ANNUAL INFORMATION FORM    SHELL CANADA LIMITED

Attached to this Annual Information Form is the Annual Report to shareholders for the year ended December 31, 2003 of Shell Canada Limited (“Annual Report”) and the Management Proxy Circular of the Corporation dated March 11, 2004 (“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 17 to 19 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.

INDEX

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	9
Oil Products	11
Competitive Conditions	13
Research and Development	13
Environmental Protection	13
Number of Employees	14
Foreign Operations	14
Selected Consolidated Financial Information	15
Annual Information	15
Dividends	16
Foreign Generally Accepted Accounting Principles (GAAP)	16
Management’s Discussion and Analysis	16
Market for Securities	16
Directors and Officers	17
Additional Information	18
Schedule I	19
Schedule II	21
Schedule III	26
Schedule IV	28
Schedule V	29
Schedule VI	31
Auditors’ Report	33

Corporate Structure    SHELL CANADA LIMITED

NAME AND INCORPORATION

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.

INTERCORPORATE RELATIONSHIPS

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 12 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.

CORPORATE STRUCTURE      1  

General Development of the Business    SHELL CANADA LIMITED

Shell Canada, one of the largest integrated petroleum companies in Canada, operates principally in three industry segments: Resources, Oil Sands and Oil Products. The Resources segment comprises exploration, production and marketing activities for natural gas, natural gas liquids, in situ 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 Sands segment has commenced the extraction of bitumen from Lease 13 in the Athabasca region of northern Alberta and processes the bitumen into a range of synthetic crude oils. The Oil Products segment includes the manufacture, distribution and marketing of refined petroleum products.

FIVE-YEAR HISTORY

1999   Shell Canada reported earnings of $678 million or $2.35 per Common Share compared with earnings of $430 million or $1.48 per share in 1998. The Company achieved a return on average capital employed of 16.7 per cent compared with 11.7 per cent in 1998. Resources earnings for 1999 were $500 million compared with $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 Project (“AOSP”) 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 $37 million in 1999 compared to an expense of $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 contributed by Shell. In December 1999, Shell Canada approved the largest investment in the Company’s history, the AOSP.

2000   Shell Canada reported earnings of $863 million or $3.06 per Common Share compared with earnings of $678 million or $2.35 per share in 1999. The Company achieved a return on average capital employed of 20.4 per cent compared with 16.7 per cent in 1999. Resources earnings for 2000 were $536 million compared with $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 Offshore Energy Project (“SOEP”). 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. 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.

2        GENERAL DEVELOPMENT OF THE BUSINESS

2001   Shell Canada announced record earnings of $1,010 million or $3.67 per Common Share compared with earnings of $863 million or $3.06 per share in 2000. The Company achieved a return on average capital employed of 21.5 per cent compared with 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 SOEP 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   Shell Canada reported earnings of $561 million or $2.03 per Common Share compared with earnings of $1,010 million or $3.67 in 2001. The return on average capital employed of 10.1 per cent was a reduction from the previous year’s exceptional high of 21.5 per cent. Resources earnings in 2002 were $387 million compared to $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. Resources capital and exploration expenditures were $389 million compared with $366 million in 2001. Oil Products earnings were $198 million in 2002, down 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. 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. Capital expenditures were $433 million, including $186 million for Oil Sands-related Scotford modifications. Oil Sands started operations at the very end of 2002 and reported a loss of $5 million due primarily to capital taxes on the related assets. The AOSP started up in December 2002 with the first production and sale of bitumen from the Muskeg River Mine.

2003   For highlights of 2003, reference is made to the business sections in the Management’s Discussion and Analysis section of the Annual Report found on pages 11 to 38.

TRENDS

2004   For a discussion of the significant initiatives planned by the Company for 2004, reference is made to the business sections in the Management’s Discussion and Analysis section of the Annual Report on pages 11 to 38.

GENERAL DEVELOPMENT OF THE BUSINESS      3  

Narrative Description of the Business    SHELL CANADA LIMITED

RESOURCES

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.

The Corporation’s conventional oil and gas reserves disclosure and related information has been prepared in reliance on a decision of the applicable Canadian securities regulatory authorities under National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”), which permits the Corporation to present this disclosure in accordance with the provisions of the United States Financial Accounting Standards Board (“FASB”) and the United States Securities and Exchange Commission (“SEC”). This disclosure differs from the corresponding information required by NI 51-101. If Shell Canada had not received the decision, the Corporation would be required to disclose proved plus probable reserves, estimates based on forecasted prices and costs and information relating to future net revenues using forecasted prices and costs.

Additional information related to Resources may be found on pages 12 to 19 of the Annual Report and in Schedule I and Schedule III on pages 19 and 20 and pages 26 and 27, respectively, of this Annual Information Form.

Principal Products

Shell Canada’s Resources segment is a major producer of natural gas, natural gas liquids, in situ bitumen and sulphur in Canada.

Principal Markets and Methods of Distribution

Natural Gas   Shell sells the majority of its Western Canada natural gas production to Coral Resources Canada ULC., an affiliated company which operates as part of The Royal Dutch/ Shell Group’s global trading organization, at Alberta market-based prices (AECO reference price).

The SOEP started up late in December 1999. It is owned jointly by Shell, ExxonMobil Canada Properties, Imperial Oil Resources, Pengrowth Corporation and Mosbacher Operating Ltd. Shell’s share of natural gas production from SOEP is 31.3 per cent and is marketed both directly to end use customers in North America and to Coral Energy Canada Inc. In May 2003, Shell and the other joint venture participants sold an 8.4 per cent interest in the SOEP infrastructure downstream of the offshore Thebaud platform to Pengrowth Corporation. This interest was acquired in 2001 through exercising a right of first refusal in the sale of SOEP assets by Nova Scotia Resources (Ventures) Ltd.

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

4        NARRATIVE DESCRIPTION OF THE BUSINESS

ownership in facilities for the fractionation and storage of ethane/ propane/ butane mixes located in Fort Saskatchewan, Alberta and for storage and fractionation facilities in Sarnia, Ontario and Point Tupper, Nova Scotia.

Natural gas liquids production from these facilities is sold to both Canadian markets and also exported to the United States. SOEP condensate production is shipped by marine tanker to the marketplace.

Bitumen   Shell Canada sells its in situ bitumen production from the Peace River facilities to both Canadian and U.S. markets. Production is shipped through a number of pipelines from Shell’s producing location to the receiving markets.

Sulphur   Shell is one of the world’s largest sulphur producers with about 47 per cent of Canadian sulphur sales and over 16 per cent of world traded sulphur. Shell markets sulphur within Canada and to export markets. Market growth in China in recent years 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 the Port of Vancouver, British Columbia, for shipping overseas.

Revenues by Product

Reference is made to the “Segmented Information” note to the consolidated financial statements on pages 46 to 49 of the Annual Report.

The following tables set out the percentage of revenue by customer:

Natural Gas (%)	2003		2002
Sales to third parties		14		18
Sales to investees		–		–
Sales to controlling shareholders		86		82
Total natural gas sales		100		100

Natural Gas Liquids (%)	2003		2002
Sales to third parties		98		97
Sales to investees		–		–
Sales to controlling shareholders		2		3
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 (“WCSB”), offshore Nova Scotia and in the Mackenzie Delta.

Seasonality

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. 2003 clearly realized this trend in the first quarter, demonstrating strong commodity prices through March. However, with the growing indication of tight supply, strong prices continued through the spring and summer, thereby resulting in a later than usual storage build into the fourth quarter. The storage build allowed for slight moderation in prices during the fourth quarter.

NARRATIVE DESCRIPTION OF THE BUSINESS      5  

Drilling Activity

Reference is made to the “Exploration and Development Wells Drilled” table on page 61 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)		(%)
Waterton		100		165		62
Jumping Pound		100		151		75
Burnt Timber		82		95		95
Caroline		72		129		93
Wildcat Hills (outside operated)		34		106		96
Goldboro (outside operated)		31		565		76

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 in 2003.

Shell also has interests in three natural gas liquids fractionation and storage facilities operated by Dow Chemical Canada Inc. (“Dow”), BP Canada Energy Inc. (“BP Canada”) and ExxonMobil Canada Properties (“ExxonMobil”). 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)
	De-ethanizer		44		31		73
	Fractionator		42		13		58
Sarnia, Ontario (BP Canada)
	Fractionator		13		15		100
Point Tupper, Nova Scotia (ExxonMobil)
	Fractionator		31		10		54

¹ Based on average daily throughput relative to available capacity.

6        NARRATIVE DESCRIPTION OF THE BUSINESS

The significant fields in which Shell owns varying interests are:

Natural Gas, Natural Gas Liquids and Sulphur Production		Bitumen Production
Alberta
Burnt Timber	Caroline	Peace River
Clearwater	Jumping Pound
Limestone	Moose/ Whiskey
Panther River	Waterton
Wildcat Hills
Nova Scotia
Alma	North Triumph
Thebaud	Venture

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 61 of the Annual Report.

Interest in Material Properties

Reference is made to the “Landholdings” table on page 66 of the Annual Report.

Reserve Estimates

Reference is made to the “Reserves” section on pages 62 and 63 of the Annual Report and to Schedule I on pages 19 and 20 of this Annual Information Form.

Source of Reserve Estimates

Conventional oil and gas reserves estimates are prepared by the Corporation’s internal qualified reserves evaluator. No independent qualified reserves evaluator or auditor was involved in the preparation of the Corporation’s reserves data. However, due to the significance of the SOEP revision, an independent third party reserves evaluation was also performed to estimate those reserves. This independent reserves evaluation confirmed Shell’s internally prepared reserves estimates for those reserves.

Shell’s Chief Reservoir Engineer is a qualified reserves evaluator, as defined by NI 51-101, and together with the Company’s internal team of reservoir engineers evaluates the Company’s oil and gas reserves data. The reserves estimates prepared by the Chief Reservoir Engineer are reviewed by the Chief Executive Officer and members of senior management in the Resources segment, the Corporation’s Disclosure Policy Committee and the Audit Committee prior to submission of the estimates to the Board of Directors for approval.

The Audit Committee has been delegated the responsibility by the Board of Directors to review the Corporation’s processes and related procedures for the disclosure of reserves data as permitted by NI 51-101. All members of the Audit Committee are outside directors and are not related to the Corporation or to its significant shareholder.

Reference is also made to Schedule III and Schedule V on pages 26 and 27 and pages 29 and 30, respectively, of this Annual Information Form.

NARRATIVE DESCRIPTION OF THE BUSINESS      7  

Reconciliation of Reserves

Reference is made to the “Reserves” section on pages 62 and 63 of the Annual Report.

History

Reference is made to the “Production” table on page 60 of the Annual Report.

            REVENUE

            Natural Gas ($/mcf)

		2003		2002		2001
Average plant gate price			6.46		4.01		5.75
Royalties			1.18		0.70		1.12
Operating expenses*
	Plant and field		0.77		0.71		0.59
	Head office		0.26		0.16		0.14
Total operating expenses			1.03		0.87		0.73
Netback			4.25		2.44		3.90

            Ethane, Propane and Butane ($/bbl)

		2003		2002		2001
Average plant gate price			25.48		19.53		24.22
Royalties			4.73		2.71		4.76
Operating expenses*
	Plant and field		4.64		4.24		3.54
	Head office		1.56		0.98		0.84
Total operating expenses			6.20		5.22		4.38
Netback			14.55		11.60		15.08

            Condensate ($/bbl)

		2003		2002		2001
Average plant gate price			41.13		37.72		38.23
Royalties			8.87		7.07		8.54
Operating expenses*
	Plant and field		4.64		4.24		3.54
	Head office		1.56		0.98		0.84
Total operating expenses			6.20		5.22		4.38
Netback			26.06		25.43		25.31

*  These costs have been restated for 2002 and 2001 to conform with U.S. FAS69 presentation, which disallows the inclusion of general corporate overhead.

8        NARRATIVE DESCRIPTION OF THE BUSINESS

Future Commitments

Volume (millions of boe*)	Source of Production
224.86		WCSB
44.29		SOEP

* barrels of oil equivalent.

(6 mcf = 1 bbl)

The conversion is based on an energy equivalency method and does not represent a value equivalency at the wellhead.

The sales commitments consist of long-term natural gas contracts.

Exploration and Development

Expenditures on exploration and development appear in Schedule I on pages 19 and 20 of this Annual Information Form.

Additional information related to exploration and development activities may be found on pages 12 to 19 of the Annual Report.

OIL SANDS

2003 was the first year of operations for the AOSP. 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 AOSP 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 power 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, but was shut down as a result of a fire at the mine in January 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 synthetic crude oils. Shell Canada operates the upgrader.

The AOSP achieved fully integrated operations in April 2003 when the Corridor Pipeline carried diluted bitumen from the Muskeg River Mine to the Scotford Upgrader where it was processed into synthetic crude oil products. The majority of the synthetic crude produced at the upgrader is supplied to Shell Canada’s refineries, with the remainder moved by pipeline to markets throughout Canada and the United States.

Production grew steadily throughout the last half of 2003, reaching or exceeding design rates of 155,000 barrels per day (100 per cent) on many occasions. During the fourth quarter, production averaged 84 per cent of design rates at 130,000 barrels per day. Total Shell share bitumen production for the year was 17 million barrels.

The Corporation’s mineable bitumen reserves disclosure and related information has been prepared in reliance on a decision of the applicable Canadian securities regulatory authorities under NI 51-101 which permits the Corporation to present this disclosure in accordance with the applicable requirements of FASB and the SEC. This disclosure differs from the corresponding information required by NI 51-101. If Shell Canada had not received the decision, the Corporation would be required to disclose reserves estimates based on forecasted prices and costs and information relating to future net revenue using constant and forecast prices and costs.

Additional information related to Oil Sands may be found on pages 20 to 23 of the Annual Report and in Schedule II and Schedule IV on pages 21 to 25 and page 28, respectively, of this Annual Information Form.

NARRATIVE DESCRIPTION OF THE BUSINESS      9  

Revenue by Product

Reference is made to the “Segmented Information” note to the consolidated financial statements on page 46 of the Annual Report.

The following table, which excludes intersegment transfers, sets out the percentage of revenue by customer:

Synthetic Crude Sales (%)	2003		2002
Sales to third parties		93		–
Sales to investees		–		–
Sales to controlling shareholders		7		–
Total synthetic crude sales		100		–

Seasonality

There were no significant seasonal fluctuations in the overall Oil Sands business. However, production rates may be lower during extremely cold weather conditions.

Interest in Material Properties

Reference is made to the “Landholdings” table on page 66 of the Annual Report.

Reserve Estimates

Reference is made to the “Reserves” section on pages 64 and 65 of the Annual Report.

Source of Reserve Estimates

Mineable bitumen reserves estimates are prepared by the Corporation’s internal qualified reserves evaluator. No independent qualified reserves evaluator or auditor was involved in the preparation of the Corporation’s reserves data.

Shell’s Chief Mining Engineer is a qualified reserves evaluator, as defined by NI 51-101, and together with the Company’s internal team of geological and mining professionals evaluates the Company’s mineable bitumen reserves data. The reserves estimates prepared by the Chief Mining Engineer are reviewed by the Chief Executive Officer and members of senior management in the Oil Sands segment, the Corporation’s Disclosure Policy Committee and the Audit Committee prior to submission of the estimates to the Board of Directors for approval.

The Audit Committee has been delegated the responsibility by the Board of Directors to review the Corporation’s processes and related procedures for the disclosure of reserves data as permitted by NI 51-101. All members of the Audit Committee are outside directors and are not related to the Corporation or to its significant shareholder.

Reference is also made to Schedule IV and Schedule V on page 28 and pages 29 and 30, respectively, of this Annual Information Form.

Reconciliation of Reserves

Reference is made to the “Reserves” section on pages 64 and 65 of the Annual Report.

10        NARRATIVE DESCRIPTION OF THE BUSINESS

OIL PRODUCTS

Shell Canada’s oil refining, supply, distribution and marketing businesses are managed and operated 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 retail sites provide a variety of other services including a Select convenience store and a car wash.

Additional information related to Oil Products may be found on pages 24 to 29 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 road 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 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 17 per cent in 2003 (2002 – slightly below 18 per cent).

The total number of Shell-branded retail sites at year-end was 1,693 (2002 – 1,705) comprising one salary-operated site, 673 commission-operated sites, 136 sites run by lessees and 883 dealer-owned and dealer-operated locations. The private-brand network consisted of 116 retail sites (2002 – 133).

The integration and rationalization of the wholly owned private-brand network into Shell’s operations commenced in 1997 and continues as planned. In 2003, 17 private-brand retail sites were either converted or closed.

Revenues by Product

Reference is made to the “Segmented Information” note to the consolidated financial statements on pages 46 to 49 of the Annual Report.

The following tables set out the percentage of revenue by customer:

Gasoline (%)	2003		2002
Sales to third parties		100		100
Sales to investees		–		–
Sales to controlling shareholders		–		–
Total gasoline sales		100		100

NARRATIVE DESCRIPTION OF THE BUSINESS      11  

Middle Distillates (%)	2003		2002
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 2003, Shell Canada’s crude oil requirements were supplied from three major sources. Domestic industry production, under a variety of purchase and sale arrangements, amounted to 39 per cent (2002 – 53 per cent). Shell Canada’s own production contributed 15 per cent (2002 – less than one per cent). The remaining 46 per cent (2002 – 47 per cent) was imported. The definition of crude oil now includes Scotford Upgrader feedstocks from the AOSP, following the start-up of production during the year.

Seasonality

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

Manufacturing

Shell’s three operating refineries located at Sarnia, Ontario; Montreal, Quebec; and Fort Saskatchewan, Alberta, achieved average utilization rates of 90 per cent in 2003 (2002 – 87 per cent). This increase in average utilization in 2003 was mainly due to configuration changes at the Scotford Refinery and smaller maintenance turnarounds in 2003 compared to the previous year. 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.

Shell Canada’s refineries continue to account for approximately 16 per cent (2002 – 16 per cent) of Canada’s operating refinery capacity in 2003. The location and rated capacity of each of Shell’s refineries at December 31, 2003 are shown below.

	Daily Rated Capacity 1
Refinery	(cubic metres)		(barrels)
Montreal East (Quebec)		19 400		122 000
Sarnia (Ontario)		11 400		71 700
Scotford (Alberta)		18 200		114 500
Total		49 000		308 200

¹ Rated capacity is based on definite specifications as to types of crude oil and Scotford Upgrader feedstocks, 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 2003, Shell’s automated lubricant blending plant in Brockville, Ontario produced 159 million litres. This represents an increase of 17 per cent over 2002 volumes. The Calgary grease manufacturing facility produced 2.8 million kilograms of soap-based and microgel-based greases in 2003, a decrease of seven per cent from 2002.

Reorganization

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. Shell Canada Products Limited owns 99.99 per cent of the partnership units and is the managing partner. The balance of the partnership units are held by a wholly owned subsidiary of the Corporation.

12        NARRATIVE DESCRIPTION OF THE BUSINESS

COMPETITIVE CONDITIONS

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 existing Oil Sands leases.

The Investment Canada Act requires Shell Canada, a statutory non-Canadian and World Trade Organization 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 transaction is not a reviewable transaction. Any direct investment in excess of $223 million in 2003 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

Research and development expense was $10 million in 2003 (2002 – $6 million).

ENVIRONMENTAL PROTECTION

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 HSE-related risks to the business that arise from our operations and/or from the areas in which we operate. 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 segments have ISO 14001 registered HSE management systems. The Scotford Upgrader was recommended for certification in late 2003.

Environmental protection expenditures are outlined in the following table:

Environmental Expenditures ($ millions)	2003		2002
Operating costs		80		61
Capital costs		25		137
Restoration and reclamation		52		49
Total		157		247

NARRATIVE DESCRIPTION OF THE BUSINESS      13  

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. Environmental operating costs increased over 2002 as the AOSP moved into production.

Capital costs   These include the cost of new equipment and associated construction costs for pollution prevention, waste management and controlling air emissions and water discharges. The environmental capital expenditures change significantly from year to year as expansion projects and process changes to meet new product quality requirements are addressed. While these costs rose for the Scotford Upgrader by $2 million in 2003, capital costs were reduced significantly at the Sarnia and Montreal East refineries compared with 2002, when $121 million was invested into gasoline desulphurization projects at these sites.

Restoration and reclamation   This includes the costs of spill cleanup, decommissioning and restoration, and the protection or restoration of wildlife and habitat. At the Muskeg River Mine, these costs increased to approximately $1 million in 2003. Restoration costs in Products and Resources, at about $50 million per year, continue to be the one of the top two environmental expenditures exclusive of capital.

NUMBER OF EMPLOYEES

The number of employees at the end of 2003 was 3,850 compared to 3,825 at the end of 2002. The number of employees in each segment is as follows:

	Number of Employees
	At		At
Segment	Dec. 31, 2003		Dec. 31, 2002
Resources		859		834
Oil Products		1 930		1 968
Oil Sands		434		425
Corporate*		627		598
Total		3 850		3 825

*  In 2003 HSE employees were centralized into the Corporate segment.

FOREIGN OPERATIONS

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

14        NARRATIVE DESCRIPTION OF THE BUSINESS

Selected Consolidated Financial Information    SHELL CANADA LIMITED

ANNUAL INFORMATION

Total Revenue

Reference is made to the “Consolidated Statement of Earnings and Retained Earnings” table, “Revenues” section, on page 41 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 41 and the “Data Per Common Share” table on page 67 of the Annual Report.

Total Assets

Reference is made to the “Consolidated Balance Sheet” table on page 43 of the Annual Report.

Long-Term Financial Liabilities

Reference is made to the “Consolidated Balance Sheet” table on page 43 of the Annual Report.

Cash Dividends Declared per Share

Reference is made to the “Data Per Common Share” table on page 67 of the Annual Report.

Factors Affecting Comparability

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 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 benefit resulting from

SELECTED CONSOLIDATED FINANCIAL INFORMATION      15  

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.

2003   Oil Sands became fully operational in June and reflected a full year loss of $142 million due mainly to start-up related costs. Total earnings in the year included a benefit resulting from a future income tax revaluation and the future income tax expense decreased by $36 million. The Company initiated the expensing of stock options, beginning with options granted in 2003. The total 2003 stock option expense was $12 million.

Eight Quarters Information

Reference is made to the “Quarterly Financial and Stock Trading Information” table on page 68 of the Annual Report.

DIVIDENDS

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 2003, dividends of 20 cents per share were paid on March 14, June 16 and September 15. In November, the Board of Directors approved a 10 per cent increase in the quarterly dividend to 22 cents per share, which was paid on December 15.

FOREIGN GENERALLY ACCEPTED ACCOUNTING PRINCIPLES (GAAP)

Oil and Gas Disclosure

Disclosure, in accordance with Statement No. 69 of the U.S. FASB, appears in Schedule I on pages 19 and 20 of this Annual Information Form.

United States Generally Accepted Accounting Principles

The significant differences between Canadian and United States Generally Accepted Accounting Principles are identified in Schedule VI on pages 31 and 32 of this Annual Information Form.

Management’s Discussion and Analysis

Reference is made to pages 11 to 38 of the Annual Report.

OFF-BALANCE SHEET ARRANGEMENTS

The Corporation has entered into an operating lease for large mobile equipment in use at the Muskeg River Mine and has sold accounts receivable under an accounts receivable securitization program. Both of these arrangements are cost effective to the Corporation versus its alternatives. Reference is made to “Accounting Standards” on page 32 of the Annual Report and to the “Commitments and Contingencies” and “Sale of Accounts Receivable” notes on pages 57 and 58, respectively, of the Annual Report.

Market for Securities

Reference is made to “Investor Information” on page 74 of the Annual Report.

16        SELECTED CONSOLIDATED FINANCIAL INFORMATION

Directors and Officers    SHELL CANADA LIMITED

Reference is made to the “Corporate Directory and Board of Directors” table on page 69 of the Annual Report, the “Statement of Corporate Governance Practices” on pages 70 to 73 of the Annual Report, and the “Information Concerning Nominees for Election to the Board of Directors” on pages two to six of the Proxy Circular and “Description of Current Occupation” on page six of the Proxy Circular.

The following were officers of the Corporation as at December 31, 2003:

		Principal Occupation
Name and Municipality		if Different from Office Held
of Residence	Office	Within Preceding Five Years 1
Linda Z. Cook Calgary, Alberta	President and Chief Executive Officer	–
H. Ian Kilgour Calgary, Alberta	Senior Vice President, Resources	–
Neil J. Camarta Calgary, Alberta	Senior Vice President, Oil Sands	–
David M. Weston Calgary, Alberta	Senior Vice President, Oil Products	–
Cathy L. Williams Calgary, Alberta	Chief Financial Officer	–
Harold W. Lemieux Calgary, Alberta	Vice President, General Counsel and Secretary	–
R. Terry Blaney Calgary, Alberta	Vice President, Marketing	–
Graham Bojé Calgary, Alberta	Vice President, Manufacturing and Supply	–
Rob W.P. Symonds Calgary, Alberta	Vice President, Foothills	–
Timothy J. Bancroft Calgary, Alberta	Vice President, Sustainable Development, Technology and Public Affairs	–
Sam Spanglet Calgary, Alberta	Vice President, Operations, Oil Sands	–
Gary N. Stewart Calgary, Alberta	Treasurer	–
Matthew B. Haney Calgary, Alberta	Controller	–
Susan S. Boughs Toronto, Ontario	Assistant Secretary	Associate General Counsel Eastern Canada

DIRECTORS AND OFFICERS      17

		Principal Occupation
Name and Municipality		if Different from Office Held
of Residence	Office	Within Preceding Five Years 1
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 Shell Canada Limited

¹ 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.

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 70 to 73 of the Annual Report for discussion of the three Board committees and their membership.

Reference is made to “Certain Transactions” on pages six and seven 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

AVAILABILITY OF DOCUMENTS

Copies of the following documents are available upon request from the Corporation’s Secretary: the Corporation’s Annual Information Form for 2003, together with the documents incorporated by reference therein; the Corporation’s Proxy Circular for its most recent annual and special meeting of shareholders; the Corporation’s Annual Report containing comparative financial statements for 2003, together with the Auditors’ Report thereon; and the Management’s Discussion and Analysis and interim financial statements subsequent to December 31, 2003.

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 30, 2004 annual and special meeting of shareholders. Additional financial information is provided in the Corporation’s comparative financial statements for its most recently completed financial year.

18        DIRECTORS AND OFFICERS

Schedule I    SHELL CANADA LIMITED

(UNAUDITED)

OIL AND GAS DISCLOSURE

The following conventional oil and gas reserves disclosure has been prepared in reliance on a decision of the applicable Canadian securities regulatory authorities under National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”), which permits the Corporation to present this disclosure in accordance with the applicable requirements of FASB Statement No. 69 (“FAS 69”), Disclosures about Oil and Gas Producing Activities. The United States 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 adheres to the requirements outlined in paragraphs 10 to 34 of FAS 69. This information differs from the corresponding information required by NI 51-101. Reference is made to “Resources” on page 4 of this Annual Information Form for a discussion of these differences.

This disclosure is unaudited, and no independent qualified reserves evaluator or auditor has been involved in its preparation and it does not include mineable bitumen.

At December 31 ($ millions)	2003			2002			2001
CAPITALIZED COSTS 1
Unproved oil and gas reserves		191			168			174
Proved oil and gas reserves		4 582			4 224			3 967
		4 773			4 392			4 141
Accumulated depreciation, depletion and amortization		(2 521	)		(2 219	)		(2 009	)
Net capitalized costs		2 252			2 173			2 132

Year ended December 31 ($ millions)	2003		2002		2001
COSTS INCURRED
Property acquisition		12		9		17
Exploration costs		118		121		109
Development costs		301		259		240
Total costs incurred		431		389		366

Year ended December 31 ($ millions)	2003			2002			2001
RESULTS OF OPERATIONS FROM PRODUCING ACTIVITIES
Revenues		2 028			1 479			1 838
Operating expenses		(682	)		(536	)		(623	)
Exploration expenses		(81	)		(123	)		(81	)
Depreciation, depletion, amortization and retirements		(293	)		(224	)		(212	)
Income tax		(345	)		(218	)		(361	)
Results of operations from producing activities		627			378			561
Cumulative effect of change in accounting policy after tax 2		(45	)		–			–
Adjusted results of operations from producing activities		582			378			561

1	Includes capitalized costs related to asset retirement obligations (FAS 143).
2	Adoption of FAS 143 – Asset Retirement Obligations.

SCHEDULE I      19  

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 conventional 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 because of, among other things:

(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.

The 2003 computation includes gross revenues from sulphur. Costs with respect to these revenues cannot be separately identified.

The information includes cash flows related to the Peace River in situ bitumen operation but does not include mineable bitumen.

At December 31 ($millions)		2003			2002			2001
NET CASH FLOWS
Future cash inflow			13 892			18 135			11 979
Future operating and development costs			5 858			6 512			6 094
Future income taxes			2 500			4 039			2 090
Future net cash flows 1			5 534			7 584			3 795
10% annual discount for estimated timing of cash flows			2 325			4 291			1 596
Standardized measure of discounted future net cash flows from proved oil and gas reserves			3 209			3 293			2 199
CHANGES IN NET CASH FLOWS
Balance at beginning of year			3 293			2 199			6 110
Changes resulting from:
	Sales, net of operating costs		(1 073	)		(700	)		(1 931	)
	Net changes in prices and operating costs		314			2 482			(5 729	)
	Extensions, discoveries and improved recoveries, less related costs		224			49			53
	Development costs incurred during the period		295			218			154
	Revisions of previous quantity estimates 2		(809	)		(382	)		(622	)
	Purchases of reserves in place		–			–			7
	Sales of reserves in place		–			–			–
	Accretion of discount		441			220			612
	Net changes in income taxes		524			(793	)		3 545
Net (decrease) increase for the year			(84	)		1 094			(3 911	)
Balance at end of year			3 209			3 293			2 199

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

20        SCHEDULE I

Schedule II    SHELL CANADA LIMITED

OIL SANDS MINING

Muskeg River Mine Development History

Shell Canada holds a 60 per cent interest in the AOSP, a joint venture established in 1999 to recover oil sands ore from certain leasehold interests in the Athabasca region of northern Alberta and to process the ore into synthetic crude oil products.

The AOSP’s Muskeg River Mine is located on the western portion of Bituminous Sands Lease No. 727708T13 (“Lease 13”) in northeastern Alberta approximately 75 kilometres north of the city of Fort McMurray and is readily accessible by public road. Figure 1 shows the location of the Muskeg River Mine. The Muskeg River Mine (“MRM”) is an integrated oil sands mining and mineral processing facility and achieved operational status in April 2003. The oil sands ore is open-pit mined using a conventional truck and shovel operation, and the mined ore is processed in an on-site bitumen extraction and clean up facility to yield a bitumen product. Power and steam for the operation is provided from an on-site cogeneration facility which is owned and operated by a third party power company. The bitumen is transported from the site by pipeline to a bitumen upgrading facility that is located in the Edmonton area of central Alberta. Current facility design capacity is for 155,000 barrels per day of bitumen production, with opportunities to expand production to 225,000 barrels per day. These facilities represent a multi billion dollar investment and are in new condition. The MRM is operated by Albian Sands Energy Inc., a company owned by the AOSP joint venture participants.

Shell Canada originally acquired the mineral rights to Lease 13 in 1956. The Lease 13 resource has since been thoroughly characterized in association with a variety of development studies, however the MRM is the first commercial operation on the lease. With the commencement of commercial mine operations on the western portion of Lease 13, the whole of Lease 13 is characterized as having “continued producing” status and the right to access the bitumen resource on the lease has been extended indefinitely for so long as production is continuing. After the establishment of the AOSP joint venture in 1999, Lease 13 was formally transferred to Albian Sands Energy Inc. to be held in trust for the AOSP joint venture participants.

Shell Canada also holds a number of other oil sands leases that are immediately adjacent to Lease 13. Leases 7288080T88 (Lease 88), 7288080T89 (Lease 89) and 7288080T90 (Lease 90) collectively have significant mineable bitumen resources and each have a lease expiry date of August 31, 2008. These leases may be extended by completion of a minimum level of exploration prior to their expiry. There are no current, and no known previous, commercial operations on these adjacent leases.

The MRM received its primary regulatory approvals in 1999. The regulatory application for the MRM was submitted to the Alberta Energy and Utilities Board (“EUB”) and Alberta Environment (“AENV”) in December 1997. The application provides significant background detail on the geology, mine planning features and development scheme, and formed the basis of the approval from the EUB in June 1999 and under the Environmental Protection and Enhancement Act in August 1999.

The following are the primary regulatory applications and approvals for the Muskeg River Mine:

1.	Application for Approval of Muskeg River Mine Project December 1997 (Application No. 970588) submitted to the EUB and AENV (available at the EUB Library, 640 – 5th Avenue S.W. Calgary, Alberta – Tel: (403) 297-8311);
2.	Supplemental Information for the Muskeg River Mine Project June 1998 (Application No. 970588) submitted to the EUB and AENV (available at the EUB Library, 640 – 5th Avenue S.W. Calgary, Alberta – Tel: (403) 297-8311);
3.	Muskeg River Mine Project Decision Report 99-2 by the EUB dated February 12, 1999 (available on-line at www.eub.gov.ab.ca);
4.	Muskeg River Mine Approval No. 8512 Order in Council by the EUB dated June 25, 1999 (available at the EUB Library, 640 – 5th Avenue S.W. Calgary, Alberta – Tel: (403) 297-8311);

SCHEDULE II      21  

5.	Muskeg River Mine 10 year Environmental Protection and Enhancement Act Approval No. 20809-00-01 from AENV dated June 18, 1999 (available on-line at www.gov.ab.ca/env/water/approvalviewer.html search parameter – Albian Sands Energy Inc.); and
6.	Muskeg River Mine Water Resources Act Approval No. 00071821-00-00, as amended, from AENV dated August 4, 1999 (available on-line at www.gov.ab.ca/env/water/approvalviewer.html search parameter – Albian Sands Energy Inc.).

The EUB has also provided Shell Canada with conditional approval for Phase 1 of the proposed Jackpine Mine, a stand-alone mining and extraction facility to be located on the eastern portion of Lease 13. The regulatory application for the Jackpine Mine remains subject to approval by the cabinets of the provincial and federal governments. The planned development for the Jackpine Mine includes a proposal to extend development to Lease 88 and Lease 89. This second phase of the Jackpine Mine will require additional regulatory approval.

Muskeg River Mine Geology

Lease 13 is situated immediately east of the Athabasca River valley. Most of the lease comprises gently undulating terrain that ranges in elevation from 330 metres above sea level in the southeast to 284 metres in the west.

The McMurray Formation is the geological unit containing the bitumen hydrocarbon resource. The McMurray Formation was laid down in a marine shoreline setting and is composed, generally, of a sequence of sediments that gets finer in an upward direction – from pebbles 5 millimetres in diameter, through sand, to silt and mud 0.06 millimetres in diameter and finer. When the McMurray Formation contains bitumen in a sand sized sediment coarser than approximately 0.12 millimeters, this is characterized as oil sands.

The McMurray Formation is present at varying depths beneath the ground over much of northern Alberta. Over 3,400 square kilometres of land has been classified by the EUB as surface mineable. Within this area the McMurray Formation is near the surface and can be excavated economically with existing mining equipment. The Devonian limestone which lies beneath the McMurray Formation is within 50 metres to 150 metres of the surface.

Muskeg River Mine Reserves

Reference is made to the “Reserves” section on pages 64 and 65 of the Annual Report and to Schedule IV on page 28 of this Annual Information Form.

The MRM development on Lease 13 was designed to access proved and probable reserves over 30 years of operation at the average design production level of 155,000 barrels per day, resulting in 1.7 billion barrels of recoverable bitumen over the project life.

Figure 2 shows the mining areas associated with the reserves for the Muskeg River Mine. Figure 3 shows the core hole coverage for those same areas.

22        SCHEDULE II

Location of the Muskeg River Mine

March 11, 2004

SCHEDULE II      23  

Muskeg River Mine Development Areas

March 11, 2004

24        SCHEDULE II

Core Hole Coverage for Development Areas

March 11, 2004

SCHEDULE II      25  

Schedule III    SHELL CANADA LIMITED

FORM 51-101F2

Report on Oil and Gas Reserves Data by Qualified Reserves Evaluator

To the board of directors of Shell Canada Limited (the “Company”):

1. Together with our staff, I have evaluated the Company’s reserves data as at December 31, 2003. The reserves data consist of the following:

(a)	proved oil and gas reserves estimated as at December 31, 2003, using constant prices and costs; and
(b)	the related estimated future net revenue.

2.	The reserves data are the responsibility of the Company’s management. Our responsibility is to express an opinion on the reserves data based on our evaluation.
3.	We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook”), modified to the extent necessary to reflect the terminology and standards of the U.S. Disclosure Requirements. We are not, however, independent of the Company, within the meaning of the term “independent” under those standards.
4.	Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data are free of material misstatement. An evaluation also includes assessing whether the reserves data are in accordance with principles and definitions presented in the COGE Handbook and applicable U.S. Disclosure Requirements.
5.	The following table sets forth the estimated future net revenue (after deduction of income taxes) attributed to proved oil and gas reserves, estimated using constant prices and costs and calculated using a discount rate of 10 per cent, included in the reserves data of the Company evaluated by us for the year ended December 31, 2003:

		Net Present Value of
	Location of Reserves	Future Net Revenue
Internal Qualified	(country or foreign	(after income taxes,
Reserves Evaluator	geographic area)	10% discount rate)
Bruce Roberts	Canada	$3,209 million

6.	In our opinion, the reserves data evaluated by us have, in all material respects, been determined in accordance with the COGE Handbook, modified to the extent necessary to reflect the terminology and standards of the U.S. Disclosure Requirements. We express no opinion on the reserves data that we did not evaluate.
7.	We have no responsibility to update our evaluation referred to in this report for events and circumstances occurring after the date of this report.

26        SCHEDULE III

8.	Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material.
	Executed as to our report referred to above at Calgary, Alberta:

           
           Bruce Roberts
           Chief Reservoir Engineer

           January 29, 2004

SCHEDULE III      27  

Schedule IV    SHELL CANADA LIMITED

FORM 51-101F2

Report on Mineable Bitumen Reserves Data by Qualified Reserves Evaluator

To the board of directors of Shell Canada Limited (the “Company”):

1.	Together with our staff, I have evaluated the Company’s reserves data as at December 31, 2003. The reserves data consist of proved and probable mineable bitumen reserves estimated as at December 31, 2003.
2.	The reserves data are the responsibility of the Company’s management. Our responsibility is to express an opinion on the reserves data based on our evaluation.
3.	We carried out our evaluation in accordance with the applicable standards set out in the Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook”), modified to the extent necessary to reflect the terminology and standards of the U.S. Disclosure Requirements. We are not, however, independent of the Company, within the meaning of the term “independent” under those standards.
4.	Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data are free of material misstatement. An evaluation also includes assessing whether the reserves data are in accordance with applicable principles and definitions presented in the COGE Handbook and applicable U.S. Disclosure Requirements.
5.	In our opinion, the reserves data evaluated by us have, in all material respects, been determined in accordance with the applicable standards set out in the COGE Handbook, modified to the extent necessary to reflect the terminology and standards of the U.S. Disclosure Requirements. We express no opinion on the reserves data that we did not evaluate.
6.	We have no responsibility to update our evaluation referred to in this report for events and circumstances occurring after the date of this report.
7.	Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material.

     Executed as to our report referred to above at Calgary, Alberta:

           
           Allen G. Vanderputten
           Chief Mining Engineer


           January 29, 2004

28        SCHEDULE IV

Schedule V    SHELL CANADA LIMITED

FORM 51-101F3

Report of Management and Directors on Oil and Gas Disclosure

Management of Shell Canada Limited (the “Company”) are responsible for the preparation and disclosure of information with respect to the Company’s oil and gas activities in accordance with securities regulatory requirements. This information includes reserves data, which consist of the following:

(a)   (i) proved oil and gas reserves estimated as at December 31, 2003 using constant prices and costs; and

           (ii) the related estimated future net revenue; and

(b) proved and probable mineable bitumen reserves estimated as at December 31, 2003.

Our Chief Reservoir Engineer and Chief Mining Engineer, who are each in an employment relationship with the Company, along with the Company’s internal teams of reservoir engineers and geological and mining professionals, have evaluated the Company’s reserves data. The reports of the internal qualified reserves evaluators will be filed with securities regulatory authorities concurrently with this report.

The Audit Committee of the Board of Directors of the Company has:

(a)	reviewed the Company’s procedures for providing information to the internal qualified reserves evaluators;
(b)	met with the internal qualified reserves evaluators to determine whether any restrictions placed by management affect the ability of the internal qualified reserves evaluators to report without reservation; and
(c)	reviewed the reserves data with management and the internal qualified reserves evaluators.

The Audit Committee of the Board of Directors has reviewed the Company’s procedures for assembling and reporting other information associated with oil and gas activities and has reviewed that information with management. The Board of Directors has, on the recommendation of the Audit Committee, approved the content and filing with securities regulatory authorities of the reserves data and other oil and gas information, the filing of the reports of the internal qualified reserves evaluators on the reserves data and the content and filing of this report.

The Company is relying on exemptive relief, which it sought and was granted by securities regulatory authorities, permitting it to use U.S.-style oil and gas disclosure and exempting it from the requirement under securities legislation to involve independent qualified reserves evaluators or independent qualified reserves auditors.

In our view, the reliability of the internally generated reserves data is not materially less than would be afforded by our involving independent qualified reserves evaluators or independent qualified reserves auditors to evaluate or audit and review the reserves data. The primary factors supporting the involvement of independent qualified reserves evaluators or independent qualified reserves auditors apply when (i) their knowledge of, and experience with, a reporting issuer’s reserves data are superior to that of the internal evaluators and (ii) the work of the independent qualified reserves evaluators or independent qualified reserves auditors is significantly less likely to be adversely influenced by self-interest or management of the reporting issuer than the work of internal reserves evaluation staff. In our view, neither of these factors applies in our circumstances.

Our view is based in large part on the following. Our reserves data were developed in accordance with the applicable standards set out in the Canadian Oil and Gas Evaluation Handbook. Our internal reserves evaluation staff includes 29 persons with an average of

SCHEDULE V      29  

15 years of relevant experience in evaluating reserves, of whom 13 are qualified reserves evaluators for purposes of securities regulatory requirements. Our internal reserves evaluation management personnel includes two persons with an average of 24 years of relevant experience in evaluating and managing the evaluation of reserves. Our procedures, records and controls relating to the accumulation of source data and preparation of reserves data by our internal reserves evaluation staff have been established, refined, documented, and subjected to review by our internal financial auditors who have reported directly to the Audit Committee of the Board of Directors.

Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material.

LINDA Z. COOK

President and Chief Executive Officer

CATHY L. WILLIAMS

Chief Financial Officer

KERRY L. HAWKINS

Director

DAVID W. KERR

Director

March 11, 2004

30        SCHEDULE V

Schedule VI    SHELL CANADA LIMITED

UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES AND REPORTING PRACTICES

The financial statements have been prepared in accordance with accounting principles generally accepted in Canada. They differ from those generally accepted in the United States 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, an electricity hedge, 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 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. A new Canadian standard will require the expensing of all options by 2004. Shell Canada has early adopted this new standard, and has applied the standard prospectively in 2003.

Asset Retirement Obligations   The U.S. accounting standard FAS 143 became effective in 2003. This standard required the recognition of legal obligations associated with the retirement of tangible long-lived assets. The cumulative effect of this accounting policy change was $45 million after tax, and has been charged to current year earnings. The equivalent Canadian pronouncement on asset retirement obligations will be adopted in 2004.

Shipping and Handling Fees   The Emerging Issues Task Force of FASB in the United States requires that shipping and handling cost not be offset against revenue. For Canadian purposes, the fees are recorded as follows:

($ millions)	2003		2002		2001
Offset against revenue		270		243		251
Included in operating expenses		55		42		42

SCHEDULE VI      31  

If the Corporation’s financial statements had been presented on the basis of U.S. generally accepted accounting principles (“GAAP”), earnings and earnings per share would have been:

($ millions)		2003			2002			2001
Earnings as reported under Canadian GAAP			810			561			1 010
Increase (decrease):
	Capitalized interest amortized		(14	)		(12	)		(18	)
	Pension expense		(31	)		(37	)		(31	)
	Change in fair value of derivative instruments		(7	)		(3	)		9
	Elimination of profit on transaction with affiliate		–			(24	)		–
	Stock-based compensation		(3	)		(3	)		–
	Income taxes		12			20			19
Adjusted Earnings Attributable to Common Shares			767			502			989
	Cumulative Effect of Change in Accounting Policy After Tax		(45	)		–			–
Adjusted Earnings After Cumulative Effect of Change in Accounting Policy			722			502			989
	Other Comprehensive Income		(169	)		(115	)		(12	)
Total Comprehensive Income			553			387			977
Basic Earnings per Common Share (dollars)			2.79			1.82			3.60
Diluted Earnings per Common Share (dollars)			2.78			1.81			3.59
Basic Earnings per Common Share After Cumulative Effect of Change in Accounting Policy (dollars)			2.63			1.82			3.60

In accordance with U.S. accounting standard FAS 130, a separate statement would be presented, which discloses the components of other comprehensive income:

($ millions)		2003			2002			2001
Other comprehensive income (loss), beginning of year			(115	)		(12	)		–
Increase (decrease):
	Cash flow hedge movements		–			19			(14	)
	Cash flow hedge movements – tax		–			(7	)		2
	Minimum additional pension liability		(66	)		(192	)		–
	Minimum additional pension liability – tax		12			77			–
Other Comprehensive Income (Loss)			(169	)		(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 2003, 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 $258 million (2002 – $192 million; 2001 – nil) would be reflected as a reduction of pension assets, with a corresponding reduction of the Company’s future income tax liability of $89 million (2002 – $77 million; 2001 – nil).

In compliance with FAS 133, in 2003 there would be reflected a derivative net liability of $2 million (2002 – $6 million net asset; 2001 – $18 million net liability).

32        SCHEDULE VI

Auditors’ Report    SHELL CANADA LIMITED

To the Shareholders of Shell Canada Limited:

Under date of January 30, 2004, we reported on the consolidated balance sheets of Shell Canada Limited as at December 31, 2003, 2002 and 2001 and the consolidated statements of earnings and retained earnings and cash flows for each of the three years in the period ended December 31, 2003, as incorporated by reference in the Annual Information Form with respect to the year ended December 31, 2003. In connection with our audits of the aforementioned consolidated financial 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.

          

Chartered Accountants
Calgary, Alberta
January 30, 2004

AUDITORS’ REPORT      33