Annual Information Form

Attached to this Annual Information Form is the Annual Report to shareholders for the year ended December 31, 2005 of Shell Canada Limited (Annual Report) and the Management Proxy Circular of the Corporation dated March 10, 2006 (Proxy Circular). Copies of these documents can also be found on the Corporation’s website at www.shell.ca and under Shell Canada’s profile at www.sedar.com.

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 and information pertaining to the appointment of auditors appears on pages 23 to 25 and page 21, respectively, of the Proxy Circular. The information contained therein, together with those sections of the Annual Report and Proxy Circular referenced herein, is specifically incorporated by reference into this Annual Information Form. Any sections of the Annual Report or Proxy Circular not referenced herein do not form part of this Annual Information Form.

INDEX

Corporate Structure	1
Name and Incorporation	1
Intercorporate Relationships	1
Capital Structure	1
General Development of the Business	2
Three-Year History	2
Trends	2
Narrative Description of the Business	3
Exploration & Production	3
Oil Sands	8
Oil Products	10
Competitive Conditions	12
Research and Development	12
Environmental Protection	12
Number of Employees	13
Foreign Operations	13
Risk Factors	13
Selected Consolidated Financial Information	14
Annual Information	14
Dividends	15
United States Generally Accepted Accounting Principles	15
Management’s Discussion and Analysis	16
Off-Balance Sheet Arrangements	16
Market for Securities and Transfer Agent	16
Directors and Officers	17
Majority Shareholder	18
Additional Information	19
Schedule I Oil and Gas Disclosure	20
Schedule II Oil Sands Mining Disclosure	22
Schedule III Report on Oil and Gas Reserves Data by Qualified Reserves Evaluator	28
Schedule IV Report on Minable Bitumen Reserves Data by Qualified Reserves Evaluator	30
Schedule V Report of Management and Directors on Oil and Gas Disclosure	31
Schedule VI United States Generally Accepted Accounting Principles and Reporting Practices	33
Auditors’ Reports	35

Corporate Structure

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, incorporated in 1911, and was continued under the Canada Business Corporations Act on May 1, 1978.

The Corporation’s articles or other establishing documents have been subject to the following material amendments: (i) Supplementary Letters Patent effective May 14, 1973 subdividing the Class “A” and Class “B” common shares of the Corporation on a three-for-one basis; (ii) Articles of Amalgamation effective January 1, 1986 reflecting the Corporation’s amalgamation with a wholly owned subsidiary, Shell Canada Resources Limited; (iii) Articles of Amendment effective June 1, 1989 converting the Class “B” common shares to Class “A” common shares on a four-for-one basis and deleting the Series “A” preferred shares; (iv) Articles of Amendment effective May 20, 1997 splitting the Class “A” common shares on a three-for-one basis; (v) Articles of Amalgamation effective July 1, 1998 reflecting the Corporation’s amalgamation with a wholly owned subsidiary, 177487 Canada Ltd.; (vi) Articles of Amendment dated May 2, 2000 redesignating the Class “A” common shares of the Corporation to common shares and deleting all references to Class “B” common shares; (vii) Restated Articles of Incorporation effective May 18, 2000 consolidating prior amendments; and (viii) Articles of Amendment effective June 6, 2005 subdividing the common shares on a three-for-one basis as of June 21, 2005.

The head and registered 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, is wholly owned and was incorporated under the Canada Business Corporations Act in 1982. Shell Canada Products Limited owns 99.99 per cent of the partnership units and is the managing partner of Shell Canada Products, a partnership governed by the laws of Alberta. The balance of the partnership units are held by a wholly owned subsidiary of the Corporation. Shell Canada Products is engaged in the manufacture, distribution and marketing of refined petroleum products.

The total revenues and total assets of the Corporation’s other operating subsidiaries, in the aggregate, represent less than 20 per cent of Shell’s total consolidated revenues and total consolidated assets, respectively.

CAPITAL STRUCTURE

The Corporation is authorized to issue an unlimited number of common shares, an unlimited number of four per cent cumulative redeemable preference shares and an unlimited number of preferred shares.

CORPORATE STRUCTURE      1  

General Development of the Business

Shell Canada, a large integrated petroleum company in Canada, operates principally in three industry segments: Exploration & Production (E&P), Oil Sands and Oil Products. The E&P 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, natural gas liquids, in situ bitumen and sulphur in Canada. The Oil Sands segment extracts 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.

THREE-YEAR HISTORY

2003   Shell Canada reported earnings of $810 million or $0.98 per common share (adjusted for the three-for-one share split of the issued and outstanding common shares that took effect on the Toronto Stock Exchange on June 21, 2005 (the share split)) compared with earnings of $555 million or $0.67 per share (adjusted for the share split) in 2002. The return on average capital employed (ROACE) of 13.1 per cent was a slight improvement over the previous year’s 10.1 per cent. Excluding the impact of Oil Sands capital, ROACE was a strong 25.5 per cent. E&P earnings in 2003 were $619 million compared with $382 million in 2002. Strong commodity prices and a gain of $32 million from the revaluation of future income taxes helped E&P achieve its best ever year, to date, in earnings. E&P capital, exploration and predevelopment expenditures were $385 million compared with $339 million in 2002. Oil Products earnings were $344 million in 2003, up from $197 million in 2002. The increase in earnings was due mainly to improved refinery margins. High transaction, pension and turnaround costs continued to put pressure on financial performance in 2003. Oil Products capital expenditures were $194 million compared with $433 million in 2002. Oil Sands reported positive earnings of $31 million during the last half of 2003, but a loss of production from a fire that occurred in January and the expensing of start-up costs led to a loss for the full year of $142 million. By the fourth quarter of 2003, bitumen production averaged 130,000 barrels per day or 84 per cent of design capacity. Oil Sands capital expenditures were $123 million compared with $1,460 million in 2002.

2004   Shell Canada reported earnings of $1,286 million or $1.56 per common share (adjusted for the share split) compared with earnings of $810 million or $0.98 per share (adjusted for the share split) in 2003. ROACE of 19.9 per cent was an improvement over the previous year’s 13.1 per cent. E&P earnings in 2004 were $449 million compared with $619 million in 2003. The decline in earnings was primarily attributed to lower production volumes, higher exploration expenses due to increased activity, higher depreciation charges for the Sable Offshore Energy Project (SOEP) and previously reported charges related to the expensing of Mackenzie Gas Project costs and changes in the Company’s Long Term Incentive Plan (LTIP). E&P capital, exploration and predevelopment expenditures were $451 million compared with $385 million in 2003. Oil Products earnings were $451 million in 2004, up from $344 million in 2003. The improvement was due to strong refining margins, higher prices for benzene and improved feedstock volumes from the integrated Oil Sands operations. Good refinery reliability throughout 2004 also contributed to the results. Oil Products capital expenditures were $313 million compared with $194 million in 2003. Oil Sands generated earnings of $378 million in 2004 versus a loss of $142 million in 2003 when the Athabasca Oil Sands Project (AOSP) was in start-up mode. Higher prices and volumes and lower unit costs were the main contributors to the earnings increase as AOSP production ramped up to design levels over the first nine months of 2004. However, production volumes decreased over the final three months of the year as a result of repair and maintenance activities at the Muskeg River Mine and the Scotford Upgrader. Oil Sands capital expenditures were $179 million compared with $123 million in 2003.

2005   For highlights of 2005, reference is made to the business sections in the Management’s Discussion and Analysis section of the Annual Report found on pages 18 to 58.

TRENDS

2006   Effective January 1, 2006, Oil Sands is responsible for Shell’s Peace River in situ bitumen business, which was previously reported in the E&P segment. For a discussion of the significant initiatives planned by the Company for 2006, reference is made to the business sections in the Management’s Discussion and Analysis section of the Annual Report found on pages 18 to 58.

2        GENERAL DEVELOPMENT OF THE BUSINESS

Narrative Description of the Business

EXPLORATION & PRODUCTION

Shell Canada has been engaged in the exploration 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, renamed in 2004 as Exploration & Production (E&P), became part of the operations of Shell Canada Limited. In 1999, Shell Canada sold its conventional crude oil producing interests.

Exploration & Production explores for, produces and markets natural gas, natural gas liquids, bitumen and sulphur. This upstream business operates four natural gas processing facilities in the Foothills of Alberta and, until December 31, 2005, an in situ bitumen facility near Peace River, Alberta. Effective January 1, 2006, the Peace River business was transferred to Shell Canada’s Oil Sands business. The Company also has a 31.3 per cent share of the Sable Offshore Energy Project, which produces natural gas and natural gas liquids off the coast of Nova Scotia.

The Corporation’s conventional oil and gas reserves disclosure and related information have 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 its reserves disclosure in accordance with the applicable requirements 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, it would be required to disclose proved plus probable oil and gas reserves estimates based on forecasted prices and costs and information relating to future net revenue using forecasted prices and costs.

Additional information related to E&P may be found on pages 29 to 36 of the Annual Report and in Schedule I and Schedule III on pages 20 and 21 and pages 28 and 29, respectively, of this Annual Information Form.

Principal Products

Shell Canada’s E&P 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 Canada sells the majority of its Western Canada natural gas production to 3095381 Nova Scotia Company, an affiliated company that operates as part of the Royal Dutch Shell plc global trading organization, 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 Canada, ExxonMobil Canada Properties, Imperial Oil Resources, Pengrowth Corporation and Mosbacher Operating Ltd. Shell’s equity 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 an affiliate, Coral Energy Canada Inc.

Natural Gas Liquids   Shell Canada is a major producer and marketer of natural gas liquids (ethane, propane, butane and condensate) in Canada. Natural gas liquids are used in a variety of petrochemical, refining, and diluent applications, with propane also being consumed by the transportation and space-heating sectors.

NARRATIVE DESCRIPTION OF THE BUSINESS      3  

Shell Canada has investments in shared 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.

Natural gas liquids production from these facilities is sold to both Canadian and U.S. markets. SOEP condensate production is shipped by marine tanker to North American markets.

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

Sulphur   Shell Canada is one of the world’s largest sulphur producers and marketers with over 40 per cent of Canadian sulphur sales, and approximately 20 per cent of world sulphur sales. Shell markets sulphur primarily to export markets. China, U.S., Australia and Brazil represent Shell’s four largest export markets. 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 in dry bulk cargo vessels to overseas markets.

Revenues by Product

Reference is made to the “Segmented Information” note to the consolidated financial statements on pages 68 to 71 of the Annual Report.

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

Natural Gas (%)	2005		2004		2003
Sales to third parties		14		13		14
Sales to related parties		86		87		86
Total natural gas sales		100		100		100

Natural Gas Liquids (%)	2005		2004		2003
Sales to third parties		93		96		98
Sales to related parties		7		4		2
Total natural gas liquids sales		100		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 four areas: gas fields in the deep foothills and the deep basin region of Western Canada, the Peace River bitumen deposit, and the gas fields near Sable Island, offshore Nova Scotia. Shell’s exploration program continues to focus on exploring for new reserves in the Western Canada Sedimentary Basin (WCSB), and maintains exploration interests off the East and West coasts of Canada and in the Mackenzie Delta. The Company has acquired significant additional land positions in both northeast British Columbia and the deep basin region of Western Canada. In March 2005, Shell acquired a 20 per cent interest in eight exploration licences in the Orphan Basin located in the deepwater region offshore Newfoundland and Labrador. A seismic program was undertaken in the Orphan Basin during 2005 and an exploratory well is planned for 2006. The Company announced the Tay River discovery in 2004. Tay River began production in May of 2005 and by year-end had the highest gas flow rate of any well in Canada. Two more wells are planned for 2006, one to delineate the original discovery and the other to test a new structure.

4        NARRATIVE DESCRIPTION OF THE BUSINESS

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. However, in 2005 prices for natural gas remained strong throughout the first nine months of the year. In the fourth quarter, prices increased further due to production shortages created by hurricanes Katrina and Rita.

Drilling Activity

Reference is made to the “Exploration and Development Wells Drilled” table and as well the “Productive Wells” table on page 85 of the Annual Report.

Present Activity

Reference is made to the “Exploration and Development Wells Drilled” table on page 85 of the Annual Report.

Location of Production

Shell Canada operates and has substantial interests in natural gas plants in Alberta and has substantial interests in natural gas plants in Nova Scotia, which process approximately 80 per cent of its current sales volumes. The remaining sales volumes are processed in other natural gas processing plants in Alberta, in which Shell Canada has varying interests or to which it has access under 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		59
Jumping Pound		100		151		73
Burnt Timber		82		95		91
Caroline		72		129		83
Wildcat Hills (outside-operated)		34		113		86
Goldboro (outside-operated)		31		565		67

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 2005.

Shell also has interests in three major outside-operated natural gas liquids fractionation and storage facilities.

NARRATIVE DESCRIPTION OF THE BUSINESS      5  

            NGL Fractionation/Storage

		Shell Canada’s		Shell Share		Shell Share
		Interest		Capacity		Utilization 1
		(%)		(thousands of barrels per day)		(%)
Fort Saskatchewan, Alberta
	De-ethanizer		44		31		68
	Fractionator		42		13		47
Sarnia, Ontario
	Fractionator		13		15		95
Point Tupper, Nova Scotia
	Fractionator		31		10		63

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		In Situ Bitumen Production
Alberta		Alberta
Burnt Timber	Caroline	Peace River
Clearwater	Jumping Pound
Limestone	Moose/ Whiskey
Panther River	Waterton
Wildcat Hills	Tay River
Nova Scotia
Alma	North Triumph
Thebaud	Venture
South 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 85 of the Annual Report.

Interest in Material Properties

Reference is made to the “Landholdings” table on page 90 of the Annual Report.

Reserves Estimates

Reference is made to the “Reserves” section on pages 86 and 87 of the Annual Report and to Schedule I on pages 20 and 21 of this Annual Information Form.

6        NARRATIVE DESCRIPTION OF THE BUSINESS

Source of Reserves Estimates

Reserves estimates are prepared by the Corporation’s internal qualified reserves evaluators. No independent qualified reserves evaluator or auditor was involved in the preparation of the Corporation’s reserves data. An external, independent petroleum consulting firm audited 100 per cent of the proved oil and gas estimates prepared by the Corporation’s internal reserves evaluators and verified compliance with applicable FASB and SEC requirements.

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, members of senior management in the E&P segment and the Reserves Committee prior to submission of the estimates to the Board of Directors for approval.

The Reserves 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 Reserves Committee are independent, outside directors and are not related to the Corporation or to its majority shareholder.

Reference is also made to Schedule III and Schedule V on pages 28 and 29 and pages 31 and 32, respectively, of this Annual Information Form.

Reconciliation of Reserves

Reference is made to the “Reserves” section on pages 86 and 87 of the Annual Report.

History

Reference is made to the “Production” table on page 84 of the Annual Report.

REVENUE

Natural Gas ($/mcf)

		2005		2004		2003
Average plant gate price			8.23		6.49		6.46
Royalties			1.70		1.19		1.18
Operating expenses
	Plant and field		1.07		0.83		0.80
	Head office		0.61		0.46		0.26
Total operating expenses			1.68		1.29		1.06
Netback			4.85		4.01		4.22

NARRATIVE DESCRIPTION OF THE BUSINESS      7  

Ethane, Propane and Butane ($/bbl)

		2005		2004		2003
Average plant gate price			34.79		28.71		25.48
Royalties			6.98		5.41		4.73
Operating expenses
	Plant and field		6.43		5.00		4.82
	Head office		3.63		2.78		1.56
Total operating expenses			10.06		7.78		6.38
Netback			17.75		15.52		14.37

Condensate ($/bbl)

		2005		2004		2003
Average plant gate price			66.76		50.46		41.13
Royalties			15.22		11.07		8.87
Operating expenses
	Plant and field		6.43		5.00		4.82
	Head office		3.63		2.78		1.56
Total operating expenses			10.06		7.78		6.38
Netback			41.48		31.61		25.88

Sales Commitments

Volume (millions of boe1)	Source of Production
183.82	Western Canada Sedimentary Basin
22.05	Sable Offshore Energy Project

¹  Barrels of oil equivalent (boe) may be misleading, particularly if used in isolation. A boe conversion of six thousand cubic feet of natural gas to one barrel of oil, as used in this Annual Information Form, is based on the energy equivalency conversion method primarily applicable at the burner tip 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 20 and 21 of this Annual Information Form.

Additional information related to exploration and development activities may be found on pages 29 to 36 of the Annual Report.

OIL SANDS

In 2005, the Athabasca Oil Sands Project (AOSP) completed its second full year of integrated operations. 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 Muskeg River Mine and the Scotford Upgrader.

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. Albian Sands Energy Inc. operates the mine and extraction plant.

8        NARRATIVE DESCRIPTION OF THE BUSINESS

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 Scotford Upgrader.

The AOSP is a fully integrated operation with the Corridor Pipeline carrying diluted bitumen from the Muskeg River Mine to the Scotford Upgrader where it is processed into synthetic crude oil products. The majority of the synthetic crude produced at the Scotford Upgrader is supplied to Shell Canada’s Scotford Refinery, with the remainder moved by pipeline to markets throughout Canada and the United States.

Production of 159,900 barrels per day (bpd) was achieved in 2005, including a record quarterly production level of 178,000 bpd achieved in the fourth quarter of 2005. Shell Canada’s share of bitumen production for the year was approximately 35 million barrels.

The primary objectives for the AOSP over the next few years will be volume growth by improving plant reliability as well as selective investments in debottlenecking and production optimization initiatives. Operations will also focus on continuous improvement in unit operating costs and product values.

The Corporation’s minable 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 forecasted prices and costs.

Additional information related to Oil Sands may be found on pages 37 to 44 of the Annual Report and in Schedule II and Schedule IV on pages 22 to 27 and page 30, respectively, of this Annual Information Form.

Revenues by Product

Reference is made to the “Segmented Information” note to the consolidated financial statements on pages 68 to 71 of the Annual Report.

The following table sets out the percentage of revenues by customer:

Synthetic Crude Sales (%)	2005		2004		2003
Inter-segment sales		54		54		53
Sales to third parties		41		44		44
Sales to related parties		5		2		3
Total synthetic crude oil sales		100		100		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 90 of the Annual Report.

NARRATIVE DESCRIPTION OF THE BUSINESS      9  

Reserves Estimates

Reference is made to the “Reserves” section on page 89 of the Annual Report.

Source of Reserves Estimates

Minable 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 minable bitumen reserves data. The reserves estimates prepared by the Chief Mining Engineer are reviewed by the Chief Executive Officer, members of senior management in the Oil Sands segment and the Reserves Committee prior to submission of the estimates to the Board of Directors for approval.

The Reserves 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 Reserves Committee are independent, outside directors and are not related to the Corporation or to its majority shareholder.

Reference is also made to Schedule IV and Schedule V on page 30 and pages 31 and 32, respectively, of this Annual Information Form.

Reconciliation of Reserves

Reference is made to the “Reserves” section on page 89 of the Annual Report.

History

Reference is made to the “Production” table on page 88 of the Annual Report.

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

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. 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 45 to 52 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 leased railway tank cars 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

10        NARRATIVE DESCRIPTION OF THE BUSINESS

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 2005 (2004 – 17 per cent; 2003 – 17 per cent).

The total number of Shell-branded retail sites at year-end 2005 was 1,599 (2004 – 1,661; 2003 – 1,693). The private-brand network consists of 82 retail sites (2004 – 101; 2003 – 116).

Revenues by Product

Reference is made to the “Segmented Information” note to the consolidated financial statements on pages 68 to 71 of the Annual Report.

Shell Canada sells 100 per cent of gasoline and middle distillates volumes to third parties.

Source and Availability of Raw Materials

Shell Canada’s crude oil requirements were supplied from three major sources as shown in the table below. The majority of purchases were done through an affiliated company of Royal Dutch Shell plc. The definition of crude oil includes Scotford Upgrader feedstocks from the AOSP.

Crude Oil Requirements (%)	2005		2004		2003
Domestic industry production		25		36		39
Shell Canada’s own production		30		27		15
Imported production		45		37		46
Total crude oil requirements		100		100		100

Seasonality

There were no significant seasonal fluctuations in the overall Oil Products business over the year and historically there have been no multi-year cycles.

Manufacturing

Shell Canada’s three operating refineries located at Sarnia, Ontario; Montreal, Quebec; and Fort Saskatchewan, Alberta achieved average utilization rates of 87 per cent in 2005 (2004 – 89 per cent; 2003 – 90 per cent).

Shell Canada’s refineries continue to account for approximately 16 per cent (2004 – 16 per cent; 2003 – 16 per cent) of Canada’s operating refinery capacity in 2005. The location and rated capacity of each of Shell’s refineries at December 31, 2005 are shown below.

	Daily Rated Capacity 1
Refinery	(cubic metres)		(barrels)
Montreal East (Quebec)		20 700		130 000
Sarnia (Ontario)		12 000		76 000
Scotford (Alberta)		18 900		118 000
Total		51 600		324 000

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.

NARRATIVE DESCRIPTION OF THE BUSINESS      11  

In 2005, Shell’s lubricant blending and packaging plant in Brockville, Ontario, produced 177 million litres of lubricants. This represents an increase of 1.7 per cent over 2004 volumes. The Calgary grease manufacturing facility produced 3.3 million kilograms of soap-based and microgel-based greases in 2005. The introduction of North American Aeroshell Grease production helped increase volumes by 10 per cent over the prior year for the second year in a row.

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 the E&P segment, 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 the Company based on market conditions and are subject to international competition.

In the Oil Sands segment, the Company has extensive leaseholdings adjacent to the initial Muskeg River Mine development. The other joint venture parties with interests in the initial Muskeg River Mine development have the option to participate in the future development of Shell’s other existing Athabasca oil sands leases. Shell Canada, in turn, has the option to participate in leases purchased by the other joint venture parties.

The Investment Canada Act requires Shell Canada, a statutory non-Canadian and World Trade Organization investor, to notify Industry 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 $250 million in 2005 was reviewable (2006 – $265 million), 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. To date, Shell Canada has not been adversely impacted by this legislation.

In the Oil Products segment, market conditions and site economics of retail outlets support a continued asset rationalization program by the Company to improve operating efficiencies within its network.

RESEARCH AND DEVELOPMENT

Research and development expense was $41 million in 2005 (2004 – $28 million; 2003 – $10 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 identification and control of HSE-related hazards arising from the Company’s operations and/or from the areas in which it operates. The Company’s E&P business has met the criteria for multi-site registration of its facilities and operations to International Standards Organization (ISO) 14001. All major facilities in the Oil Products manufacturing business and the Oil Sands business (Muskeg River Mine and Scotford Upgrader) are also registered to this international environmental management standard.

12        NARRATIVE DESCRIPTION OF THE BUSINESS

Total environmental expenditures for Shell Canada in 2005 and the previous two years are shown in the following table:

Environmental Expenditures ($ millions)	2005		2004		2003
Operating costs		89		70		80
Capital costs		313		168		25
Restoration and reclamation		37		40		52
Total		439		278		157

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. Total environmental fines and penalties paid in 2005 did not exceed $1,000.

Capital costs   These include the cost of new equipment and associated construction costs for pollution prevention and controlling air emissions, water discharges and waste management. A significant portion of the capital spent in 2005 was on the ultra-low-sulphur diesel (ULSD) project ($242 million) at Shell’s Montreal East and Scotford refineries and the Superclaus project at Jumping Pound ($25 million). The ULSD project is designed to provide product that can meet new legislated sulphur levels in automotive tailpipe emissions. The Superclaus project at Jumping Pound was designed to improve overall facility sulphur recovery from 97% to 98%. The facility is currently realizing a 98.2% recovery with an expected long-term recovery of 98.4%.

Restoration and reclamation   This includes the costs of spill cleanup, decommissioning and restoration and the protection or restoration of wildlife and habitat.

NUMBER OF EMPLOYEES

The number of employees at the end of 2005 was 4,564 compared with 4,003 at the end of 2004. The number of employees in each segment is as follows:

Number of Employees
As at December 31	2005		2004		2003
E&P		1 000		904		859
Oil Products		2 078		1 921		1 930
Oil Sands		665		505		434
Corporate*		821		673		627
Total		4 564		4 003		3 850

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

FOREIGN OPERATIONS

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

RISK FACTORS

Reference is made to the Risk Management Sections on pages 26, 36, 44, 52 and 58 of the Annual Report.

NARRATIVE DESCRIPTION OF THE BUSINESS      13  

Selected Consolidated Financial Information

ANNUAL INFORMATION

Total Revenue

Reference is made to the “Consolidated Statement of Earnings and Retained Earnings” table, “Revenues” section on page 62 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 62 and the “Data Per Common Share” table on page 91 of the Annual Report.

Total Assets

Reference is made to the “Consolidated Balance Sheet” table on page 64 of the Annual Report.

Long-Term Financial Liabilities

Reference is made to the “Consolidated Balance Sheet” table on page 64 of the Annual Report.

Cash Dividends Declared Per Share

Reference is made to the “Data Per Common Share” table on page 91 of the Annual Report.

Factors Affecting Comparability

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.

2004   Shell Canada’s modification to the existing options under the Long Term Incentive Plan (LTIP) resulted in an $82 million charge to earnings where share appreciation rights were attached. In its first full year of production, Oil Sands contributed $378 million to income. Due to the degree of uncertainty in terms of timing and realization of future benefits, the Company wrote off $32 million after-tax of front-ended expenditures related to the Mackenzie Gas Project. The Company’s earnings were impacted by a number of significant dry hole write-offs, which included the Weymouth well for $28 million and the Onondaga well for $15 million. Oil Products earnings included a provision of $25 million for increased liability associated with the AIR MILES^® Reward Miles program.

2005   The impact of the Company’s LTIP resulted in a $173 million charge to earnings due to strong appreciation in the share price during the year. The use of non-capital losses increased earnings by $164 million in 2005 and, along with proceeds from insurance settlements of $94 million, outweighed the effect of the higher LTIP charge. The Company also recorded a favourable tax settlement of $64 million related to prior year returns.

^®  Trademark of AIR MILES International Trading B.V. Used under license by Loyalty Management Group Canada Inc. and Shell Canada Products.

14        SELECTED CONSOLIDATED FINANCIAL INFORMATION

Trading Price and Volume

Reference is made to the “Stock Trading Information” table on page 91 of the Annual Report.

The monthly financial and stock trading information as quoted on the Toronto Stock Exchange for 2005 is as follows:

            Share Price (Dollars)

	Jan		Feb		Mar		Apr		May		Jun		Jul		Aug		Sep		Oct		Nov		Dec		Total
High		26.75		28.60		31.67		29.90		29.32		34.39		36.00		40.09		41.62		41.25		37.75		42.35		42.35
Low		25.26		25.11		28.33		26.84		26.84		28.88		33.30		35.54		38.70		32.45		32.60		34.68		25.11
Close		26.13		28.52		29.00		28.07		28.87		32.89		35.83		38.50		40.65		32.88		34.96		42.05		42.05
Volume (000)		6 195		15 924		9 898		8 439		5 614		7 908		7 317		8 225		6 819		9 921		7 032		6 767		100 059

Credit Ratings

Reference is made to page 55 of the Annual Report.

DIVIDENDS

Dividends are declared at the discretion of the Board of Directors of the Corporation. At the annual and special meeting of shareholders held April 29, 2005, the Company’s shareholders approved a three-for-one share split, which took effect on the Toronto Stock Exchange on June 21, 2005. In 2005, dividends declared and paid for the year totalled $0.367 per common share (adjusted for the share split), up from $0.313 per share in 2004.

Reference is made to the “Summary of Quarterly Results” table and to the “Selected Annual Financial Information” table on page 19 of the Annual Report.

UNITED STATES GENERALLY ACCEPTED ACCOUNTING PRINCIPLES

Oil and Gas Disclosure

Disclosure, in accordance with Statement No. 69 of the United States Financial Accounting Standards Board (FASB), appears in Schedule I on pages 20 and 21 of this Annual Information Form.

United States Generally Accepted Accounting Principles

The significant differences between Canadian and United States generally accepted accounting principles (GAAP) are identified on pages 33 and 34 of this Annual Information Form.

Accounting Policy

Exchange Transactions The Corporation enters into exchange transactions for inventory held for sale in the ordinary course of its business to balance regional supply and demand, increase transportation efficiencies and reduce overall cost of acquiring inventory. These transactions are accounted for using Accounting Principles Board Opinion No. 29 Accounting for Nonmonetary Transactions and are netted in cost of goods sold. These transactions do not have a material impact on the Corporation’s earnings.

The Emerging Issues Task Force (EITF) reached a consensus regarding EITF Issue No. 04-13 Accounting for Purchases and Sales of Inventory with the Same Counterparty that a nonmonetary exchange whereby an entity transfers (a) raw materials or work in process (WIP) for raw materials or WIP or (b) finished goods inventory for finished goods inventory, should not be recognized at fair value. This EITF does not impact the Corporation’s current accounting treatment for nonmonetary exchange transactions.

SELECTED CONSOLIDATED FINANCIAL INFORMATION      15  

Exploratory Drilling Costs

Pursuant to FASB Statement No. 19 Financial Accounting Reporting by Oil and Gas Producing Companies, the Company’s exploratory drilling costs related to exploratory wells in an area that requires major capital expenditures are carried as an asset, provided that (a) there have been sufficient oil and gas reserves found to justify completion as a producing well if the required capital expenditure is made, and (b) drilling of additional exploratory wells is underway or firmly planned for the near future. The determination of whether or not reserves are sufficient is subject to establishing, through a well test, the volume of hydrocarbons that can be economically produced.

The following table provides the net change in capitalized exploration well costs:

($ thousands)	2005			2004			2003
Beginning balance at January 1		44 106			68 102			59 088
Additions to exploratory well costs pending the determination of proved well reserves		57 977			101 790			72 295
Reclassification to well, facilities, and equipment based on the determination of proved reserves		(29 777	)		(11 157	)		(21 179	)
Exploratory well costs charged to expense		(34 596	)		(114 629	)		(42 102	)
Ending balance at December 31		37 710			44 106			68 102

New United States Generally Accepted Accounting Principles

In December 2004, FASB Statement No. 123(R) Stock-Based Payment was issued. Pursuant to the U.S. Securities and Exchange Commission’s Final Rule Release dated April 21, 2005, registrants that are not a small business issuer are required to prepare financial statements in accordance with FASB Statement No. 123(R) beginning with the first interim or annual reporting period of the registrant’s first fiscal year beginning on or after June 15, 2005. Effective for 2006, all stock options will be accounted for using the fair value method. The impact of adopting this standard is dependent upon a number of valuation factors including the share price at December 31, 2006. Based on Shell Canada’s share price at December 31, 2005, it is estimated that there would be an increase of approximately $20 million before taxes in U.S. GAAP earnings.

Management’s Discussion and Analysis

Reference is made to pages 18 to 58 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. Effective January 1, 2005, the Corporation adopted Accounting Guideline 15 Consolidation of Variable Interest Entities. The standard mandates that certain entities should be consolidated by the primary beneficiary. Accordingly, the Corporation has consolidated the lease arrangement for large mobile equipment. Reference is made to the “Accounting Policies” note on page 65 of the Annual Report.

The Corporation has sold accounts receivable under an accounts receivable securitization program. In 2005, this $600 million program was reduced to zero and the Corporation elected to terminate the program.

Both of these arrangements were cost-effective to the Corporation versus its alternatives.

Market for Securities and Transfer Agent

Reference is made to “Investor Information” on page 102 of the Annual Report.

16        SELECTED CONSOLIDATED FINANCIAL INFORMATION

Directors and Officers

Reference is made to the “Corporate Directory and Board of Directors” table on pages 92 to 95 of the Annual Report, the “Corporate Governance Practices” section on pages 96 to 101 of the Annual Report and pages 56 to 69 of the Proxy Circular and the “Election of Directors” section on pages 7 to 21 of the Proxy Circular.

The following were officers of the Corporation as at December 31, 2005:

Name and Municipality of Residence	Position and Office1
Clive Mather Calgary, Alberta, Canada	President and Chief Executive Officer
H. Ian Kilgour Calgary, Alberta, Canada	Senior Vice President, Exploration & Production
Brian E. Straub Calgary, Alberta, Canada	Senior Vice President, Oil Sands
David M. Weston Calgary, Alberta, Canada	Senior Vice President, Oil Products
Cathy L. Williams Calgary, Alberta, Canada	Chief Financial Officer
David Fulton Calgary, Alberta, Canada	General Manager, Human Resources
Graham Bojé Calgary, Alberta, Canada	Vice President, Manufacturing and Supply
Rob W.P. Symonds Calgary, Alberta, Canada	Vice President, Foothills
Timothy J. Bancroft Calgary, Alberta, Canada	Vice President, Sustainable Development, Technology and Public Affairs
Sam Spanglet Calgary, Alberta, Canada	Vice President, Operations, Oil Sands
Matthew B. Haney Calgary, Alberta, Canada	Treasurer
Donna Tarka Calgary, Alberta, Canada	Controller
Richard W. Riegert Calgary, Alberta, Canada	Acting Head of Legal, Associate General Counsel, E&P and Assistant Secretary
Susan S. Boughs Calgary, Alberta, Canada	Chief Compliance Officer, Associate General Counsel, Regulatory & Compliance and Assistant Secretary
Shannon L. Cosmescu Calgary, Alberta, Canada	Acting Corporate Secretary, Associate General Counsel, Corporate and Assistant Secretary
John T.D. Courtright Calgary, Alberta, Canada	Associate General Counsel, Oil Sands and Assistant Secretary
Leanne D. Geale Calgary, Alberta, Canada	Associate General Counsel, Oil Products and Assistant Secretary

¹  All of these officers of the Corporation have, for the past five years, been actively engaged in executive or employee capacities with the Corporation or its affiliates, except for Leanne Geale who was previously employed during this period as Counsel and Assistant Secretary for Rio Algom Limited until 2002 and Senior Counsel with the Royal Bank of Canada from 2002 to 2003.

The percentage of common shares of the Corporation owned beneficially, directly or indirectly, or over which control or direction is exercised by the directors, senior officers and any expert whose report is contained in this Annual Information Form, as a group, is less than one per cent.

DIRECTORS AND OFFICERS      17

The Corporation has five committees of the Board of Directors. Reference is made to pages 96 to 101 of the Annual Report for a discussion of the Corporation’s corporate governance practices.

Reference is made to “Interest of Informed Persons in Material Transactions” on page 48 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.

Majority Shareholder

Until July 20, 2005, Royal Dutch Petroleum Company (Royal Dutch), a Netherlands company, and The “Shell” Transport and Trading Company, plc (Shell T&T), an English company, (together referred to as Royal Dutch/ Shell) held, indirectly, approximately 78 per cent of the Corporation’s common shares. On July 20, 2005, Royal Dutch and Shell T&T were unified following receipt of shareholder approval and the satisfaction of applicable legal conditions. The unified entity, Royal Dutch Shell plc, holds, indirectly, approximately 78 per cent of the Corporation’s common shares. Royal Dutch Shell plc is an English company with headquarters in the Netherlands.

On July 29, 2004, Royal Dutch/ Shell reached agreements in principle with the United Kingdom’s Financial Services Authority (FSA) and the staff of the United States Securities and Exchange Commission (SEC) to resolve their pending inquiries related to Royal Dutch/ Shell’s reserves recategorization.

In connection with the agreement in principle with the FSA, Royal Dutch/ Shell agreed, without admitting or denying the FSA’s findings or conclusions, to the entry of a Final Notice by the FSA finding that Royal Dutch/ Shell breached market abuse provisions of the United Kingdom’s Financial Services and Markets Act 2000 and the Listing Rules made thereunder. In connection with the proposed settlement, Royal Dutch/ Shell paid a penalty of £17 million.

In connection with the agreement in principle with the SEC, Royal Dutch/ Shell consented, without admitting or denying the SEC’s findings or conclusions, to an administrative order finding that Royal Dutch/ Shell violated, and requiring Royal Dutch/ Shell to cease and desist from future violations of, the antifraud, reporting, recordkeeping and internal control provisions of the U.S. Federal securities laws and related SEC rules. In connection with the proposed settlement, Royal Dutch/ Shell paid a U.S. $120 million civil penalty and undertook to spend an additional U.S. $5 million developing a comprehensive internal compliance program.

18        DIRECTORS AND OFFICERS

Additional Information

AVAILABILITY OF DOCUMENTS

Copies of the following documents are available upon request from the Corporation’s Secretary: the Annual Information Form for 2005, together with the documents incorporated by reference therein; the Proxy Circular for the most recent annual meeting of shareholders; the Corporation’s Annual Report containing comparative financial statements for 2005, together with the Auditors’ Report thereon; and the Management’s Discussion and Analysis and interim financial statements filed subsequent to December 31, 2005.

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 a 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 and options to purchase securities is contained in the Proxy Circular. Additional financial information is provided in the Corporation’s comparative financial statements and Management’s Discussion and Analysis for its most recently completed financial year.

Additional information relating to Shell Canada filed with Canadian and U.S. securities regulatory authorities, including this Annual Information Form and the Form 40-F, can be found online under Shell Canada’s profile at www.sedar.com and www.sec.gov.

ADDITIONAL INFORMATION      19  

Schedule I

(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 Exploration & Production on page 3 of this Annual Information Form for a discussion of these differences.

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

As at December 31 ($ millions)	2005		2004		2003
CAPITALIZED COSTS
Unproved oil and gas reserves		426		209		191
Proved oil and gas reserves		5 442		4 877		4 600
		5 868		5 086		4 791
Accumulated depreciation, depletion and amortization		3 231		3 016		2 539
Net capitalized costs		2 637		2 070		2 252

Year ended December 31 ($ millions)	2005		2004		2003
COSTS INCURRED
Property acquisition		260		26		12
Exploration costs		146		171		118
Development costs		542		323		301
Total costs incurred		948		520		431

Year ended December 31 ($ millions)
RESULTS OF OPERATIONS FROM PRODUCING ACTIVITIES
Revenues	2 799	2 361	2 298
Operating expenses	961	749	691
Transportation expenses	331	309	270
Exploration and predevelopment expenses	156	221	81
Depreciation, depletion, amortization and retirements	366	353	282
Income tax	336	275	346
Results of operations from producing activities	649	454	628

20        SCHEDULE I

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 or fair 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 minable bitumen activities.

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

As at December 31 ($ millions)		2005			2004			2003
FUTURE NET CASH FLOWS
Future cash inflow			15 281			10 776			13 892
Future operating and development costs			4 596			4 029			5 858
Future income taxes			3 392			2 045			2 500
Future net cash flows1			7 293			4 702			5 534
10% annual discount for estimated timing of cash flows			2 624			1 720			2 325
Standardized measure of discounted future net cash flows from proved oil and gas reserves			4 669			2 982			3 209
CHANGES IN FUTURE NET CASH FLOWS
Balance at beginning of year			2 982			3 209			3 689
Changes resulting from:
	Sales, net of operating costs		(1 528	)		(1 016	)		(1 073	)
	Net changes in prices, development and operating costs		2 212			(226	)		(457	)
	Extensions, discoveries and improved recoveries, less related costs		1 065			597			224
	Development costs incurred during the period		509			319			295
	Revisions of previous quantity estimates		(101	)		(265	)		(809	)
	Purchases (sales) of reserves in place		53			(173	)		–
	Accretion of discount		348			382			499
	Net changes in income taxes		(871	)		155			841
Net increase (decrease) for the year			1 687			(227	)		(480	)
Balance at end of year			4 669			2 982			3 209

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.

Since the beginning of the Company’s 2005 fiscal year, the Company has not filed or furnished reserves estimates with any authority or agency of the United States other than the U.S. Securities and Exchange Commission.

SCHEDULE I      21  

Schedule II

OIL SANDS MINING DISCLOSURE

Muskeg River Mine Development History

Shell Canada holds a 60 per cent interest in the Athabasca Oil Sands Project (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 fully integrated operations in June 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 cleanup 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 located in the Edmonton area of central Alberta. The current facility’s original design rate is 155,000 barrels per day of bitumen production, with opportunities to expand production to approximately 270,000 barrels per day. These facilities are in new condition, having commenced operations in June of 2003, and processed 58 million barrels of bitumen in 2005 (159,900 barrels per day). 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 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 minable bitumen resources and each have a lease expiry date of August 31, 2008. During 2004, Shell Canada acquired two additional minable oil sands leases in the general vicinity of the MRM development from EnCana Corporation. These are Leases 7400120009 (Lease 9) and 7401100017 (Lease 17). Both leases have lease expiry dates of December 31, 2015. During 2005, Shell Canada also acquired seven additional minable oil sands leases through Alberta Crown land sales. These leases are shown in table below and have lease expiry dates in 2020.

Athabasca West		Athabasca East
Lease 309	7405120309	Lease 015	7405120015
Lease 310	7405120310	Lease 631	7405090631
Lease 351	7405080351	Lease 632	7405090632
Lease 352	7405080352

Shell Canada also completed two exchanges in 2005. The respective Asset Exchange Agreements have been executed however the exchanged lease areas have yet to be registered with the Alberta Department of Energy. All lease holdings are shown in Figure 2. All of these lease holdings may be extended by completing a minimum level of development prior to their expiry. There are no current, and

22        SCHEDULE II

no known previous, commercial operations on any of these lease holdings. The MRM, together with Lease 13 and the adjacent and acquired oil sands leases, represent a multi-billion dollar investment for Shell Canada.

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 online 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);
5.	Muskeg River Mine 10-year Environmental Protection and Enhancement Act Approval No. 20809-00-01 from AENV dated June 18, 1999 (available online 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 online at www.gov.ab.ca/env/water/ approvalviewer.html search parameter — Albian Sands Energy Inc.).

On September 21, 2004, Shell Canada disclosed a description of plans to expand the capacity of the existing Muskeg River Mine. A regulatory application and environmental impact assessment for a Muskeg River Mine expansion to approximately 270,000 barrels per calendar day of bitumen production was filed with the regulatory agencies in April 2005. It is available on-line at www.shell.ca/oilsands. Regulatory approval is targeted for mid-2006 when an investment decision regarding the proposed expansion is planned to be taken.

The EUB has also provided Shell Canada with approval for Phase 1 of the proposed Jackpine Mine, a mining and extraction development to be located on the eastern portion of Lease 13. The Jackpine Mine Approval No. 9756 Order in Council was issued by the EUB on February 25, 2004. The Jackpine Mine 10-year Environmental Protection and Enhancement Act Approval No. 153125-00-00 from AENV was issued on June 23, 2004. Site development activities commenced in late 2005 with major plant construction to be underway in late 2006. The planned development for the Jackpine Mine will include appropriate integration with the existing Muskeg River Mine base development and the potential to also extend development to Leases 88 and 89. Additional regulatory approval will be required for the incorporation of Leases 88 and 89, as well as the future integration of the other growing inventory of additional area lease holdings.

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 five 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 millimetres, this is characterized as oil sands.

SCHEDULE II      23  

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 minable. Within this area, the McMurray Formation is near 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 surface.

Muskeg River Mine Reserves

Reference is made to the “Reserves” section on page 89 of the Annual Report and to Schedule IV on page 30 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.

The ultimate pit limits and mine plans were updated in 2005 to incorporate the results from the development drilling in 2004 and 2005. This represented an update relative to the original mine plans. Total reserves continue to be defined based on the original premise of a 30-year development plan.

Figure 3 shows the mining areas associated with the designated reserves for the Muskeg River Mine. Figure 4 shows the core hole coverage for those same areas.

Location of the Muskeg River Mine

24        SCHEDULE II

Lease Holdings

SCHEDULE II      25  

Muskeg River Mine Reserves Areas

26        SCHEDULE II

Muskeg River Mine Core Hole Coverage

SCHEDULE II      27  

Schedule III

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 my staff, I have evaluated the Company’s reserves data as at December 31, 2005. The reserves data consist of the following:

(a)	proved oil and gas reserves estimated as at December 31, 2005, 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, 2005:

		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	$4,669 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.

28        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 P. Eng.
           Chief Reservoir Engineer


           January 31, 2006

SCHEDULE III      29  

Schedule IV

FORM 51-101F2

Report on Minable Bitumen Reserves Data by Qualified Reserves Evaluator

To the Board of Directors of Shell Canada Limited (the Company):

1.	Together with my staff, I have evaluated the Company’s reserves data as at December 31, 2005. The reserves data consist of proved and probable minable bitumen reserves estimated as at December 31, 2005.
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 P. Eng.
           Chief Mining Engineer


           January 31, 2006

30        SCHEDULE IV

Schedule V

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, 2005, using constant prices and costs; and

(ii)  the related estimated future net revenue; and

(b) proved and probable minable bitumen reserves estimated as at December 31, 2005.

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 Reserves 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;
(c)	reviewed the reserves data with management and the internal qualified reserves evaluators; and
(d)	reviewed the report of an external, independent petroleum consulting firm on its audit of 100 per cent of the Company’s proved oil and gas reserves.

The Reserves 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 Reserves 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.

For 2005, notwithstanding this exemptive relief, the Company also received a report of an external, independent petroleum consulting firm on its audit of 100 per cent of the Company’s proved oil and gas reserves. This report reached a conclusion that is not materially different from the report prepared by our Chief Reservoir Engineer.

In our view, the reliability of the internally generated reserves data is not materially less than would be afforded by our involving this firm or would be afforded by our involving any other independent qualified reserves evaluators or independent qualified reserves

SCHEDULE V      31  

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 27 persons with an average of 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 26 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 Reserves 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.

CLIVE MATHER

President and Chief Executive Officer

CATHY L. WILLIAMS

Chief Financial Officer

KERRY L. HAWKINS

Director

DAVID W. KERR

Director

March 10, 2006

32        SCHEDULE V

Schedule VI

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   FASB Statement No. 133 requires that hedging activity that does not qualify as a hedge, be mark-to-market and charged to earnings.

Stock-Based Compensation   FASB Statement No. 123 requires performance-based options to be charged to earnings. Shell Canada adopted the new Canadian standard requiring the expensing of stock options prospectively in 2003.

In December 2004, FASB Statement No. 123(R) Stock-Based Payment was issued. Pursuant to the U.S. Securities and Exchange Commission’s Final Rule Release dated April 21, 2005, registrants that are not a small business issuer are required to prepare financial statements in accordance with FASB Statement No. 123(R) beginning with the first interim or annual reporting period of the registrant’s first fiscal year beginning on or after June 15, 2005. Effective for 2006, all stock options will be accounted for using the fair value method. The impact of adopting this standard is dependent upon a number of valuation factors including the share price at December 31, 2006.

Asset Retirement Obligations   FASB Statement No. 143 became effective in 2003. This standard required the recognition of legal obligations associated with the retirement of tangible long-lived assets. The equivalent Canadian pronouncement was adopted in 2004.

SCHEDULE VI      33  

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)		2005			2004			2003
Earnings			2 014			1 286			810
Increase (decrease):
	Capitalized interest amortized		(4	)		(15	)		(14	)
	Pension expense		12			(1	)		(31	)
	Change in fair value of derivative instruments		–			2			(7	)
	Operating expense		(19	)		19			13
	Depreciation expense		(10	)		(25	)		(13	)
	Interest expense		6			(6	)		–
	Stock–based compensation		–			6			(3	)
	Income taxes		5			10			12
Adjusted earnings attributable to common shares			2 004			1 276			767
Cumulative effect of change in accounting policy after–tax			–			–			(45	)
Adjusted earnings after cumulative effect of change in accounting policy after–tax			2 004			1 276			722
Other comprehensive income			(82	)		(3	)		(54	)
Total comprehensive income			1 922			1 273			668
Basic earnings per common share (dollars)1			2.43			1.55			0.93
Diluted earnings per common share (dollars)1			2.40			1.54			0.93
Basic earnings per common share after cumulative1 effect of change in accounting policy (dollars)			2.43			1.55			0.88

¹  2004 and 2003 per common share information has been restated to reflect the impact of the share split.

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

($ millions)		2005			2004			2003
Accumulated other comprehensive income (loss), beginning of year			(172	)		(169	)		(115	)
Increase (decrease):
	Minimum additional pension liability		(123	)		(2	)		(66	)
	Minimum additional pension liability — tax		41			(1	)		12
Accumulated other comprehensive income (loss)			(254	)		(172	)		(169	)

There are no material differences on the Corporation’s Consolidated Statement of Cash Flows.

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 since this was a related party transaction.

In 2005, 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 is the cumulative result of weakening equity markets in prior years and a decline in bond yields which are used to determine the discount rate. The additional minimum liability of $383 million (2004 – $260 million; 2003 – $258 million) would be reflected as a reduction of pension assets, with a corresponding reduction of the Company’s future income tax liability of $129 million (2004 – $88 million; 2003 – $89 million).

In compliance with FASB Interpretation Number 46R, assets for 2004 would have increased by $200 million and liabilities would have increased by $212 million.

34        SCHEDULE VI

AUDITORS’ REPORTS

To the Shareholders of Shell Canada Limited:

Under date of February 21, 2006, we reported on the consolidated balance sheets of Shell Canada Limited as at December 31, 2005, 2004 and 2003 and the consolidated statements of earnings and retained earnings and cash flows for each of the three years in the period ended December 31, 2005, as incorporated by reference in the Annual Information Form with respect to the year ended December 31, 2005. 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.

          

Chartered Accountants
Calgary, Alberta
February 21, 2006

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 1 to the financial statements. Our report to the shareholders, dated February 21, 2006, 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.

          

Chartered Accountants
Calgary, Alberta
February 21, 2006

AUDITORS’ REPORTS      35