. Over time the liabilities will be accreted for the
change in their present value, and the initial capitalized costs will be
depreciated over the useful lives of the related assets. There are no asset
retirement liabilities set up for those assets that have an indeterminate
useful life. Estimated cash flows have been discounted at six percent. Implementation
of the new standard has reduced environmental liabilities by $28 million to
$462 million as of December 31, 2003. The total undiscounted amount of the
estimated cash flows required to settle the obligations is $895 million.
Payments to settle the obligations occur on an ongoing basis and will continue
over the lives of the operating assets, which can exceed 25 years. This change
in accounting standard has no impact on the cash flow profile of the Company.
The new standard has been applied retroactively, and the financial statements
of prior periods have been restated. (Continued on following page) F-10




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##### Table of Contents



The impact of adopting the new standard of accounting for asset retirement
obligations on the consolidated balance sheet and statement of earnings is: Changes in consolidated balance sheet millions of dollars increase/(decrease)
    
    2003
    
    2002Property, plant and equipment
    
    
    24
    
    
    
    26Total assets
    
    
    24
    
    
    
    26Other long-term obligations
    
    
    (28
    )
    
    
    20Future income tax liabilities
    
    
    18
    
    
    
    2Retained earnings
    
    
    34
    
    
    
    4Total liabilities and shareholders equity
    
    
    24
    
    
    
    26
 Changes in consolidated statement of earnings millions of dollars increase/(decrease)
    
    2003
    
    2002
    
    2001Operating expense
    
    
    (48
    )
    
    
    (23
    )
    
    
    (25
    )Depreciation and depletion expense
    
    
    2
    
    
    
    2
    
    
    
    2Total expenses
    
    
    (46
    )
    
    
    (21
    )
    
    
    (23
    )Income taxes
    
    
    16
    
    
    
    7
    
    
    
    7Net earnings
    
    
    30
    
    
    
    14
    
    
    
    16Earnings per share basic and diluted (dollars)
    
    
    0.08
    
    
    
    0.04
    
    
    
    0.04
 The change in asset retirement obligations liability is as follows: millions of dollars
    
    2003
    
    2002Asset retirement obligations liability at January 1
    
    
    341
    
    
    
    334Additions
    
    
    
    
    
    
    8Accretion
    
    
    20
    
    
    
    20Settlements
    
    
    (34
    )
    
    
    (21Asset retirement obligations liability at December 31
    
    
    327
    
    
    
    341
  3.
    
    Long-term debt 2003
    
    2002issued
    
    maturity date
    
    interest rate
    
    millions of dollars1989
    
    September 1, 2004 (2002  $600 million (U.S.))(a)
    
    Variable
    
    
    
    
    
    
    9462002
    
    May 7, 2004 (b)
    
    Variable
    
    
    
    
    
    
    5002003
    
    $250 million due May 26, 2005 and$250 million due August 26, 2005(a)
    
    Variable
    
    
    500
    
    
    
    2003
    
    January 19, 2006(a)
    
    Variable
    
    
    318
    
    
    
    Long-term debt (at period-end exchange rates)(c)
    
    
    
    
    818
    
    
    
    1,446Capital leases(d)
    
    
    
    
    41
    
    
    
    20Total long-term debt(e)
    
    
    
    
    859
    
    
    
    1,466
  (a)
    
    During the first half of 2003, the company redeemed the $600-million (U.S.)
variable-rate debt for $818 million (Cdn) and replaced it with long-term
variable-rate loans of $818 million (Cdn) from Exxon Overseas Corporation at
interest equivalent to Canadian market rates. The average effective interest
rate for the loans was 3.1 percent for 2003.(b)
    
    Principal payments on medium-term notes of $500 million, which have been
reclassified to current portion of long-term debt in the balance sheet, are due
in 2004.These notes are extendable up to May 7, 2007, at note holders discretion.(c)
    
    The estimated fair value of the long-term debt at December 31, 2003, was
$818 million (2002  $1,446 million).(d)
    
    These obligations primarily relate to the capital lease for marine
services, which are to be provided by the lessor commencing in 2004 for a
period of 10 years, extendable for an additional five years. The obligations
recorded to date represent the costs incurred by the lessor for the
construction of the related marine assets.(e)
    
    Principal payments on long-term loans of $500 million are due in 2005 and
$318 million are due in 2006. Principal payments on capital leases of
approximately $4 million a year are due in each of the next five years. F-11




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##### Table of Contents



4.
    
    Income taxes millions of dollars
    
    2003
    
    2002
    
    2001Current income tax expense
    
    
    610
    
    
    
    718
    
    
    
    679Future income tax expense (a)
    
    
    70
    
    
    
    (140
    )
    
    
    (20
    )Total income tax expense(b)
    
    
    680
    
    
    
    578
    
    
    
    659Statutory corporate tax rate (percent)
    
    
    38.5
    
    
    
    42.0
    
    
    
    42.7Increase/(decrease) resulting from:Non-deductible royalty payments to governments
    
    
    5.0
    
    
    
    5.4
    
    
    
    7.9Resource allowance in lieu of royalty deduction
    
    
    (7.5
    )
    
    
    (11.8
    )
    
    
    (11.4
    )Manufacturing and processing credit
    
    
    0.2
    
    
    
    (0.3
    )
    
    
    (1.3
    )Non-deductible depreciation and amortization
    
    
    
    
    
    
    
    
    
    
    0.6Enacted tax rate change
    
    
    (3.1
    )
    
    
    (0.9
    )
    
    
    (2.1
    )Other
    
    
    (4.3
    )
    
    
    (2.3
    )
    
    
    (2.0
    )Effective income tax rate
    
    
    28.8
    
    
    
    32.1
    
    
    
    34.4
 Future income taxes are based on differences between the accounting and
tax values of assets and liabilities. These differences in value are remeasured
at each period-end using the tax rates and tax laws expected to apply when
those differences are realized or settled in the future. Components of future
income tax liabilities and assets as at December 31 were: millions of dollars
    
    2003
    
    2002Depreciation and amortization
    
    
    1,233
    
    
    
    1,098Successful drilling and land acquisitions
    
    
    495
    
    
    
    660Pension and benefits
    
    
    (137
    )
    
    
    (229
    )Site restoration
    
    
    (167
    )
    
    
    (186
    )Net tax loss carryforwards (c)
    
    
    (57
    )
    
    
    (37
    )Other
    
    
    (5
    )
    
    
    (44
    )Total future income tax liabilities
    
    
    1,362
    
    
    
    1,262LIFO inventory valuation
    
    
    (268
    )
    
    
    (271
    )Other
    
    
    (85
    )
    
    
    (52
    )Total future income tax assets
    
    
    (353
    )
    
    
    (323
    )Net future income tax liabilities
    
    
    1,009
    
    
    
    939
  (a)
    
    The future income tax expense for the year is the difference in net future
income tax liabilities at the beginning and end of the year.(b)
    
    Net cash outflow from income taxes, plus investment credits earned, were
$573 million in 2003 (2002  $935 million; 2001  $1,086 million).(c)
    
    Tax
losses can be carried forward indefinitely. The operations of the Company are complex, and related tax
interpretations, regulations and legislation are continually changing. As a
result, there are usually some tax matters in question. The Company believes
the provision made for income taxes is adequate.  5.
    
    Employee retirement benefits Retirement benefits, which cover almost all retired employees and their
surviving spouses, include pension-income and certain health-care and
life-insurance benefits. They are met through funded registered
retirement plans and through unfunded supplementary benefits that are
paid directly to recipients. Funding of registered retirement plans
complies with federal and provincial pension regulations, and the Company
makes contributions to the plans based upon an independent actuarial
valuation. Pension-income benefits consist mainly of company-paid defined benefit plans
that are based on years of service and final average earnings. The
Company shares in the cost of health-care and life-insurance benefits.
The Companys benefit obligations are based on the projected benefit
method of valuation which includes employee service to date and present
compensation levels as well as a projection of salaries and service to
retirement. The expense and obligations for both funded and unfunded benefits are
determined in accordance with generally accepted Canadian accounting
principles and actuarial procedures. The process for determining
retirement-income expense and related obligations includes making certain
long-term assumptions regarding the discount rate, rate of return on plan
assets and rate of compensation increases. The total obligation for employee retirement benefits exceeded the fair
value of plan assets at December 31, 2003, by
$1,357 million (2002 
$1,780 million), 975 million (2002  $1,426 million) of which was related
to pension benefits and $382 million (2002  354 million) was related to
other post-retirement benefits. The obligation and pension expense can
vary significantly with changes in the assumptions used to estimate the
obligation and the expected return on plan assets. (Continued on following page) F-12




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##### Table of Contents



Details of the employee retirement benefits plans are as follows: Pension benefits
    
    Other post-retirement benefitsmillions of dollars
    
    2003
    
    2002
    
    2001
    
    2003
    
    2002
    
    2001Components of net benefit expenseCurrent service cost
    
    
    71
    
    
    
    64
    
    
    
    57
    
    
    
    5
    
    
    
    4
    
    
    
    4Interest cost
    
    
    219
    
    
    
    222
    
    
    
    215
    
    
    
    22
    
    
    
    21
    
    
    
    21Expected return on plan assets
    
    
    (179
    )
    
    
    (191
    )
    
    
    (257
    )
    
    
    
    
    
    
    
    
    
    
    Amortization of prior service cost
    
    
    25
    
    
    
    25
    
    
    
    23
    
    
    
    
    
    
    
    
    
    
    
    Recognized actuarial loss/(gain)
    
    
    69
    
    
    
    34
    
    
    
    
    
    
    
    3
    
    
    
    1
    
    
    
    Net benefit expense(a)(e)
    
    
    205
    
    
    
    154
    
    
    
    38
    
    
    
    30
    
    
    
    26
    
    
    
    25Change in benefit obligationBenefit obligation at January 1
    
    
    3,530
    
    
    
    3,248
    
    
    
    
    
    
    
    354
    
    
    
    323Current service cost
    
    
    71
    
    
    
    64
    
    
    
    
    
    
    
    5
    
    
    
    4Interest cost
    
    
    219
    
    
    
    222
    
    
    
    
    
    
    
    22
    
    
    
    21Amendments
    
    
    
    
    
    
    27
    
    
    
    
    
    
    
    
    
    
    
    Actuarial loss/(gain)
    
    
    171
    
    
    
    196
    
    
    
    
    
    
    
    19
    
    
    
    25Benefits paid
    
    
    (230
    )
    
    
    (227
    )
    
    
    
    
    
    
    (18
    )
    
    
    (19
    )Benefit obligation at December 31(b)(e)
    
    
    3,761
    
    
    
    3,530
    
    
    
    
    
    
    
    382
    
    
    
    354Change in plan assetsFair value of plan assets at January 1
    
    
    2,104
    
    
    
    2,390Actual return on plan assets
    
    
    377
    
    
    
    (107
    )Company contributions (b)
    
    
    511
    
    
    
    19Payments directly to participants
    
    
    24
    
    
    
    29Benefits paid
    
    
    (230
    )
    
    
    (227
    )Fair value of plan assets at December 31(b)
    
    
    2,786
    
    
    
    2,104Excess/(deficiency) of plan assets
over benefit obligation
    
    
    (975
    )
    
    
    (1,426
    )
    
    
    
    
    
    
    (382
    )
    
    
    (354
    )Unrecognized net actuarial (gain)/loss (c)
    
    
    829
    
    
    
    924
    
    
    
    
    
    
    
    52
    
    
    
    36Unrecognized prior service cost (c)
    
    
    89
    
    
    
    114
    
    
    
    
    
    
    
    
    
    
    
    Total net liability
    
    
    (57
    )
    
    
    (388
    )
    
    
    
    
    
    
    (330
    )
    
    
    (318
    )Less: Prepaid benefit cost (d)
    
    
    162
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    Liability recognized (note 6)
    
    
    (219
    )
    
    
    (388
    )
    
    
    
    
    
    
    (330
    )
    
    
    (318
    )The benefit obligation at year-end includes
funded and unfunded plans, as follows:Funded plans
    
    
    3,464
    
    
    
    3,230
    
    
    
    
    
    
    
    
    
    
    
    Unfunded plans
    
    
    297
    
    
    
    300
    
    
    
    
    
    
    
    382
    
    
    
    354Benefit obligation at December 31
    
    
    3,761
    
    
    
    3,530
    
    
    
    
    
    
    
    382
    
    
    
    354
 Assumptions The discount rate used for year-end employee retirement liabilities
reflects the rate at which employee retirement liabilities could be effectively
settled and is based on the year-end rate of interest on a portfolio of
high-quality bonds. Assumptions used to determine benefit
obligations at December 31 (percent)Discount rate
    
    
    6.25
    
    
    
    6.25
    
    
    
    
    
    
    
    6.25
    
    
    
    6.25Long-term rate of compensation increase
    
    
    3.50
    
    
    
    3.50
    
    
    
    
    
    
    
    3.50
    
    
    
    3.50Assumptions used to determine net benefit
expense for years ended December 31 (percent)Discount rate
    
    
    6.25
    
    
    
    6.75
    
    
    
    7.00
    
    
    
    6.25
    
    
    
    6.75
    
    
    
    7.00Long-term rate of compensation increase
    
    
    3.50
    
    
    
    3.50
    
    
    
    3.50
    
    
    
    3.50
    
    
    
    3.50
    
    
    
    3.50Long-term rate of return on plan assets
    
    
    8.25
    
    
    
    8.25
    
    
    
    10.00
    
    
    
    
    
    
    
    
    
    
    
    
 (Continued on following page) F-13




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##### Table of Contents



Plan assets  The Companys pension plan asset allocation at December 31, 2002 and 2003, and
target allocation for 2004 are as follows: Percentage ofTarget
    
    plan assetsallocation
    
    at December 31Asset category (percent)
    
    2004
    
    2003
    
    2002Equities
    
    
    50 - 75
    
    
    
    62
    
    
    
    60Fixed income
    
    
    25 - 50
    
    
    
    38
    
    
    
    40Other
    
    
    0 - 10
    
    
    
    
    
    
    
    Total
    
    
    
    
    
    
    100
    
    
    
    100
 The Company establishes the long-term expected rate of return by
developing a forward-looking long-term return assumption for each asset class,
taking into account factors such as the expected real return for the specific
asset class and inflation. A single, long-term rate of return is then
calculated as the weighted average of the target asset allocation and the
long-term return assumption for each asset class. The 2003 long-term expected
rate of return of 8.25 percent used in the calculations of pension expense
compares to an actual rate of return over the past decade of 9.5 percent. The Companys investment strategy for benefit plan assets reflects a
long-term view, a careful assessment of the risks inherent in various asset
classes and broad diversification to reduce the risk of the total portfolio.
The Company primarily invests in funds that follow an index-based strategy to
achieve its objectives of diversifying risk while minimizing costs. The fund
holds the Companys common shares only to the extent necessary to replicate the
relevant equity index. Asset-liability studies, or simulations of the
interaction of cash flows associated with both assets and liabilities, are
periodically used to establish the preferred target asset allocation. The
target asset allocation for equity securities reflects the long-term nature of
the liability. The balance of the fund is targeted to debt securities.  (a)
    
    Additional expenses include contributions to defined contribution plans,
primarily the employee savings plan, of $31 million in 2003
(2002  $30
million; 2001  $23 million).(b)
    
    The most recent independent actuarial
valuation was as at June 30, 2003. The measurement date used to determine the
plan assets and the benefit obligations was December 31, 2003.(c)
    
    Unrecorded assets/(liabilities) are amortized over the average remaining
service life of employees, which for 2004 and subsequent years is 13 years
(2003  13.5 years; 2002  13.5 years).(d)
    
    Prepaid benefit costs are included in investments and other
long-term assets on the consolidated balance sheet.(e)
    
    A one-percent
change in the assumptions at which retirement liabilities could be
effectively settled is as follows: One-percent
    
    One-percentmillions of dollars
    
    increase
    
    decreaseRate of return on plan assets:Effect on net benefits expenses
    
    
    (20
    )
    
    
    20Discount rate:Effect on net benefits expenses
    
    
    (35
    )
    
    
    40Effect on benefits obligations
    
    
    (440
    )
    
    
    540Rate of compensation increases:Effect on net benefits expenses
    
    
    25
    
    
    
    (25
    )Effect on benefits obligations
    
    
    130
    
    
    
    (115
    )
  For measurement purposes, a five-percent health-care cost trend rate was
assumed for 2003 and thereafter. A one-percent change in the assumed
health-care cost trend rate would have the following effects: One-percent
    
    One-percentmillions of dollars
    
    increase
    
    decreaseEffect on service and interest cost components
    
    
    3
    
    
    
    (2
    )Effect on other post-retirement benefit obligation
    
    
    35
    
    
    
    (30
    )
  6.
    
    Other long-term obligations millions of dollars
    
    2003
    
    2002Employee retirement benefits (note 5)(a)
    
    
    505
    
    
    
    671Asset
retirement obligations and other environmental liabilities  (b)
    
    
    393
    
    
    
    454Other obligations
    
    
    74
    
    
    
    82Total other long-term obligations
    
    
    972
    
    
    
    1,207
  (a)
    
    Total recorded employee retirement benefits obligations also include $44
million in current liabilities (2002  $35 million).(b)
    
    Total asset retirement obligations and other environmental liabilities
also include $69 million in current liabilities (2002  $71 million).  7.
    
    Derivative financial instruments No significant energy derivatives, foreign-exchange forward contracts or
currency and interest-rate swaps were transacted in the past three years. The
Company maintains a system of controls that includes a policy covering the
authorization, reporting and monitoring of derivative activity. F-14




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##### Table of Contents



8.
    
    Incentive compensation programs Incentive compensation programs are designed to retain selected employees,
reward them for high performance and promote individual contribution to
sustained improvement in the Companys future business performance and
shareholder value.  Incentive share units, deferred share units, earnings bonus units and
restricted stock units Incentive share units have value if the market price of the Companys
common shares when the unit is exercised exceeds the market value when the unit
was issued. The issue price of incentive share units is the closing price of
the Companys shares on the Toronto Stock Exchange on the grant date. Up to 50
percent of the units may be exercised after one year from issuance; an
additional 25 percent may be exercised after two years; and the remaining 25
percent may be exercised after three years. Incentive share units are eligible
for exercise up to 10 years from issuance. The units may expire earlier if
employment is terminated other than by retirement, death or disability. The deferred share unit plan is made available to selected executives and
nonemployee directors. The selected executives can elect to receive all or part
of their performance bonus compensation in units and the nonemployee directors
can elect to receive all or part of their directors fees in units. The number
of units granted to executives is determined by dividing the amount of the
bonus elected to be received as deferred share units by the average of the
closing prices of the Companys shares on the Toronto Stock Exchange for the
five consecutive trading days immediately prior to the date that the bonus
would have been paid. The number of units granted to a nonemployee director is
determined at the end of each calendar quarter by dividing the amount of
directors fees for the calendar quarter that the nonemployee director elected
to receive as deferred share units by the average closing price of the
Companys shares for the five consecutive trading days immediately prior to the
last day of the calendar quarter. Additional units are granted based on the
cash dividend payable on the Companys shares divided by the average closing
price immediately prior to the payment date for that dividend and multiplying
the resulting number by the number of deferred share units held by the
recipient. Deferred share units cannot be exercised until after termination of
employment with the Company or resignation as a director and must be exercised
no later than December 31 of the year following termination or resignation. On
the exercise date, the cash value to be received for the units is determined
based on the average closing price of the Companys shares for the five
consecutive trading days immediately prior to the date of exercise. The earnings bonus unit plan is available to selected executives. Each
earnings bonus unit entitles the recipient to receive an amount equal to the
Companys cumulative net earnings per common share as announced each quarter
beginning after the grant. Payout occurs on the fifth anniversary of the grant
or when the maximum settlement value per unit is reached, if earlier. Earnings
bonus units may expire if employment is terminated other than by death or
disability. Under the restricted stock unit plan, each unit entitles the recipient to
the conditional right to receive from the Company, upon exercise, an amount
equal to the closing price of the Companys common shares on the Toronto Stock
Exchange on the exercise dates. Fifty percent of the units are exercised three
years following the grant date, and the remainder are exercised seven years
following the grant date. All units require settlement by cash payments with one exception. The
restricted stock unit plan was amended for units granted in 2003 and future
years by providing that the recipient may receive one common share of the
Company per unit or elect to receive the cash payment for the units to be
exercised on the seventh anniversary of the grant date. For deferred share units, a charge is made to expense in the year of grant
equal to the cash performance bonus payment and directors fees foregone. The
Company records expense for incentive share, deferred share and restricted
stock units based on changes in the price of common shares in the year. Expense
for earnings bonus units is recorded based on the cumulative net earnings per
outstanding common share from issue date, up to the maximum settlement value
for the units.  Incentive stock options In April 2002, incentive stock options were granted for the purchase of
the Companys common shares at an exercise price of $46.50 per share. Up to 50
percent of the options may be exercised on or after January 1, 2003, a further
25 percent may be exercised on or after January 1, 2004, and the remaining 25
percent may be exercised on or after January 1, 2005. Any unexercised options
expire after April 29, 2012. The Company did not issue incentive stock options
in 2003 and has no plans to issue incentive stock options in the future. The Company does not recognize compensation expense on the issuance of
stock options because the exercise price is equal to the market value at the
date of grant. If the fair-value-based method of accounting had been adopted,
net income and earnings per share (on both a basic and diluted basis) for 2003
would have been reduced by $5 million or $0.01 per share (2002
 $16 million or
$0.04 per share). The average fair value of each option granted during 2002 was
$12.70. The fair value was estimated at the grant date using an option-pricing
model with the following weighted average assumptions: risk-free interest rate
of 5.7 percent, expected life of five years, volatility of 25 percent and a
dividend yield of 1.9 percent. The Company has purchased shares on the market to fully offset the
dilutive effects from the exercise of stock options. The practice is expected
to continue. (Continued on following page) F-15




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##### Table of Contents



A summary of the incentive compensation is as follows: Granted in period
    
    Number
    
    
    
    
    
    Obligationsof units
    
    Expensed
    
    outstanding atNumber
    
    To number
    
    To number of
    
    outstanding at
    
    in period
    
    December 31of units
    
    of employees
    
    nonemployees
    
    December 31
    
    (millions of dollars)
    
    (millions of dollars)Incentive share units2003
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    6,889,330
    
    
    
    109
    
    
    
    2162002
    
    
    7,000
    
    
    
    3
    
    
    
    
    
    
    
    8,012,250
    
    
    
    39
    
    
    
    1422001
    
    
    2,752,700
    
    
    
    744
    
    
    
    
    
    
    
    8,823,125
    
    
    
    51
    
    
    
    129Deferred share units2003
    
    
    8,253
    
    
    
    5
    
    
    
    6
    
    
    
    43,911
    
    
    
    1
    
    
    
    32002
    
    
    7,479
    
    
    
    6
    
    
    
    7
    
    
    
    85,523
    
    
    
    
    
    
    
    42001
    
    
    15,222
    
    
    
    2
    
    
    
    5
    
    
    
    87,897
    
    
    
    1
    
    
    
    4Earnings bonus units2003
    
    
    2,221,580
    
    
    
    84
    
    
    
    
    
    
    
    3,234,250
    
    
    
    3
    
    
    
    32002
    
    
    1,036,500
    
    
    
    75
    
    
    
    
    
    
    
    2,169,040
    
    
    
    3
    
    
    
    32001
    
    
    1,132,540
    
    
    
    21
    
    
    
    
    
    
    
    1,132,540
    
    
    
    
    
    
    
    Incentive stock options2003
    
    
    
    
    
    
    
    
    
    
    
    
    
    
    3,136,150
    
    
    
    
    
    
    
    2002
    
    
    3,210,200
    
    
    
    765
    
    
    
    
    
    
    
    3,196,700
    
    
    
    
    
    
    
    Restricted stock units2003
    
    
    872,085
    
    
    
    613
    
    
    
    5
    
    
    
    1,660,555
    
    
    
    11
    
    
    
    112002
    
    
    791,890
    
    
    
    690
    
    
    
    5
    
    
    
    791,890
    
    
    
    
    
    
    
    
  9.
    
    Commitments and contingent liabilities At December 31, 2003, the Company had commitments for noncancellable
operating leases and other long-term agreements that require the
following minimum future payments: millions of dollars
    
    2004
    
    2005
    
    2006
    
    2007
    
    2008
    
    After 2008Operating leases (a)
    
    
    72
    
    
    
    59
    
    
    
    49
    
    
    
    43
    
    
    
    34
    
    
    
    114Unconditional purchase obligations (b)
    
    
    90
    
    
    
    47
    
    
    
    38
    
    
    
    38
    
    
    
    38
    
    
    
    98Firm capital commitments (c)
    
    
    176
    
    
    
    8
    
    
    
    5
    
    
    
    
    
    
    
    
    
    
    
    Other long-term agreements (d)
    
    
    260
    
    
    
    235
    
    
    
    151
    
    
    
    57
    
    
    
    57
    
    
    
    277
  (a)
    
    Total rental expense incurred for operating leases in 2003 was $124 million
(2002  $124 million; 2001  $122 million). Operating lease commitments related
to joint-venture activities are not material.  (b)
    
    Unconditional purchase obligations are those long-term commitments that are
noncancellable or cancellable only under certain conditions. These mainly
pertain to pipeline throughput agreements. Total payments under unconditional
purchase obligations were $114 million in 2003 (2002  $115 million; 2001 
$179 million).(c)
    
    Firm capital commitments related to capital projects, shown
on an undiscounted basis, totalled approximately $189 million at the end of
2003 (2002  $284 million). The largest commitments outstanding at year-end
2003 were associated with the Companys share of capital projects at Syncrude
of $56 million and offshore East Coast of $50 million.  (d)
    
    Other long-term agreements include primarily raw material supply and
transportation services agreements. Total payments under other long-term
agreements were $332 million in 2003 (2002  $288 million; 2001  $264
million). Payments under other long-term agreements related to joint-venture
activities are approximately $44 million per year.  Other commitments arising in the normal course of business for operating
and capital needs do not materially affect the Companys consolidated financial
position.The Company was contingently liable at December 31, 2003, for a maximum of
$163 million relating to guarantees for purchasing operating equipment and
other assets from its rural marketing agents upon expiry of the agency
agreement or the death or resignation of the agent. The Company expects that
the fair value of the operating equipment and other assets so purchased would
cover the maximum potential amount of future payment under the guarantees.The Company provides in its financial statements for asset retirement
obligations and other environmental liabilities (see accounting policies on
page F-6). Provision is not made with respect to those manufacturing,
distribution and marketing facilities with indeterminate useful lives for which
estimates of these future costs cannot be reasonably determined. These are
primarily currently operated sites. These costs are not expected to have a
material effect on the Companys current consolidated financial position.Various lawsuits are pending against the Company 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. F-16




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##### Table of Contents



10.
    
    Common shares  The number of authorized common shares of the Company as at December 31,
2003 was 450,000,000, unchanged from December 31, 2002 and December 31,
2001.From 1995 to 2002, the Company purchased shares under eight 12-month
normal course share purchase programs, as well as an auction tender. On
June 23, 2003, another 12-month normal course share purchase program was
implemented with an allowable purchase of 18.6 million shares (five
percent of the total at June 19, 2003), less any shares purchased by the
employee savings plan and Company pension fund. The results of these
activities are shown below. Purchased
    
    Millions ofYear
    
    shares
    
    dollars1995 to 2001
    
    
    202,365,149
    
    
    
    5,1562002
    
    
    296,052
    
    
    
    132003
    
    
    16,259,538
    
    
    
    799Cumulative purchases to date
    
    
    218,920,739
    
    
    
    5,968
  Exxon Mobil Corporations participation in the above maintained its ownership
interest in the Company at 69.6 percent.The excess of the purchase cost over the stated value of shares purchased has
been recorded as a distribution of retained earnings.The Companys common
share activity is summarized below: Thousands of
    
    At stated value,shares
    
    millions of dollarsBalance as at December 31, 2001
    
    
    379,159
    
    
    
    1,941Issued for cash under stock option plan
    
    
    
    
    
    
    Purchases
    
    
    (296
    )
    
    
    (2
    )Balance as at December 31, 2002
    
    
    378,863
    
    
    
    1,939Issued for cash under stock option plan
    
    
    49
    
    
    
    2Purchases
    
    
    (16,260
    )
    
    
    (82
    )Balance as at December 31, 2003
    
    
    362,652
    
    
    
    1,859
  The following table provides the calculation of basic and diluted earnings per share: 2003
    
    2002
    
    2001Net earnings (millions of dollars)
    
    
    1,682
    
    
    
    1,224
    
    
    
    1,255Average number of common shares outstanding, weighted monthly (thousands)
    
    
    372,011
    
    
    
    378,875
    
    
    
    393,121Plus: average number of shares issued on assumed exercise of stock options (thousands)
    
    
    143
    
    
    
    1
    
    
    
    Weighted average number of diluted common shares (thousands)
    
    
    372,154
    
    
    
    378,876
    
    
    
    393,121Earnings per share  basic (dollars)
    
    
    4.52
    
    
    
    3.23
    
    
    
    3.19Earnings per share  diluted (dollars)
    
    
    4.52
    
    
    
    3.23
    
    
    
    3.19
  11.
    
    Miscellaneous financial information  In 2003, net earnings included an after-tax gain of $9 million (2002  $2 million loss; 2001  $18 million gain) attributable to the effect of
changes in last-in, first-out (LIFO) inventories. The replacement cost of inventories was estimated to exceed their LIFO carrying values at
December 31, 2003, by $797 million (2002  $941 million). Inventories of crude oil and products at year-end consisted of the following: millions of dollars
    
    2003
    
    2002Crude oil
    
    
    161
    
    
    
    148Petroleum products
    
    
    175
    
    
    
    198Chemical products
    
    
    57
    
    
    
    70Natural gas and other
    
    
    14
    
    
    
    17Total inventories of crude oil and products
    
    
    407
    
    
    
    433
  Research and development costs in 2003 were $63 million (2002  $64
million; 2001  $71 million) before investment tax credits earned on these
expenditures of $10 million (2002  $10 million; 2001  $6 million). The net
costs are included in expenses due to the uncertainty of future benefits.Cash flow from earnings included dividends of $15 million received from equity
investments in 2003 (2002  $18 million; 2001  $10 million).Accounts
receivable included allowance for doubtful accounts of $13 million in 2003
(2002  $13 million).  12.
    
    Financing costs millions of dollars
    
    2003
    
    2002
    
    2001Debt-related interest
    
    
    38
    
    
    
    40
    
    
    
    77Other interest
    
    
    4
    
    
    
    2
    
    
    
    4Total interest expense (a)
    
    
    42
    
    
    
    42
    
    
    
    81Foreign-exchange expense (gain) on long-term debt
    
    
    (129
    )
    
    
    (10
    )
    
    
    71Total financing costs
    
    
    (87
    )
    
    
    32
    
    
    
    152
  (a)
    
    Cash interest payments in 2003 were $38 million (2002  $41 million;
2001  $99 million). The weighted-average interest rate on short-term
debt in 2003 was 3.1 percent (2002  2.4 percent). The average effective
interest rate on the Companys debt was 2.9 percent in 2003 (2002  2.1
percent). F-17




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##### Table of Contents



13.
    
    Transactions with Exxon Mobil Corporation and affiliated companies
(ExxonMobil)  Revenues and expenses of the Company also include the results of transactions
with ExxonMobil in the normal course of operations. These were conducted
on terms as favourable as they would have been with unrelated parties
and primarily consisted of the purchase and sale of crude oil, petroleum
and chemical products, as well as transportation, technical and
engineering services. Transactions with ExxonMobil also included amounts
paid and received in connection with the Companys participation in a
number of natural resources joint-venture operations in Canada. The
Company has an existing agreement with ExxonMobil Canada to share common
business and operational support services that allow the companies to
consolidate duplicate work and systems. The amounts paid or received
have been reflected in the statement of earnings as shown in the table
below. millions of dollars
    
    2003
    
    2002
    
    2001Operating revenues
    
    
    950
    
    
    
    1036
    
    
    
    664Purchases of crude oil and products
    
    
    2,464
    
    
    
    2,134
    
    
    
    1,873Operating expense
    
    
    14
    
    
    
    57
    
    
    
    47
  Accounts payable due to Exxon Mobil Corporation at December 31, 2003, with
respect to the above transactions were $167 million (2002  $146 million).  During 2003, the Company borrowed $818 million (Cdn) from Exxon Overseas
Corporation under two long-term loan agreements as described in note 3.
Interest paid on the loans in 2003 was $14 million.  14.
    
    Net payments to governments millions of dollars
    
    2003
    
    2002
    
    2001Current income tax expense (note 4)
    
    
    610
    
    
    
    718
    
    
    
    679Federal excise tax
    
    
    1,254
    
    
    
    1,231
    
    
    
    1,180Property taxes included in expenses
    
    
    80
    
    
    
    85
    
    
    
    86Payroll and other taxes included in expenses
    
    
    52
    
    
    
    51
    
    
    
    47GST/QST/HST collected (a)
    
    
    2,015
    
    
    
    1,717
    
    
    
    1,749GST/QST/HST input tax credits (a)
    
    
    (1,705
    )
    
    
    (1,368
    )
    
    
    (1,384
    )Other consumer taxes collected
    
    
    1,662
    
    
    
    1,589
    
    
    
    1,585Crown royalties
    
    
    418
    
    
    
    314
    
    
    
    460Total paid or payable to governments
    
    
    4,386
    
    
    
    4,337
    
    
    
    4,402Less investment tax credits and other receipts
    
    
    30
    
    
    
    12
    
    
    
    7Net payments to governments
    
    
    4,356
    
    
    
    4,325
    
    
    
    4,395Net payments to:Federal government
    
    
    2,061
    
    
    
    2,171
    
    
    
    2,160Provincial governments
    
    
    2,215
    
    
    
    2,069
    
    
    
    2,149Local governments
    
    
    80
    
    
    
    85
    
    
    
    86Net payments to governments
    
    
    4,356
    
    
    
    4,325
    
    
    
    4,395
  (a)
    
    The abbreviations refer to the federal goods and services tax, the Quebec
sales tax and the federal/provincial harmonized sales tax, respectively. The
HST is applicable in the provinces of Nova Scotia, New Brunswick and
Newfoundland and Labrador.  15.
    
    Reporting investments in mineral interests in oil and gas properties  Statements of Financial Accounting Standards No. 141 (FAS 141),
Business Combinations and No. 142 (FAS 142), Goodwill and Other intangible
Assets were issued by the Financial Accounting Standards Board (FASB) in
June 2001 and became effective for the Company on July 1, 2001 and January 1,
2002, respectively. Currently, the Emerging Issues Task Force (EITF) is
considering the issue of whether FAS 141 and 142 require interests held under
oil, gas and mineral leases to be separately classified as intangible assets
on the balance sheets of companies in the extractive industries. If such
interests were deemed to be intangible assets by the EITF, mineral rights to
extract oil and gas for both undeveloped and developed leaseholds would be
classified separately from oil and gas properties as intangible assets on the
Companys balance sheet. Historically, the Company has capitalized the cost
of oil and gas leasehold interests in accordance with statement of Financial
Accounting Standard No. 19 (FAS 19), Financial Accounting and Reporting by
Oil and Gas Producing Companies. Also, consistent with industry practice,
the Company has reported these assets as part of tangible oil and gas
property, plant and equipment.This interpretation of FAS 141 and 142 would only affect the
classification of oil and gas leaseholds on the Companys balance sheet and
would not affect total assets, net worth or cash flows. The Companys results
of operations would not be affected, since these leasehold costs would
continue to be amortized in accordance with FAS 19. The amount that is
subject to reclassification as of December 31, 2003 was $935 million and
$1,109 million as of December 31, 2002. F-18




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##### Table of Contents



INDEX TO EXHIBITS The following exhibits numbered in accordance with Item 601 of Regulation S-K
are filed as part of this report:  (3)
    
    (i) Restated certificate and articles of incorporation of the Company
(Incorporated herein by reference to Exhibit (3) to the Companys Quarterly
Report on Form 10-Q for the quarter ended June 30, 1998 (File No. 0-12014)).  (ii)
    
    By-laws of the Company (Incorporated herein by reference to Exhibit
(3)(ii) to the Companys Quarterly Report on Form 10-Q for the quarter ended
March 31, 2003 (File No. 0-12014)).  (4)
    
    The Companys long term debt authorized under any instrument does not
exceed 10 percent of the Companys consolidated assets. The Company agrees to
furnish to the Commission upon request a copy of any such instrument.  (10)
    
    (ii) (1) Alberta Crown Agreement, dated February 4, 1975, relating to
the participation of the Province of Alberta in Syncrude (Incorporated
herein by reference to Exhibit 13(a) of the Companys Registration
Statement on Form S-1, as filed with the Securities and Exchange Commission
on August 21, 1979 (File No. 2-65290)).  (2)
    
    Amendment to Alberta Crown Agreement, dated January 1, 1983
(Incorporated herein by reference to Exhibit (10)(ii)(2) of the Companys
Annual Report on Form 10-K for the year ended December 31, 1983 (File No.
2-9259)).(3)
    
    Syncrude Ownership and Management Agreement, dated February 4, 1975
(Incorporated herein by reference to Exhibit 13(b) of the Companys
Registration Statement on Form S-1, as filed with the Securities and
Exchange Commission on August 21, 1979 (File No. 2-65290)).(4)
    
    Letter Agreement, dated February 8, 1982, between the Government of
Canada and Esso Resources Canada Limited, amending Schedule C to the
Syncrude Ownership and Management Agreement filed as Exhibit (10)(ii)(2)
(Incorporated herein by reference to Exhibit (20) of the Companys Annual
Report on Form 10-K for the year ended December 31, 1981 (File No.
2-9259)).(5)
    
    Norman Wells Pipeline Agreement, dated January 1, 1980, relating to the
operation, tolls and financing of the pipeline system from the Norman Wells
field (Incorporated herein by reference to Exhibit 10(a)(3) of the
Companys Annual Report on Form 10-K for the year ended December 31, 1981
(File No. 2-9259)).(6)
    
    Norman Wells Pipeline Amending Agreement, dated April 1, 1982
(Incorporated herein by reference to Exhibit (10)(ii)(5) of the Companys
Annual Report on Form 10-K for the year ended December 31, 1982 (File No.
2-9259)).(7)
    
    Letter Agreement clarifying certain provisions to the Norman Wells
Pipeline Agreement, dated August 29, 1983 (Incorporated herein by reference
to Exhibit (10)(ii)(7) of the Companys Annual Report on Form 10-K for the
year ended December 31, 1983 (File No. 2-9259)).(8)
    
    Norman Wells Pipeline Amending Agreement, made as of February 1, 1985,
relating to certain amendments ordered by the National Energy Board
(Incorporated herein by reference to Exhibit (10)(ii)(8) of the Companys
Annual Report on Form 10-K for the year ended December 31, 1986 (File No.
0-12014)).(9)
    
    Norman Wells Pipeline Amending Agreement, made as of April 1, 1985,
relating to the definition of Operating Year (Incorporated herein by
reference to Exhibit (10)(ii)(9) of the Companys Annual Report on Form
10-K for the year ended December 31, 1986 (File No. 0-12014)).(10)
    
    Norman Wells Expansion Agreement, dated October 6, 1983, relating to
the prices and royalties payable for crude oil production at Norman Wells
(Incorporated herein by reference to Exhibit (10)(ii)(8) of the Companys
Annual Report on Form 10-K for the year ended December 31, 1983 (File No.
2-9259)).(11)
    
    Alberta Cold Lake Crown Agreement, dated June 25, 1984, relating to
the royalties payable and the assurances given in respect of the Cold Lake
production project (Incorporated herein by reference to Exhibit
(10)(ii)(11) of the Companys Annual Report on Form 10-K for the year ended
December 31, 1986 (File No. 0-12014)).




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##### Table of Contents



(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)).




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##### Table of Contents



(2)
    
    Incentive Share Unit Plan and Incentive Share Units granted in 2001
are incorporated herein by reference to Exhibit (10)(iii)(A)(2) of the
Companys Annual Report on Form 10-K for the year ended December 31,
2001. Units granted in 2000 are incorporated herein by reference to
Exhibit (10)(iii)(A)(2) of the Companys Annual Report on Form 10-K for
the year ended December 31, 2000 (File No. 0-12014); units granted in
1999 are incorporated herein by reference to Exhibit (10)(iii)(A)(3) of
the Companys Annual Report on Form 10-K for the year ended December 31,
1999 (File No. 0-12014); units granted in 1998 are incorporated herein
by reference to Exhibit (10)(iii)(A)(3) of the Companys Annual Report
on Form 10-K for the year ended December 31, 1998 (File No. 0-12014);
units granted in 1997 are incorporated herein by reference to Exhibit
(10)(iii)(A)(3) of the Companys Annual Report on Form 10-K for the year
ended December 31, 1997 (File No. 0-12014); units granted in 1996 are
incorporated herein by reference to Exhibit (10)(iii)(A)(3) of the
Companys Annual Report on Form 10-K for the year ended December 31,
1996 (File No. 0-12014); units granted in 1995 are incorporated herein
by reference to Exhibit (10)(iii)(A)(3) of the Companys Annual Report
on Form 10-K for the year ended December 31, 1995 (File No. 0-12014);
and units granted in 1994 are incorporated herein by reference to
Exhibit (10)(iii)(A)(3) of the Companys Annual Report on Form 10-K for
the year ended December 31, 1994 (File No. 0-12014).(3)
    
    Deferred Share Unit Plan. (Incorporated herein by reference to
Exhibit(10)(iii)(A)(5) of the Companys Annual Report on Form 10-K for
the year ended December 31, 1998 (File No. 0-12014)).(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 Units granted in 2003; Earnings Bonus Unit Plan and
units granted in 2002 are (incorporated herein by reference to Exhibit
(10)(iii)(A)(5) of the Companys Annual Report on Form 10-K for the year
ended December 31, 2002 (File No. 0-12014)) and Earnings Bonus Unit Plan
and units granted in 2001 are 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, 2000 (File No. 0-12014).(6)
    
    Incentive Stock Option Plan and Incentive Stock Options granted in
2002 (Incorporated herein by reference to Exhibit (10)(iii)(A)(6) of the
Companys Quarterly Report on Form 10-Q for the quarter ended June 30,
2002 (File No. 0-12014)).(7)
    
    Restricted Stock Unit Plan and Restricted Stock Units granted in
2002 (incorporated herein by reference to Exhibit (10)(iii)(A)(7) of the
Companys Annual Report on Form 10-K for the year ended December 31,
2002 (File No. 0-12014)).(8)
    
    Restricted Stock Unit Plan and Restricted Stock Units granted in
2003.  (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, 2003.  (23)
    
    (ii)
    
    (A)
    
    Consent of PricewaterhouseCoopers LLP.  (B)
    
    Consent of Chief Engineering Officer.  (31.1)
    
    Certification by principal executive officer of Periodic Financial
Report pursuant to Rule 13a-14(a).(31.2)
    
    Certification by principal financial
officer of Periodic Financial Report pursuant to Rule 13a-14(a).(32.1)
    
    Certification by chief executive officer of Periodic Financial Report pursuant
to Rule 13a-14(b) and 18 U.S.C. Section 1350.(32.2)
    
    Certification by chief financial officer of Periodic Financial Report
pursuant to Rule 13a-14(b) and 18 U.S.C. Section 1350.