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ENBRIDGE INC.
ANNUAL INFORMATION FORM
For the Year Ended December 31, 2004

TABLE OF CONTENTS


	Page
Corporate Structure		1
General Development of the Business		2
Description of the Business		5
Liquids Pipelines		5
Gas Pipelines		11
Sponsored Investments		12
Gas Distribution and Services		13
International		22
Corporate		23
Risk Factors		23
Dividends		23
Description of Capital Structure		24
Market for Securities		26
Directors and Officers		27
Legal Proceedings		30
Registrar and Transfer Agent		30
Interests of Experts		30
Additional Information		30

Metric Conversion: 1 barrel of liquid hydrocarbons = 0.159 cubic metre; 1 mile = 1.609 kilometres; 1 barrel mile = 0.256 cubic metre kilometre; 1 cubic foot of natural gas = 0.0283 cubic metre.

Amounts, unless otherwise stated, are in Canadian currency.

Certain information provided in this Annual Information Form constitutes forward-looking statements. The words “anticipate”, “believe”, “estimate”, “expect”, “forecast”, “project” and similar expressions are intended to identify “forward-looking statements” (within the meaning of the United States Private Securities Litigation Reform Act of 1995), which include statements relating to pending and proposed projects. Such statements reflect the Company’s current views with respect to future events and are subject to certain risks, uncertainties and assumptions pertaining to operating performance, regulatory parameters, weather and economic conditions, and, in the case of pending and proposed projects, risks relating to design and construction, regulatory processes, obtaining financing and performance of other parties, including partners, contractors and suppliers. If one or more of these risks or uncertainties materialize, or if the underlying assumptions prove incorrect, actual results may vary significantly from those described in this Annual Information Form.

CORPORATE STRUCTURE

Incorporation

Enbridge Inc. (Enbridge or the Company) was incorporated on April 13, 1970 under the Companies Act of the Northwest Territories as Gallery Holdings Ltd. and was continued under the Canada Business Corporations Act (the CBCA) on December 15, 1987 under the name 159569 Canada Ltd. The Articles of Continuance were amended on August 2, 1989 to change the registered office to Calgary, Alberta; on April 30, 1992 to change the number of shares authorized for issuance to an unlimited number of common and preferred shares, to change the name to Interprovincial Pipe Line System Inc., and to change the registered office to Edmonton, Alberta; on July 2, 1992 to change the French version of the name to Réseau de Pipelines Interprovincial Inc.; and on August 6, 1992 to change the number of directors to a minimum of 1 and a maximum of 15, as fixed by the Board of Directors.

The Company, formerly a wholly-owned subsidiary of Interprovincial Pipe Line Inc. (Interprovincial), became the parent company of Interprovincial on December 18, 1992, pursuant to a Plan of Arrangement implementing a corporate reorganization approved by Interprovincial’s shareholders at the Annual and Special Meeting of Shareholders held on May 6, 1992. As a result of the reorganization, each common share of Interprovincial was deemed to be exchanged for one common share of the Company.

The Articles of Continuance were further amended on May 5, 1994 to change the name of the Company to IPL Energy Inc. and to change the registered office to Calgary, Alberta. On October 6, 1998, the Articles of Continuance were amended to change the name of the Company to Enbridge Inc. On November 24, 1998, the Articles of Continuance were amended to increase the capital of the Company by designating a new series of preference shares as 5.5% Cumulative Redeemable Preference Shares, Series A. On April 29, 1999, the Articles of Continuance were further amended to divide each issued and outstanding common share on a two for one basis and to provide the Board of Directors with a process to add directors between meetings of the shareholders.

The Company’s head office is located at 3000, 425-1^st Street SW in Calgary, Alberta.

Subsidiaries

Each subsidiary listed below is 100% owned. Numerous subsidiaries, many of which are inactive, are omitted from the following list. Individually their total revenue and assets are less than 10% of the consolidated revenue and consolidated assets of the Company. In the aggregate, for excluded subsidiaries, total revenue and total assets are less than 20% of the consolidated revenue and consolidated assets of the Company.


Name	Jurisdiction of Incorporation
IPL System Inc.		Alberta
Enbridge Pipelines Inc.		Canada
Enbridge Energy Company, Inc.		Delaware
Enbridge Pipelines (NW) Inc.		Canada
Enbridge Energy Distribution Inc.		Canada
Enbridge Gas Distribution Inc.		Ontario
Enbridge (U.S.) Inc.		Delaware
Enbridge Gas Services (U.S.) Inc.		Delaware
Enbridge Gas Services Inc.		Canada
Enbridge Pipelines (Athabasca) Inc.		Alberta
Enbridge Capital ApS		Denmark

GENERAL DEVELOPMENT OF THE BUSINESS

Enbridge’s primary business activities are the transportation and distribution of energy. Enbridge conducts its business through five operating segments: Liquids Pipelines, Gas Pipelines, Sponsored Investments, Gas Distribution and Services, and International.

•   Liquids Pipelines includes the operation of a common carrier pipeline and feeder pipelines that transport crude oil and other liquid hydrocarbons.

•   Gas Pipelines includes proportionately consolidated investments in pipelines that transport natural gas including the U.S. portion of the Alliance Pipeline, Vector Pipeline and a system of transmission and gathering pipelines in the Gulf of Mexico.

•   Sponsored Investments consists of the Company’s investments in Enbridge Energy Partners, L.P. (EEP), Enbridge Energy Management, L.L.C. (EEM) (collectively, the Partnership) and Enbridge Income Fund (EIF). The Partnership transports crude oil and other liquid hydrocarbons through common carrier and feeder pipelines and transports, gathers, processes and markets natural gas and natural gas liquids. Enbridge Income Fund is a publicly traded income fund whose assets are a 50% interest in a gas transmission pipeline and a 100% interest in a crude oil and liquids pipeline and gathering system.

•   Gas Distribution and Services consists of gas utility operations which serve residential, commercial, industrial and transportation customers, primarily in central and eastern Ontario. It also includes natural gas distribution in Quebec, New Brunswick and New York State, as well as gas services operations, including the Company’s proportionately consolidated investment in Aux Sable, a natural gas fractionation and extraction business near Chicago, Illinois.

•   The Company’s International business invests in energy transportation and related energy projects outside of Canada and the United States. This business also provides consulting and training services related to proprietary pipeline operating technologies and natural gas distribution.

The following paragraphs describe significant events and transactions in the development of the Company’s business over the last three years.

On December 31, 2004, the Company closed the purchase of ownership interests in natural gas pipeline systems in the Gulf of Mexico from Shell for approximately $754 million. The assets, renamed the Enbridge Offshore System, include ownership interests in 11 transmission and gathering pipelines that transport about 3 billion cubic feet (bcf) per day of natural gas. The assets, which are held primarily through joint venture interests ranging from 22% to 80%, transport approximately half of all deepwater production in the Gulf of Mexico.

During 2004, Enbridge secured 10-year shipper commitments for initial volumes of 60,000 barrels per day (bpd) on the Spearhead Pipeline, formerly the Cushing to Chicago Pipeline, which was purchased during 2003. Enbridge also paid the final installment of $67.5 million (US $55 million) on its 90% interest in the pipeline. The pipeline originally delivered crude oil north from Cushing, Oklahoma to Chicago, Illinois but is now idle except for a short portion on the southern end. Enbridge plans to reverse the direction of flow of the pipeline to transport Canadian crude south, from Chicago to Cushing, and expects the reversal to be completed during the first quarter of 2006. The Spearhead Pipeline project is currently estimated to result in a total investment of $230 million, of which approximately $150 million has been spent.

During 2004, Enbridge entered into interim pipeline agreements to provide pipeline transportation services for two major oil sands projects. These interim agreements allow work on the transportation facilities to proceed while final agreements are being negotiated. The agreements will require the expansion of the Athabasca Pipeline and the construction of new lateral pipelines and tankage facilities. Subsequent to year-end, Enbridge finalized the agreements with Nexen Inc. and OPTI Canada Inc. (the Long Lake Shippers).

Under the interim agreement with ConocoPhillips Surmont Partnership, Total E&P Canada Ltd. and Devon ARL Corporation (the Surmont Shippers), Enbridge will undertake preliminary work for the construction of a pipeline and related facilities required by the Surmont Project. Those facilities, which would accommodate an initial

contract volume of 50,000 bpd of blended crude, could include one or more diluent lateral pipelines, a blended crude lateral pipeline, as well as blending and tank facilities at Enbridge’s proposed Cheecham Terminal on the Athabasca Pipeline. The preliminary agreement would facilitate a planned in-service date of mid-2006.

Under the terms of the agreements with the Long Lake Shippers, Enbridge will construct, own and operate the pipeline and tank facilities required by the Long Lake oil sands project, including one or more diluent laterals, a crude lateral and tank facilities at a proposed terminal on the Athabasca Pipeline, near Cheecham. The estimated cost of these facilities is $40 to $45 million with a planned availability for service date in late 2006. Enbridge’s 545-km Athabasca Pipeline will also require capacity expansion from the Cheecham-area terminal to its mainline terminal at Hardisty, Alberta. The agreements provide for an initial contract volume of up to 60,000 barrels per day of crude oil with provisions for increases to the contract volume. The agreement covering the dedicated Long Lake lateral facilities is for a term of 25 years and the agreement for service on the Athabasca Pipeline is for a 50-month term with extension provisions.

Enbridge sold its investment in AltaGas in 2004 resulting in an after-tax gain of $97.8 million.

As of February 11, 2005, the Company has an effective 11.2% ownership interest in EEP (2004 – 11.6%; 2003 – 12.2%; 2002 – 14.1%). EEP has actively pursued growth through a number of strategic acquisitions, including the acquisition of the Mid-Continent System on March 1, 2004 for US$117 million. This system consists of over 480 miles of crude oil pipelines and 9.5 million barrels of storage capacity, primarily located in Cushing, Oklahoma. On January 6, 2005, EEP closed the acquisition of the North Texas Natural Gas System for approximately US$165.0 million, which consists of approximately 2,200 miles of gas gathering pipelines and three processing plants.

In 2003 EEP acquired natural gas gathering and processing assets in north Texas. The assets were purchased for cash of US$249.7 million.

In 2002, the Company commenced development of underground cavern facilities to provide crude oil storage services through a partnership with CCS Income Trust. The facilities were placed into service on November 1, 2003. These facilities are located near the Company’s main pipeline terminal at Hardisty, Alberta and capacity is approximately three million barrels.

On October 1, 2003, the Company purchased an additional 15% interest in Vector Pipeline Partnership from Duke Energy for approximately $97.7 million, including the assumption of $61.5 million in debt, increasing the Company’s ownership interest from 45% to 60%. As a result of this additional investment, the Company established joint control effective October 1, 2003. The Company provides operating services for Vector Pipeline Partnership, which consists of a natural gas transmission pipeline between Chicago, Illinois and Dawn, Ontario that has a delivery capacity of one bcf per day. The pipeline commenced operations in late 2000.

On June 30, 2003, the Company formed EIF, an unincorporated open-ended trust established under the laws of Alberta. On formation, the Company sold its 50% interest in Alliance Pipeline Canada together with its 100% interest in Enbridge Pipelines (Saskatchewan) Inc. to EIF for total proceeds of $905.0 million.

Phase III of the Terrace Expansion Project (Terrace) was completed on April 1, 2003 at a cost of approximately $120 million on the Enbridge System and approximately US$193 million on the Lakehead System. Completion of Phase III has increased capacity by 140,000 barrels per day. Phase II was completed in 2002 and provided an additional 40,000 barrels per day of capacity at a cost of approximately $100 million in Canada. Phase I was completed in 1999, at a cost of $610 million on the Enbridge System and US$145 million on the Lakehead System, and provided additional heavy crude oil capacity of 170,000 barrels per day.

During 2003, the Company purchased additional interests in both Alliance Pipeline and Aux Sable for a total cost of approximately $223 million, increasing the Company’s interest in both Alliance Pipeline Canada and Alliance Pipeline US from 37.1% to 50%, and increasing the Company’s interest in Aux Sable from 30.9% to 42.7%. As a result of these additional investments, the Company established joint control effective April 1, 2003. The Company’s 50% interest in Alliance Pipeline Canada was sold to EIF in June 2003. During 2002, the Company purchased an additional 15.7% interest in the Alliance Pipeline and a 9.5% interest in Aux

Sable for a total cost of approximately $315 million. The Alliance Pipeline commenced operations in late 2000 and delivers capacity of 1.3 bcf per day of western Canadian natural gas to the U.S. Midwest states.

On October 17, 2002, the Company closed the sale of the United States assets of Enbridge Midcoast Energy, including the South Texas System and the Northeast Texas assets, to EEP for $1,289.3 million (US$820 million), including cash and the assumption of debt.

Concurrent with the US$820 million sale transaction, EEM, a subsidiary of Enbridge, completed an initial public offering of 9,000,000 shares representing limited liability company interests with limited voting rights. The net proceeds from the offering were used to purchase i-units, a new class of limited partnership interests, from EEP. The proceeds from the issuance of the i-units were used to finance a portion of the acquisition cost of the assets. In connection with the offering, Enbridge purchased 17.2% of the EEM shares. EEM has no assets or operations other than those related to the interest in EEP and, by agreement, will manage the business and affairs of EEP. The EEM shares trade on the New York Stock Exchange under the symbol “EEQ”.

In November 2002, the staff of the United States Securities and Exchange Commission (SEC) advised Enbridge, Enbridge Energy Company, Inc., EEM and EEP that they had commenced an informal inquiry into the US$820 million sale transaction and the initial public offering by EEM. The SEC staff advised Enbridge that their principal focus included the financial forecast made in connection with the US$820 million sale transaction and the price for the assets. The SEC staff did not assert that Enbridge, EEP or EEM acted improperly or illegally, and it did not indicate an intention to seek a formal order of investigation. Enbridge cooperated fully with SEC staff. Based on an internal review of the forecast and terms of the transaction, Enbridge continues to believe that the financial forecast had a reasonable basis and the price for the assets was fair to EEP. Enbridge believes that the informal investigation will not have a material adverse effect on the financial condition of the Company.

With respect to EEP’s acquisition of the assets, a committee of independent members of the Board of Directors of Enbridge Energy Company, Inc., an indirect wholly-owned subsidiary of the Company and the general partner of EEP, negotiated the purchase price and terms of the transaction on behalf of EEP’s public unitholders and recommended that the Board approve the transaction. The independent committee retained its own expert financial and legal advisors to assist in this process and the financial advisor rendered a fairness opinion in connection with the transaction.

In May 2002, the Company closed the sale of the business operations that provide energy products and services to retail and commercial customers for cash proceeds of $1 billion.

In 2002, Enbridge acquired 25% of Compañia Logistica de Hidrocarburos (CLH) for approximately $430.8 million. CLH owns and operates the largest refined products pipeline network and storage facilities on the Spanish mainland and Balearic Islands. The purchase agreement allowed for contingent consideration of up to 90.1 million Euros to become payable over the four years following the acquisition if certain minimum annual and cumulative volume targets were met. In 2003, Enbridge paid 1.1 million Euros ($1.8 million) and, in 2004, Enbridge paid 9.4 million Euros ($15.1 million). Also in 2004, Enbridge accrued an additional 63.4 million Euros ($103.3 million) that will become due in 2005 and 2006 in respect of CLH volume targets that have been met. An additional payment of 10.9 million Euros, with respect to 2005 annual volume targets, may become payable in 2006.

DESCRIPTION OF THE BUSINESS


Revenues by Segment
(Canadian dollars in millions)	2004		2003		2002

Liquids Pipelines		872.7		821.5		787.7
Gas Pipelines		271.7		222.1		—
Sponsored Investments¹		—		—		1,219.0
Gas Distribution and Services²		5,363.8		3,785.4		2,513.5
International		32.3		26.2		27.2
Corporate		—		0.1		0.1


Revenues from continuing operations		6,540.5		4,855.3		4,547.5
Revenues from discontinued operations		—		—		181.9


Total Revenues		6,540.5		4,855.3		4,729.4

Notes:

¹		Earnings from EEP and EIF are accounted for as investment income and are therefore not included in revenues.

²		Gas Distribution and Services includes 15 months of revenues in 2004 for Enbridge Gas Distribution and other gas distribution businesses which changed their year end to December 31 in 2004.

LIQUIDS PIPELINES

Enbridge has ownership in, and operates, the world’s longest liquid petroleum pipeline system. The mainline system (the System) consists of the Enbridge System (the portion of the System located in Canada) and the Lakehead System (the portion of the System located in the United States), which is owned by EEP. The Company has an equity investment in EEP that is included in Sponsored Investments. The System is the primary transporter of crude oil from western Canada to the United States. It is the only pipeline that transports crude oil from western Canada to eastern Canada, serving all of the major refining centres in Ontario, as well as the midwest region of the United States. The Athabasca System transports synthetic and heavy crude oil from the Athabasca and Cold Lake regions of Alberta to Hardisty, Alberta. The Norman Wells (NW) System transports crude oil from the Northwest Territories to Zama, Alberta. In addition, Enbridge has interests in various feeder pipeline systems (Frontier, Toledo, Mustang and Chicap), which operate in the United States, as well as a 90% interest in the Spearhead Pipeline, which is still awaiting regulatory review and approvals to reverse the flow of the line.

Enbridge System

The Enbridge System extends approximately 1,200 miles from Edmonton, across the Canadian prairies, to the U.S. border near Gretna, Manitoba where it connects with the Lakehead System. It continues from the US border near Sarnia, Ontario to Toronto, Ontario with lateral lines to Nanticoke, Ontario and Niagara Falls, Ontario and includes the reversed Line 9, which extends from Montreal, Quebec to Sarnia. The Enbridge System is regulated by the National Energy Board (NEB).

Properties

The Enbridge System consists of approximately 4,950 miles of pipe with diameters ranging from 12 inches to 48 inches, 33 main line pump station locations with a total of approximately 980,000 installed horsepower and 104 tanks with an aggregate capacity of approximately 14.3 million barrels. Linefill required for operation amounts to approximately 18.5 million barrels, all of which is owned by the shippers on the Enbridge System. The Enbridge System regularly transports up to 70 different types of liquid hydrocarbons including light, medium and heavy crude oil (including bitumen), condensate, synthetic crudes, NGL and refined products.

The Enbridge System consists of a number of separate segments:

(i)   a Western Canadian segment that consists of five pipelines, ranging in diameter from 16-48 inches, with a capacity of 1,930,000 barrels/day from Edmonton, Alberta to the U.S. border near Gretna, Manitoba.

(ii)   a Sarnia, Ontario to Toronto, Ontario segment that consists of two 20-inch lines from Sarnia to the Toronto area, with a capacity of 150,000 barrels per day. The Sarnia to Toronto segment includes lateral lines (ranging from 12 to 20 inches) from Westover, Ontario, to Nanticoke, Ontario and Niagara Falls, Ontario.

(iii)   a Montreal, Quebec to Sarnia, Ontario segment, Line 9, which consists of a 30-inch line with a capacity of 240,000 barrels per day.

The annual capacities noted above take into account estimated receipt and delivery patterns and ongoing pipeline maintenance and reflect achievable pipeline capacity over long periods of time.

Terrace Expansion Project

Enbridge has carried out a number of projects to expand the mainline over the last 10 years. The most recent was the Terrace Expansion Project (Terrace), which was undertaken by Enbridge and EEP. Phase I was completed in 1999, at a cost of $610 million on the Enbridge System and US$145 million on the Lakehead System. Phase I provided additional heavy crude oil capacity of 170,000 barrels per day. Phase II was completed in 2002 and included the extension of the 36-inch pipeline on the Enbridge System between Hardisty, Alberta and Kerrobert, Saskatchewan. Phase II provided an additional 40,000 barrels per day of capacity at a cost of approximately $100 million in Canada. Phase III included an extension of the 36-inch pipeline on the Lakehead System between Clearbrook, Minnesota and Superior, Wisconsin and pumping additions in both Canada and the United States. It was completed on April 1, 2003 at a cost of approximately $120 million on the Enbridge System and approximately US$193 million on the Lakehead System. Completion of Phase III has increased capacity by 140,000 barrels per day.

Tolling Agreements and Tariffs

The NEB has regulatory authority in Canada over the construction and operation of pipelines for the interprovincial transportation of liquid hydrocarbons and over matters relating to accounting and rates of such pipelines. Prior to 1995, Enbridge System tolls were regulated under a method called “cost-of-service ratemaking”. Under this method, Enbridge was allowed, though not guaranteed, the opportunity to recover its investment in pipeline facilities and to earn a return on rate base. Tolls were approved by the NEB based on the estimated costs of operating the pipeline, projections of system deliveries, rate base and an allowed rate of return.

In February 1995, Enbridge filed a toll settlement negotiated with the Canadian Association of Petroleum Producers (CAPP), which incorporated a methodology of determining tolls based on an incentive approach. Specific parameters were agreed upon to calculate tolls through 1999. The main objective of this methodology was to more closely align the interests of the Company with the interests of its shippers. The Incentive Tolling Agreement provided for sharing with customers the results of operating efficiencies and cost savings achieved above certain thresholds on an annual basis. In 1999, Enbridge reached an agreement with CAPP for the continuation of certain incentive parameters from the 1995 agreement for 2000 through 2004 (the Incentive Tolling Settlement). Negotiations on a new incentive tolling agreement are currently underway. Until the new agreement is signed, tolls in effect on December 31, 2004 are continuing to be charged on an interim basis.

Tariffs

Tolls are calculated in accordance with various agreements. Under published tariffs for the Enbridge System, the tolls for transportation, including terminalling and tankage charges where applicable, of light crude oil from Edmonton to principal delivery points, at December 31, 2004 are set forth below.



	Canadian Toll
	Per Barrel
Regina, Saskatchewan	$	0.952
U.S. border near Gretna, Manitoba	$	1.188
Sarnia, Ontario	$	1.385

The rates for medium and heavy crude oils are higher, while those for refined products and natural gas liquids (NGL) are lower than the rates set forth in the above table to compensate for differences in costs for shipping different types and grades of liquid hydrocarbons. Enbridge plans to file new tolls with the NEB after finalizing the 2005 Incentive Tolling Agreement with CAPP, to reflect the provisions of the new 2005 Incentive Tolling Agreement, the System Expansion Project (SEP) II Risk Sharing Agreement and the Terrace Agreement.

SEP II Risk Sharing Agreement

Enbridge, EEP and CAPP entered into a Risk Sharing Agreement, effective for 15 years, with respect to SEP II, a 100,000 barrels per day expansion completed in 1998. The Risk Sharing Agreement provides that the rate of return on the SEP II investment will be based, in part, on the utilization level of the additional capacity constructed. Higher utilization will result in a greater return, subject to a minimum and maximum rate of return of 7.5% and 15.0%, respectively. During 2004, Enbridge and EEP earned the minimum rate of return on SEP II.

Terrace Agreement Toll Surcharge

As part of the Terrace Agreement, Enbridge, EEP and CAPP agreed to a fixed toll surcharge of $0.05 per barrel for the movement of light crude from Edmonton to the Chicago area. The Canadian portion of the surcharge is included in the tolls listed in the table above. This toll surcharge commenced on April 1, 1999, when Terrace Phase I was completed. The incremental toll is allocated between Enbridge and EEP. The toll surcharge is also subject to increase or decrease in certain defined circumstances.

Trade Credit Risk

Trade receivables consist primarily of amounts due from companies operating in the oil and gas industry and are collateralized by the crude oil and other liquid hydrocarbon products contained in the Company’s pipeline and tankage facilities.

At December 31, 2004, 41 shippers tendered crude oil and other liquid hydrocarbons for delivery through the pipeline system. In 2004, the top four customers accounted for approximately 16%, 14%, 12% and 11% respectively, of total billed revenue.

Sources of Shipments and Outlook on Supply

Shipments tendered to the Enbridge System originate in oilfields and oil sands in Alberta, Saskatchewan, Manitoba, British Columbia and the Northwest Territories, and reach the Enbridge System through the NW and Athabasca Systems owned by Enbridge, as well as pipelines owned and operated by others. These pipelines connect with the Enbridge System at two receiving points in Alberta, two in Saskatchewan and one in Manitoba. In addition, the Enbridge System receives offshore crude oil through connecting pipelines at Montreal, Quebec.

Supply of crude oil from the Western Canadian Sedimentary Basin (WCSB) has grown consistently since 1999 particularly in the last two years during which production has grown by 170,000 bpd⁽¹⁾. Over the same period, production from Canada’s conventional resources declined by 66,000 bpd. Development of Canada’s world scale oil sands resource has more than replaced the declining conventional production, growing by 235,000 bpd over the last two years. The NEB estimates 2004 production from the WCSB to exceed 2.2 million bpd. This places the WCSB on a comparable level with production from OPEC members Kuwait and Nigeria.

Remaining established conventional oil reserves in Western Canada were estimated to be 4.7 billion barrels at the end of 2003. Remaining proved reserves from oil sands currently stand at 174.1 billion barrels. Combined conventional and oil sands reserves of 178.8 billion barrels puts Canada, with 14% of the worldwide estimated proved reserves⁽²⁾, second only to Saudi Arabia.

Notes:

(1) National Energy Board 2004 Estimate Production of Canadian Crude Oil and Equivalent Table 1

(2) Oil and Gas Journal’s Worldwide Look at Reserves and Production, December 20, 2004

Deliveries and Demand for WCSB Crude

Deliveries from the System are made in the prairie provinces, the Province of Ontario and in the Great Lakes and Midwest regions of the United States, principally to refineries, either directly or through the connecting pipelines of other companies. Within these regions are located major refining centres near Sarnia, Nanticoke, and Toronto, Ontario; the Minneapolis-St. Paul area of Minnesota; Superior, Wisconsin; Chicago, Illinois; the Patoka/Wood River, Illinois area; Detroit, Michigan; Toledo, Ohio; and Buffalo, New York.

The Company’s liquids pipelines are dependent upon the demand for crude oil and other liquid hydrocarbons produced from Western Canada. Historically, the pipeline system has delivered crude oil to two main markets: Ontario/Quebec, and the Midwest portion of the United States with some volume delivered to Western Canada. Western Canada demand is served by local supply and has increased by 36,000 bpd over the last two years. With the reversal of the Company’s Line 9, competition from Atlantic Basin crude oil has decreased deliveries of Canadian crude into the Ontario/Quebec market. During 2004, an equal mix of western Canadian and Atlantic Basin crude satisfied Ontario’s demand for crude with demand for WCSB crude down slightly over the last two years. Deliveries of WCSB crude into the US Midwest (PADD II) have increased significantly over the last two years, growing by 80,000 bpd. At the same time, deliveries into the U.S. Rocky Mountains (PADD IV) have increased by 25,000 bpd and the Western U.S. (PADD V) deliveries have increased by 45,000 bpd.

The following table sets forth the information related to deliveries and other distance-related operating data of the Enbridge System for each of the years in the three-year period ended December 31, 2004.



	Deliveries
(thousands of barrels per day)	2004		2003		2002

Prairie Provinces
Light crude oil		194		176		170
Medium and heavy crude oil		126		91		73
Refined products		83		83		81

		403		350		324

United States
Light crude oil		261		252		286
Medium and heavy crude oil		748		690		601
Natural gas liquids		4		4		6

		1,013		946		893

Ontario
Light crude oil		403		391		380
Medium and heavy crude oil		79		68		78
Natural gas liquids		103		109		111

		585		568		569

		2,001		1,864		1,786


Barrel Miles (billions)		383		361		351
Average Haul (miles)		523		530		539

Enbridge System average deliveries include Line 9 volumes of 227,000 barrels per day (2003 – 216,000; 2002 – 204,000).

Competition

Competition among common carrier pipelines is based primarily upon the cost of transportation, access to supply, and proximity to markets. Terasen Pipelines (Trans Mountain) Inc. and Express Pipeline, as well as other common carriers, can be used by producers to ship Western Canadian crude oil to refineries in either Canada or the United States. Although the Company does not compete directly in the regions served by these other pipelines, producers can elect to have their crude oil refined elsewhere than delivery points on the Enbridge System. Competition may also arise from pipeline proposals that may provide access to market areas currently served by the Company’s liquids pipelines. One such proposal is the Keystone Project put forward by TransCanada Pipelines Limited to ship Western Canadian crude oil into PADD II starting in 2008 or 2009. The Company believes that its liquids pipelines are serving larger markets and provide attractive options to producers in the WCSB due to their competitive tolls.

Safety and Environment

Enbridge has appropriate mechanisms in place to monitor and address the safety and environmental aspects of its operation. Enbridge has health, safety and environmental management systems and has established policies, programs and practices for conducting safe and environmentally sound operations. These systems promote awareness and foster openness and dialogue with employees, the public, regulators and key stakeholders, resulting in a positive safety and environmental image, and improved safety and environmental performance throughout the Company’s pipeline operations and in the communities in which it operates.

Enbridge seeks to ensure compliance with all applicable regulatory and permit requirements. Enbridge acts to identify, evaluate and mitigate any potential impacts and issues associated with its operations. It also engages in a concerted effort to reduce environmental liabilities associated with oil-contaminated soil.

Impacts resulting from spills of crude oil and petroleum products are not unusual within the petroleum pipeline industry and the Company has experienced such spills in the past. A comprehensive methodology for

managing environmental aspects of hydrocarbon spills is in place. Historic spills along the pipeline system may have resulted in soil or groundwater contamination where further remediation may be required. Enbridge continues to voluntarily investigate past leak sites to assess whether any remediation is required in light of current legislation, in consultation with regulatory agencies and landowners, to remediate contaminated lands. To date, no material environmental risks have been identified.

The environmental protection requirements applicable to the Company’s pipeline operations do not adversely affect the pipeline operations’ competitive position, capital expenditures program or level of earnings. However, the risk of substantial liabilities is inherent in pipeline operations and there can be no assurance that such liabilities will not be incurred.

Regular internal reviews and audits are conducted to assess compliance with legislation and company policy. Enbridge has consistently been an industry leader in safety and environment and has received numerous industry awards. To the best of the Company’s knowledge, its pipeline operations are in compliance with all applicable safety and environmental regulations governing their operations.

There are possible effects from the environment policy initiatives outlined in the Canadian federal government budget of February 2005. Any such effects cannot yet be quantified.

Pipeline Integrity

The focus of Enbridge’s integrity management program is to continuously monitor the condition of the pipeline system and apply preventative maintenance programs. In 2004, in-line inspections for corrosion, cracks and pipe deformities such as dents were conducted in various lines throughout the pipeline system. Investigative excavations were conducted to evaluate anomalies detected by the inspections and repairs were conducted as needed. All work plans and implementation procedures meet or exceed regulatory requirements and are regularly reviewed and continuously improved to ensure best technologies are utilized and integrity management processes are optimised.

Other Liquids Pipelines

Athabasca System

The Athabasca System, which is owned and operated by Enbridge, has a design capacity of 570,000 barrels per day and extends approximately 340 miles from north of Fort McMurray in northern Alberta, south to the pipeline hub at Hardisty, Alberta. At Hardisty, it accesses the Enbridge System and other carriers for transportation to Canadian and U.S. refineries. The Athabasca System also includes the Athabasca Terminal with 1.6 million barrels of receipt tankage, as well as the MacKay River and Christina Lake lateral feeder lines and tankage facilities. Enbridge has a 30-year take-or-pay transportation arrangement with Suncor Energy Inc., the initial shipper on the pipeline. The agreement also provides the shipper with options to increase and extend the life of the agreement beyond the initial 30-year term. Enbridge has also contracted to provide transportation services for EnCana Corporation and Petro-Canada Oil and Gas. The Athabasca System is regulated by the Alberta Energy and Utilities Board (the EUB).

NW System

The NW System extends approximately 540 miles between Norman Wells, Northwest Territories and Zama, Alberta. From Zama, crude oil is transported through the pipeline facilities of others to Edmonton, Alberta for delivery to refineries in the Edmonton area or to the Enbridge System and to other carriers for transportation to other Canadian and U.S. refineries. The NW System is regulated by the NEB and is subject to a negotiated settlement and throughput agreement with its main shipper.

Spearhead Pipeline

The Spearhead Pipeline, which was acquired in September 2003, will have a capacity of 125,000 barrels per day, and 4.3 million barrels of tankage, and extends approximately 650 miles from Chicago, Illinois to Cushing, Oklahoma. During 2004, Enbridge secured 10-year shipper commitments for initial volumes of 60,000 barrels per day. Enbridge also paid the final installment of $67.5 million (US $55 million) on its 90% interest in the pipeline. Enbridge has an option to purchase the remaining 10% interest during 2005. Also, Enbridge may be required to purchase this remaining 10% interest during 2005 at the option of the current owner. The

pipeline originally delivered crude oil north from Cushing, Oklahoma to Chicago, Illinois but is now idle except for a short portion on the southern end. Enbridge plans to reverse the pipeline to transport Canadian crude south, from Chicago to Cushing, and expects the reversal to be completed during the first quarter of 2006. The reversal is currently estimated to result in a total investment of $230 million, of which approximately $150 million has been spent.

Other U.S. Liquids Pipelines

Other U.S. Liquids Pipelines are regulated by the Federal Energy Regulatory Commission (FERC) and include the Frontier System, the Mustang System, the Chicap System and the Toledo System.

Enbridge owns 77.8% of the Frontier System, which consists of 290 miles of 16-inch pipeline running from Wyoming to the northeast border of Utah, for ultimate delivery into the Salt Lake City refining market. The Frontier System has a capacity of 62,200 barrels per day and 2004 deliveries averaged 48,000 barrels per day.

Enbridge has a 30% joint venture interest in the Mustang System. This pipeline consists of 215 miles of 18-inch line with a capacity of 100,000 barrels per day. The Mustang System receives crude oil from the Lakehead System in the Chicago, Illinois area and delivers to the Patoka, Illinois area. Deliveries averaged 63,700 barrels per day in 2004.

Enbridge has a 22.8% interest in the Chicap System, which consists of 205 miles of 26-inch line with a capacity of 360,000 barrels per day. The pipeline transports crude oil from the Patoka pipeline hub to the Chicago, Illinois area. Deliveries in 2004 averaged 243,000 barrels per day.

Enbridge owns and operates the Toledo System, which consists of 35 miles of 16-inch line and connects the Lakehead System at Stockbridge, Michigan to two refineries in the Toledo, Ohio area. Toledo also leases 52 miles of pipeline from the Wolverine Pipeline Company. The pipeline has a capacity of 100,000 barrels per day of heavy crude oil and deliveries averaged 61,600 barrels per day in 2004.

Employees

Approximately 913 individuals are employed in providing services to the Liquids Pipelines segment within Enbridge. This does not include the individuals employed in the Liquids Pipelines segment within EEP and the Liquids Transportation segment within EIF. These individuals are included in the Sponsored Investments segment.

GAS PIPELINES

Gas Pipelines includes joint venture interests in natural gas transmission and gathering pipelines, including the Alliance Pipeline US, the Vector Pipeline and Enbridge Offshore System.

Alliance Pipeline

The Alliance Pipeline is a natural gas pipeline extending 1,875 miles from supply areas in northwestern Alberta and northeastern British Columbia to Chicago, Illinois. The pipeline has a firm delivery capacity of approximately 1.3 bcf of natural gas per day, all of which is committed through transportation agreements. Enbridge holds a 50.0% interest in, and jointly controls, the U.S. portion of the Alliance Pipeline with Fort Chicago Energy Partners L.P. The Canadian portion of the Alliance Pipeline is 50% owned by Enbridge Income Fund, a sponsored investment, and 50% owned by Fort Chicago Energy Partners L.P.

The Alliance Pipeline connects in the Chicago area with two local natural gas distribution systems and five interstate natural gas pipelines, which provide shippers access to natural gas markets in the midwestern and northeastern United States and eastern Canada. The Alliance Pipeline also connects with a natural gas liquids (NGL) extraction facility (Aux Sable) in Channahon, Illinois near the terminus of the Alliance Pipeline. It also interconnects with a pipeline in North Dakota.

The rates and tariff for Alliance Pipeline US are regulated by the FERC in the United States. All shippers have accepted toll principles negotiated with Alliance and signed transportation contracts incorporating the same toll principles and tariff.

Vector Pipeline

Enbridge holds a 60% investment in, and provides operating services to, the Vector Pipeline, which transports natural gas from Chicago, Illinois to Dawn, Ontario. The Vector Pipeline extends 344 miles and connects with the Alliance Pipeline and other natural gas transmission systems, all providing a transportation link for western Canadian gas supplies. The Vector Pipeline has a delivery capacity of 1.0 bcf of natural gas per day. Vector’s primary sources of supply are through interconnections with the Alliance System and the Northern Border Pipeline in Joliet, Illinois. The rates and tariff for Vector are regulated by the FERC. Approximately 70% of the long haul capacity of Vector is committed to long-term firm transportation contracts at rates negotiated with the shippers and approved by the FERC. The remaining capacity is sold at market rates. Transportation service is provided through a number of different forms of service agreements such as Firm Transportation Service and Interruptible Transportation Service. Vector is currently operating at or near capacity.

Enbridge Offshore Pipelines

Enbridge Offshore Pipelines, acquired on December 31, 2004, is comprised of ownership interests in 11 natural gas gathering and transmission pipelines in five major corridors in the Gulf of Mexico. The assets are held primarily through joint ventures with ownership interests ranging from 22% to 80%. The Enbridge Offshore Pipelines transport about 3 bcf of natural gas per day, which is approximately half of all deepwater production in the Gulf of Mexico.

All natural gas pipelines are subject to federal, state or local laws and regulations related to environmental protection and operational safety. To the best of the Company’s knowledge, the operations of all affiliated systems are in substantial compliance with applicable environmental and safety regulations.

Employees

Approximately 85 individuals are directly employed by Enbridge to provide operating services to the Enbridge Offshore System. The Alliance Pipeline is operated and administered entirely by employees of Alliance Pipeline. The Vector Pipeline is operated and administered in part by employees of Vector Pipelines, and in part through operating and administrative services provided by Enbridge.

SPONSORED INVESTMENTS

Sponsored Investments consists of the Company’s investments in Enbridge Energy Partners, L.P. (EEP), Enbridge Energy Management, L.L.C. (EEM) (collectively, the Partnership) and Enbridge Income Fund (EIF). The Partnership, which is publicly traded, transports crude oil and other liquid hydrocarbons through common carrier and feeder pipelines and transports, gathers, processes and markets natural gas and natural gas liquids. EIF is a publicly traded income fund whose assets consist of a 50% interest in Alliance Pipeline Canada, a gas transmission pipeline, and a 100% interest in the Enbridge Saskatchewan System, a crude oil and liquids pipeline and gathering system.

Enbridge Energy Partners

As of February 11, 2005, Enbridge has an effective 11.2% ownership interest (2004 – 11.6%, 2003 – 12.2%, 2002 – 14.1%) in EEP. This ownership interest represents the Company’s direct investment in EEP of 8.5% and an indirect investment of 3.1% through the Company’s 17.2% ownership interest in EEM. EEM’s business activities are limited to managing the business and affairs of EEP and holding an approximate 18% interest in EEP.

EEP owns and operates crude oil and liquid petroleum transmission pipeline systems, natural gas gathering and related facilities and marketing assets in the United States. Significant assets include the Lakehead System, which is the extension of the Enbridge System in the US, natural gas gathering and processing assets in east Texas (East Texas System), the mid-continent crude oil system (Mid-Continent System), which was acquired in 2004, a natural gas system in north Texas (North Texas System), which was also acquired in 2003, and a feeder pipeline in North Dakota.

Enbridge, as the general partner of EEP, receives incentive income based on the level of quarterly cash distributions. EEP makes quarterly cash distributions of all of its available cash to the holders of its common units, including Enbridge. Under the Partnership Agreement, Enbridge receives incremental incentive cash distributions, which represent incentive income, on the portion of cash distributions, on a per unit basis, that exceed certain target thresholds.

Enbridge Income Fund

Enbridge created EIF in June 2003. On formation, EIF acquired the Company’s 50% interest in the Canadian segment of the Alliance Pipeline, as well as its 100% interest in the Enbridge Saskatchewan System. A subsidiary of Enbridge acts as EIF’s manager, and holds a 41.9% interest in EIF in the form of subordinated units of EIF. Enbridge also holds 100% of the preferred units of Enbridge Commercial Trust, a direct subsidiary of EIF.

The Canadian segment of the Alliance Pipeline consists of an approximately 1,560 km high-pressure, natural gas transmission system and an approximately 700 km lateral pipeline system. The Saskatchewan System’s primary business activity is the transportation of crude oil and other liquid hydrocarbons by pipeline through the ownership and operation of the Saskatchewan, Westspur and Weyburn pipeline systems located primarily in Saskatchewan and the Virden pipeline system located in Manitoba.

Employees

Enbridge employs approximately 1,175 individuals who provide services to the Sponsored Investments segment.

Each of Enbridge Energy Partners, L.P. and Enbridge Energy Management, L.L.C. has filed an Annual Report on Form 10-K for the year ended December 31, 2004 with the Securities and Exchange Commission in the United States. These documents contain detailed disclosure with respect to each entity and are publicly available from the Securities and Exchange Commission and through www.edgar.com. No part of Form 10-K is intended to be incorporated by reference in this Renewal Annual Information Form of Enbridge Inc.

Enbridge Income Fund has filed an Annual Report and an AIF for the year ended December 31, 2004 with Canadian Securities Administrators in Canada. The AIF and the Annual Report, which includes consolidated financial statements and Management’s Discussion and Analysis, contain detailed disclosure with respect to the Enbridge Income Fund and are publicly available through www.sedar.com. No part of Enbridge Income Fund’s Annual Report, consolidated financial statements, Management’s Discussion and Analysis or Renewal AIF is intended to be incorporated by reference in this AIF of Enbridge Inc.

GAS DISTRIBUTION AND SERVICES

Gas Distribution and Services consists of gas utility operations, which serve residential, commercial, industrial and transportation customers, primarily in central and eastern Ontario. It also includes natural gas distribution activities in Quebec, New Brunswick and New York State, as well as gas services operations, including the Company’s proportionately consolidated investment in Aux Sable, a natural gas liquids extraction and fractionation business.

Enbridge’s gas distribution business is conducted primarily through Enbridge Gas Distribution (EGD), a wholly-owned subsidiary. EGD is Canada’s largest natural gas distribution utility, serving over 1.7 million residential, commercial, industrial and transportation service customers in central and eastern Ontario, including the City of

Toronto and the surrounding areas of Peel, York and Durham, as well as the Niagara Peninsula, Ottawa, Brockville, Peterborough, Barrie and many other Ontario communities. In addition, EGD, through its wholly-owned subsidiary, St. Lawrence Gas Company, Inc. (St. Lawrence), serves Massena, Ogdensburg, Potsdam and surrounding areas in northern New York State.

The gas distribution utility business of EGD is regulated by the Ontario Energy Board (the OEB), its principal regulator, which regulates various aspects of EGD’s utility operations in Ontario. Similar regulations apply to St. Lawrence under the New York State Public Service Commission. Gazifère is regulated under La Regie de L’energie in Quebec and Enbridge Gas New Brunswick is regulated by the New Brunswick Public Utilities Board.

Effective December 31, 2004, Enbridge’s gas distribution businesses in Ontario, Quebec and New York State changed their fiscal year-end for financial reporting purposes from September 30 to December 31. Consistent with that change, Enbridge will no longer be consolidating gas distribution operations on a quarter lag basis. The quarter lag basis entailed consolidating EGD results for the year ended September 30, the fiscal year-end end prior to the change, with the Enbridge results for the year ended December 31. This caused a quarter lag in the reporting of EGD’s results. For example, when the first quarter of EGD was consolidated with the first quarter of Enbridge, the EGD results were for the three months ended December 31 whereas Enbridge’s results were for the three months ended March 31. To eliminate the quarter lag difference it is necessary to record the EGD results for the 15 months ended December 31, 2004 with the Enbridge results for the twelve months ended December 31, 2004. Going forward, management is of the view that this change will provide additional clarity when discussing the gas distribution operations, as the fiscal periods will be consistent.

Enbridge Gas Distribution

Description of Business

Distribution Service

EGD’s principal source of revenue is from distribution services provided to its customers. The services provided to residential and small commercial and industrial heating customers are primarily on a general service (non-contract) basis. The services provided to larger commercial and industrial customers are usually on an annual contract basis under firm or interruptible service contracts. Under a firm service contract, EGD is obligated to deliver natural gas to the customer up to a maximum daily volume. The service provided under an interruptible service contract is similar to that of a firm contract, except that it allows for service interruption at the option of EGD to meet seasonal or peak demands. The OEB approves rates for both contract and general services.

Customers have several choices in respect of gas supply. One option is the sales service option whereby the customer purchases gas from EGD’s supply portfolio (system supply). EGD does not earn a profit on the gas commodity it provides to customers. Alternatively, a customer may select a direct purchase option, which is either a transportation service arrangement or a buy/sell arrangement. Under the transportation service arrangement, a customer supplies natural gas at a TransCanada receipt point in western Canada or at a TransCanada delivery point in Ontario, and EGD redelivers an equivalent amount of gas to the customer’s end-use location. Under the buy/sell arrangement, a customer purchases gas directly from a western Canadian producer or a marketer and sells it to EGD at a TransCanada receipt point in western Canada. EGD, in turn, resells the gas, now integrated into its general supply portfolio, back to the customer at its end-use location. The buy/sell arrangements are being phased out as they expire, and are being replaced with transportation service arrangements. Both types of arrangements are billed under the OEB-approved rate schedules.

Gas Supply

To acquire the necessary volume of gas to service its customers, the Company maintains a diversified gas supply portfolio. During the 15 months ended December 31, 2004, EGD acquired approximately 177 billion cubic feet of natural gas, of which 41.2% was acquired from western Canadian producers, 43.2% from suppliers in Chicago and 15.6% was acquired on a delivered basis in Ontario. EGD also transported 272 billion cubic feet of natural gas on behalf of direct purchase customers operating under a transportation service arrangement.

EGD’s system supply gas contracts have pricing structures responsive to supply and demand conditions in the North American natural gas market. The prices in these contracts are indexed to either Alberta, Chicago or New York based prices. EGD uses natural gas financial derivatives such as price swaps, calls and collars to manage customers’ exposure to natural gas price risk.

Transportation

EGD relies primarily upon TransCanada PipeLines Limited (TransCanada) for transportation service to bring its diversified gas supply from western Canada to its franchise area. EGD has long-term firm transportation service contracts with TransCanada, over varying time periods, for annual deliveries of approximately 300 billion cubic feet of natural gas. This includes deliveries by direct purchase customers via TransCanada capacity that has been assigned by EGD to the direct purchase customer or capacity that has been contracted directly with TransCanada by the direct purchase customer.

The transportation service contracts are not directly linked with any particular source of gas supply. Separating transportation contracts from gas supply allows EGD flexibility in obtaining its own gas supply and accommodating the transportation of natural gas purchased directly by end-use customers. EGD continues to forecast the gas supply needs of all its customers, including the associated transportation and storage requirements.

TransCanada’s transportation tolls, which are approved by the NEB, consist of a fixed cost (demand component) and a variable cost (commodity component) for Firm Transportation (FT) service. An FT shipper, such as EGD, must pay the demand component regardless of the volume of gas that TransCanada actually transports for the FT shipper. Consequently, if an FT shipper does not utilize all of its FT capacity rights, the FT shipper would incur unabsorbed demand charges in respect of the unutilized portion.

Enbridge has contracted for 105 million and 260 million cubic feet per day of the capacity available on the Alliance and Vector pipelines, respectively, of which a substantial portion is committed to satisfy EGD’s delivery requirements. EGD relies on its long-term contracts with Union Gas Limited (Union) for transportation from Dawn in southwestern Ontario to the Company’s major market in the greater Toronto area. The contracts effectively provide the Company with access to U.S.-sourced gas delivered at St. Clair by Michigan Consolidated Gas Company (MichCon), including gas delivered to MichCon by upstream pipelines in the United States and at Dawn by the Vector Pipeline. The contracts also provide transportation for gas stored at the Company’s and Union’s storage pools in the Sarnia area to the market area.

EGD is also a participant in the Link Project, which involved the construction of connecting pipelines in southwestern Ontario by Niagara Gas Transmission Limited (Niagara Gas), a wholly-owned subsidiary of Enbridge, and in southwestern Michigan by ANR Pipeline Company (ANR). These pipelines effectively link ANR’s southeast and southwest mainlines, which access major U.S. supply basins, and MichCon’s transportation system, which accesses Michigan supplies, directly to the EGD’s principal storage facilities near Dawn (see “Gas Storage” below) and indirectly to Union’s transmission system at Dawn. EGD has entered into long-term contracts for transportation service with ANR, MichCon and Niagara Gas.

Gas Storage

The business of EGD is highly seasonal as daily market demand for gas fluctuates with changes in weather, with peak consumption occurring in the winter months. Utilization of storage facilities permits EGD to take delivery of gas on favourable terms during off-peak summer periods for subsequent use during the winter heating season. This practice permits EGD to minimize the annual cost of transportation of gas from western Canada, assists in reducing its overall cost of gas supply and adds a measure of security in the event of short-term interruption of transportation of gas from western Canada to EGD’s franchise area.

EGD’s principal storage facilities are located in southwestern Ontario near Dawn and have a total capacity of approximately 99 billion cubic feet. Approximately 92 billion cubic feet of the total capacity is available to EGD. EGD also has a storage contract with Union for 20 billion cubic feet of storage capacity.

The EGD-operated storage facilities are connected to the Dawn storage and transmission hub by two 30-inch pipelines owned by EGD. In the summer, gas is delivered to Dawn for injection into storage through the transmission facilities of TransCanada and Vector pipelines. In the winter, gas is withdrawn from storage

and delivered to Dawn and transported to EGD’s major market area of Toronto through the transmission facilities of Union. EGD has transportation contracts with TransCanada, Vector and Union for the delivery of gas to and from storage.

Properties

On December 31, 2004, EGD owned and operated approximately 32,642 kilometres of mains (31,403 kilometres on September 30, 2003 and 30,593 kilometres on September 30, 2002) for the transportation and distribution of gas, as well as the service pipes to transfer gas from mains to meters on the customers’ premises. In addition, EGD owns equipment and other properties used for offices, warehouses, metering and regulating stations and service shops. These assets are located in EGD’s franchise area.

Regulation

While EGD will again be under a cost of service rate setting mechanism in 2005, EGD continues to explore alternate rate-making models with the regulator. EGD has participated in the OEB’s Natural Gas Forum, which has been initiated for the purpose of exploring options for better regulation of the evolving gas market. In addition to rate regulation, the review by the forum would include issues relating to system supply and natural gas storage. The goal is to create a more efficient natural gas marketplace. EGD will be an active participant in the development of policies on these matters.

In order to maintain rate-setting on a prospective basis, EGD expects to file an application for rates for the 2006 calendar year in March 2005. Future applications will be accompanied by incentive regulation earnings mechanisms.

Fiscal 2005 Rate Application

The rate application was based on the traditional cost of service as described under 2003 Rates. The key elements are summarized below:


	Approved			Approved
Regulatory year ended September 30,	2005			2003

Rate base (millions)	$	3,422.1		$	3,155.8
Rate of return on rate base		8.10	%		8.32	%
Deemed common equity for regulatory purposes		35.00	%		35.00	%
Rate of return on common equity		9.57	%		9.69	%

The fiscal 2004 rate application was not a traditional cost of service application since EGD requested an increase in 2003 rates by 90 percent of the forecast Ontario consumer price index. Accordingly, no rate base information has been provided for 2004 in the table above.

EGD’s rate application for 2005 has been approved by the OEB. The fiscal 2005 rate application also requested a change in year-end to December 31 for regulatory rate setting purposes. Therefore, rates were requested to be set for the period October 1, 2004 to December 31, 2005. The request for a change in year-end was aimed at synchronizing EGD’s fiscal year with that of Enbridge. The OEB approved EGD’s request for change in year-end in its decision of November 1, 2004.

Discontinuation of Seasonal Rates

Effective October 1, 2004, seasonal rates for delivery charges have been replaced with a uniform rate throughout the year. The impact of this change will result in lower earnings in the winter months, offset by higher earnings in the summer months, causing a shift in earnings between quarters with no earnings impact over 12 consecutive months, mitigating weather risk, to some degree.

2004 Rates

EGD’s 2004 rate application requested that rates for 2004 be set by increasing 2003 rates by 90 percent of the forecast Ontario consumer price index, that being an increase of 1.8 percent. The OEB accepted the

proposal for EGD’s fiscal 2004 rates on September 4, 2003, thus allowing rates to be in place for the start of the 2004 fiscal year.

The OEB also added a sharing mechanism to fiscal 2004, whereby if earnings on a weather-normalized basis exceed the benchmark ROE, these excess earnings would be shared on a 50/50 basis between ratepayers and the Company’s shareholders. Since EGD’s regulated earnings for the rate setting year ended September 30, 2004 exceeded the regulator’s allowed rate of return, a charge of $13.4 million ($8.7 million after-tax) was recorded in the financial statements for the 15 months ended December 31, 2004.

2003 Rates

EGD’s 2003 rates were established pursuant to a cost-of-service methodology that allowed revenues to be set to recover EGD’s forecast costs. Forecast costs included gas commodity and transportation, operation and maintenance, depreciation, income taxes, and the debt and equity costs of financing the rate base. The rate base is EGD’s investment in all assets used in gas distribution, storage and transmission, as well as an allowance for working capital. Under cost-of-service, it is EGD’s responsibility to demonstrate to the OEB the prudence of the forecast costs. EGD does not profit from the sale of the natural gas commodity.

The rate base is financed by EGD through a combination of debt and equity. The proportion of debt and equity is approved by the OEB. For the debt portion, interest expense incurred by the Company is recovered in rates. For the equity portion, the OEB sets the rate of return that EGD may recover in rates. The allowed rate of return on equity for EGD is based on the yield on Canadian government long-term bonds. For 2005, the allowed rate of return was 9.57% (2003 – 9.69%; 2002 - 9.66%) on a deemed common equity ratio of 35.0%.

2002 Rates

During the fiscal periods 2000 to 2002, EGD operated under a targeted Performance-Based Regulation (PBR) plan. The PBR plan used a formula to calculate the level of operation and maintenance costs recoverable in rates. During the PBR period, EGD was allowed to retain any savings realized if it achieved lower operation and maintenance expenses than those calculated under the formula.

Legislative Change and Future Regulatory Direction

On August 1, 2003, the Ontario Energy Board Consumer Protection and Governance Act, 2003 was proclaimed, providing a new mandate for the OEB. The legislation provides for improved regulatory processes, performance measurement and reporting by the OEB, as well as the establishment of the OEB as a self-financing Crown Agency.

Gas Distribution Access Rule

The OEB, pursuant to the Energy Competition Act, has undertaken the development of a Gas Distribution Access Rule (GDAR). The purpose of the GDAR is to establish rules governing natural gas distributors’ conduct in relation to gas marketers and to establish conditions of access to distribution services. The OEB issued the final version of the GDAR in December 2002. Despite EGD’s arguments with respect to the GDAR’s position on customer mobility and billing options, the GDAR mandates that distributors, including EGD, provide gas marketers with the option to consolidate the gas distribution charges to consumers on the marketers’ own bill, forcing the distributor to appoint the marketer as its billing agent. EGD would have to undertake extensive system changes and negotiate new contractual arrangements in order to effect the GDAR directives. Despite appeal by both Union Gas Limited and EGD, on January 11, 2005 the Ontario Court of Appeal dismissed the appeal and upheld the OEB’s authority to enact the vendor consolidated billing aspects of the GDAR. EGD is reviewing the decision and considering its options.

Price Advantage of Natural Gas

Natural gas is the predominant energy form in the residential heating market throughout EGD’s franchise area. In 2004, over 50% of EGD’s gas distribution revenues were from the residential market. The primary competition to natural gas in the residential market has historically been from domestic fuel oil and electricity. In 2004, natural gas in the residential market experienced, on average, a price advantage on an equivalent annual volume basis of 38% (2003 – 36%) against electricity and 23% (2003 – 20%) against domestic fuel oil.

Although natural gas commodity prices remained historically high over the year, the concurrent run-up in oil prices and electricity prices have kept natural gas prices competitive with alternative energy sources. Oil prices were driven higher by political instability and uncertainty in a variety of oil producing regions, while electricity prices increased with the escalation of the Ontario retail price cap as of April 1, 2004.

Customer Growth

EGD expects to continue to grow its gas distribution business by adding customers to existing infrastructure, and through geographic extension of the distribution system.

EGD will continue to enhance and build upon the successful penetration of gas-fired heating and drying applications in the new construction markets. Similarly, new channel partnerships are being used to leverage cost-effective growth initiatives such as gas systems in vertical highrise buildings, promotion of commercial space conditioning equipment, and conversion of forklift trucks to clean-burning natural gas. New energy efficiency opportunities will also be developed and initiated in the coming year.

EGD continues to selectively develop new end-use technologies that add load and offer energy efficiency opportunities to its customers. EGD’s technology development initiatives cover a broad range of end-uses, from traditional water heating and space heating to power generation, commercial cooking, and industrial processes.

Energy Efficiency & Demand Side Management

EGD uses its prominent profile in the communities it serves to communicate the benefits and opportunities associated with responsible energy conservation.

The OEB requires that gas distribution companies support demand side management (DSM) programs on behalf of all customer groups. Hence, EGD not only promotes the use of natural gas as an environmentally preferred fuel, but also develops and delivers energy efficiency and conservation programs which enable customers to optimize their energy usage. EGD is exploring business opportunities to assist Ontario’s electric local distribution companies in managing newly created conservation targets.

In 1998, EGD successfully negotiated a regulatory arrangement that awards it a financial incentive when it exceeds its energy efficiency targets. This is in addition to the cost recovery and lost revenue adjustment mechanisms that were already in place to ensure EGD did not bear the costs of supporting DSM.

EGD remains committed to investing in collaborative research, development, demonstration and implementation of more efficient natural gas technologies. Improved end-use offerings not only provide customers with a choice of more efficient, cleaner-burning natural gas appliances, but also deliver improved space conditioning, water heating, commercial cooking and industrial process equipment across all consumer segments.

EGD is facilitating the emergence of Distributed Energy (DE), which is localized power generation close to the site of use. Localized DE technologies are looked upon as a supplement or support to the larger power grid system. Such DE technologies include gas-fired cogeneration or combined heat and power (CHP) systems that utilize waste heat and increase efficiencies, thus conserving resources. Localized natural gas-fired power generation offers many social benefits, including higher energy efficiencies, reduced emissions, and reduced electrical power transmission losses. These higher efficiencies and reduced transmission losses are both forms of responsible energy conservation. Self-generation customers also benefit from improvements in power resiliency and quality, and better cost control. Many customers look towards EGD for sophisticated technical and sales assistance to help them decide their best options.

Historical Operating Statistics for EGD



	15 Months Ended			12 Months Ended						Year Ended
	December 31,			September 30,			September 30,

	2004			2004			2003			2002

Gas supply and sendout (mmcf)¹
Natural gas purchased		214,853			175,746			181,671			117,376

Gas into storage		(104,435	)		(100,700	)		(117,831	)		(51,508	)

Gas out of storage		126,699			95,334			101,615			63,033

Total gas sendout		237,117			170,380			165,455			128,901

Transportation of gas		337,775			272,961			295,775			281,416


Total gas and transportation gas sendout		574,892			443,341			461,230			410,317


Gas sales to customers (mmcf)¹
Residential		132,375			101,170			95,751			74,132

Commercial		69,859			53,021			53,076			42,531

Industrial		14,826			11,155			9,400			8,352

Wholesale		6,283			4,448			4,241			3,523

Gas sales to customers		223,343			169,794			162,468			128,538

Transportation of gas		352,047			274,359			295,775			281,416


Total sales		575,390			444,153			458,243			409,954

Used by EGD (mmcf)¹		265			219			219			226

Other (mmcf)¹		(763	)		(1,031	)		2,768			137


		574,892			443,341			461,230			410,317


Degree day deficiency ²
Actual		5,052			3,774			4,029			3,362

Forecast based on normal weather		4,849			3,565			3,565			3,700


Number of active customers – year end ³		1,726,857			1,705,215			1,652,373			1,597,579


Average use per residential customer (mcf)¹		126			105			109			97

Number of employees – period end		1,633			1,627			1,600			1,585

Miles of mains in use – period end		20,283			20,129			19,513			19,010

Notes:

1. mcf = thousand cubic feet

mmcf = million cubic feet

2.		Degree day deficiency is a measure of coldness, which is indicative of volumetric requirements of natural gas utilized for heating purposes in all markets. It is calculated by accumulating from the start of the fiscal period the total number of degrees each day by which the daily mean temperature falls below 18 degrees Celsius (the figures given are those accumulated in the Toronto area).

3.		Number of active customers includes gas sales and transportation service customers. As the commodity cost of gas is flowed through to gas sales customers with no mark up, the composition of customers between gas sales and transportation service has no impact on EGD’s earnings.



	15 Months Ended		12 Months Ended				Year Ended
	December 31,		September 30,		September 30,

	2004		2004		2003		2002

Number of active customers – period end
Residential		976,384		962,015		925,674		770,754

Commercial		85,338		82,732		81,289		71,807

Industrial		3,441		3,392		3,413		2,938

Wholesale		1		1		1		1

Transportation		661,693		657,075		641,996		752,079


Total active customers		1,726,857		1,705,215		1,652,373		1,597,579

Environment and Safety

The impact of energy usage on the environment is a significant concern with attention being focused not only on the environmental impacts associated with the production, transmission and delivery of energy, but also with respect to emissions resulting from energy use. The relationship of these emissions to potential global climate change and poor local air quality is currently under study by research organizations and governments. The use of fossil fuels results in emissions of carbon dioxide, sulphur dioxide, nitrogen oxides, total suspended particulates, carbon monoxide, volatile organic compounds and methane. However, the levels of these emissions are not the same for all fossil fuel types. Natural gas is the cleanest burning fossil fuel, releasing significantly lower emissions than those arising from oil or coal.

Methane, the principal component of natural gas, is a “greenhouse gas”. Scientists are concerned that increases in greenhouse gas concentrations in the atmosphere could lead to global climate change. Although small atmospheric release of methane during the production, processing, transmission and distribution of natural gas is inevitable, studies have shown that methane emissions from the natural gas industry in Canada, relative to natural sources such as wetlands, are low. The Canadian Gas Association estimates that releases of methane average about 1.13% of total Canadian natural gas production from wellhead to burner tip. Leak detection studies are ongoing to identify potential sources of methane emissions in the distribution of natural gas and to identify specific measures that can be taken to reduce these emissions.

EGD is committed to participating in Canada’s Voluntary Climate Change Challenge and Registry Program, and has been recognized by that organization for its leadership. EGD has implemented measures to reduce methane emissions from its distribution system, lower the energy used in its daily business activities, encourage customer participation in EGD’s energy efficiency and conservation programs, and to promote fuel-switching to natural gas from more polluting fuels. Each of these measures moves EGD closer to the realization of its emission reduction targets, despite the pressures of significant growth in its customer base. These initiatives have been documented by EGD, in conjunction with Enbridge, in annual “Action Plans” submitted to VCR Inc. (the VCR). The VCR, the entity that manages the Voluntary Climate Change Registry, intends to cease operations at the end of 2004. EGD will continue to report into this web-based greenhouse

gas reporting and registry system when it is restructured in 2005 under the Canadian Standards Association (CSA).

Programs have been implemented to ensure adherence to Enbridge’s Environment, Health and Safety policy. These include environmental training for specific employee groups, implementation of environmentally sound construction practices, production of environmental communication materials to increase awareness of key issues, environmental auditing, adoption of an environmental management system and a continuing focus on corporate due diligence. None of the environmental protection requirements applicable to EGD are expected to adversely affect its competitive position, capital expenditure program or level of earnings.

Employees

On December 31, 2004, EGD had 1,633 employees, 37% of whom are unionized and the majority of which are represented by the Communications, Energy and Paperworkers Union, Local 975. The current negotiated collective agreement expires in December 2006.

EGD has filed an AIF, financial statements and Management’s Discussion and Analysis with Canadian Securities Regulatory Authorities. These documents contain detailed disclosure about EGD and are publicly available through www.sedar.com. No part of EGD’s AIF, financial statements or Management’s Discussion and Analysis is intended to be incorporated by reference in this AIF of Enbridge Inc.

Other Gas Distribution and Services Businesses

Other businesses in the Gas Distribution and Services segment include Enbridge Gas Services, Gazifère Inc., Niagara Gas Transmission Ltd. (Niagara Gas), Tidal Energy Marketing, CustomerWorks LP, and ownership interests in Noverco, Enbridge Gas New Brunswick (EGNB), Aux Sable, Sunbridge, and Inuvik Gas. Gazifère is a gas distribution utility located in southwestern Quebec. Niagara Gas provides transmission services to EGD, Gazifère, St. Lawrence and MichCon (an unrelated company). Enbridge Gas Services manages the Company’s merchant capacity commitments on the Alliance and Vector pipelines.

Enbridge Commercial Services Inc., a wholly owned subsidiary, commenced operations on January 1, 2000 to provide information technology, fleet services, call management centre, customer care and billing services to EGD and others. In 2001, Enbridge and Terasen Inc. (formerly BC Gas Inc.) (“Terasen”) formed a new entity, CustomerWorks LP, to provide service covering the entire meter-to-cash process, including many of the services provided by Enbridge Commercial Services. Operations commenced January 1, 2002. CustomerWorks provides services to more than 2.4 million customers including customers of Terasen and EGD. In August 2002, CustomerWorks outsourced the provision of its customer care services to a new entity owned and operated by Accenture Inc.

Enbridge owns an equity interest in Noverco through ownership of common shares and a cost investment through ownership of preferred shares. Noverco is a holding company that owns a 75% interest in Gaz Metro L.P., a gas distribution company operating in the province of Quebec and the state of Vermont. Gaz Metro L.P. has a 50% interest in TQM Pipeline, a pipeline transporting natural gas in Quebec.

The Company owns 63% of and operates EGNB, the natural gas distribution franchise in the province of New Brunswick. EGNB constructed a new distribution system and has approximately 3,150 customers. Over 310 kilometres (193 miles) of distribution main has been installed with the capability of attaching between 14,000 and 15,000 customers. EGNB is regulated by the New Brunswick Board of Commissioners of Public Utilities.

Enbridge also holds a 42.7% interest in the Aux Sable natural gas liquids extraction and fractionation facility. This facility processes up to 1.6 bcf of natural gas per day delivered through the Alliance Pipeline and recovers ethane, propane, butane and pentane.

Enbridge performs liquids marketing activities through its ownership of Tidal Energy Marketing Inc. and is a partner in the SunBridge wind power project. In January 2002, the Company entered into a strategic alliance to facilitate the development of heavy oil upgrading technology. These activities require limited capital and are not expected to provide significant returns in the near term.

The Company also holds a 33.3% interest in the Inuvik Gas project, a 30-mile gas pipeline and a local distribution network that supplies natural gas to the Town of Inuvik in the Northwest Territories. This project represents the first commercialization of Mackenzie Delta natural gas reserves and augments the Company’s experience with construction of pipelines in permafrost conditions. It also provided a successful model for cooperation with local interests in the development of energy delivery infrastructure.

Employees

Enbridge employs approximately 185 individuals in its Other Gas Distribution and Services businesses.

INTERNATIONAL

The Company’s International business invests in energy transportation and related energy projects outside of Canada and the United States. This business also provides consulting and training services related to proprietary pipeline operating technologies and natural gas distribution. The Company has a 25% interest in a Spanish pipeline company, Compañia Logistica de Hidrocarburos (CLH), a 24.7% investment in the Colombian crude oil pipeline, Oleoducto Central S.A. (OCENSA), and a 100% interest in CIT Colombiana S.A. (CITCol), which is responsible for operating the OCENSA pipeline. The Company holds a 45% interest in the Sociedad Williams Enbridge Compañia (SWEC) Partnership that previously operated the Jose Terminal in Venezuela.

CLH is the largest basic logistics distribution network for refined products in Spain and provides services on an open access non-discriminatory basis. The system consists of over 3,400 kilometers of pipelines and 40 storage facilities located throughout the country. CLH provides product distribution to locations not connected to the pipeline system through its own fleet of tanker trucks and chartered tanker ships. CLH’s core business is the provision of basic logistics and the company also offers secondary distribution services, the most significant being the services provided through CLH Aviation, which handles aviation fuel at airport locations throughout Spain. This business includes the storage of aviation fuel, loading of aircraft refueling units and the refueling of aircraft. New policies issued by the Spanish airport authority (AENA) to promote competition, allow for new non-CLH operators to enter the aircraft-refueling segment of this business. While CLH’s share of this segment of the market may reduce over time, the aviation fuel business will continue. CLH’s pipeline facilities are connected to the country’s eight crude oil refineries and to major coastal port locations where crude oil and refined products are imported.

The OCENSA pipeline consists of 515 miles of 30-inch and 36-inch pipeline, pumping units, tankage and marine loading facilities, with a capacity to transport 550,000 barrels per day of crude oil. The pipeline links the Cuisiana and Cupiagua oilfields in the central interior of Colombia to the Port of Coveñas on the Caribbean coast. The Company earns a fixed rate of return on the OCENSA pipeline investment, as well as operating fees, through its 100% interest in the operating entity, CITCol.

The Jose Terminal is part of a large petroleum and petrochemical complex in Venezuela and handles crude oil from eastern Venezuelan fields for loading into tankers for export. As a result of breaches of the Jose Terminal operating agreement by PDVSA, the Venezuelan state oil company, the SWEC Partnership terminated the agreement and filed for international arbitration, as provided for in the operating agreement. The arbitration proceedings concluded January 19, 2005 and a decision is expected later in the year. The company ceased recognition of earnings commencing February 1, 2003.

Through Enbridge Technology Inc. (Enbridge Technology), the Company offers technology solutions for liquid hydrocarbon pipelines and natural gas transmission and distribution companies around the world. In addition to pipeline operator training services, Enbridge Technology offers advisory, technology transfer, engineering and contract operations services.

The international operations of Enbridge are subject to federal, state or local laws and regulations relating to environmental protection and operational safety. To the best of the Company’s knowledge, all international

operations are in compliance with applicable environmental and safety regulations. Risks of significant costs and liabilities, however, are inherent in the nature of the operations, and there can be no assurances that such costs and liabilities will not be incurred.

Employees

Enbridge’s International operations directly employ 31 individuals.

CORPORATE

Corporate activities are limited to business development activities not attributable to a specific business segment, corporate financing costs and various support personnel costs. In addition, business activities in the development stage or those that may represent an emerging technology are included in Corporate. These activities are seen as potential growth areas that may have a strategic fit with existing operations or present the opportunity to enhance activity levels in existing operating segments. Approximately 163 employees are employed in the Corporate segment.

RISK FACTORS

A discussion of the Company’s risk factors is contained in the following subsections of the Management’s Discussion and Analysis for the year ended December 31, 2004, which are incorporated herein by reference (the page references below are to the Company’s 2004 Management’s Discussion and Analysis filed on SEDAR at www.sedar.com):

Liquids Pipelines – Business Risks (page 11);
Gas Pipelines – Business Risks (pages 14 to 15);
Sponsored Investments – Business Risks (pages 19 to 20);
Gas Distribution and Services – Business Risks (pages 28 to 29);
International – Business Risks (page 31);
Overall Risk Management (pages 37 to 39).

DIVIDENDS


DIVIDENDS PAID
(Canadian dollars per share)	2004		2003		2002

Preference Shares, Series A		1.375		1.375		1.375
Common Shares		1.830		1.660		1.520

Dividends on common shares are paid quarterly as determined by the Company’s Board of Directors. The Company’s common share dividend in recent years has been in a range of approximately 50-60% of adjusted operating earnings and, subject to Board approval, is expected to continue in this range. Dividends on the preference shares, Series A, are fixed and are paid quarterly.

There are no restrictions that currently prevent the Company from paying dividends. However, in the event of liquidation, dissolution or winding-up of the Company, the preferred shareholders have priority in the payment of dividends over the common shareholders. As well, should the Company fail to make payments on certain financial obligations, the Company could be precluded from paying dividends on its common and preferred shares.

DESCRIPTION OF CAPITAL STRUCTURE

GENERAL DESCRIPTION OF CAPITAL STRUCTURE

At December 31, 2004, the Company’s capital structure consists of 173.1 million common shares with a book value of $2,282.4 million and 5.0 million preference shares, Series A with a book value of $125.0 million.

Common Shares

The authorized share capital of the Company consists of an unlimited number of common shares with no par value and an unlimited number of preferred shares. Each common shareholder is entitled to one vote at all such meetings of shareholders for each share held.

Under the dividend reinvestment and share purchase plan, registered shareholders may reinvest their dividends in additional common shares of the Company or make optional cash payments to purchase additional common shares, in either case, free of brokerage or other charges.

The Company has a Shareholder Rights Plan that is designed to encourage the fair treatment of shareholders in connection with any take-over offer for the Company. Rights issued under the plan become exercisable when a person, and any related parties, acquires or announces the intention to acquire 20% or more of the Company’s outstanding common shares without complying with certain provisions set out in the plan or without approval of the Board of Directors of the Company. Should such an acquisition occur, each rights holder, other than the acquiring person and related parties, will have the right to purchase common shares of the Company at a 50% discount to the market price at that time.

Preferred Shares

The 5.5% Cumulative Redeemable Preference Shares, Series A are entitled to fixed, cumulative, preferential dividends of $1.375 per share per year, payable quarterly. Preferred shareholders have no voting rights. The Company may, at its option, redeem all or a portion of the outstanding preferred shares for $25.75 per share if redeemed on or prior to December 1, 2005; $25.50 per share if redeemed on or prior to December 1, 2006; $25.25 per share if redeemed on or prior to December 1, 2007; and $25.00 per share if redeemed thereafter, in each case with all accrued and unpaid dividends to the redemption date.

RATINGS

The following table sets forth the ratings assigned to the Company’s Preference Shares, Series A, Preferred Securities, Commercial Paper and Unsecured Debt by Dominion Bond Rating Service Limited (DBRS), Standard & Poor’s Ratings Services (S&P) and Moody’s Investor Services, Inc. (Moody’s):


	DBRS	S&P	Moody’s
Preference Shares, Series A	Pfd-2 (low)¹	P-2³	Baa2⁵
Preferred Securities	Pfd-2y¹	BBB³	Baa1⁵
Commercial Paper	R-1 (low)²	A-1 (low)⁴	Not Rated
Unsecured Debt	A²	A-⁴	A3⁶

Notes:

1.		DBRS’ rating of preferred securities and preferred shares is on a rating scale that ranges from a high of Pfd-1 to a low of Pfd-5. The ‘y’ modifier is used to indicate a hybrid security. DBRS also applies modifiers ‘high’, ‘medium’, and ‘low which indicate where the obligation ranks in its generic rating category.

2.		DBRS rates debt instruments by rating categories from a high of ‘AAA’ to a low of ‘C’. DBRS’ rating of commercial paper is on a rating scale that ranges from a high of R-1 to a low of D. DBRS applies modifiers ‘high’, ‘medium’, and ‘low’ which indicate where the obligation ranks in its generic rating category.

3.		S&P rates preferred shares using categories from a high of ‘P-1’ to a low of ‘P-5’. Preferred securities are rated using a long-term debt rating scale that ranges from a high of ‘AAA’ to a low of ‘D’.

4.		S&P rates debt instruments by rating categories from a high of ‘AAA’ to a low of ‘D’. S&P’s rating of commercial paper is on a rating scale that ranges from a high of A-1 to a low of C. S&P applies modifiers ‘high’, ‘medium’, and ‘low’, which indicate where the obligation ranks in its generic rating category.

5.		Moody’s rates securities and shares by rating categories from a high of ‘Aaa’ to a low of ‘C’. Moody’s applies modifiers 1, 2 and 3, which indicate where the obligation ranks in its generic rating category. Modifier 1 is higher end, modifier 2 is mid-range and modifier 3 is low end ranking of the generic rating category.

6.		Moody’s rates debt instruments by rating categories from a high of ‘Aaa’ to a low of ‘C’. Moody’s applies modifiers ‘1’, ‘2’ and ‘3’, which indicate where the obligation ranks in its generic rating category. Modifier ‘1’ is higher end, modifier ‘2’ is mid-range and modifier ‘3’ is low end ranking of the generic rating category.

The credit ratings accorded by these rating agencies are not recommendations to purchase, hold or sell the shares or securities inasmuch as such ratings do not comment as to market price or suitability for a particular investor. There is no assurance that any rating will remain in effect for any given period of time or that any rating will not be revised or withdrawn entirely by a rating agency in the future if, in its judgment, circumstances so warrant.

MARKET FOR SECURITIES

The following table sets forth the monthly price range and volume traded for each of the Company’publicly traded securities for each month during the most recently completed financial year.



			TSX (C$)						NYSE (US$)
			ENB		ENB.PR.A		ENB.PR.D		ENB
January		High		54.10		26.70		28.20		42.32
		Low		50.36		25.96		26.81		38.10
	30-Jan	Close		51.00		26.11		28.00		38.46

		Volume		7,209,100		224,116		94,874		167,500

February		High		52.30		26.70		28.49		39.44
		Low		50.50		26.13		27.80		37.72
	27-Feb	Close		51.89		26.55		27.97		38.87
		Volume		7,879,000		52,919		88,357		268,100

March		High		55.00		26.74		28.38		41.54
		Low		51.31		26.20		27.25		38.41
	31-Mar	Close		53.30		26.64		27.98		40.69
		Volume		7,669,100		40,989		180,984		371,600

April		High		54.39		26.34		28.00		41.25
		Low		48.51		25.00		26.36		35.45
	30-Apr	Close		50.15		25.11		27.05		36.45
		Volume		10,932,600		46,660		147,733		366,800

May		High		53.44		25.81		27.38		38.57
		Low		49.45		24.39		25.61		36.15
	31-May	Close		50.35		25.55		26.85		36.55
		Volume		7,228,200		102,067		103,657		198,100

June		High		50.36		25.81		26.85		37.20
		Low		47.60		24.81		25.64		35.18
	30-Jun	Close		48.71		25.28		26.00		36.59
		Volume		5,523,400		126,186		101,430		325,500

July		High		50.83		26.22		27.40		38.30
		Low		47.25		25.25		25.86		36.38
	31-Jul	Close		50.10		26.10		26.60		37.84
		Volume		5,268,500		28,529		88,767		278,300

August		High		52.75		25.96		27.30		40.00
		Low		49.15		25.50		26.30		37.45
	31-Aug	Close		52.62		25.70		26.75		39.75
		Volume		5,616,000		29,638		147,892		209,800

September		High		53.35		26.05		27.38		41.85
		Low		51.01		25.38		26.51		39.40
	30-Sep	Close		52.75		25.38		26.61		41.64
		Volume		4,821,400		33,230		97,839		289,900

October		High		53.50		25.99		27.39		43.41
		Low		51.05		25.31		26.65		40.70
	29-Oct	Close		52.88		25.73		27.00		43.41
		Volume		4,557,400		38,008		130,367		567,200

November		High		57.90		26.00		27.91		48.76
		Low		51.21		25.62		26.74		42.28
	30-Nov	Close		57.50		25.76		27.40		48.50
		Volume		5,313,600		70,401		100,925		552,600

December		High		60.15		26.16		28.00		49.99
		Low		55.80		25.66		27.02		45.30
	31-Dec	Close		59.70		26.16		27.78		49.78
		Volume		5,613,500		25,826		127,804		741,100

Annual		High		60.15		26.74		28.49		49.99
		Low		47.25		24.39		25.61		35.18
		Close		59.70		26.16		27.78		49.78
		Volume		77,631,800		818,569		1,410,629		4,336,500

As of the date of this Annual Information Form, the common shares of the Company are traded on the Toronto Stock Exchange in Canada and on the New York Stock Exchange in the United States under the symbol ENB. The Toronto Stock Exchange is the principal market for Enbridge’s common shares. The Preference Shares, Series A are traded on the Toronto Stock Exchange under the symbol ENB.PR.A and the preferred securities, series 7.8%, are traded on the Toronto Stock Exchange under the symbol ENB.PR.D.

DIRECTORS AND OFFICERS

DIRECTORS

The following table sets forth the names of the Directors of Enbridge Inc. effective December 31, 2004, unless otherwise noted, their municipalities of residence, their respective principal occupations within the five preceding years and the year from which they first became a Director of the Company. Enbridge does not have an Executive Committee. As required, the Company has an Audit, Finance & Risk Committee.



Name ¹ and	Principal Occupation for the	Year First Became
Municipality of Residence	Five Preceding Years	a Director²

DAVID A. ARLEDGE^{3, 6} Naples, Florida	Corporate Director; Vice Chairman of the Board of Directors of El Paso Corporation (integrated energy company) in 2001; prior thereto, Chairman, President and/or Chief Executive Officer of the Coastal Corporation since 1994.		2002

JAMES J. BLANCHARD^{4, 5} Beverly Hills, Michigan	Senior Partner, DLA Piper Rudnick Gray Cary U.S., LLP (law firm), since 1996; prior thereto, United States Ambassador to Canada.		1999

J. LORNE BRAITHWAITE^{4, 5} Thornhill, Ontario	Corporate Director; President & Chief Executive Officer of Cambridge Shopping Centres Limited (developer and manager of retail shopping malls in Canada) from 1978 to 2001.		1989

PATRICK D. DANIEL Calgary, Alberta	President & Chief Executive Officer of Enbridge since January 2001; prior thereto, President & Chief Operating Officer of Enbridge since September 2000; prior thereto, President & Chief Operating Officer – Energy Delivery of Enbridge since 1999.		2000

E. SUSAN EVANS^{3, 6} Calgary, Alberta	Corporate Director.		1996

WILLIAM R. FATT^{3, 6, 7} Toronto, Ontario	Chief Executive Officer of Fairmont Hotels & Resorts Inc. since September 2001; prior thereto, Chairman & Chief Executive Officer of Canadian Pacific Hotels & Resorts Inc. since January 1998.		2000

LOUIS D. HYNDMAN^{3, 4} Edmonton, Alberta	Senior Partner, Field Law LLP (law firm).		1993

ROBERT W. MARTIN^{3, 6, 8} Toronto, Ontario	Corporate Director; Chairman of Silcorp Limited (convenience stores) from 1993 to 1999.		1992



Name ¹ and	Principal Occupation for the	Year First Became
Municipality of Residence	Five Preceding Years	a Director²

GEORGE K. PETTY^{4, 5} San Luis Obispo, California	Corporate Director; President & Chief Executive Officer of Telus Corporation (telecommunications company) from 1994 to 1999.		2001

CHARLES E. SHULTZ Calgary, Alberta	Chairman & Chief Executive Officer of Dauntless Energy Inc. (private oil and gas corporation) since 1995; Chairman of Calpine Power Income Fund (public utilities company) and Canadian Oil Sands Limited (a subsidiary of Canadian Oil Sands Trust, a public oil and gas trust).		2004

DONALD J. TAYLOR^{5, 6} Jacksons Point, Ontario	Corporate Director; Chair of the Board of Directors of Enbridge Inc. since 1996.		1979

Notes:

1.		Each Director elected holds office until the next annual meeting of shareholders or until a successor is duly elected or appointed.

2.		“Year First Became a Director” refers to the year the person named was elected or appointed as a Director of the Company or of its predecessor parent, Interprovincial Pipe Line Inc.

3.		Member of the Audit, Finance & Risk Committee of the Board of Directors.

4.		Member of the Corporate Social Responsibility Committee of the Board of Directors.

5.		Member of the Governance Committee of the Board of Directors.

6.		Member of the Human Resources & Compensation Committee of the Board of Directors.

7.		Mr. Fatt was a director of Unitel Inc., a company that instituted a compromise with its creditors on December 8, 1995. Mr. Fatt resigned as a director of Unitel in January 1996.

8.		Mr. Martin was a director of the following corporations when they became bankrupt, made a proposal under the bankruptcy or insolvency legislation or were subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver manager or trustee appointed to hold their assets: Silcorp Ltd., Peoples Jewellers Limited and Confederation Life Insurance Company.

		On December 2, 2003, the Ontario Securities Commission (the “Commission”) issued a temporary cease trade order against Atlas Cold Storage Income Trust (“Atlas”), and subsequently a cease trade order on December 15, 2003 after Atlas failed to file its interim financial statements for its nine-month period ended September 30, 2003. Under such orders, certain trustees, including Mr. Martin, were prohibited from trading Atlas trust units until the Commission was in receipt of the necessary filings. Atlas made the requisite filings on January 27, 2004 and the cease trade order lapsed on February 2, 2004.

OFFICERS

The following table sets forth the names of the executive officers, their current office with the Company effective December 31, 2004, unless otherwise noted, their municipality of residence and their principal occupations for the five preceding years.



Name, Position and		Position and Principal Occupations for the
Municipality of Residence		Five Preceding Years

PATRICK D. DANIEL President & Chief Executive Officer Calgary, Alberta		President & Chief Executive Officer since January 2001; prior thereto, President & Chief Operating Officer from September to December 2000; prior thereto, President & Chief Operating Officer – Energy Delivery since 1999.



Name, Position and		Position and Principal Occupations for the
Municipality of Residence		Five Preceding Years

MEL F. BELICH Group Vice President, International & Corporate Law Calgary, Alberta		Group Vice President, International & Corporate Law since April 2003; prior thereto, Group Vice President, International since September 2000; prior thereto, Senior Vice President, International Development & Corporate Law, and Corporate Secretary since 1999.

J. RICHARD BIRD Group Vice President, Transportation North Calgary, Alberta		Group Vice President, Transportation North since May 2001; prior thereto, Group Vice President, Transportation since September 2000; prior thereto, Senior Vice President, Corporate Planning & Development since 1997.

BONNIE D. DUPONT Group Vice President, Corporate Resources Calgary, Alberta		Group Vice President, Corporate Resources since September 2000; prior thereto, Senior Vice President, Human Resources & Public Affairs since 1999.

STEPHEN J.J. LETWIN Group Vice President, Gas Strategy & Corporate Development Calgary, Alberta		Group Vice President, Gas Strategy & Corporate Development since April 2003; prior thereto, Group Vice President, Distribution & Services since September 2000; prior thereto, President & Chief Operating Officer – Energy Services since 1999.

DAN C. TUTCHER Group Vice President, Transportation South Houston, Texas		Group Vice President, Transportation South since May 2001; prior thereto, Chairman of the Board, President & Chief Executive Officer of Midcoast Energy Resources, Inc. since 1992.

STEPHEN J. WUORI Group Vice President & Chief Financial Officer Calgary, Alberta		Group Vice President & Chief Financial Officer since April 2003; prior thereto, Group Vice President, Planning & Development since September 2000; prior thereto, President, Enbridge Pipelines Inc.

JAMES A. SCHULTZ Senior Vice President Gormley, Ontario		Senior Vice President since April 2003; President of Enbridge Gas Distribution Inc. (“EGDI”) since June 2001; prior thereto, Vice President, Operations and Engineering, EGDI, since July 1999.

SCOTT R. WILSON Senior Vice President & Controller Calgary, Alberta		Senior Vice President & Controller since June 2003; prior thereto, Senior Vice President, Finance since April 2003; prior thereto, Vice President, Finance since October 2001; prior thereto, Vice President & Treasurer since 1998.

LEIGH S. CRUESS Vice President, Financial Services Calgary, Alberta		Vice President, Financial Services since April 2003; prior thereto, Vice President, Corporate Development since January 2000; prior thereto, Vice President of UtiliCorp United Inc. since 1996.

AL MONACO Senior Vice President, Planning & Development Calgary, Alberta		Senior Vice President, Planning & Development since June 2003; prior thereto, Vice President, Financial Services since February, 2002; prior thereto, Director, Financial Services since 2000; prior thereto, Director, Investor Relations.

DARBY J. WADE Vice President & General Counsel Calgary, Alberta		Vice President & General Counsel since September 2000; prior thereto, Director of Law & Commercial Affairs of Enbridge International Inc.

JOHN K. WHELEN Vice President & Treasurer Calgary, Alberta		Vice President & Treasurer since February 2002; prior thereto, Assistant Treasurer.



Name, Position and		Position and Principal Occupations for the
Municipality of Residence		Five Preceding Years

BLAINE G. MELNYK Corporate Secretary & Associate General Counsel Calgary, Alberta		Corporate Secretary & Associate General Counsel since September 2000; prior thereto, Senior Legal Counsel & Assistant Corporate Secretary.

As at December 31, 2004, the directors and officers of the Issuer beneficially owned, directly or indirectly, 770,885 common shares of the Issuer, representing approximately 0.45% of the issued and outstanding common shares on that date. The information as to shares beneficially owned or over which control or direction is exercised, not being within the knowledge of the Issuer, has been furnished by the respective directors and officers individually. The directors and officers do not beneficially own, directly or indirectly, any voting securities of any subsidiary of the Issuer.

LEGAL PROCEEDINGS

The information, which is found under note 21 “Commitments and Contingencies” of the Company’s audited consolidated financial statements, as at, and for the year ended, December 31, 2004, is incorporated by reference herein.

REGISTRAR AND TRANSFER AGENT

The registrar and transfer agent for the common shares is CIBC Mellon Trust Company at its principal offices in Vancouver, British Columbia; Calgary, Alberta; Winnipeg, Manitoba; Toronto, Ontario; Montreal, Quebec; and Halifax, Nova Scotia. The co-registrar and co-transfer agent in the United States for the common shares is Mellon Investor Services at its principal office in Ridgefield Park, New Jersey.

The registrar and transfer agent for the Preference Shares, Series A is CIBC Mellon Trust Company at its principal offices in Vancouver, British Columbia; Calgary, Alberta; Winnipeg, Manitoba; Toronto, Ontario; Montreal, Quebec; and Halifax, Nova Scotia.

The registrar and transfer agent for the Preferred Securities, Series D is Computershare Trust Company of Canada at its principal office in Calgary, Alberta.

INTERESTS OF EXPERTS

The consolidated financial statements of the Company, as at and for the years ended December 31, 2004 and 2003, have been examined by PricewaterhouseCoopers LLP, Chartered Accountants, as detailed in their auditors’ report dated January 25, 2005.

ADDITIONAL INFORMATION

Additional information, including Directors’ and Officers’ remuneration and indebtedness, principal holders of the Company’s securities and options to purchase Enbridge’s securities, and the interest of insiders in material transactions, all as at December 31, 2004, is contained in Enbridge’s Management Information Circular dated March 4, 2005 furnished in connection with the Annual and Special Meeting of Shareholders to be held on May 5, 2005 for the purpose of, among other things, the election of directors. Additional financial information is provided in the Company’s comparative financial statements and management’s

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•	Liquids Pipelines includes the operation of a common carrier pipeline and feeder pipelines that transport crude oil and other liquid hydrocarbons.

•	Gas Pipelines includes proportionately consolidated investments in pipelines that transport natural gas including the U.S. portion of the Alliance Pipeline, Vector Pipeline and a system of transmission and gathering pipelines in the Gulf of Mexico.

•	Sponsored Investments consists of the Company’s investments in Enbridge Energy Partners, L.P. (EEP), Enbridge Energy Management, L.L.C. (EEM) (collectively, the Partnership) and Enbridge Income Fund (EIF). The Partnership transports crude oil and other liquid hydrocarbons through common carrier and feeder pipelines and transports, gathers, processes and markets natural gas and natural gas liquids. Enbridge Income Fund is a publicly traded income fund whose assets are a 50% interest in a gas transmission pipeline and a 100% interest in a crude oil and liquids pipeline and gathering system.

•	Gas Distribution and Services consists of gas utility operations which serve residential, commercial, industrial and transportation customers, primarily in central and eastern Ontario. It also includes natural gas distribution in Quebec, New Brunswick and New York State, as well as gas services operations, including the Company’s proportionately consolidated investment in Aux Sable, a natural gas fractionation and extraction business near Chicago, Illinois.

•	The Company’s International business invests in energy transportation and related energy projects outside of Canada and the United States. This business also provides consulting and training services related to proprietary pipeline operating technologies and natural gas distribution.

(i)	a Western Canadian segment that consists of five pipelines, ranging in diameter from 16-48 inches, with a capacity of 1,930,000 barrels/day from Edmonton, Alberta to the U.S. border near Gretna, Manitoba.

(ii)	a Sarnia, Ontario to Toronto, Ontario segment that consists of two 20-inch lines from Sarnia to the Toronto area, with a capacity of 150,000 barrels per day. The Sarnia to Toronto segment includes lateral lines (ranging from 12 to 20 inches) from Westover, Ontario, to Nanticoke, Ontario and Niagara Falls, Ontario.

(iii)	a Montreal, Quebec to Sarnia, Ontario segment, Line 9, which consists of a 30-inch line with a capacity of 240,000 barrels per day.

Notes:

(1)		National Energy Board 2004 Estimate Production of Canadian Crude Oil and Equivalent Table 1

(2)		Oil and Gas Journal’s Worldwide Look at Reserves and Production, December 20, 2004