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ENBRIDGE INC.
ANNUAL INFORMATION FORM
For the Year Ended December 31, 2006

TABLE OF CONTENTS


	Page
Corporate Structure		2

General Development of the Business		3

Description of the Business		8
Liquids Pipelines		8
Gas Pipelines		12
Sponsored Investments		14
Gas Distribution and Services		15
International		22
Corporate		23
Corporate Social Responsibility		23

Risk Factors		24

Dividends		24

Description of Capital Structure		25

Market for Securities		26

Directors and Officers		28

Audit, Finance & Risk Committee – Further Information		31

Legal Proceedings		33

Registrar and Transfer Agent		33

Interests of Experts		33

Additional Information		33

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.

In the interest of providing Enbridge shareholders and potential investors with information about the Company and its subsidiaries, including management’s assessment of Enbridge’s and its subsidiaries’ future plans and operations, certain information provided in this Annual Information Form (AIF) constitutes forward-looking statements or information (collectively, “forward-looking statements”). Forward-looking statements are typically identified by words such as “anticipate”, “expect”, “project”, “estimate”, “forecast”, “plan”, “intend”, “target”, “believe” and similar words suggesting future outcomes or statements regarding an outlook. Although Enbridge believes that these forward-looking statements

are reasonable based on the information available on the date such statements are made, such statements are not guarantees of future performance and readers are cautioned against placing undue reliance on forward-looking statements. By their nature, these statements involve a variety of assumptions, known and unknown risks and uncertainties and other factors, which may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements.

Enbridge’s forward-looking statements are subject to risks and uncertainties pertaining to operating performance, regulatory parameters, weather, economic conditions, exchange rates, interest rates and commodity prices, including but not limited to those risks and uncertainties discussed in this AIF and in the Company’s other filings with Canadian and United States securities regulators. The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these are interdependent and Enbridge’s future course of action depends on management’s assessment of all information available at the relevant time. Except to the extent required by law, Enbridge assumes no obligation to publicly update or revise any forward-looking statements made in this AIF or otherwise, whether as a result of new information, future events or otherwise. All subsequent forward-looking statements, whether written or oral, attributable to Enbridge or persons acting on the Company’s behalf, are expressly qualified in their entirety by these cautionary statements.

CORPORATE STRUCTURE

INCORPORATION

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

The Company, formerly a wholly-owned subsidiary of Interprovincial, became the parent company of Interprovincial on December 18, 1992, pursuant to a Plan of Arrangement implementing a corporate reorganization approved by Interprovincial’s shareholders at the Annual and Special Meeting of Shareholders held on May 6, 1992. As a result of the reorganization, each common share of Interprovincial was deemed to be exchanged for one common share of the Company. The shares of Interprovincial, which was incorporated in 1949 by a special act of Parliament, were listed for trading on the Toronto and Montreal stock exchanges in 1953.

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. On October 6, 1998, the Articles of Continuance were amended to change the name of the Company to Enbridge Inc. On November 24, 1998, the Articles of Continuance were amended to increase the capital of the Company by designating a new series of preference shares as 5.5% Cumulative Redeemable Preference Shares, Series A. On April 29, 1999, the Articles of Continuance were further amended to divide each issued and outstanding common share on a two for one basis and to provide the Board of Directors with a process to add directors between meetings of the shareholders. On May 20, 2005, the Articles of Continuance were further amended to divide each issued and outstanding common share on a two for one basis.

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

SUBSIDIARIES

Each subsidiary listed below is 100% owned by the Company unless otherwise noted. Numerous subsidiaries, many of which are inactive, are omitted from the following list. Individually the total revenue and assets for each of these excluded subsidiaries is less than 10% of the consolidated revenue and

consolidated assets of the Company. In the aggregate, for excluded subsidiaries, total revenue and total assets are less than 20% of the consolidated revenue and consolidated assets of the Company.


Name	Jurisdiction of Incorporation
IPL System Inc.		Alberta
Enbridge Pipelines Inc.		Canada
Enbridge Energy Company Inc .		Delaware
Enbridge Pipelines (NW) Inc		Canada
Enbridge Energy Distribution Inc.		Canada
Enbridge Gas Distribution Inc.		Ontario
Enbridge (U.S.) Inc.		Delaware
Enbridge Gas Services (U.S.) Inc.		Delaware
IPL AP Holdings (U.S.A.) Inc.¹		Delaware
Enbridge Gas Services Inc.		Canada
Enbridge Pipelines (Athabasca) Inc		Alberta
Enbridge Capital ApS		Denmark
Enbridge Income Fund²		Alberta
Tidal Energy Marketing Inc.		Canada


¹		IPL AP Holdings (U.S.A.) Inc. owns the Company’s 50% joint venture interest in Alliance Pipeline US.

²		The Company owns 41.9% of Enbridge Income Fund (EIF) and is the primary beneficiary of EIF through a combination of voting interest and an investment in preferred units and as such, starting January 1, 2005, EIF is consolidated under Variable Interest Entity accounting rules.

GENERAL DEVELOPMENT OF THE BUSINESS

Enbridge’s primary business activities are the transportation and distribution of crude oil and natural gas. 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 Enbridge’s Canadian common carrier pipeline and feeder pipelines that transport crude oil and other liquid hydrocarbons.

	•		Gas Pipelines consists of proportionately consolidated investments in pipelines that transport natural gas including the United States portion of the Alliance Pipeline, Vector Pipeline and transmission and gathering pipelines in the Gulf of Mexico.

	•		Sponsored Investments consists of the Company’s investments in Enbridge Energy Partners, L.P. (EEP), Enbridge Energy Management, L.L.C. (EEM) (collectively, the Partnership) and Enbridge Income Fund (EIF). The Partnership transports crude oil and other liquid hydrocarbons through common carrier and feeder pipelines and transports, gathers, processes and markets natural gas and natural gas liquids in the United States. EIF is a publicly traded income fund whose primary operations include a 50% interest in the Canadian portion of the Alliance 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, and the Company’s proportionately consolidated investments in CustomerWorks Limited Partnership, a customer care provider serving natural gas distribution companies, and Aux Sable, a natural gas fractionation and extraction business. The Company’s commodity marketing businesses are also included in Gas Distribution and Services. These businesses manage the Company’s volume commitments on Alliance and Vector Pipelines as well as offering commodity storage, transport, and supply management services.

	•		The Company’s International business consists of investments in energy delivery businesses, Compañía Logística de Hidrocarburos CLH, S.A. (CLH) in Spain and Oleoducto Central, S.A. (OCENSA) in Colombia.

THREE YEAR HISTORY

Significant events and transactions in the development of the Company’s business over the last three years include completion of the Spearhead Pipeline reversal which commenced operations in the first quarter of 2006, the acquisition of Olympic Pipeline in February of 2006, the negotiation of an Incentive Tolling Settlement (ITS) with the Canadian Association of Petroleum Producers (CAPP) on the Enbridge System (described under Liquids Pipelines) in 2005 and the initiation of a number of strategic organic growth projects and acquisitions. Certain organic growth projects are described in detail in the Company’s Management’s Discussion and Analysis for the year ended December 31, 2006, filed on SEDAR (www.sedar.com). The projects which are expected to meaningfully influence the general development of the business are described below.

2006 Transactions and Events

Olympic Pipe Line

In February 2006, Enbridge acquired a 65% interest in the Olympic Pipeline from BP Pipelines. Olympic is the largest refined products pipeline in the State of Washington, transporting approximately 290,000 bpd of gasoline, diesel and jet fuel. The pipeline system extends approximately 480 kilometres (300 miles) from Blaine, Washington to Portland, Oregon, connecting four Puget Sound refineries to terminals in Washington and Portland. The system consists of 640 kilometres (400 miles) of 6 to 20 inch diameter pipe, a 500,000-barrel terminal, 9 pumping stations and 21 delivery facilities. BP will continue to operate the pipeline system.

Investment in EEP

In 2006, the Company acquired 5.4 million Class C units of EEP for $280.2 million (US$250 million), increasing the Company’s combined ownership from 10.9% to 16.6% (2004 – 11.6%). The Class C units have the same voting rights as Class A and B units of EEP and holders of the Class C units are entitled to quarterly distributions equal to those paid to Class A and B units. Prior to August 15, 2009, distributions are paid in additional Class C units, where Class C units are valued at the market value of Class A units. After August 15, 2009, distributions will be paid in cash and, subject to the approval of existing holders of Class A and Class B units, the Class C units will convert to Class A units on a one-to-one basis. If approval of the conversion is not received, the holders of Class C units will receive cash distributions equal to 115% of those paid to holders of Class A units.

Spearhead Pipeline

The Company reversed the flow of the Spearhead Pipeline, which previously operated from Cushing, Oklahoma to Chicago, Illinois to bring crude oil from Chicago to Cushing. The reversed pipeline went into service in March 2006. Enbridge acquired 90% of the Spearhead Pipeline in 2003 and the remaining 10% in 2005.

Progress on Projects Under Development

Southern Access Mainline Expansion Project

The Southern Access Mainline Expansion project is currently under construction and will ultimately add a total of 400,000 bpd incremental capacity to the mainline system from Hardisty, Alberta to Flanagan, Illinois, near Chicago. The United States portion of the expansion is being undertaken by EEP and Enbridge is undertaking the Canadian segment.

The Canadian segment expansion schedule has been expedited with 120,000 bpd added in 2006, an additional 63,000 bpd expected in 2008 and another 85,000 bpd expected in 2009 in order to match the total additional capacity of 400,000 bpd being provided in the United States. With the support of industry, the proposed diameter of the Southern Access Expansion from Superior, Wisconsin to Flanagan, Illinois has been increased to 42 inches, increasing the estimated cost to US$1.3 billion on the United States segment. The estimated cost of the Canadian segment is $0.2 billion.

Alberta Clipper Project

The Alberta Clipper Project involves the construction of a new 36-inch diameter pipeline from Hardisty, Alberta to Superior, Wisconsin, in conjunction with additional pumping power applied to the new 42-inch pipe from Superior to Flanagan, Illinois, described above under Southern Access Expansion. The Alberta Clipper Project will interconnect with the existing mainline system in Superior where it will provide access to

Enbridge’s full range of delivery points and storage options, including Chicago, Toledo, Sarnia, Patoka, Wood River and Cushing.

The expected capacity of the pipeline has been increased from 400,000 bpd to 450,000 bpd. The Canadian segment of the line is expected to cost $1.5 billion (in 2006 dollars) and the U.S. segment, which will be undertaken by EEP, is expected to cost US$0.8 billion.

In January 2007, industry confirmed its support for the Alberta Clipper project. Regulatory applications will be filed once commercial terms are finalized, which is expected to occur in the first quarter of 2007. The Alberta Clipper Project is expected to be in service in late 2009 or 2010.

Waupisoo Pipeline Project

The 30-inch diameter, 380-kilometre (236 mile) pipeline will transport crude oil from the Cheecham terminal, currently under construction on the Athabasca System, to the Edmonton area. The initial capacity of the line will be 350,000 bpd and is expandable to a maximum of 600,000 bpd through the addition of pumping units. Enbridge has filed an application for regulatory approval with the Alberta Energy and Utilities Board (AEUB) and other provincial government departments. Following regulatory approvals, which are expected in the first quarter of 2007, Enbridge will begin construction on the approximately $0.5 billion pipeline in 2007, with an expected in-service date of mid-2008. The previously announced 16-inch, 150,000 bpd diluent return line from the Edmonton area refinery hub north to the oil sands has been removed from the regulatory filing in order to expedite the crude oil line.

Southern Access Extension

The Southern Access Extension involves the construction of a new 36-inch diameter, 400,000 bpd pipeline extending the mainline from Flanagan to Patoka, Illinois, at a cost of approximately US$0.4 billion to Enbridge. Discussions with shippers have been finalized and, with industry support for this project, a Federal Energy Regulatory Commission (FERC) Offer of Settlement was filed on September 1, 2006.

The initial Offer of Settlement proposing a rolled in toll design was not approved by the FERC. However, support for the project remains strong and Enbridge is working with industry representatives on an alternative tolling structure to address the initial opposition from the intervening parties. The Company expects that a second application will be filed with the FERC in the first quarter of 2007 to allow the project to continue on schedule, with an estimated 2009 in-service date.

The Gateway Project

The Gateway Project includes both a condensate import pipeline and a petroleum export pipeline. The condensate line would transport imported diluent from Kitimat, British Columbia to the Edmonton area. The petroleum export line would transport crude oil from the Edmonton area to Kitimat. The condensate line is expected have a 20-inch diameter and an initial capacity of 193,000 bpd. The petroleum export line would have a 36-inch diameter and an initial capacity of 525,000 bpd. Capital cost estimates will be completed once commercial terms are finalized.

Current shipper preferences to accelerate the development of capacity to traditional United States markets will likely result in the acceleration of the Alberta Clipper Project, such that it precedes the Gateway Pipeline project. The Company now estimates that the Gateway in-service date will be in the 2012 to 2014 timeframe. The decision to proceed with the regulatory filing for either pipeline is subject to commercial considerations, including satisfactory completion of shipper agreements, environmental assessment as well as public and Aboriginal consultation.

Southern Lights Pipeline

Following the successful completion of a binding open season in July 2006, Enbridge announced plans in December 2006 to proceed with the Southern Lights Pipeline to increase the availability of diluent in Alberta. When completed, this 180,000 barrels per day (bpd), 20-inch diameter pipeline will transport diluent from Chicago to Edmonton and is expected to be in service in mid 2010.

The Southern Lights Pipeline project involves reversing the flow of a portion of Enbridge’s Line 13, an existing crude oil pipeline, from Clearbrook, Minnesota to Edmonton. The Canadian portion of Line 13 is currently part of the mainline system and the United States portion of Line 13 is owned by EEP. In order to replace the light crude capacity that would be lost through the reversal of Line 13, the Southern Lights Project also includes the construction of a new 20-inch diameter crude oil pipeline from Cromer, Manitoba to Clearbrook, and the expansion of existing Line 2. These changes to the existing crude oil system will ultimately increase southbound light crude system capacity by 45,000 bpd. The capital cost of the Southern Lights Project, including the new 20-inch diameter diluent pipeline, is estimated to be approximately US$1.3 billion.

In the fourth quarter of 2006, Enbridge received industry endorsement for the Southern Lights Pipeline including an acceleration of the light crude capacity replacement and a delay in the transfer of Line 13 from the mainline system to the Southern Lights Pipeline Project. This change will increase the light crude capacity on the mainline system by 215,000 bpd until Line 13 is transferred. Line 13 will be transferred to the Southern Lights Pipeline Project on the earlier of the completion of construction of new light crude capacity or the middle of 2010. Also during the fourth quarter, EEP approved the exchange of its portion of Line 13 for a portion of the Cromer to Clearbrook crude oil pipeline to be constructed. Remaining regulatory applications are expected to be filed in the first quarter of 2007.

Hardisty Terminal

The Company plans to proceed with the construction of a new crude oil terminal at Hardisty, Alberta. The terminal is expected to have a capacity of 7.5 million barrels and will cost approximately $0.4 billion. Enbridge has executed contracts for over 80% of the capacity and is close to closing contracts for the balance of the capacity. It is anticipated that the terminal will start to come into service early in 2008, with tanks being commissioned throughout 2008 and into 2009. An additional phase of development, which will increase the terminal’s capacity by up to 3.4 million barrels, is planned and the Company is in discussions with customers who are seeking this additional capacity. Once complete, the Hardisty Terminal will be one of the largest crude oil terminals in North America.

Stonefell Terminal

BA Energy Inc. is building a bitumen upgrader near Fort Saskatchewan, Alberta for which Enbridge has agreed to provide pipeline and terminaling services. Based on initial scope and cost estimates, Enbridge expects to invest approximately $0.1 billion in new facilities to provide storage services at a new satellite terminal to be developed adjacent to the upgrader. Enbridge will also provide pipeline transportation for the upgrader’s output from the new terminal to a refinery hub near Edmonton. These facilities are expected to be in service in mid-2008.

The Stonefell Terminal is also strategically located adjacent to several other proposed or operating upgrading facilities and pipeline systems and will be a focus for further development of contract terminaling infrastructure.

East Texas Clarity

The East Texas Clarity project, undertaken by EEP, is a US$0.6 billion expansion of EEP’s East Texas system and is progressing on schedule to add 0.7 billion cubic feet (bcf) per day of natural gas transportation capacity to the Texas intrastate market in 2007. The Clarity project will be completed in phases during the year with the first phase scheduled for completion in early 2007. This phase involves the construction of a natural gas treating facility and related mainline expansion. Additional phases will be complete in mid-2007 and end of year 2007. When complete, the Clarity project will link growing natural gas production in East Texas, and third party storage assets in East Texas, with major third party pipelines and markets in the Beaumont, Texas area.

Ontario Wind Project

Enbridge is developing approximately 182 megawatts of wind power in the Municipality of Kincardine on the eastern shore of Lake Huron in Ontario. Construction will commence when final environmental and zoning approvals are obtained. The project is waiting for its Environmental Screening Report to be passed by the Ontario Ministry of Environment and its zoning laws to be approved by the Ontario Municipal Board. Total

capital expenditures are expected to be approximately $0.5 billion. Enbridge has entered into a 20-year electricity purchase agreement with the Ontario Power Authority for all the power produced by the project. The Company expects the Ontario Wind Project to be in service in late 2008.

2005 Transactions and Events

ITS

The ITS, negotiated in 2005, defines the methodology for calculating tolls on the core component of the Enbridge System in Canada. The new ITS is in effect from January 1, 2005 to December 31, 2009 and excludes minor pipelines that have their own tolling arrangements as well as expansions to the Enbridge System, known as the SEP I, SEP II and Terrace expansions, which have separate tolling arrangements described under Liquids Pipelines.

Enbridge Offshore Pipelines

During 2005, the Company acquired further interests in Neptune Pipeline and Garden Banks Gas Pipeline, businesses included in Enbridge Offshore Pipelines. The Company also initiated a project to construct and operate both a natural gas lateral and a crude oil lateral to connect the deepwater Neptune oil and gas field to existing Enbridge Offshore Pipelines infrastructure. The project is expected to cost approximately US$0.1 billion and is expected to be completed in 2007.

2004 Transactions and Events

Enbridge Offshore Pipelines

On December 31, 2004, the Company completed the purchase of ownership interests ranging from 22% to 80% in natural gas pipeline systems in the Gulf of Mexico from Shell for approximately $754 million. The assets, referred to as Enbridge Offshore Pipelines, include ownership interests in 11 transmission and gathering pipelines that can transport approximately 3 bcf/d of natural gas. The assets, which currently transport more than 50% of all deepwater production in the Gulf of Mexico, are held primarily through joint venture interests.

North Texas Natural Gas System

EEP acquired the North Texas Natural Gas System on January 6, 2005, for approximately US$165.0 million, which consists of approximately 3,540 kilometres (2,200 miles) of gas gathering pipelines and three processing plants. EEP acquired the Mid-Continent System on March 1, 2004 for US$117.0 million. The Mid-Continent System consists of over 770 kilometres (480 miles) of crude oil pipelines and 9.5 million barrels of storage capacity, primarily located in Cushing.

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

DESCRIPTION OF THE BUSINESS

REVENUES BY SEGMENT


(Canadian dollars in millions)	2006		2005		2004

Liquids Pipelines		1,048.1		881.0		872.7
Gas Pipelines		345.9		364.3		271.7
Sponsored Investments¹		254.7		249.0		—
Gas Distribution and Services²		8,981.6		6,947.1		6,631.1
International		14.2		11.7		32.3
Corporate		—		—		—


Total Revenues		10,644.5		8,453.1		7,807.8

Notes:


¹		Prior to 2005, earnings from EIF were accounted for as investment income and were therefore not included in revenues. Starting in 2005, the Company consolidated EIF under Variable Interest Entity accounting guidelines.

²		Gas Distribution and Services included 15 months of revenues in 2004 for Enbridge Gas Distribution and other gas distribution businesses, all of which changed their year end to December 31 from September 30, in 2004.

LIQUIDS PIPELINES

Enbridge is the primary transporter of Western Canadian crude oil production. The mainline system (the System) consists of the Enbridge System (the portion of the System located in Canada) and the Lakehead System (the portion of the System located in the United States), which is owned by EEP. The Company has an equity investment in EEP that is included in Sponsored Investments. The Athabasca System transports synthetic and heavy crude oil from the Athabasca and Cold Lake regions of Alberta to Hardisty. The Norman Wells System (NW System) transports crude oil from the Northwest Territories to Zama, Alberta. In addition, Enbridge has interests in various feeder pipeline systems (Frontier, Olympic, Toledo, Mustang and Chicap) and liquid storage facilities (Patoka), which operate in the United States, as well as the Spearhead Pipeline, which began transporting Canadian crude oil from the Lakehead System at Chicago to Cushing in March 2006.

Enbridge System

The Enbridge System extends from Edmonton, Alberta, across the Canadian prairies to the U.S. border near Gretna, Manitoba. It continues from the United States border near Sarnia, Ontario, to Toronto, Ontario, and Montreal, Quebec, with lateral lines to Nanticoke, Ontario, and Niagara Falls, Ontario. The total length of pipeline right-of-way is approximately 2,300 kilometres (1,400 miles). The Enbridge System is regulated by the National Energy Board (NEB).

Services

The Enbridge System regularly transports up to 70 different types of liquid hydrocarbons including light, medium and heavy crude oil (including bitumen), condensate, synthetic crudes, natural gas liquids (NGL) and refined products.

The Enbridge System consists of a number of separate segments:

(i)

a mainline segment that consists of five pipelines, with a capacity of 1,930,000 bpd from Edmonton to the United States border near Gretna, Manitoba.

(ii)

a Sarnia to Toronto segment that consists of two lines with a capacity of 150,000 bpd. The Sarnia to Toronto segment includes lateral lines from Westover, Ontario, to Nanticoke and Niagara Falls.

(iii)

a Montreal, Quebec to Sarnia segment, Line 9, with a capacity of 240,000 bpd.

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

Significant Contracts — Tolling Agreements and Tariffs

The NEB has regulatory authority in Canada over the construction and operation of pipelines for the interprovincial transportation of liquid hydrocarbons and over matters relating to the accounting and rates of such pipelines.

Enbridge System tolls have been based on an incentive model since 1995. The main objective of this methodology is to more closely align the interests of the Company with the interests of its shippers. It provides for the sharing with customers of the results of operating efficiencies and cost savings achieved above certain thresholds on an annual basis.

In 2005, Enbridge and CAPP approved the key terms of a new negotiated ITS, effective for January 1, 2005 to December 31, 2009. In January 2006, the NEB approved the new ITS. The new ITS continues the sharing of earnings in excess of a stipulated threshold and provides a fixed annual mainline integrity allowance. In conjunction with the Terrace Agreement, the new ITS continues the throughput protection provisions ensuring the Company is insulated from volume fluctuations beyond its control. In addition to the incentive-based provisions in prior agreements, service and reliability metrics, collectively referred to as performance metrics, have been added to the new ITS to further align the Company’s interests with its shippers. The Company has the opportunity to increase earnings by achieving performance targets under the new service and reliability performance metric provisions. Service metrics establish financial bonuses and penalties for prescribed performance targets related to crude oil quality management and predictability of scheduled deliveries. The reliability metric provides for bonuses and penalties associated with optimization of system capacity, which are calculated relative to annual capacity targets.

Tariffs

Tolls are calculated in accordance with various agreements. Under published tariffs for the Enbridge System, the tolls for transportation, including terminaling charges where applicable, of light crude oil from Edmonton to principal delivery points, at December 31, 2006 are set forth below.


	Canadian Toll
	Per Barrel
Regina, Saskatchewan	$	0.842
U.S. border near Gretna, Manitoba	$	1.199
Sarnia, Ontario	$	1.315

The rates for medium and heavy crude oils are higher, while those for refined products and 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. The Canadian portion of the Terrace Agreement toll surcharge, described below, is included in the tolls listed in the table above.

SEP II Risk Sharing Agreement

Enbridge, EEP and CAPP entered into a Risk Sharing Agreement, effective for 15 years, with respect to SEP II, a 100,000 bpd 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 is expected to result in a greater return, subject to a minimum and maximum rate of return of 7.5% and 15.0%, respectively. During 2006, Enbridge and EEP earned the minimum rate of return on SEP II.

Terrace Agreement Toll Surcharge

As part of the Terrace Agreement, Enbridge, EEP and CAPP agreed to a fixed toll surcharge of $0.05 per barrel for the movement of light crude from Edmonton to the Chicago area. This toll surcharge commenced on April 1, 1999, when Terrace Phase I was completed. The incremental toll is allocated between Enbridge and EEP. Unused capacity under the Terrace Agreement is incorporated in tolls in the following year.

Principal Markets

The System (comprised of Enbridge System and Lakehead) is the primary transporter of crude oil from Western Canada to the United States. It is the only pipeline that transports crude oil from Western Canada to Eastern Canada, serving all of the major refining centres in Ontario, as well as the Midwest region of the United States. Shipments delivered to the Enbridge System originate in oilfields and oil sands in Alberta, Saskatchewan, Manitoba, British Columbia and the Northwest Territories, and reach the Enbridge System through the NW and Athabasca Systems owned by Enbridge, as well as pipelines owned and operated by others. These pipelines connect with the Enbridge System at two receiving points in Alberta, two in Saskatchewan and one in Manitoba. In addition, the Enbridge System receives offshore crude oil through connecting pipelines at Montreal, Quebec.

Supply and Reserves

Generally, development of the oil sands has more than offset declining conventional production. The NEB estimates that total Western Canada production was 2.5 million bpd¹ at the end of 2006 (2005 – 2.3 million bpd). At the end of 2005, remaining established conventional oil reserves in Western Canada were estimated to be 3.8 billion barrels² and remaining established reserves from oil sands were estimated at 174 billion barrels³. Combined conventional and oil sands reserves put Canada second only to Saudi Arabia with 14% of the worldwide estimated proved reserves⁴.


(1)		National Energy Board 2006 Estimate Production of Canadian Crude Oil and Equivalent Table 1

(2)		Canadian Association of Petroleum Producers Statistical Handbook 2006

(3)		Alberta Energy and Utilities Board Alberta’s Reserves 2005 and Supply/Demand Outlook/Overview

(4)		Oil and Gas Journal’s Worldwide Look at Reserves and Production, December 18, 2006

Deliveries and Demand for Western Canadian Sedimentary Basin Crude
The Company’s liquids pipelines are dependent upon the demand for crude oil and other liquid hydrocarbons produced from Western Canada. Deliveries from the System are made in the prairie provinces, the Province of Ontario and in the Great Lakes and Midwest regions of the United States, principally to refineries, either directly or through the connecting pipelines of other companies. Within these regions are located major refining centres near Sarnia, Nanticoke, and Toronto, Ontario; the Minneapolis-St. Paul area of Minnesota; Superior; Chicago; the Patoka/Wood River, Illinois area; Detroit, Michigan; and Toledo, Ohio. Through Company initiatives, Canadian crude oil has begun to penetrate southern markets in the United States Midwest (PADD II) with the Spearhead Pipeline as well as the United States Gulf Coast (PADD III) via a third party pipeline system.

Historically, Canada has been the third largest supplier of crude to the United States. However, for the past three years, Canada has surpassed both Mexico and Saudi Arabia to become the largest exporter of crude oil to the United States. Western Canada demand is served by local supply and has remained relatively flat over the last two years. During 2006, greater volumes of Western Canadian crude were transported to Ontario, pushing back Atlantic Basin crude oil. Deliveries of WCSB crude into PADD II increased by 64,300 bpd over the last two years with increased WCSB crude oil supply in 2006². Over the same two-year period, deliveries into PADD IV (the U.S. Rocky Mountains) have increased by 6,700 bpd, PADD V (the Western U.S.) deliveries have increased by 6,000 bpd, and PADD III deliveries have increased by 63,800 bpd².


(1)		“Table 38: Year-To-Date Imports of Crude Oil and Petroleum Products into the United States by Country of Origin, January – October 2006”, Energy Information Administration/Petroleum Supply Monthly, December 2006

(2)		“Disposition of Domestic Light and Heavy Crude Oil and Imports – 2006”, National Energy Board

(3)		“2006 Estimated Production of Canadian Crude Oil and Equivalent”, National Energy Board

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, 2006.


	Deliveries
(thousands of barrels per day)	2006		2005		2004

Prairie Provinces
Light crude oil		190		182		194
Medium and heavy crude oil		138		132		126
Refined products		79		79		83

		407		393		403

United States
Light crude oil		276		198		261
Medium and heavy crude oil		871		783		748
Natural gas liquids		4		4		4

		1,151		985		1,013

Ontario¹
Light crude oil		302		338		403
Medium and heavy crude oil		63		58		79
Natural gas liquids		90		98		103

		455		494		585

		2,013		1,872		2,001


Barrel Miles (billions)		388		350		383
Average Haul (miles)		529		513		523


¹		Enbridge System average deliveries include Line 9 volumes of 141,000 bpd (2005 – 190,000; 2004 – 227,000).

Competitive Conditions

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

Other Liquids Pipelines

Athabasca System

The Athabasca System, which is owned and operated by Enbridge, has a design capacity of 570,000 bpd and extends approximately 630 kilometres (391 miles) from north of Fort McMurray in Northern Alberta, south to the pipeline hub at Hardisty. At Hardisty, it accesses the Enbridge System and other carriers for transportation to Canadian and United States refineries. The Athabasca System also includes the Athabasca Terminal with 1.6 million barrels of receipt tankage, as well as the MacKay River and Christina Lake lateral feeder lines and tankage facilities. Enbridge has a 30-year take-or-pay transportation arrangement with Suncor Energy Inc., the initial shipper on the Athabasca System. The agreement also provides the shipper with options to increase and extend the life of the agreement beyond the initial 30-year term. Enbridge has also contracted to provide transportation services for EnCana Corporation and Petro-Canada Oil and Gas and, starting in early 2007, for ConocoPhillips Surmont Partnership and Total E&P Canada Ltd. (the Surmont Shippers) and Nexen Inc. and OPTI Canada Inc. (the Long Lake Shippers). The Athabasca System is regulated by the AEUB.

NW System

The NW System extends approximately 870 kilometres (540 miles) between Norman Wells, Northwest Territories and Zama, Alberta. The NW System is regulated by the NEB and is subject to a negotiated settlement and throughput agreement with its main shipper.

Spearhead Pipeline

The Spearhead Pipeline, which went into service in March 2006, has a capacity of 125,000 bpd and extends approximately 1,058 kilometres (657 miles) from Chicago to Cushing. The Company has 10-year shipper commitments for 108,000 bpd. The Spearhead Pipeline is regulated by the FERC.

Other United States Liquids Pipelines

Other United States Liquids Pipelines are regulated by the FERC and include a 77.8% interest in the Frontier System, a 65% joint venture interest in the Olympic System, a 30% joint venture interest in the Mustang System, a 22.8% interest in the Chicap System as well as the wholly-owned Toledo System and the Patoka West Tank Farm Facility.

Safety and Environmental Protection

Enbridge has appropriate mechanisms in place to monitor and address the safety and environmental aspects of its operations. Enbridge has health, safety and environmental management systems and has established policies, programs and practices for conducting safe and environmentally sound operations.

Spills of crude oil and petroleum products are not unusual within the liquids pipeline industry and the Company has experienced such spills in the past. A comprehensive methodology for managing environmental aspects of hydrocarbon spills is in place. Historic spills along the pipeline system may have resulted in soil or groundwater contamination where further remediation may be required. Enbridge continues to voluntarily investigate past leak sites to assess whether any remediation of contaminated lands is required in light of current legislation, in consultation with regulatory agencies and landowners.

The environmental protection requirements applicable to the Company’s pipeline operations do not adversely affect the pipeline operations’ competitive position, capital expenditures program or level of earnings. However, the risk of substantial liabilities is inherent in pipeline operations and there can be no assurance that such liabilities will not be incurred. Regular internal reviews and audits are conducted to assess compliance with legislation and company policy. To the best of the Management’s knowledge, its pipeline operations are in material compliance with all applicable safety and environmental regulations governing their operations.

Pipeline Integrity

The focus of Enbridge’s integrity management program is to monitor the condition of the pipeline system and apply preventative maintenance programs. In 2006, in-line inspections for corrosion, cracks and pipe deformities such as dents were conducted in various lines throughout the pipeline system. Investigative excavations were conducted to evaluate anomalies detected by the inspections and repairs were conducted as needed. All work plans and implementation procedures meet or exceed regulatory requirements and are regularly reviewed and continuously improved to ensure best technologies are utilized and integrity management processes are optimised.

Employees

Approximately 1,100 individuals are employed in the Liquids Pipelines segment within Enbridge.

GAS PIPELINES

Gas Pipelines consists of investments in Alliance Pipeline US, Vector Pipeline and Enbridge Offshore Pipelines. Enbridge has joint control over these investments with one or more other owners. Enbridge owns a 50% interest in the United States portion of the Alliance System, a 60% interest in Vector Pipeline and interests ranging from 22% to 100% in the pipelines comprising the Enbridge Offshore Pipelines.

Alliance Pipeline

The Alliance Pipeline is a natural gas pipeline extending 3,000 kilometres (1,875 miles) from supply areas in Northwestern Alberta and Northeastern British Columbia to Chicago. The Canadian portion of the Alliance Pipeline is 50% owned by EIF, which is included in the Sponsored Investments business segment.

The Alliance Pipeline has a firm delivery capacity of approximately 1.305 bcf/d of natural gas or 98.5% of the total contracted capacity. Alliance has 20 mmcf/d of natural gas contracted on a short-term basis. Additional transportation capacity of approximately 0.3 bcf/d is available to shippers at no additional cost other than the cost of the associated fuel requirements. The contracts permit Alliance to recover the cost of service, which includes operating and maintenance costs, cost of financing, an allowance for income tax, an annual allowance for depreciation, and an allowed return on equity. Each contract may be renewed upon five years notice for successive one-year terms beyond the original 15-year primary term ending in 2015. The rates and tariff for Alliance Pipeline US are regulated by the FERC.

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

Vector Pipeline

Enbridge provides operating services to the 560 kilometres (348 miles) Vector Pipeline, which transports natural gas from Chicago to Dawn, Ontario. The primary source of natural gas for Vector Pipeline is through interconnection facilities established with Alliance Pipeline and Northern Border Pipeline. Vector Pipeline has a nominal delivery capacity of 1.0 bcf/d of natural gas and is expandable to 1.5 bcf/d with additional compression stations. Approximately 70% of the long haul capacity of Vector is committed to firm transportation contracts that expire in 2015 at rates negotiated with the shippers and approved by the FERC. The remaining capacity is sold at market rates and various term lengths under firm and interruptible transportation service agreements. Vector Pipeline is currently operating at or near capacity. In 2006, Vector Pipeline received approval from the FERC to construct two additional compressor stations, which would expand Vector Pipeline’s nominal capacity to 1.2 bcf/d. The projected in service date for the additional compressor stations is November 1, 2007 and supported by 10 year, binding agreements with various shippers.

Enbridge Offshore Pipelines

Enbridge Offshore Pipelines (EOP) is comprised of 11 natural gas gathering and FERC-regulated transmission pipelines in five major corridors in the Gulf of Mexico, extending to deepwater frontiers. These pipelines include almost 2,400 kilometres (1,500 miles) of underwater pipe and onshore facilities and transport more than half of all current deepwater Gulf of Mexico natural gas production. Approximately 2.0 bcf/d is transported currently on these pipelines.

The primary shippers on the EOP systems are producers who execute life-of-lease commitments in connection with transmission and gathering service contracts. In exchange, EOP provides firm capacity for the contract term at an agreed upon rate. The throughput volume generally reflects the lease’s maximum sustainable production.

The transportation contracts allow the shippers to define a maximum daily quantity (MDQ), which corresponds with the expected production life. The contracts typically have minimum throughput volumes which are subject to take-or-pay criteria but also provide the shippers with flexibility given advance notice criteria to modify the projected MDQ schedule to match current deliverability expectations.

The long-term transport rates established in the gathering and transmission service agreements are generally market-based but are established utilizing a cost-of-service methodology, which includes operating cost, projected revenue generation directly tied to production deliverability and the appropriate cost of capital.

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

Employees

Approximately 73 individuals are directly employed by Enbridge to provide operating service to EOP. The Alliance Pipeline is operated and administered entirely by employees of Alliance Pipeline. The Vector Pipeline is operated and administered in part by employees of Vector Pipelines, and in part through operating and administrative services provided by Enbridge.

SPONSORED INVESTMENTS

Sponsored Investments includes the Company’s interests in EEP and EIF. Enbridge manages the day-to-day operations of, and develops and assesses opportunities for each, including both organic growth and acquisition opportunities.

Enbridge Energy Partners

Enbridge has a combined 16.6% ownership in EEP, through a 2.0% interest in general partner units, a 5.0% interest in Class B units, a 6.9% interest in Class C units, and a 2.7% interest in EEP via a 17.2% investment in EEM, which owns 100% of EEP’s i-units.

EEP owns and operates crude oil and liquid petroleum transmission pipeline systems, natural gas gathering and related facilities and marketing assets in the United States. Significant assets include the Lakehead System, which is the extension of the Enbridge System in the United States, natural gas gathering and processing assets in Texas, the mid-continent crude oil system, various interstate and intrastate natural gas pipelines and a crude oil feeder pipeline in North Dakota.

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

Enbridge Income Fund

EIF’s primary assets include a 50% interest in Alliance Pipeline Canada, and a 100% interest in the Enbridge Saskatchewan System. A subsidiary of Enbridge acts as EIF’s manager. Enbridge holds a 41.9% interest in EIF in the form of subordinated units of EIF and 100% of the non-voting, preferred units of Enbridge Commercial Trust, a direct subsidiary of EIF.

Alliance Pipeline Canada consists of approximately 1,560 kilometres (970 miles) high-pressure, natural gas transmission system and an approximately 700 kilometres (435 miles) lateral pipeline system. The Saskatchewan System’s primary business activity is the transportation of crude oil and other liquid hydrocarbons by pipeline through the ownership and operation of the Saskatchewan, Westspur and Weyburn pipeline systems located primarily in Saskatchewan and the Virden pipeline system located in Manitoba.

EIF also owns interests in three wind power generation projects purchased from Enbridge in October, 2006 and a business that develops waste-heat power generation projects at Alliance Pipeline Canada compressor stations.

Tax Fairness Plan

On October 31, 2006, the Canadian Government announced a “Tax Fairness Plan” that would, among other things, create a new tax regime for publicly traded income trusts including EIF. Under the proposed rules, the taxable portion of an income trust’s distributions would be subject to taxation in a manner similar to the treatment of taxable income within a corporation. For existing income trusts, the new rules would not become applicable until 2011 provided they limit their expansion to “normal growth” prior to that year. On December 15, 2006 the Government issued guidelines with respect to what it would consider “normal growth” for existing income trusts that wish to ensure that they do not become subject to the proposed tax rules until 2011. Under

these guidelines, the amount of equity units that an income trust can issue to finance growth up to 2011 may not exceed the value of its publicly traded equity units on October 31, 2007 (subject to annual limits).

On December 21, 2006, the Government released draft legislation for comment. Considerable uncertainty still exists as the draft legislation does not fully address all aspects of the tax regime introduced in the Tax Fairness Plan (including the “normal growth” guidelines). Further, the proposed legislation is now subject to review by a Parliamentary committee through an expedited public hearing process. Timing for enactment of the legislation by Parliament remains uncertain.

If enacted in their present form, the proposed tax changes would, all other things being equal, likely result in a reduction of cash available for distribution by EIF commencing in 2011.

Employees

Enbridge employs approximately 1,624 individuals who provide services to Sponsored Investments.

Each of EEP and EEM has filed an Annual Report on Form 10-K for the year ended December 31, 2006 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.sec.gov/edgar.shtml. No part of the Form 10-K filed by EEP or by EEM is intended to be incorporated by reference in this Annual Information Form.

EIF has filed an Annual Report and a renewal Annual Information Form (AIF) for the year ended December 31, 2006 with Canadian Securities Administrators in Canada. The AIF and the Annual Report, which includes consolidated financial statements and Management’s Discussion and Analysis, contain detailed disclosure with respect to the Enbridge Income Fund and are publicly available through www.sedar.com. No part of EIF’s Annual Report, consolidated financial statements, Management’s Discussion and Analysis or AIF is intended to be incorporated by reference in this Annual Information Form.

GAS DISTRIBUTION AND SERVICES

The primary component of Gas Distribution and Services is the gas distribution operations of Enbridge Gas Distribution (EGD). This segment also includes Noverco, CustomerWorks, the gas services business, which manages the Company’s merchant capacity commitments on Alliance and Vector, and the Company’s investment in Aux Sable.

Enbridge Gas Distribution

There are four principal interrelated aspects of the natural gas distribution business in which the EGD is directly involved: Distribution Service, Gas Supply, Transportation and Storage.

Distribution Service

EGD’s principal source of revenue is from distribution of natural gas to customers. The services provided to residential and small commercial and industrial heating customers are primarily on a general service basis (without a specific fixed term or fixed price 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” contract, EGD is obligated to deliver natural gas to the customer up to a maximum daily volume. The service provided under an “interruptible” contract is similar to that of a firm contract, except that it allows for service interruption at EGD’s option to meet seasonal or peak demands. The Ontario Energy Board (OEB) approves rates for both contract and general services.

Customers have a choice with respect to gas supply. One choice is a sales service option, whereby the customer purchases gas from EGD’s supply portfolio (system supply). EGD does not earn income on the gas commodity it provides to customers. Alternatively, a gas user may select a direct purchase option, which is a transportation service arrangement. Under the transportation service arrangement, a customer supplies natural gas at a TransCanada receipt point in Western Canada or at a TransCanada delivery point in Ontario, and EGD redelivers an equivalent amount of gas to the customer’s end-use location. This arrangement is billed under the OEB approved rate schedules.

Gas Supply

To acquire the necessary volume of gas to service its customers, EGD maintains a diversified gas supply portfolio. During the year ended December 31, 2006, EGD acquired approximately 156.9 bcf (2005 – 183.3 bcf; 2006 – 4.4 billion cubic metres, 2005 – 5.0 billion cubic metres) of natural gas, of which 23.8% (2005 – 29.4%) was acquired from Western Canadian producers, 53.8% (2005 – 44.1%) was acquired from suppliers in Chicago and 22.4% (2005 – 26.5%) was acquired on a delivered basis in Ontario. EGD also transported 258 bcf (2005 – 265 bcf; 2006 – 7.3 billion cubic metres, 2005 – 7.5 billion cubic metres) of natural gas on behalf of direct purchase customers operating under a transportation service arrangement.

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

Transportation

EGD relies primarily upon TransCanada for transportation service to bring its diversified gas supply from Western Canada to its franchise area. EGD has long term firm transportation service contracts with TransCanada, over varying time periods, for annual deliveries of approximately 271.9 bcf (7.7 billion cubic metres) of natural gas. This includes deliveries by direct purchase customers via TransCanada capacity that has been assigned by EGD to the direct purchase customer or capacity that has been contracted directly with TransCanada by the direct purchase customer.

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

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

EGD also has contracts for firm transportation service on the pipelines of Alliance Pipeline Canada, Alliance Pipeline U.S. and Vector Pipeline. The Alliance network of pipelines extends over 3,000 kilometres and runs from Northeastern British Columbia to the Chicago area hub, where it interconnects with the North American pipeline grid. Vector is a 550 kilometre pipeline that connects the hub facilities at the Chicago area to Dawn, Ontario. Enbridge has joint venture interests in all of these pipeline facilities.

EGD relies on its long-term contracts with Union Gas Limited (Union) for transportation of gas from Dawn to EGD’s major market in the Greater Toronto Area. The contracts effectively provide EGD with access to United States sourced gas at Dawn by the Vector Pipeline. The contracts also provide transportation for gas stored at the EGD’s and Union’s storage pools in the Sarnia area to the market area.

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

Storage

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

EGD’s principal storage facilities are located near Dawn, and have a total working capacity of approximately 95.3 bcf (2.7 billion cubic metres.) Approximately 88.2 bcf (2.5 billion cubic metres) of the total working capacity are available to EGD. Further, EGD has storage contracts with Union for 19.9 bcf (0.564 billion cubic metres) of storage capacity, with terms varying from two to four years.

EGD operated storage facilities are connected to the Dawn storage and transmission hub by two 30-inch pipelines owned by EGD. In the summer, gas is delivered to Dawn for injection into storage through the transmission facilities of TransCanada and Vector pipelines. In the winter, gas is withdrawn from storage and delivered to Dawn and transported from there to EGD’s major market area of Toronto through the transmission facilities of Union. EGD has transportation contracts with TransCanada, Vector and Union for the delivery of gas to and from storage.

Pursuant to a Notice of Proceeding issued by the OEB on December 29, 2005 the OEB indicated its intention to examine two issues involving gas storage under the Natural Gas Electricity Interface Review (NGEIR). The first issue related to rates for gas-fired electricity generators (and other qualified customers). The second issue involved storage regulation in Ontario and, more specifically, whether the OEB should refrain, in whole or in part, from exercising its power to regulate the rates charged for the storage of gas in Ontario. Both of these issues were identified in a 2005 report of the OEB entitled “Natural Gas Regulation in Ontario: A Renewed Policy Framework”.

On November 7, 2006, the OEB issued its Decision with Reasons in the NGEIR proceeding. In its decision, the OEB recognized that the gas storage market in Ontario is subject to competition sufficient to protect the public interest, and the OEB will not regulate new storage prices or storage prices outside the franchise area. As such, new storage services developed by EGD will be subject to competitive market conditions and priced accordingly.

On November 28, 2006, EGD announced that it is conducting a binding open season for high deliverability natural gas storage service at its existing facility near Dawn. The binding open season is for services totalling a daily maximum of 2,124,600 gigajoules (GJ), or approximately 2 bcf, of storage capacity, including 10 or 20-day storage service with firm year-round withdrawal and injection levels. The service is expected to be in place between April 2008 and April 2009, depending on customer needs. If EGD determines, through this open season, that sufficient demand exists for its storage services, and can be contracted on terms acceptable to EGD, it will proceed with the necessary investment to meet this market need.

HISTORICAL OPERATING STATISTICS

The following tables present certain statistics relating to the past three years of operations of Enbridge Gas Distribution:


							15 months
	Year ended			Year ended			ended
	December 31,			December 31,			December 31,
	2006			2005			2004

Gas supply and sendout (mmcf)
Natural gas purchased		156,850			183,333			214,853
Gas into storage		(75,224	)		(105,097	)		(104,435	)
Gas out of storage		74,602			96,381			126,699

Total gas sendout		156,228			174,617			237,117
Transportation of gas		250,445			264,034			337,775

		406,673			438,651			574,892


Gas sales to customers (mmcf)		159,503			174,515			223,343
Transportation of gas		248,389			264,182			352,047

Total sales		407,892			438,652			575,390
Used by EGD		141			170			265
Other volumetric variations		(1,360	)		(215	)		(763	)

		406,673			438,652			574,892


Average daily sendout (mmcf)		1,109			1,194			1,264
Average use per residential customer (mcf)		93			104			126
Degree day deficiency¹
Actual		3,355			3,750			5,052
Forecast based on normal weather		3,745			3,747			4,849

Number of active customers – year end²		1,819,765			1,774,067			1,726,856

Number of employees – end of period		1,914			1,765			1,633


					15 months
	Year ended		Year ended		ended
	December 31,		December 31,		December 31,
	2006		2005		2004

Number of active customers – end of period
Residential		1,007,058		1,047,350		976,384
Commercial		92,053		93,686		85,338
Industrial		3,549		3,763		3,441
Wholesale		1		1		1
Transportation		717,104		629,267		661,692

Total active customers²		1,819,765		1,774,067		1,726,856


New customer additions³		47,622		50,697		74,307



Notes:

¹		Degree day deficiency is a measure of coldness which is indicative of volumetric requirements of natural gas utilized for heating purposes in EGD’s franchise area. It is calculated by accumulating, for the fiscal period, the total number of degrees each day by which the daily mean temperature falls below 18 degrees Celsius. The figures given are those accumulated in the Greater Toronto Area.


²		Active customers relate to the count of gas-consuming customers at the end of the period. The 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 material impact on EGD’s earnings.

³		New customer additions relate to new service lines installed during the period.

Regulation

In March 2005, the OEB released its renewed policy framework with respect to natural gas regulation in Ontario, the subject matter of an OEB proceeding known as the Natural Gas Forum. The OEB expressed its belief that a multi-year incentive regulation (IR) plan will meet its objectives. IR is a method of government regulation of monopoly firms, with an objective of achieving socially desired outcomes through the provision of incentives.

Fiscal 2007 Rate Application

The EGD’s 2007 rate application was filed with the OEB in August 2006 and consisted of a traditional cost of service application. In January 2007, the Company arrived at an agreement to settle certain major issues in its rate application with key stakeholders. This settlement was approved by the OEB on January 29, 2007 and will allow the Company to continue operating within its current environment. A final decision on the remaining issues of the 2007 rate application is expected during the second quarter of 2007. The key elements of the application are summarized below:


	Requested for			Approved for			Approved for
	December 31,			December 31,			September 30,
Regulatory year ended	2007			2006			2005

Rate base (millions)	$	3,801.3		$	3,633.6		$	3,422.1
Rate of return on rate base		7.76	%		7.74	%		8.10	%
Deemed common equity for regulatory purposes		38.00	%		35.00	%		35.00	%
Rate of return on common equity		8.39	%		8.74	%		9.57	%

As part of its 2007 rate application, the EGD has requested an increase in the equity component of its deemed capital structure. The requested 38% equity level reflects changes in EGD’s current business risk environment and financial risk position relative to the current approved deemed equity level of 35%. The rate of return on common equity is calculated with reference to a formula approved by the OEB that incorporates the long bond yield forecast. The rate of return of 8.74% used in the 2007 rate application was a placeholder, and reflected the OEB approved return embedded within 2006 rates. The allowed rate of return on common equity for 2007, calculated in accordance with the OEB’s formula, is 8.39%. This rate of return on common equity will replace the placeholder used by EGD in its 2007 rate application and will be embedded in 2007 rates.

Incentive Regulation

Improving the regulatory environment is also a key strategic thrust to provide greater operational and organizational flexibility. EGD will remain in a cost of service environment in 2007 but a change to Incentive Regulation (IR), is expected in 2008, with 2007 as the base year for a potential four to five year plan. Consultation with the OEB has commenced with respect to potential implementation of IR methodology for setting rates for services provided by EGD, which differs from the existing cost of service methodology. The potential impact on the future operating environment of EGD is not currently known, however EGD expects to obtain details on a proposed IR plan in the fourth quarter of 2007.

The following are the key anticipated parameters of IR:

	•		Inclusion of an appropriate annual adjustment mechanism to give effect to cost changes and productivity improvements, to ensure that benefits of efficiencies are shared with customers during the term of the plan;

	•		Mandatory cost of service rebasing at the end of each IR plan term and before a new plan is put in place to ensure that efficiency improvements will be identified and the benefits are passed onto customers through base rates for the following IR plan period;

	•		Earnings sharing mechanisms will not form part of IR plans, in order to provide a strong incentive to achieve sustainable efficiencies that can be shared with customers through the annual adjustment mechanism and rebasing; and

	•		IR term plans are expected to run between four and five years.

The objectives of IR are as follows:

	•		Reduce regulatory costs with less frequent hearings (maximum every 3 to 5 years) rather than every year under the current cost of service mechanism;

	•		Provide incentives for improved efficiency;

	•		Provide more flexibility for utility management; and

	•		Provide more stable rates.

2006 Rates

On February 9, 2006, the OEB released its decision relating to EGD’s 2006 rate application. See the above table for the details of the decision.

Competitive Conditions

Natural gas is the predominant fuel of choice in the residential heating market throughout EGD’s franchise area. The primary competition for natural gas remains domestic fuel oil and electricity. Natural gas has continued to provide both environmental and price advantages, and this is expected to continue. During 2006, natural gas in the residential market experienced, on average, a price advantage on an equivalent annual volume basis of 38% (2005 – 40%) against electricity and 30% (2005 – 32%) against domestic fuel oil.

The Ontario franchise area remains one of the most rapidly growing regions in North America. While customer growth results in increased distribution volumes, this increase is limited by the partially offsetting impact of lower average annual consumption, resulting from increased adoption of energy efficient technology and more energy efficient building construction. In addition, conservation efforts by customers to partially mitigate the impact of higher natural gas commodity prices further contribute to the decline in annual average consumption.

Energy Efficiency and Demand Side Management (DSM)

EGD is pursuing relationships to increase the penetration of natural gas products and to encourage fuel switching from electricity to natural gas. EGD continues to develop and introduce new end-use technologies that add volume and offer energy efficient alternatives to customers. EGD’s DSM initiatives cover a broad range of end-uses, from traditional water heating and space heating to fuel-cell power generation, commercial cooking and industrial processes.

In 2006, EGD successfully negotiated an update to the regulatory arrangements relating to DSM. The new DSM provides an accelerated financial incentive from the first unit of net savings. The financial incentive is in addition to the cost recovery and lost revenue adjustment mechanisms that were already in place to offset the costs of supporting DSM.

Environment and Safety

The impact of energy use on the environment is a significant concern with attention being focused on the environmental impacts associated with the production, transmission, delivery of energy, and air emissions, including greenhouse gases (GHG’s). The use of fossil fuels results in air emissions including carbon dioxide, sulphur dioxide, nitrogen oxides, total suspended particulates, and to a lesser extent, carbon monoxide and methane. However, the levels of these emissions are not the same for all fossil fuel types. Natural gas has the lowest emissions profile of any of the fossil fuels, emitting less carbon dioxide than conventional coal-fired generation and no sulfur dioxides. For these reasons, natural gas offers a substantial comparative environmental benefit for energy delivery.

Methane, the principal component of natural gas, is a GHG and is understood to contribute to global warming. Although small atmospheric releases of methane during the production, processing, transmission and

distribution of natural gas are inevitable, methane emissions from the natural gas industry in Canada, relative to natural sources such as wetlands, are low.

EGD performs on-going leak detection studies to identify potential sources of methane emissions and the specific measures to reduce these emissions. Further, EGD is participating in the Canadian Energy Partnership for Environmental Innovation study to identify where the largest emission sources occur in the system. EGD has also been recognized by Canada’s GHG Challenge Registry (formerly the Climate Change Voluntary Challenge and Registry Program) for its leadership and quality reporting.

Between 1995 and the end of 2006 EGD was successful in helping its customers reduce their natural gas consumption by 102.4 bcf (2.9 billion cubic metres) through participation in its DSM programs. This translates into the avoidance of 5.5 million tonnes of GHG emissions being released into the atmosphere. Each of these measures moves EGD closer to the realization of its emission reduction targets, despite the pressures of significant growth in EGD’s customer base. EGD’s emission reductions are documented in the GHG Challenge Registry reports.

Programs have been implemented to ensure adherence to Enbridge Inc.’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, on-site environmental auditing, and a continuing focus on corporate due diligence. None of the environmental protection requirements applicable to EGD are expected to significantly adversely affect EGD’s competitive position, capital expenditure program or level of earnings.

Employees

EGD has 1,914 employees, 38% of whom are unionized. All of EGD’s unionized employees are represented by the Communications, Energy and Paperworkers Union, Local 975. The current collective agreement expires in December 2008.

EGD has filed an Annual Information Form, Financial Statements, and Management’s Discussion and Analysis with Canadian Securities Regulatory Authorities. These documents contain detailed disclosure about EGD and are publicly available through www.sedar.com. No part of EGD’s AIF, Financial Statements or Management’s Discussion and Analysis is incorporated by reference in this AIF.

Other Gas Distribution and Services Businesses

Gazifère is a gas distribution utility located in Southwestern Quebec. Niagara Gas provides transmission services to EGD, Gazifère, St. Lawrence and MichCon (an unrelated company). Enbridge Gas Services manages the Company’s merchant capacity commitments on the Alliance and Vector pipelines.

Enbridge has a 70% joint venture interest in CustomerWorks, which provides service covering the entire meter-to-cash process, including information technology, fleet services, call management centre, customer care and billing. CustomerWorks provides services to more than 2.4 million customers including customers of Terasen and EGD. In August 2002, CustomerWorks outsourced the provision of its customer care services to a new entity owned and operated by Accenture Inc.

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

The Company owns 70% of and operates EGNB, the natural gas distribution franchise in the province of New Brunswick. EGNB constructed a new distribution system and has approximately 5,600 customers. Approximately 565 kilometres (351 miles) of distribution main has been installed with the capability of attaching 27,000 customers. EGNB is regulated by the New Brunswick Board of Commissioners of Public Utilities.

Enbridge also holds a 42.7% interest in the Aux Sable natural gas liquids extraction and fractionation facility at its facilities near Chicago. 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. In 2006, Aux Sable entered into an agreement with BP Products North America Inc. to sell all of its NGL production to BP. Aux Sable receives a fixed annual fee and a share of any net margin generated from the business in excess of specified thresholds. In addition, BP reimburses Aux Sable for all operating, maintenance and certain capital costs. BP supplies, at its cost, all make-up gas and fuel supply gas to the Aux Sable facilities and assumes responsibility for capacity on the Alliance Pipeline held by an Aux Sable affiliate, at market rates. The agreement is for an initial term of 20 years, commencing December 31, 2005 and may be extended by mutual agreement for 10 year terms. If cumulative losses exceed a certain limit, BP will have the option to terminate the agreement, however Aux Sable has the right to reduce such losses to avoid termination.

Tidal Energy provides commodity marketing services for the Company and its customers in a full range of crude oil types including light sweet, light and medium sours and several heavy grades and natural gas liquids. Tidal Energy transacts at many of the major North American market hubs and provides its customers with a variety of programs including flexible pricing arrangements, hedging programs, product exchanges, physical storage programs and total supply management, through the analysis and implementation of different transportation options, reduced quality differentials and tariff structures, and utilizing Risk Management Pricing options. Tidal Energy’s business involves buying, selling and storing large quantities of crude oil and gas at low margins. Tidal Energy’s business includes the purchase and sale of crude oil and in the course these activities, physical receipt or delivery shortfalls can create modest commodity exposures. Any open positions created from this physical business are tightly monitored by, and must comply with, the Company’s formal risk management policies.

Employees

Enbridge employs approximately 264 individuals in its Other Gas Distribution and Services businesses.

INTERNATIONAL

The Company’s International business invests in energy transportation and related energy projects outside of Canada and the United States. The Company has a 25% interest in a Spanish pipeline company, Compañía Logística de Hidrocarburos CLH, S.A. (CLH), a 24.7% investment in the Colombian crude oil pipeline, Oleoducto Central S.A. (OCENSA), and a 100% interest in CIT Colombiana S.A. (CITCol), which provides technical and management services in connection with the operation of the OCENSA pipeline. The Company also has a 100% interest in Enbridge Technology Inc., which provides advisory, consulting and training services related to proprietary pipeline operating technologies.

CLH

The primary activity of CLH is the storage and shipment of refined products through a comprehensive distribution network located throughout Spain. Earnings are based on a fee for service tariff, adjusted annually for inflation, and are dependent on throughput volumes and storage levels.

CLH is the primary basic logistics distribution network for refined products in Spain and provides services on an open access non-discriminatory basis. The system consists of over 3,400 (2,100 miles) kilometres of pipelines and 38 storage facilities located throughout the country. CLH’s pipeline facilities are connected to the country’s eight crude oil refineries and to major coastal port locations where crude oil and refined products are imported. CLH receives refined products from customers at the refineries or ports and transports them, mainly by pipeline, to its storage facilities located throughout the Spanish mainland and the Balearic Islands. The network of pipelines and storage facilities are the primary means by which the Spanish refiners and other market players supply their commercial and retail customers. CLH customers’ product destinations are located, on average, less than 60 kilometres via highway from a CLH terminal. CLH provides product distribution to locations not connected to the pipeline system through its own fleet of tanker trucks and chartered tanker ships.

Based on the extensive network of pipelines and storage facilities, and its tariff structure, CLH has a dominant market position in Spain, with a total market share in 2006 of 82% for gasoline and diesel, and transports 100% of aviation fuel. Most of the competition comes from storage services provided by other companies. CLH has approximately 70% of the total refined products storage capacity in Spain (excluding refineries). CLH also offers secondary distribution services, the most significant being the services provided through CLH

Aviation, which handles aviation fuel at airport locations throughout Spain. This business includes the storage of aviation fuel, loading of aircraft refuelling units and the refuelling of aircraft. New policies issued by the Spanish airport authority (AENA) to promote competition allow for new non-CLH operators to enter the aircraft-refueling segment of this business. While CLH’s share of this segment of the market may reduce over time, the aviation fuel business will continue.

Earnings from CLH are directly impacted by the demand for refined products. Economic growth in Spain over the last decade has been one of the highest in the European Union, which has led to increasing demand for energy, including refined products. The central region of the country, in and around Madrid, has seen the largest growth in demand. CLH is in the process of expanding its system over the next several years in order to meet the continued growth expected in this region. This expansion, which includes an increase in storage capacity and looping of both the northern and southern main lines, will be constructed in stages to match the expected growth in volumes.

OCENSA

The OCENSA pipeline consists of 829 kilometres (515 miles) of 30-inch and 36-inch pipeline, pumping units, tankage and marine loading facilities, with a capacity to transport 550,000 bpd of crude oil. The pipeline links the Cuisiana and Cupiagua oilfields in the central interior of Colombia to the Port of Coveñas on the Caribbean coast. The Company earns a fixed rate of return on the OCENSA pipeline investment, as well as operating fees, through its 100% interest in CITCol.

Environmental Protection

The international operations of Enbridge are subject to applicable laws and regulations relating to environmental protection and operational safety. To the best of the Company’s knowledge, all international operations are in material compliance with applicable environmental and safety regulations. Risks of significant costs and liabilities, however, are inherent in the nature of the operations, and there can be no assurances that such costs and liabilities will not be incurred.

Employees

Enbridge International operations directly employ 20 employees.

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 may be included in Corporate. These activities are seen as potential growth areas that may have a strategic fit with existing operations or present the opportunity to enhance activity levels in existing operating segments. Approximately 198 individuals are employed by Enbridge in the Corporate segment.

CORPORATE SOCIAL RESPONSIBILITY

Enbridge defines Corporate Social Responsibility (CSR) as conducting business in a socially responsible and ethical way, protecting the environment and health and safety of people, supporting human rights and engaging, respecting and supporting the communities and cultures with which the Company works.

A comprehensive system of stewardship and accountability is in place and functioning among Directors, management and employees. Examples include compliance with Sarbanes-Oxley requirements and the Canadian equivalent rules, internal and external audits of operations throughout the Company, employee compliance with Enbridge’s Statement of Business Conduct and a majority of independent Directors on the Company’s Board as well as plain and open communication with stakeholders.

Environmental initiatives include pursuing alternative and renewable energy technologies such as wind power, preventing pipeline leaks by conducting on-going inspection and maintenance programs as part of

the comprehensive integrity management of pipelines and facilities, and the development of a strategy to reduce greenhouse gas emissions. This strategy involves initiatives such as improving the energy efficiency of pipelines, encouraging the efficient use of natural gas by customers and replacing older cast iron pipe with new polyethylene mains at EGD. Enbridge engages employees on health and safety issues through training, communication programs and the establishment of local and regional environmental, health and safety committees.

Stakeholder relations involve developing positive relationships with government agencies, environmental groups, landowners, business partners and local communities. Initiatives include early-stage project consultation with a variety of stakeholders on organic growth projects and public awareness programs on pipeline safety.

Enbridge supports universal human rights and reinforces this with comprehensive policies and practices addressing human rights. For example, Enbridge was one of the first Canadian companies to adopt the Voluntary Principles on Security and Human Rights, which stress the importance of promoting and protecting human rights throughout the world and the constructive role business can play in advancing these goals.

Enbridge makes voluntary contributions to charitable organizations in the areas of: education, health, environment, social services, arts and culture, civic leadership and volunteer resources in order to contribute to the economic and social development of communities where Enbridge employees live and work.

While Enbridge is focused on generating long-term value for investors, Corporate Social Responsibility defines the Company’s commitment to achieving and sustaining that objective in a socially and environmentally responsible way.

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, 2006, which are incorporated herein by reference (the page references below are to the Company’s 2006 Management’s Discussion and Analysis filed on SEDAR at www.sedar.com):

Liquids Pipelines – Business Risks (page 18);
Gas Pipelines – Business Risks (pages 20-21);
Sponsored Investments – Business Risks (pages 26-27; 29);
Gas Distribution and Services – Business Risks (pages 34-35);
International – Business Risks (page 41);
Overall Risk Management (pages 45-48).

DIVIDENDS

DIVIDENDS PAID


(Canadian dollars per share)	2006		2005		2004

Preferred Shares, Series A		1.375		1.375		1.375
Common Shares		1.150		1.038		0.915

Dividends on common shares are paid quarterly as determined by the Company’s Board of Directors. The Company is targeting to pay out approximately 60% to 70% of earnings as dividends, balancing its future capital reinvestment requirements and investors’ preferences for income. Dividends on the preferred shares, Series A, are fixed and are paid quarterly.

There are no restrictions that currently prevent the Company from paying dividends. However, in the event of liquidation, dissolution or winding-up of the Company, the preferred shareholders have priority in the payment of dividends over the common shareholders. As well, should the Company fail to make payments

on certain financial obligations, the Company could be precluded from paying dividends on its common and preferred shares.

DESCRIPTION OF CAPITAL STRUCTURE

GENERAL DESCRIPTION OF CAPITAL STRUCTURE

At December 31, 2006, the Company’s capital structure consists of 351.8 million common shares with a book value of $2,416.1 million and 5.0 million preferred shares, Series A with a book value of $125.0 million.

Common Shares

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

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

The Company has a Shareholder Rights Plan that is designed to encourage the fair treatment of shareholders in connection with any take-over offer for the Company. Rights issued under the plan become exercisable when a person, and any related parties, acquires or announces the intention to acquire 20% or more of the Company’s outstanding common shares without complying with certain provisions set out in the plan or without approval of the Board of Directors. Should such an event 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 Preferred Shares, Series A are entitled to fixed, cumulative, quarterly preferential dividends of $1.375 per share per year. Subsequent to December 31, 2006, the Company may, at its option, redeem all or a portion of the outstanding preferred shares for $25.25, if redeemed on or prior to December 1, 2007; $25.00, if redeemed thereafter, in each case all accrued and unpaid dividends will be paid on redemption.

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
Preferred Shares, Series A	Pfd-2 (low)¹	BBB³	Baa2⁵
Preferred Securities	Pfd-2y¹	BBB³	Baa1⁵
Unsecured Debt	A²	A-⁴	A3⁵
Commercial Paper	R-1 (low)²	A-1 (low)⁴	Not Rated
Rating Outlook	Stable	Stable	Under Review⁶


Notes:

1.		DBRS’ rating of preferred securities and preferred shares is on a rating scale that ranges from a high of ‘Pfd-1’ to a low of ‘D’. The ‘y’ modifier is used to indicate a hybrid security. Each rating category is denoted by the subcategories “high” and “low”. The absence of either a “high” or “low” designation indicates the rating is in the middle of the category.

2.		DBRS rates debt instruments by rating categories from a high of ‘AAA’ to a low of ‘D’. Each rating category, other than AAA, is denoted by the subcategories “high” and “low”. The absence of either a “high” or “low” designation indicates the rating is in the middle of the category. DBRS’ rating of commercial paper is on a rating scale that ranges from a high of ‘R-1’ to a low of ‘R-3’. DBRS applies modifiers ‘high’, ‘middle’, and ‘low’ to designate relative standing within a particular rating category.

3.		S&P rates preferred shares and preferred securities 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’. The ratings from ‘AA’ to ‘CCC’ may be modified by the addition of a ‘plus’ or ‘minus’ to show relative standing in the major rating categories. S&P’s rating of commercial paper is on a rating scale that ranges from a high of ‘A-1’ to a low of ‘D’.

5.		Moody’s rates securities, shares and 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.

6.		Moody’s placed Enbridge’s credit ratings under review for possible downgrade on December 13, 2006.

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

MARKET FOR SECURITIES

The common shares of the Company are traded on the Toronto Stock Exchange in Canada and on the New York Stock Exchange in the United States under the symbol ENB. The Toronto Stock Exchange is the principal market for Enbridge’s common shares. The Preference Shares, Series A are traded on the Toronto Stock Exchange under the symbol ENB.PR.A and the preferred securities, series 7.8%, are traded on the Toronto Stock Exchange under the symbol ENB.PR.D. On December 18, 2006 the Company announced its intention to redeem all 8,000,000 Preferred Securities. The redemption price is $25.00 per Preferred Security plus accrued and unpaid interest of $0.2458 per security for the period covering from the last interest payment date of December 31, 2006 to the redemption date of February 15, 2007.

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


			TSX (C$)						NYSE (US$)
			ENB		ENB.PR.A		ENB.PR.D		ENB

January		High		37.00		26.50		26.80		32.06
		Low		34.90		26.10		25.90		29.81
	31-Jan	Close		36.02		26.31		26.05		31.75
		Volume		11,664,700		42,900		115,300		2,502,400

February		High		36.99		26.74		26.25		32.29
		Low		35.09		25.86		25.84		30.01
	28-Feb	Close		35.80		26.33		25.95		31.52
		Volume		14,254,600		40,100		110,300		3,043,800

March		High		35.97		26.32		26.41		31.46
		Low		33.42		25.65		25.61		28.64
	31-Mar	Close		33.60		25.85		26.00		28.87
		Volume		15,822,400		24,200		120,900		3,108,500

April		High		34.37		25.70		26.18		30.26
		Low		32.69		25.00		25.40		28.06
	28-Apr	Close		33.15		25.38		25.40		29.83
		Volume		21,652,900		43,000		86,400		2,479,500

May		High		35.24		25.90		26.00		32.01
		Low		31.75		25.30		25.22		28.25
	31-May	Close		34.55		25.50		25.34		31.60


			TSX (C$)						NYSE (US$)
			ENB		ENB.PR.A		ENB.PR.D		ENB

		Volume		20,354,500		39,700		119,200		4,104,500

June		High		35.00		25.86		25.85		31.90
		Low		32.54		25.30		25.25		29.01
	30-Jun	Close		33.97		25.35		25.31		30.57
		Volume		15,580,800		43,200		122,600		5,963,100

July		High		37.08		25.93		25.70		32.73
		Low		34.48		25.20		25.31		30.33
	31-Jul	Close		36.19		25.93		25.68		32.04
		Volume		8,998,900		26,000		128,300		3,723,600

August		High		37.02		25.95		26.30		33.34
		Low		35.28		25.50		25.55		31.36
	31-Aug	Close		36.39		25.73		25.71		32.98
		Volume		11,466,700		50,600		103,200		2,689,600

September		High		36.80		25.84		26.00		33.28
		Low		34.44		25.52		25.26		30.71
	29-Sep	Close		36.07		25.54		25.74		32.30
		Volume		13,482,000		75,000		76,300		2,176,200

October		High		37.93		25.92		25.71		33.90
		Low		34.50		25.53		25.40		30.32
	31-Oct	Close		37.76		25.85		25.54		33.90
		Volume		11,532,400		39,200		105,800		2,349,500

November		High		40.71		25.95		25.85		35.73
		Low		37.41		24.35		25.49		33.05
	30-Nov	Close		40.20		25.67		25.63		35.28
		Volume		18,445,600		44,800		127,900		3,038,500

December		High		41.45		26.70		25.94		36.00
		Low		39.22		25.45		24.91		33.80
	29-Dec	Close		40.27		25.78		25.07		34.40
		Volume		10,455,800		254,900		186,800		3,337,300

Annual		High		41.45		26.74		26.80		36.00
		Low		31.75		24.35		24.91		28.06
	29-Dec	Close		40.27		25.78		25.07		34.40
		Volume		173,711,300		723,600		1,403,000		38,516,500

The following table outlines the securities issued by the Company during 2006 that are not listed or quoted on an exchange. These are in the form of unsecured medium term note debentures.


	Principal
Issuer	Amount	Coupon			Issue Date	Maturity Date	Issue Price

Enbridge Gas Distribution Inc.	$300 million		5.21	%	February 24, 2006	February 25, 2036	$	99.864
Enbridge Inc.	$200 million		4.67	%	March 24, 2006	March 25, 2013	$	99.970
Enbridge Inc.	$300 million		5.00	%	August 9, 2006	August 9, 2016	$	99.984
Enbridge Pipelines Inc.	$150 million		5.08	%	December 18, 2006	December 19, 2036	$	99.924
Enbridge Gas Distribution Inc.	$175 million		4.77	%	December 19, 2006	December 17, 2021	$	99.958

DIRECTORS AND OFFICERS

DIRECTORS

The following table sets forth the names of the Directors of Enbridge Inc. as of February 21, 2007, their municipalities of residence, their respective principal occupations within the five preceding years and the year from which they first became a Director of the Company (except where otherwise noted). Each Director elected holds office until the next annual meeting of shareholders or until a successor is duly elected or appointed. Enbridge does not have an Executive Committee. As required, the Company has an Audit, Finance & Risk Committee (AFR Committee).


Name and	Principal Occupation for the	Director
Municipality of Residence	Five Preceding Years	Since¹

DAVID A. ARLEDGE^{4, 5} Naples, Florida U.S.A.	Corporate Director; Chair of the Board of Directors of Enbridge Inc. since 2005. Vice Chairman of the Board of Directors of El Paso Corporation (integrated energy company) in 2001; prior thereto, Chairman, President and/or Chief Executive Officer of the Coastal Corporation since 1994.		2002

JAMES J. BLANCHARD^{3, 4, 6} Beverly Hills, Michigan U.S.A.	Chairman, Government Affairs, DLA Piper U.S., LLP (law firm), since June, 2006; prior thereto, Senior Partner, DLA Piper U.S., LLP (law firm) since 1996; prior thereto, United States Ambassador to Canada.		1999

J. LORNE BRAITHWAITE^{3, 5} Dublin, Ireland	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 Canada	President & Chief Executive Officer of Enbridge since January 2001; prior thereto, President & Chief Operating Officer from September to December 2000.		2000

J. HERB ENGLAND Naples, Florida U.S.A.	President & Chief Executive Officer of Stahlman-England Irrigation Inc. (contracting company) since January 2000; prior thereto, Chairman, President & Chief Executive Officer of Sweet Ripe Drinks Ltd. (fruit beverage manufacturing company) from 1993 to 1997.		2007

E. SUSAN EVANS^{3, 5} Calgary, Alberta Canada	Corporate Director.		1996


Name and	Principal Occupation for the	Director
Municipality of Residence	Five Preceding Years	Since¹

DAVID A. LESLIE^{2, 4} Toronto, Ontario Canada	Corporate Director; Chairman and Chief Executive Officer of Ernst & Young LLP from 1999 to 2004.		2005

ROBERT W. MARTIN^{2, 5, 7} Toronto, Ontario Canada	Corporate Director.		1992

GEORGE K. PETTY^{2, 4} San Luis Obispo, California U.S.A.	Corporate Director; President & Chief Executive Officer of Telus Corporation (telecommunications company) from 1994 to 1999.		2001

CHARLES E. SHULTZ^{2, 5} Calgary, Alberta Canada	Chairman & Chief Executive Officer of Dauntless Energy Inc. (private oil and gas corporation) since 1995; Chairman of Canadian Oil Sands Limited (a subsidiary of Canadian Oil Sands Trust, a public oil and gas trust) since 1996; Chair and member of Compensation Committee and Lead Director of Newfield Exploration since 1994.		2004

DONALD J. TAYLOR^{3, 4} Jacksons Point, Ontario Canada	Corporate Director; Chair of the Board of Directors of Enbridge Inc. from 1996 to 2005.		1979

DAN C. TUTCHER^{3, 4} Houston, Texas U.S.A.	Corporate Director; Group Vice President, Transportation South of Enbridge Inc., President of Enbridge Energy Company, Inc. and Enbridge Energy Management L.L.C. from 2001 to 2006; prior thereto, Chairman of the Board, President & Chief Executive Officer of Midcoast Energy Resources, Inc. from 1992 to 2001.		2006


Notes:

1.		“Director Since” 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. Herb England joined the Board of Directors on January 1, 2007 and at February 21, 2007, he was not a member of any Committees of the Board.

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

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

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

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

6.		On April 10, 2006, the Ontario Securities Commission (the “Commission”) issued a temporary cease trade order against Bennett Environmental Inc. (“Bennett”), and subsequently a cease trade order on April 24, 2006, after Bennett failed to file its annual financial statements and related management’s discussion and analysis for the year ended December 31, 2005. Under such orders, certain directors, officers and insiders of Bennett, including Governor Blanchard, were prohibited from trading Bennett securities until the Commission was in receipt of the necessary filings. Bennett made the requisite filings on or about May 30, 2006 and the cease trade order lapsed on June 19, 2006. Governor Blanchard resigned from Bennett on August 7, 2006.

7.		On December 2, 2003, the Commission issued a temporary cease trade order against Atlas Cold Storage Income Trust (“Atlas”), and subsequently a cease trade order on December 15, 2003, after Atlas failed to file its interim financial statements for its nine-month period ended September 30, 2003. Under such orders, certain trustees, including Mr. Martin, were prohibited from trading Atlas trust units until the Commission was in receipt of the necessary filings. Atlas made the requisite filings on January 27, 2004 and the cease trade order lapsed on February 2, 2004. Mr. Martin did not stand for re-election as a Trustee of Atlas at the Atlas annual meeting held in June 2004.

OFFICERS

The following table sets forth the names of the executive officers, their current office with the Company effective December 31, 2006, 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 Canada		President & Chief Executive Officer since January 2001; prior thereto, President & Chief Operating Officer from September to December 2000.

J. RICHARD BIRD Executive Vice President, Liquids Pipelines Calgary, Alberta Canada		Executive Vice President, Liquids Pipelines since May, 2006; prior thereto, Group Vice President, Liquids Pipelines since May 2005; prior thereto, Group Vice President, Transportation North since May 2001.

STEPHEN J.J. LETWIN Executive Vice President, Gas Transportation & International Woodlands, Texas Canada		Executive Vice President, Gas Transportation & International since May 2006; prior thereto, Group Vice President, Gas Strategy & Corporate Development since April 2003; prior thereto, Group Vice President, Distribution & Services since September 2000.

STEPHEN J. WUORI Executive Vice President, Chief Financial Officer & Corporate Development Calgary, Alberta Canada		Executive Vice President, Chief Financial Officer & Corporate Development since May 2006; prior thereto, Group Vice President & Chief Financial Officer since April 2003; prior thereto, Group Vice President, Planning & Development since September 2000.

BONNIE D. DUPONT Group Vice President, Corporate Resources Calgary, Alberta Canada		Group Vice President, Corporate Resources since September 2000.

DAVID T. ROBOTTOM Group Vice President, Corporate Law Calgary, Alberta Canada		Group Vice President, Corporate Law since June 2006; prior thereto, partner, Stikeman Elliott LLP from February 2004 to May 2006; prior thereto, partner, Fraser Milner Casgrain LLP to January, 2004 and was also Chief Executive Officer, Fraser Milner Casgrain LLP from February 1999 to February 2003.


Name, Position and		Position and Principal Occupations for the
Municipality of Residence		Five Preceding Years
JAMES A. SCHULTZ Senior Vice President, New Ventures Calgary, Alberta Canada		Senior Vice President, New Ventures since September 2006; prior thereto, Senior Vice President since April 2003 and President of Enbridge Gas Distribution Inc. since June 2001.

JOHN K. WHELEN Senior Vice President, Corporate Development Calgary, Alberta Canada		Senior Vice President, Corporate Development since September 2006; prior thereto, Vice President & Treasurer from February 2002 to August 2006; prior thereto, Assistant Treasurer from December 1997 to January 2002.

As at December 31, 2006, the directors and all officers of the Issuer (including the Executive Officers listed above) beneficially owned, directly or indirectly, 1,394,473 common shares of the Company, representing approximately 3.96% of the issued and outstanding common shares on that date. The information as to shares beneficially owned or over which control or direction is exercised, not being within the knowledge of the Company, 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 Company.

AUDIT, FINANCE & RISK COMMITTEE – FURTHER INFORMATION

GENERAL INFORMATION

Enbridge is required by law to have an audit committee and to disclose certain information concerning that committee pursuant to MI 52-110.

The Board has established the AFR Committee, which at December 31, 2006 was comprised: Robert W. Martin (Chair), David A. Leslie, George K. Petty and Charles E. Shultz. The Board of Directors has determined that each of the members is “independent” and “financially literate”, within the meaning of MI 52-110.

MANDATE

A summary of the AFR Committee’s mandate and responsibilities is set forth under the “Report of the Audit, Finance & Risk Committee” in the Management Information Circular for the May 2007 meeting of Shareholders. The AFR Committee’s Terms of Reference are available on the Company’s website.

RELEVANT EDUCATION AND EXPERIENCE OF MEMBERS

The following is a brief summary of the education or experience of each member of the AFR Committee that is relevant to the performance of his responsibilities as a member of the AFR Committee, including any education or experience that has provided the member with, among other things, an understanding of the accounting principles used by Enbridge to prepare its annual and interim financial statements.

Robert W. Martin

Mr. Martin acquired significant financial experience and exposure to accounting and financial issues as President, Chief Executive Officer and director of various corporations and in various finance positions. He was the President & Chief Executive Officer of Consumers Gas Company (now Enbridge Gas Distribution Inc.) where he was responsible for financial aspects related to that corporation. He has acted as a member and Chair of other audit committees, and currently serves as Chair of the audit committee of HSBC Bank Canada.

David A. Leslie, F.C.A.

Mr. Leslie is a chartered accountant and in his career of over 30 years, he was, among other things, personally involved in, and then actively supervised persons engaged in, preparing, auditing, analyzing and evaluating financial statements. He is the former Chairman and Chief Executive Officer of Ernst & Young LLP. He is also a director and member of the audit committee of Sobeys Inc.

George K. Petty

Mr. Petty acquired significant financial experience and exposure to accounting and financial issues during his lengthy career, including being President & Chief Executive Officer of Telus Corporation from 1994 to 1999. He has acted as a member of other audit committees.

Charles E. Shultz

Mr. Shultz acquired significant financial experience as a business executive and board member of several large Canadian and United States public companies. He served as President & Chief Executive Officer of Gulf Canada Resources Limited from 1990 to 1995 and has served as a director and Chairman of Canadian Oil Sands Limited since its inception.

PRE-APPROVAL POLICIES AND PROCEDURES

On October 30, 2003, the AFR Committee adopted a policy that requires pre-approval by the Committee of any services to be provided by the auditors, whether audit or non-audit services. The policy prohibits the Corporation from engaging the auditors to provide the following non-audit services:

	(a)		bookkeeping or other services related to accounting records and financial statements;

	(b)		financial information systems design and implementation;

	(c)		appraisal or valuation services, fairness opinions, or contribution-in-kind reports;

	(d)		actuarial services;

	(e)		internal audit outsourcing services;

	(f)		management functions or human resources;

	(g)		broker or dealer, investment adviser, or investment banking services;

	(h)		legal services; and

	(i)		expert services unrelated to the audit.

The AFR Committee believes that the policy will protect the Corporation from the potential loss of independence of the external auditors.

A copy of the policies and procedures applicable to the pre-approval of non-audit services by the Company’s external auditors may be obtained from the Corporate Secretary of the Corporation by sending a written request to #3000, 425 – 1^st Street S.W., Calgary, Alberta, T2P 3L8, by faxing a written request to (403) 231-5929, by calling (403) 231-3900 or by sending an e-mail request to corporatesecretary@enbridge.com.

The AFR Committee has also adopted a policy which prohibits the Company from hiring former employees of the auditors who provided more than 10 hours of audit, review or attest services for the Company or its subsidiaries within the one year preceding the commencement of the audit of the current year’s financial statements.

EXTERNAL AUDITOR SERVICES – FEES
The following table sets forth all services rendered by the auditors (PWC) by category, together with the corresponding fees billed by the auditors for each category of service for the financial years ended December 31, 2005 and 2006.


	Year ended December 31
	2006		2005

Audit Fees¹	$	3,688,620	$	1,658,869
Audit-Related Fees ²		248,645		166,552
Tax Fees ³		310,599		210,490
All Other Fees⁴		388,444		32,360

Total Fees	$	4,636,308	$	2,068,271


Notes:

(1)		Represents the aggregate fees billed by the Company’s auditors for audit services.

(2)		Represents the aggregate fees billed for assurance and related services by the Corporation’s auditors that are reasonably related to the performance of the audit or review of the Company’s financial statements and are not included under “Audit Fees”.

(3)		Represents the aggregate fees billed for professional services rendered by the Company’s auditors for tax compliance, tax advice and tax planning.

(4)		Represents the aggregate fees billed for products and services provided by the Company’s auditors other than those services reported under “Audit Fees”, “Audit Related Fees” and “Tax Fees”.

LEGAL PROCEEDINGS

The information, which is found under note 23 “Commitments and Contingencies” of the Company’s audited consolidated financial statements, as at, and for the year ended, December 31, 2006, is incorporated by reference herein.

REGISTRAR AND TRANSFER AGENT

The registrar and transfer agent for the common shares is CIBC Mellon Trust Company at its principal offices in Vancouver, British Columbia; Calgary, Alberta; 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 Jersey City, New York.

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; Toronto, Ontario; Montreal, Quebec; and Halifax, Nova Scotia.

INTERESTS OF EXPERTS

The consolidated financial statements of the Company, as at and for the years ended December 31, 2006, 2005 and 2004, have been examined by PWC, as detailed in their auditors’ report dated February 21, 2007. PWC is independent of the Company in accordance with the auditor’s rules of professional conduct in Canada.

ADDITIONAL INFORMATION

Additional information, including Directors’ and Officers’ remuneration and indebtedness, principal holders of the Company’s securities and options to purchase Enbridge’s securities, and the interest of insiders in material transactions, all as at December 31, 2006, is contained in Enbridge’s Management Information Circular dated March 2, 2007 furnished in connection with the Annual and Special Meeting of Shareholders to be held on May 2, 2007 for the purpose of, among other things, the election of directors. Additional financial information is provided in the Company’s comparative financial statements and management’s


Enbridge Inc. Board Guidelines		Appendix A Audit, Finance & Risk Committee

TERMS OF REFERENCE FOR THE
AUDIT, FINANCE & RISK COMMITTEE

I. CONSTITUTION

There shall be a committee, to be known as the Audit, Finance & Risk Committee (the “Committee”), of the Board of Directors of Enbridge Inc.

II. MEMBERSHIP

Following each annual meeting of shareholders of the Corporation, the Board shall elect from its members, not less than three (3) Directors to serve on the Committee (the “Members”). The Members and the Chair of the Committee are elected by the Board following the nomination of Directors by the Governance Committee. No Member of the Committee shall be an officer or employee of the Corporation or any of the Corporation’s affiliates. All members of the Committee shall, in the judgment of the Board, be unrelated and independent and shall satisfy applicable stock exchange and legal requirements. Determinations on whether a Director meets the requirements for membership on the Committee shall be made by the Board. At least one member of the Committee shall be a “financial expert” as determined by the Board and as defined by American legal or regulatory requirements. No Director may serve as a member of the Committee if such Director also serves on the audit committees of more than two other public entities unless the Board determines that such simultaneous service would not impair the ability of such Director to effectively serve on the Committee.

Any Member may be removed or replaced at any time by the Board and shall cease to be a Member upon ceasing to be a Director of the Corporation. Each Member shall hold office until the close of the next annual meeting of Shareholders of the Corporation or until the Member ceases to be a Director, resigns or is replaced, whichever first occurs. Vacancies may be filled by the Board with nominees approved by the Governance Committee.

III. MEETINGS

The Committee shall convene at such times and places designated by its Chair or whenever a meeting is requested by a Member, the Board, an officer, the internal auditor or the external auditors of the Corporation. A minimum of twenty-four (24) hours notice of each meeting shall be given to each Member and to the internal and external auditors.

A majority of the committee shall be duly convened if all Members are present, or at least a majority of the Members are present. A quorum at a meeting shall consist of at least a majority of Members. Where the Members consent, and proper notice has been given or waived, Members of the Committee may participate in a meeting of the Committee by means of such telephonic, electronic or other communication facilities as permit all persons participating in the meeting to communicate adequately with each other, and a Member participating in such a meeting by any such means is deemed to be present at that meeting.

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Enbridge Inc. Board Guidelines		Appendix A Audit, Finance & Risk Committee

In the absence of the Chair of the Committee, the Members may choose one (1) of the Members to be the Chair of the meeting.

At the invitation of a Member, other Board members, officers or employees of the Corporation, the external auditors, external counsel and other experts or consultants may attend any meeting of the Committee.

Members of the Committee may meet separately with any member of management, the external auditors, the internal auditor, internal or external counsel or any other expert or consultant.

Minutes shall be kept of all meetings of the Committee.

IV. FUNDING

The Corporation shall provide appropriate funding, as determined by the Committee, for the payment of compensation to the external auditors and any independent counsel, experts or advisors employed by the Committee and administrative expenses of the Committee.

V. REVIEW OF CHARTER

The Committee shall review and reassess the adequacy of its Terms of Reference at least annually and propose recommended changes to the Board.

VI. DUTIES AND RESPONSIBILITIES OF THE CHAIR

The Chair is responsible for:

	A.		convening Committee meetings and designating the times and places of those meetings;

	B.		ensuring Committee meetings are duly convened and that quorum is present when required;

	C.		working with Management on the development of agendas and related materials for the Committee meetings;

	D.		ensuring Committee meetings are conducted in an efficient, effective and focused manner;

	E.		ensuring the Committee has sufficient information to permit it to properly make decisions when decisions are required;

	F.		providing leadership to the Committee and to assist the Committee in reviewing and monitoring its responsibilities; and

	G.		reporting to the Board on the recommendations and decisions of the Committee.

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Enbridge Inc. Board Guidelines		Appendix A Audit, Finance & Risk Committee

VII. DUTIES AND RESPONSIBILITIES

The Committee provides assistance to the Board in fulfilling its oversight responsibility to the shareholders, the investment community and others, relating to the integrity of the Corporation’s financial statements and the financial reporting process, the management information systems and financial controls, the internal audit function, the external auditors’ qualifications, independence, performance and reports, the Corporation’s compliance with legal and regulatory requirements and the risk identification, assessment and management program. In so doing, it is the Committee’s responsibility to maintain an open avenue of communication between the Committee, the external auditors, the internal auditors and management of the Corporation.

Management is responsible for preparing the interim and annual financial statements and financial disclosure of the Corporation and for maintaining a system of internal controls to provide reasonable assurance that assets are safeguarded and that transactions are authorized, executed, recorded and reported properly. The Committee’s role is to provide meaningful and effective oversight and counsel to management without assuming responsibility for management’s day-to-day duties.

In performance of its duties and responsibilities, the Committee shall have the right as it determines necessary to carry out its duties to engage independent counsel, experts and other advisors, to inspect any and all of the books and records of the Corporation, its subsidiaries and affiliates, and to discuss with the officers of the Corporation, its subsidiaries and affiliates, the internal auditor and the external auditors, such accounts, records and other matters as any Member considers appropriate.

The Committee shall have the following specific duties and responsibilities:

A. DUTIES AND RESPONSIBILITIES RELATED TO THE EXTERNAL AUDITORS.

The Committee shall:

(i)

(a)

be responsible for the appointment, compensation, oversight, retention and termination of the external auditors who shall report directly to the Committee, provided that the appointment of the auditor shall be subject to shareholder approval; and

(b)

be responsible for the appointment, compensation, oversight, retention and termination of any other registered public accounting firm for audit, review or attestation services;

	(ii)		review and approve the terms of the external auditors’ annual engagement letter, including the proposed audit fees;

	(iii)		review and approve all engagements for audit services and non-audit services to be provided by the external auditors and, as necessary, consider

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Enbridge Inc. Board Guidelines		Appendix A Audit, Finance & Risk Committee

the potential impact of such services on the independence of the external auditors;

	(iv)		review and discuss with the external auditors all relationships that the external auditors and their affiliates have with the Corporation and its affiliates in order to determine the external auditors’ independence;

	(v)		at least annually, obtain and review a report by the external auditors describing the firm’s internal quality-control procedures, any material issues raised by the most recent internal quality-control review or peer review of the firm or by any inquiry or investigation by governmental or professional authorities within the preceding five years respecting one or more independent audits carried out by the external auditors and any steps taken to deal with any such issues and all relationships between the external auditors and the Corporation;

	(vi)		resolve disagreements, if any, between management and the external auditors regarding financial reporting;

	(vii)		inform the external auditors and management that the external auditors shall have access directly to the Committee at all times, as well as the Committee to the external auditors and that the external auditors are ultimately accountable to the Committee as representatives of the shareholders of the Corporation;

	(viii)		discuss with management and the external auditors any correspondence from or with regulators or governmental agencies, any employee complaints or any published reports that raise material issues regarding the Corporation’s financial statements or accounting policies; and

	(ix)		establish hiring policies for employees or former employees of the external auditors.

B. DUTIES AND RESPONSIBILITIES RELATED TO AUDITS AND FINANCIAL REPORTING.

The Committee shall:

	(i)		review the engagement terms and the audit plan with the external auditors and with the Corporation’s management;

	(ii)		review with management and the Corporation’s external auditors the Corporation’s financial reporting in connection with the annual audit and the preparation of the financial statements, including, without limitation, the judgment of the external auditors as to the quality, not just the acceptability of, and the appropriateness of the Corporation’s accounting principles as applied in its financial reporting and the degree of aggressiveness or

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Enbridge Inc. Board Guidelines		Appendix A Audit, Finance & Risk Committee

conservatism of the Corporation’s accounting principles and underlying estimates;

(iii)

review with management and the external auditors and make recommendations to the Board on all financial statements and financial disclosure which require approval by the Board including:

	(a)		the Corporation’s annual financial statements including the notes thereto and “Management’s Discussion and Analysis”;

	(b)		any report or opinion to be rendered in connection therewith;

	(c)		any change or initial adoption in accounting policies and their applicability to the business;

	d)		any audit problems or difficulties and management’s response;

	(e)		all significant adjustments proposed by the external auditors; and

	(f)		satisfying itself that there are no unresolved issues between management and the external auditors that could reasonably be expected to materially affect the financial statements.

	(iv)		review the Corporation’s interim financial results, including the notes thereto and “Management’s Discussion and Analysis” with management and the external auditors and approve the release thereof by management or recommend approval thereof to the Board for release by the Board;

	(v)		review annually the approach taken by management in the preparation of earnings press releases, as well as financial information and earnings guidance provided to analysts and rating agencies;

	(vi)		discuss with the external auditors their perception of the Corporation’s internal audit and accounting personnel, and any recommendations which the external auditors may have;

	(vii)		review with management, the external auditors and, as necessary, internal and external legal counsel, any litigation, claim or contingency, including tax assessments, that could have a material effect upon the financial position of the Corporation, and the manner in which these matters may be, or have been, disclosed in the financial statements;

	(viii)		review with management and monitor the funding exposure of the Corporation under the Corporation’s pension plans and review annually the annual report and financial statements applicable to each of the pension plans;

	(ix)		annually or more frequently as deemed necessary, meet separately with management and the external auditors, and at least annually with the internal

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Enbridge Inc. Board Guidelines		Appendix A Audit, Finance & Risk Committee

auditors, to review issues and matters of concern respecting audits and financial reporting processes;

	(x)		review with the Corporation’s management and, as deemed necessary, review with the external auditors, any proposed changes in or initial adoption of accounting policies, the presentation and impact of significant risks and uncertainties, and key estimates and judgments of the Corporation’s management that may be material to financial reporting;

	(xi)		review with the Corporation’s management and, as deemed necessary, with the external auditors, significant financial reporting issues arising during the fiscal period, including the methods of resolution;

	(xii)		review any problems experienced by the external auditors in performing an audit, including any restrictions imposed by the Corporation’s management or significant accounting issues on which there was a disagreement with the Corporation’s management;

	(xiii)		review the post-audit or management letter containing the recommendations of the external auditors and the response of the Corporation’s management, if any, including an evaluation of the adequacy and effectiveness of the internal financial controls of the Corporation (in respect of the scope of review of internal controls by the external auditors, the review is carried out to enable the external auditors to express an opinion on the Corporation’s financial statements);

	(xiv)		review before release relevant public disclosure documents containing audited or unaudited financial information, including annual and interim earnings press releases, prospectuses, the Annual Information Form, and the Management’s Discussion and Analysis disclosure;

	(xv)		review, in conjunction with the Human Resources & Compensation Committee, the appointment of the chief financial officer;

	(xvi)		inquire into and determine the appropriate resolution of conflicts of interest in respect of audit, finance or risk matters between or among an officer, Director, shareholder, the internal auditors, or the external auditors, which are properly directed to the Committee by the Chair of the Board, the Board, a shareholder, the internal auditors, the external auditors, or the Corporation’s management; and

	(xvii)		as deemed necessary by the Committee, inquire into and examine matters relating to the financial affairs of the Corporation, its subsidiaries or affiliates, or any of them, including the review of subsidiary or affiliate Audit Committee reports.

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Enbridge Inc. Board Guidelines		Appendix A Audit, Finance & Risk Committee

C. DUTIES AND RESPONSIBILITIES RELATED TO FINANCIAL REPORTING PROCESSES AND INTERNAL CONTROLS

The Committee shall:

	(i)		review the adequacy and effectiveness of the accounting and internal control policies of the Corporation and procedures through inquiry and discussions with the external auditors, management, and the internal auditor;

	(ii)		review with management the Corporation’s administrative, operational and accounting internal controls, including controls and security of the computerized information systems, and evaluate whether the Corporation is operating in accordance with prescribed policies, procedures and the Statement on Business Conduct;

	(iii)		annually or more frequently if deemed necessary, meet separately with the external auditor, the head of the internal audit group and management, to review issues and matters of concern respecting financial reporting processes and internal controls;

	(iv)		review with management and the external auditors any reportable conditions, material weaknesses and significant deficiencies affecting internal control;

	(v)		establish and maintain free and open means of communication between and among the Committee, the external auditors, the internal auditor and management;

	(vi)		review at least annually with the internal auditor the Corporation’s internal control procedures, and the scope and plans for the work of the internal audit group; and

	(vii)		review the adequacy of resources of the internal auditor and ensure that the internal auditor has unrestricted access to all functions, records, property and personnel of the Corporation and inform the internal auditors and management that the internal auditors shall have unfettered access directly to the Committee at all times, as well as the Committee to the internal auditors.

D. DUTIES AND RESPONSIBILITIES RELATED TO FINANCE.

The Committee shall:

	(i)		review and as required, approve or recommend for approval to the Board, prospectuses and documents, where practicable, which may be incorporated by reference into a prospectus;

	(ii)		review the issuance of equity or debt securities by the Corporation, and if deemed appropriate, authorize the filing with securities regulatory authorities

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Enbridge Inc. Board Guidelines		Appendix A Audit, Finance & Risk Committee

of any prospectus, prospectus supplement or other documentation relating thereto; and

(iii)

review and recommend for approval to the Board the annual management information circular with respect to matters related to the auditor, affecting the capital of the Corporation or principal risks to be managed by the Corporation.

E. DUTIES AND RESPONSIBILITIES RELATED TO RISK MANAGEMENT

The Committee shall:

(i)

review at least annually with senior management, internal counsel and, as necessary, external counsel and the Corporation’s internal and external auditors:

	(a)		the Corporation’s method of reviewing major risks inherent in the Corporation’s businesses, facilities, and strategic directions, including the Corporation’s risk management and evaluation process (in respect of risk management evaluations and guidelines relating to environment, health and safety matters, the Committee shall consult with and, as deemed necessary, review the recommendations of the Environment, Health & Safety Committee);

	(b)		the strategies and practices applicable to the Corporation’s assessment, management, prevention and mitigation of risks (including the foreign currency and interest rate risk strategies, counterparty credit exposure, the use derivative instruments, insurance and adequacy of tax provisions);

	(c)		the Corporation’s annual insurance report including the risk retention philosophy and resulting uninsured exposure, if any,

	(d)		the loss prevention policies, risk management programs, disaster response and recovery programs, corporate liability protection programs for Directors and officers, and standards and accountabilities of the Corporation in the context of competitive and operational considerations.

F. OTHER DUTIES OF AUDIT, FINANCE & RISK COMMITTEE

The Committee shall, as required, or as deemed necessary by the Committee:

	(i)		review senior management’s expense report summaries of the officers and Directors of the Corporation, and review senior management’s report summaries concerning corporate aircraft usage;

	(ii)		meet separately with senior management, the internal auditors, the external auditors and, as is appropriate, internal and external legal counsel and

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Enbridge Inc. Board Guidelines		Appendix A Audit, Finance & Risk Committee

independent advisors in respect of issues not elsewhere listed concerning any other audit, finance and risk matters;

	(iii)		review incidents or alleged incidents as reported by senior management, audit services, the external auditor, the Corporate Secretary, the law department, or otherwise of fraud, illegal acts and conflicts of interest;

	(iv)		establish procedures for the receipt, retention and treatment of complaints received by the Corporation regarding accounting, internal accounting controls or auditing matters and the confidential, anonymous submission by employees of concerns regarding questionable accounting or auditing matters;

	(v)		report to the Board after each Committee meeting, as required during the year, with respect to the Committee’s activities and recommendations;

	(vi)		address any other matter properly referred to the Committee by the Chair of the Board, the Board, a Director, the internal auditors, the external auditors, the CEO, or the management of the Corporation or any other matter as may be required under stock exchange rules or by law;

	(vii)		in conjunction with the Governance Committee, conduct an annual performance evaluation of the Committee; and

	(viii)		the Committee shall, in conjunction with Management, coordinate the performance of its duties concerning:

	(a)		the external auditor;

	(b)		audits and financial reporting;

	(c)		financial reporting processes and internal controls;

	(d)		finance; and

	(e)		risk management

	(f)		with any audit committee of a subsidiary corporation, respecting the independence of such subsidiary directors and managing to ensure efficiency, effectiveness and consistency of approach with such subsidiary.

VIII. COMMITTEE TIMETABLE

The major annual activities of the Committee shall be outlined in an annual schedule.

IX. DELEGATION TO SUBCOMMITTEE

The Committee may, in its discretion, delegate all or a portion of its duties and

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