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Shell Canada Ltd – ‘40-F’ for 12/31/02 – EX-1

On:  Monday, 3/24/03, at 5:05pm ET   ·   For:  12/31/02   ·   Accession #:  1130319-3-274   ·   File #:  0-12049

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  As Of                Filer                Filing    For·On·As Docs:Size              Issuer               Agent

 3/24/03  Shell Canada Ltd                  40-F       12/31/02    3:7.4M                                   Bowne - BCG/FA

Annual Report of a Foreign Private Issuer   —   Form 40-F
Filing Table of Contents

Document/Exhibit                   Description                      Pages   Size 

 1: 40-F        Annual Report of a Foreign Private Issuer           HTML     37K 
 2: EX-1        Underwriting Agreement                              HTML   1.62M 
 3: EX-2        Plan of Acquisition, Reorganization, Arrangement,   HTML      5K 
                          Liquidation or Succession                              

EX-1   —   Underwriting Agreement
Exhibit Table of Contents

Page (sequential) | (alphabetic) Top
11st Page   -   Filing Submission
"Table of Contents
"Corporate Structure
"Name and Incorporation
"Intercorporate Relationships
"General Development of the Business
"Five-Year History
"Narrative Description of the Business
"Oil Sands
"Oil Products
"Competitive Conditions
"Research and Development
"Environmental Protection
"Number of Employees
"Foreign Operations
"Selected Consolidated Financial Information
"Annual Information
"Foreign Generally Accepted Accounting Principles (GAAP)
"Management's Discussion and Analysis
"Market for Securities
"Directors and Officers
"Additional Information
"Schedule I
"Schedule II
"Auditors' Report
"Management's Report
"Consolidated Statement of Earnings and Retained Earnings
"Consolidated Statement of Cash Flows
"Consolidated Balance Sheet
"Supplemental Disclosure
"Supplemental Financial Data
"Quarterly Financial and Stock Trading Information
"Corporate Directory and Board of Directors
"Appendix 1
"Appendix 2

This exhibit is an HTML Document rendered as filed.  [ Alternative Formats ]

  AIF, Annual Report and Management Proxy Circular  


Corporate Structure
Name and Incorporation
Intercorporate Relationships
General Development of the Business
Five-Year History
Narrative Description of the Business
Oil Sands
Oil Products
Competitive Conditions
Research and Development
Environmental Protection
Number of Employees
Foreign Operations
Selected Consolidated Financial Information
Annual Information
Foreign Generally Accepted Accounting Principles (GAAP)
Management’s Discussion and Analysis
Market for Securities
Directors and Officers
Additional Information
Schedule I
Schedule II
Auditors’ Report
Management’s Discussion and Analysis
Supplemental Disclosure
Oil Products
Oil Sands
Supplemental Financial Data
Quarterly Financial and Stock Trading Information
Exhibit 1
Exhibit 2

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Attached to this Annual Information Form is the Annual Report to shareholders for the year ended December 31, 2002, of Shell Canada Limited (the “Annual Report”) and the Management Proxy Circular of the Corporation dated March 13, 2003 (the “Proxy Circular”).

  Unless the contents indicate otherwise, the terms “Shell”, “Shell Canada”, “Shell Canada Limited”, “Corporation” and “Company” are used interchangeably in this Annual Information Form to refer to Shell Canada Limited and its consolidated subsidiaries.
  Shell Canada Limited’s Report of the Audit Committee appears on pages 14 and 15 of the Proxy Circular. The information contained therein is specifically incorporated by reference into this Annual Information Form. Any parts of the Annual Report or Proxy Circular not specifically incorporated by reference herein do not form part of this Annual Information Form.



    Corporate Structure   1
          Name and Incorporation   1
          Intercorporate Relationships   1
    General Development of the Business   2
          Five-Year History   2
          Trends   3
    Narrative Description of the Business   4
          Resources   4
          Oil Sands   10
          Oil Products   11
          Competitive Conditions   13
          Research and Development   14
          Environmental Protection   14
          Number of Employees   15
          Foreign Operations   15
    Selected Consolidated Financial Information   16
          Annual Information   16
          Dividends   17
          Foreign Generally Accepted Accounting Principles (GAAP)   17
    Management’s Discussion and Analysis   17
    Market for Securities   17
    Directors and Officers   18
    Additional Information   19
    Schedule I   20
    Schedule II   22
    Auditors’ Report   25

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Corporate Structure Shell Pectin Logo    SHELL CANADA LIMITED


  Shell Canada Limited was incorporated under the laws of Canada in 1925 as the successor to The Shell Company of Canada, Limited, which was incorporated in 1911 and was continued under the Canada Business Corporations Act on May 1, 1978. Shell Canada Limited was amalgamated with a wholly owned subsidiary, Shell Canada Resources Limited, by Articles of Amalgamation dated January 1, 1986. Articles of Amendment effecting the conversion of the Class “B” Common Shares to Class “A” Common Shares on a four-for-one basis and deleting the Series “A” Preferred Shares were effective June 1, 1989. Articles of Amendment splitting the Class “A” Common Shares on a three-for-one basis were effective June 30, 1997. The Corporation amalgamated with a wholly owned subsidiary, 177487 Canada Ltd., effective July 1, 1998. An Amendment to the Articles of the Corporation to effect a redesignation of the Class “A” Common Shares of the Corporation to Common Shares and to delete all references to Class “B” Common Shares was approved by special resolution of the shareholders at their Annual and Special Meeting held April 26, 2000. Articles of Amendment effecting the changes were issued May 2, 2000. Effective May 18, 2000, a restated Certificate of Incorporation was issued consolidating prior amendments. The head and principal office of the Corporation is located at 400 – 4th Avenue S.W., Calgary, Alberta T2P 0J4.


  The Corporation’s principal subsidiary, Shell Canada Products Limited, which is wholly owned and was incorporated under the Canada Business Corporations Act in 1982, began carrying on business in 1986. Until December 31, 2000, it was engaged in the manufacture, distribution and marketing of refined petroleum products. Effective January 1, 2001, the business of Shell Canada Products Limited was transferred as described under “Reorganization” on page 13 of this Annual Information Form.
  The remaining operating subsidiaries, in the aggregate, represent less than 20 per cent of Shell’s total consolidated revenues or total consolidated assets.

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General Development of the Business Shell Pectin Logo    SHELL CANADA LIMITED

Shell Canada, one of the largest integrated petroleum companies in Canada, operates principally in three industry segments: Resources, Oil Products and Oil Sands. The Resources segment comprises exploration, production and marketing activities for natural gas, natural gas liquids, bitumen and sulphur. Shell Canada is a major producer of natural gas liquids, a large producer of natural gas and the largest producer of sulphur in Canada. At the end of 1999, Shell Canada sold its conventional crude oil producing interests. The Oil Products segment includes the manufacture, distribution and marketing of refined petroleum products. The Oil Sands segment has commenced the extraction of bitumen from Lease 13 in the Athabasca region of northern Alberta and will process the bitumen into a range of synthetic crude oils.


  In 2002, the Canadian accounting standard related to the treatment of unrealized foreign exchange gains and losses was changed and is now harmonized with the U.S. standard. This change results in unrealized gains and losses being reflected in income. The earnings for 1998 to 2001 have been restated to reflect this change. The restated amounts have been noted in brackets where appropriate.
  1998   Resources earnings for 1998 were $169 million compared to $264 million in 1997. The earnings declined primarily due to lower prices for crude oil and natural gas liquids as well as reduced volumes resulting from asset sales. The Oil Products business achieved record earnings of $275 million for 1998 compared with $252 million for the previous year, mainly due to increased sales volumes. Construction of the Sable project offshore Nova Scotia continued on budget and on schedule to bring natural gas to market by early 2000. Shell continued to hold a 31.3 per cent producing interest in the project. Plans for the three elements of the Athabasca Oil Sands Project (“AOSP”), namely the Muskeg River Mine on Lease 13 in the Athabasca region of Alberta, an upgrader at Shell’s Scotford site and the Corridor Pipeline, proceeded on schedule.
  1999   Resources earnings for 1999 were $500 million compared to $169 million in 1998. The $500 million included a gain of $230 million from the sale of the Plains business, a $32 million impairment provision for Peace River and a gain of $35 million for the sale of Shell’s 12 per cent equity ownership in Coral Energy L.P. Even excluding these one-time items, Resources achieved record earnings due to strong commodity prices. Oil Products earnings were $141 million in 1999, down sharply from the record $275 million of the previous year. The 1999 earnings included a $30 million gain from fees paid by the other Athabasca Oil Sands joint venture participants for access to the infrastructure value from Shell’s Scotford Refinery. The earnings decrease was due mainly to severely depressed refining margins. The margin squeeze resulted from high inventories of finished products worldwide at the beginning of 1999 combined with a steep increase in crude oil prices, which doubled over the course of the year. Shell’s Corporate income was nil ($37 million) in 1999 compared to an expense of $12 ($14) million in 1998. The 1999 results benefited from gains from a favourable tax court decision and the sale of real estate holdings. Results from 1999 also included a $24 million gain from fees paid by other joint venture participants in the AOSP for resources value

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  contributed by Shell. In December 1999, Shell Canada approved the largest investment in the Company’s history – the AOSP.
  2000   Resources earnings for 2000 were $536 million compared to $500 million in 1999. Strong commodity prices and plant reliability were the main reasons for the exceptional performance in 2000. Resources capital and exploration expenditures were $254 million in 2000 compared to $488 million in the previous year, which included $335 million for the Sable project. Oil Products earnings were a record $340 million in 2000 compared to $141 million in 1999. The increase was due mainly to the rise in wholesale prices for gasoline and diesel caused by a North American shortage of finished petroleum products. This tightness in supply persisted throughout the year and kept refining margins well above 1999 levels, allowing Oil Products to capitalize on high production and plant reliability. Oil Products return on average capital employed was 19.6 per cent compared to 8.2 per cent in 1999. Capital expenditures were $279 million, including $147 million for modifications to the Scotford Refinery, compared to $109 million in 1999. Oil Products profitability was mainly due to the earnings contributed by Manufacturing and Supply. The continuing high demand for manufactured petroleum products was one of the main reasons for this success. Construction commenced on the AOSP and progressed on schedule. Increasing domestic and international construction activity in the oil and gas industry resulted in upward cost pressure on the project. A detailed review of the downstream components of the project indicated the potential for a cost increase in the range of 10 per cent over the original total downstream estimate. The principal reasons for this increase were rising labour and bulk material costs as well as more definitive engineering.
  2001   Shell Canada announced record earnings of $1,010 million or $3.67 per Common Share compared with earnings of $858 ($863) million or $3.04 ($3.06) per share in 2000. The Company achieved a return on average capital employed of 21.5 per cent compared with 20.3 (20.4) per cent in 2000. Resources earnings for 2001 were $600 million compared with $536 million in 2000. The 2001 total included a one-time benefit of $25 million from the impact of a lower provincial tax rate on the Company’s future tax liability and a $14 million gain from the sale of a pipeline asset. Strong commodity prices, plant reliability and higher Sable production levels were the main reasons for Resources outstanding performance in 2001. Oil Products outperformed all its major competitors in 2001 with earnings of $401 million compared to $340 million in 2000. High refining margins combined with a continued focus on business basics and operational excellence contributed to record results for the second consecutive year. Throughout the first six months of the year, manufacturing margins remained high as strong demand for gasoline and diesel fuels in North America depleted inventory levels. In the second half of the year, manufacturing margins decreased as a weakening economy reduced demand. Oil Products capitalized on favourable conditions by controlling costs and improving reliability. Construction of the AOSP joint venture made good progress in 2001, despite significant increases in cost estimates. These increases were associated mainly with labour availability and productivity, but also reflected greater than expected design complexity. The detailed engineering at the Muskeg River Mine and the Scotford Upgrader was essentially finished. Construction was 70 per cent complete at the mine and 50 per cent at the upgrader, with the start up targeted for late 2002.
  2002   For highlights of 2002, reference is made to the business sections in the Management’s Discussion and Analysis section of the Annual Report found on pages nine to 44.


  2003   For a discussion of changes in the Company’s business that are expected to occur in 2003, reference is made to the business sections in the Management’s Discussion and Analysis section of the Annual Report on pages nine to 44.

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Narrative Description of the Business Shell Pectin Logo    SHELL CANADA LIMITED


  Shell Canada has been engaged in the exploration for and production of crude oil and natural gas in Canada since 1939. From 1976 to 1985, Shell Canada’s exploration and production operations were managed and operated through a wholly owned subsidiary of the Corporation, Shell Canada Resources Limited (“Shell Resources”). Shell Canada Limited was amalgamated with Shell Resources on January 1, 1986, and the Resources business of Shell Canada became part of the operations of Shell Canada Limited. In 1999, Shell Canada sold its conventional crude oil producing interests.
  Additional information related to Resources may be found on pages 10 to 17 of the Annual Report.

Principal Products

  In 2002, Shell Canada was a major producer of natural gas, natural gas liquids, bitumen and sulphur in Canada.

Principal Markets and Methods of Distribution

  Natural Gas   Before 1997, Shell maintained a diverse portfolio of fixed and floating price contracts indexed to markets throughout North America. Since 1997, Shell has been selling its Western Canada natural gas production to Coral Energy Canada Inc., a Shell Group company which operates as part of the Shell Trading network, at Alberta market-based prices (AECO reference price).
  The Sable Offshore Energy Project (“SOEP”) started up late in December 1999. It is owned jointly by Shell, ExxonMobil Canada Properties, Imperial Oil Resources, Emera Offshore Incorporated and Mosbacher Operating Ltd. Shell sells its share of natural gas production from SOEP to markets in Atlantic Canada and the northeastern United States. In late 2002, Shell and the other joint venture participants were negotiating the sale of an 8.4 per cent interest in the SOEP infrastructure downstream of the offshore Thebaud platform. This interest was acquired in 2001 through exercising a right of first refusal.
  The following table sets out the SOEP assets by ownership:
Upstream Assets (Significant discovery licences and platforms) (%)

Shell Canada
Emera Offshore



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Downstream Assets Ownership
(Offshore gathering line, gas plants, onshore liquids pipeline, fractionation plant) (%)

Shell Canada


  Natural Gas Liquids   Shell Canada is a major producer and marketer of natural gas liquids (ethane, propane, butane and condensate) in Canada. Ethane is used primarily as a petrochemical feedstock and is moved by pipelines to markets in Alberta. The major markets for propane are for use in transportation, space heating, petrochemical and agricultural sectors. Butane is used primarily as a direct gasoline additive and in the manufacturing of oxygenated gasoline additives. Condensate is used mainly as a diluent for heavy crude oil and as a refinery feedstock. Shell has invested in infrastructure near major market centres in Edmonton, Alberta; Sarnia, Ontario; and Point Tupper, Nova Scotia; for the processing, storage and delivery of natural gas liquids to meet customer requirements. This infrastructure includes shared ownership in: facilities located in Fort Saskatchewan, Alberta, for the fractionation and storage of ethane/ propane/ butane mixes; storage facilities in Superior, Wisconsin, connected to the Enbridge Pipelines Inc. system; and storage and fractionation facilities in Sarnia, Ontario and Point Tupper, Nova Scotia. SOEP condensate production is shipped by marine tanker to the marketplace.
  Natural gas liquids production from these facilities is sold to Canadian markets and exported to the United States.
  Bitumen    Shell Canada sells its bitumen production to both Canadian and U.S. markets. Production is shipped through a number of pipelines from Shell’s producing locations to the receiving markets.
  Sulphur    Shell is the world’s largest sulphur producer with about 47 per cent of Canadian sulphur sales and over 19 per cent of world traded sulphur. In 2002, Shell continued to market sulphur within Canada and to export markets. Market growth in China offset significantly reduced volumes being shipped to the United States. Most of Shell’s sulphur customers are in the fertilizer industry. Sulphur is shipped by rail to the United States primarily in liquid form and, for markets outside North America, it is moved in solid form by rail to Vancouver, British Columbia, for shipping overseas.

Revenues by Product

  Reference is made to the “Segmented Information” note to the Consolidated Financial Statements on page 52 of the Annual Report.
  The following tables set out the percentage of revenue by customer:
Natural Gas (%) 2002 2001

Sales to third parties
    18       16  
Sales to investees
Sales to controlling shareholders
    82       84  

Total natural gas sales
    100       100  


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Natural Gas Liquids (%) 2002 2001

Sales to third parties
    97       100  
Sales to investees
Sales to controlling shareholders

Total natural gas liquids sales
    100       100  

Source and Availability of Raw Materials

  The source and availability of hydrocarbon reserves depends upon the success of Shell’s exploration and development programs. Shell’s development programs are focused in three areas: the existing deep foothills gas fields in Western Canada, the Peace River bitumen deposit, and the gas fields near Sable Island, offshore Nova Scotia. Shell’s exploration program is focused on exploring for new reserves in the Western Canada Sedimentary Basin, offshore Nova Scotia and in the Mackenzie Delta.


  Historically, natural gas sales prices have been higher in the first and fourth quarters of the year as a result of increased heating demand during the winter months. This seasonal effect, coupled with lower inventories of gas in storage at year end, resulted in strong prices moving into 2003.

Drilling Activity

  Reference is made to the “Exploration and Development Wells Drilled” table on page 67 of the Annual Report.

Location of Production

  Shell Canada operates and has substantial interests in natural gas plants in Western Canada and Nova Scotia, which process approximately 77 per cent of its current sales volumes. The remaining sales volumes are processed in other natural gas processing plants in Western Canada, in which Shell Canada has varying interests or to which it has access under long-term processing agreements. The following table sets out the capacity and utilization of Shell Canada’s major plants:

            Gas Plants


Current Utilization
Shell Canada’s Sales Gas of Current
Interest Capacity 1 Capacity 2
(%) (millions of cubic feet per day) (%)

    100       165       53  

Jumping Pound
    100       151       75  

Burnt Timber
    82       95       97  

    72       127       96  

Wildcat Hills (outside operated)
    34       106       91  

Goldboro (outside operated)
    34       565       89  

  1  Based on inlet gas composition, the current volume of sales gas that can be processed with all equipment running and feed gas optimized based on product prices.
  2  Based on average daily sales relative to current capacity.

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  Shell also has interests in three natural gas liquids fractionation and storage facilities operated by Dow Chemical Canada Inc. (“Dow”), BP Canada Energy Inc. and Sable Offshore Energy Inc. (“SOEI”). These facilities add value to Shell’s natural gas liquids production and are located near major marketing centres.

            NGL Fractionation/Storage


Shell Canada’s Shell Share Shell Share
Interest Capacity Utilization 1
(%) (thousands of barrels per day) (%)

Fort Saskatchewan, Alberta (Dow)

    44       31       75  

    42       13       77  

Sarnia, Ontario (BP Canada)

    13       15       100  

Point Tupper, Nova Scotia (SOEI)

    34       10       71  

  1  Based on average daily throughput relative to available capacity.

  The significant fields in which Shell owns varying interests are:
Natural Gas, Natural Gas Liquids and Sulphur Production Bitumen Production


Burnt Timber
  Caroline      Peace River

  Jumping Pound    

  Moose/ Whiskey    

Panther River

Wildcat Hills

Nova Scotia

North Triumph


  A large quantity of the natural gas production comes from fields with natural gas containing significant amounts of liquids and hydrogen sulphide. Production from these fields requires complex treatment, which yields substantial volumes of natural gas liquids and sulphur, as well as marketable natural gas.

Location of Wells

  Reference is made to the “Productive Wells” table on page 67 of the Annual Report.

Interest in Material Properties

  Reference is made to the “Landholdings” table on page 71 of the Annual Report.

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Reserve Estimates

  Reference is made to the “Reserves” section on pages 68 and 69 of the Annual Report and to Schedule I on page 20 of this Annual Information Form.

Source of Reserve Estimates

  Reserve estimates are prepared by the Corporation.

Reconciliation of Reserves

  Reference is made to the “Reserves” section on pages 68 and 69 of the Annual Report.




2002 2001
Q1 Q2 Q3 Q4 Year Q1 Q2 Q3 Q4 Year

Natural gas (thousands of cubic feet/day)
    629 000       597 000       615 000       595 000       610 000       619 000       582 000       618 000       634 000       614 000  

Ethane, propane and butane (barrels/day)
    29 600       25 900       27 700       28 100       27 900       30 400       26 300       29 200       29 200       28 800  

Condensate (barrels/day)
    21 800       18 600       19 300       19 100       19 700       23 500       19 900       23 300       22 700       22 300  

Bitumen (barrels/day)
    8 200       8 700       6 400       12 200       8 900       3 000       2 200       5 200       7 700       4 500  

  Gross production includes all production attributable to Shell’s interest before deduction of royalties.


            Natural Gas ($/mcf)


2002 2001
Q1 Q2 Q3 Q4 Year Q1 Q2 Q3 Q4 Year

Average plant gate price     3.27       4.26       3.38       5.18       4.01       9.58       6.36       3.96       3.31       5.75  
Royalties     0.55       0.78       0.55       0.94       0.70       1.97       1.23       0.70       0.61       1.12  
Operating expenses                                                                                
Plant and field
    0.54       0.86       0.67       0.76       0.71       0.57       0.62       0.62       0.55       0.59  
Head office
    0.15       0.15       0.14       0.20       0.16       0.11       0.19       0.12       0.12       0.13  
    0.08       0.10       0.07       0.09       0.08       0.03       0.07       0.07       0.19       0.09  

Total operating expenses     0.77       1.11       0.88       1.05       0.95       0.71       0.88       0.81       0.86       0.81  

Netback     1.95       2.37       1.95       3.19       2.36       6.90       4.25       2.44       1.84       3.82  


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Ethane, Propane and Butane ($/bbl)


2002 2001
Q1 Q2 Q3 Q4 Year Q1 Q2 Q3 Q4 Year

Average plant gate price     15.63       19.12       18.23       24.96       19.53       35.76       26.21       17.80       15.96       24.22  
Royalties     1.96       2.76       2.43       3.74       2.71       8.80       3.48       4.08       2.50       4.76  
Operating expenses                                                                                
Plant and field
    3.30       5.21       4.00       4.53       4.24       3.46       3.66       3.75       3.31       3.54  
Head office
    0.87       0.90       0.84       1.20       0.95       0.65       1.17       0.71       0.73       0.81  
    0.45       0.58       0.43       0.55       0.50       0.16       0.43       0.43       1.11       0.54  

Total operating expenses     4.62       6.69       5.27       6.28       5.69       4.27       5.26       4.89       5.15       4.89  

Netback     9.05       9.67       10.53       14.94       11.13       22.69       17.47       8.83       8.31       14.57  

Condensate ($/bbl)


2002 2001
Q1 Q2 Q3 Q4 Year Q1 Q2 Q3 Q4 Year

Average plant gate price
    30.60       38.73       41.12       41.14       37.72       42.46       42.22       39.26       29.43       38.23  
    5.13       7.38       7.15       8.86       7.07       11.22       8.65       8.51       5.70       8.54  
Operating expenses
Plant and field
    3.30       5.21       4.00       4.53       4.24       3.46       3.66       3.75       3.31       3.54  
Head office
    0.87       0.90       0.84       1.20       0.95       0.65       1.17       0.71       0.73       0.81  
    0.45       0.58       0.43       0.55       0.50       0.16       0.43       0.43       1.11       0.54  

Total operating expenses
    4.62       6.69       5.27       6.28       5.69       4.27       5.26       4.89       5.15       4.89  

    20.85       24.66       28.70       26.00       24.96       26.97       28.31       25.86       18.58       24.80  

            COSTS INCURRED

            ($ millions)


2002 2001
Q1 Q2 Q3 Q4 Year Q1 Q2 Q3 Q4 Year

Property acquisition
    3       4       2             9             1       16             17  
Exploration costs
    67       36       17       1       121       26       20       17       46       109  
Developmental costs
    52       53       67       87       259       49       50       85       56       240  

Total costs incurred
    122       93       86       88       389       75       71       118       102       366  

Future Commitments

            Sales Commitments


(in millions) Sales Price per boe* (in millions of boe) Term

$ 438     $ 17.76       24.65       1-8  years  

             * barrel of oil equivalent.

  The sales commitments include long-term gas contracts from SOEP production as well as bitumen/ asphalt sales.

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Exploration and Development

  Expenditures on exploration and development appear in Schedule I on page 20 of this Annual Information Form.
  Additional information related to exploration and development activities may be found on pages 12 and 17 of the Annual Report.


  In 2002, construction was completed on the Athabasca Oil Sands Project (AOSP). The AOSP started up in December 2002 with its first production and sale of bitumen. Under a joint venture agreement, Shell Canada has a 60 per cent interest in the project while Chevron Canada Limited and Western Oil Sands L.P. each hold 20 per cent.
  The Athabasca Oil Sands Project joint venture includes the following:
  The Muskeg River Mine, on Lease 13, is located 75 kilometres north of Fort McMurray, Alberta. The Muskeg River Mine uses trucks and shovels to excavate the oil sands, as well as advanced extraction technologies to separate the bitumen from the sands. Bitumen production started in late 2002. It is expected to reach its full production rate of 155,000 barrels per day in 2003. Albian Sands Energy Inc. operates the mine and extraction plant.
  The Scotford Upgrader is adjacent to Shell’s existing Scotford Refinery north of Fort Saskatchewan, Alberta. The Scotford Upgrader uses hydrogen-addition technology to process the bitumen from the Muskeg River Mine into a range of premium, synthetic crude oils. These crude oils will be used to produce high quality fuels to help meet the transportation needs of Canadians. Production of synthetic crude will begin in early 2003. Shell Canada operates the upgrader.
  Shell Canada’s estimate of its share of the mine and upgrader has been revised to $3.4 billion, up from the original estimate of $2.3 billion. The cost estimate for the Scotford modifications has risen to $500 million from the original $400 million.
  Shell Canada’s share of capital expenditures for the full year 2002 was $1,646 million, including $186 million for Scotford Refinery modifications.
  Shell expects to invest about $55 million in Oil Sands for 2003, which mainly relates to completion of the infrastructure.
  Additional information related to Oil Sands may be found on pages 18 to 25 of the Annual Report.

Interest in Material Properties

  Reference is made to the “Landholdings” table on page 71 of the Annual Report.

Reserve Estimates

  Reference is made to the “Reserves” section on page 70 of the Annual Report and to Schedule I on page 20 of this Annual Information Form.

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Source of Reserve Estimates

  Reserve estimates are prepared by the Corporation.

Reconciliation of Reserves

  Reference is made to the “Reserves” section on page 70 of the Annual Report.

Future Commitments

            Transportation Commitments


(in millions) Price per Barrel (in millions of barrels) Term

$ 1,273     $ 0.90       1,414       25  years  

  The Corridor Pipeline carries diluted bitumen from the mine to the upgrader.


  Shell Canada’s oil refining, supply, transportation and marketing businesses were managed and operated in 2002 through Shell Canada Products, a partnership wholly owned indirectly by the Corporation. Shell manufactures and markets a full range of petroleum products, including automotive gasolines, diesel fuels, aviation fuels, heating oils, lubricating oils and greases, heavy fuel oils, solvents and asphalts. In addition to these products, many Shell Canada service stations provide a variety of other services including a Select Convenience Store.
  Oil Products also markets fluid management services to plants in the automotive component manufacturing sector. The program is designed to reduce operating costs and improve process productivity in the customer plant operations. In 2002, the Company expanded its range of services to include maintenance planning as well as initiating sales penetration into other industrial sectors.
  Additional information related to Oil Products may be found on pages 26 to 33 of the Annual Report.

Methods of Distribution

  Shell Canada uses various modes of transportation, including marine, pipeline, rail and truck, to transport crude oil and refined products. Shell arranges marine transportation, principally by charter, to transport petroleum products in the Great Lakes, the Gulf of St. Lawrence, the Arctic and the West Coast. Shell has minority ownership interests in various crude oil and refined product pipelines. Shell Canada’s transportation system for refined products also includes railway tank cars, most of which are leased, and contracted delivery services.

Principal Markets

  Refined petroleum products, as well as specialty items for the automotive, commercial, farm and home markets, are marketed nationally, principally under Shell trademarks. Shell Canada is also a major supplier of aviation fuels and lubricants to international and domestic airlines, and of marine fuels and lubricants to ships in Canadian ports. The Shell Pecten trademark, which is owned in Canada by the Corporation, and

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  related trademarks and brand names constitute a cornerstone of the Oil Products business. Shell’s retail market share for large urban markets in Canada was slightly below 18 per cent (2001 – 19 per cent).
  The total number of Shell-branded retail sites at year-end was 1,705 (2001 – 1,757) comprising three salary-operated sites, 682 commission-operated sites, 144 sites run by lessees and 876 dealer-owned and -operated locations. The private-brand network consists of 133 service stations (2001 – 178).
  The integration and rationalization of the wholly owned private-brand network into Shell’s operations commenced in 1997 and continues as planned.

Revenues by Product

  Reference is made to the “Segmented Information” note to the Consolidated Financial Statements on page 53 of the Annual Report.
  The following tables set out the percentage of revenue by customer:
Gasoline (%) 2002 2001

Sales to third parties
    100       100  
Sales to investees
Sales to controlling shareholders

Total gasoline sales
    100       100  

Middle Distillates (%) 2002 2001

Sales to third parties
    100       100  
Sales to investees
Sales to controlling shareholders

Total middle distillates sales
    100       100  

Source and Availability of Raw Materials

  In 2002, 53 per cent (2001 – 55 per cent) of Shell Canada’s crude oil requirements were supplied from domestic industry production under a variety of purchase and sale arrangements. Less than one per cent (2001 – one per cent) of this supply came from Shell Canada’s own production. The remaining 47 per cent (2001 – 45 per cent) was imported.


  There are no significant seasonal fluctuations in the overall Oil Products business over the year and there are no multi-year cycles.


  Shell’s three operating refineries located at Sarnia, Ontario; Montreal, Quebec; and Fort Saskatchewan, Alberta, achieved average utilization rates of 87 per cent in 2002 (2001 – 92 per cent). This reduction in average utilization in 2002 was mainly due to maintenance turnarounds. A consistent focus on safe and reliable refinery operations, together with the ability of the sales and trading groups to balance domestic market requirements with export opportunities, has enabled Shell to operate these facilities at efficient utilization rates.

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  Shell Canada’s refineries continue to account for approximately 16 per cent (2001 – 16 per cent) of Canada’s operating refinery capacity in 2002. The location and rated capacity of each of Shell’s refineries at December 31, 2002 are shown below.

Daily Rated Capacity 1
Refinery (cubic metres)

Montreal East (Quebec)
    20 700  

Sarnia (Ontario)
    11 400  

Scotford (Alberta)
    15 500  

    47 600  

  1  Rated capacity is based on definite specifications as to types of crude oil, the products to be obtained and the refinery processes, taking into consideration an estimated allowance for normal annual maintenance shutdowns. Accordingly, capacity under actual operating conditions may be higher or lower than rated capacity.

  In 2002, Shell’s automated lubricant blending plant in Brockville, Ontario, produced 136 million litres. This represents an increase of five per cent over 2001 volumes. The Calgary grease manufacturing facility produced three million kilograms of soap-based and microgel-based greases in 2002, a comparable quantity to 2001.


  Effective January 1, 2001, the business of Shell Canada Products Limited was transferred to Shell Canada Products, a partnership now governed by the laws of Alberta, of which Shell Canada Products Limited owns 99.99 per cent of the units and of which Shell Canada Products Limited is the managing partner. The balance of the units of the partnership are held by a subsidiary of the Corporation.


  The oil and gas industry in Canada operates under federal, provincial and municipal legislation and regulations governing land tenure, royalties, production rates, environmental protection, exports, income and other matters.
  The Canadian petroleum industry is highly competitive in all its aspects, including the exploration for and development of new sources of supply; the acquisition of oil and gas interests; the construction and operation of crude oil, natural gas and refined products pipelines; and the refining, distributing and marketing of petroleum products.
  In Resources, acquisitions of exploration rights on Crown-owned lands in Canada are subject to an open bidding process. Company-held exploration seismic and drilling data are generally considered trade secrets. Prices of all products are set by market conditions and are subject to international competition.
  In Oil Sands, the Company has extensive leaseholdings adjacent to the initial Muskeg River Mine development. The other joint venturers in the initial Muskeg River Mine development have the option to participate in future development involving Shell’s other oil sands leases.
  The Investment Canada Act requires Shell Canada, a statutory non-Canadian and World Trade Organization (WTO) investor, to notify Investment Canada of all investments resulting in acquisition of control of an existing Canadian business, or the establishment of a new Canadian business where the

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  transaction is not a reviewable transaction. Any direct investment in excess of $218 million in 2002 is reviewable, and an indirect acquisition is reviewable if the value of the assets of the business located in Canada amounts to more than 50 per cent of the asset value of the transaction. Additional thresholds apply for the acquisition or establishment of particular types of Canadian businesses.
  The industry-wide buildup of retail outlets in previous decades has not yet been fully rationalized by members of the industry. As a result, there continues to be an excessive number of outlets. Market conditions and site economics suggest continued asset rationalization programs by companies, to improve operating efficiencies within the networks.


  Research and development expense was $6 million in 2002 (2001 – $5 million).


  Shell Canada has a systematic approach to health, safety and environmental (HSE) management designed to ensure compliance with the law and to achieve continuous performance improvement. The HSE management system provides for full identification and control of all risks to the business that arise from the company’s operations and/or from the areas in which it operates. All major operating facilities are registered to the international environmental management standard, ISO 14001. This includes four gas complexes (Burnt Timber, Caroline, Jumping Pound, Waterton), the in situ heavy oil facility at Peace River, three refineries (Montreal East, Sarnia and Scotford), two lubricants plants (Brockville and Calgary) and well construction and geophysical operations. Additionally, the Corporate and Resources business units have ISO 14001 registered HSE management systems.
  Environmental protection expenditures are outlined in the following table:
Environmental Expenditures ($ millions) 2002 2001

Operating costs
    61       58  
Capital costs
    137       66  
Restoration and reclamation
    49       49  

    247       173  

  Operating costs.   These include: waste disposal; environmental operating costs (such as cost of energy and chemicals for environmental systems); maintenance (of plant systems to ensure continued environmentally sound performance); studies to determine environmental impact; monitoring and reporting requirements; salaries; environmental association fees; hearings; and legal costs and fines. In May 2002, an application and Environmental Impact Assessment (EIA) costing $1.8 million was submitted for the Jackpine Mine-Phase 1 project. Increased turnaround costs were incurred in Products in 2002.
  Capital costs.    These include costs of new equipment and associated construction costs for waste management, pollution prevention and control of air emissions and water discharges. The environmental capital expenditures were down at all gas plant complexes compared with 2001. Expenditure at Peace River Complex increased to $1 million from $0.3 million in 2001 as production increased to meet its objective of 12 thousand barrels per day.

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  Shell Canada’s $150 million gasoline desulphurization projects at the Sarnia and Montreal refineries successfully started up in 2002 ahead of schedule and on budget. This will enable the Company to produce 30 parts per million sulphur content gasoline at the two refineries well ahead of the January 1, 2005 legislated deadline. Shell Canada’s Scotford Refinery already produces gasoline that meets these requirements.
  Restoration and reclamation.    This includes the costs of spill cleanup, decommissioning and restoration (DAR) and the protection or restoration of wildlife and habitat. DAR expenditure in Resources increased to $8.2 million in 2002 from $6.5 million in 2001. Restoration costs at Waterton to rectify problems created by a severe spring flood and snowfall cost $2.1 million. A reduced spill incidence led to a reduction in spill clean up costs from $0.5 million in 2001 to $0.3 million in 2002.


  The number of employees at the end of 2002 was 3,825 compared to 3,674 at the end of 2001. The number of employees in each business unit is as follows:


Number of Employees
Business Unit At December 31, 2002 At December 31, 2001

    834       817  
Oil Products
    1,968       2,019  
Oil Sands
    425       275  
    598       563  

    3,825       3,674  


  None of the Corporation’s segments depends upon foreign operations.

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Selected Consolidated Financial Information Shell Pectin Logo    SHELL CANADA LIMITED


Total Revenue

  Reference is made to the “Consolidated Statement of Earnings and Retained Earnings” table, “Revenues” section on page 47 of the Annual Report.

Earnings in Total and on a Per-Equity-Share and Diluted-Equity-Share Basis

  Reference is made to the “Consolidated Statement of Earnings and Retained Earnings” table on page 47 and the “Data Per Common Share” table on page 72 of the Annual Report.

Total Assets

  Reference is made to the “Consolidated Balance Sheet” table on page 49 of the Annual Report.

Long-Term Financial Liabilities

  Reference is made to the “Consolidated Balance Sheet” table on page 49 of the Annual Report.

Cash Dividends Declared per Share

  Reference is made to the “Data Per Common Share” table on page 72 of the Annual Report.

Factors Affecting Comparability

  1998   Earnings include the sale of northeastern British Columbia properties for $18 million and the sale of Midale for $23 million. A $60 million portion from the 1997 tax settlement was recognized in 1998. A gain of $32 million from the sale of Shell Centre, the Corporation’s head office in Calgary, Alberta, in June was also included in the 1998 results.
  1999   The Plains business was sold for a gain of $230 million and earnings were reduced by $32 million related to an impairment provision in Peace River. A $54 million gain from fees paid by the other Athabasca Oil Sands joint venturers was recognized. Also, an after-tax gain of $35 million for the sale of Shell’s equity ownership in Coral Energy L.P. was recognized.
  2000   Effective January 1, 2000, the Company adopted the new Canadian accounting standard for Income Taxes. The Corporation adopted this standard retroactively without restating financial statements for prior periods. The effect of this new recommendation on the balance sheet was to decrease the future income tax liability and increase retained earnings by $61 million. The effect on net income for the period ended December 31, 2000, was not material.
  2001   Earnings in the year included a one-time benefit resulting from the Alberta and Ontario governments reducing their corporate income tax rates. The future income tax expense for the Resources and Oil Products segments decreased by $25 million and $8 million respectively. In June, the sale of the Cochin Pipeline

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  resulted in a $14 million gain. Hedging activities related to natural gas production reduced earnings for the year by approximately $10 million.
  2002   Earnings in the year included the $41 million after-tax write off of the exploration section of Shell’s wholly owned Onondaga natural gas well offshore Nova Scotia. Oil Products earnings included the impact of extensive shutdowns at each of its three refineries in the second quarter. Although these shutdowns were planned, they significantly reduced plant availability, increased operating costs and lowered yields, which reduced earnings by an estimated $20 million. Earnings in the year also included a one-time benefit resulting from reductions in corporate income tax rates. The future income tax expense for the Resources and Oil Products segments decreased by $12 million and $5 million respectively. Earnings in 2002 also included $20 million of after tax interest income related to prior period income tax settlements.

Eight-Quarters Information

  Reference is made to the “Quarterly Financial and Stock Trading Information” table on page 73 of the Annual Report.


  Dividends are declared at the discretion of the Board of Directors of the Corporation. Prior to 1996, semi-annual dividends had been declared. In January 1996, the Board of Directors approved the quarterly payment of dividends. In 2002, dividends of 20 cents per share were paid on March 15, June 14, September 16 and December 16.


Supplemental Information

  Supplemental reporting information, in accordance with Statement No. 69 of the United States Financial Accounting Standards Board, appears in Schedule I, which is attached hereto and forms part of this Annual Information Form.

United States Generally Accepted Accounting Principles

  The significant differences between Canadian and U.S. Generally Accepted Accounting Principles are identified in Schedule II, on page 22 of this Annual Information Form.

Management’s Discussion and Analysis

  Reference is made to pages nine to 44 of the Annual Report.

Market for Securities

  Reference is made to “Investor Information” on page 77 of the Annual Report.

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Directors and Officers Shell Pectin Logo    SHELL CANADA LIMITED

  Reference is made to the “Corporate Directory and Board of Directors” table on page 74 of the Annual Report, the “Statement of Corporate Governance Practices” on pages 75 and 76 of the Annual Report, and the “Information Concerning Nominees for Election to the Board of Directors” on pages three and four of the Proxy Circular.
  The following are officers of the Corporation as at December 31, 2002:

Principal Occupation
Name and Municipality if Different from Office Held
of Residence Office within Preceding Five Years

Timothy W. Faithfull
Calgary, Alberta
  President and
Chief Executive Officer

H. Ian Kilgour
Calgary, Alberta
  Senior Vice President, Resources    

Steinar Støtvig
Calgary, Alberta
  Vice President and
Chief Financial Officer

R. Terry Blaney
Calgary, Alberta
  Vice President, Marketing    

Harold W. Lemieux
Calgary, Alberta
  Vice President, General Counsel and Secretary  

Neil J. Camarta
Calgary, Alberta
  Senior Vice President, Oil Sands  

Graham Bojé
Calgary, Alberta
  Vice President, Manufacturing  

Gary N. Stewart
Calgary, Alberta

Matthew B. Haney
Calgary, Alberta

Susan S. Boughs
Toronto, Ontario
  Assistant Secretary   Associate General Counsel Eastern Canada

Jane M. Coull
Calgary, Alberta
  Assistant Secretary   Senior Solicitor
Shell Canada Limited

John Courtright
Calgary, Alberta
  Assistant Secretary   Associate General Counsel
Oil Sands
Shell Canada Limited

Linda M. Howey
Calgary, Alberta
  Assistant Secretary   Senior Counsel, Products
Shell Canada Limited

  All of the foregoing officers of the Corporation have, for the past five years, been actively engaged in executive or employee capacities with the Corporation or its affiliates.

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  Steinar Støtvig and Timothy Faithfull will be retiring at the end of March and July of 2003, respectively, and will be succeeded by Catherine Williams as Chief Financial Officer and by Linda Cook as President and Chief Executive Officer.
  The percentage of Common Shares of the Corporation owned beneficially, directly or indirectly, or over which control or direction is exercised by the directors and senior officers as a group, is less than one per cent.
  The Corporation has three committees of the Board. Reference is made to pages 75 and 76 of the Annual Report for discussion of the three Board committees and their membership.
  Reference is made to “Certain Transactions” on page five of the Proxy Circular and Appendix 2 of the Proxy Circular for identification of other entities that transact business with the Corporation of which a director of the Corporation also serves as a director or officer.

Additional Information


  Copies of the following documents are available upon request from the Corporation’s Secretary: the Corporation’s Annual Information Form for 2002, together with the documents incorporated by reference therein; the Corporation’s Proxy Circular for its most recent Annual Meeting of shareholders; the Corporation’s Annual Report containing comparative financial statements for 2002, together with the Auditors’ Report thereon; and the Management’s Discussion and Analysis and interim financial statements subsequent to December 31, 2002.
  When securities of the Corporation are in the course of a distribution pursuant to a short form prospectus, or a preliminary short form prospectus, copies of the foregoing documents and any other documents that are incorporated by reference into the preliminary short form prospectus or short form prospectus may also be obtained from the Corporation’s Secretary upon request.
  Additional information, including directors’ and officers’ remuneration and indebtedness, principal holders of the Corporation’s securities, options to purchase securities and interests of insiders in material transactions, where applicable, is contained in the Corporation’s Proxy Circular for its April 24, 2003 Annual Meeting of shareholders. Additional financial information is provided in the Corporation’s comparative financial statements for its most recently completed financial year.

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Schedule I Shell Pectin Logo    SHELL CANADA LIMITED


  The following supplemental oil and gas disclosure has been prepared in accordance with the provisions of the U.S. Financial Accounting Standards Board’s Statement No. 69, Disclosures about Oil and Gas Producing Activities, and is unaudited. The U.S. Securities and Exchange Commission has adopted this standard as a comprehensive set of disclosure requirements for conventional oil and gas producing activities. The format of this disclosure strictly adheres to the requirements outlined in paragraphs 10 to 34 of Statement No. 69.
At December 31 ($ millions) 2002 2001 2000

Capitalized Costs
Unproved oil and gas reserves
    168       174       167  
Proved oil and gas reserves
    4 224       3 967       3 743  

      4 392       4 141       3 910  
Accumulated depreciation, depletion and amortization
    2 219       2 009       1 863  

Net capitalized costs
    2 173       2 132       2 047  

Year ended December 31 ($ millions)

Costs Incurred
Property acquisition
    9       17       12  
Exploration costs
    121       109       62  
Development costs
    259       240       180  

Total costs incurred
    389       366       254  

Year ended December 31 ($ millions)

Results of Operations from Producing Activities
    1 479       1 838       1 786  
Operating expenses
    536       623       613  
Exploration expenses
    123       81       41  
Depreciation, depletion, amortization and retirements
    224       212       189  
Income tax
    218       361       407  

Results of operations from producing activities
    378       561       536  

20        SCHEDULE I

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Standardized Measure of Discounted Future Net Cash Flows

  The following future net revenue information, in management’s view, does not purport to represent an accurate estimate of the value of the Corporation’s oil and gas operations. The information should be interpreted with considerable caution since actual future cash flows will differ from future net cash flows presented in that:

  (a) future cash flows will be derived not only from proved reserves but also from probable and potential reserves that ultimately become proved;
  (b) future-year rather than current-year costs and prices will apply;
  (c) economic, regulatory and operating conditions will change; and
  (d) this computation excludes cash flows from mineable bitumen activities.

  This computation includes gross revenues from sulphur of $210 million (2001 – $138 million; 2000 – $232 million). Costs with respect to these revenues cannot be separately identified.
  The information includes cash flows related to the Peace River in situ operation.
At December 31 ($ millions) 2002 2001 2000

Net Cash Flows
Future cash inflow
    18 135       11 979       25 745  
Future operating and development costs
    6 512       6 094       6 572  
Future income taxes
    4 039       2 090       8 649  

Future net cash flows1
    7 584       3 795       10 524  
10% annual discount for estimated timing of cash flows
    4 291       1 596       4 414  

Standardized measure of discounted future net cash flows from proved oil and gas reserves
    3 293       2 199       6 110  

Changes in Net Cash Flows
Balance at beginning of year
    2 199       6 110       3 303  
Changes resulting from:
Sales, net of operating costs
    (700 )     (1 931 )     (862 )
Net changes in prices and operating costs
    2 482       (6 054 )     6 486  
Extensions, discoveries and improved recoveries, less related costs
    49       53       8  
Development costs incurred during the period
    218       154       136  
Revisions of previous quantity estimates
    (382 )     (297 )     (151 )
Purchases of reserves in place
Sales of reserves in place
                (14 )
Accretion of discount
    220       612       330  
Net changes in income taxes
    (793 )     3 545       (3 126 )

Net (decrease) increase for the year
    1 094       (3 911 )     2 807  

Balance at end of year
    3 293       2 199       6 110  

  1  Future net cash flows were computed using year-end prices and costs, and year-end statutory tax rates that relate to existing proved developed and undeveloped oil and gas reserves.
SCHEDULE I      21  

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Schedule II Shell Pectin Logo    SHELL CANADA LIMITED


  The financial statements have been prepared in accordance with accounting principles generally accepted in Canada. They differ from those generally accepted in the U.S. in the following respects:
  Capitalization of Interest   Interest costs were expensed as incurred. U.S. accounting principles require capitalization and subsequent amortization of certain interest costs incurred on capital outlays.
  Pension Expenses   Prior to 2000, the application of the corridor method of accounting for pension expense used in the U.S. accounting principles resulted in the amortization of gains and losses only if a 10 per cent threshold was exceeded. On January 1, 2000, a new accounting standard was adopted, which harmonized Canadian and U.S. accounting standards. Adoption of the new Canadian standard gave rise to a transition asset, which is being amortized over the expected average remaining service life of the employee group. This amount is not recognized for U.S. reporting purposes.
  Derivative Instruments and Hedging Activity   In 2001, a new U.S. accounting standard FAS 133 relating to the treatment and disclosure of financial instruments was adopted. Under this standard, a hedging activity that does not qualify as a hedge, as specified under the U.S. standard, is marked-to-market to earnings. The Company has qualified only one transaction for U.S. hedge accounting treatment at year-end.
  Transactions with Affiliated Companies   U.S. accounting standards require the elimination of profit from related party transactions. In 2002, Shell Canada completed a non-recurring transaction with Shell Global Solutions International B.V. regarding Oil Products manufacturing cost-sharing agreement. This transaction resulted in a gain, which has been eliminated for U.S. reporting purposes.
  Stock-Based Compensation   U.S. accounting standard FAS 123 requires performance-based options to be charged to earnings.
  Income Taxes   U.S. accounting principles require an asset and liability approach to the recognition of deferred tax assets and liabilities in the Corporation’s financial statements. Effective January 1, 2000, the principles for recognizing deferred tax assets and liabilities in Canada and the U.S. were harmonized.
  Shipping and Handling Fees   The Emerging Issues Task Force of the Financial Accounting Standards Board (FASB) in the U.S. requires that shipping and handling cost not be offset against revenue. Under the Canadian standard, the fees are recorded in the following accounts:
($ millions) 2002 2001 2000

    243       251       347  
Operating expenses
    42       42       46  

22        SCHEDULE II

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  If the Corporation’s financial statements had been presented on the basis of U.S. accounting principles, earnings and earnings per share would have been:
($ millions) 2002 2001 2000

    561       1010       863  
Increase (decrease):
Capitalized interest amortized
    (12 )     (18 )     (12 )
Pension expense
    (37 )     (31 )     (33 )
Change in fair value of derivative instruments
    (3 )     9        
Elimination of profit on transaction with affiliate
    (24 )            
Stock-based compensation
    (3 )            
Income taxes
    20       19       7  

Adjusted Earnings Attributable to Common Shares
    502       989       825  

Basic Earnings per Common Share (dollars)
    1.82       3.60       3.00  
Diluted Earnings per Common Share (dollars)
    1.81       3.59       2.98  

  In accordance with U.S. accounting standard FAS 130, a separate statement would be presented which discloses the components of other comprehensive income:
($ millions) 2002 2001 2000

Other comprehensive income (loss), beginning of year
    (12 )            
Increase (decrease):
Cash flow hedge movements
    19       (14 )      
Cash flow hedge movements – tax
    (7 )     2        
Minimum additional pension liability
    (192 )            
Minimum additional pension liability – tax

Other Comprehensive Income (Loss)
    (115 )     (12 )      

  The net effect of the differences on the Corporation’s consolidated balance sheet is not material except for the following:
  From 1996, there is $225 million of retained earnings as a result of the sale of the Chemicals business. This would be classified as contributed surplus.
  In 2002, to comply with FAS 87, the prepaid pension asset would be adjusted by an additional minimum liability amount. FAS 87 requires this adjustment to reflect the excess of the plan’s accumulated benefit obligation over the market value of the plan assets. This excess over market value was the result of weakening equity markets. The additional minimum liability of $192 million would be reflected as a reduction of pension assets, with a corresponding reduction of the Company’s future income tax liability of $77 million.
  In compliance with FAS 133, in 2002 there would be reflected a derivative net asset of $6 million.

Accounting Recommendations

  The new U.S. standard FASB Interpretation No. 46 will be adopted in fiscal year 2003. This standard relates to the consolidation of Variable Interest Entities. Transactions involving these entities, which were not previously reflected on the balance sheet, must be included on the balance sheet. To comply with this new
SCHEDULE II      23  

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  standard, Shell Canada would be required to consolidate the lease arrangement for large mobile equipment at the Muskeg River Mine. The total value of this equipment could reach $260 million, with Shell’s share expected to be in the range of $140 to $160 million (approximately $75 million at December 31, 2002). Canadian standard setters are actively considering a similar standard.
  Additionally, U.S. accounting standard FAS 143 is applicable to fiscal years beginning on or after January 1, 2003. This standard requires the recognition of legal obligations associated with the retirement of tangible long-lived assets. A similar Canadian standard has been issued which will come into effect for Shell Canada on January 1, 2004. The adoption of this standard is expected to have no significant impact on the future earnings of the Corporation.
24        SCHEDULE II

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Auditors’ Report Shell Pectin Logo    SHELL CANADA LIMITED

To the Shareholders of Shell Canada Limited:

  Under date of January 31, 2003, we reported on the consolidated balance sheets of Shell Canada Limited as at December 31, 2002, 2001 and 2000 and the consolidated statements of earnings and retained earnings and cash flows for each of the three years in the period ended December 31, 2002, as incorporated by reference in the Annual Information Form with respect to the year ended December 31, 2002. In connection with our audits of the aforementioned consolidated statements, we also have audited the related supplemental note entitled United States Generally Accepted Accounting Principles and Reporting Practices as set forth in the Annual Information Form. This supplemental note is the responsibility of the Company’s management. Our responsibility is to express an opinion on this supplemental note based on our audits.
  In our opinion, such supplemental note, when considered in relation to the basic consolidated financial statements as a whole, presents fairly, in all material respects, the information set forth therein.

          (PricewaterhouseCoopers sig)

  Chartered Accountants
Calgary, Alberta
January 31, 2003

To the Shareholders of Shell Canada Limited:

  In the United States, reporting standards for auditors require the addition of an explanatory paragraph (following the opinion paragraph) when there is a change in accounting principles that has a material effect on the comparability of the company’s financial statements, such as the change described in Note 4 to the financial statements. Our report to the shareholders dated January 31, 2003, is expressed in accordance with the Canadian reporting standards which do not require a reference to such a change in accounting principles in the auditors’ report when the change is properly accounted for and adequately disclosed in the financial statements.

          (PricewaterhouseCoopers sig)

  Chartered Accountants
Calgary, Alberta
January 31, 2003

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Shell Canada reported earnings of $561 million or $2.03 per Common Share in 2002, with a return on average capital employed (ROACE) of 10.1 per cent. The reduction from the previous year’s exceptional high of 21.5 per cent was due to significantly lower commodity prices and higher capital employed for the Athabasca Oil Sands Project (AOSP), which did not start producing until late in the year.

The AOSP is poised to make a major contribution to Shell’s future earnings. The Muskeg River Mine achieved first bitumen production in December 2002 with synthetic crude oil production expected to start at the Scotford Upgrader around the end of the first quarter of 2003. The AOSP provides us with a significant new source of crude oil and refinery feedstock, extends the range and scale of our portfolio of businesses, and positions us well for future growth. I am proud to be part of this immense undertaking.

Clearly, 2002 was a very challenging year. Natural gas prices were down significantly from 2001 but gained strength in the fourth quarter, as supply tightened. Crude oil prices, which reflected the effect of tight global supply for most of 2002, rose strongly towards year-end, driven by the impact of concerns over Iraq and disruption of Venezuela’s supplies. Following two consecutive record years, refining margins were very weak in the first six months of 2002, improving in the second half. Marketing margins remained depressed throughout the year, with intense competition in both retail and commercial markets.

Resources results demonstrated the value of operational excellence. The Foothills natural gas plants performed reliably and safely. Shell’s share of natural sales gas production volumes from the Sable Offshore Energy Project (SOEP) averaged 158 million cubic feet per day. This was up slightly from 2001 and partially offset a small decline in production from the Foothills facilities. Although results from the deep section of the Onondaga exploration well were disappointing, the well confirmed reserves in a shallow section that are expected to support longer-term production from the Sable Basin. The Peace River in-situ heavy oil facility achieved its targeted increase in production rates.


Oil Products faced tough challenges. We successfully managed significant planned shutdowns and the start-up of major projects in all Shell refineries. Some Shell customers reported fuel system difficulties with their automobiles early in 2002. A prompt analysis of the situation indicated that a fuel additive may have contributed to this problem. As a result, we changed our fuel additive package in March 2002 and took steps to regain customer confidence. Shell sincerely regrets the inconvenience imposed on our customers and I am confident that we effectively managed their concerns. Our commitment to meeting our customers’ needs remains paramount. The retail gasoline market saw the extension of supermarket retailing networks, and subsequent price wars in certain areas further eroded market share. Reduced volumes combined with much greater than normal expenditures for planned maintenance contributed to higher unit costs.

Shell Canada’s dividends in 2002 were $0.80 cents per share, unchanged from 2001. Total shareholder return fell to 9.2 per cent from 19.2 per cent the previous year.


Before elaborating on our 2002 performance, I want to address the issue of corporate governance.

Shell Canada’s reputation rests on the honesty and integrity of all its business dealings. Every employee, starting with me, must read, understand and be held accountable to our Statement of General Business Principles and Code of Ethics. This is the foundation on which we base our policies, processes and controls. I am confident that we have sound principles and processes to ensure that Shell Canada complies not only with its own standards, but also with all those required by accounting and regulatory bodies. You will find more details on page 36 of this report and in the Statement of Corporate Governance Practices on page 75.


Although we have made progress in a number of areas, I regret that our overall safety performance was overshadowed by two fatalities in 2002. We have made every effort to learn from these tragic incidents and to apply what we have learned throughout the Company.


President’s Message  n  Shell Canada Limited 5


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We know that with concentrated effort we can move toward our goal of causing no harm to people. In 2002, Resources completed its best-ever year for recordable and lost-time incidents, while Oil Sands recorded an excellent safety performance in spite of the pressures associated with construction completion and commissioning activities. Nowhere is continuous improvement more important than in safety performance and we remain committed to the belief that all accidents are preventable.


Shell Canada began its journey towards sustainable development about 12 years ago. In that time, we have reviewed, refined and even redefined what SD means to the Company and how to achieve it. We continue to make progress and have realized that sustainable


provincial governments, the details of what will be required. We in Shell continue to pursue implementation plans that can achieve the Accord’s environmental objectives without undermining Canada’s competitiveness in world markets and damaging economic growth. It is imperative that any economic burden be shared across all sectors of society, including consumers. Finally, I believe that market-based mechanisms must play an important role in implementation.

As part of our interest in renewable energy sources, we continue to pursue long-term commercial opportunities in wind power. Our strategy is to identify and acquire appropriate properties to develop a platform for growth, and we have established a small wind business department.


The Athabasca Oil Sands Project is poised
to make a
major contribution to Shell’s future earnings

development — the integration of economic, environmental and social considerations into all our activities — goes hand in hand with engagement and transparency. We listen and respond to our many stakeholders and, where appropriate, we invite the scrutiny of independent third parties. I believe this approach helps Shell to maintain its licence to operate, it helps us to meet our customers’ expectations and it keeps our business robust, especially in challenging times.

I also believe that Shell Canada’s commitment to SD positions us well to work towards the requirements of the Kyoto Accord, which Canada has ratified. We accepted some years ago the need to respond to growing concerns on climate change and set tough goals to reduce our own greenhouse gas emissions. Of course, we have to deliver on our goals to earn the trust and respect of our stake-holders. We continue to work with our Climate Change Advisory Panel, which gives us valuable advice as we seek ways to meet the additional reduction targets we have set. We are engaged with others in our industry in working through, with the federal and


I am pleased to report that, for the third consecutive year, Shell Canada appeared in Canada’s Top 100 Employers list. In addition, Shell was among the Globe and Mail’s list of “50 Best Companies to Work For in Canada” and was named one of Alberta’s Most Respected Corporations.


The largest project in Shell Canada’s history has now become the Company’s newest operating business. Production of bitumen at the Muskeg River Mine began in December 2002 along with delivery of diluted bitumen into the Corridor Pipeline system en route to the new Scotford Upgrader. A contained fire occurred at the mine site in January 2003. In spite of this setback and severe weather conditions, synthetic crude oil production is expected to start around the end of the first quarter of 2003.

Pressures on costs and schedule continued throughout 2002 and it was disappointing to report in the third quarter an additional construction cost overrun of 10 per cent for the project. The availability of labour improved over the previous year, but productivity did not meet expectations and contributed to the increase in expenditures, as did engineering deficiencies and rework in some areas.


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In spite of the challenges associated with planning and building such an immense project, the AOSP has maintained an impressive safety performance throughout peak construction. The project has set new standards for community dialogue and stakeholder engagement. It also has the lowest intensity of carbon dioxide emissions of any project of its size and plans further reductions. The AOSP is crucial to the Company’s future profitability and growth.


Shell Canada will continue to pursue its corporate goals of leadership in profitability and profitable growth within the context of a strong commitment to sustainable development. Operational excellence remains the basis for achieving a sustained 15 per cent ROACE, which is our long-term goal.

Although commodity prices strengthened significantly in the fourth quarter of 2002, continuing uncertainty driven by international tensions and global economic concerns is likely to lead to intense market volatility in 2003.

The key business objective in 2003 is to move beyond the commissioning and start-up of the AOSP to full design production and upgrading of 155,000 barrels per day of bitumen and ensure that the AOSP begins to contribute to Shell’s profitability. At the same time, we will continue to assess expansion opportunities on our Athabasca leases.

We announced in November a 2003 capital and exploration expenditure plan of more than $800 million. This is far less than our spending programs in 2002 and 2001 when construction of the AOSP was at its peak. In 2003, we will invest about $55 million in Oil Sands mainly for completion of the infrastructure.

Resources will invest approximately $500 million in 2003. Included in our budgeted investment are plans to sustain production from our properties in the Foothills and potential expansion of our Peace River operation to 16,000 barrels per day of bitumen. In the Frontier areas we will continue to evaluate opportunities in the Sable Basin and the deep water off Nova Scotia, as well as in the Mackenzie Delta.

Oil Products plans to invest approximately $235 million in 2003, focusing on the implementation of a marketing strategy aimed at increasing market share for fuels and the convenience retail business. The manufacturing business will invest in projects to improve efficiency, reliability and yields and to comply with new ultra-low sulphur diesel legislation.

Ultimately, Shell Canada’s progress depends on people: our customers, our business associates and our employees. As we stand on the brink of a new era with the start-up of our Oil Sands operation, I thank all those who have contributed to our continuing success. And most of all I thank Shell employees everywhere for their loyalty, their talents, their perseverance and their enthusiasm.

Regrettably, we will lose two valued directors with the retirement of Bob Stewart and Bob Sprague in 2003. Shell Canada has benefited greatly from Bob Stewart’s experience and integrity since his election to the Board in 1995. And while Bob Sprague’s tenure has been only two years, we have much appreciated his contribution. I thank them both for their commitment and dedication.

I would like to thank our shareholders for their support. Along with our customers, you are the people who give us the opportunity to progress in a fiercely competitive industry and we will continue to work hard to retain your confidence in Shell Canada.

Finally, I will be retiring from Shell Canada in July 2003 after a career of 36 years with the Royal Dutch/Shell Group. I feel privileged to have had the opportunity to lead Shell Canada during an important period of its development and much appreciate the broad support I have received from all quarters. I extend my best wishes to Linda Cook, who will succeed me.

On behalf of the Board,

-s- Tim W. Faithfull

Tim W. Faithfull
President and Chief Executive Officer
Calgary, Alberta

March 2003


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Resources earnings for 2002 were $387 million compared with $600 million in 2001. Lower prices for natural gas and natural gas liquids together with higher unit costs and a $41 million after-tax write-off for the deeper section of the Onondaga exploration well contributed to the decline in earnings. Exploration and development investments and continued high plant reliability helped to sustain total barrels-of-oil-equivalent production near 2001 levels. Unit costs increased largely because of the elimination of Alberta energy rebates that were in place in 2001. Return on average capital employed was 23.3 per cent, down from 39.9 per cent in 2001. Resources capital and exploration expenditures were $389 million compared with $366 million in the previous year.


A warm winter, historically high storage levels and a struggling North American economy pushed down natural gas and natural gas liquids prices for much of 2002. Prices rose in the last quarter as weather turned colder and demand grew. Crude oil prices, affected by a variety of global events, increased throughout the year.

Natural Gas

Prices at Henry Hub in the United States dipped close to $2 US per million British thermal units (mmBtu) early in the year but recovered to more than $4 US per mmBtu by the fourth quarter. In Western Canada, increased hydro capacity, which temporarily reduced gas-fired power generation, weakened Pacific Northwest demand and weighed down prices. These lower prices discouraged North American natural gas drilling for much of the year, which raised questions about the availability of longer-term production. These concerns coupled with high crude oil prices supported the price rally in the last quarter of the year. The Company’s average plant gate price fell to $4.01 per thousand cubic feet (mcf) from the exceptionally high $5.75 per mcf in 2001.


($ millions except as noted)   2002   2001   2000

    1 384       1 645       1 600  
    387       600       536  
Capital employed
    1 725       1 596       1 408  
Capital and exploration expenditures
    389       366       254  
Return on average capital employed (%)
    23.3       39.9       38.7  


Natural Gas Liquids

Natural gas liquids include ethane, propane, butane and condensate. Ethane in Western Canada is priced relative to natural gas and, as natural gas prices fluctuated in 2002, ethane prices also changed considerably. Although overall North American demand for petrochemical feedstock was weak, demand for ethane in Western Canada remained steady during the year.

Seasonal inventories of propane and butane reached near-record highs several times during the year, but as demand increased in the fall and winter months, prices improved.

Condensate is used mainly to dilute bitumen and heavy crude oils so they can be transported by pipeline. As a result, production levels of heavy crude oil and bitumen significantly affect condensate prices. During the early part of 2002 when heavy crude oil production from industry was down, condensate traded at a discount to light crudes. As crude oil prices rose through the year, production of bitumen and heavy crude oils increased, raising the demand for condensate. Consequently, condensate sold at a premium to light crude in the second half of the year.

Crude Oil

Crude oil prices started the year at about $20 US per barrel (West Texas Intermediate) and rose during the year, averaging over $29 US per barrel in December. Prices reflected the impact of tight supply for much of the year. Tensions surrounding Iraq, disruption to Venezuelan production and decline in U.S. inventories exerted strong upward pressure through the end of 2002.


In 2002, several phosphate fertilizer plants in China expanded and consumption increased dramatically. At the same time, the U.S. fertilizer industry recovered from its dramatic decline the previous year and shipments of Canadian liquid sulphur to U.S. markets resumed. These factors coupled with low sulphur inventories at export terminals and consumers’ facilities put more strain on already tight worldwide supplies. By the end of 2002, market prices for sulphur were more than $40 US per tonne (FOB Vancouver), which was double the 2001 average.


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In previous years when demand was low, Shell poured and solidified any excess product into a sulphur block at its Shantz facility near Caroline, Alberta. As demand increased during the year, the Company remelted a modest volume of this block and profited from the high sulphur prices. In 2002, most of the sulphur production was shipped through Vancouver to markets in China, Australasia, Brazil and South Africa.


The Foothills business continued to make an important contribution to the profitability of Resources and the Company as a whole. The infrastructure is strategically located and, where capacity is available, Shell plants process some third party production.

Overall, Foothills was able to sustain production volumes close to 2001 levels. The Foothills fields continue to benefit from investment in development opportunities that generate new production volumes to help offset natural field decline. Some volume erosion occurred due to the impact of weather-related flooding in the


Continued investment in exploration and development opportunities extends the life of Shell’s Foothills natural gas fields.

The Waterton plant celebrated
its 40th birthday in 2002.

Waterton area, and pipeline replacement and repair work at the north end of Waterton and at Burnt Timber. Nevertheless, Foothills achieved excellent reliability and all pipelines were back in service by early 2003.


In 2002, the Waterton plant celebrated its 40th anniversary. The Waterton area continues to demonstrate potential for future exploration and development, particularly at the north end.

Jumping Pound/Moose Mountain

An exploration discovery in the Moose Mountain area in 2002 was tied into existing infrastructure in the fourth quarter. Additional wells are planned to delineate further these new reserves.


The Caroline Complex achieved high daily throughput levels in 2002, up to 125 per cent of initial design capacity. Increased plant throughput drove gas volumes higher during the year, but condensate volumes continued to fall due to the natural decline in the condensate content of the raw gas stream.


The successful infill drilling program in the Limestone area near Burnt Timber continued with the drilling of three new wells in 2002. Additional drilling is planned for 2003.

Burnt Timber/Panther

Exploration and development drilling continued in the South Burnt Timber area in 2002. In the Panther field, Shell is participating in a joint venture program to develop the large potential reserve base.


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The Company is actively working to find new Foothills gas reserves. Shell increased Foothills exploration spending to $47 million in 2002, acquiring an interest in approximately 37,000 gross hectares of land and 510 square kilometres of three-dimensional (3-D) seismic. Shell also participated in five exploration wells. Two of the wells resulted in discoveries and one well continued drilling into 2003. Shell will resume drilling in British Columbia in 2003 as an extension to the existing strategy of exploring in the foothills and the adjacent deep basin.


In 2001, Shell announced that it would drill additional soak radial wells at its Peace River in-situ oil sands operation to enable the plant to reach full capacity. In 2002, two additional pads, each comprising eight to 10 thermal in-situ bitumen wells, were drilled and tied-in, completing a total investment plan of $100 million. By the fourth quarter of 2002, all wells were tracking or exceeding


Sable Offshore Energy Project (SOEP)

SOEP operational performance continued to improve in 2002. Shell’s share of sales gas production averaged 158 million cubic feet per day (mmcf/d), up slightly over 2001. Natural gas liquids recovery also improved following modifications to the facilities in late 2001. One infill well was drilled in the Venture field in 2002 to maintain field productivity.

Based on technical reviews completed at the end of 2002, Shell has reduced its estimate of original sales gas reserves for the SOEP fields by approximately 90 billion cubic feet (bcf) to 700 bcf, and has reclassified some 200 bcf of sales gas reserves to proven undeveloped from the proven developed category. The effect of these revisions to the net reserves position is reflected on page 68 in the Supplemental Resources disclosure section. These reserve changes will result in higher depreciation charges for Shell’s share of SOEP over the next few years.


Peace River filled the plant to its licensed capacity
of 12,000 barrels of bitumen per day

expectations as measured by the oil-to-steam ratio, which is a key performance measure. Peace River filled the plant to its licensed capacity of 12,000 barrels of bitumen per day and achieved record production rates in December of 2002. The technology that is driving the efficient recovery of bitumen will create the opportunity for future expansion of this large resource base.

The Company has approved a plan to increase production to 16,000 barrels per day by debottlenecking the plant and drilling additional wells. This expansion and subsequent growth are contingent upon regulatory approvals and ongoing satisfactory operating performance. Competitive unit costs are key to unlocking the potential value of Shell’s extensive leaseholdings in the area.


SOEP Tier II comprises the development of three fields — Alma, South Venture and Glenelg — and the installation of compression. These projects are planned for the 2003-2006 period and will extend the life of the project. By year-end, construction of the Alma facilities was well under way. Drilling at Alma is expected to begin around mid-2003, with production start-up anticipated in late 2003. An early development well at South Venture was drilled in late 2002. A decision on proceeding with development of the field is expected early in 2003.

In February 2002, ExxonMobil Canada Properties became the SOEP operator, the role formerly held by Sable Offshore Energy Inc. The main reason for this change was to emphasize operational performance as the project moves from development to operations.


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In late 2002, Shell and the other joint venture participants were in the final stages of negotiating the sale of an 8.4 per cent interest in the SOEP infrastructure downstream of the offshore Thebaud platform. This interest was acquired in 2001 by exercising a right of first refusal on the sale of SOEP assets by Nova Scotia Resources Ltd. Following the sale, Shell’s share of the project will revert to 31.3 per cent overall.

Nova Scotia Shelf

In May 2002, Shell suspended its wholly owned Onondaga B-84 exploration well as a potential natural gas producer. The main purpose of the well was to evaluate a previously untested deep geological section identified from seismic surveys. The well encountered indications of gas throughout the deeper section and some potential reservoir sections, but overall reservoir development was not enough to warrant production testing. The well did confirm the presence of natural gas in a shallower section and delineated a previous (1969) discovery. The reserves confirmed by the Onondaga well are expected to result in further development and production from the basin, potentially using the existing SOEP infrastructure.

Shell has a significant presence in the Nova Scotia Shelf through its SOEP ownership, various interests in other discovery licences and its joint venture interest in about 473,000 hectares of exploration licences. Although recent exploration drilling results have been disappointing, Shell will continue to assess opportunities on these landholdings and evaluate other joint exploration opportunities on the Nova Scotia Shelf.

Nova Scotia Deep Water

Shell has a one-third interest in approximately 474,400 hectares of exploration licences in the Nova Scotia offshore deep water and is the operator of this exploration joint venture. With completion of the initial evaluation of the extensive 3-D seismic work conducted in 2001-2002, the focus in 2002 was on identifying potential drilling locations for an exploration well in 2003-2004.

Shell is also evaluating options to improve its portfolio of exploration opportunities in the Nova Scotia deep water.

Development of the Alma,South Venture and Glenelg natural gas fields will extend the life of the Sable project.

Mackenzie Delta

In January 2002, Shell and the other members of the Mackenzie Delta Producers’ Group, along with the Mackenzie Valley Aboriginal Pipeline Corporation, announced their intention to begin preparing regulatory applications to develop onshore natural gas resources in the Mackenzie Delta, Northwest Territories. This development, called the Mackenzie Gas Project, includes a pipeline development, tie-ins of Shell’s wholly owned Niglintgak field and two other anchor fields, and gas gathering and liquids handling facilities. Niglintgak has potential natural gas reserves in the range of one trillion cubic feet. In 2002, base-line environmental work and community consultation efforts began on the Mackenzie Gas Project. In addition, the project participants initiated pre-engineering work on the three fields, the gathering system and the Mackenzie Valley Pipeline.

The producers’ group expects to file regulatory applications for the project in the latter half of 2003, with the decision to proceed with development of the project anticipated in 2005. A favourable market, business climate, viable project economics and continued support from Aboriginal communities will be necessary to maintain the project schedule for 2008 start-up.


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During 2002, Shell completed 2-D and 3-D seismic programs on its wholly owned exploration licence south of the proposed Niglintgak field development. The Company is now evaluating this data and a decision on exploration drilling will follow. Shell also continues to review potential joint exploration opportunities in the onshore Mackenzie Delta region. The Company has entered into an agreement to participate in exploration drilling in early 2003.

Other Frontier Opportunities

The Frontier regions remain a platform for growth for Shell Canada. Technical and commercial assessments of other basins continue in order to evaluate the potential for investment in regions beyond offshore Nova Scotia and onshore Mackenzie Delta.


Shell’s 2002 exploration program totalled $130 million compared with $112 million in 2001. Exploration activities again focused on seismic and drilling programs in the foothills of Alberta, and on selective plays offshore Nova Scotia and in the Mackenzie Delta.


In 2002, Resources achieved its best-ever safety performance with respect to recordable injuries, but was deeply saddened by the death in August of a contractor working at the Peace River Complex. Resources continues to focus on appropriate standards and procedures to ensure that a safe work environment exists for everybody.

The Company assesses all new Resources projects and existing sites for aspects of sustainable development based on a formal Health, Safety and Environment system. All key Resources sites undergo audits, submit data to peer group benchmarking programs and maintain ISO registration. Over the past few years, all major sites achieved ISO 14001 registration for environmental management. ISO 14001 is an internationally recognized standard of environmental management requiring third party audits. In 2002, the ISO registrars visited these facilities to ensure continued compliance, and work began on the 2003 reregistration required by the ISO program. Health and safety programs are in place at all sites.


Resources has developed and implemented community consultation and communication programs to engage with people potentially affected by Shell’s activities.

For several years, Resources has been measuring greenhouse gas (GHG) emissions from its operations and setting targets for their reduction through investments aimed at reducing energy consumption.


Resources strategy is to continue to be a leader in profitability and profitable growth. Resources plans to:

n   maximize profit and cash flow by maintaining focus on operational excellence and investment in exploration and development opportunities in the foothills and the offshore Nova Scotia Shelf, which could be tied into existing infrastructure;

n   grow Shell’s existing business at Peace River to 16,000 barrels per day, continue development of the Niglintgak field and pursue exploration opportunities in the Mackenzie Delta and in the deep water offshore Nova Scotia; and

n   maintain a commitment to sustainable development through a focus on safety, health and environmental efficiencies and consultation with the public.


Resources plans to spend $503 million on capital investments in 2003 compared with $389 million in 2002. Plans are to continue investing in the Frontier areas, the Foothills and Peace River.

In the Frontier, Resources intends to invest $272 million in the next field developments of the Sable project as well as continued activity on the Nova Scotia deep water and in the Mackenzie Delta. At the same time, a budgeted investment of $180 million will support exploration and development in the Foothills. Peace River plans to spend $34 million in 2003 to begin the next phase of development. The balance of the spending program relates to marketing and information technology.


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Oil Sands started operations at the end of 2002 and reported a loss of $5 million due primarily to capital taxes on the related assets. After years of planning and construction, Shell Canada Limited’s largest-ever project has become the first new fully integrated oil sands project in Alberta in 30 years. The Athabasca Oil Sands Project (AOSP) started up in December 2002 with the first production and sale of bitumen from the Muskeg River Mine. Production of synthetic crude oil is anticipated around the end of the first quarter of 2003. At full production, the AOSP is expected to:

n   supply the equivalent of 10 per cent of Canada’s oil needs;
n   increase Shell’s barrels-of-oil-equivalent (BOE) production by more than 50 per cent;
n   fuel the equivalent of one-third of Alberta’s vehicles; and
n   employ almost 1,000 full-time workers.

The project is also expected to incur more than $5 billion in royalties and taxes over its life.

The AOSP is a joint venture of Shell Canada Limited (60 per cent), Chevron Canada Limited (20 per cent) and Western Oil Sands L.P. (20 per cent). It comprises:

n   the Muskeg River Mine and extraction plant located on Lease 13, about 75 kilometres north of Fort McMurray, Alberta; and
n   the Scotford Upgrader located adjacent to Shell’s Scotford Refinery, north of Fort Saskatchewan, Alberta.

The AOSP has also added important new infrastructure to Alberta’s energy sector through a number of commercial arrangements, which include:

n   the Corridor Pipeline, which carries diluted bitumen 493 kilometres from the mine near Fort McMurray to the Scotford Upgrader and returns recycled diluent to the mine;
n   ATCO Pipelines’natural gas pipeline to the mine; and
n   ATCO Power’s cogeneration facilities at the mine and upgrader, providing more than 300 megawatts of natural gas-fired power generation.

The AOSP is a unique operation in the oil sands industry and offers many benefits:

n   high quality ore;
n   new technology, particularly in the froth treatment facilities;
n   increased yield and product quality through the use of hydrogen addition technology in upgrading;
n   high energy efficiency through the use of state-of-the-art facilities, including two large cogeneration plants;
n   synergies with the Scotford Refinery; and
n   lowest carbon dioxide emissions intensity of any mineable oil sands project.

With completion of the AOSP, Shell has launched a new business unit that will provide a secure source of crude oil for its downstream business. The Scotford Refinery will use more than half of the production from the upgrader to make high quality transport fuels and other products.

Albian Sands Energy Inc. (Albian Sands), a company owned by the joint venture, operates the Muskeg River Mine and extraction plant. In 2002, Albian Sands took delivery of diluent at the mine site, brought the first ore to extraction, commissioned the world’s largest mining trucks and shovels and began production of diluted bitumen. The Muskeg River Mine is designed to produce an average of 155,000 barrels per day (bpd) of bitumen at full production.


  ($ millions except as noted) 2002   2001   2000    
  Revenues     3                
  Earnings (loss)     (5 )              
  Capital employed     3 380       1 911       564    
  Capital and exploration expenditures     1 460       1 313       606    


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The world’s largest haul truck, a Caterpillar 797B, and the first Bucyrus 495HF electric rope shovel in operation at the Muskeg River Mine.  

The work completed in 2002 for the Scotford Upgrader and modifications to Shell’s adjacent refinery included the successful commissioning and testing of the sulphur recovery, hydrogen manufacturing, cogeneration, atmospheric and vacuum distillation units and utility systems. As well, the residue hydroconversion unit was well into commissioning and start-up by year-end. The Scotford modifications were successfully completed, tied in and commissioned during a major refinery turnaround.

With more than 56 million work-hours since 1999, the AOSP has maintained an impressive safety performance. Following a record-breaking safety performance in 2001, the upgrader site set a new record in 2002 for the industrial construction industry in Alberta of 6.25 million consecutive hours without a lost-time incident. Throughout the year, the AOSP was one of the largest and safest employers of trades and construction workers in Alberta with over 13,000 people employed and no serious injuries. For this and other achievements, Alberta Construction Magazine recognized the AOSP as one of two best industrial projects in 2002.

Cost and schedule pressures remained a challenge throughout the year, with project cost estimates increasing by an additional 10 per cent over November 2001 estimates. The total cost estimate for the AOSP has risen to $5.7 billion ($3.4 billion Shell share) from the original estimate of $3.8 billion. The cost estimate for the Scotford modifications has risen to $500 million from the original $400 million. Shell’s share of the capital costs in 2002 was $1,646 million, including $186 million for the refinery modifications compared with estimated amounts of $991 million and $102 million respectively.

Even though labour availability improved over 2001, it continued to be a challenge as more craft workers than planned were needed to regain schedule losses from 2001. As well, deficiencies in the quality of engineering work and equipment in some areas caused additional field work, resulting in lower than planned productivity.

With the start of production, the AOSP delivered to the pipeline product that met all the required specifications. However, a hydrocarbon leak at the Muskeg River Mine in January 2003 caused a fire, which was quickly extinguished. Repairs are under way, with completion expected in the first quarter.


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The licence to operate and grow the AOSP business comes from a strong commitment to the principles of sustainable development. This is particularly important to people who live closest to the Muskeg River Mine and the Scotford Upgrader. Through continued dialogue, the AOSP has maintained successful relationships with project stakeholders who include potential customers, employees, neighbours, shareholders, Aboriginal groups, government repre-sentatives, environmental organizations and other industry players.

The AOSP is involved in a number of organizations, including the Cumulative Environmental Management Association (CEMA) and the Athabasca Regional Issues Working Group Association (RIWG). These organizations provide a forum for regional stakeholders to ensure management of the region’s cumulative environmental effects and social impacts associated with orderly oil sands development. The upgrader staff focused on resident communi-


The AOSP continues to support the communities where its employees live and the joint venture does business. Almost half of all Albian Sands employees have been hired locally from the Regional Municipality of Wood Buffalo. To date, Wood Buffalo companies have received $50 million for contract services, with $24 million paid to local Aboriginal businesses. For example, the AOSP’s closest Aboriginal neighbours, the Fort McKay/Albian Sands Business Alliance, had contracts in 1999 worth about $4 million. Over the last three years, the AOSP has worked to build capacity and increase project scope so that the five-year (2002-2006) contracts with the Alliance are now valued at more than $70 million.


The AOSP continues to support the communities where
its employees live and the joint venture does business


cation, ensuring neighbouring residents were fully briefed on startup conditions and processes. In addition, Shell has established a 24-hour Scotford community update phone line and began operating two of the eight air monitoring systems of the Fort Air Partnership in Fort Saskatchewan.


Shell wants to make sure it is making a positive contribution in the neighbouring communities. Some of the initiatives in 2002 included:

n   start of construction on an Elder Centre in Fort McKay;
n   sponsorship of Aboriginal youth-elder camps and workshops;
n   sponsorship of interactive educational programs at the Oil Sands Discovery Centre in Fort McMurray so that all students in the community can attend free of charge;
n   implementation of an employee orientation program about the culture and history of neighbouring Aboriginal communities;
n   sponsorship of the 2004 Arctic Winter Games volunteer program through a donation of $175,000; and
n   donation of $230,000 to Tree Canada towards the planting of 360,000 trees in Strathcona County and Boyle, Alberta, on behalf of the AOSP.


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22 Shell Canada Limited  n  Oil Sands

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The AOSP is also committed to the efficient use of materials and resources throughout the project and into operations. For example, the on-site cogeneration plants, commissioned in 2002, produce both electricity and heat for the upgrader and the mine site, with surplus electricity sold to the Alberta provincial electrical grid. The AOSP also built a pipeline between the upgrader and a neigh-bouring chemical plant to use hydrogen that is a byproduct of that plant’s processes at the upgrader in the manufacture of synthetic crude oil.

The AOSP has set a goal of reducing greenhouse gas (GHG) emissions by 50 per cent by 2010. This reduction would make the project’s synthetic crude oil less GHG-intensive than the average North American imported crude that it will replace. The Shell Canada Climate Change Advisory Panel has provided input into the AOSP’s greenhouse gas management plan. The portfolio of activities includes:

n   internal energy efficiency projects;
n   domestic purchased offsets like the Tree Canada Afforestation project;
n   offsets generated within Shell and partners’activities;
n   clean development mechanism projects with international partners; and
n   feasibility studies regarding carbon dioxide sequestration.

The Path to Operational Excellence

With the achievement of bitumen production at the Muskeg River Mine in 2002, the focus will be on producing first synthetic crude oil and building production volumes up to full rates in the third quarter of 2003 while maintaining the drive to be the lowest cost operator in the industry. Key goals are:

n   managing costs and growing production;
n   achieving the best possible plant reliability with minimum downtime and energy consumption, and maximum product yield;
n   being a reliable source of quality products for the marketplace; and
n   achieving GHG reduction targets.

The foundation for success with operational excellence is a large, high quality resource base, new and efficient end-to-end processing facilities and a ready market for much of Shell’s production within its own manufacturing facilities.

Another cornerstone of future success is to deliver excellent safety performance and community relations as the transition is made from construction to operations.



Floyd Gladue is a field operator in
Ore Preparation at the Muskeg River Mine.
The atmospheric and vacuum units
at the new Scotford Upgrader.

24 Shell Canada Limited  n  Oil Sands

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The Path to Growth

Once the AOSP is fully operational, Shell will look for further opportunities to reduce costs, enhance processes and increase production.

Shell continues to evaluate expansion opportunities in the Athabasca area. The experience and knowledge gained from the AOSP, its stakeholders and other projects will contribute to the regulatory process and development plans. Some of the work on long-term growth opportunities began in August of 2001 with the release of a formal public disclosure of its potential growth plans, which included:

Muskeg River Mine

Optimization and expansion of Lease 13 West and development of Lease 90 would bring total production to approximately 225,000 bpd of bitumen, up from the current design of 155,000 bpd. This would represent the first stage of growth by building on the existing assets and regulatory approvals.

Jackpine Mine — Phase 1

In May 2002, on behalf of the AOSP joint venture participants, Shell submitted a regulatory application and Environmental Impact Assessment to the Alberta Energy and Utilities Board and Alberta Environment for phase one of the Jackpine Mine. The Jackpine Mine would involve the construction of a mining and extraction facility on the eastern portion of Lease 13 to produce approximately 200,000 bpd of bitumen. Early entry into the public regulatory process, with the 2001 public disclosure, provided adequate time for stakeholder consultation and involvement. The regulatory process continues, with approvals anticipated by the end of 2003.


Jackpine Mine — Phase 2

Following the development of Jackpine Mine — Phase 1, mining additional resources from leases 88 and 89 would increase bitumen production by approximately 100,000 bpd.

These growth initiatives will capitalize on existing infrastructure associated with commercial arrangements and AOSP facilities.

Muskeg River Mine expansion would likely take place in the 2005 time frame, followed by development of Jackpine Mine — Phase 1 and Jackpine Mine — Phase 2. The exact timing of these developments will depend on factors such as market conditions, construction costs, project economics, technology, the ability of the project to meet Shell’s sustainable development principles and the outcome of the various regulatory processes.


Shell has planned capital expenditures for the oil sands business of $57 million in 2003. Most of this capital spending will be for completion of the AOSP. The balance relates to screening of growth opportunities.

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Oil Products earnings were $198 million in 2002, down sharply from the record $401 million in 2001. The decrease in earnings was due mainly to lower refinery and marketing margins, increased operating costs and reduced throughputs. Oil Products return on average capital employed was 10.7 per cent compared with 22.2 per cent in 2001. Capital expenditures were $433 million, including $186 million for Oil Sands-related Scotford modifications, compared with $343 million the previous year.

The 2002 environment for refiners was much less favourable than in 2001. High product inventories in North America, weak demand for diesel and jet fuels in the first six months of the year and rising crude oil costs all contributed to weaker industry refinery margins. However, conditions improved in the second half of the year.

The retail and commercial businesses faced significant challenges from competitive pressure and pockets of weakness in the economy, which inhibited growth in sales volumes.

Marketing expenditures increased in 2002, partly as a result of sales promotion programs and other customer relationship initiatives. Refinery operating costs were higher than in the previous year due to twice the normal level of turnaround activity and related reductions in refinery utilization. Consequently, unit costs of 5.4 cents per litre were unusually high for Shell. Nevertheless, the Company remained a leader among its competitors in unit cost performance.

Safety performance was an area of serious concern in 2002 for Oil Products. Along with the tragic fatality at the Montreal East Refinery, there was an increase in the number of recordable incidents in the Sarnia and Montreal East refineries, despite continued emphasis on keeping the job environment safe for employees and contractors. Both locations have stepped up efforts in the area of safety management including external reviews, high levels of management visibility and employee and contractor engagement. The continued focus in 2003 will be on working safely. In line with the Company’s belief that all accidents are preventable, Shell’s goal is zero accidents and no harm to people.

Shell Canada undertook substantial project and planned maintenance activity in its refineries during 2002. Major turnarounds took place at all three refineries in the second quarter of the year. However, all Shell refineries resumed normal operations by mid-year and subsequently benefited from excellent operational availability.

Supply and Distribution (S&D) continued to focus on securing crude oil and synthetic crude oil that add the most value to Shell’s refinery network and enhance facility performance. S&D also took advantage of long-term agreements to ensure uninterrupted supply throughout a major turnaround period. The distribution network maintained its best-in-class standing for unit cost in an international benchmarking study completed in 2002.

During its biggest-ever turnaround, Scotford Refinery completed and commissioned major modifications enabling it to receive feed-stock provided by the Oil Sands upgrader from bitumen extracted at the Muskeg River Mine. The refinery made significant gains in hydrocarbon management, particularly after the turnaround, when new capabilities from the integration project improved yields.

Sarnia Refinery celebrated its 50th anniversary of operation in September 2002. The refinery improved yields, operated with high reliability and developed the flexibility to process a greater variety of feedstock than in previous years. Sarnia completed a major turnaround and the first two of five phases to install new instrumentation for a distributed control system. Anew flare system was also installed.

Throughout 2002, Montreal East Refinery operated more reliably than in previous years, taking advantage of the stronger refinery margins available in the second half of the year.


  ($ millions except as noted) 2002   2001   2000  

  Revenues     6 071       6 240       6 740  
  Earnings     198       401       340  
  Capital employed     1 913       1 789       1 818  
  Capital expenditures     433       343       279  
  Return on average capital employed (%)     10.7       22.2       19.6  


26 Shell Canada Limited  n  Oil Products

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Product Reformulation
Refinery staff and contractors completed construction of gasoline hydrotreaters at both the Sarnia and Montreal East refineries. The projects began in 2001 and the completed units became operational December 2002. At a total cost of $150 million, these projects will enable the refineries to meet new federal regulations on sulphur content in gasoline. The new regulations require Canadian refiners to produce and sell gasoline with a cumulative average of 150 parts per million (ppm) of sulphur over the period between July 1, 2002, and December 31, 2004, falling to an average of 30 ppm on January 1, 2005. Product from Shell’s Scotford Refinery already met the new requirements. With completion of these projects, Shell became the first national refiner capable of producing 30 ppm gasoline.

The retail gasoline market became increasingly competitive through 2002 with continued network upgrading by traditional competitors and significant expansion into the fuels business by grocery and supermarket retailers. Shell’s share in the major urban markets declined to an average of 17.8 per cent from 18.6 per cent in 2001. Unit fuel margins declined due mainly to increasing crude oil and wholesale prices, which could not be fully recovered at the pump, as well as to localized retail price wars. The Company completed a comprehensive review of the Retail business and, in 2003, will be implementing changes to improve the competitiveness of the business and capitalize on new opportunities.

In early 2002, Shell became aware of and addressed problems associated with its gasoline quality. Athorough investigation determined that an additive may have been a factor in the failure of some fuel system components. The Company took quick action to address customer concerns and initiate corrective action. Subsequent tracking showed that this response led to a major decline in the number of customers experiencing fuel system difficulties. Shell continues to stand behind the quality of its products.

Customer Focus
Shell is committed to delivering superior customer value through high quality products and services, one-stop convenience and a high level of customer service.

Shell’s affiliation with the AIR MILES® reward miles program marked its 10th year in 2002. The Company celebrated this milestone with an extensive sweepstakes program where individual customers could win 10,000 AIR MILES® reward miles every day. The AIR MILES® program remains very popular with Shell consumers.

The easyPAYTM technology has now reached over 200,000 Canadian consumers. In January 2002, Shell introduced this technology to participating sites in the Winnipeg and London markets in addition to existing easyPAYTM sites in Vancouver, Calgary, Edmonton, Toronto, Ottawa and Montreal. The technology improves the speed and ease of vehicle refuelling. At participating sites, customers simply present their easyPAYTM key tag to the easyPAYTM symbol at the pump. The easyPAYTM tag is cross-referenced with the customer’s credit card and AIR MILES® information.

Retail Network
Efforts to improve Shell’s network efficiency continued in 2002. Average annual throughput at Shell- and private-brand sites remained at 3.8 million litres in 2002. Retail completed 29 image conversions including refurbishing 10 Provisoir stores in Quebec and rebranding four private-brand sites. There were 1,838 Shell retail sites at year-end, including 133 private-brand sites. This compares with 1,935 Shell sites at the end of 2001, of which 178 were private-brand sites.

Non-Petroleum Products and Services
Margin growth from increased sales of food store and car wash products and services continued in 2002. Both convenience store sales and car wash revenues grew by more than 10 per cent over 2001. Additional food stores, plus a strong focus on sales promotion and product placement and display, improved convenience store sales. The growth in car wash revenues was mainly due to increased consumer purchases of premium washes and promotional activities.

®   Trademark of AIR MILES International Trading B.V. Used under licence by Shell Canada Products.

TM   Trademark of Shell Canada Limited. Used under licence by Shell Canada Products.


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Shell’s Commercial business sells branded products to aviation, agricultural, industrial, transportation, resource-based and home-heating sectors, and unbranded product to commercial distributors and other gasoline retailers. A tough business environment marked by volatile crude oil and wholesale prices compressed margins in 2002.

In June 2002, Shell upgraded its flagship diesel engine oil, Shell Rotella TTM Multigrade 15W-40. The reformulated product exceeds the CI-4 American Petroleum Institute’s new standards for low-emission heavy-duty diesel engines, in readiness for future exhaust gas recirculation diesel engines. Importantly, the reformulation maintained the strong heritage of Rotella TTM, using current technology to provide maximum protection for existing engines.

In September 2002, the Commercial business piloted the Shell e-Store. This self-serve Internet application allows customers to check product prices, place orders, review their account information and perform several other useful functions. Shell e-Store meets the needs of customers looking for a supply capability that is reliable, easy to use, and provides “information at your fingertips.” After a targeted offering to selected customers in 2002, a broad market rollout will follow in 2003.

Commercial Network
The general slowdown in the agricultural sector associated with drought conditions across Western Canada resulted in lower network throughputs in 2002. Shell further reduced its number of bulk storage plants to 43 from 48.

Shell’s Aviation network comprises 57 fixed-base operations within Canada. Included in this network are 17 AerocentreTM sites in major centres, which feature pilot and passenger lounges, catering services, business amenities, hangerage and more. In 2002, Shell Canada customers gained access to about 700 sites in the United States as a result of an arrangement between Shell Global Aviation and Avfuel Corporation. This arrangement provides worldwide card acceptance for both Shell and Avfuel customers.

Aviation fuel sales volumes fell in 2002 compared with 2001. The decrease was due mainly to a lingering weakness in the aviation sector following the tragic events of September 11, 2001.



Aviation fuel sales are an important part of Shell Canada’s Commercial business.



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In 2002, the Calgary Lubricants and Grease Plant celebrated its 20th year of operation, while the Brockville Lubricant Plant completed its 10th anniversary.

Blending and packaging rates at the Brockville plant improved marginally in 2002 as a result of growth in third party packaging contracts. In 2003, Brockville will pursue further production growth opportunities, including additional production for Pennzoil-Quaker State, an affiliate of Shell Oil Company of Houston, Texas, to increase plant utilization and further reduce unit cost. Grease production at the Calgary plant also increased marginally.

Industrial Services
In 2001, Industrial Services began marketing fluid management services to plants in the automotive component manufacturing sector. The program is designed to reduce operating costs and improve process productivity in customer plant operations. In 2002, working with Royal Dutch/Shell Group affiliates Shell Global Services and Shell Global Solutions, the Company expanded its range of services to include maintenance planning, and initiated sales penetration into other industrial sectors. The team secured an important contract with a major North American automobile manufacturer in late 2002.


Formula Shell synthetic
blend motor oil is available at
any Shell retail gasoline station.


Oil Products continued its commitment to integrate sustainable development into day-to-day activities in 2002. Operational excellence, which means running a host of complex facilities safely, responsibly and efficiently, helps to minimize Shell’s impact on its neighbours and other stakeholders.

During 2002, all Shell refineries and lubricants and grease plants continued to meet ISO 14001 standards first attained in 2001. ISO 14001 is an international standard of environmental management that requires verification through external audits.

Shell also monitors its health, safety and environmental performance internally and takes action when targets are not met. Spill frequency, which is the number of litres of product spilled per million litres handled, is one important measure. Shell’s spill frequency in 2002 was 3.34 compared with 21.3 the previous year. Following several spills at refinery tank storage areas in 2001, Shell reviewed winterizing procedures, consulted with other companies to identify best practices and introduced changes.

In 2002, Oil Products implemented Community Dialogue, a formal framework to enhance mutual understanding between facility staff and their publics, and to communicate emergency preparedness and response efforts more effectively. By year-end, 21 plans were in place to engage nearby residents, key government officials and public groups.

The Company continued to supply fuel to the Dreams Take Flight charity. The program provides “a trip of a lifetime” to Disneyland or Disney World for physically, mentally or socially challenged children. Shell also donated 40,000 litres of diesel fuel to the Hay West campaign during the drought in Western Canada. The fuel helped defray the cost of transporting donated hay between the farms and rail yards.




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Oil Products goals are to sustain a 15 per cent return on average capital employed through the pursuit of operational excellence, and to focus on profitable growth with an ongoing commitment to sustainable development. There will be a major emphasis on improving safety performance.

Oil Products key strategies in 2003 will be as follows:

Manufacturing, Supply and Distribution

n   maintain first quartile performance in operational availability;
n   continue to drive for improved efficiency and yields at all the refineries;
n   leverage new technology, like the instrumentation digital control system at Sarnia Refinery, to improve yields and efficiency;
n   maximize benefits from the new Oil Sands upgrader feedstocks at the Scotford and Sarnia refineries; and
n   initiate the design and engineering phase of the distillate desulphurization projects to meet ultra-low sulphur diesel (ULSD) legislation, which requires that ULSD be available at less than 15 parts per million of sulphur by mid-2006.


n   differentiate the Shell brand by offering improved value to targeted retail customers, with a focus on fuels, the refuelling experience, and related products and services;
n   increase Shell’s share in both the fuels and convenience retail business through increased investment and growth in the base network; and
n   reduce net unit cost to increase competitiveness.


Part of the Brockville tank farm, where
product is stored before blending.


n   provide relevant, valued customer service at reduced operating unit costs;
n   increase branded sales and market share by offering additional value to targeted customers;
n   expand Industrial Services sales penetration into various industry sectors;
n   launch e-Store, an on-line customer ordering/transaction system;
n   service the needs of global Shell customers in Canada through linkages with the Royal Dutch/Shell Group of Companies;
n   improve lubricants supply chain costs; and
n   improve asset efficiency — plants, costs, working capital.

Oil Products plans capital expenditures of $237 million in 2003, a decrease from $433 million in 2002. Of this total, $155 million is budgeted for growth and profitability projects and $36 million for compliance with new legislation and expenditures related to changes in product specifications. The remaining $46 million is earmarked for supporting the asset integrity of existing facilities.




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Shell Canada’s Corporate sector reported expenses of $19 million in 2002 compared with earnings of $9 million in 2001. Interest income received for prior-period income tax settlements only partly offset higher net financing costs.

Record capital spending in 2002, much of it associated with construction of the Athabasca Oil Sands Project (AOSP), resulted in total financing of $1.4 billion.

Shell’s financing plan includes short-term commercial paper, medium-term notes and accounts receivable securitization. This combination provides cost-effective financing and repayment flexibility.

Commercial paper outstanding at year-end increased from the previous year by $459 million to $671 million. The Board of Directors authorized a $250 million increase in the upper limit of this facility to $1.5 billion late August 2002. Also in 2002, Shell issued $745 million of medium-term notes under the Company’s $1 billion shelf prospectus. In July 2002, the Board approved a $250 million increase to the Company’s accounts receivable securitization program. Under this $600 million program, Shell increased accounts receivable sales during the year by $170 million, bringing total accounts receivable sold to $520 million. The balance of financing relates to capital lease arrangements associated mainly with the AOSP.

Interest and other financing charges in 2002 totalled $49 million. All of Shell’s financing costs in 2002 were based on floating interest rates. Low interest rates resulted in attractive financing charges that averaged well below three per cent for Shell over the year.

On February 4, 2003, the Company announced a Normal Course Issuer Bid to repurchase for cancellation up to two per cent of its 275,908,290 Common Shares or a maximum of 5,518,166 Common Shares. The bid began February 7, 2003, and will continue to February 6, 2004, or the date when Shell has either purchased the

maximum number of shares or terminated the bid. The purchase of the Common Shares under the bid will counter the effects of dilution due to issuance of Common Shares under the employee stock option program. Purchase of the shares will be at the market price at time of acquisition and will be conducted through the Toronto Stock Exchange. A copy of the Notice of Intention may be obtained upon request, without charge, by contacting CIBC Mellon Trust Company.

Dividends paid for the year 2002 totalled $0.80 per Common Share, unchanged from 2001.

With completion of the largest capital spending program in its history, Shell Canada remains financially strong. The Company expects that operating cash flow from Resources and Oil Products and cash flow from new Oil Sands production will exceed capital spending in 2003 and 2004. Shell will use available cash to reduce debt that it issued to finance the 2002 capital program. The Company can also gain ready access to debt capital markets in Canada and the United States, should the need arise.

Reductions in equity market valuations over the last two years have eroded Shell Canada’s pension surplus. The Company decided that a 7.5 per cent long-term rate of return would better reflect the expected market performance of plan assets than the rate of 8.0 per cent used by Shell in 2001 and 2002. The resulting increase in pension costs is expected to reduce 2003 earnings by about $25 million compared with 2002.

Actuarial valuations of pension funding requirements will be completed in May 2003. Given lower expected pension asset returns, the Company anticipates a cash contribution in 2003. However, the funding requirement should not have a significant effect on Shell Canada’s overall financial position.




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One of three parallel conveyor belts at
the Muskeg River Mine takes ore from
the silo into the breaker building.


Variable Interest Entities
Accounting standard bodies in North America are proposing new accounting guidelines to consolidate transactions currently not reflected in balance sheets. The Financial Accounting Standards Board has recently published FASB Interpretation No. 46 regarding the Consolidation of Variable Interest Entities (previously referred to as Special Purpose Entities). The Canadian Institute of Chartered Accountants is considering similar measures. Under these guidelines, certain financial arrangements where Shell has a variable interest will be included in the consolidated balance sheet starting as early as the third quarter of 2003. Based on these latest U.S. accounting guidelines, Shell Canada would consolidate a lease arrangement for large mobile equipment (trucks, scrapers and shovels) in use at the Muskeg River Mine. The total value of this equipment could reach $260 million with Shell’s share expected to be in the range of $140 million to $160 million (approximately $75 million at December 31, 2002). This arrangement is accounted for as an operating lease under existing accounting principles.

Shell Canada has sold $520 million of accounts receivable to a multi-seller trust under its securitization program. The Company did not retain any ownership as part of the sale and removed the corresponding values from its balance sheet. Under the new FASB Variable Interest Entities guidelines, this transaction will not require consolidation, as the Company is not the primary beneficiary in the multi-seller trust.

Asset Retirement Obligations
A new U.S. standard for the accounting of asset retirement obligations was issued, applicable to fiscal years beginning on or after January 1, 2003. A similar Canadian standard has been issued, which will come into effect for Shell Canada January 1, 2004. This standard requires recognition of legal obligations associated with the retirement of tangible long-lived assets. The Company does not expect the adoption of this standard to have any significant impact on its future earnings.

Shell Canada’s corporate governance policies are reviewed annually. A number of regulatory bodies are involved in setting requirements and guidelines. The Company is well positioned to meet all the necessary standards.

The U.S. government enacted the Sarbanes-Oxley Act in 2002. One purpose of this legislation is to give added protection to investors by improving the reliability and accuracy of corporate disclosures. As a foreign private issuer, Shell Canada will comply with this new legislation as required. The Company’s existing controls and processes provide an excellent framework for certification under this Act.

In 2002, Shell Canada formalized its Corporate Disclosure Policy in a document approved by the Board of Directors. The intent of this policy is to raise awareness of and ensure compliance inside the organization with disclosure requirements and practices, and legal and regulatory requirements. A disclosure policy committee is responsible for ensuring implementation of and adherence to the policy.




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All employees at every level of the organization must understand and be accountable for upholding Shell Canada’s Statement of General Business Principles and Code of Ethics. This document is the foundation of the Company’s governance, controls and processes that, together, ensure and protect the integrity of all its business dealings. At the end of each quarter, senior managers prepare and sign a letter of assurance affirming that all financial and accounting transactions for their department have been described appropriately and are properly recorded.

Shell Canada conducts annual risk assessment reviews with each business and corporate management team, then consolidates the results. The reviews take place at the beginning of the annual planning cycle so that any action items may be incorporated into the budget and planning process.

Senior management identifies significant risks and reviews them with the Board of Directors. In addition, the Board receives operating and financial reports as well as quarterly reports on health, safety and sustainable development, commodity futures trading, and any interest rate and currency risk management.

Areas of risk identified by Shell Canada relate to project execution, operations, marketing, exploration and development, finance, health, safety and environment, and information technology system security. Senior management performs quarterly reviews to identify and monitor additional risk factors.

Project Execution
Every project undertaken by Shell Canada presents unique risks and challenges. Risks involving material costs, productivity, resource availability and foreign currency fluctuations are influenced by external factors beyond Shell’s control. To mitigate these risks, the Company identifies project objectives and critical success factors, measures progress and incorporates flexibility into project plans. Shell monitors and measures progress to meet project objectives, identify critical success factors and achieve milestones.

Measures in place to mitigate operational risks for Shell Canada include regular maintenance programs, ongoing asset integrity reviews and retention of highly trained and experienced personnel. The varied nature and location of Shell’s production facilities reduce the risk of more than one facility being inoperable at the same time.

Risks in marketing include disruptions in supply and market accessibility, commodity price volatility and credit risk. Shell has negotiated several supply and transportation arrangements to secure product supply and access to markets. Within the guidelines established by the Board of Directors, hedging tools are used to manage supply and inventory price risk. The Company manages credit risk by regularly reviewing credit profiles of current customers and conducting assessments of new customers.



With completion of the largest capital spending program in its history, Shell Canada remains financially strong



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Exploration and Development
Exploration and development risks involve activities related to locating commercially viable reserves and carrying out successful drilling programs. The use of modern exploration technology, such as three-dimensional (3-D) seismic surveys, and risk analysis techniques mitigates risk. Shell’s diverse portfolio of exploration opportunities ranging from the subarctic Northwest Territories to offshore Eastern Canada also helps to reduce risk.

Financial exposure risks result from currency and interest rate fluctuations.

Currency risk arises from fluctuation in foreign currency rates relative to the Canadian dollar. The resulting effect on earnings depends on the level of activity involving foreign currency. Shell conducts some commodity transactions priced in non-Canadian currency, mainly U.S. dollars. Netting foreign cash flow transactions across operations each month reduces foreign currency risk. For large capital projects, Shell hedges foreign currency capital commitments.

Interest rate fluctuations affect interest expense. Throughout 2002, the Company’s debt was based on floating interest rates.

Shell uses risk control and risk financing techniques, including insurance, to protect Shell against losses due to accidents.

Health, Safety and Environment (HSE)
and Sustainable Development

HSE exposure presents critical risks for Shell. The application of standards, procedures, training programs, audits and performance monitoring helps to prevent or minimize these risks. Shell Canada uses a comprehensive HSE management system to manage hazards and effects. Assessing the economic, environmental and social aspects of its projects and activities helps Shell to protect the robustness of its business and its licence to operate.

Information Technology Systems Security
Internet technologies, work force mobility and sophisticated tools for remote access have increased risks to data and information security. Investments in skilled, dependable staff, infrastructure tools and systems management practices manage the risk.


OPERATING EARNINGS SENSITIVITIES (after-tax) Increase (Decrease)  

    Natural gas   10-cent US increase per million Btu (Henry Hub)   $ 12 million    
    Condensate   $1 US increase per barrel (West Texas Intermediate)   $ 4 million    
    Bitumen   $1 US increase per barrel (West Texas Intermediate)   $ 2 million    
    Sulphur   $1 Cdn increase per tonne   $ 1 million    
    Foothills natural gas production   Increase of 10 mmcf/day   $ 6 million    

    Oil Products              
    Light oil sales margin   1/4-cent Cdn increase per litre   $ 23 million    
    Natural gas   10-cent US increase per million Btu (Henry Hub)   ($ 3 million )  

    Oil Sands              
    Crude oil   $1 US increase per barrel (West Texas Intermediate)   $ 25 million    
    Natural gas   10-cent US increase per million Btu (Henry Hub)   ($ 2 million )  
    Equity production   Increase of 1,000 bbl/day   $ 3 million    

    Shell Canada Exchange Rate (Total)   1-cent improvement in $Cdn vs. $US   ($ 20 million )  



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Shell Canada is committed to contributing to sustainable development through the integration of economic, environmental and social considerations in its business decision-making process. This requires the Company to understand and try to meet society’s expectations.

Health and Safety
Respecting and Safeguarding People
Shell Canada pursues the goal of no harm to people. So it was with profound regret that the Company experienced two worker fatalities in 2002.

Shell measures its health and safety performance by the frequency of employee and contractor incidents relative to hours worked. The total recordable injury frequency for employees and contractors in 2002 was 1.05 per 200,000 work-hours compared with 1.27 the previous year. In 2002, the total lost-time injury frequency for employees and contractors was 0.11 per 200,000 work-hours compared with 0.16 in 2001, and is the best ever recorded for Shell Canada. By comparison, the overall Canadian industry average for lost-time injury frequency (in 1998) was 2.62.


Shell Bridge over Talfourd Creek near
the Sarnia Manufacturing Centre is
an important part of the
community’s St. Clair River trail.

Brockville Lubricants Plant received the 2002 President’s Safety Award. This award recognizes the department or operating unit with the most outstanding safety performance and overall approach to safety management.

Brockville demonstrated excellence in safety performance, with exceptional worker involvement, innovation and ownership in addressing performance issues. The plant is a model of highly effective teams, committed to identifying and resolving potential safety hazards.


              Frequency of   Frequency of  
      Lost-Time   Lost-Time   Total Recordable  
      Injuries   Injuries   Injuries  


    2       0.04       0.70    

    22       0.13       1.16    

    24       0.11       1.05    


    2       0.06       0.54    

    23       0.18       1.48    

    25       0.16       1.27    




40 Shell Canada Limited  n  Corporate

Table of Contents

Protecting the Environment
Greenhouse Gas (GHG) Emissions Management
With the ratification of the Kyoto Protocol, Canada has set aggressive GHG reduction targets for the country. Shell Canada has been taking action on climate change for over a decade and is well positioned to participate in and respond to GHG policy development. Each business unit has developed its own GHG management plan, which considers Shell’s voluntary commitment and will help the Company respond to the emerging federal government policy for GHG management by industry.

Since achieving its 2000 target of stabilizing the GHG emissions for existing businesses at 1990 levels, Shell Canada has committed to a further six per cent reduction by 2008 for its 2000 base business. In 2002, the GHG emissions were approximately 240,000 tonnes below those in 2000.

For the fourth consecutive year, Shell Canada’s Voluntary Climate Change Action Plan Update to the Voluntary Challenge and Registry Inc. (VCR) gained the highest recognition for reporting status (gold).

The Shell Canada Climate Change Advisory Panel met twice in 2002. Panel members include Shell Canada’s president, a Shell International representative, and representatives of local communities as well as national and international environmental organizations. They provide input to Shell Canada’s strategy for managing climate change. This strategy, which was approved in September 2001, sets out the Company’s vision, plans and actions to manage Shell’s role in climate change.


The location of Shell’s Waterton field facilities underscores
the importance of sound environmental management.

Managing Resources
Resources met its target to improve energy use by 1.6 per cent. Oil Products refineries continued their progress towards a target of five per cent energy efficiency improvement between 2000 and 2005.

Since the end of 2000, Shell Canada has purchased the output from three wind turbines in southern Alberta. While this is quite a small contribution to the Company’s total electricity requirement, it has been important to the consideration of opportunities for energy diversification. Shell’s business strategy includes exploring opportunities to develop, own and operate wind farms in Canada.

Health, Safety and Environment (HSE)
Management System

Shell Canada has a systematic approach to identifying and preventing or minimizing health, safety and environmental hazards and effects throughout its operations and activities. Since 2001, Shell Canada has been registered as an ISO 14001 company for all its key operating facilities. These include four natural gas plants, three oil refineries, two lubricants manufacturing plants, and one heavy oil production facility, plus well construction and geophysical operations. The environmental management systems for the Corporate and Resources business units are also ISO 14001 registered. ISO 14001 is a voluntary, internationally recognized standard that is applicable to various industries worldwide.




Corporate  n  Shell Canada Limited 41

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Technology experts provide technical and engineering support to secure the best possible performance from Shell’s assets and new business opportunities. This expertise enables Shell to operate its refineries, gas plants, oil sands plants and other facilities efficiently and safely, as well as reduce any potential impact on the environment. The availability and application of this technical expertise and the development of creative solutions to technical problems has saved money for the Company.

Access to the worldwide research and technical support capabilities of the Royal Dutch/Shell Group of Companies augments Shell Canada’s capabilities.

Asset integrity requires reviews of Shell’s management systems as well as HSE and technical integrity management audits of the Company’s facilities.


Piikani Elder Margaret Plain Eagle
shares her knowledge with
Shell Canada in an historical
resources impact assessment of a
proposed pipeline route.

Shell Canada continued its successful deployment of applications and business processes where the speed and reach of the Internet could improve efficiency and cost-effectiveness while enhancing communication with customers, suppliers, partners, government and employees.

e-Business applications implemented in 2002 include:

n   a portal that provides a single information window for all Oil Sands locations, joint venture owners and business associates;
n   the sale of lubricants and bulk fuels on-line to Oil Products commercial customers;
n   on-line reporting of Resources production volumes to the Petroleum Registry of Alberta; and
n   a customer portal for on-line ordering, tracking, invoicing and reporting of Resources natural gas liquids.

In support of Shell Canada’s commitment to the social dimension of sustainable development, the Company donated a total of $7.3 million to not-for-profit organizations across Canada. The funds supported environmental and educational programs as well as local communities where employees, retirees and marketing associates live and work.

For example, in 2002 Shell pledged more than $1.3 million to post-secondary education over a three-year period. One such pledge of $100,000 was to the Lambton College Targets Excellence in Education campaign. Campaign funds will be used to upgrade and renovate the college to ensure it remains a leader in education in the Sarnia-Lambton area of Ontario. The college will apply Shell’s donation to the area of chemical production technology. In addition to financial support, Shell’s Sarnia Manufacturing Centre continues to provide cooperative education opportunities for Lambton College students.




42 Shell Canada Limited  n  Corporate

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Combining protection of biodiversity with a 2002 summer employment program for university and college students, Shell Canada partnered with the Nature Conservancy of Canada (NCC) in a new initiative called the Shell Conservation Internship program. Through this program, the NCC hired 16 students of environmental sciences at universities and colleges across Canada to conduct stewardship work on its properties. At the end of their work term, the students joined Shell executives and staff for a two-day workshop on conservation, sustainable development, and renewable energy and fossil fuels.

The 12-year-old Shell Environmental Fund (SEF) continued to support innovative environmental projects in 2002. Since its inception in 1990, the SEF has granted $9.4 million to more than 3,400 community projects, such as habitat restoration, energy conservation, waste reduction, recycling, trail building and educational initiatives.


Meherzad Romer is a student who
took part in the Shell Conservation
Internship Program.

individual frogs from existing breeding populations in southern Alberta to other areas. And in Ontario, the Uxbridge Public School purchased a small demonstration solar- and wind-powered electric system with funds from an SEF grant. The system enabled conversion of an unused portable classroom into a science laboratory and greenhouse, which was opened in September 2002.


The Company matched the money raised by employees and retirees for donations totalling $2.6 million

In 2002, one SEF grant to the Alberta Conservation Association of Caroline, Alberta, helped to reintroduce the northern leopard frog into areas from which it has disappeared. Once found throughout central and southern Alberta, this species of amphibian is officially designated “threatened” under Alberta’s Wildlife Act. Employees from Shell’s Caroline complex near Sundre helped to move

The Shell Community Service Fund (CSF) continues to support the growing volunteer efforts of the Company’s employees, retirees and marketing partners. In 2002, the CSF awarded $430,000 to more than 300 community organizations with which Shell people volunteer.

Shell Canada again conducted United Way campaigns across the country. The Company matched the money raised by employees and retirees for donations totalling $2.6 million. The Calgary and area campaign broke Shell’s 2001 record with a donation of just over $2 million and included 278 Leaders of the Way, who contributed $1,000 or more. Approximately 930 volunteers gave 4,700 hours to support United Way agencies in their communities through Days of Caring.




Corporate  n  Shell Canada Limited 43

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Shell Canada’s commitment to building a positive reputation based on sustainable development and a framework of ethical business principles helps the Company to attract and retain motivated and highly skilled employees. Shell actively encourages all its employees to embrace diversity and, in 2002, published its first annual diversity report. Shell also fosters mutual respect and strives to treat people fairly on the basis of merit. The Company’s Ombuds office is a valuable resource in support of these efforts.

Another important goal is to train, develop and reward employees appropriately. Shell provides a wide variety of local, in-house opportunities for training and development, including world-class technical and leadership development programs through the Royal Dutch/Shell Group of Companies. Employees are encouraged to manage their careers using a career development system, which includes coaching, career and skills discussions, and open job posting.


Marty Ouellette is a rotating
craft mechanic at Shell’s
Waterton Complex.



The annual employee survey, which incorporates upward appraisal, helps to identify employee concerns. It provides management the opportunity to continuously improve the work environment. Employee participation in the annual survey increased again from 77 per cent response rate in 2001 to 82 per cent in 2002. Overall survey results also showed improvement; in 2002, 77 per cent of employees gave the Company a “favourable” score, up one percentage point from 2001. The survey results are benchmarked against other companies both within and outside the oil and gas industry.

Selected from 47,000 organizations, Shell Canada will appear in Canada’s Top 100 Employers for the third consecutive year. And, for the first time, a national business magazine has placed Shell among the 50 Best Companies to Work For in Canada.

A company-wide performance management system aligns individual activities with the overall corporate direction. Employees share in the Company’s success through a results pay system based on a scorecard. The scorecard covers a range of financial performance measures, including competitive ranking. It also includes Shell’s relationship with its customers and overall reputation as well as health, safety, environment and sustainable development. In addition, management compensation is now linked to specific objectives relating to the attraction and retention of employees. By the end of 2002, 1,410 employees, or more than 35 per cent of the workforce, were participating in the Employee Share Purchase Plan introduced in 2001 as an additional incentive for employees to become involved in the fortunes of the Company.

The Company regularly reviews and improves its leadership succession and development planning processes. The senior management team takes steps to equip tomorrow’s leaders with the skills and experience necessary for them to meet future business challenges.




44 Shell Canada Limited  n  Corporate

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To the Shareholders of Shell Canada Limited

The management of Shell Canada Limited is responsible for the preparation of all information included in this Annual Report. The consolidated financial statements have been prepared in accordance with generally accepted accounting principles and necessarily include amounts based on management’s informed judgments and estimates. Financial information included elsewhere in this Annual Report is consistent with the consolidated financial statements.

To assist management in fulfilling its responsibilities, a system of internal accounting controls has been established to provide reasonable assurance that the consolidated financial statements are accurate and reliable and that assets are safeguarded. Management believes that this system of internal control has operated effectively for the year ended December 31, 2002.

PricewaterhouseCoopers LLP, Chartered Accountants, appointed by the shareholders, have audited the financial statements and conducted a review of internal accounting policies and procedures to the extent required by generally accepted auditing standards and performed such tests as they deemed necessary to enable them to express an opinion on the consolidated financial statements.

The Board of Directors, through its Audit Committee, is responsible for ensuring that management fulfills its financial reporting responsibilities. The Audit Committee is composed of independent directors who are not employees of the Corporation. The committee reviews the financial content of the Annual Report and meets regularly with management, internal audit and PricewaterhouseCoopers LLP to discuss internal controls, accounting, auditing and financial matters. The committee recommends the appointment of the external auditors. The committee reports its findings to the Board of Directors for its consideration in approving the consolidated financial statements for issuance to the shareholders.


(-s- Timothy W. Faithfull)
Timothy W. Faithfull
President and Chief Executive Officer
  (-s- Steinar Støtvig)
Steinar Støtvig
Chief Financial Officer
  (-s- Matthew B. Haney)
Matthew B. Haney

January 31, 2003







Management’s Report  n  Shell Canada Limited 45

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To the Shareholders of Shell Canada Limited

We have audited the consolidated balance sheets of Shell Canada Limited as at December 31, 2002, 2001 and 2000 and the consolidated statements of earnings and retained earnings and cash flows for each of the years in the three-year period ended December 31, 2002. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance that 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, 2002, 2001 and 2000 and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2002, in accordance with Canadian generally accepted accounting principles.


(-s- PricewaterhouseCoopers)
Chartered Accountants
Calgary, Alberta

January 31, 2003






46 Shell Canada Limited  n  Auditor’s Report

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Year ended December 31 ($ millions)     2002       2001       2000       1999       1998  

                    (restated)   (restated)   (restated)  
Sales and other operating revenues
    7 232       7 658       8 100       5 286       4 449  
Dividends, interest and other income
    82       72       89       93       57  

Total revenues
    7 314       7 730       8 189       5 379       4 506  

Purchased crude oil, petroleum products and other merchandise
    4 661       4 627       5 166       3 205       2 372  
Operating, selling and general
    1 222       1 104       1 086       1 053       1 039  
    123       81       42       70       57  
Depreciation, depletion, amortization and retirements
    390       318       366       254       265  
Interest on long-term debt
    19       5       44       49       69  
Other interest and financing charges
    30       12       17       (35 )     57  

Total expenses
    6 445       6 147       6 721       4 596       3 859  

Asset sales and rationalization

Earnings before income tax
    869       1 583       1 468       1 150       647  

Current income tax
    135       472       607       369       165  
Future income tax
    173       101       (2 )     103       52  

Total income tax (Note 4)
    308       573       605       472       217  

    561       1 010       863       678       430  

Per Common Share (dollars) (Note 13)
Earnings — basic
    2.03       3.67       3.06       2.35       1.48  
Earnings — diluted
    2.02       3.65       3.05       2.34       1.48  

Balance at beginning of year
    4 268       3 478       3 357       2 889       2 690  
Implementation of accounting standard (Note 4)
                (61 )            
    561       1 010       863       678       430  

    4 829       4 488       4 159       3 567       3 120  
Common Shares buy-back (Note 3)
                466       2       22  
    221       220       215       208       209  

Balance at end of year
    4 608       4 268       3 478       3 357       2 889  





Consolidated Financial Statements  n  Shell Canada Limited 47

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Year ended December 31 ($ millions)
    2002       2001       2000       1999       1998  
                      (restated)   (restated)   (restated)  
    561       1 010       863       678       430  
    123       81       42       70       57  
Non-cash items
Depreciation, depletion, amortization and retirements
    390       318       366       254       265  
Asset sales and rationalization
                      (367 )      
Current tax related to major property disposal
Future income tax
    173       101       (2 )     103       52  
Other items
    (20 )     (15 )     (14 )     (98 )     41  

Cash flow from operations
    1 227       1 495       1 255       795       845  
Movement in working capital and other from operating activities
    186       178       76       227       (301 )

    1 413       1 673       1 331       1 022       544  

Capital and exploration expenditures
    (2 289 )     (2 027 )     (1 153 )     (715 )     (796 )
Movement in working capital from investing activities
    (67 )     (60 )     188       21       16  

    (2 356 )     (2 087 )   (965 )     (694 )     (780 )
Proceeds on disposal of properties, plant and equipment
    3       59       16       951       253  
Investments, long-term receivables and other
    (87 )     (42 )     (28 )     26       (85 )

    (2 440 )     (2 070 )     (977 )     283       (612 )

Common Shares buy-back (Note 3)
                (490 )     (2 )     (24 )
Proceeds from exercise of Common Share stock options
    10       5       5       4       1  
Dividends paid
    (221 )     (220 )     (215 )     (208 )     (209 )
Long-term debt and other
    804       (377 )     49       (375 )     6  
Short-term financing
    459       212                    

    1 052       (380 )     (651 )     (581 )     (226 )

Increase (decrease) in cash
    25       (777 )     (297 )     724       (294 )
Cash at beginning of year
    (25 )     752       1 049       325       619  
Cash at end of year1
          (25 )     752       1 049       325  

Supplemental disclosure of cash flow information
Dividends received
    15       11       13       46       21  
Interest received
    35       21       50       13       27  
Interest paid
    45       33       43       52       67  
Income tax paid
    285       692       559       162       464  

1Cash comprises cash and highly liquid short-term investments less bank overdraft.




48 Shell Canada Limited  n  Consolidated Financial Statement

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As at December 31 ($ millions)   2002   2001   2000   1999   1998

(restated)   (restated)   (restated)
Current assets
Cash and short-term investments
          (25 )     752       299       325  
Loan to SPCO (Note 10)
Accounts receivable
    497       415       1 119       889       627  
Inventories Crude oil, products and merchandise
    440       473       440       464       545  
Materials and supplies
    75       57       47       49       49  
Prepaid expenses
    93       159       157       121       122  

    1 105       1 079       2 515       2 572       1 668  

Investments, long-term receivables and other
    414       305       255       219       198  
Properties, plant and equipment (Note 2)
    7 836       6 075       4 496       3 783       3 946  

Total assets
    9 355       7 459       7 266       6 574       5 812  

Current liabilities
Short-term borrowings
    671       212                    
Accounts payable and accrued liabilities
    1 223       1 012       1 346       916       656  
Income and other taxes payable
    115       211       404       391       10  
Current portion of site restoration and other long-term obligations
    19       21       20       21       21  
Current portion of long-term debt
    402       2       450       2       367  

    2 430       1 458       2 220       1 330       1 054  
Site restoration and other long-term obligations
(Note 7)
    193       195       205       183       188  
Long-term debt (Note 6)
    523       119       51       448       495  
Future income tax
    1 132       959       857       783       717  

Total liabilities
    4 278       2 731       3 333       2 744       2 454  

Commitments and contingencies (Note 11)

Capital stock (Note 3)
100 4% Preference Shares
    1       1       1       1       1  
275 908 290 Common Shares
(2001 — 275 514 500;2000 — 275 274 286)
    468       459       454       472       468  

    469       460       455       473       469  
Retained earnings
    4 608       4 268       3 478       3 357       2 889  

Total shareholders’ equity
    5 077       4 728       3 933       3 830       3 358  

Total liabilities and shareholders’ equity
    9 355       7 459       7 266       6 574       5 812  

The consolidated financial statements have been approved by the Board of Directors.

(-s- Timothy W. Faithfull)   (-s- Robert T. Stewart)
Timothy W. Faithfull
  Robert T. Stewart

Consolidated Financial Statements  n  Shell Canada Limited 49

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Shell Canada’s consolidated financial statements are prepared in accordance with accounting principles generally accepted in Canada.

The Corporation’s major accounting policies are summarized as follows:



The consolidated financial statements include the accounts of Shell Canada Limited and its subsidiary companies. The financial statements reflect the Corporation’s proportionate interests in joint ventures.


Inventories of crude oil, products and merchandise are stated at the lower of cost, applied on the Last-In, First-Out (LIFO) basis, or net realizable value. Materials and supplies are stated at the lower of cost or estimated useful value.


Investments in companies over which Shell Canada exercises significant influence are accounted for using the equity method. Accordingly, the book value of the investment in such companies equals the original cost of the investment, plus Shell Canada’s share of earnings since the investment date, less dividends received. Other long-term investments are recorded at cost. Short-term investments are carried at the lower of cost or market value and are highly liquid securities with a maturity of three months or less when purchased.


The Corporation follows the successful efforts method of accounting for exploration and development activities. Under this method, acquisition costs of resource properties are capitalized. Exploratory drilling costs are initially capitalized and costs relating to wells subsequently determined to be unsuccessful are charged to earnings. Other exploration costs are charged to earnings. All development costs are capitalized.


Depreciation and depletion on resource and mining assets are provided on the unit-of-production basis. Land and lease costs relating to producing properties and costs of gas plants are depleted and depreciated over remaining proved reserves. Resource and mining development costs are depleted and depreciated over remaining proved developed reserves. A valuation allowance for unproved properties is provided through amortization of costs; the amortization rate is determined in accordance with experience. Costs relating to refinery, upgrader, distribution, marketing and non-resource assets are depreciated on the straight-line basis over each asset’s estimated useful life.


Estimated site restoration costs are provided for on either the unit-of-production or the straight-line basis over the useful life of the related assets. Costs are based on engineering estimates of the anticipated method and extent of site restoration, in accordance with current legislation, industry practices and costs. Provision is being made for site restoration costs that the Corporation expects to incur within the foreseeable future and that can be reasonably estimated.


Interest costs are expensed as incurred.


Revenues are recognized upon delivery. Inter-segment sales, which are accounted for at estimated market-related values, are included in revenues of the segment making the transfer. On consolidation, such inter-segment sales and any associated estimated profits in inventory are eliminated.


All royalty entitlements and mineral taxes are reflected as reductions in sales and other operating revenues.


50 Shell Canada Limited  n  Notes to Consolidated Financial Statements

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The costs of pension and other retirement benefits are actuarially determined using the projected benefit method prorated on service and management’s best estimate of expected plan investment performance, salary escalation, retirement ages of employees and expected health care costs. For the purpose of calculating the expected return on plan assets, those assets are valued at a market-related value. The excess of the net actuarial gain or loss over 10 per cent of the greater of the benefit obligation and the market-related value of plan assets is amortized over the average remaining service period of active employees.


Monetary items are translated to Canadian dollars at rates of exchange in effect at the end of the period. The gains and losses on the translation of foreign denominated monetary items are charged to earnings.


Financial instruments including cash, marketable securities and short-term borrowings are recorded at historical cost.


The Company uses derivative instruments in the management of its foreign currency, interest rate and commodity price exposures. The Company does not use derivative instruments for speculative purposes.

Foreign exchange contracts are used to hedge certain foreign purchases and sales. Those foreign transactions are recorded in the financial statements in Canadian dollars at the rate specified in the forward contract. Exchange gains and losses on the contracts offset the gains and losses on the initial transaction.

Interest rate swaps are used to manage interest rate exposure. Differentials under interest rate swap arrangements are recognized by adjustments to interest expense.

Energy futures are used to reduce exposure to price fluctuations in some contractual energy purchases and sales. Any gain or loss on these transactions is applied to the cost of the products purchased or sold.


     The Corporation has a stock-based compensation plan, which is described in Note 3. No compensation expense is recognized for this plan when stock or stock options are issued to employees. Any consideration paid by employees on exercise of stock options or purchase of stock is credited to share capital.


The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Significant estimates used in the preparation of these financial statements include the estimate of proved oil and gas reserves, site restoration and employee future benefits.


Effective January 1, 2002, the Corporation adopted the new Canadian accounting standard for foreign currency translation, which eliminates the deferral and amortization of translation gains and losses. The new standard has been applied retroactively and financial statements of prior periods have been restated. The impact on 2002 earnings was nil (2001 — nil; 2000 — $5 million increase). Opening retained earnings for 2000 were decreased by $5 million.


Certain information provided for prior years has been reclassified to conform to the current presentation.

Notes to Consolidated Financial Statements  n  Shell Canada Limited 51

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The operating segments are those adopted by senior management of the Corporation to determine resource allocations and assess performance. In all material respects, the segmented information is applied consistently in accordance with the Corporation’s significant accounting policies. The Corporation’s revenues are attributed principally to Canada where all of its major properties, plants and equipment are located.

Segmented financial results and properties, plant and equipment data are reported as if the segments were separate entities.

EARNINGS ($ millions)

      TOTAL                        RESOURCES  
2002     2001   2000             2002     2001   2000

867     1 260     988     Natural gas   867     1 260     988  
530     619     757     Natural gas liquids   530     619     757  
77     36     42     Crude oil and bitumen   74     36     42  
(234 )     (371 )     (337 )   Royalties   (234 )     (371 )     (337 )
2 848     2 885     3 025     Gasolines                
1 984     2 157     2 434     Middle distillates                
921     858     1 018     Other products   26       (6 )     76  
321     286     262     Other revenues   39     40     5  
            Inter-segment sales   82     67     69  

7 314     7 730     8 189     Total revenues   1 384     1 645     1 600  

            Purchased crude oil, petroleum            
4 661     4 627     5 166       products and other merchandise            
            Inter-segment purchases   104     143     151  
1 222     1 104     1 086     Operating, selling and general   324     277     275  
123     81     42     Exploration   123     81     42  
            Depreciation, depletion, amortization            
390     318     366       and retirements   224     172     189  
19     5     44     Interest on long-term debt            
30     12     17     Other interest and financing charges            

6 445     6 147     6 721     Total expenses   775     673     657  

869     1 583     1 468     Earnings (loss) before income tax   609     972     943  

135     472     607     Current income tax   215     409     362  
173     101     (2 )   Future income tax   7     (37 )   45  

308     573     605   Total income tax   222     372   407  

561     1 010     863   Earnings (loss)   387       536  



52 Shell Canada Limited  n  Notes to Consolidated Financial Statements

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The Corporation has the following segments:

Resources includes exploration, production and marketing activities for natural gas, natural gas liquids, bitumen, crude oil and sulphur.

Oil Sands includes mining and extraction of bitumen, upgrading of bitumen to synthetic crude oils and marketing of products.

Oil Products includes the manufacturing, distribution and selling of the Corporation’s refined petroleum products.

Corporate includes controllership, financing, administration and general corporate facility management.

2002   2001   2000   2002   2001   2000   2002   2001   2000

2 848
      2 885       3 025    
1 984
      2 157       2 434    
      864       942    
      191       188    
      55       69  
      143       151    

6 071
      6 240       6 740    
      55       69  

4 665
      4 627       5 166    
      67       69    
      803       783    
      24       28  
      148       176    
      (2 )     1  
      5       44  
      12       17  

5 779
      5 645       6 194    
      39       90  

      595       546    
)     16       (21 )

)     (33 )     (6 )  
      95       269    
)     1       (18 )
      33       6    
)     99       (63 )  
      6       10  

      194       206    
)     7       (8 )

      401       340    
)     9       (13 )



Notes to Consolidated Financial Statements   n  Shell Canada Limited 53

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n    2.  SEGMENTED INFORMATION (continued)

CASH FLOW ($ millions)

    TOTAL             RESOURCES
2002   2001   2000         2002   2001   2000

1 227     1 495   1 255   Cash flow from operations   740   812     808  
    Movement in working capital and                        
186     178   76       other from operating activities   (33 ) (99 )   (206 )

1 413     1 673   1 331   Cash from operating activities   707 713   602

(2 289 )   (2 027 ) (1 153 ) Capital and exploration expenditures   (389 ) (366 )   (254 )
    Movement in working capital                      
(67 )   (60 ) 188     from investing activities   (7 ) 30   37

(2 356 )   (2 087 ) (965 )   (396 ) (336 )   (217 )
(84 )   17 (12 ) Other cash invested   (19 ) 35   7
1 052   (380 ) (651 ) Cash from financing activities   (3 ) 1   4

25   (777 ) (297 ) Increase (decrease) in cash   289 413   396

CAPITAL EMPLOYED ($ millions except as noted)

    TOTAL             RESOURCES
2002   2001   2000         2002   2001   2000

12 382     10 289   8 478   Properties, plant and equipment at cost   4 405   4 153     3 954  
    Accumulated depreciation, depletion                      
4 546     4 214   3 982       and amortization   2 226   2 015     1 893  

7 836     6 075   4 496   Net properties, plant and equipment   2 179   2 138     2 061  
(1 162 )   (1 014 ) (63 ) Other assets less other liabilities   (454 ) (542 )   (653 )

6 674   5 061 4 433 Capital employed   1 725 1 596   1 408

    Return on average capital                      
10.1   21.5 20.4 employed (%) 1   23.3 39.9   38.7

1Return on average capital employed (ROACE) is earnings plus after-tax interest expense divided by the average of opening and closing capital employed for the 12 months to December 31. Capital employed is a total of equity, long-term debt and short-term borrowings.



54 Shell Canada Limited  n  Notes to Consolidated Financial Statements

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2002   2001   2000   2002   2001   2000   2002   2001   2000


      33       6    
      637       429    
)     13       12  
      165       (60 )  
    112       342  

    33       6    
      802       369  
    125       354  

(1 460
)     (1 313 )     (606 )  
)     (343 )     (279 )  
)     (5 )     (14 )
)     (66 )     151  
)     (24 )      

(1 498
)     (1 379 )     (455 )  
)     (367 )     (279 )  
)     (5 )     (14 )
)     (4 )     14  
)     (6 )     22  
    (8 )     (55 )
    3     2  
    3     11  
1 047
    (387 )     (668 )

(1 512
)     (1 347 )     (433 )  
    432     123  
1 172
    (275 )     (383 )


2002   2001   2000   2002   2001   2000   2002   2001   2000

3 520
    2 083     770  
4 363
    3 963     3 656  
    90     98
2 255
    2 137     2 025  
    62     64

3 518
    2 083     770  
2 108
    1 826     1 631  
    28     34
)     (172 )     (206 )  
)     (37 )     187  
)     (263 )     609
)     (172 )     (206 )  
)     (37 )     187  
)     (263 )     609

3 380
      1 411       564    
1 913
      1 789       1 818  
)     (235 )     643

    22.2     19.6  


Notes to Consolidated Financial Statements   n  Shell Canada Limited 55

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Shell Canada Limited carries on business under the Canada Business Corporations Act. Common Shares are without nominal or par value and are authorized in unlimited number.

The holder of the four per cent Preference Shares receives fixed, cumulative dividends of $40,000 per annum. The Preference Shares may be redeemed at the amount paid up thereon plus accrued dividends.

Under the Long-Term Incentive Plan, the Company may grant options to executives and other employees. The exercise price of each option equals the market price of the Company’s stock on the date of grant and the maximum term of an option is 10 years. Options may not be exercised during the one-year period following the date of grant, after which time one-third of the options may be exercised in each of the next three years on a cumulative basis. For executives, 50 per cent of the options are based on the Company’s Total Shareholder Return (TSR). For the option to vest, the TSR must exceed the average TSR of the Corporation’s comparator group at the end of the three-year period after being granted. If the Corporation’s TSR does not meet the target, the Long-Term Incentive Subcommittee may determine, in its sole discretion, that all or a portion of the options granted shall vest. If the options vest, they must be exercised within seven years of the date of vesting.

At December 31, 2002, the Company had 8,746,667 shares reserved to meet outstanding options for the purchase of Common Shares.

Effective January 1, 2002, the Corporation adopted the new Canadian accounting standard for stock-based compensation plans. The new standard has been applied prospectively and the financial statements have not been restated. No expense related to the stock compensation plan is included in earnings.

In 2002, the Company granted 1,567,000 options with an exercise price of $44.70. The fair value of the options granted in 2002 was estimated using the Black-Scholes model with the following assumptions: risk-free interest rate of 5.42 per cent, expected life of five years, volatility of 22.1 per cent and a dividend yield of 1.9 per cent.

Had the Company included the effects of stock-based compensation in earnings for 2002, after-tax earnings and basic earnings per share would have decreased by $8 million to $553 million or by $0.03 to $2.00, respectively. No effect was included for awards granted prior to January 1, 2002.

On May 10, 2000, the Company initiated a normal course issuer bid for up to five per cent of its outstanding Common Shares. The bid was terminated on September 18, 2000, at which time 14,358,509 shares, five per cent, had been repurchased at an average price of $34.02, for a total cost of $489 million. Shell Investments Limited (SIL), a related company as described on page 77 of this report, owns approximately 78 per cent of the outstanding Common Shares of Shell Canada Limited, and participated in the share purchase program. SIL sold 11,199,552 Shell Canada Limited Common Shares, maintaining its existing ownership interest.

An earlier normal course issuer bid, which commenced August 17, 1999, was terminated May 4, 2000, concurrent with the announcement of the May 10, 2000 bid. Under the terminated bid, Shell purchased 110,100 shares at an average price of $29.78, for a total cost of $3 million, which includes $1 million of shares purchased in 2000.

COMMON SHARES   2002   2001   2000

      Shares     Dollars     Shares     Dollars     Shares     Dollars  

Balance at the beginning of the year
    275 514 500       458 793 830       275 274 286       453 599 996       289 377 839       472 170 047  
Activity during the year
Options exercised
    393 790       8 972 144       240 214       5 193 834       287 056       5 015 731  
Normal course issuer bid
                            (14 390 609 )     (23 585 782 )

Balance at year-end
    275 908 290       467 765 974       275 514 500       458 793 830       275 274 286       453 599 996  


56 Shell Canada Limited  n  Notes to Consolidated Financial Statements

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A summary of the status of the Company’s stock option plans as at December 31, 2002, 2001 and 2000, and changes during the years ending on those dates is presented below:

STOCK OPTIONS   2002   2001   2000

            Weighted           Weighted           Weighted
            Average           Average           Average
    Options   Exercise Price   Options   Exercise Price   Options   Exercise Price
    (thousands)   (dollars)   (thousands)   (dollars)   (thousands)   (dollars)

Outstanding at the beginning of the year
    3 616       28.48       2 560       23.71       2 059       19.95  
    1 567       44.70       1 311       36.50       801       31.20  
    (394 )     22.78       (240 )     21.61       (287 )     17.47  
    (12 )     39.73       (15 )     32.01       (13 )     26.53  

Outstanding at year-end
    4 777       34.22       3 616       28.48       2 560       23.71  

Options exercisable at year-end
    1 958               1 587               1 114          

Stock options outstanding at December 31, 2002:

    Options Outstanding   Options Exercisable

            Average   Weighted           Weighted
            Remaining   Average           Average
    Number   Contractual   Exercise Price   Number   Exercise Price
Exercise Price   Outstanding   Life (years)   (dollars)   Exercisable   (dollars)

$10 to $18
    351 750       3.2       15.52       351 750       15.52  
$18 to $26
    889 036       5.6       22.54       889 036       22.54  
$26 to $34
    734 766       7.1       31.20       371 605       31.20  
$34 to $45
    2 801 411       8.6       41.07       345 779       36.50  

$10 to $45
    4 776 963       7.4       34.22       1 958 170       25.39  


Notes to Consolidated Financial Statements   n  Shell Canada Limited 57

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The income tax provisions included in the determination of earnings are developed by applying Canadian federal and provincial statutory tax rates to pretax earnings, with adjustments as set out in the table below.

Effective January 1, 2000, the Company adopted the new Canadian accounting standard for income taxes. The Corporation adopted this standard retroactively without restating financial statements for prior periods. The effect, on the balance sheet, of the new recommendation was to increase the future income tax liability and decrease retained earnings by $61 million. The effect on net income for the period ended December 31, 2000, is not material.

The future income tax liability is substantially all related to the excess carrying value of property, plant, and equipment over the associated tax basis.

The Corporation has $165 million in capital losses for which no future income tax benefit has been recognized.

($ millions except as noted)   2002   2001   2000

Earnings before income tax
    869       1 583       1 468  
Basic corporate tax rate (%)
    40.8       42.2       43.9  

Income tax at basic rate
    355       667       644  

Increase (decrease) resulting from:
Crown royalties and other payments to provinces
    83       132       123  
Resource allowance and other abatement measures
    (99 )     (146 )     (137 )
Manufacturing and processing credit
    (14 )     (30 )     (32 )
Changes in income tax rates
    (17 )     (33 )      
Other, including revisions in previous tax estimates
          (17 )     7  

    308       573       605  



The following amounts were included in the determination of earnings:
($ millions)   2002   2001   2000

Items reported separately:
Income tax
    308       573       605  
Items included in sales and other operating revenues and in operating, selling and general expenses:
Crown royalties and mineral taxes
    193       303       274  
Royalties paid to private leaseholders
    41       68       63  
Other taxes
    51       49       53  
Research and development expense
    6       5       7  

    599       998       1 002  


58 Shell Canada Limited  n   Notes to Consolidated Financial Statements

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($ millions)   Issued     Maturity     2002     2001     2000  

8 7/8% ($300 US)
            2001                   448  
Medium-Term Notes
Floating rate note1
  Feb 14, 2002     Dec 15, 2003       250              
Floating rate note1
  Mar 22, 2002     Mar 15, 2004       140              
Floating rate note
  Mar 22, 2002     Jun 15, 2004       105              
Floating rate note1
  Sep 24, 2002     Sep 24, 2003       150              
Floating rate note
  Sep 24, 2002     Sep 24, 2004       100              
Capital leases
          varying dates       180       121       53  

                    925       121       501  
Included in current liabilities
                    (402 )     (2 )     (450 )

                    523       119       51  

1 These floating rate note issues may be extended, at the holder’s option, for an additional one-year term.

Under the Medium-Term Note (MTN) Shelf Prospectus filed in December 2001, the Corporation issued five tranches of floating rate notes. In the first quarter of 2002, three tranches of floating rate notes totalling $495 million were issued. On August 9, 2002, the short-form MTN Shelf Prospectus was amended, increasing the aggregate principal amount of unsecured medium-term notes that may be offered under the Prospectus from $500 million to $1 billion. Subsequent to the amendment in the third quarter of 2002, two additional tranches totalling $250 million of floating rate notes were issued. Interest on the floating rate notes is paid quarterly at rates that range from 10 to 17 basis points above the three-month Canadian Dollar Offer Rate.

Capital leases include $175 million of incurred costs related to the hydrogen manufacturing unit, which will be used in connection with the Athabasca Oil Sands Project.

Repayments of obligations necessary during the next five years are as follows:

$402 million in 2003
$347 million in 2004
$1 million in 2005
$1 million in 2006
$1 million in 2007


($ millions)   2002     2001     2000  

Site restoration1
    66       68       78  
Other employee future benefits
    121       113       105  
Other obligations
    25       35       42  

    212       216       225  
Included in current liabilities
    (19 )     (21 )     (20 )

    193       195       205  

1 Site restoration expenditures for 2002 were $8 million (2001 — $16 million; 2000 — $11 million).



Notes to Consolidated Financial Statements  n  Shell Canada Limited 59

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    Notional Fair Value1   Unrealized Gain (Loss) 2
($ millions)   2002   2001   2000   2002   2001   2000

Commodity contracts
    80       20       278       1       (19 )     (59 )
Foreign exchange contracts
    11       44       475             1       2  


    Notional Fair Value1   Carrying Value
($ millions)   2002     2001     2000     2002     2001     2000  

Interest rate swaps
Long-term debt3
    745             510       745             500  


1 Notional fair value is the product of the contract volume and the mark-to-market forward price. Purchase and sales positions have not been offset. Amounts disclosed represent the sum of the absolute values of the positions. The reported amounts of financial instruments such as cash equivalents, marketable securities and short-term debt approximate fair value.
2 Unrealized gain or loss represents the gain or loss the Corporation would incur if the contract was liquidated at December 31.
3 Long-term debt includes the current portion.

The Corporation uses commodity contracts to reduce the risk of price fluctuations of some commodities. Over-the-counter contracts with terms generally no longer than one year are used. At December 31, commodity contracts outstanding were:

    2002     2001     2000  

($ millions except as noted)   Face Value     Volume4     Face Value     Volume4     Face Value     Volume4  

Crude oil and refined products commitments
    79       1 683       6       294       5       164  
Natural gas commitments
                            116       18  
Electricity commitments
          3       33       356       65       711  


4 Crude oil and refined product volumes are expressed as thousands of barrels, natural gas volumes as billions of cubic feet and electricity is denoted in thousands of megawatt hours.

A portion of the Corporation’s cash flow is in U.S. dollars. The U.S. dollar receipts are less than U.S. dollar disbursements primarily due to the cost of foreign crude cargoes exceeding U.S. dollar-denominated product sales. The resulting net shortage of U.S. dollars is funded through U.S. dollar spot, forward and swap contracts. These instruments generally mature in less than 30 days. U.S. dollar requirements for significant capital projects and some marketing transactions are funded through forward contracts with maturities generally of less than one year.

Non-performance by the other parties to the financial instruments exposes the Corporation to credit loss. The counterparties are domestic and international banks and corporations, all with credit ratings of “A” or better. There is no significant concentration of credit risk and Shell does not anticipate non-performance by the counterparties.



60 Shell Canada Limited  n  Notes to Consolidated Financial Statements

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Employees initially participate in the defined contribution segment of the Corporation’s pension plan. After meeting certain service requirements, employees can elect to participate in the defined benefit segment of the pension plan. Benefits from this segment are Company-paid and are based on years of service and final average earnings. In addition to the pension plan, life insurance and supplementary health and dental coverage benefits are provided to retirees.
ACCRUED BENEFIT OBLIGATION ($ millions)   2002   2001   2000

    Pension   Other   Pension   Other   Pension   Other
    Benefit   Benefit   Benefit   Benefit   Benefit   Benefit
    Plans   Plans   Plans   Plans   Plans   Plans

Accrued benefit obligation as at January 1
    1 730       150       1 548       135       1 416       132  
Current service cost
    27       2       24       2       22       1  
Interest cost
    112       10       98       9       101       9  
Actuarial loss
    58       1       74       (3 )     127       (1 )
Benefits paid
    (123 )     (7 )     (120 )     (7 )     (118 )     (6 )
Change in assumption
    5       7       106       14              

Accrued benefit obligation as at December 31
    1 809       163       1 730       150       1 548       135  

Included in the above are unfunded obligations for the supplemental pension plan of $105 million (2001 – $92 million; 2000 – $68 million) and $30 million (2001 – $32 million; 2000 – $33 million) for the spousal pension plan.

PLAN ASSETS ($ millions)   2002   2001   2000

Plan assets as at January 1
    1 786             1 944             1 907        
Actual return on plan assets
    (67 )           (49 )           139        
Employer contributions
    33       7       8       7       7       6  
Employee contributions
    2             2             2        
    22             5             14        
Benefits paid
    (123 )     (7 )     (120 )     (7 )     (118 )     (6 )
    (5 )           (4 )           (7 )      

Fair value as at December 31
    1 648             1 786             1 944        

Funded status – surplus (deficit)
    (161 )     (163 )     56       (150 )     396       (135 )
Unamortized net (gain) losses
    710       15       474       16       114       (1 )
Unamortized transitional (asset) obligation1
    (215 )     27       (251 )     30       (287 )     33  

Accrued benefit asset (obligation)
    334       (121 )     279       (104 )     223       (103 )

1 Unrecorded assets are amortized over the expected average remaining service life of employees, which is currently nine years (2001 – nine years;2000 – nine years).


Notes to Consolidated Financial Statements  n  Shell Canada Limited 61


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(INCOME) EXPENSE  ($ millions)   2002   2001   2000

    Pension   Other   Pension   Other   Pension   Other
    Benefit   Benefit   Benefit   Benefit   Benefit   Benefit
    Plans   Plans   Plans   Plans   Plans   Plans

Current service cost
    27       2       24       2       22       2  
Employee contributions
    (2 )           (2 )           (2 )      
Interest cost
    112       10       98       9       101       9  
Expected return on plan assets
    (145 )           (143 )           (132 )      
Amortization of transitional (asset) obligation
    (36 )     3       (36 )     3       (36 )     3  
Amortization of net actuarial loss

Net (income) expense for plans
    (28 )     15       (59 )     14       (47 )     14  
Defined contribution plan
    11             10                    

    (17 )     15       (49 )     14       (47 )     14  

ASSUMPTIONS  (per cent)   2002   2001   2000

Discount rate
    6.6       6.6       6.6       6.6       6.5       6.5  
Long-term rate of return on plan assets
    8.0             8.0             7.5        
Rate of compensation growth
    3.1       3.1       3.5       3.5       3.0       3.0  

For the purpose of measuring the expected cost of other benefit plans, a 10 per cent annual rate of increase in the per-capita cost of covered health care benefits was assumed for 2002, decreasing each year to a rate of four per cent in 2007 and thereafter.


Shell Canada, in the course of its regular business activities, has routine transactions with affiliates. Such transactions are at commercial rates. The following transactions occurred with Shell International Trading Company and other affiliates of the Royal Dutch/Shell Group of Companies as at December 31:
($ millions)   2002   2001   2000

Purchases of crude oil, petroleum products and chemicals
    1 854       1 802       2 032  
Amounts payable in respect of such purchases
    220       84       141  
Sale of natural gas, petroleum products and chemicals
    1 154       1 400       1 308  
Amounts receivable in respect of such sales
    133       99       200  

The only material product purchase is crude oil, which comprises 94 per cent of total affiliated company purchases.

In December 2002, Shell Canada completed a non-recurring transaction with Shell Global Solutions International B.V. regarding the global Oil Products manufacturing cost sharing agreement. This transaction resulted in a $19 million after-tax gain.

Shell Investments Limited (SIL) is a wholly owned subsidiary of the Royal Dutch/Shell Group of Companies and owns about 78 per cent of the outstanding Common Shares of Shell Canada Limited. SIL participated in the share purchase program announced May 10, 2000, as outlined in Note 3.

In December 1999, the Corporation entered into a loan agreement with The Shell Petroleum Company, a wholly owned subsidiary of the Corporation’s ultimate parents, under which it advanced $750 million Cdn at competitive Canadian short-term interest rates as part of its cash management activities. The loan matured in February 2000.


62 Shell Canada Limited  n   Notes to Consolidated Financial Statements


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At December 31, 2002, the Corporation had non-cancellable operating and other long-term commitments with an initial or remaining term of one year or more. Future minimum payments under such commitments are estimated to be:
    Operating   Other Long-Term
($ millions)   Commitments1   Commitments2

    46       629  
    47       502  
    44       455  
    39       426  
    40       422  
    195       6 539 3

1   These operating commitments cover leases of service stations, mine equipment, office space and other facilities.
2   The Corporation has substantial commitments for use of facilities or services and supply and processing of products, all made in the normal course of business.
3   Includes an Oil Products commitment to purchase $4 billion of certain feedstocks from the Athabasca Oil Sands Project (AOSP) joint venture participants, $1.3 billion for pipeline charges and $1.2 billion of AOSP utilities and hydrogen commitments.

The Corporation has a leasing arrangement for large mobile equipment (trucks, scrapers and shovels) in use at the Muskeg River Mine. A guarantee has been provided to the lessor in order to secure attractive leasing terms and is payable when the equipment is returned to the lessor. At December 31, 2002, the Corporation’s share of the maximum payable under the guarantee was $65 million. However, any proceeds received from the sale of the equipment would offset any payment required under the guarantee. The guarantee is in place for the equipment lease term, which will continue for the next two to seven years.

As part of an aircraft leasing arrangement, the Corporation has provided a residual value guarantee to the lessor, which is payable when the aircraft is returned. The maximum amount payable under the guarantee at December 31, 2002, was $15 million. However, proceeds from the sale of the aircraft would offset any payment required under the guarantee. The guarantee is in place for the duration of the lease term, which continues for another 15 months.

The Corporation has been served with a motion to commence a class action suit regarding the Company’s pension plan. The claim challenges the Corporation’s right to take contribution holidays on the defined benefit segment when the plan is in a surplus position. The claim demands that Shell contribute approximately $100 million to the pension plan. The likelihood and amount of the eventual settlement is not determinable at this time.

Other lawsuits are pending against the Corporation. Actual liability with respect to these lawsuits is not determinable, but management believes, based on counsels’ opinions, that any potential liability will not materially affect the Corporation’s financial position.


Notes to Consolidated Financial Statements  n  Shell Canada Limited 63


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In 2000, the Board of Directors approved a $350 million accounts receivable securitization program. Under this program, the Corporation sold $200 million of receivables in 2000 and $150 million of receivables in 2001. In 2002, the Board of Directors approved a $250 million increase to the program. During the year the Corporation increased sales by $170 million, bringing the total amount sold under the program to $520 million.

The Corporation has not retained any beneficial ownership interest in the sold assets and received proceeds that approximated their fair value. The assets were sold on a fully serviced basis and, as such, the Corporation has not estimated the fair value of the servicing liability.


Effective January 1, 2001, a new accounting standard related to the calculation and disclosure of earnings per share was established. The effect of this change was not material.
    2002   2001   2000

Earnings ($ millions)
    561       1 010       863  
Weighted average number of Common Shares (millions)
    276       275       282  
Dilutive securities (millions) Options on long-term incentive plan1
    2       2       1  
Basic earnings per share ($  per share)2
    2.03       3.67       3.06  
Diluted earnings per share ($  per share)3
    2.02       3.65       3.05  
1   The amount shown is the net number of Common Shares outstanding after the notional exercise of the share options and the cancellation of the notionally repurchased Common Shares as per the treasury stock method.
2   Basic earnings per share is the earnings divided by the weighted average number of Common Shares.
3   Diluted earnings per share is the earnings divided by the aggregate of the weighted average number of Common Shares plus the dilutive securities.


64 Shell Canada Limited  n   Notes to Consolidated Financial Statements

Table of Contents


Year ended December 31 (unaudited)

  PRODUCTION (thousands of cubic metres/day)   2002     2001     2000     1999     1998  

Crude oil processed by Shell refineries
Montreal East (Quebec)
    17.9       18.2       18.6       17.0       18.0  
Sarnia (Ontario)
    10.1       10.6       10.0       9.9       9.7  
Scotford (Alberta)
    13.4       14.9       14.5       14.9       14.1  

    41.4       43.7       43.1       41.8       41.8  

Rated refinery capacity at year-end
Montreal East (Quebec)
    20.7       20.7       20.7       20.7       20.6  
Sarnia (Ontario)
    11.4       11.4       11.4       11.4       11.4  
Scotford (Alberta)
    15.5       15.5       15.3       15.3       15.0  

    47.6       47.6       47.4       47.4       47.0  


  SALES (thousands of cubic metres/day)   2002   2001   2000   1999   1998

    20.8       20.8       20.6       20.8       20.6  
Middle distillates
    16.7       16.6       17.6       17.1       17.0  
Other products
    6.9       7.5       7.2       7.1       7.4  

    44.4       44.9       45.4       45.0       45.0  













Supplemental Oil Products Disclosure  n  Shell Canada Limited 65

Table of Contents


Year ended December 31 (unaudited)


   PRODUCTION   2002   2001   2000   1999   1998

Natural gas (millions of cubic feet/day)
    610       614       593       562       587  
    474       498       482       473       463  
Ethane, propane and butane (thousands of barrels/day)
    27.9       28.8       30.2       30.4       30.8  
    21.1       22.5       23.9       25.3       26.8  
Condensate (thousands of barrels/day)
    19.7       22.3       23.2       23.6       24.9  
    13.9       17.2       17.7       18.7       20.2  
Bitumen (thousands of barrels/day)
    8.9       4.5       4.2       6.1       7.2  
    8.7       4.4       4.0       5.7       6.9  
Crude oil (thousands of barrels/day)
                      13.6       15.7  
                      11.1       13.5  
Sulphur (thousands of long tons/day)
    6.1       6.1       6.5       6.6       6.6  

  Gross production includes all production attributable to Shell’s interest before deduction of royalties; net production is determined by deducting royalties from gross production.
  SALES   2002   2001   2000   1999   1998

Natural gas – gross (millions of cubic feet/day)
    598       608       585       552       593  
Ethane, propane and butane – gross (thousands of barrels/day)
    47.7       48.1       54.2       53.5       64.2  
Condensate – gross (thousands of barrels/day)
    26.4       28.7       31.5       34.5       36.3  
Bitumen – gross (thousands of barrels/day)
    13.1       6.8       6.6       9.1       11.1  
Crude oil – gross (thousands of barrels/day)
                      13.4       14.1  
Sulphur – gross (thousands of long tons/day)
    9.5       8.2       9.1       9.3       8.0  

  PRICES   2002   2001   2000   1999   1998

Natural gas average plant gate netback price ($/mcf)
    4.01       5.75       4.74       2.69       1.89  
Ethane, propane and butane average field gate price ($/bbl)
    19.53       24.22       22.75       12.91       7.25  
Condensate average field gate price ($/bbl)
    37.72       38.23       42.62       24.90       18.54  
Crude oil average field gate price ($/bbl)
                      24.97       18.83  




66 Shell Canada Limited  n   Supplemental Resources Disclosure

Table of Contents

EXPLORATION AND                    
DEVELOPMENT WELLS DRILLED   2002   2001   2000   1999   1998

    Gross   Net   Gross   Net   Gross   Net   Gross   Net   Gross   Net

    2       1       2       1       2       1       1             6       3  
                                                    2       2  
    3       2       4       2       3       2       15       13       12       8  

    5       3       6       3       5       3       16       13       20       13  

    11       8       10       7       16       8       9       7       7       6  
    17       17       16       16                               17       17  
                                        2       1       24       14  
                            1       1       2       1              

    28       25       26       23       17       9       13       9       48       37  

Total wells drilled
    33       28       32       26       22       12       29       22       68       50  

Wells in progress
    8       5       16       14       8       5       10       3       24       21  

Exploration wells – Wells drilled either in search of new and as yet undiscovered pools of oil or gas, or with the expectation of significantly extending the limits of established pools. All other wells are development wells.

PRODUCTIVE WELLS   2002   2001   2000   1999   1998

    Gross   Net   Gross   Net   Gross   Net