ENBRIDGE INC.

ANNUAL INFORMATION FORM

For the Year Ended December 31, 2003
dated
April 13, 2004

ENBRIDGE INC.
ANNUAL INFORMATION FORM
For the Year Ended December 31, 2003

TABLE OF CONTENTS

		Page
Item 1	Cover Page	i
Item 2	Corporate Structure	1
Item 3	General Development of the Business	2
Item 4	Narrative Description of the Business	5
	Liquids Pipelines	5
	Gas Pipelines	11
	Sponsored Investments	11
	Gas Distribution and Services	12
	International	21
	Corporate	21
Item 5	Risk Factors	22
Item 6	Dividends	23
Item 7	Description of Capital Structure	24
Item 8	Market for Securities	26
Item 9	Directors and Officers	28
Item 10	Legal Proceedings	32
Item 11	Registrar and Transfer Agent	33
Item 12	Additional Information	34

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.

When used in this Annual Information Form, 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 Issuer’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.

ITEM 2

CORPORATE STRUCTURE

Incorporation of the Issuer

Enbridge Inc. (the Issuer or 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 Issuer, 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 Issuer.

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 Issuer 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.

Subsidiaries

Each subsidiary listed below is 100% owned, directly or indirectly, by the Issuer. 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, respectively, of the Issuer and considered in the aggregate, their total revenue and total assets are less than 20% of the consolidated revenue and consolidated assets, respectively, of the Issuer.

Name				Jurisdiction of Incorporation
IPL System Inc.				Canada
	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 Inc.				Canada

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ITEM 3

GENERAL DEVELOPMENT OF THE BUSINESS

The Issuer’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 transmission pipelines that transport natural gas.

• 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. From May 2001 to October 2002, the Company, through its subsidiary, Enbridge Pipelines Inc., owned 100% of Enbridge Midcoast Energy, which is now a wholly owned subsidiary of EEP. 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 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 and natural gas gathering and processing operations through an equity investment in AltaGas Services Inc.

• 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 Issuer’s business over the last three years.

On December 31, 2003, EEP, a sponsored investment of the Issuer, acquired natural gas gathering and processing assets in north Texas. The assets were purchased for cash of US$249.7 million.

On December 22, 2003, the Issuer announced the acquisition of several assets from Shell Pipeline Company LP and Shell Oil Products U.S. The acquisition consists primarily of two different pipelines and two crude oil storage terminals that are to be acquired by EEP for approximate consideration of US$115 million. Closing of this acquisition is anticipated to occur in the first quarter of 2004, subject to regulatory approvals and rights of first refusal.

Underground cavern storage facilities were placed into service on November 1, 2003. The Company commenced development of underground cavern facilities to provide crude oil storage services through a partnership with CCS Income Trust in 2002. The storage 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 billion cubic feet (bcf) per day. The pipeline commenced operations in late 2000.

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In September 2003, the Company acquired 90% of the outstanding shares of CCPS Transportation L.L.C., owner of a 650-mile crude oil pipeline system extending from Cushing, Oklahoma to Chicago, Illinois. Of the total purchase price, $78.3 million was paid on the date of acquisition. Payment of the remaining US$65.0 depends upon completion of reversal of the flow of the pipeline and must be paid no later than December 31, 2004 to allow reversal to proceed. Upon reversal, which, subject to shipper and regulatory approvals, is expected to be completed in 2004, the pipeline will transport Canadian crude south from Chicago to Cushing, Oklahoma and will be renamed the Spearhead Pipeline.

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 before working capital adjustments of $20.6 million and transaction costs of $0.2 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. 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 added 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 approximately 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 $1,279.4 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, increasing its effective ownership in the Partnership to 14.1% from 12.9%. Subsequent to this transaction, the Company’s effective interest in the Partnership decreased from 14.1% to 12.2% due to unit issuances by EEP, which the Company did not participate in. 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”.

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.

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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 has advised Enbridge that their principal focus includes the financial forecast made in connection with the US$820 million sale transaction and the price for the assets. The SEC staff has not asserted that Enbridge, EEP or EEM have acted improperly or illegally, and it has not indicated an intention to seek a formal order of investigation. Enbridge is cooperating 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.

Enbridge acquired Midcoast Energy Resources, Inc. (Enbridge Midcoast Energy) on May 11, 2001 for $561.8 million and the assumption of $406.0 million of long-term debt. Enbridge Midcoast Energy transports, gathers, processes and markets natural gas and other petroleum products. In January 2002, Enbridge Midcoast Energy acquired the South Texas System for $14.3 million. This system includes approximately 175 miles of natural gas gathering pipelines, a hydrogen sulfide treating plant and an inactive natural gas processing plant. In March 2002, Enbridge Midcoast Energy acquired natural gas gathering and processing facilities in northeast Texas (the Northeast Texas assets) from Sulphur River Gathering L.P. for approximately $290 million. The Northeast Texas assets consist of 1,100 miles of natural gas gathering pipelines and gas treating and processing plants. These assets were sold to EEP in October 2002 as previously disclosed.

During 2001, Enbridge and B.C. Gas Inc. created a limited partnership to develop and operate a new entity, CustomerWorks LP (CustomerWorks), that provides full-service customer management solutions to utilities, municipalities and retail energy companies across Canada. CustomerWorks provides services to more than 3.5 million customers including those from Terasen Gas, Enbridge Gas Distribution Inc. (Enbridge Gas) and Enbridge Gas New Brunswick. In August 2002, CustomerWorks outsourced the provision of its customer care services to a new entity owned by Accenture Inc.

The SunBridge wind power project was officially opened in June 2002. The $22 million project, which generates approximately 11 megawatts of electricity, is operated by Enbridge and was developed through a 50/50 partnership with Suncor Energy Inc. SaskPower is purchasing the wind-generated electricity for sale to the Government of Canada and other customers in Saskatchewan.

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. These operations include the water heater rental program; retail appliance, fireplace and water heater sales and service; mass market commercial plumbing, heating, ventilation and air conditioning; appliance repair and electrician contractor services in Canada and the United States; and the consumer financing operations.

In 2002, Enbridge acquired 25% of Compañia Logistica de Hidrocarburos CLH, S.A. (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. Contingent consideration of up to 84.3 million Euros ($137.2 million) will become payable over the next three years if certain minimum annual and cumulative volume targets are met.

The Issuer acquired an additional 34% interest in the Frontier Pipeline Company in the fourth quarter of 2001 for US$28.9 million, increasing Enbridge’s interest to 77.8%. The Frontier Pipeline transports crude oil from Casper, Wyoming to the Salt Lake City area of Utah.

Enbridge is a 63% participant in Enbridge Gas New Brunswick, which was awarded the franchise for natural gas distribution in the Province of New Brunswick in September 1999. This investment provides the Issuer with a strategic presence in Atlantic Canada. Operations commenced with initial customer connections in March 2001.

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ITEM 4

NARRATIVE DESCRIPTION OF THE BUSINESS

Revenues by Segment

(Canadian dollars in millions)	2003		2002		2001
Liquids Pipelines		821.5		787.7		722.9
Gas Pipelines		222.1		—		—
Sponsored Investments1		—		1,219.0		681.5
Gas Distribution and Services		3,785.4		2,513.5		2,645.7
International		26.2		27.2		30.8
Corporate		0.1		0.1		—
Revenues from continuing operations		4,855.3		4,547.5		4,080.9
Revenues from discontinued operations		—		181.9		463.0
Total Revenues		4,855.3		4,729.4		4,543.9

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

LIQUIDS PIPELINES

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

Liquids Pipelines Business

The Issuer has ownership in, and operates, the world’s longest liquid petroleum pipeline system. The main pipeline system (the System) consists of the Enbridge System in Canada and the Lakehead System 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 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 the Province of Ontario, as well as the Great Lakes region of the United States. A system owned by Enbridge Pipelines (NW) Inc. (NW System) transports crude oil from the Northwest Territories to the Enbridge System. The Athabasca System transports synthetic and heavy crude oil from the Athabasca and Cold Lake regions of Alberta to Hardisty, Alberta. In addition, the Issuer owns various feeder pipeline systems (Frontier, Toledo, Mustang and Chicap), which operate in the United States, as well as a 90% interest in the Cushing to Chicago Pipeline System (CCPS), which was acquired in the third quarter of 2003.

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. The Lakehead System reconnects with the Enbridge System at the U.S. border near Sarnia, Ontario. The Enbridge System extends from Sarnia 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). Total deliveries averaged 1,864,000 barrels per day in 2003.

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 or to other carriers for transportation to other Canadian or U.S. refineries. The NW System is regulated by the NEB and is subject to a negotiated

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settlement and throughput agreement with its main shipper. Total deliveries averaged 26,600 barrels per day in 2003.

The Athabasca System, which is owned by Enbridge Pipelines (Athabasca) Inc. (Enbridge Athabasca), 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 or other carriers for transportation to Canadian or 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 Athabasca has a 30-year transportation arrangement with Suncor Energy Inc., the initial shipper on the pipeline. The Athabasca System is regulated by the Alberta Energy and Utilities Board (the EUB).

CCPS was acquired by the Issuer in September 2003. It has a capacity of 300,000 barrels per day, including 4.3 million barrels of tankage, and extends approximately 650 miles from Chicago, Illinois to Cushing, Oklahoma. CCPS has historically operated a south-to-north service, but the Issuer intends to reverse the flow of this system in order to transport Canadian crude south by the end of 2004. Reversal of the line is dependent upon acceptance of proposed tolling arrangements by Canadian producers and regulatory approval. The reversed line would be renamed the Spearhead Pipeline.

The Frontier System is owned by Frontier Pipeline Company, a Wyoming general partnership owned 77.8% by the Issuer. This pipeline 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 total deliveries averaged 41,700 barrels per day in 2003. The Frontier System is regulated by the Federal Energy Regulatory Commission (FERC).

The Mustang System is owned and operated by Mustang Pipe Line Company, a Delaware general partnership, owned 30% by the Issuer. This pipeline consists of 215 miles of 18-inch line with a capacity of 100,000 barrels per day. Total deliveries averaged 50,200 barrels per day in 2003. The Mustang System receives crude oil from the Lakehead System in the Chicago, Illinois area and delivers to the Patoka, Illinois area. The Mustang System is regulated by the FERC.

The Chicap System is owned and operated by Chicap Pipe Line Company, a Delaware corporation, owned 23% by the Issuer. This pipeline 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. Total deliveries averaged approximately 221,700 barrels per day in 2003. The Chicap System is regulated by the FERC.

The Toledo System is owned and operated the Issuer. This pipeline consists of 35 miles of 16-inch line and connects the Lakehead System at Stockbridge, Michigan to two refineries in the Toledo, Ohio area. The pipeline has a capacity of 80,000 barrels per day of heavy crude oil and total deliveries averaged 63,400 barrels per day in 2003. The Toledo System is regulated by the FERC.

Enbridge System

Properties

The Enbridge System (including Terrace Phase III) 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 14.8 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

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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”, 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.

Title to Properties

In general, the Enbridge System is located on land owned by others and operated under perpetual easements or rights of way granted by the owners. Enbridge Pipelines Inc. (Enbridge Pipelines) has the right under the National Energy Board Act (the NEB Act) to apply to the NEB for an immediate right to enter any land and has exercised this right from time to time as required. In addition, the NEB Act provides for the approval of the crossing by interprovincial pipelines of roads, highways and other utilities. Approval for the crossing of railways and rivers by the pipeline is obtained from railways and public authorities, respectively. The pumping stations, terminals and certain other facilities are located on land owned by Enbridge Pipelines.

Terrace Expansion Project

The Terrace Expansion Project, which was undertaken by the Issuer and the Partnership, was a phased expansion that has provided an additional net 350,000 barrels per day of capacity for western Canadian crude oil producers seeking greater access to U.S. Midwest markets. Phase I was completed in 1999 and provided additional heavy crude oil capacity of 170,000 barrels per day. The first phase of the expansion included construction of a new 36-inch diameter pipeline and related facilities from Kerrobert, Saskatchewan to Clearbrook, Minnesota. The new pipeline construction joined existing 48-inch pipeline loops between Kerrobert and Clearbrook, creating another separate pipeline joining those locations. Phase I cost $610 million in Canada and US$145 million was spent by the Partnership in the United States. Phase II was completed in 2002 and included the extension of the 36-inch pipeline on the Enbridge System between Hardisty and Kerrobert. Phase II added 40,000 barrels per day of incremental capacity to the Enbridge System at a cost of approximately $100 million.

Phase III was completed in 2003 and 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 U.S. This phase added 140,000 barrels per day of incremental capacity at a cost of approximately $120 million on the Enbridge System and approximately US$193 million on the Lakehead System.

Regulation

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”, which uses the historical cost of property, plant and equipment, less depreciation and deferred income taxes in setting the rate base. Under this method, the Issuer was allowed, though not guaranteed, the opportunity to recover its investment in pipeline facilities and to earn a return on rate base. Tolls were

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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 Pipelines 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 Issuer with the interests of its shippers. The Incentive Tolling Agreement provides for the sharing with customers the results of operating efficiencies and cost savings achieved above certain thresholds on an annual basis. Enbridge reached an agreement with CAPP for the continuation of certain incentive parameters for 2000 through 2004 (the Incentive Tolling Settlement). The Issuer expects that negotiations for a renewed agreement will be completed in 2004.

The incentive toll model incorporates several mechanisms that protect the earnings of the Enbridge System. In addition to safeguards from volume fluctuations beyond the Issuer’s control, the toll structure contains adjustment provisions to incorporate cost increases resulting from occurrences such as new safety and environmental legislation, certain expenses associated with maintaining the integrity of the pipeline, and new or expanded services requested by industry. In addition, the agreement provides for the recovery of actual income taxes and an allowance for oil losses. In general terms, the Incentive Tolling Settlement ensures that the Issuer is not at risk in the short-term for changes in crude oil production, but will benefit on a shared basis from its efforts to increase effective system utilization and operate more efficiently.

Tariffs

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, 2003, are set forth below.

	Canadian Toll
	Per Barrel
	(Cdn dollars)
Regina, Saskatchewan	$	0.870
U.S. border near Gretna, Manitoba	$	1.091
Sarnia, Ontario	$	1.269

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 on April 1, 2004 to reflect provisions in the Incentive Tolling Settlement, the SEP II Risk Sharing Agreement and the Terrace Agreement.

SEP II Risk Sharing Agreement

The Issuer, 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 2003, the Issuer and EEP were allowed to earn the minimum rate of return on SEP II.

Terrace Agreement Toll Surcharge

As part of the Terrace Agreement, the Issuer, 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. This toll surcharge commenced

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on April 1, 1999 when Terrace Phase I was completed. The incremental toll is allocated between the Issuer and EEP. The toll surcharge is also subject to increase or decrease in certain defined circumstances.

Sources of Shipments

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.

Deliveries

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 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 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, 2003.

		Deliveries
(thousands of barrels per day)		2003		2002		2001
Prairie Provinces
	Light crude oil		176		170		158
	Medium and heavy crude oil		91		73		76
	Refined products		83		81		76
			350		324		310
United States
	Light crude oil		252		286		273
	Medium and heavy crude oil		690		601		631
	Natural gas liquids		4		6		5
			946		893		909
Ontario
	Light crude oil		391		380		391
	Medium and heavy crude oil		68		78		78
	Natural gas liquids		109		111		104
			568		569		573
			1,864		1,786		1,792
Barrel Miles (billions)			361		351		350
Average Haul (miles)			530		539		535

Enbridge System average deliveries include Line 9 volumes of 216,000 barrels per day (2002 – 204,000; 2001 – 217,000).

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Safety and Environment

The Issuer has appropriate mechanisms in place to monitor and address the safety and environmental aspects of its operation. The Issuer 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 Issuer’s pipeline operations and in the communities in which it operates.

The Issuer seeks to ensure compliance with all applicable regulatory and permit requirements. The Issuer 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 Issuer has in the past experienced such spills. A comprehensive methodology for managing environmental aspects of hydrocarbon spills is in place. Historic spills along the pipeline system as a result of past operations may have resulted in soil or groundwater contamination where further remediation may be required. The Issuer continues to voluntarily investigate past leak sites for the purpose of assessing 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.

In response to increased awareness of the climate change issue, Enbridge has established a Climate Change Task Force. This task force reviews business and environmental risks associated with climate change and identifies policies and actions to mitigate this risk. No material risks have been identified to date. Following Canada’s ratification of the Kyoto Protocol, the Company has continued to assess the potential impact on oil sands investment. Moody’s Investor Services recently surveyed oil sands operators and concluded that Kyoto is expected to have a minimal effect on the development of Alberta’s oil sands resource. The Company is encouraged by this conclusion as it lends support for the sustainability of supply for its liquids pipelines.

None of the environmental protection requirements applicable to the pipeline operations of the Issuer 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 reviews and audits are conducted to assess compliance with legislation and company policy. The Issuer consistently has been an industry leader in safety and environment and has received numerous industry awards. To the best of the Issuer’s knowledge, its pipeline operations are in compliance with all applicable safety and environmental regulations governing their operations.

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 2003, 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 optimized.

Employees

The Issuer employs approximately 810 individuals in its Liquids Pipelines operations.

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GAS PIPELINES

Gas Pipelines includes proportionately consolidated investments in transmission pipelines that transport natural gas.

The Alliance Pipeline is a natural gas pipeline extending 1,860 miles from supply areas in northwestern Alberta and northeastern British Columbia to Chicago, Illinois. The pipeline commenced service in December 2000 and has a firm delivery capacity of approximately 1.3 bcf of natural gas per day, the majority of which is committed through transportation agreements. The Issuer 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 Issuer 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 commenced service in December 2000 and has a delivery capacity of 1.0 bcf of natural gas per day.

The Issuer 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 Enbridge Gas’ delivery requirements.

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 Issuer’s knowledge, the operations of all affiliated systems are in substantial compliance with applicable environmental and safety regulations.

SPONSORED INVESTMENTS

Sponsored Investments consists of the Company’s investments in Enbridge Energy Partners, L.P., Enbridge Energy Management, L.L.C. and Enbridge Income Fund. 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. From May 2001 to October 2002, the Company, through its subsidiary, Enbridge Pipelines Inc., owned 100% of Enbridge Midcoast Energy, which is now a wholly owned subsidiary of EEP. EIF is a publicly traded income fund whose primary operations include a 50% interest in Alliance Pipeline Canada and a 100% interest in a crude oil and liquids pipeline and gathering system located in southeastern Saskatchewan and southwestern Manitoba. The business activities of Sponsored Investments are carried out in the United States through the Partnership, and in Canada through EIF.

The Company owns an effective 12.2% equity investment in the Partnership. The Partnership transports crude oil and other liquid hydrocarbons through a common carrier pipeline and transports, gathers, processes and markets natural gas and natural gas liquids.

The Partnership owns the Lakehead System, which consists of approximately 3,300 miles of pipe extending from the Canadian border near Neche, North Dakota, where it connects with the Enbridge System, to Superior, Wisconsin, where it splits into two branches. One branch travels through the upper Great Lakes region and the other though the lower Great Lakes region of the Unites States. Both branches re-enter Canada near Marysville, Michigan where they reconnect with the Enbridge System.

The Partnership also owns Enbridge Midcoast Energy, purchased from the Company in October 2002. Enbridge Midcoast Energy transports, gathers, processes and markets natural gas and natural gas liquids in the Gulf Coast and mid-continent areas of the United States.

In December 2001, the Partnership acquired the East Texas System, which includes approximately 2,000 miles of natural gas gathering and transmission pipelines, four natural gas treating plants, two of which are active currently, and three natural gas processing plants, two of which are active currently.

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On December 22, 2003, the Issuer announced the acquisition of several assets from Shell Pipeline Company LP and Shell Oil Products U.S. The majority of the assets, located at or originating from Cushing, Oklahoma, and consisting of two different pipelines and two crude oil storage terminals, are to be acquired by EEP for approximate consideration of US$115 million. Closing of this acquisition is anticipated to occur in the first quarter of 2004, subject to regulatory approvals and rights of first refusal.

On December 31, 2003, EEP acquired natural gas gathering and processing assets in north Texas. The gathering system, referred to as the North Texas system, primarily serves the Fort Worth Basin, including the Barnett Shale producing zone, and is complementary to the Partnership’s existing natural gas systems in the area. The assets were purchased for cash of US$249.7 million.

The Issuer created EIF in June 2003. On formation, the Issuer sold to EIF its 50% interest in the Canadian segment of the Alliance Pipeline, as well as its 100% interest in Enbridge Pipelines (Saskatchewan) Inc. The Issuer acts as EIF’s sponsor and manager, and holds a 41.9% interest in EIF in the form of subordinated trust units of EIF, and preferred units of Enbridge Commercial Trust, a direct subsidiary of EIF.

Employees

The Issuer employs approximately 1,050 individuals who provide services only to its Sponsored Investments business 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, 2003 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 either Form 10-K is intended to be incorporated by reference in this Renewal Annual Information Form 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 and natural gas gathering and processing operations through an equity investment in AltaGas Services Inc.

The Issuer’s gas distribution business is conducted primarily through Enbridge Gas, a wholly-owned subsidiary. Enbridge Gas 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, Enbridge Gas, through its wholly-owned subsidiary, St. Lawrence Gas Company, Inc. (St. Lawrence), serves Massena, Ogdensburg, Potsdam and surrounding areas in northern New York State. Consistent with the quarter lag basis of consolidation as described in Note 1 to the Issuer’s Consolidated Financial Statements, the operating and financial information of Enbridge Gas represent September 30 fiscal year end results.

The gas distribution utility business of Enbridge Gas is regulated by the Ontario Energy Board (the OEB), its principal regulator, which regulates various aspects of the Issuer’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.

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ENBRIDGE GAS

Description of Business

Distribution Service

Enbridge Gas’ 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 basis (i.e., non-contract). 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, Enbridge Gas 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 Enbridge Gas 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 the Enbridge Gas supply portfolio (system supply). Alternatively, a gas user 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 the gas at a TransCanada receipt point in western Canada or at a TransCanada delivery point in Ontario, and the Company 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 Enbridge Gas at a TransCanada receipt point in western Canada. Enbridge Gas, 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. Since the commodity cost of gas is flowed through to customers with no mark up, the customer’s choice of gas supply has no effect on earnings.

Gas Supply

To acquire the necessary volume of gas to service its customers, the Company maintains a diversified gas supply portfolio. During 2003, Enbridge Gas acquired approximately 182 bcf of natural gas, of which 41.5% was under long-term contracts with independent western Canadian producers. The remaining 58.5% was purchased through short-term or monthly spot purchases. Enbridge Gas also transported 296 bcf of natural gas on behalf of direct purchase customers operating under a transportation service arrangement.

Enbridge Gas’ 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-based prices or the differential between such prices and prices based on the New York Mercantile Exchange. Enbridge Gas has undertaken, on behalf of its customers, a natural gas price risk management program to manage the price volatility of its forecasted system supply gas.

Enbridge Gas supports the concept of direct purchase by its customers; however, there are security of supply, operational and consumer protection issues associated with this option. Therefore, all of Enbridge Gas’ long-term supply contracts with independent western Canadian producers or marketers allow for reductions in contract volumes to accommodate customers who pursue direct purchase arrangements for the first time.

Transportation

Enbridge Gas relies primarily upon TransCanada for transportation service to bring its diversified gas supply from western Canada to its franchise area. Enbridge Gas has long-term firm transportation service contracts with TransCanada, over varying time periods, for annual deliveries of approximately 311 bcf of natural gas. This includes deliveries by direct purchase customers via TransCanada capacity that has been assigned by Enbridge Gas to the direct purchase customer or capacity that has

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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 Enbridge Gas flexibility in obtaining its own gas supply and accommodating the transportation of natural gas purchased directly by end-use customers.

TransCanada’s transportation tolls, which are approved by the NEB, consist of a fixed cost (demand component) and a variable cost (commodity component). The demand component must be paid regardless of the volume transported except to the extent that Enbridge Gas has negotiated the right to turn back a certain amount of unused capacity to TransCanada. Enbridge Gas allows customers to turn back capacity up to the amount that can be turned back by Enbridge Gas to TransCanada. This enabled Enbridge Gas to avoid paying for unused capacity during 2003. In 2004, Enbridge Gas Distribution does not expect to incur any charges for unused capacity.

While Enbridge Gas continues to place great reliance on western Canadian supplies and pipeline transportation systems, efforts have been directed towards acquiring U.S. supply and alternative pipeline capacity directly into Ontario. Enbridge Gas has entered into contracts for firm transportation service on the Alliance and Vector pipelines, which began operations in fiscal 2001. Enbridge Gas also has long-term contracted capacity on the St. Clair Pipeline, which interconnects with the facilities of Union Gas Limited (Union) and Michigan Consolidated Gas Company (MichCon), as well as access to U.S. gas supplies throughout the Union system near Windsor, Ontario and at Dawn by the Vector Pipeline. In addition, Enbridge Gas has contracted with Niagara Gas for long-term capacity on the Link Pipeline, which interconnects the facilities of Enbridge Gas with ANR Pipelines Company (ANR) and MichCon.

Gas Storage

The business of Enbridge Gas 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 Enbridge Gas to take delivery of gas on favourable terms during off-peak periods for subsequent use during the winter heating season. This practice permits Enbridge Gas 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 to Enbridge Gas’ franchise area.

Enbridge Gas’ principal storage facilities are located in southwestern Ontario near Dawn and have a total working capacity of approximately 99 bcf. Approximately 92 bcf of the total working capacity is available to Enbridge Gas with the remaining capacity contracted to third parties. In addition, Enbridge Gas has a long-term storage contract with Union for 20 bcf of storage capacity.

The Enbridge Gas storage facilities are connected to the Dawn storage and transmission hub by two 30-inch pipelines and a 16-inch pipeline owned by Enbridge Gas. 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, from there, transported to Enbridge Gas’ major market area in the greater Toronto area through the transmission facilities of Union. Enbridge Gas has transportation contracts with TransCanada, Vector and Union for the delivery of gas to and from storage.

Properties

At the end of its 2003 fiscal year, Enbridge Gas owned and operated approximately 19,513 miles of mains (2002 – 19,010 miles) 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, Enbridge Gas owns equipment and other properties used for offices, warehouses, metering and regulating stations and service shops.

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Regulation

Recent changes in regulation reflect a trend in North America toward incentive or performance-based regulation (PBR). Enbridge Gas operated under an OEB-approved targeted PBR plan for a three-year term, which concluded in fiscal year 2002. The PBR plan used a formula to calculate the level of operation and maintenance costs recoverable in rates. The formula included escalation factors for customer growth and inflation, which were offset by an annual productivity credit of 1.1%. The PBR plan also allowed for the recognition, subject to OEB approval, of factors impacting operation and maintenance costs that were outside of management’s control. During the PBR period, Enbridge Gas was allowed to retain the savings if it achieved lower operation and maintenance expenses than those calculated under the formula.

The key elements in the OEB rate application for fiscal 2004 and rate decisions for 2003 and 2002 are summarized as follows.

	2004	2003						2002
	Requested1	Approved			Requested			Approved			Requested
Rate base (Cdn $millions)			3,156			3,226			3,019			3,114
Rate of return on rate base			8.32	%		8.32	%		8.26	%		9.32	%
Deemed common equity component of total capital structure			35.00	%		35.00	%		35.00	%		35.00	%
Rate of return on common equity			9.69	%		9.69	%		9.66	%		11.38	%

1. EGD’s 2004 rate application requested that rates for 2004 be set by increasing 2003 rates by 90% of the forecast Ontario Consumer Price Index, that being an increase of 1.8%. As such, the typical rate base and rate of return related information would not be applicable to 2004 rates.

2004 Fiscal Year

Enbridge Gas filed its fiscal 2004 rate application with the OEB in April 2003. Enbridge Gas’ objective was to return to a regulatory schedule whereby rates would be set prospectively. The 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. No adjustment was required to the 2004 rates.

On November 7, 2003, the OEB issued its Decision with Reasons in respect of Enbridge Gas’ 2003 rate application (Decision).

The OEB accepted the negotiated settlement proposal for Enbridge Gas’ 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 normalized basis exceed the benchmark return on equity (ROE), these excess earnings would be shared on a 50/50 basis between ratepayers and Enbridge Gas’ shareholder.

In September 2003, the OEB completed a generic hearing (Enbridge and Union Gas were co-applicants) to review and consider possible revisions to the current formula that is based on the long-term Canadian bond yield, which is used to set the utility’s rate of return. A decision was issued on January 16, 2004, which dismissed the application and confirmed the use of the existing formula. A return on equity of 9.69% is embedded in 2004 rates.

2003 Fiscal Year

In September 2002, Enbridge Gas filed its fiscal 2003 rate application with the OEB. In March 2003, as a result of settlement negotiations with intervenors, an agreement was reached on the majority of the financial aspects affecting rates, such that rates could be set on an interim basis. Interim rate increases, reflecting a revenue deficiency of $38.2 million, were implemented beginning in May 2003. Enbridge Gas’

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2003 rates remained preliminary until the OEB’s Decision with Reasons (Decision) was issued on November 7, 2003, with respect to outsourcing of its customer care, gas supply and gas control functions in prior years. In its Decision, the OEB disallowed the recovery of a portion of customer care costs from ratepayers relating to the 2003 and 2004 fiscal years. The full impact of the decision was recorded in the first quarter of fiscal 2004 for Enbridge Gas, resulting in a $14.1 million ($9.1 million after tax) reduction in earnings.

The 2003 rate application also included a request to review and revise the current formula used to calculate the rate of return on common equity. This request was heard in a separate phase of the 2003 rate hearing. The increase in the requested rate of return from 9.69% to 11.50% reflected Enbridge Gas’ need to compete for investment dollars in the North American marketplace.

2002 Fiscal Year

In fiscal 2002, Enbridge Gas moved to a quarterly review of rates in order to ensure that gas commodity prices recovered in rates more closely reflect market conditions. As Enbridge Gas does not mark up the cost of the gas commodity, increases or decreases in rates during a fiscal year are due to fluctuations in the market price of natural gas.

Final rates, reflecting a revenue deficiency of $9.2 million, were implemented effective August 1, 2002.

Gas Distribution Access Rule

In December 2002, the OEB issued the Gas Distribution Access Rule (GDAR). The purpose of GDAR is to establish rules governing natural gas distributors’ conduct in relation to gas marketers and establish conditions of access to gas distribution services. As Enbridge Gas does not accept that the OEB has jurisdiction to impose billing options on Enbridge Gas, an appeal was filed with the Divisional Court of Appeal in January 2003. The appeal states that the GDAR discriminates against gas distributors in favour of gas vendors, creates a contractual model that improperly provides for gas vendors rather than gas distributors to provide distribution services to consumers and improperly regulates billing services.

In September 2003, the Ontario Divisional Court issued a decision dismissing the appeals and upholding the OEB’s jurisdiction to enact the billing portions of the GDAR. Both the Company and Union Gas Limited have sought leave from the Ontario Court of Appeal to hear an appeal of the decision.

In the interim, the Company is working closely with the OEB and gas marketers to resolve outstanding GDAR implementation issues.

Undertakings

The Issuer and Enbridge Gas have entered into undertakings with the Government of Ontario committing the Issuer and Enbridge Gas to certain obligations relating to the maintenance of common equity, as well as a restriction on diversification to the effect that Enbridge Gas must not carry on, except through an affiliate or affiliates, any business activity other than the distribution, storage, or transmission of gas, without the OEB’s prior approval.

In compliance with these undertakings, Enbridge Gas applied to the OEB and has received approval to carry on the Natural Gas Vehicle Program, Agent Billing and Collection Program and the Gas Sales and Oil Production activities.

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Affiliate Relationships Code

Enbridge Gas is subject to the provisions of the Affiliate Relationships Code for Gas Utilities (the Code). The Code sets out the standards and conditions that govern the interaction between gas distributors, transmitters and storage companies and their respective affiliate companies. It is intended to minimize the potential for a utility to cross-subsidize competitive or non-monopoly activities; protect the confidentiality of consumer information collected in the course of providing utility services; and ensure there is no preferential access to regulated utility services. The Code specifically sets out standards of conduct including the degree of separation, sharing of services and resources, terms under which service level agreements must be prepared and transfer pricing guidelines.

Price Advantage of Natural Gas

Natural gas is the predominant energy form in the residential heating market throughout Enbridge Gas’ franchise area. In 2003, over 50% of Enbridge Gas’ distribution revenues resulted from natural gas sales to the residential market. The primary competition to natural gas in the residential market has historically been from domestic fuel oil and electricity. For the twelve months ended September 30, 2003, natural gas enjoyed, on average, a price advantage on an equivalent annual volume basis of about 37% against electricity and 20% against domestic fuel oil.

Despite recent increases in the price of natural gas, Enbridge Gas expects that natural gas will continue to hold a price advantage over electricity in its franchise area and maintain its competitive advantage against domestic fuel oil in the residential heating market. Enbridge Gas’ commercial and industrial distribution volume is exposed to the risk of customers switching to an alternate fuel, to the extent they have that ability. However, the customer’s ability to fuel switch requires a long-term decision and a potentially significant capital investment, thus reducing the risk of long-term decreases in natural gas demand due to short-term price competitiveness.

Energy Efficiency

Enbridge Gas maintains a prominent profile in the communities it serves and uses this to effectively 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. Since the mid-1990s, Enbridge Gas has employed an energy conservation strategy in the design of its marketing programs. Through its DSM program, Enbridge Gas 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.

Enbridge Gas has 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 hold Enbridge Gas harmless from the costs of supporting DSM.

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Historical Operating Statistics for Enbridge Gas

Year ended September 30,		2003			2002			2001
Gas supply and sendout (mmcf)1
	Natural gas purchased		181,671			117,376			186,873
	Gas into storage		(117,831	)		(51,508	)		(113,598	)
	Gas out of storage		101,615			63,033			112,320
Total gas sendout			165,455			128,901			185,595
Gas sales to customers (mmcf)1
	Residential		95,751			74,132			99,595
	Commercial		53,076			42,531			63,323
	Industrial		9,400			8,352			18,056
	Wholesale		4,241			3,523			1,387
Total sales			162,468			128,538			182,361
Used by Enbridge Gas (mmcf)1			219			226			311
Other (mmcf)1			2,768			137			2,923
			165,455			128,901			185,595
Transportation of gas (mmcf)1			295,775			281,416			243,125
Total sales and transportation of gas (mmcf)1			458,243			409,954			425,486
Degree day deficiency2
	Actual		4,029			3,362			3,743
	Forecast based on normal weather		3,565			3,700			3,816
Number of active customers – year end3			1,652,372			1,597,579			1,546,255
Average use per residential customer (mcf)1			109			97			130
Number of employees – year end			1,600			1,585			1,563
Miles of mains in use – year end			19,513			19,010			18,173

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 October 1 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 Enbridge Gas’ earnings.

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Safety and Environment

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 compositions of the atmosphere could lead to global climate change. Although some 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.

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

Programs have been implemented to ensure adherence to the Issuer’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 Enbridge Gas are expected to adversely affect its competitive position, capital expenditure program or level of earnings.

Employees

At September 30, 2003, Enbridge Gas had 1,600 employees, 44% 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 expired on December 31, 2003. The Company reached a tentative settlement with representatives of its union in early December 2003 for a 3-year collective agreement. The settlement was ratified in January 2004.

Enbridge Gas has filed a Renewal Annual Information Form for the year ended September 30, 2003 with the Canadian Securities Regulatory Authorities. This document contains detailed disclosure about Enbridge Gas and is publicly available through www.sedar.com. No part of Enbridge Gas’ Renewal Annual Information Form is intended to be incorporated by reference in this Renewal Annual Information Form of Enbridge Inc.

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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, AltaGas Services, Aux Sable, Sunbridge, and Inuvik Gas. Gazifère is a gas distribution utility located in southwestern Quebec. Niagara Gas provides transmission services to Enbridge Gas, Gazifère, St. Lawrence and MichCon. 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 Enbridge Gas and others. In 2001, Enbridge and BC Gas Inc. 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 BC Gas Utility and Enbridge Gas. 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 preference shares. Noverco is a holding company that owns a 77% interest in Gaz Metropolitain, a gas distribution company operating in the province of Quebec and the state of Vermont. Gaz Metropolitain has a 50% interest in TQM Pipeline, a pipeline transporting natural gas in Quebec.

The Company owns 63% of and operates Enbridge Gas New Brunswick (EGNB), the natural gas distribution franchise in the province of New Brunswick. EGNB constructed a new distribution system and has approximately 2,500 customers. Over 310 kilometres (193 miles) of distribution main has been installed with the capability of attaching approximately 9,300 customers. EGNB is regulated by the New Brunswick Board of Commissioners of Public Utilities.

The Issuer holds a 40.3% interest in AltaGas Services Inc., a company engaged in midstream natural gas activities, including distribution and energy services, natural gas and natural gas liquids marketing, and the wholesale marketing of power.

The Issuer 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.

The Issuer 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 Issuer’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

The Issuer employs approximately 170 individuals in its Other Gas Distribution and Services businesses.

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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, CLH, a 24.7% investment in the Colombian crude oil pipeline, Ocensa, and a 100% interest in CITCol, which is responsible for operating the Ocensa pipeline. The Company holds a 45% interest in the SWEC Partnership that previously operated the Jose Terminal in Venezuela.

CLH is Spain’s largest refined products transportation and storage business. CLH operations include a 2,100-mile pipeline distribution network and storage facilities with capacity of approximately 40 million barrels. The pipeline network links Spanish refineries with the principal areas of consumption. CLH’s transportation capability is enhanced through the operation of a fleet of tanker trucks and ships.

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.

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 has filed for international arbitration, as provided for in the operating agreement. The company ceased recognition of earnings commencing February 1, 2003.

Through Enbridge Technology Inc. (Enbridge Technology), the Issuer 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 the Issuer are subject to federal, state or local laws and regulations relating to environmental protection and operational safety. To the best of the Issuer’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

The Issuer’s International operations directly employ approximately 30 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.

Employees

The Issuer’s corporate activities and operations employ approximately 130 individuals.

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ITEM 5

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, 2003, which are incorporated herein by reference (the page references below are to the Company’s 2003 Annual Report):

Liquids Pipelines – Business Risks (pages 21 to 22);
Gas Pipelines – Business Risks (page 24);
Sponsored Investments – Business Risks (page 27);
Gas Distribution and Services – Business Risks (pages 32 to 33);
International – Business Risks (page 35).

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ITEM 6

DIVIDENDS

DIVIDENDS PAID

(Canadian dollars per share)	2003		2002		2001
Preference Shares, Series A		1.375		1.375		1.375
Common Shares		1.660		1.520		1.400

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 50-60% of normalized 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.

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ITEM 7

DESCRIPTION OF CAPITAL STRUCTURE

GENERAL DESCRIPTION OF CAPITAL STRUCTURE

At December 31, 2003, the Company’s capital structure consists of 171.9 million common shares with a book value of $2,239.9 million, 5.0 million preference shares, Series A with a book value of $125.0 million and $532.4 million in preferred securities.

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 bid 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 or announcement 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 5,000,000 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. Subsequent to December 31, 2003, the Company may, at its option, redeem all or a portion of the outstanding preferred shares for $26.00 per share if redeemed on or prior to December 1, 2004; $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.

Preferred Securities

The Company has $175.0 million of 7.6%, $200 million of 7.8%, and $175.0 million of 8.0% Preferred Securities outstanding. The Preferred Securities may be redeemed at the Company’s option at par value plus all accrued and unpaid distributions to the redemption date, in whole or in part, after the fifth anniversary of each issue and have no stated maturity date. Both the 7.6% and the 8.0% Preferred Securities were issued during 1999 and therefore may be redeemed in 2004. The 7.8% Preferred Securities were issued during 2002 and therefore may be redeemed in 2007. The Company has the right to defer, subject to certain conditions, payments of distributions on the securities for up to 20 consecutive quarterly periods. Deferred and regular distribution amounts are payable in cash or, at the option of the Company, in common shares of the Company.

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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-2	3		Baa2	5
Preferred Securities		Pfd-2y	1		BBB	3		Baa1	5
Commercial Paper		R-1 (low)	2		A-1 (low)	4		Not Rated
Unsecured Debt		A	2		A–	4		A3	6

Notes:

1.	DBRS’ rating of 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.

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ITEM 8

MARKET FOR SECURITIES

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

			TSX (C$)										NYSE (US$)
			ENB		ENB.PR.A		ENB.PR.B		ENB.PR.C		ENB.PR.D		ENB
January		High		44.33		26.00		26.25		26.50		26.89		28.71
		Low		41.85		24.90		25.75		26.00		26.15		27.20
	31-Jan	Close		42.50		25.16		25.77		26.16		26.50		27.74
		Volume		6,090,600		170,300		99,900		98,800		124,700		575,200
February		High		42.60		25.51		25.90		26.58		27.00		28.61
		Low		40.95		24.35		25.30		26.05		26.25		26.90
	28-Feb	Close		42.50		24.85		25.76		26.31		26.79		28.53
		Volume		6,020,600		271,800		99,700		58,300		87,000		398,600
March		High		44.32		25.00		25.95		26.60		26.93		30.02
		Low		42.00		24.25		25.02		25.50		25.29		28.25
	31-Mar	Close		43.94		24.35		25.30		25.55		25.90		29.80
		Volume		6,840,300		42,900		129,100		64,700		189,800		362,400
April		High		44.40		25.44		25.80		26.34		26.78		30.50
		Low		42.71		23.77		25.11		25.53		25.70		29.45
	30-Apr	Close		43.65		25.44		25.65		26.34		26.35		30.40
		Volume		5,647,900		54,500		86,900		69,900		155,200		186,800
May		High		47.90		25.81		26.60		27.00		27.47		35.01
		Low		43.35		24.91		25.55		25.91		26.40		30.52
	30-May	Close		46.77		25.68		26.20		26.47		27.20		34.13
		Volume		6,103,200		72,200		98,300		81,300		181,100		407,800
June		High		49.30		26.23		26.60		27.00		27.74		36.76
		Low		45.91		25.51		25.54		26.08		26.50		33.32
	30-Jun	Close		47.93		25.85		25.80		26.31		27.00		35.62
		Volume		5,894,000		191,800		156,200		98,200		240,400		349,400
July		High		51.02		26.07		26.45		27.00		27.34		36.91
		Low		47.53		25.23		25.50		26.15		26.56		35.18
	31-Jul	Close		50.15		25.47		25.75		26.75		27.00		35.80
		Volume		7,762,900		93,900		117,300		99,400		129,600		198,600
August		High		52.00		25.52		26.43		27.00		27.29		37.40
		Low		48.85		24.79		25.58		25.81		26.55		34.80
	29-Aug	Close		51.05		25.52		25.90		26.55		27.25		36.80
		Volume		6,064,200		50,100		72,100		107,300		116,700		199,200
September		High		51.80		26.00		26.40		26.94		27.60		37.75
		Low		47.50		25.10		25.80		25.92		26.75		35.50
	30-Sep	Close		51.05		25.52		25.90		26.55		27.25		35.63
		Volume		6,555,600		40,900		82,300		86,800		95,600		156,600
October		High		52.12		26.40		26.35		27.09		27.95		39.72
		Low		47.90		25.30		25.95		25.90		27.25		35.61
	31-Oct	Close		51.79		26.16		26.10		26.49		27.31		39.26
		Volume		7,308,100		44,000		95,200		113,900		71,500		198,700
November		High		54.00		26.42		26.90		26.65		28.39		41.40
		Low		51.40		25.70		25.60		25.76		27.25		38.54
	28-Nov	Close		52.00		25.80		26.05		26.09		27.70		41.09
		Volume		6,412,600		34,500		95,800		91,000		94,200		146,200
December		High		54.14		26.40		26.05		26.53		28.00		41.66
		Low		51.50		25.68		25.30		25.75		26.86		38.03
	31-Dec	Close		53.70		26.11		25.45		26.00		27.55		41.39
		Volume		4,330,300		119,200		95,600		83,500		99,200		180,200

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As of the date of this Annual Information Form, the common shares of the Issuer 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 the Issuer’s common shares. The Preference Shares, Series A of the Issuer are traded on the Toronto Stock Exchange under the symbol ENB.PR.A and the preferred securities of the Issuer, series 7.6%, 8.0% and 7.8%, are traded on the Toronto Stock Exchange under the symbols ENB.PR.B, ENB.PR.C and ENB.PR.D, respectively.

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ITEM 9

DIRECTORS AND OFFICERS

DIRECTORS

The following table sets forth the names of the Directors of Enbridge Inc. effective December 31, 2003, 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 Issuer. The Issuer does not have an Executive Committee. As required, the Issuer has an Audit, Finance & Risk Committee.

Name1 and	Principal Occupation for the	Year First Became
Municipality of Residence	Five Preceding Years	a Director2
DAVID A. ARLEDGE3,6 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 1993.		2002
JAMES J. BLANCHARD4,5 Beverly Hills, Michigan	Senior Partner, Piper Rudnick (law firm), since 1996; prior thereto, United States Ambassador to Canada.		1999
J. LORNE BRAITHWAITE4,5 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 EVANS3,6 Calgary, Alberta	Corporate Director.		1996
WILLIAM R. FATT3,6,7 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
RICHARD L. GEORGE4,6 Calgary, Alberta	President and Chief Executive Officer of Suncor Energy Inc. (integrated oil and gas company).		1996
LOUIS D. HYNDMAN3,4 Edmonton, Alberta	Senior Partner, Field Law LLP (law firm).		1993

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Name1 and	Principal Occupation for the	Year First Became
Municipality of Residence	Five Preceding Years	a Director2
GEORGE K. PETTY4,5 San Luis Obispo, California	Corporate Director; President & Chief Executive Officer of Telus Corporation (telecommunications company) from 1994 to 1999.		2001
ROBERT W. MARTIN3,6,8 Toronto, Ontario	Corporate Director; Chairman of Silcorp Limited (convenience stores) from 1993 to 1999.		1992
DONALD J. TAYLOR5,6 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 Environment, Health & Safety 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.

OFFICERS

The following table sets forth the names of the executive officers, their current office with the Issuer effective December 31, 2003, 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.
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.

29

Name, Position and	Position and Principal Occupations for the
Municipality of Residence	Five Preceding Years
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, Distribution Services 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; prior thereto, Vice President Operations, EGDI, since January 1999; prior thereto, Senior Vice President, Planning & Business Services, EGDI, in 1998.
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.

30

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.

The directors and officers of the Issuer beneficially owned, directly or indirectly, less than 1% of the Issuer’s common shares. 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.

The following individuals were also Officers during the year ended December 31, 2003.

Name, Position and	Position and Principal Occupations for the
Municipality of Residence	Five Preceding Years
DEREK P. TRUSWELL Group Vice President & Chief Financial Officer Calgary, Alberta	Group Vice President & Chief Financial Officer from September 2000 to April 2003; prior thereto, Senior Vice President & Chief Financial Officer.
KARYN A. BROOKS Vice President & Controller Calgary, Alberta	Vice President & Controller from April 2000 to June 2003; prior thereto, Vice President, Financial Services, Transmission of TransCanada PipeLines Limited since August 1999; prior thereto, Vice President & Controller of TransCanada PipeLines Limited.

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ITEM 10

LEGAL PROCEEDINGS

The information, which is found under note 21 “Commitments and Contingencies” of the Corporation’s audited consolidated financial statements, as at, and for the year ended, December 31, 2003, is incorporated by reference herein.

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ITEM 11

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 B, C and D is Computershare Trust Company of Canada at its principal office in Calgary, Alberta.

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ITEM 12

ADDITIONAL INFORMATION

The Issuer shall provide any person or company, upon request, to the Office of the Corporate Secretary of the Issuer at 3000, 425 – 1st Street S.W., Calgary, Alberta, T2P 3L8:

(a) when the securities of the Issuer are in the course of a distribution under a preliminary short form prospectus or a short form prospectus,

(i)	one copy of the latest Annual Information Form of the Issuer together with one copy of any document, or the pertinent pages of any document, incorporated by reference in the Annual Information Form;
(ii)	one copy of the comparative financial statements of the Issuer for its most recently completed financial year for which financial statements have been filed together with the accompanying report of the auditor and one copy of the most recent interim financial statements of the Issuer that have been filed, if any, for any period after the end of its most recently completed financial year;
(iii)	one copy of the information circular of the Issuer in respect of its most recent annual meeting of shareholders that involved the election of directors; and
(iv)	one copy of any other documents that are incorporated by reference into the preliminary short form prospectus or the short form prospectus and are not required to be provided under subparagraphs (i), (ii), or (iii) above; or

(b) at any other time, one copy of any documents referred to in subparagraphs (a)(i), (ii) and (iii) above, provided that the Issuer may require the payment of a reasonable charge if the request is made by a person or company who is not a security holder of the Issuer.

Additional information, including Directors’ and Officers’ remuneration and indebtedness, principal holders of the Issuer’s securities and options to purchase the Issuer’s securities, and the interest of insiders in material transactions, all as at December 31, 2003, is contained in the Issuer’s Management Information Circular dated March 4, 2004 furnished in connection with the Annual and Special Meeting of Shareholders to be held on May 5, 2004 for the purpose of, among other things, the election of directors. Additional financial information is provided in the Issuer’s comparative financial statements for the year ended December 31, 2003. Additional information relating to the Company may be found on SEDAR at www.sedar.com.

Effective Date

Unless otherwise specifically herein provided, the information contained in this Annual Information Form is stated effective as at December 31, 2003.

34