EX-99.5 6 a12-4695_1ex99d5.htm EX-99.5 ANNUAL INFORMATION FORM OF THE REGISTRANT DATED FEBRUARY 21, 2012.

Exhibit 99.5

ENBRIDGE INC.

ANNUAL INFORMATION FORM

FOR THE YEAR ENDED DECEMBER 31, 2011

February 21, 2012

TABLE OF CONTENTS

|  | Page
Glossary |  | 3
Presentation of Information |  | 5
Forward-Looking Information |  | 5
Corporate Structure |  | 6
Description of the Business |  | 8
General Development of the Business |  | 10
Liquids Pipelines |  | 14
Gas Distribution |  | 17
Gas Pipelines, Processing and Energy Services |  | 20
Sponsored Investments |  | 23
Corporate |  | 27
General |  | 28
Corporate Social Responsibility |  | 28
Environmental Matters |  | 29
Risk Factors |  | 29
Dividends |  | 29
Description of Capital Structure |  | 30
Market for Securities |  | 34
Credit Facilities |  | 35
Directors and Officers |  | 36
Audit, Finance & Risk Committee |  | 39
Legal Proceedings |  | 42
Interest of Management and Others in Material Transactions |  | 42
Registrar and Transfer Agent |  | 42
Material Contracts |  | 42
Interests of Experts |  | 42
Additional Information |  | 43
Appendix A – Audit, Finance & Risk Committee Terms of Reference |  | A-1

GLOSSARY

The following terms, when used in this Annual Information Form, have the meanings set forth below, unless otherwise indicated.

adjusted earnings/(loss) |  | Earnings or loss attributable to common shareholders adjusted for non-recurring or non-operating factors
AFR Committee |  | Audit, Finance & Risk Committee of the Company
AIF or Annual Information Form |  | Annual Information Form for the Company dated February 21, 2012
bpd |  | Barrels per day
bps |  | Basis points
bcf |  | Billion cubic feet
bcf/d |  | Billion cubic feet per day
Board of Directors or Board |  | Board of Directors of the Company
Canadian GAAP |  | Part V – Pre-changeover Accounting Standards of the Canadian Institute of Chartered Accountants Handbook
Common Shares |  | Common shares in the capital of the Company
CSR |  | Corporate Social Responsibility
CTS |  | Competitive Toll Settlement on the Enbridge mainline system
EEP |  | Enbridge Energy Partners, L.P., a NYSE listed Delaware limited partnership in which the Company has a 23.0% indirect ownership interest
EGD |  | Enbridge Gas Distribution Inc., a corporation continued under the laws of Ontario and an indirect wholly-owned subsidiary of the Company
EGNB |  | Enbridge Gas New Brunswick Inc., a corporation incorporated under the laws of Canada and an indirect wholly-owned subsidiary of the Company
Enbridge or Company |  | Enbridge Inc.
ENF |  | Enbridge Income Fund Holdings Inc., a TSX listed corporation incorporated under the laws of Alberta in which the Company has a 19.9% ownership interest
EPI |  | Enbridge Pipelines Inc., a corporation continued under the laws of Canada and an indirect wholly-owned subsidiary of the Company
FERC |  | Federal Energy Regulatory Commission
Fund |  | Enbridge Income Fund, an unincorporated open-ended trust established under the laws of Alberta in which the Company has a 35.4% combined direct and indirect ownership interest and an overall 69.2% economic interest
GHG |  | Greenhouse gases
IR |  | Incentive Regulation (applicable to EGD)
MD&A |  | Management’s Discussion and Analysis for the Company dated February 21, 2012
mmcf |  | Million cubic feet
mmcf/d |  | Million cubic feet per day
MTNs |  | Medium-term notes
MW |  | Megawatt
NEB |  | National Energy Board
NGL |  | Natural gas liquids
NYSE |  | New York Stock Exchange
OEB |  | Ontario Energy Board
Offshore |  | Enbridge Offshore Pipelines – Enbridge has interests ranging from 22% to 100% in these underwater pipelines in the Gulf of Mexico

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Preference Shares |  | Preference shares in the capital of the Company, which are issuable in series
PwC |  | PricewaterhouseCoopers LLP
ROE |  | Return on equity
SEDAR |  | The System for Electronic Document Analysis and Retrieval
Series A Preference Shares |  | 5.50% Cumulative Redeemable Preference Shares, Series A in the capital of the Company
Series B Preference Shares |  | Cumulative Redeemable Preference Shares, Series B in the capital of the Company
Series C Preference Shares |  | Cumulative Redeemable Preference Shares, Series C in the capital of the Company
Series D Preference Shares |  | Cumulative Redeemable Preference Shares, Series D in the capital of the Company
Series E Preference Shares |  | Cumulative Redeemable Preference Shares, Series E in the capital of the Company
Series F Preference Shares |  | Cumulative Redeemable Preference Shares, Series F in the capital of the Company
Series G Preference Shares |  | Cumulative Redeemable Preference Shares, Series G in the capital of the Company
TSX |  | Toronto Stock Exchange
WCSB |  | Western Canadian Sedimentary Basin
WRGGS |  | Walker Ridge Gas Gathering System
Year End |  | December 31, 2011

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PRESENTATION OF INFORMATION

Unless otherwise noted, the information contained in this Annual Information Form is given at or for the year ended December 31, 2011. Amounts are expressed in Canadian dollars unless otherwise indicated. Financial information is presented in accordance with Canadian GAAP.

Enbridge’s Management’s Discussion and Analysis, dated February 21, 2012, and Enbridge’s Audited Consolidated Financial Statements as at and for the year ended December 31, 2011 are incorporated by reference into this AIF and can be found on SEDAR at www.sedar.com.

METRIC CONVERSION TABLE

The conversion factors set out below are approximate factors. To convert from Metric to Imperial multiply by the factor indicated. To convert from Imperial to Metric divide by the factor indicated.

Metric |  | Imperial |  | Factor
Cubic metre of liquid hydrocarbons |  | Barrel of liquid hydrocarbons |  | 6.29
Cubic metre kilometre |  | Barrel mile |  | 3.91
Cubic metre of natural gas |  | Cubic feet of natural gas |  | 35.31
Kilometre |  | Mile |  | 0.62

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

FORWARD-LOOKING INFORMATION

Forward-looking information, or forward-looking statements, have been included in this AIF to provide the Company’s shareholders and potential investors with information about the Company and its subsidiaries and affiliates, including management’s assessment of Enbridge’s and its subsidiaries’ future plans and operations. This information may not be appropriate for other purposes. 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. Forward-looking information or statements included or incorporated by reference in this document include, but are not limited to, statements with respect to: expected earnings or adjusted earnings; expected earnings or adjusted earnings per share; expected costs related to projects under construction; expected in-service dates for projects under construction; expected tariffs for pipelines; expected capital expenditures; estimated future dividends; and expected costs related to leak remediation and potential insurance recoveries.

Although Enbridge believes that these forward-looking statements are reasonable based on the information available on the date such statements are made and processes used to prepare the information, 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. Material assumptions include assumptions about: the expected supply and demand for crude oil, natural gas and NGL; prices of crude oil, natural gas and NGL; expected exchange rates; inflation; interest rates; the availability and price of labour and pipeline construction materials; operational reliability; customer project approvals; maintenance of support and regulatory approvals for the Company’s projects; anticipated in-service dates; and weather. Assumptions regarding the expected supply and demand of crude oil, natural gas and NGL, and the prices of these commodities, are material to and underlie all forward-looking statements. These factors are relevant to all forward-looking statements as they may impact current and future levels of demand for the Company’s services. Similarly, exchange rates, inflation and interest rates impact the economies and business environments in which the Company operates, may impact levels of demand for the Company’s services and cost of inputs, and are therefore inherent in all forward-looking statements. Due to the interdependencies and correlation of these macroeconomic factors, the impact of any one assumption on a forward-looking statement cannot be determined with certainty, particularly with respect to expected earnings or adjusted earnings and

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associated per share amounts, or estimated future dividends. The most relevant assumptions associated with forward-looking statements on projects under construction, including estimated in-service dates, and expected capital expenditures include: the availability and price of labour and pipeline construction materials; the effects of inflation and foreign exchange rates on labour and material costs; the effects of interest rates on borrowing costs; and the impact of weather and customer and regulatory approvals on construction schedules.

Enbridge’s forward-looking statements are subject to risks and uncertainties pertaining to operating performance, regulatory parameters, project approval and support, weather, economic and competitive conditions, exchange rates, interest rates, commodity prices and supply and demand for commodities, 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’s head office and registered office are located at 3000, 425 - 1 st Street SW, Calgary, Alberta, T2P 3L8. Enbridge is a public company trading on both the Toronto and New York stock exchanges under the symbol “ENB”. Significant dates and events are set forth below.

Date | Event
April 13, 1970 | Incorporated under the Companies Ordinance of the Northwest Territories as “Gallery Holdings Ltd.”
December 15, 1987 | Continued under the Canada Business Corporations Act under the name “159569 Canada Ltd.”
April 30, 1992 | Amended Articles to (i) change the Company’s name from “159569 Canada Ltd.” to “Interprovincial Pipe Line System Inc.”, and (ii) change the Company’s authorized shares to an unlimited number of Common Shares and an unlimited number of Preference Shares
August 6, 1992 | Amended Articles to change the minimum number of directors to one and the maximum number of directors to 15.
December 18, 1992 | Amended Articles in accordance with the Plan of Arrangement effected on December 18, 1992 between the Company and EPI (formerly Interprovincial Pipe Line Inc.). Pursuant to the Plan of Arrangement, the Company, previously a wholly-owned subsidiary of EPI, became the parent of EPI.
May 5, 1994 | Amended Articles to (i) change the Company’s name from “Interprovincial Pipe Line System Inc.” to “IPL Energy Inc.”, and (ii) change the place of the registered office of the Company to Calgary, Alberta.
October 7, 1998 | Amended Articles to change the Company’s name from “IPL Energy Inc.” to “Enbridge Inc.”
November 24, 1998 | Amended Articles to designate the Series A Preference Shares.
April 29, 1999 | Amended Articles to (i) divide each then issued and outstanding Common Share on a two-for-one basis, effective May 10, 1999; and (ii) provide the Board of Directors with a process to add directors between meetings of the shareholders.
May 5, 2005 | Amended Articles to divide each then issued and outstanding Common Share on a two-for-one basis, effective May 21, 2005.
May 11, 2011 1 | Amended Articles to divide each then issued and outstanding Common Share on a two-for-one basis, effective May 26, 2011.
September 28, 2011 | Amended Articles to designate the Series B Preference Shares and the Series C Preference Shares.
November 21, 2011 | Amended Articles to designate the Series D Preference Shares and the Series E Preference Shares.
January 16, 2012 | Amended Articles to designate the Series F Preference Shares and the Series G Preference Shares.

1 The stock split completed by the Company in 2011 was effective as of the close of business on May 25, 2011. Accordingly, the division of the Company’s then issued and outstanding Common Shares on a two-for-one basis pursuant to the Articles of Amendment filed on May 11, 2011 took effect on the next business day.

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SUBSIDIARIES

The following organization chart presents the name and the jurisdiction of incorporation of Enbridge’s material subsidiaries as at December 31, 2011. The chart does not include all of the subsidiaries of Enbridge. The assets and revenues of excluded subsidiaries in the aggregate did not exceed 20% of the total consolidated assets or total consolidated revenues of Enbridge as at and for the year ended December 31, 2011. Unless otherwise indicated, the Company owns, directly or indirectly, 100% of the voting securities of all of the subsidiaries listed below.

1 The Company holds a 69.2% economic interest in the Fund, held both directly and indirectly through ENF and, as such, the Fund is consolidated under Variable Interest Entity accounting rules.

DESCRIPTION OF THE BUSINESS

Enbridge is a North American leader in delivering energy. As a transporter of energy, Enbridge operates, in Canada and the United States, the world’s longest crude oil and liquids transportation system. The Company also has significant involvement in the natural gas transmission and midstream businesses. As a distributor of energy, Enbridge owns and operates Canada’s largest natural gas distribution company and provides distribution services in Ontario, Quebec, New Brunswick and New York State. As a clean energy generator, Enbridge is expanding its interests in renewable and green energy technologies, including wind, solar and geothermal energy, as well as hybrid fuel cells. Enbridge employs approximately 6,900 people, primarily in Canada and the United States.

The Company’s activities are carried out through five business segments: Liquids Pipelines, Gas Distribution, Gas Pipelines, Processing and Energy Services, Sponsored Investments and Corporate. The following table identifies each business segment’s contribution to revenues and earnings:

| 2011 | 2010 | 2009
| Revenues | Earnings 1 | Revenues | Earnings 1 | Revenues | Earnings 1
Liquids Pipelines | 10% | 51% | 11% | 53% | 11% | 29%
Gas Distribution | 13% | 18% | 17% | 16% | 24% | 12%
Gas Pipelines, Processing and Energy Services | 75% | 29% | 70% | 13% | 62% | 27%
Sponsored Investments | 2% | 35% | 2% | 14% | 3% | 9%
Corporate | - | (33)% | - | 4% | - | 23%

1 Earnings/(loss) attributable to Enbridge Inc. common shareholders

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The following map depicts the locations of the Company’s principal operations:

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GENERAL DEVELOPMENT OF THE BUSINESS

Enbridge’s vision is to be the leading energy delivery company in North America. The Company transports, generates and distributes energy. By doing so, it delivers value to shareholders. The Company’s objective is to generate superior economic value for shareholders through securing constructing and operating energy infrastructure projects that are consistent with its investment value proposition: visible growth, a reliable business model and a growing income stream. Consistently applied, such stewardship should continue to generate attractive returns on invested capital and, in turn, provide for growing dividend distributions and capital appreciation to its shareholders.

In support of its long-term vision, the Company employs six key strategies that guide decision making across the enterprise:

· focusing on operations and system integrity;

· strengthening its core businesses;

· developing new platforms for growth and diversification;

· developing people;

· responding to environmental priorities; and

· preserving financial strength and flexibility.

In 2010, Enbridge was successful in placing almost $7 billion of new growth projects into service, including the $3.5 billion Alberta Clipper project, the largest liquids pipeline project in the Company’s history, as well as the $2.3 billion Southern Lights Pipeline. In 2011, the Company was very successful in re-stocking its growth project inventory by securing close to $8 billion in new infrastructure growth projects across many of its businesses, including Liquids Pipelines, Canadian gas midstream, Texas gathering and processing, offshore Gulf of Mexico gas processing, renewable power generation and power transmission. The Company now has approximately $13 billion in commercially secured growth projects that have or are expected to come into service between 2011 and 2015. Further, the Company has identified an additional $35 billion of potential opportunities for development over the 2011-2020 time horizon.

The following table summarizes acquisitions and commercially secured projects, within each of the Company’s business segments, which were either completed in the last three years or are currently under active development or construction.

Project |  | Description |  | Actual / Estimated Capital Cost 1 |  | Actual / Expected In-Service Date
LIQUIDS PIPELINES |  |  |  |  |  |
Spearhead Pipeline Expansion |  | Additional pumping stations increasing system capacity from Flanagan, Illinois to Cushing, Oklahoma |  | US$ | 0.1 billion |  | 2009
Line 4 Extension |  | Additional pipeline from Edmonton, Alberta to Hardisty, Alberta |  | $ | 0.3 billion |  | 2009
Hardisty Contract Terminal |  | New crude oil terminal at Hardisty, Alberta |  | $ | 0.6 billion |  | 2009
Alberta Clipper - Canadian portion |  | New pipeline from Hardisty, Alberta to the Canada/United States border |  | $ | 2.2 billion |  | 2010
Southern Lights Pipeline |  | New and reversed pipeline to transport diluent from Chicago, Illinois to Edmonton, Alberta |  | $ US$ | 0.5 billion + 1.6 billion |  | Light Sour Line - 2009; Diluent Line - 2010
Christina Lake Lateral Project 2 |  | New terminal and pipeline to deliver increased production volumes directly into the Athabasca Pipeline |  | $ | 0.2 billion |  | 2011
Edmonton Terminal Expansion 2 |  | Expansion of tankage at the mainline terminal at Edmonton, Alberta |  | $ | 0.3 billion |  | 2012
Woodland Pipeline 2 |  | New pipeline from the Kearl oil sands mine |  | $ | 0.3 billion |  | 2012

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Project |  | Description |  | Actual / Estimated Capital Cost 1 |  | Actual / Expected In-Service Date
|  | to the Cheecham Terminal |  |  |  |  |
Wood Buffalo Pipeline 2 |  | New pipeline connecting the Athabasca Terminal to the Cheecham Terminal |  | $ | 0.4 billion |  | 2012
Seaway Crude Pipeline System (including reversal and extension)2 |  | Reversal of pipeline from Freeport, Texas to Cushing, Oklahoma, as well as extension to the Port Arthur/Beaumont, Texas refining center |  | US$ | 1.5 billion |  | 2012-2013 (in phases)
Waupisoo Pipeline Capacity Expansion 2 |  | Expansion of the pipeline for additional capacity |  | $ | 0.4 billion |  | 2012-2013 (in phases)
Norealis Pipeline 2 |  | New terminal and pipeline for the Sunrise Oil Sands Project and additional tankage at Cheecham |  | $ | 0.5 billion |  | 2013
Athabasca Pipeline Capacity Expansion 2 |  | Expansion of the pipeline to its full capacity |  | $ | 0.4 billion |  | 2013-2014 (in phases)
Flanagan South Pipeline Project 2 |  | New pipeline from Flanagan, Illinois to Cushing, Oklahoma |  | US$ | 1.9 billion |  | 2014
Athabasca Pipeline Twinning 2 |  | New pipeline from Kirby Lake to Hardisty, Alberta |  | $ | 1.2 billion |  | 2015
GAS PIPELINES, PROCESSING AND ENERGY SERVICES
Shenzi Lateral |  | Natural gas lateral to connect the new deepwater Shenzi field to existing Enbridge infrastructure |  | US$ | 0.1 billion |  | 2009
Ontario Wind Project |  | 190-MW wind energy project located in Kincardine, Ontario; power produced is sold to the Ontario Power Authority |  | $ | 0.5 billion |  | 2009
Sarnia Solar Project |  | 80-MW photovoltaic, solar energy facility located in Sarnia, Ontario; power produced is sold to the Ontario Power Authority |  | $ | 0.4 billion |  | 2010
Talbot Wind Energy Project |  | 99-MW wind project located near Chatham, Ontario; power produced is sold to the Ontario Power Authority |  | $ | 0.3 billion |  | 2010
Amherstburg Solar/Tilbury Solar Projects 2 |  | 20-MW solar energy facilities located in Ontario; power produced is sold to the Ontario Power Authority |  | $ | 0.1 billion |  | 2010-2011
Cedar Point Wind Energy Project 2,3 |  | 250-MW wind project located near Denver, Colorado; power produced is sold to the Public Service Company of Colorado grid |  | US$ | 0.5 billion |  | 2011
Greenwich Wind Energy Project 2 |  | 99-MW wind energy project located near Lake Superior, Ontario; power produced is sold to the Ontario Power Authority |  | $ | 0.3 billion |  | 2011
Prairie Rose Pipeline and Palermo Conditioning Plant 2 |  | Aux Sable acquisition of condensate removal plant and pipeline that connects plant to the Alliance Pipeline |  | US$ | 0.1 billion |  | 2011
Lac Alfred Wind Project 2 |  | 300-MW wind energy project located in Quebec’s Bas-Saint-Laurent region; power produced to be sold to Hydro-Quebec |  | $ | 0.3 billion |  | 2012-2013 (in phases)
Cabin Gas Plant 2,3 |  | 71% interest in gas processing plant in Horn River Basin northeast of Fort Nelson, British Columbia |  | $ | 1.1 billion |  | 2012-2014 (in phases)
Tioga Lateral Pipeline 2 |  | Alliance Pipeline US project for new gas pipeline and associated facilities from Bakken region to the Alliance mainline near Sherwood, North Dakota |  | US$ | 0.1 billion |  | 2013
Venice Condensate Stabilization Facility 2 |  | Expansion of the condensate processing capacity to accommodate additional natural gas production |  | US$ | 0.2 billion |  | 2013
Walker Ridge Gas Gathering System 2 |  | New pipeline to provide natural gas gathering services to the proposed Jack, St. Malo and Big Foot ultra-deepwater developments |  | US$ | 0.4 billion |  | 2014

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Project |  | Description |  | Actual / Estimated Capital Cost 1 |  | Actual / Expected In-Service Date
Big Foot Oil Pipeline 2 |  | New crude oil pipeline from the proposed Big Foot ultra-deepwater development in the Gulf of Mexico |  | US$ | 0.2 billion |  | 2014
SPONSORED INVESTMENTS
EEP - Southern Access Mainline Expansion - United States portion |  | Mainline system expansion from Canada/United States border to Flanagan, Illinois |  | US$ | 2.1 billion |  | 2009
EEP - North Dakota System Expansion |  | Upgrades to existing pump stations, additional tankage as well as infrastructure to facilitate extensive use of drag reducing agents |  | US$ | 0.2 billion |  | 2010
EEP/EELP - Alberta Clipper - United States portion |  | New pipeline from the Canada/United States border to Superior, Wisconsin |  | US$ | 1.2 billion |  | 2010
The Fund - Saskatchewan System Capacity Expansion |  | Three separate projects to reduce capacity constraints at a variety of locations |  | $ | 0.1 billion |  | 2010
EEP - Bakken Expansion Program 2 |  | Joint project with the Fund to expand crude oil pipeline capacity from the Bakken and Three Forks formations |  | US$ | 0.4 billion |  | 2013
The Fund - Bakken Expansion Program 2 |  | Joint project with EEP to expand crude oil pipeline capacity from the Bakken and Three Forks formations |  | $ | 0.2 billion |  | 2013
EEP – Allison Cryogenic Processing Plant 2 |  | Project to increase processing capacity on EEP’s Anadarko System |  | US$ | 0.1 billion |  | 2011
EEP - Cushing Terminal Storage Expansion Project 2 |  | Project to construct 13 new storage tanks at EEP’s Cushing Terminal |  | US$ | 0.1 billion |  | 2011-2012 (in stages)
EEP - South Haynesville Shale Expansion 2 |  | New lateral pipelines, as well as the construction of gathering and related treating facilities |  | US$ | 0.3 billion |  | 2012+
EEP - Eastern Market Expansion 2 |  | Two projects including the expansion of EEP’s Line 5 light crude oil line between Superior, Wisconsin and Sarnia, Ontario and the reversal of a portion of Enbridge’s Line 9 in western Ontario |  | US$ | 0.1 billion |  | 2013
EEP - Ajax Cryogenic Processing Plant 2 |  | New project to increase processing capacity on EEP’s Anadarko System |  | US$ | 0.2 billion |  | 2013
EEP - Bakken Access Program 2 |  | Series of projects to complement EEP’s Bakken Expansion Program, including increasing pipeline capacities, construction of storage tanks and addition of truck access facilities |  | US$ | 0.1 billion |  | 2013
EEP - Berthold Rail Project 2 |  | Expansion of Berthold Terminal, as well as construction of a train loading facility, crude oil tankage and other terminal facilities |  | US$ | 0.1 billion |  | 2013
EEP - Texas Express Pipeline 2 |  | New project to construct a new NGL pipeline, as well as two new NGL gathering systems |  | US$ | 0.4 billion |  | 2013
EEP - Line Replacement Program 2 |  | Project to replace 120 kilometres (75 miles) of non-contiguous sections of Line 6B of EEP's Lakehead System |  | US$ | 0.3 billion |  | 2013
CORPORATE |  |  |  |  |  |  |
Noverco |  | Acquisition of an additional 6.8% interest in Noverco Inc. |  | $ | 0.1 billion |  | 2011
Montana-Alberta Tie-Line 2 |  | Transmission line from Great Falls, Montana to Lethbridge, Alberta |  | US$ | 0.3 billion |  | 2012-2013 (in stages)

1 These amounts are actual costs or current estimates that are subject to upward or downward adjustment based on various factors. As appropriate, the amounts reflect Enbridge’s share of joint venture projects.

2 The Company’s Year End MD&A includes further details on each of these projects.

3 Expenditures to date reflected total expenditures before receipt of US$0.1 billion payment from the United States Treasury.

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Over the past three years, the Company continued to focus on growth across all of its business segments, with key focus on strengthening its core businesses, including expansion of oil sands infrastructure and further development in the Bakken formation, as well as new green energy projects and opportunities in its natural gas businesses.

Within the Liquids Pipelines segment, the 10-year CTS reached with shippers in 2011 was an important first step in maintaining the competitiveness of mainline assets. The CTS provides a stable and competitive toll to shippers and preserves and enhances throughput on the Canadian mainline system for Enbridge. The CTS provides the foundation to support further extensions off the mainline system and the Company continues to pursue opportunities to provide its customers broader market access for Canadian bitumen and synthetic crude oil, including expansion initiatives to the Texas Gulf Coast. In late 2011, the Company announced it had acquired a 50% interest in the Seaway Crude Pipeline System and that it was proceeding with the Gulf Coast Access initiative, which will offer shippers access to the Gulf Coast refining complex. The Company’s efforts to expand market access and provide the highest netback for producers also include eastern market access opportunities and development of the proposed Northern Gateway pipeline, which would provide access to markets off the Pacific coast of Canada.

Regional liquids pipeline development involves projects which connect new oil sands production to existing hubs on the Canadian mainline. Enbridge, the largest pipeline operator in the oil sands region of Alberta, is currently developing close to $3.4 billion in commercially secured regional oil sands transportation facilities that are being placed into service between 2011 and 2015. The Company also has $0.8 billion of secured system expansion projects in Saskatchewan and North Dakota where the Company is strategically located to capture increased production from the Bakken play.

Within the Gas Pipelines, Processing and Energy Services segment, the Company made a significant investment in the Canadian midstream business in October 2011 and is evaluating opportunities for follow on investments. The Company acquired a 71% interest in the development of the Cabin Gas Plant (Cabin), located 60 kilometres (37 miles) northeast of Fort Nelson, British Columbia in the Horn River Basin, for approximately $1.1 billion. In 2011, a number of the Company’s renewable energy assets, including the Cedar Point Wind Energy, Greenwich Wind Energy and Amherstburg Solar projects, entered service.

In October 2011, Enbridge entered the power transmission business with the acquisition of all outstanding shares of Tonbridge Power Inc. (Tonbridge) for $20 million and assumed long-term debt of $182 million incurred by Tonbridge in the development of the Montana-Alberta Tie-Line (MATL) project. MATL is a 345-kilometre (215-mile) transmission line from Great Falls, Montana to Lethbridge, Alberta, designed to take advantage of the growing supply of electric power in Montana and the buoyant power demand in Alberta.

In 2010, the largest pipeline projects in the Company’s history, the Alberta Clipper and Southern Lights Pipeline projects, were placed into service. The Company also advanced its green energy strategy in 2010, placing into service the Sarnia Solar Project and achieving substantial completion of the Talbot Wind Energy Project. Construction also continued on the Company’s Cedar Point Wind Energy Project in Colorado, the Company’s first entrance into the United States green energy market, and the Greenwich Wind Energy Project in Ontario. In 2010, EEP grew its natural gas transportation and midstream businesses with the US$686 million acquisition of natural gas gathering and processing assets in the Granite Wash area of Texas.

Key development activities completed in 2009 included the Spearhead Pipeline Expansion, the Line 4 Extension and the Hardisty Contract Terminal, one of the largest crude oil terminals in North America, within the Liquids Pipelines segment, and the Shenzi Lateral and Ontario Wind Project within the Gas Pipelines, Processing and Energy Services segment. The Company and EEP also completed the Southern Access Mainline Expansion at a total cost of US$2.3 billion. Also in 2009, the Company sold its 24.7% interest in Oleoducto Central S.A (OCENSA), a crude oil export pipeline in Colombia.

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LIQUIDS PIPELINES

Liquids Pipelines consists of common carrier and contract crude oil, NGL and refined products pipelines and terminals in Canada and the United States, including Canadian Mainline, Regional Oil Sands System, Southern Lights Pipeline, Spearhead Pipeline, Seaway Crude Pipeline interest and other feeder pipelines.

CANADIAN MAINLINE

The mainline system is comprised of Canadian Mainline and Lakehead System (the portion of the mainline in the United States that is operated by Enbridge and owned by EEP). Enbridge has operated, and frequently expanded, the mainline system since 1949. Through six adjacent pipelines with a combined capacity of approximately 2.5 million bpd, the system transports various grades of crude oil and diluted bitumen from western Canada to the midwest region of the United States and eastern Canada. Also included within the Canadian Mainline and located in eastern Canada are two crude oil pipelines and one refined products pipeline with a combined capacity of 0.4 million bpd.

The following table sets forth the information related to deliveries and other distance-related operating data of the Canadian Mainline and Lakehead System for each of the years in the three-year period ended December 31, 2011.

(thousands of bpd) |  | 2011 | 2010 | 2009
Prairie Provinces |  |  |  |
Light crude oil |  | 322 | 227 | 173
Medium and heavy crude oil |  | 280 | 230 | 165
Refined products |  | 74 | 74 | 71
|  | 676 | 531 | 409
United States |  |  |  |
Light crude oil |  | 356 | 364 | 397
Medium and heavy crude oil |  | 849 | 840 | 834
Refined products |  | 4 | 3 | 3
|  | 1,209 | 1,207 | 1,234
Ontario 1 |  |  |  |
Light crude oil |  | 259 | 300 | 264
Medium and heavy crude oil |  | 84 | 57 | 72
Refined products |  | 70 | 73 | 75
|  | 413 | 430 | 411
Total Deliveries |  | 2,298 | 2,168 | 2,054
Barrel Miles (billions) |  | 400 | 399 | 400
Average Haul (miles) |  | 477 | 505 | 535

1 Canadian Mainline average deliveries include Line 9 (from Montreal to Ontario) volumes: 2011 - 39,000 bpd; 2010 - 77,000 bpd; 2009 - 67,000 bpd.

Competitive Toll Settlement

On June 24, 2011, the NEB approved the 10-year CTS reached between Enbridge and shippers on its mainline system. The CTS, which took effect on July 1, 2011, covers local tolls, denominated in United States dollars, to be charged for service on the mainline system (with the exception of Lines 8 and 9). Under the terms of the CTS, the initial Canadian Local Toll (CLT), applicable to deliveries within western Canada, is based on the 2011 Incentive Tolling Settlement (ITS) toll and will be subsequently adjusted by 75% of the Canada Gross Domestic Product at Market Price Index, effective July 1st, for each of the remaining nine years of the settlement. The CTS also provides for an International Joint Tariff (IJT) for crude oil shipments originating in Canada on the mainline system and delivered in the United States off the Lakehead System and into eastern Canada. The IJT, which is based on a fixed toll for the term of the settlement that was negotiated between Enbridge and shippers, will be adjusted annually by the same factor as the CLT. In other limited circumstances, the shippers or Enbridge may elect to renegotiate the toll, including a shipper option to renegotiate if TransCanada’s Keystone XL pipeline project does not receive the required United States presidential permit by January 1, 2013. If a renegotiation of the toll is triggered, Enbridge and the shippers will meet and use reasonable efforts to agree on how the CTS can

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be amended to accommodate the event. Local tolls for service on the Lakehead System will not be affected by the CTS and will continue to be established by EEP’s existing toll agreements. To the extent the sum of the CLT and the Lakehead System local toll exceeds the IJT, the CLT will be adjusted to ensure the IJT is maintained. The IJT is designed to provide mainline shippers with a stable and competitive long-term toll, preserving and enhancing throughput on both the Canadian Mainline and Lakehead System. Although the Company may utilize derivative financial instruments to hedge foreign exchange rate risk on United States dollar denominated revenues and commodity price risk resulting from exposure to variable crude oil and power prices, earnings under the CTS are subject to variability in volume throughput, as well as capital and operating costs.

With NEB approval of the CTS, shippers who initiated the Alberta Clipper hearing request with the NEB formally withdrew their complaints and the hearing proceedings were terminated on July 7, 2011.

Incentive Tolling

Prior to the CTS taking effect, tolls on Canadian Mainline were governed by various agreements which were subject to NEB approval. These agreements included both the 2011 and 2010 ITS applicable to the Canadian Mainline (excluding Lines 8 and 9), the Terrace agreement, the SEP II Risk Sharing agreement, the Alberta Clipper agreement and the Southern Access Expansion agreement which were recovered via the Mainline Expansion Toll.

REGIONAL OIL SANDS SYSTEM

Regional Oil Sands System includes two long haul pipelines, the Athabasca Pipeline and the Waupisoo Pipeline, as well as a variety of other facilities including the MacKay River, Christina Lake, Surmont and Long Lake facilities. It also includes Hardisty Caverns Limited Partnership (Hardisty Caverns), which provides storage service, and two large terminals: the Athabasca Terminal located north of Fort McMurray, Alberta and the Cheecham Terminal, located 95 kilometres (59 miles) south of Fort McMurray where the Waupisoo Pipeline initiates.

The Athabasca Pipeline is a 540-kilometre (335-mile) synthetic and heavy oil pipeline, built in 1999, that links the Athabasca oil sands in the Fort McMurray, Alberta region to a pipeline hub at Hardisty, Alberta. The Athabasca Pipeline has an ultimate design capacity of approximately 570,000 bpd, dependent on the viscosity of crude being shipped. It is currently configured to transport approximately 345,000 bpd. The Company will undertake an expansion of its Athabasca Pipeline to its full capacity to accommodate additional contractual commitments, including production from the Christina Lake Oilsands Project operated by Cenovus. This expansion is expected to increase the capacity of the Athabasca Pipeline to its maximum capacity of approximately 570,000 bpd, depending on type of crude oil. The estimated cost of full expansion is approximately $0.4 billion, with expenditures to date of approximately $0.1 billion and an expected in service date of 2013 for an initial 430,000 bpd of capacity. The balance of additional capacity is expected to be available by early 2014. The Company has a long-term (30-year) take-or-pay contract with the major shipper on the Athabasca Pipeline which commenced in 1999.

In September 2011, Enbridge announced plans to twin the southern section of its Athabasca Pipeline from Kirby Lake, Alberta to the Hardisty, Alberta crude oil hub to accommodate the need for additional capacity to serve Kirby Lake area expected oil sands growth. The expansion project, with an estimated cost of approximately $1.2 billion, will include 345 kilometres (210 miles) of 36-inch pipeline within the existing Athabasca Pipeline right-of-way. The initial annual capacity of the twin pipeline will be approximately 450,000 bpd, with expansion potential to 800,000 bpd. The line is expected to enter service in 2015.

The Waupisoo Pipeline is a 380-kilometre (236-mile) synthetic and heavy oil pipeline that entered into service on May 31, 2008 and provides access to the Edmonton market for oil sands producers. The Waupisoo Pipeline initiates at Enbridge’s Cheecham Terminal and terminates at its Edmonton Mainline Terminal. The pipeline currently has a design capacity, dependent on crude slate, of up to 350,000 bpd, which can ultimately be expanded to 600,000 bpd. The Waupisoo Pipeline Capacity Expansion, which received regulatory approval in November 2010, is expected to provide 65,000 bpd of additional capacity in the second half of 2012 and an estimated 190,000 bpd of additional capacity in the second half of 2013 when the expansion is fully in service. The project is expected to accommodate additional shipper commitments of 229,000 bpd.

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Enbridge has a long-term (25-year) take-or-pay commitment with the four founding shippers on the Waupisoo Pipeline who collectively have contracted for approximately one-third of the initial capacity on the line. The associated revenues provide for a base ROE with significant upside potential as incremental founders and third party volumes are added.

In June 2010, the Company acquired the remaining 50% of the Hardisty Caverns previously owned by CCS Corporation for $52 million. The Hardisty Caverns facility, now wholly owned by Enbridge, also includes four salt caverns totaling 3.1 million barrels of capacity. The capacity at the facility is fully subscribed under long-term contracts that generate revenues from storage and terminaling fees.

SOUTHERN LIGHTS PIPELINE

The 180,000 bpd, 20-inch diameter Southern Lights Pipeline was placed into service on July 1, 2010 transporting diluent from Chicago, Illinois to Edmonton, Alberta. Enbridge receives tariff revenues under long-term (15-year) contracts with committed shippers. Tariffs provide for recovery of all operating and debt financing costs plus a ROE of 10%. Uncommitted volumes, up to a specified amount, provide for tariff revenues that are fully credited to all shippers. Enbridge retains 25% of uncommitted tariff revenues on volumes above the specified amount, with the remainder being credited to shippers.

Both the Canadian and United States portions of the 2010, 2011 and 2012 rates for uncommitted shippers on Southern Lights Pipeline have been challenged. The Canadian Southern Lights toll hearing was held before NEB panel members in November 2011. On February 9, 2012, the NEB issued its decision rejecting the challenge from uncommitted shippers stating that tolls in place are just and reasonable. A FERC hearing was held in January 2012. Briefs will be filed February 27 and March 28, 2012 and an initial decision is expected on or before June 5, 2012.

SPEARHEAD PIPELINE

Spearhead Pipeline delivers crude oil from Chicago, Illinois to Cushing, Oklahoma. The pipeline was originally placed into service in March 2006 and the Spearhead Pipeline Expansion was completed in May 2009. The expansion increased the capacity to Cushing from 125,000 bpd to 193,300 bpd from the new initiating point at Flanagan, Illinois.

Initial committed shippers and expansion shippers currently account for more than 70% of the 193,300 bpd capacity on Spearhead. Both the initial committed shippers and expansion shippers were required to enter into 10-year shipping commitments at negotiated rates that were offered during the open season process. The balance of the capacity is currently available to uncommitted shippers on a spot basis at FERC approved rates.

FEEDER PIPELINES AND OTHER

Feeder Pipelines and Other primarily includes the Company’s 85% interest in Olympic Pipe Line Company (Olympic Pipeline), the largest refined products pipeline in the State of Washington, transporting approximately 290,000 bpd of gasoline, diesel and jet fuel. It also includes the NW System, which transports crude oil from Norman Wells in the Northwest Territories (NWT) to Zama, Alberta; interests in a number of liquids pipelines in the United States; contract tankage facilities, including the Hardisty Contract Terminal, which is comprised of 19 tanks with a working capacity of approximately 7.5 million barrels of storage; and business development costs related to Liquids Pipelines activities.

Norman Wells Pipeline Crude Oil Release

The Norman Wells Pipeline is a 12-inch, 39,400 bpd line transporting sweet crude oil that stretches 869 kilometres (540 miles) from Norman Wells, NWT to Zama, Alberta. On May 9, 2011, Enbridge reported a crude oil release from the Norman Wells Pipeline approximately 50 kilometres (31 miles) south of the community of Wrigley, NWT. On May 20, 2011, Enbridge returned the Norman Wells line to service after completing necessary repairs. Excavation of all contaminated soils from the spill site was completed in late November 2011. Based on the volume of contaminated materials removed from the site, the current estimate of volume released is approximately 1,600 barrels. Site reclamation work is anticipated to be completed in the summer of 2012. Monitoring of surface water and groundwater at the site will continue until remediation and reclamation goals have been achieved in accordance with plans filed with the regulator.

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COMPETITIVE CONDITIONS

Competition among existing pipelines is based primarily on the cost of transportation, access to supply, the quality and reliability of service, contract carrier alternatives and proximity to markets. Other competing carriers are available to ship western Canadian liquids hydrocarbons to markets in either Canada or the United States. Competition also arises from new pipeline proposals that provide access to market areas currently served by the Company’s liquids pipelines. One such competing project began commercial operations in early 2010 and serves markets at Wood River, Illinois and Cushing, Oklahoma. This pipeline has an initial capacity of 435,000 bpd and an ultimate stated capacity of 591,000 bpd. Commercial support has also been announced for the construction of additional ex-Alberta capacity of 500,000 bpd to Nederland, Texas, with an in-service date during 2015. Competing alternatives for delivering western Canadian liquid hydrocarbons into the United States or other markets could erode shipper support for current or future expansion. However, the Company believes that its liquids pipelines provide attractive options to producers in the WCSB due to its competitive tolls and multiple delivery and storage points. Increased competition could arise from new feeder systems servicing the same geographic regions as the Company’s feeder pipelines.

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GAS DISTRIBUTION

Gas Distribution consists of the Company’s natural gas utility operations, the core of which is EGD which serves residential, commercial and industrial customers, primarily in central and eastern Ontario as well as northern New York State. This business segment also includes natural gas distribution activities in Quebec and New Brunswick.

ENBRIDGE GAS DISTRIBUTION

EGD is Canada’s largest natural gas distribution company and has been in operation for more than 160 years. It serves approximately 2 million customers in central and eastern Ontario and parts of northern New York State. EGD’s utility operations are regulated by the OEB and by the New York State Public Service Commission.

EGD is subject to seasonal demand as a significant portion of gas distribution customers use natural gas for space heating. As a result, volumes delivered and resulting revenues and earnings typically increase during the winter months of the first and fourth quarters of any given year. Revenues generated by EGD also vary from quarter-to-quarter with fluctuations in the price of natural gas, although earnings remain neutral due to the pass through nature of these costs. Further, as a result of continued changes in customer billing to increase the fixed charge portion and decrease the per unit volumetric charge, revenues and earnings will shift from the colder winter quarters progressively to the warmer summer quarters, with no material impact on full year revenue and earnings. This change will also have an impact upon the comparability of a given quarter from year to year.

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

Distribution Service

EGD’s principal source of revenue arises from distribution of natural gas to customers. The services provided to residential, 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.

Gas Supply

To acquire the necessary volume of gas to serve its customers, EGD maintains a diversified gas supply portfolio. During the year ended December 31, 2011, EGD acquired approximately 222 bcf (2010 – 208; 2009 – 194) of natural gas, of which 44% (2010 – 37%; 2009 – 26%) was acquired from Western Canadian producers, 28% (2010 – 42%; 2009 – 46%) was acquired from suppliers in Chicago and 28% (2010 – 22%; 2009 – 29%) was acquired on a delivered basis in Ontario.

Transportation

TransCanada Pipelines Ltd. (TransCanada) transports approximately 63% or 268 bcf of the annual natural gas supply requirements of the Company’s customers. EGD has firm transportation service contracts with TransCanada for a portion of this requirement.

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

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 natural gas from its supply basins, assists in reducing its overall cost of natural gas supply and adds a measure of security in the event of any short-term interruption of transportation of natural gas to EGD’s franchise area.

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EGD’s principal storage facilities are located in southwestern Ontario, near Dawn, and have a total working capacity of approximately 110 bcf.

Historical Operating Statistics

The following tables present certain statistics relating to the past three years of operations of EGD:

|  | 2011 |  | 2010 |  | 2009 |
Gas supply and send out (mmcf) |  |  |  |  |  |  |
Natural gas purchased |  | 223,385 |  | 206,511 |  | 195,268 |
Gas into storage |  | (84,899 | ) | (101,279 | ) | (75,001 | )
Gas out of storage |  | 83,628 |  | 90,512 |  | 79,536 |
Total gas sendout |  | 222,114 |  | 195,744 |  | 199,803 |
Transportation of gas |  | 203,051 |  | 214,736 |  | 223,503 |
|  | 425,165 |  | 410,480 |  | 423,306 |
Gas sales to customers (mmcf) |  | 220,878 |  | 195,921 |  | 194,679 |
Transportation of gas |  | 189,566 |  | 197,121 |  | 213,117 |
Total sales |  | 410,444 |  | 393,042 |  | 407,796 |
Used by EGD |  | 141 |  | 212 |  | 205 |
Other volumetric variations |  | 14,579 |  | 17,226 |  | 15,305 |
|  | 425,164 |  | 410,480 |  | 423,306 |
Average daily sendout (mmcf) |  | 1,165 |  | 1,130 |  | 1,158 |
Average use per residential customer (thousand cubic feet) |  | 91 |  | 89 |  | 96 |
Heating degree days 1 |  |  |  |  |  |  |
Actual |  | 3,597 |  | 3,466 |  | 3,767 |
Forecast based on normal weather |  | 3,602 |  | 3,546 |  | 3,514 |
Number of active customers at year end 2 |  |  |  |  |  |  |
Residential |  | 1,508,381 |  | 1,329,439 |  | 1,215,998 |
Commercial |  | 120,397 |  | 110,846 |  | 106,298 |
Industrial |  | 4,676 |  | 4,292 |  | 4,072 |
Wholesale |  | 1 |  | 1 |  | 1 |
Transportation |  | 364,027 |  | 518,689 |  | 598,704 |
|  | 1,997,482 |  | 1,963,267 |  | 1,925,073 |
New customer additions 3 |  | 35,862 |  | 37,023 |  | 32,275 |

1 Heating degree days is a measure of coldness that is indicative of volumetric requirements for natural gas utilized for heating purposes in EGD’s distribution franchise area. It is calculated by accumulating, for the fiscal year, 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 Number of active customers is the number of natural gas consuming customers at the end of the year and includes gas sales and transportation service customers. As the commodity cost of gas is flowed through to natural gas sales customers with no mark up, the composition of customers between natural gas sales and transportation service has no material impact on EGD’s earnings.

3 New customer additions is the number of new service lines installed during the year.

Incentive Regulation

In 2007, the Company filed a rate application with the OEB requesting a revenue cap incentive rate mechanism calculated on a revenue per customer basis for the 2008 to 2012 period. The OEB approved the IR Settlement Agreement (the Settlement) with customer representatives.

The objectives of the Settlement are as follows:

· reduce regulatory costs;

· provide incentives for improved efficiency;

· provide more flexibility for utility management; and

· provide more stable rates to its customers.

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Under the Settlement, EGD is allowed to earn and fully retain 100 basis points (bps) over the base return. Any return over 100 bps must be shared with customers on an equal basis. EGD estimates the customer portion of 2011 earnings over the allowed threshold to be $14 million (2010 - $19 million). In preparation for the conclusion of the current IR term at the end of 2012, EGD filed a 2013 cost of service application, which they expect will be addressed by the OEB in 2012.

Rate Adjustment Applications

In September of each year, EGD files an application with the OEB to adjust rates for the next calendar year. Each of the 2012, 2011 and 2010 rate applications were filed pursuant to the approved IR formula. Out of the total distribution revenue applied for in the 2012 rate application, 98% was approved for recovery with the rate adjustment being effective January 1, 2012. The hearing with respect to the remaining 2% and related issues was held by the OEB in January 2012 with a decision expected in April 2012.

The total distribution revenue applied for in the 2011 rate application was approved by the OEB and the rate adjustment was effective January 1, 2011. In September 2009, EGD filed an application with the OEB to adjust rates for 2010 pursuant to the approved IR formula and to seek approval for specific changes to the Rate Handbook. Subsequent to filing a settlement agreement with ratepayer groups with the OEB, in March 2010, EGD received approval of a fiscal 2010 final rate order from the OEB. The 2010 final rate order approved the implementation of a rate change effective April 1, 2010, which enabled EGD to recover the approved revenues as if rates were effective January 1, 2010.

OTHER GAS DISTRIBUTION AND STORAGE

Other Gas Distribution includes natural gas distribution utility operations in Quebec and New Brunswick, the most significant being EGNB, which owns the natural gas distribution franchise in the province of New Brunswick. EGNB is constructing a new distribution system and has approximately 11,000 customers. Approximately 790 kilometres (490 miles) of distribution main has been installed with the capability of attaching approximately 30,000 customers.

EGNB is regulated by the New Brunswick Energy and Utilities Board (EUB). As it is currently in the development period, EGNB’s cost of service exceeds its distribution revenues. The EUB had previously approved the deferral of the shortfall between distribution revenues and the cost of service during the development period for recovery in future rates. The recovery period is expected to commence at the end of the development period in 2013 and end no sooner than 2040.

On December 9, 2011, the Government of New Brunswick tabled and subsequently passed legislation related to the regulatory process for setting rates for gas distribution within the province. The legislation permits the government to implement new regulations which could affect the franchise agreement between EGNB and the province, impact prior decisions by the province’s independent regulator and influence the regulator’s future decisions. Significant details of the rate setting process were left to be established in the new regulations which have yet to be published. As the details of the regulations have not yet been made available, the effect of such regulations is not determinable as at the date of this AIF. While EGNB continues to engage in discussions with the Province about the potential effect of the regulations, EGNB will preserve its legal rights.

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GAS PIPELINES, PROCESSING AND ENERGY SERVICES

Gas Pipelines, Processing and Energy Services consists of investments in natural gas pipelines and processing facilities, green energy projects, Canadian midstream businesses, the Company’s energy services businesses and international activities.

Investments in natural gas pipelines include the Company’s interests in the United States portion of Alliance Pipeline (Alliance Pipeline US), the Vector Pipeline and transmission and gathering pipelines in the Gulf of Mexico. Investments in natural gas processing include the Company’s interest in Aux Sable, a natural gas fractionation and extraction business and an interest in the development of Cabin Gas Plant in northeastern British Columbia, and processing facilities connected to the Gulf of Mexico system. The energy services businesses manage the Company’s volume commitments on Alliance and Vector Pipelines, as well as perform natural gas, NGL and crude oil storage, transport and supply management services, as principal and agent.

ENBRIDGE OFFSHORE PIPELINE

Offshore is comprised of 13 natural gas gathering and FERC-regulated transmission pipelines and one oil pipeline with a capacity of 60,000 bpd, in five major corridors in the Gulf of Mexico, extending to deepwater developments. These pipelines include almost 2,400 kilometres (1,500 miles) of underwater pipe and onshore facilities with total capacity of approximately 7.2 bcf/d. Offshore currently moves approximately 40% of offshore deepwater gas production through its systems in the Gulf of Mexico.

Transportation Contracts

The primary shippers on the Offshore systems are producers who execute life-of-lease commitments in connection with transmission and gathering service contracts. In exchange, Offshore provides firm capacity for the contract term at an agreed upon rate. The firm capacity made available 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, subject to advance notice criteria, to modify the projected MDQ schedule to match current delivery expectations. The majority of long-term transport rates are market-based, with revenue generation directly tied to actual production deliveries. Some of the systems operate under a cost-of-service methodology while others have minimum take-or-pay obligations.

The business model utilized on a go forward basis and included in the WRGGS, Big Foot and Venice commercially secured projects differs from the historic model. These new projects have a base level return which is locked in through take or pay commitments. If volumes reach producer anticipated levels the return on these projects will increase. In addition, Enbridge has minimal capital cost risk on these projects and commercial agreements continue to contain life-of-lease commitments. The WRGGS and Big Foot project agreements provide for recovery of actual capital costs to complete the project in fees payable by producers over the contract term. The Venice project provides for a capital cost risk sharing mechanism, whereby Enbridge is exposed to a portion of the capital costs in excess of an agreed upon target. Conversely, Enbridge can recover in fees from producers a portion of the capital cost savings below the agreed upon target.

Competitive Conditions

There is competition for new and existing business in the Gulf of Mexico. Offshore has been able to capture key opportunities, allowing it to more fully utilize existing capacity. Offshore’s gas pipelines serve a majority of the strategically located deepwater host platforms, positioning it favourably to make incremental investments for new platform connections and receive additional transportation volumes from sub-sea development of smaller fields tied back to existing host platforms. Offshore is also able to construct pipelines to transport crude oil, diversifying the risk of declining gas production, as demonstrated with the Neptune crude oil lateral and the planned Big Foot. Given rates of decline, offshore pipelines typically have available capacity, resulting in significant competition for new developments in the Gulf of Mexico.

ALLIANCE PIPELINE US

The Alliance System (Alliance), which includes both the Canadian and United States portions of the

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pipeline system, consists of an approximately 3,000-kilometre (1,864-mile) integrated, high-pressure natural gas transmission pipeline system and an approximately 730-kilometre (454-mile) lateral pipeline system and related infrastructure. Alliance transports liquids-rich natural gas from northeast British Columbia, northwest Alberta and the Bakken area in North Dakota to Channahon, Illinois. Alliance Pipeline US and Alliance Pipeline Canada have firm service shipping contract capacity to deliver 1.405 bcf/d and 1.325 bcf/d, respectively. Enbridge owns 50% of Alliance Pipeline US, while the Fund, described under Sponsored Investments, owns 50% of Alliance Pipeline Canada.

Alliance connects with Aux Sable, (of which Enbridge owns 42.7%), an NGL extraction and fractionation facility in Channahon, Illinois. The natural gas may then be transported to two local natural gas distribution systems in the Chicago area and five interstate natural gas pipelines, providing shippers with access to natural gas markets in the midwestern and northeastern United States and eastern Canada.

Alliance Pipeline US is adjacent to the Bakken oil formation in North Dakota which offers new incremental sources of liquids-rich natural gas for delivery to downstream markets. In February 2010, a new receipt point on the pipeline near Towner, North Dakota was placed into service. The receipt point connects to the Prairie Rose Pipeline, which initially provided access to a shipper operating out of the Bakken formation with firm transportation contract for an initial contract capacity of 40 mmcf/d under a 10-year contract. An additional 40 mmcf/d of firm transportation capacity at this same receipt point became effective February 2011. The Prairie Rose Pipeline was acquired by Aux Sable in 2011.

Transportation Contracts

Alliance Pipeline US has long-term, take-or-pay contracts to transport substantially all its 1.405 bcf/d of natural gas capacity with terms ending on December 1, 2015. A small percentage of natural gas is being contracted on a short-term basis with an annual renewal option. These contracts permit Alliance Pipeline US, whose operations are regulated by the FERC, to recover the cost of service, which includes operating and maintenance costs, the cost of financing, an allowance for income tax, an annual allowance for depreciation and an allowed ROE of 10.88%.

Competitive Conditions

Alliance Pipeline US faces competition for pipeline transportation services to the Chicago area from both existing and proposed pipeline projects. Competing pipelines provide natural gas transportation services from the WCSB and the Bakken to natural gas markets in the midwestern United States. In addition, there are several proposals to upgrade existing pipelines or to build new pipelines serving these markets. Any new or upgraded pipelines could either allow shippers greater access to natural gas markets or offer natural gas transportation services that are more desirable than those provided by Alliance Pipeline US because of location, facilities or other factors. In addition, these pipelines could charge rates or provide transportation services to locations that result in greater net profit for shippers, with the effect of forcing Alliance Pipeline US to realize lower revenues and cash flows. Shippers on Alliance Pipeline US have access to additional high compression delivery capacity at no additional cost, other than fuel requirements, serving to enhance the competitive position of Alliance Pipeline US.

VECTOR PIPELINE

The Vector Pipeline (Vector) system, which includes both the Canadian and United States portions of the pipeline system, consists of 560 kilometres (348 miles) of mainline natural gas transmission pipeline between the Chicago, Illinois hub and the storage complex at Dawn, Ontario. Vector’s primary sources of supply are through interconnections with Alliance and the Northern Border Pipeline in Joliet, Illinois. Vector has the capacity to deliver a nominal 1.3 bcf/d and is operating at or near capacity. The Company provides operating services to and holds a 60% joint venture interest in Vector.

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Transportation Contracts

The total long haul capacity of Vector is approximately 87% committed through 2015. Approximately 55% of the long haul capacity is committed through firm transportation contracts at rates negotiated with the shippers and approved by the FERC, while the remaining committed capacity is sold at market rates. Transportation service is provided through a number of different forms of service agreements such as Firm Transportation Service and Interruptible Transportation Service. Vector is an interstate natural gas pipeline with FERC and NEB approved tariffs that establish the rates, terms and conditions governing its service to customers. On the United States portion of Vector, tariff rates are determined using a cost of service methodology and tariff changes may only be implemented upon approval by the FERC. For 2011, the FERC approved maximum tariff rates include an underlying weighted average after-tax ROE component of 11.18% (2010 - 11.18 %; 2009 - 11.07 %). On the Canadian portion, Vector is required to file its negotiated tolls calculation with the NEB on an annual basis. Tolls are calculated on a levelized basis that include a rate of return incentive mechanism based on construction costs and are subject to a rate cap. In 2011, maximum tariff tolls include a ROE component of 10.48% after-tax.

Competitive Conditions

Vector faces competition for pipeline transportation services to its delivery points from new supply sources and traditional low cost pipelines, which could offer transportation that is more desirable to shippers because of cost, supply location, facilities or other factors. Vector has mitigated this risk by entering into long-term firm transportation contracts, which expire starting in November 2015, for approximately 87% of its capacity. The remaining contracts expire at various times starting in April 2012. Certain long-term firm contracts (55% of capacity) provide for additional compensation to Vector if shippers do not extend their contracts beyond the initial term ending November 2015. The effectiveness of these mitigating factors is evidenced by the increased utilization of the pipeline since its construction, despite the presence of transportation alternatives.

Vector and Alliance pipelines also face potential competition from new sources of natural gas such as the Marcellus shale formation, which is among the largest gas play in North America. The Marcellus shale formation is in close proximity to the Chicago Hub. The development of the Marcellus shale formation could provide an alternate source of gas to the Chicago Hub as well as decrease the northeastern region of the United States’ reliance on natural gas imports from Canada.

AUX SABLE

Enbridge owns 42.7% of Aux Sable, an NGL extraction and fractionation business, which owns and operates a plant near Chicago, Illinois at the terminus of Alliance. The plant extracts NGL from the liquids-rich natural gas transported on Alliance, as necessary to meet gas quality specifications of downstream transmission and distribution companies and to take advantage of positive fractionation spreads.

Aux Sable sells its NGLs production to BP under a long-term contract. BP pays Aux Sable a fixed annual fee and a share of any net margin generated from the business in excess of specified natural gas processing margin thresholds (the upside sharing mechanism). In addition, BP compensates Aux Sable for all operating, maintenance and capital costs associated with the Aux Sable facilities subject to certain limits on capital costs. BP supplies, at its cost, all make-up gas and fuel gas requirements of the Aux Sable plant and pays market rates for the capacity on the Alliance Pipeline held by an Aux Sable affiliate. The BP agreement is for an initial term of 20 years, expiring March 31, 2026, and may be extended by mutual agreement for 10-year terms.

Aux Sable also owns and operates facilities upstream of the Alliance Pipeline that deliver liquids-rich gas volumes into the pipeline for further processing at the Aux Sable plant. These facilities include the Prairie Rose Pipeline and the Palermo Conditioning Plant in the Bakken area of North Dakota and the Septimus Gas Plant and the Septimus Pipeline in the Montney area of British Columbia.

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ENERGY SERVICES

Energy Services provides energy supply and marketing services to North American refiners, producers and other customers. Crude oil and NGL marketing services are provided by Tidal Energy. This business transacts at many North American market hubs and provides its customers with various services, including transportation, storage, supply management, flexible pricing, hedging programs and product exchanges. Tidal Energy is primarily a physical barrel marketing company and in the course of its market activities can create commodity exposures. Any residual open positions created from this physical business are closely monitored and must comply with the Company’s formal risk management policies.

Natural gas marketing services are provided by Tidal Energy and Gas Services. Tidal Energy markets natural gas to optimize Enbridge’s commitments on the Alliance and Vector pipelines. Capacity commitments at December 31, 2011 and 2010 were 30 mmcf/d on Alliance and 156 mmcf/d on Vector. Earnings from these commitments are dependent upon the basis (location) differentials between Alberta and Chicago, Illinois for Alliance, and between Chicago and Dawn, Ontario for Vector. To the extent transportation costs exceed the basis (location) differential, earnings will be negatively affected. Tidal Energy also provides fee-for-service arrangements for third parties, leveraging its natural gas marketing expertise and access to transportation capacity. Gas Services markets natural gas to commercial and industrial customers in the upper mid-west area of the United States.

OTHER

Other includes operating results from the Company’s investments in green energy projects, net of business development expenses associated with international and Canadian gas activities.

In October 2011, ownership of the Sarnia Solar, Ontario Wind and Talbot Wind energy projects was transferred to the Fund. Effective October 21, 2011, earnings contributions from these assets, net of noncontrolling interest, will be reflected within the Sponsored Investments segment. Green energy projects remaining in the Gas Pipelines, Processing and Energy Services segment include Greenwich Wind Energy, Cedar Point Wind Energy, Lac Alfred Wind, Amherstburg Solar and Tilbury Solar.

In 2009, the Company sold its 24.7% interest in OCENSA, a crude oil export pipeline in Colombia. This investment was sold at a very attractive price and proceeds were utilized in the funding of the North American expansion projects discussed earlier. There are currently minimal operations in International; however, Enbridge continues to actively monitor the international business environment to identify potential new investment opportunities.

SPONSORED INVESTMENTS

Sponsored Investments includes the Company’s 23.0% ownership interest in EEP, Enbridge’s 66.7% investment in the United States segment of the Alberta Clipper Project through EEP and Enbridge Energy, Limited Partnership (EELP) and an overall 69.2% economic interest in the Fund, held both directly, and indirectly through ENF. Enbridge manages the day-to-day operations of, and develops and assesses opportunities for each of these investments, including both organic growth and acquisition opportunities.

EEP transports crude oil and other liquid hydrocarbons through common carrier and feeder pipelines and transports, gathers, processes and markets natural gas and NGL. The primary operations of the Fund include a crude oil and liquids pipeline and gathering system, a 50% interest in the Canadian portion of Alliance Pipeline (Alliance Pipeline Canada) and interests in renewable power generation projects.

ENBRIDGE ENERGY PARTNERS

EEP owns and operates crude oil and liquid petroleum transportation and storage assets and natural gas and NGL gathering, treating, processing, transportation and marketing assets in the United States. Significant assets include the Lakehead System, which is the extension of the Canadian Mainline in the United States, the Mid-Continent crude oil system consisting of an interstate crude oil pipeline and storage facilities, a crude oil gathering system and interstate pipeline system in North Dakota and natural gas assets located primarily in Texas. Subsidiaries of Enbridge provide services to EEP in connection with the operation of its liquids assets, including the Lakehead System.

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In September 2010, EEP acquired the entities that comprise the Elk City System from Atlas Pipeline Partners for US$686 million. The Elk City System extends from southwestern Oklahoma to Hemphill County in the Texas Panhandle and consists of approximately 1,290 kilometres (800 miles) of natural gas gathering and transportation pipelines, one carbon dioxide treating plant and three cryogenic processing plants with a total capacity of 370 mmcf/d and a combined NGLs production capability of 20,000 bpd. The acquisition of the Elk City System complements EEP’s existing Anadarko natural gas system by providing additional processing capacity and expansion capability.

Enbridge’s ownership interest in EEP is impacted by EEP’s issuance and sale of its Class A common units. To the extent Enbridge does not fully participate in these offerings, the Company’s ownership interest in EEP is reduced. At December 31, 2011, Enbridge’s ownership interest in EEP was 23.0% (2010 - 25.5%; 2009 - 27.0%). The Company’s average ownership interest in EEP during 2011 was 24.4% (2010 - 26.7%; 2009 - 27.0%).

EEP Lakehead System Line 6B and 6A Crude Oil Releases

Line 6B Crude Oil Release

On July 26, 2010, a release of crude oil on Line 6B of EEP’s Lakehead System was reported near Marshall, Michigan. EEP estimates that approximately 20,000 barrels of crude oil were leaked at the site, a portion of which reached the Talmadge Creek, a waterway that feeds the Kalamazoo River. The pipelines in the vicinity were shut down, appropriate United States federal, state and local officials were notified and emergency response crews were dispatched to oversee containment of the released crude oil and cleanup of the affected areas. The released crude oil affected approximately 61 kilometres (38 miles) of area along the Talmadge Creek and Kalamazoo River waterways, including residential areas, businesses, farmland and marshland between Marshall and downstream of Battle Creek, Michigan. The cause of the release remains the subject of an investigation by the National Transportation Safety Board and other United States federal and state regulatory agencies.

Pursuant to an administrative order issued by the Environmental Protection Agency (EPA) under the United States Clean Water Act, EEP was directed to clean up the released oil and remediate and restore the affected areas – a process EEP had begun upon discovering the release.

As at December 31, 2010, EEP estimated that before insurance recoveries, and not including fines and penalties, costs of approximately US$550 million ($96 million after-tax net to Enbridge), excluding lost revenue of approximately US$13 million ($2 million after-tax net to Enbridge), would be incurred in connection with this incident. These costs included emergency response, environmental remediation and cleanup activities associated with the crude oil release, as well as potential claims by third parties.

As at December 31, 2011, EEP revised its total estimate for this crude oil release to US$765 million ($129 million after-tax net to Enbridge), an increase of US$215 million ($33 million after-tax net to Enbridge) from December 31, 2010. The change in estimate was primarily based on a review of costs and commitments incurred, and additional information concerning the reassessment of the overall monitoring area, related cleanup, including submerged oil recovery operations, and remediation activities, including the estimated costs related to the additional scope of work set forth in its response to the directive it submitted to the EPA on October 20, 2011. During the fourth quarter of 2011, EEP resubmitted a revised work plan which was approved by the EPA on December 19, 2011.

EEP continues to make progress on the cleanup, remediation and restoration of the areas affected by the Line 6B crude oil release. All of the initiatives EEP undertakes in the monitoring and restoration phases are intended to restore the crude oil release area to the satisfaction of the appropriate regulatory authorities.

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Expected losses associated with the Line 6B crude oil release include those costs that are considered probable and that could be reasonably estimated at December 31, 2011. The estimates do not include amounts capitalized or any fines, penalties or claims associated with the release that may later become evident and are before insurance recoveries. Despite the efforts EEP has made to ensure the reasonableness of its estimates, changes to the recorded amounts associated with this release are possible as more reliable information becomes available. There continues to be the potential for EEP to incur additional costs in connection with this crude oil release due to variations in any or all of the cost categories, including modified or revised requirements from regulatory agencies, in addition to fines and penalties as well as expenditures associated with litigation and settlement of claims.

Line 6A Crude Oil Release

A crude oil release from Line 6A of EEP’s Lakehead System was reported in an industrial area of Romeoville, Illinois on September 9, 2010. The pipeline in the vicinity was immediately shut down and emergency response crews were dispatched to oversee containment, cleanup and replacement of the pipeline segment. EEP estimated approximately 9,000 barrels of crude oil were released, of which approximately 1,400 barrels were removed from the pipeline as part of the repair. Excavation and replacement of the pipeline segment were completed and the pipeline was returned to service on September 17, 2010. The cause of the crude oil release remains subject to investigation by United States federal and state environmental and pipeline safety regulators.

EEP continues to monitor the areas affected by the crude oil release from Line 6A of its Lakehead System for any additional requirements; however, the cleanup, remediation and restoration of the areas affected by the release have been substantially completed.

As at December 31, 2010, EEP estimated that before insurance recoveries, and not including fines and penalties, costs for emergency response, environmental remediation and cleanup activities associated with the Line 6A crude oil release would be approximately US$45 million ($7 million after-tax net to Enbridge), excluding lost revenue of approximately US$3 million ($1 million after-tax net to Enbridge).

As at December 31, 2011, EEP revised its cost estimate for this crude oil release to US$48 million ($7 million after-tax net to Enbridge), before insurance recoveries and excluding fines and penalties. The US$3 million increase was based on a refinement of future costs based on additional information.

EEP included those costs it considered probable and that it could reasonably estimate for purposes of determining its expected losses associated with the Line 6A crude oil release. The estimates do not include consideration of any unasserted claims associated with the release that later may become evident, nor has EEP considered any potential recoveries from third-parties that may later be determined to have contributed to the release. EEP is pursuing recovery of the costs associated with the Line 6A crude oil release from third parties; however, there can be no assurance that any such recovery will be obtained.

Insurance Recoveries

EEP is included in the comprehensive insurance program that is maintained by Enbridge for its subsidiaries and affiliates which renews in May of each year. The program includes commercial liability insurance coverage that is consistent with coverage considered customary for its industry and includes coverage for environmental incidents such as those incurred for the crude oil releases from Lines 6A and 6B, excluding costs for fines and penalties. The claims for the crude oil release for Line 6B are covered by Enbridge’s comprehensive insurance policy that expired on April 30, 2011, which had an aggregate limit of US$650 million for pollution liability. Based on EEP’s increased estimate of costs associated with the crude oil releases, Enbridge and its affiliates will exceed the limits of its coverage under this insurance policy. Additionally, fines and penalties would not be covered under the existing insurance policy.

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EEP recognized US$335 million ($50 million after-tax net to Enbridge) in insurance recoveries for the year ended December 31, 2011 for insurance claims filed in connection with the Line 6B crude oil release. EEP expects to record a receivable for additional amounts claimed for recovery pursuant to insurance policies during the period it deems realization of the claim for recovery is probable.

During the second quarter of 2011, the Company renewed its comprehensive insurance program. The current coverage year has an aggregate limit of US$575 million for pollution liability for the period from May 1, 2011 through April 30, 2012.

Line 6B Pipeline Integrity Plan

In connection with the restart of Line 6B, EEP committed to accelerate a process initiated prior to the crude oil release to perform additional inspections, testing and refurbishment of Line 6B within and beyond the immediate area of the July 26, 2010 crude oil release. Pursuant to this agreement with the United States Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (PHMSA), EEP completed remediation of those pipeline anomalies it identified between 2007 and 2009 that were scheduled for refurbishment, and anomalies identified for action in a July 2010 PHMSA notification, on schedule within 180 days of the September 27, 2010 restart of Line 6B, as required. In addition to the required integrity measures, EEP also agreed to replace a 3,600 foot section of the Line 6B pipeline that lies underneath the St. Clair River in Michigan within one year of the restart of Line 6B, subject to obtaining required permits. A new line was installed beneath the St. Clair River in March 2011 and was tied into Line 6B during June 2011.

In February 2011, EEP filed a tariff supplement with the FERC, which became effective on April 1, 2011, for recovery of US$175 million of capital costs and US$5 million of operating costs for the 2010 and 2011 Line 6B Pipeline Integrity Plan. The costs associated with the Line 6B Pipeline Integrity Plan, which include an equity return component, interest expense and an allowance for income taxes will be recovered over a 30-year period, while operating costs will be recovered through EEP’s annual tolls for actual costs incurred. These costs include costs associated with the PHMSA Corrective Action Order and other required integrity work.

Legal and Regulatory Proceedings

A number of United States governmental agencies and regulators have initiated investigations into the Line 6A and Line 6B crude oil releases. Approximately 25 actions or claims have been filed against Enbridge, EEP or their affiliates in United States federal and state courts in connection with the Line 6B crude oil release, including direct actions and actions seeking class status. With respect to the Line 6B crude oil release, no penalties or fines have been assessed against Enbridge, EEP or their affiliates as at December 31, 2011. One claim related to the Line 6A crude oil release has been filed against Enbridge, EEP or their affiliates by the State of Illinois in a United States state court. The parties are currently operating under an agreed interim order.

Competitive Conditions

EEP’s Lakehead System, the United States portion of the Liquids Pipelines mainline, is a major crude oil export conduit from the WCSB. Other existing competing carriers and pipeline proposals to ship western Canadian liquids hydrocarbons to markets in the United States represent competition for the Lakehead System. Further details on such competing projects are described within Business Risks under Liquids Pipelines. EEP’s Mid-Continent and North Dakota systems also face competition from existing competing pipelines, proposed future pipelines and alternative gathering facilities (being predominately rail), available to producers or the ability of the producers to build such gathering facilities. Competition for EEP’s storage facilities includes large integrated oil companies and other midstream energy partnerships.

Other interstate and intrastate natural gas pipelines (or their affiliates) and other midstream businesses that gather, treat, process and market natural gas or NGL represent competition to EEP’s natural gas segment. The level of competition varies depending on the location of the gathering, treating and processing facilities. However, most natural gas producers and owners have alternate gathering, treating and processing facilities available to them, including those owned by competitors that are substantially larger than EEP.

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EEP’s marketing segment has numerous competitors, including large natural gas marketing companies, marketing affiliates of pipelines, major oil and natural gas producers, independent aggregators and regional marketing companies.

ENBRIDGE ENERGY, LIMITED PARTNERSHIP – ALBERTA CLIPPER US

In July 2009, the Company committed to fund 66.7% of the cost to construct the United States segment of the Alberta Clipper Project. The Company funded 66.7% of the project’s equity requirements through EELP, while 66.7% of the debt funding was made through EEP. EELP - Alberta Clipper US earnings are the Company’s earnings from its investment in EELP which undertook the project. The Alberta Clipper Project was placed into service on April 1, 2010.

ENBRIDGE INCOME FUND

The Fund is involved in the generation and transportation of energy through its 50% interest in Alliance Pipeline Canada, its crude oil and liquids pipelines business in Saskatchewan (the Saskatchewan System) and interests in more than 400 MW of renewable power generation capacity. The Saskatchewan System operates a crude oil gathering system and trunkline pipeline in southern Saskatchewan and southwestern Manitoba, connecting to Enbridge’s mainline pipeline to the United States. The Fund’s renewable power portfolio includes the 190-MW Ontario Wind Project, the 99-MW Talbot Wind Project and the 80-MW Sarnia Solar Project, which were acquired from a wholly-owned subsidiary of Enbridge in October 2011, as well as interests in three wind power joint ventures and a business that operates waste-heat power generation projects at Alliance Pipeline Canada compressor stations.

Corporate Restructuring

On December 17, 2010, a plan of arrangement (the Plan) to restructure the Fund took effect. Under the Plan all publicly held trust units and five million units held by Enbridge were exchanged on a one-for-one basis for shares of a taxable Canadian corporation, ENF. The business of ENF is generally limited to investment in the Fund. Following completion of the Plan, the Company retained its overall 72% economic interest in the Fund and remained the primary beneficiary of the Fund both before and after the Plan through a combined direct and indirect investment in the Fund voting units and a non-voting preferred unit investment. As such, Enbridge continues to consolidate the Fund under variable interest entity accounting rules.

Renewable Energy Assets Transfer

In October 2011, the Fund acquired the Ontario Wind, Sarnia Solar and Talbot Wind energy projects from a wholly-owned subsidiary of Enbridge for an aggregate price of approximately $1.2 billion. The transaction was financed by the Fund through a combination of debt and equity, including the issuance of additional ordinary trust units of the Fund to ENF and preferred units to Enbridge. ENF in turn issued additional common shares to the public and to Enbridge. Enbridge’s overall economic interest in the Fund was reduced from 72% to 69% upon completion of the transaction and associated financing.

Saskatchewan System Shipper Complaint

On December 17, 2010, the Saskatchewan System filed amended Westspur tariffs with the NEB with an effective date of February 1, 2011. In January 2011, a shipper on the Westspur System requested the NEB make the tolls “interim” effective February 1, 2011 pending discussions between the shipper and the Saskatchewan System on information requests put forward by the shipper. Subsequently, the shipper filed a complaint with the NEB on the basis the information provided by the Fund was not adequate to allow an assessment to be made of the reasonableness of the tolls. Six parties have filed letters with the

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NEB supporting the shipper’s complaint. The NEB directed additional discussion among the parties and, as of February 6, 2012, the Fund continues to discuss the reasonableness of its Westspur tolls with shippers.

Competitive Conditions

The Saskatchewan System faces competition in pipeline transportation from other pipelines as well as other forms of transportation, most notably trucking. These alternative transportation options could charge rates or provide service to locations that result in greater net profit for shippers and thereby potentially reduce shipping on the Saskatchewan System or result in possible toll reductions. The Saskatchewan System manages exposure to loss of shippers by ensuring the shipping rates are competitive and by providing a high level of service. Furthermore, the Saskatchewan System’s right-of-way and expansion efforts have created a competitive advantage. The Saskatchewan System will continue to focus on increasing efficiencies through its expansion projects in order to meet its shippers’ growing demand.

The competition environment for Alliance Canada is similar to that for Alliance Pipeline US. See “Gas Pipelines, Processing and Energy Services – Alliance Pipeline US – Competitive Conditions”.

Incentive and Management Fees

Enbridge receives an annual base management fee for administrative and management services it provides to the Fund, plus incentive fees. Incentive fees are paid to Enbridge based on cash distributions by the Fund that exceed a base distribution amount. In 2011, the Company received intercompany incentive fees of $10 million (2010 - $8 million; 2009 - $8 million) before income taxes. Enbridge also provides management services to ENF. No additional fee is charged to ENF for these services provided the Fund is paying a fee to Enbridge.

CORPORATE

Corporate consists of the Company’s investment in Noverco Inc. (Noverco), new business development activities, corporate investments and financing costs not allocated to the business segments.

NOVERCO

At December 31, 2011, Enbridge owned an equity interest in Noverco through ownership of 38.9% (2010 - 32.1%; 2009 - 32.1%) of its common shares and a cost investment in preferred shares. Noverco is a holding company that owns approximately 71% of Gaz Metro Limited Partnership (Gaz Metro), a natural gas distribution company operating in the province of Quebec with interests in subsidiary companies operating gas transmission, gas distribution and power distribution businesses in the province of Quebec and the state of Vermont. Effective September 2010, Gaz Metro became a privately held limited partnership as a result of a reorganization of its publicly held partnership units, which were exchanged on a one-for-one basis for common shares in Valener Inc., a new publicly listed corporation.

On June 30, 2011, the Company completed the acquisition of an additional 6.8% interest in Noverco for $144 million. Following the completion of the transaction, Enbridge and Trencap, a partnership managed by the Caisse de Depot et Placement du Quebec (the Caisse), became the sole shareholders of Noverco.

Noverco also holds, directly and indirectly, an aggregate 69.4 million Common Shares. The substantial increase in the value of these Common Shares over the last decade has resulted in a significant shift in the balance of Noverco’s asset mix. The board of directors of Noverco has authorized the Caisse, as manager of Noverco, to rebalance Noverco’s asset mix through the sale of up to 22.5 million Common Shares, by way of private placement, secondary offering or stock market sales, from time to time as market conditions permit, and to distribute the proceeds to Noverco’s shareholders, subject to compliance with restrictions under applicable law and credit facilities. Enbridge’s share of such proceeds is expected to be up to approximately $300 million.

OTHER CORPORATE

Corporate also consists of the new business development activities, general corporate investments and financing costs not allocated to the business segments.

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GENERAL

EMPLOYEES

At December 31, 2011, Enbridge employed 6,934 employees as set forth in the following table.

Liquids Pipelines |  | 2,051
Gas Distribution 1 |  | 2,196
Gas Pipelines, Processing and Energy Services |  | 786
Sponsored Investments 2 |  | 1,605
Corporate |  | 296
|  | 6,934

1 Approximately 10% of the Enbridge’s workforce is represented by the Communications, Energy and Paperworkers Union, Local 975 (CEPU) and the International Brotherhood of Electrical Workers (IBEW), Local 97. A collective agreement with CEPU expiring in 2013 was ratified by union members in April 2011. A four-year collective agreement with the IBEW is in effect, expiring in February 2015.

2 Neither EEP nor the Fund have employees. Both use the services of the Company’s wholly-owned subsidiaries for managing and operating their businesses.

CORPORATE SOCIAL RESPONSIBILITY

Enbridge believes it must have effective strategies to respond to environmental and other corporate responsibilities. Enbridge adheres to a strong set of corporate values, has adopted a number of corporate responsibility policies and practices and has made significant investments in renewable and alternative energy technologies.

Enbridge defines CSR as conducting business in an ethical and responsible manner, protecting the environment and the safety of people, providing economic and other benefits to the communities in which we operate, supporting universal human rights and employing a variety of policies, programs and practices to manage corporate governance and ensure fair, full and timely disclosure. Enbridge’s 2011 CSR Report can be found at http://csr.enbridge.com/. None of the information contained on, or connected to, the Enbridge website is incorporated or otherwise part of this AIF.

The Company’s Neutral Footprint plan includes commitments to counteract the environmental impact of Enbridge’s operations since January 2009 within five years of their occurrence. Enbridge Neutral Footprint commitments include:

· planting a tree for every tree we remove to build new facilities;

· conserving an acre of land for every acre of wilderness we permanently impact; and

· generating a kilowatt of renewable energy for every kilowatt our operations consume.

To achieve its Neutral Footprint goal, Enbridge is working with the Nature Conservancy of Canada, The Conservation Fund in the United States and others. As reported in Enbridge’s 2011 CSR Report, progress on the Company’s Neutral Footprint initiatives (which are subject to change based on changes in the Company’s operations) includes:

· 589,850 trees removed; 246,000 tree seedlings planted;

· 1,598 acres disturbed; 3,955 acres conserved through the Nature Conservancy of Canada; and

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· forecasted growth in power consumption (from 2008 to 2015) is 1,852 gigawatts per hour (GWh); power currently generated from renewable sources is approximately 1,900 GWh.

ENVIRONMENTAL MATTERS

CLIMATE CHANGE LEGISLATION

Compliance with current and future environmental laws and regulations, which are likely to become more stringent over time, including those governing GHG emissions, may impose additional capital costs and financial expenditures and affect the demand for the Company’s services, which could adversely affect operating results and profitability.

Uncertainty continues with respect to GHG regulations in Canada and the United States. The federal governments of both countries have signaled their intention to develop sector specific carbon related regulations but are reluctant to implement measures that might slow economic recovery. As a result, it is uncertain how climate legislation could affect the industry.

Enbridge has voluntarily reported its GHG emissions for over ten years. The Company is on track to deploy a new emissions data management system to ensure compliance with reporting requirements mandated in Canada and the United States. The Company will continue to monitor GHG regulatory developments and publicly report its GHG emissions as well as develop internal procedures to reduce these emissions.

RENEWABLE ENERGY

Enbridge has significant interests in wind, solar and geothermal power generation and is well positioned to expand this portfolio. Many programs to encourage and advance renewable energy exist in Canada and the United States as well as individual provinces and states. Enbridge continues to assess and advance renewable energy opportunities and monitor potential changes to government policies and incentives that may positively or negatively impact existing or future renewable energy projects.

RISK FACTORS

A discussion of the Company’s risk factors can be found in the Year End MD&A under the subheading “Business Risks” for each of the operating segments as well as under the heading “Risk Management and Financial Instruments”.

DIVIDENDS

The declaration of dividends is at the discretion of the Board of Directors and is approved quarterly. The Company continues to target a pay out of approximately 60% to 70% of adjusted earnings as dividends to holders of the Common Shares. Dividends on the Series A Preference Shares are fixed and are paid quarterly. Dividends on the Series B Preference Shares, the Series D Preference Shares and the Series F Preference Shares are fixed for the initial term (the period from and including the date of issue of such shares to but excluding June 1, 2017, March 1, 2018 and June 1, 2018, respectively) and are paid quarterly. At the end of the initial term, the fixed dividend rate for the Series B Preference Shares, the Series D Preference Shares and the Series F Preference Shares will be reset for a subsequent five-year term, or the holders may elect to convert to a floating rate dividend which will be reset quarterly thereafter. See “Description of Capital Structure - Preference Shares”.

There are no restrictions that currently prevent the Company from paying dividends. However, in the event of any liquidation, dissolution or winding-up of the Company, whether voluntary or involuntary, the holders of the Preference Shares have priority in the payment of dividends over the holders of the Common Shares. Additionally, so long as any series of Preference Shares is outstanding, the Company is not permitted to declare, pay or set apart for payment any dividends (other than stock dividends in shares of the Company ranking junior to the Preference Shares) on the Common Shares or any other shares of the Company ranking junior to the Preference Shares with respect to the payment of dividends unless all dividends up to and including the dividends payable on the last preceding dividend payment dates on all Preference Shares then outstanding shall have been declared and paid or set apart for payment at the date of any such action. Restrictions in credit or financing agreements entered into by the Company or provisions of applicable law may also preclude the payment of dividends in certain circumstances.

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As at Year End, the Company did not have any Series F Preference Shares issued and outstanding. The following table shows dividends paid on the Common Shares, the Series A Preference Shares, the Series B Preference Shares and the Series D Preference Shares in 2011, 2010 and 2009:

(Canadian dollars per share) |  | 2011 |  | 2010 |  | 2009
Common Shares 1, 2 |  | 0.9800 |  | 0.8500 |  | 0.7400
Series A Preference Shares |  | 1.3750 |  | 1.3750 |  | 1.3750
Series B Preference Shares 3 |  | - |  | - |  | -
Series D Preference Shares 3 |  | - |  | - |  | -

1 Comparative amounts were restated to reflect the Company’s two-for-one stock split which was effective May 25, 2011.

2 Dividends paid on the Common Shares include a dividend of $0.2450 per share declared in 2010 but paid in the first quarter of 2011 and a dividend of $0.2125 per share declared in 2009 but paid in the first quarter of 2010. In 2011, the Company also declared a dividend of $0.2850 on the Common Shares which is payable in the first quarter of 2012.

3 No dividends were paid on the Series B Preference Shares and the Series D Preference Shares for the year ended December 31, 2011. On December 7, 2011, the Board of Directors declared a quarterly dividend of $0.4192 per share on the Series B Preference Shares and a quarterly dividend of $0.2705 per share on the Series D Preference Share. These are the first dividends payable on the Series B Preference Shares and the Series D Preference Shares and are both payable on March 1, 2012. The regular quarterly dividend of $0.25 per share payable on the Series B Preference Shares and the regular quarterly dividend of $0.25 per share payable on the Series D Preference Shares will take effect with the dividend payment to be made in the second quarter of 2012 for such series of Preference Shares.

DESCRIPTION OF CAPITAL STRUCTURE

SHARE CAPITAL

Enbridge’s authorized share capital consists of an unlimited number of Common Shares and an unlimited number of Preference Shares, issuable in series. At Year End, the Company had 781,677,715 Common Shares, 5,000,000 Series A Preference Shares, 20,000,000 Series B Preference Shares and 18,000,000 Series D Preference Shares issued and outstanding.

Common Shares

Holders of Common Shares are entitled to receive dividends if, as and when declared by the Board of Directors. Holders of Common Shares are entitled to receive notice of and to attend all meetings of the holders of the Common Shares and are entitled to one vote per Common Share held at all such meetings. In the event of liquidation, dissolution or winding up of the Company or other distribution of assets of the Company among its shareholders for the purpose of winding up its affairs, holders of Common Shares will be entitled to participate ratably in any distribution of assets of the Company.

The Company has a Shareholder Rights Plan that is designed to encourage the fair treatment of shareholders in connection with any takeover offer for the Company. Rights issued under the plan become exercisable when a person, including any related parties, acquires or announces the intention to acquire 20% or more of the outstanding Common Shares without complying with certain provisions set out in the plan, or without approval of the Board of Directors. Should such an acquisition occur, each rights holder, other than the acquiring person and its related parties, will have the right to purchase Common Shares at a 50% discount to the market price at that time. The plan was reconfirmed at the 2005, 2008 and 2011 annual meetings of shareholders and must be reconfirmed at every third annual meeting thereafter.

Enbridge’s Dividend Reinvestment and Share Purchase Plan enables registered shareholders of the Company to purchase additional Common Shares by reinvesting all of the cash dividends paid on the Common Shares and also by making optional cash payments of up to $5,000 per quarter, in both cases without incurring brokerage or other transaction expenses. Effective with dividends payable on March 1, 2008, participants in the Company’s Dividend Reinvestment and Share Purchase Plan receive a 2% discount on the purchase of Common Shares with reinvested dividends.

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Enbridge also has stock-based compensation plans that allow employees to purchase Common Shares. Option exercise prices are determined based on the weighted average market prices of the Common Shares for the five days preceding the date of issuance. Options granted under the plan are generally fully exercisable after four years and expire ten years after the grant date.

Effective May 25, 2011, the Company completed a two-for-one stock split of the then issued and outstanding Common Shares.

Preference Shares

The Preference Shares may be issued in one or more series. The Board of Directors may determine the designation, rights, privileges, restrictions and conditions attached to each series of Preference Shares before the issue of such series. Holders of the Preference Shares are not entitled to receive notice of or to attend or vote at any meeting of the shareholders of the Company, except as required by law. At any meeting of the holders of the Preference Shares as a class or at any joint meeting of the holders of two or more series of the Preference Shares, each holder of Preference Shares entitled to vote at the meeting will have, on a poll, one one-hundredth of a vote in respect of each dollar of the issue price of each Preference Share held. The Preference Shares of each series rank on parity with the Preference Shares of every other series with respect to priority in the payment of dividends and with respect to priority on the return of capital or any other distribution of assets of the Company in the event of any liquidation, dissolution or winding-up of the Company, whether voluntary or involuntary (a Liquidation Distribution). The Preference Shares of each series are entitled to priority over the Common Shares and any other shares of the Company ranking junior to the Preference Shares with respect to the payment of dividends and on a Liquidation Distribution.

As at the date of this AIF, the Company has designated seven series of Preference Shares: the Series A Preference Shares, the Series B Preference Shares, the Series C Preference Shares, the Series D Preference Shares, the Series E Preference Shares, the Series F Preference Shares and the Series G Preference Shares.

The table below sets forth the issued and outstanding Preference Shares as at Year End and certain characteristics thereof:

| Outstanding | Per Share Redemption Price 1 | Redemption and Conversion Option Date 1,2 | Right to Convert 2,3
Series A Preference Shares | 5,000,000 | $25 | - | -
Series B Preference Shares | 20,000,000 | $25 | June 1, 2017 | Series C Preference Shares
Series D Preference Shares | 18,000,000 | $25 | March 1, 2018 | Series E Preference Shares

1 The Company may, at its option, redeem all or a portion of the outstanding Series B Preference Shares and Series D Preference shares for the applicable redemption price per share plus all accrued and unpaid dividends on the applicable redemption option date and on every fifth anniversary thereafter.

2 Holders of the Series B Preference Shares and the Series D Preference Shares will have the right, subject to certain conditions being met, to convert their shares into Series C Preference Shares and Series E Preference Shares, respectively, on the applicable conversion option date and on every fifth anniversary thereafter. The Series C Preference Shares and the Series E Preference Shares are issuable only upon conversion of the Series B Preference Shares and the Series D Preference Shares, respectively. Holders of the Series C Preference Shares and the Series E Preference Shares will have the right, subject to certain conditions being met, to convert their shares back into Series B Preference Shares and Series D Preference Shares on June 1, 2022 and March 1, 2023, respectively, and on every fifth anniversary thereafter, as applicable.

3 Holders of the Series C Preference Shares and the Series E Preference Shares will be entitled to receive quarterly floating rate cumulative dividends per share at a rate equal to: $25 x (number of days in quarter/365) x (90-day Government of Canada treasury bill rate + 2.40% (Series C Preference Shares) or 2.37% (Series E Preference Shares). The Series C Preference Shares and Series E Preference Shares will also be redeemable at the option of the Company at a redemption price per share equal to (i) in the case of the Series C Preference Shares, $25.00 per share if redeemed on or after June 1, 2022 on an applicable conversion option date or $25.50 per share if redeemed on any date after June 1, 2017 that is not a conversion option date, plus all accrued and unpaid dividends thereon, and (ii) in the case of the Series E Preference Shares, $25.00 per share if redeemed on or after March 1, 2023 on an applicable conversion option date or $25.50 per share if redeemed on any date after March 1, 2018 that is not a conversion option date, plus all accrued and unpaid dividends thereon.

Subsequent to Year End, on January 18, 2012, the Company issued 20 million Series F Preference Shares. The Series F Preference Shares are entitled to the same dividends, redemption and conversion terms as the Series B Preference Shares and the Series D Preference Shares. Redemption of the Series F Preference Shares by the Company or conversion by holders into Series G Preference Shares can occur on June 1, 2018 and on June 1 of every fifth year thereafter. The Series G Preference Shares are issuable only upon conversion of the Series F Preference Shares. Holders of the Series G Preference Shares will have the right, subject to certain conditions being met, to convert their shares back into Series F Preference Shares on June 1, 2023 and on June 1 of every fifth year thereafter. Holders of the Series G Preference Shares will also be entitled to receive quarterly floating rate cumulative dividends per share at a rate equal to $25 multiplied by the number of days in the quarter divided by 365 and multiplying that product by the sum of the then 90-day Government of Canada treasury bill rate plus 2.51%. The Series G Preference Shares will also be redeemable at the option of the Company at a redemption price of $25.00 per share if redeemed on or after June 1, 2023 on an applicable conversion option date or $25.50 per share if redeemed on any date after June 1, 2018 that is not a conversion option date, plus all accrued and unpaid dividends thereon.

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RATINGS

The Company’s objectives when managing capital are to maintain flexibility among: enabling its businesses to operate at the highest efficiency while maintaining safety and reliability; providing liquidity for growth opportunities; and providing acceptable returns to shareholders. These objectives are primarily met through maintenance of an investment grade credit rating, which provides access to lower cost capital. A ratings downgrade could potentially increase the Company’s financing costs and reduce its access to capital markets. The following table sets forth the ratings assigned to the Company’s Preference Shares, Medium-Term Notes (MTNs) and Unsecured Debt and Commercial Paper by DBRS Limited (DBRS), Moody’s Investor Services, Inc. (Moody’s) and Standard & Poor’s Ratings Services (S&P).

| DBRS | Moody’s | S&P
Preference Shares 1 | Pfd-2 (low) | Baa3 | BBB
MTNs and Unsecured Debt | A(low) | Baa1 | A-
Commercial Paper | R-1 (low) | Not Rated | A-1 (low)
Rating Outlook | Stable | Stable | Stable

1 The Series A Preference Shares, the Series B Preference Shares, the Series D Preference Shares and the Series F Preference Shares have all had the same ratings assigned to them.

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. A description from the rating agency for each credit rating listed in the table above is set out below.

DBRS has different rating scales for short and long-term debt and preferred shares. “High” or “low” grades are used to indicate the relative standing within a rating category. The absence of either a “high” or “low” designation indicates the rating is in the “middle” of this category. The Pfd-2 (low) rating assigned to the Preference Shares is the second highest of six rating categories for preferred shares. Preferred shares rated Pfd-2 are of satisfactory credit quality. Protection of dividends and principal is still substantial, but earnings, the balance sheet and coverage ratios are not as strong as Pfd-1 rated companies. The A (low) rating assigned to Enbridge’s MTNs and unsecured debentures is the third highest of eight categories for long-term debt. Entities in this category may be vulnerable to future events, but qualifying negative factors that exist are considered manageable. Long-term debt rated A (low) is of good credit quality. The capacity for the payment of financial obligations is substantial, but of lesser credit quality than AA.

The R-1 (low) rating assigned to Enbridge’s commercial paper is the third highest of ten rating categories and indicates good credit quality. The capacity for the payment of short-term financial obligations as they fall due is substantial. The overall strength is not as favorable as with higher rating categories. Entities in this category may be vulnerable to future events, but qualifying negative factors that exist are considered manageable.

Moody’s has differen t rating scales for short and long-term obligations. Numerical modifiers 1, 2 and 3 are applied to each rating classification, with 1 being the highest and 3 being the lowest. The Baa3 rating assigned to the Preference Shares and the Baa1 rating assigned to Enbridge’s MTNs and unsecured debentures is the fourth highest of nine rating categories for long-term obligations. Obligations rated Baa are subject to moderate credit risk. They are considered medium-grade and, as such, may possess certain speculative characteristics.

S&P has different rating scales for short and long-term obligations. Ratings may be modified by the addition of a plus (+) or a minus (-) sign to show the relative standing within a particular rating category. The BBB rating assigned to the Preference Shares is the fourth highest of ten rating categories for long-term obligations. An obligor rated BBB has adequate capacity to meet its financial commitments; however, adverse economic conditions or changing circumstances are more likely to lead to a weakened capacity of the obligor to meet its financial commitments. The A- rating assigned to Enbridge’s MTNs and unsecured debentures is the third highest of ten rating categories. An A rating indicates the obligor has strong capacity to meet its financial commitments but is somewhat more susceptible to the adverse effects of

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changes in circumstances and economic conditions than obligors in higher-rated categories. The rating of A-1 (low) assigned to Enbridge’s commercial paper is the highest of nine rating categories for short-term obligations. An obligor rated A-1 has strong capacity to meet its financial commitments.

MARKET FOR SECURITIES

COMMON SHARES

The Common Shares are traded on the TSX in Canada, the principal market for such shares, and on the NYSE in the United States under the symbol “ENB”. The following table sets forth the monthly price ranges and volumes traded for the Common Shares on the TSX and NYSE:

| TSX 1 | NYSE 1
| High ($) | Low ($) | Close ($) | Volume Traded | High (US$) | Low (US$) | Close (US$) | Volume Traded
January 2011 | 29.18 | 27.05 | 29.03 | 25,778,492 | 29.12 | 27.23 | 28.97 | 4,950,186
February 2011 | 29.51 | 28.35 | 29.03 | 34,747,428 | 29.99 | 28.52 | 29.95 | 4,621,156
March 2011 | 30.00 | 28.15 | 29.71 | 29,865,320 | 30.90 | 28.80 | 30.73 | 7,097,752
April 2011 | 31.22 | 29.38 | 30.75 | 25,152,742 | 32.85 | 30.54 | 32.42 | 5,417,010
May 2011 | 32.63 | 29.79 | 32.47 | 30,675,681 | 33.65 | 30.72 | 33.65 | 8,537,118
June 2011 | 32.74 | 29.95 | 31.36 | 28,169,246 | 33.71 | 30.55 | 32.46 | 8,409,026
July 2011 | 31.97 | 30.51 | 31.37 | 17,111,408 | 33.58 | 32.00 | 32.89 | 4,638,580
August 2011 | 32.50 | 28.27 | 32.50 | 50,366,340 | 33.50 | 28.52 | 33.07 | 9,000,113
September 2011 | 33.71 | 30.76 | 33.45 | 36,820,600 | 33.49 | 29.92 | 31.93 | 7,065,186
October 2011 | 35.50 | 31.52 | 34.53 | 35,205,082 | 35.70 | 29.73 | 34.71 | 7,982,802
November 2011 | 36.89 | 34.07 | 36.14 | 35,712,154 | 36.04 | 33.16 | 35.27 | 6,625,349
December 2011 | 38.17 | 34.72 | 38.09 | 46,223,005 | 37.46 | 34.27 | 37.41 | 6,120,949

1 Monthly price ranges and volumes for the months of January 2011 to May 2011 have been restated to reflect the Company’s two-for-one stock split which was effective May 25, 2011.

SERIES A PREFERENCE SHARES

The Series A Preference Shares are traded on the TSX under the symbols “ENB.PR.A”. The following table sets forth the monthly price range and volume traded for the Series A Preference Shares on the TSX:

| High ($) | Low ($) | Close ($) | Volume Traded
January 2011 | 25.73 | 25.33 | 25.46 | 42,681
February 2011 | 25.60 | 25.02 | 25.07 | 58,616
March 2011 | 25.34 | 24.69 | 25.07 | 87,354
April 2011 | 25.45 | 25.01 | 25.18 | 59,946
May 2011 | 25.39 | 25.01 | 25.23 | 78,073
June 2011 | 25.50 | 25.10 | 25.25 | 98,360
July 2011 | 25.49 | 25.25 | 25.33 | 56,783
August 2011 | 25.72 | 25.02 | 25.32 | 84,049
September 2011 | 25.72 | 25.25 | 25.42 | 92,856
October 2011 | 25.97 | 25.10 | 25.60 | 50,014
November 2011 | 26.00 | 25.46 | 26.00 | 55,719
December 2011 | 26.48 | 25.61 | 26.31 | 35,023

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SERIES B PREFERENCE SHARES

The Series B Preference Shares are traded on the TSX under the symbols “ENB.PR.B”. The following table sets forth the monthly price range and volume traded for the Series B Preference Shares on the TSX:

| High ($) | Low ($) | Close ($) | Volume Traded
September 2011 1 | 25.25 | 25.15 | 25.19 | 978,815
October 2011 | 25.74 | 25.05 | 25.70 | 1,491,126
November 2011 | 25.87 | 25.20 | 25.61 | 1,222,459
December 2011 | 25.95 | 25.42 | 25.90 | 163,269

1 The Series B Preference Shares commenced trading on the TSX on September 30, 2011.

SERIES D PREFERENCE SHARES

The Series D Preference Shares are traded on the TSX under the symbols “ENB.PR.D”. The following table sets forth the monthly price range and volume traded for the Series D Preference Shares on the TSX:

| High ($) | Low ($) | Close ($) | Volume Traded
November 2011 1 | 25.20 | 25.05 | 25.12 | 2,382,430
December 2011 | 25.70 | 25.08 | 25.50 | 1,141,372

1 The Series D Preference Shares commenced trading on the TSX on November 23, 2011.

OTHER SECURITIES

The table below outlines the securities issued by the Company and its wholly-owned subsidiaries that are reporting issuers during 2011 that are not listed or quoted on an exchange. These are in the form of unsecured medium-term notes.

Issuer | Principal Amount ($ millions) | Coupon | Issue Date | Maturity Date | Issue Price ($)
Enbridge | 350 | 3 Month CDOR + 1.00% | August 19, 2011 | August 19, 2015 | 100.000
Enbridge | 250 | 3 Month CDOR + 1.05% | November 25, 2011 | November 25, 2013 | 100.000
EGD | 100 | 4.95% | September 7, 2011 | November 22, 2050 | 104.415

There are no provisions associated with this debt that entitle debt holders to voting rights. From time to time, the Company also issues commercial paper for various terms.

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CREDIT FACILITIES

Credit facilities carry a weighted average standby fee of 0.17% per annum on the unused portion and draws bear interest at market rates. Certain credit facilities serve as a backstop to the commercial paper programs and the Company has the option to extend the facilities, which are currently set to mature from 2012 to 2016. The following table provides details of the Company’s credit facilities at Year End:

| Maturity Dates 1 | Total Facilities | Credit Facility Draws 2 | Available
(millions of Canadian dollars) |  |  |  |
Liquids Pipelines | 2013 | 300 | 26 | 274
Gas Distribution | 2012-2013 | 717 | 556 | 161
Sponsored Investments 3 | 2013 | 500 | 268 | 232
Corporate | 2012-2016 | 5,653 | 2,832 | 2,821
|  | 7,170 | 3,682 | 3,488
Southern Lights project financing 4 | 2013-2014 | 1,576 | 1,466 | 110
Total credit facilities |  | 8,746 | 5,148 | 3,598

1 Total facilities include $30 million in demand facilities with no maturity date.

2 Includes facility draws, letters of credit and commercial paper issuances that are back-stopped by the credit facility.

3 In January 2012, the Company secured additional revolving facilities of US$1.3 billion with a maturity date of 2015.

4 Total facilities inclusive of $61 million for debt service reserve letters of credit.

DIRECTORS AND OFFICERS

As at December 31, 2011, the directors and all officers of Enbridge (including the executive officers listed below) as a group beneficially owned, directly or indirectly, 3,257,619 Common Shares of the Company, representing less than 1% 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, more than 1% of the voting securities of any subsidiary of the Company.

DIRECTORS

The following table sets forth the names of the Directors of Enbridge Inc. on February 21, 2012, their municipalities of residence, their respective principal occupations within the five preceding years, and the year in which they first became a Director of the Company. Each Director who is elected holds office until the next annual meeting of shareholders or until a successor is duly elected or appointed.

Name and Place of Residence | Principal Occupation During the Five Preceding Years | Director Since 1
David A. Arledge Naples, Florida USA | Corporate Director. Chair of the Board of Directors of Enbridge Inc. since 2005. | 2002
James J. Blanchard 2, 4 Beverly Hills, Michigan USA | Chairman, Government Affairs, DLA Piper U.S., LLP (law firm) since June, 2006. United States Ambassador to Canada from 1993 to 1996. | 1999
J. Lorne Braithwaite Thornhill, Ontario Canada | Corporate Director. President and Chief Executive Officer of Build Toronto Inc. since April 2009. | 1989
Patrick D. Daniel Calgary, Alberta Canada | President and Chief Executive Officer of Enbridge since January 2001. | 2000
J. Herb England Naples, Florida USA | Chairman and Chief Executive Officer of Stahlman-England Irrigation Inc. (contracting company) since January 2000. | 2007

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Name and Place of Residence | Principal Occupation During the Five Preceding Years | Director Since 1
Charles W. Fischer Calgary, Alberta Canada | Corporate Director. President and Chief Executive Officer of Nexen Inc. from 2001 to 2008. | 2009
V. Maureen Kempston Darkes Lauderdale-by-the-Sea, Florida USA | Corporate Director. Group Vice President and President, Latin America, Africa and Middle East of General Motors Corporation Group from 2002 to 2009. | 2010
David A. Leslie 3 Toronto, Ontario Canada | Corporate Director. | 2005
George K. Petty San Luis Obispo, California USA | Corporate Director. | 2001
Charles E. Shultz Calgary, Alberta Canada | Chairman and Chief Executive Officer of Dauntless Energy Inc. (private oil and gas corporation) since 1995. | 2004
Dan C. Tutcher Houston, Texas USA | Corporate Director. Principal in Center Coast Capital Advisors, L.P. since 2007. | 2006
Catherine L. Williams Calgary, Alberta Canada | Corporate Director. Chief Financial Officer of Shell Canada Limited from 2003 to 2007. | 2007

1 “Director Since” refers to the year the person named was first elected or appointed as a Director of the Company or of its predecessor parent, Interprovincial Pipe Line Inc.

2 On April 10, 2006, the Ontario Securities Commission (OSC) 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 OSC 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.

3 Mr. Leslie served as a member of the Board of Directors of Canwest Global Communications Corp. from March 26, 2007 to January 14, 2009. On October 6, 2009, Canwest Global Communications Corp. voluntarily entered into, and successfully obtained, an Order from the Ontario Superior Court of Justice (Commercial Division) relating to proceedings under the Companies’ Creditors Arrangement Act.

4 On May 31, 2004 and again on April 10, 2006, certain directors, senior officers and certain current and former employees of Nortel Networks Corporation and Nortel Networks Limited were prohibited from trading in the securities of Nortel Networks Corporation and Nortel Networks Limited pursuant to management cease trade orders issued by the Ontario Securities Commission and certain other provincial securities regulators in connection with delays in the filing of certain financial statements. Following the filing of the required financial statements, the Ontario Securities Commission and subsequently the other provincial securities regulators lifted such cease trade orders effective June 21, 2005 and June 8, 2006 respectively. Mr. Blanchard was a director of Nortel Networks Corporation until June 29, 2005. At no time did the above noted cease trade orders apply to Mr. Blanchard.

Enbridge has four committees of the Board of Directors: (1) Audit, Finance & Risk Committee (AFR Committee); (2) Governance Committee; (3) Human Resources & Compensation Committee (HRC Committee); and (4) Corporate Social Responsibility Committee. The members of each of these committees, as of 2011 Year End, are identified below:

Director | AFR Committee | Governance Committee | HRC Committee | CSR Committee
David A. Arledge |  | ü | ü |
James J. Blanchard |  | ü |  | Chair
J. Lorne Braithwaite |  |  | ü | ü
Patrick D. Daniel |  |  |  |
J. Herb England | ü | ü |  |
Charles W. Fischer |  |  | ü | ü
V. Maureen Kempston Darkes |  |  | ü | ü

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David A. Leslie | Chair | ü |  |
George K. Petty | ü | Chair |  |
Charles E. Shultz | ü |  | ü |
Dan C. Tutcher |  | ü |  | ü
Catherine L. Williams | ü |  | Chair |

OFFICERS

The following table sets forth the names of the executive officers, their current office with the Company on February 21, 2012, their municipalities of residence and their principal occupations for the five preceding years.

Name and Place of Residence | Present Position Held | Principal Occupation During the Five Preceding Years
Patrick D. Daniel Calgary, Alberta Canada | President & Chief Executive Officer | President & Chief Executive Officer since January 2001.
D. Guy Jarvis Aurora, Ontario Canada | President, Gas Distribution | President, Gas Distribution and President, Gas Distribution Inc. since September 2011. Senior Vice President, Investor Relations & Enterprise Risk from October 2010 to September 2011. Senior Vice President, Business Development, Enbridge Pipelines Inc. from March 2008 to October 2010. Vice President, Upstream Development, Enbridge Pipelines Inc. from December 2004 to March 2008.
Al Monaco Calgary, Alberta Canada | President, Gas Pipelines, Green Energy & International | President, Gas Pipelines, Green Energy & International since October 2010. Executive Vice President, Major Projects & Green Energy from January 2008 to October 2010. President, Enbridge Gas Distribution Inc. from September 2006 to January 2008.
Stephen J. Wuori Calgary, Alberta Canada | President, Liquids Pipelines | President, Liquids Pipelines since October 2010. Executive Vice President, Liquids Pipelines from January 2008 to October 2010. Executive Vice President, Chief Financial Officer & Corporate Development from May 2006 to January 2008.

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Name and Place of Residence | Present Position Held | Principal Occupation During the Five Preceding Years
J. Richard Bird Calgary, Alberta Canada | Executive Vice President, Chief Financial Officer & Corporate Development | Executive Vice President, Chief Financial Officer & Corporate Development since January 2008. Executive Vice President, Liquids Pipelines from May 2006 to January 2008.
Janet A. Holder Prince George, British Columbia Canada | Executive Vice President, Western Access | Executive Vice President, Western Access since September 2011. President, Gas Distribution from October 2010 to September 2011 and President, Enbridge Gas Distribution Inc. from January 2008 to September 2011. Vice President, Support Services, Enbridge Pipelines Inc. from April 2006 to January 2008.
Karen L. Radford Calgary, Alberta Canada | Executive Vice President, People & Partners | Executive Vice President, People & Partners since September 2011. Various Executive Vice President and President positions with TELUS Corporation from July 2004 to January 2011.
David T. Robottom, Q.C. Calgary, Alberta Canada | Executive Vice President & Chief Legal Officer | Executive Vice President & Chief Legal Officer since October 2010. Executive Vice President, Law from January 2010 to October 2010. Group Vice President, Corporate Law from June 2006 to January 2010.
Byron C. Neiles Calgary, Alberta Canada | Senior Vice President, Major Projects | Senior Vice President, Major Projects since November, 2011. Vice President, Major Projects from October 2010 to November 2011. Vice President, Engineering, Procurement & Construction & Project Services, Enbridge Pipelines Inc. from January 2010 to October 2010. Vice President, Project Services, Enbridge Pipelines Inc. from May 2008 to December 2009. Vice President, Customer, Regulatory & Public Affairs, Enbridge Gas Distribution from June 2003 to April 2008.
John K. Whelen Calgary, Alberta Canada | Senior Vice President & Controller | Senior Vice President & Controller since April 2010. Senior Vice President, Corporate Development from September 2006 to April 2010.

CONFLICTS OF INTEREST

Directors and officers of Enbridge and its subsidiaries are required to disclose the existence of potential conflicts in accordance with Enbridge policies governing directors and officers and in accordance with the Canada Business Corporations Act. Although some of the directors sit on boards or may be otherwise associated with companies that ship crude oil and/or natural gas on Enbridge’s pipeline systems, Enbridge as a common carrier in Canada cannot, under its tariff, deny transportation service to a credit-worthy shipper. Further, due to the specialized nature of the industry, Enbridge believes it is important for its Board to be composed of qualified and knowledgeable directors, so it is likely that some of them will come from oil and gas producers and shippers. The Governance Committee closely monitors relationships among directors to ensure that business associations do not affect the Board’s performance. In a circumstance where a director declares an interest in any material contract or material transaction being considered at a meeting, the director generally absents himself or herself from the meeting during the consideration of the matter, and does not vote on the matter.

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AUDIT, FINANCE & RISK COMMITTEE

The Audit, Finance & Risk Committee’s Terms of Reference are attached to this AIF as Appendix A and can also be found on the Company’s website at www.enbridge.com.

RELEVANT EDUCATION AND EXPERIENCE OF MEMBERS

The members of the AFR Committee at Year End were David A. Leslie (Chair), J. Herb England, George K. Petty, Charles E. Shultz and Catherine L. Williams. The Board believes the composition of the AFR Committee reflects a high level of financial literacy and expertise. Each member of the AFR Committee has been determined by the Board to be “independent” and “financially literate” as those terms are defined under Canadian and United States securities laws and NYSE requirements.

In addition, the Board has determined that Messrs. England and Leslie and Ms. Williams are each an “Audit Committee Financial Expert” as that term is defined under United States securities laws. The Board has made these determinations based on the education and breadth and depth of experience of each member of the AFR Committee. The following is a description of the education and experience, apart from their respective roles as Directors of Enbridge, of each member of the AFR Committee that is relevant to the performance of his or her responsibilities as a member of the AFR Committee.

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 an active supervisor of persons engaged in 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 committees of Enbridge Gas Distribution Inc. (a subsidiary of Enbridge Inc.), Crombie REIT, Empire Company Limited, Sobeys Inc. (a subsidiary of Empire Company Limited), and Imris Inc. The NYSE Corporate Governance Standards requires that listed companies disclose if any member of the audit committee serves on more than three public companies’ audit committees. While Mr. Leslie does serve on more than three audit committees, he is no longer employed on a full-time basis and the Board has determined that his service on these audit committees enhances his experience and does not impair his ability to serve on the Enbridge audit committee.

J. Herb England

Mr. England acquired extensive financial experience and exposure to accounting and financial issues during a lengthy career with the John Labatt Limited group of companies, including as Chief Financial Officer of John Labatt Limited. He is currently Chairman and Chief Executive Officer of Stahlman-England Irrigation Inc., a contracting company in Florida.

George K. Petty

Mr. Petty acquired significant financial experience and exposure to accounting and financial issues during his lengthy business career, which included serving as President and Chief Executive Officer of Telus Corporation from 1994 to 1999. He has acted as a member of other United States and Canadian audit committees.

Charles E. Shultz

Mr. Shultz acquired significant financial experience as a business executive, board member and audit committee member of several large Canadian and U.S. public companies. He served as President and Chief Executive Officer of Gulf Canada Resources Limited from 1990 to 1995 and has served as a director of Newfield Exploration and of Canadian Oil Sands Limited since its inception and was Chairman until 2009. He is currently Chair & Chief Executive Officer of Dauntless Energy Inc., a private oil and gas company.

Catherine L. Williams

Ms. Williams held senior finance positions during a 30-year career in business which included international experience. She worked for 20 years in the Shell group of companies, including as Chief Financial Officer of Shell Canada Limited from 2003 to 2007 and as Controller of Shell Europe Oil Productions from 2001 to 2003.

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PRE-APPROVAL POLICIES AND PROCEDURES

The AFR Committee has adopted a policy that requires pre-approval by the AFR Committee of any services to be provided by the external auditors, PwC, whether audit or non-audit services. The policy prohibits the Company from engaging the auditors to provide the following non-audit services:

· bookkeeping or other services related to accounting records and financial statements;

· financial information systems design and implementation;

· appraisal or valuation services, fairness opinions or contribution-in-kind reports;

· actuarial services;

· internal audit outsourcing services;

· management functions or human resources;

· broker or dealer, investment adviser or investment banking services;

· legal services; and

· expert services unrelated to the audit.

The AFR Committee believes that the policy will protect the Company from the potential loss of independence of the external auditors. The AFR Committee has also adopted a policy which prohibits the Company from hiring (as a full-time employee, contractor or otherwise) into a financial reporting oversight role any current or former employee or partner of its external auditor who provided audit, review or attest service in respect of the Company’s financial statements (including such financial statements of its reporting issuer subsidiaries and significant investees) during the 12 month period preceding the date of the initiation of the current annual audit. In all cases, the hiring of any partner or employee or former partner or employee of the independent auditor is subject to joint approval by the lead engagement partner and the Company’s Senior Vice President and Controller.

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 Company by sending a written request to 3000, 425 - 1st 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.

EXTERNAL AUDITOR SERVICES – FEES

The following table sets forth all services rendered by the Company’s 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, 2011 and 2010.

| 2011 | 2010 | Description of Fee Category
Audit Fees 1 | $5,285,637 | $4,202,285 | Represents the aggregate fees for audit services.
Audit-Related Fees | 158,118 | 151,501 | Represents the aggregate fees for assurance and related services by the Company’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”. During fiscal 2011 and 2010, the services provided in this category included due diligence related to prospectus offerings and other items.
Tax Fees | 576,159 | 712,742 | Represents the aggregate fees for professional services rendered by the Company’s auditors for tax compliance, tax advice and tax planning.
All Other Fees 1 | 614,577 | 1,435,327 | Represents the aggregate fees for products and services provided by the Company’s auditors other than those services reported under “Audit Fees”, “Audit-Related Fees” and “Tax Fees”. These fees include those related to United States Generally Accepted Accounting Principles (US GAAP), International Financial Reporting Standards (IFRS), Canadian Public Accountability Board fees, French translation work and process reviews.
Total Fees | $6,634,491 | $6,501,855 |

1 “Audit Fees” for the year ended December 31, 2011 included fees related to the Company’s transition to U.S. GAAP effective January 1, 2012. For the year ended December 31, 2011, fees related to U.S. GAAP were included in the “All Other Fees” category.

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LEGAL PROCEEDINGS

Information related to Enbridge’s legal proceedings can be found in Note 31, “Commitments and Contingencies”, to the Company’s audited consolidated financial statements for the year ended December 31, 2011.

INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

No director, executive officer or principal shareholder of Enbridge, or associate or affiliate of these persons, has any material interest, direct or indirect, in any transaction within the last three years that has materially affected or will materially affect Enbridge.

REGISTRAR AND TRANSFER AGENT

The registrar and transfer agent for the Company’s Common Shares is CIBC Mellon Trust Company 1:

In Canada: Canadian Stock Transfer Company P.O. Box 700, Station B Montreal, Quebec H3B 3K3 Telephone: 1-800-387-0825 or 416-682-3860 outside of North America Website: www.canstockta.com | In the United States: Computershare 480 Washington Blvd. Jersey City, New Jersey United States of America 07310

1 Canadian Stock Transfer Company Inc. acts as the Administrative Agent for CIBC Mellon Trust Company.

The registrar and transfer agent for the Series A Preference Shares, the Series B Preference Shares, the Series D Preference Shares and the Series F Preference Shares is CIBC Mellon Trust Company 1:

In Canada:

Canadian Stock Transfer Company

P.O. Box 700, Station B

Montreal, Quebec H3B 3K3

Telephone: 1-800-387-0825 or

416-682-3860 outside of North America

Website: www.canstockta.com

1 Canadian Stock Transfer Company Inc. acts as the Administrative Agent for CIBC Mellon Trust Company.

MATERIAL CONTRACTS

Enbridge has not entered into any material contracts outside the ordinary course of business.

INTERESTS OF EXPERTS

The Company’s independent auditors are PricewaterhouseCoopers LLP, Chartered Accountants, who have issued an independent auditor’s report dated February 21, 2012 in respect of the Company’s consolidated financial statements as at December 31, 2011 and December 31, 2010 and for each of the years in the three year period ended December 31, 2011 and the Company’s internal control over financial reporting as at December 31, 2011. Both of these opinions are dated February 21, 2012.

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PricewaterhouseCoopers LLP has advised that they are independent with respect to the Company within the meaning of the Rules of Professional Conduct of the Institute of Chartered Accountants of Alberta and the rules of the US Securities and Exchange Commission.

ADDITIONAL INFORMATION

Additional information about Enbridge is available on our website at www.enbridge.com and on SEDAR at www.sedar.com in Canada, and on the United States Securities and Exchange Commission’s website (EDGAR) at www.sec.gov. The aforementioned information is made available in accordance with legal requirements and is not incorporated by reference into this AIF.

Additional information, including directors’ and officers’ remuneration and indebtedness, principal holders of our securities and securities authorized for issuance under equity compensation plans, where applicable, is contained in the Management Information Circular for Enbridge’s most recent annual meeting of shareholders at which directors were elected.

Additional financial information is provided in Enbridge’s Consolidated Financial Statements and MD&A for the most recently completed financial year.

Enbridge Gas Distribution Inc.

Additional information about EGD can be found in its AIF, Financial Statements and MD&A which have been filed with Canadian Securities Regulatory Authorities and are publicly available at www.sedar.com. These documents are not incorporated by reference into this AIF.

Enbridge Energy Partners, L.P. and Enbridge Energy Management, L.L.C.

Additional information about EEP and Enbridge Energy Management, L.L.C. (EEM) can be found in their Annual Reports on Form 10-K that have been filed with the United States Securities and Exchange Commission. These documents contain detailed disclosure with respect to each entity and are publicly available at www.sec.gov. No part of the Form 10-K filed by EEP or by EEM is incorporated by reference into this AIF.

Enbridge Income Fund

Additional information about the Fund can be found in its AIF, Financial Statements and MD&A which have been filed with Canadian Securities Regulatory Authorities. These documents contain detailed disclosure with respect to the Enbridge Income Fund and are publicly available at www.sedar.com. These documents are not incorporated by reference into this AIF.

Enbridge Income Fund Holdings Inc.

Additional information about ENF can be found in its AIF, Financial Statements and MD&A which have been filed with Canadian Securities Regulatory Authorities. These documents contain detailed disclosure with respect to the Enbridge Income Fund Holdings Inc. and are publicly available at www.sedar.com. These documents are not incorporated by reference into this AIF.

Enbridge Pipelines Inc.

Additional information about EPI can be found in its AIF, Financial Statements and MD&A which have been filed with Canadian Securities Regulatory Authorities and are publicly available at www.sedar.com. These documents are not incorporated by reference into this AIF.

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APPENDIX A

AUDIT, FINANCE & RISK COMMITTEE TERMS OF REFERENCE

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.

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.

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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. advising the Committee of any finance, accounting or misappropriation matters brought to the Chair’s attention through the Corporation’s Ethics and Conduct hotline procedures;

G. reviewing the CEO’s expense reports;

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

I. reporting to the Board on the recommendations and decisions of the 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:

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

(iii) review with management any anticipated changes in reporting standards, the preparedness of management and potential outcomes and impacts;

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(iv) 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.

(v) 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;

(vi) 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;

(vii) 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;

(viii) 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;

(ix) review with management and monitor the funding exposure of the Corporation under the Corporation’s pension plans, annually review the Annual Pension Report and review and approve the financial statements applicable to each of the pension plans;

(x) annually or more frequently as deemed necessary, meet separately with management and the external auditors, and at least annually with the internal auditors, to review issues and matters of concern respecting audits and financial reporting processes;

(xi) 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;

(xii) 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;

(xiii) 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;

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(xiv) 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);

(xv) 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;

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

(xvii) 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

(xviii) 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.

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.

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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 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 of 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) meet separately with senior management, the internal auditors, the external auditors and, as is appropriate, internal and external legal counsel and independent advisors in respect of issues not elsewhere listed concerning any other audit, finance and risk matters;

(ii) 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;

(iii) 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;

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

(v) 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;

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

(vii) 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;

(e) risk management; and

(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 responsibilities to a subcommittee of the Committee. The Committee may, in its discretion, delegate to one or more of its members the authority to pre-approve any audit or non-audit services to be performed by the external auditors, provided that any such approvals are presented to the Committee at its next scheduled meeting.

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