EX-99.5 6 a11-5192_1ex99d5.htm EX-99.5 ANNUAL INFORMATION FORM OF THE REGISTRANT DATED FEBRUARY 18, 2011.

Exhibit 99.5

ENBRIDGE INC.

ANNUAL INFORMATION FORM

FOR THE YEAR ENDED DECEMBER 31, 2010

February 18, 2011

TABLE OF CONTENTS

	Page
Glossary	3

Presentation of Information	4

Forward-Looking Information	4

Corporate Structure	5

Description of the Business	6

General Development of the Business	8

Liquids Pipelines	11

Gas Distribution	14

Gas Pipelines, Processing and Energy Services	16

Sponsored Investments	20

Corporate	23

General	24

Corporate Social Responsibility	24

Environmental Matters	25

Risk Factors	25

Dividends	25

Description of Capital Structure	26

Market for Securities	28

Credit Facilities	29

Directors and Officers	29

Audit, Finance & Risk Committee	32

Legal Proceedings	34

Interest of Management and Others in Material Transactions	34

Registrar and Transfer Agent	35

Material Contracts	35

Interests of Experts	35

Additional Information	35

Appendix A – Audit, Finance & Risk Committee Terms of Reference	37

GLOSSARY

Adjusted earnings		Earnings applicable to common shareholders adjusted for non-recurring or non-operating factors

AFR Committee or the Committee		Audit, Finance & Risk Committee

AIF		Annual Information Form

bpd		Barrels per day

bps		Basis points

bcf		Billion cubic feet

bcf/d		Billion cubic feet per day

CAPP		Canadian Association of Petroleum Producers

CSR		Corporate Social Responsibility

EEM		Enbridge Energy Management, L.L.C. – Enbridge has a 17.2% investment in EEM, which owns 100% of EEP’s i-units

EEP		Enbridge Energy Partners, L.P. – Enbridge has a 25.5% ownership interest in EEP, which owns and operates crude oil and liquid petroleum transmission pipeline systems, natural gas gathering and related facilities and marketing assets in the United States

EGD		Enbridge Gas Distribution Inc. – 100% owned natural gas distribution utility serving customers in its franchise areas of Central and Eastern Ontario, including the City of Toronto and surrounding areas

EGNB		Enbridge Gas New Brunswick Inc. – Enbridge owns 100% of this natural gas distribution utility

EIF		Enbridge Income Fund – Enbridge has a 41.9% combined direct and indirect ownership interest and an overall 72% economic interest in this unincorporated open-ended trust

EIFH		Enbridge Income Fund Holdings Inc. – Enbridge has a 19.9% interest in this publicly traded corporation which owns 72.6% of the units of EIF

FERC		Federal Energy Regulatory Commission

GHG		Greenhouse gases

IR		Incentive Regulation (applicable to EGD)

ITS		Incentive Tolling Settlement on the Enbridge mainline system

MD&A		Management’s Discussion and Analysis

mmcf		Million cubic feet

mmcf/d		Million cubic feet per day

MTNs		Medium-term notes

NEB		National Energy Board

NGLs		Natural gas liquids

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

PwC		PricewaterhouseCoopers LLP – the Company’s external auditors

SEP		System Expansion Project

Year End		December 31, 2010

PRESENTATION OF INFORMATION

Unless otherwise noted, the information contained in this Annual Information Form (AIF) for Enbridge Inc. (Enbridge or the Company) is given at or for the year ended December 31, 2010 (Year End). Amounts are expressed in Canadian dollars unless otherwise indicated. Financial information is presented in accordance with Canadian generally accepted accounting principles (GAAP).

Enbridge’s Management’s Discussion and Analysis (MD&A), dated February 18, 2011, and Enbridge’s Audited Consolidated Financial Statements, dated February 18, 2011, as at and for the year ended December 31, 2010 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	35.3145

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 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 natural gas liquids; prices of crude oil, natural gas and natural gas liquids; 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 natural gas liquids, and the prices of these commodities, are material to and underlay 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 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 - 1st 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 Act of the Northwest Territories as Gallery Holdings Ltd.
December 15, 1987		Continued under the Canada Business Corporations Act under the name 159569 Canada Ltd.
May 5, 1994		Articles of Amendment to (i) change the name to IPL Energy Inc. (French version – IPL Energie Inc.); and (ii) change the registered office to Calgary, Alberta.
October 7, 1998		Articles of Amendment to change the name of the Company to Enbridge Inc.
April 29, 1999		Articles of Amendment to (i) divide each issued and outstanding common share on a two for one basis; and (ii) provide the Board of Directors with a process to add directors between meetings of the shareholders.
May 5, 2005		Articles of Amendment to divide each issued and outstanding common share on a two for one basis.

SUBSIDIARIES

The following organization chart presents the name and the jurisdiction of incorporation of Enbridge’s material subsidiaries as at December 31, 2010. 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, 2010. Unless otherwise indicated, the Company owns, directly or indirectly, 100% of the voting securities of all of the subsidiaries listed below.

1 The Company is the primary beneficiary of Enbridge Income Fund (EIF) through the combination of a total direct and indirect 41.9% equity interest and a preferred unit investment and, as such, EIF 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 a 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, and hybrid fuel cells. Enbridge employs approximately 6,400 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. Each business segment’s contribution to earnings and revenues is as follows:

	2010				2009				2008
	Revenue		Earnings		Revenue		Earnings		Revenue		Earnings
Liquids Pipelines	11	%	53	%	11	%	29	%	7	%	25	%
Gas Distribution	17	%	16	%	24	%	12	%	20	%	12	%
Gas Pipelines, Processing and Energy Services	70	%	13	%	62	%	27	%	71	%	58	%
Sponsored Investments	2	%	14	%	3	%	9	%	2	%	8	%
Corporate	-		4	%		-	23	%		-	(3	%)

The following map depicts the Company’s principal operations:

GENERAL DEVELOPMENT OF THE BUSINESS

In support of its long-term vision and objective, the Company employs several key strategies that guide decision making across the enterprise. The Company’s strategies include:

· focusing on project execution and operating excellence;

· leveraging the strategic location of its existing asset base;

· developing new platforms for growth and diversification;

· maintaining financial strength and flexibility; and

· developing people, safety and environmental stewardship, and corporate social responsibility.

Over the last three years Enbridge has placed into service over $12 billion in growth projects. In 2010 alone, Enbridge placed into service $6.5 billion of growth projects, 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. Enbridge has also secured over $6 billion in new infrastructure growth projects in strategically significant areas including the Canadian Oil Sands and Bakken formation, mid-west Texas and Louisiana shale gas plays and offshore natural gas and oil, as well as wind, solar and other renewable projects. In addition, the Company has a further $30 billion in growth opportunities under development, but not yet commercially secured, for the post-2011 period, of which it expects to be successful on a significant portion.

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

Project	Description		Actual / Estimated Capital Cost1	Actual / Expected In-Service Date

LIQUIDS PIPELINES
Southern Access Mainline Expansion - Canadian portion	–	mainline system expansion from Hardisty, Alberta to the Canada/United States border	$0.2 billion	2008
Waupisoo Pipeline	–	pipeline from Cheecham Terminal to Edmonton, Alberta	$0.6 billion	2008
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 portion2	–	new pipeline from Hardisty, Alberta to the Canada/United States border	$2.2 billion	2010
Southern Lights Pipeline2	–	new and reversed pipeline to transport diluent from Chicago, Illinois to Edmonton, Alberta	$0.5 billion + US$1.6 billion	Light Sour Line - 2009; Diluent Line - 2010
Christina Lake Lateral Project2	–	new terminal and pipeline to deliver increased production volumes directly into the Athabasca Pipeline	$0.3 billion	2011
Woodland Pipeline2	–	new pipeline from the Kearl oil sands mine to the Cheecham Terminal	$0.5 billion	2012
Edmonton Terminal Expansion2	–	expansion of tankage at the mainline terminal at Edmonton, Alberta	$0.3 billion	2011-2012 (in phases)
Wood Buffalo Pipeline2	–	new pipeline connecting the Athabasca Terminal to the Cheecham Terminal	$0.4 billion	2013
Norealis Pipeline2	–	new terminal and pipeline for the Sunrise Oil Sands Project and additional tankage at Cheecham	$0.5 billion	2013

Project	Description		Actual / Estimated Capital Cost1	Actual / Expected In-Service Date
Waupisoo Pipeline Expansion2	–	expansion of the pipeline for additional capacity	$0.4 billion	2013
Athabasca Pipeline Capacity Expansion2	–	expansion of the pipeline to its full capacity	$0.4 billion	2013-2014 (in phases)
Fort Hills Pipeline System2	–	new pipeline and terminaling services for the Fort Hills project	$2.0 billion	TBD (pending customer timing)

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 Project2	–	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 Project2	–	99 MW wind project located near Chatham, Ontario; power produced to be sold to the Ontario Power Authority	$0.3 billion	2010
Greenwich Wind Energy Project2	–	99 MW wind energy project located near Lake Superior, Ontario; power produced to be sold to the Ontario Power Authority	$0.3 billion	2011
Cedar Point Wind Energy Project2	–	250 MW wind project located near Denver, Colorado; power produced to be sold to the Public Service Company of Colorado grid	US$0.5 billion	2011
Amherstburg/Tilbury Solar Projects2	–	15 MW and 5 MW, respectively, solar energy facilities located in Ontario; power produced to be sold to the Ontario Power Authority	$0.1 billion	2011/2010
Venice Gas Processing Facility2	–	expansion of the condensate processing capacity to accommodate additional natural gas production	$0.2 billion	2013
Walker Ridge Gas Gathering System2	–	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
Big Foot Oil Pipeline2	–	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 portion2	–	new pipeline from the Canada/United States border to Superior, Wisconsin	US$1.2 billion	2010
EIF - Saskatchewan System Capacity Expansion2	–	three separate projects to reduce capacity constraints at a variety of locations	$0.1 billion	2010
EEP - Bakken Expansion Program2	–	joint project with EIF to expand crude oil pipeline capacity from the Bakken and	US$0.4 billion	2013

Project	Description		Actual / Estimated Capital Cost1	Actual / Expected In-Service Date
		Three Forks formations
EIF - Bakken Expansion Program2	–	joint project with EEP to expand crude oil pipeline capacity from the Bakken and Three Forks formations	$0.2 billion	2013

1 These amounts are actual costs or current estimates that are subject to upward or downward adjustment based on various factors.

2 The Company’s MD&A for the year ended 2010 includes further details on each of these projects as well as other projects Enbridge is currently undertaking.

In addition to placing into service the largest pipeline projects in the Company’s history, the Alberta Clipper and Southern Lights Pipeline projects, in 2010 the Company continued to focus on growth across all of its business segments, with key focus on expansion of oil sands infrastructure, further development in the Bakken formation, new green energy projects and opportunities in its natural gas businesses. In 2010, the Company reinforced its presence in the oil sands by securing six new growth and expansion projects that are expected to go into service between 2011 and 2014. These projects include expansion of the Company’s Athabasca Pipeline to its maximum capacity; expansion of the Waupisoo Pipeline; three new pipelines, the Woodland, Wood Buffalo and Norealis pipelines; and the Christina Lake Lateral project that will provide additional pipeline and terminal facilities to support expansion of the Christina Lake enhanced oil project. The Company will also expand its Edmonton Terminal facilities to accommodate growing oil sands production.

In 2010, the Company further solidified its competitive position in the Bakken region. The Company’s sponsored investment, Enbridge Income Fund, substantially completed expansion of its Saskatchewan System near the end of 2010, and announced a joint project with Enbridge Energy Partners, L.P. (EEP) to further develop its Bakken infrastructure. The Bakken Expansion Program, being constructed in North Dakota and Saskatchewan, will accommodate growing production from the Bakken and Three Forks formations and is expected to come into service in 2013.

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 continues 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. Early in 2011, additional investments in green energy were announced including the Amherstburg and Tilbury Solar Projects in Ontario.

In 2010, EEP, in which the Company holds an approximate 25.5% interest, grew its natural gas transportation and midstream businesses with the US$700 million acquisition of natural gas gathering and processing assets in the Granite Wash area of Texas. The Company is also advancing projects to provide natural gas gathering services to the Jack-St. Malo and Big Foot deepwater developments in the Gulf of Mexico, with completion expected in 2014.

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. In 2008, the Company sold its 25% equity interest in Compañía Logística de Hidrocarburos CLH, S.A. (CLH), Spain’s largest refined products transportation and storage business. Both of these investments were sold at very attractive prices and proceeds were utilized to fund North American expansion projects. Given the disposals of OCENSA and CLH, there are currently minimal operations in the Company’s international businesses; however, Enbridge continues to actively monitor the international business environment to identify potential new investment opportunities.

LIQUIDS PIPELINES

Liquids Pipelines consists of common carrier and contract crude oil, natural gas liquids (NGLs) and refined products pipelines and terminals in Canada and the United States, including the Enbridge System, the Enbridge Regional Oil Sands System, Southern Lights Pipeline and other feeder pipelines.

ENBRIDGE SYSTEM

The mainline system is comprised of the Enbridge System and the 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 Enbridge System and located in eastern Canada are two crude oil pipelines and one refined products pipeline with a combined capacity of 0.4 million bpd. Average system utilization in 2010 was 79% and it is expected to decrease in 2011 due to a combination of additional pipeline capacity being added to the system by the Company in 2010 and a new pipeline placed into service by a competitor during the year.

The following table sets forth the information related to deliveries and other distance-related operating data of the Enbridge and Lakehead Systems for each of the years in the three-year period ended December 31, 2010.

(thousands of barrels per day)	2010	2009	2008
Prairie Provinces
Light crude oil	227	173	161
Medium and heavy crude oil	230	165	142
Refined products	74	71	69
	531	409	372
United States
Light crude oil	364	397	316
Medium and heavy crude oil	840	834	875
Refined products	3	3	3
	1,207	1,234	1,194
Ontario1
Light crude oil	300	264	294
Medium and heavy crude oil	57	72	81
Refined products	73	75	89
	430	411	464
Total Deliveries	2,168	2,054	2,030
Barrel Miles (billions)	399	400	397
Average Haul (miles)	505	535	534

1 Enbridge System average deliveries include Line 9 (from Montreal to Ontario) volumes of 77,000 bpd (2009 - 67,000 bpd; 2008 - 111,000 bpd).

Incentive Tolling

Tolls on the Enbridge System are governed by various agreements, which are subject to the approval of the NEB. The NEB’s jurisdiction over the Enbridge System includes statutory authority over matters such as construction, rates and ratemaking agreements and other contractual arrangements with customers. Significant agreements include the incentive tolling settlement (ITS) applicable to the Enbridge mainline system (excluding Line 8 and Line 9), the Terrace agreement, the SEP II Risk Sharing agreement, the Alberta Clipper agreement and the Southern Access Expansion agreement which are recovered via the Mainline Expansion Toll. Tolls on the core mainline system have been governed by ITS since 1995, with the most recent ITS term effective through 2010. The Company has reached agreement with industry to roll forward the 2010 ITS agreement for a year and will file the 2011 ITS with the NEB in March 2011. The 2011 ITS has similar terms as the 2010 ITS. Discussions with industry continue for a longer term settlement agreement which will support a competitive toll structure.

Until all matters before the NEB are settled, interim tolls will continue to be collected for the Enbridge System.

The ITS agreement allows for continued throughput protection on the Canadian mainline, the flow through of costs not controllable by Enbridge and includes an earnings incentive mechanism for controllable costs. The NEB Line 9 hearing scheduled for September 2010 and the Alberta Clipper NEB hearing scheduled for November 2010 have been suspended while the Company and the intervenors pursue settlement discussions including the long-term Canadian mainline tolling agreement.

In conjunction with the Terrace Agreement, the 2010 ITS continues the throughput protection provisions included in earlier incentive tolling arrangements, ensuring the Company was largely insulated from volume fluctuations beyond its control. Accordingly the agreements establish tolls based on an agreed capacity and an allowed revenue requirement. Where actual volumes on the pipeline fall short of the agreed capacity and Enbridge is unable to fully collect its annual revenue requirement, the deficiency is collectible from shippers in the following year and a receivable, referred to as tolling deferrals, is recognized.

This basis may affect the timing of recognition of revenues compared with that otherwise expected under Canadian GAAP for companies that are not rate-regulated. As at December 31, 2010, $91 million (2009 - $98 million) was recorded as tolling deferrals.

Enbridge pays taxes each year only on the tolls collected in cash; therefore the tax payable on the tolling deferrals lags behind the recognition of the revenue. As the Terrace capacity is increasingly utilized, there will be less tolling deferrals recorded and more cash tolls collected. This will result in the Company paying taxes in future years on both the tolling deferral realization and the current year’s cash tolls.

ENBRIDGE REGIONAL OIL SANDS SYSTEM

Enbridge 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, which provides storage service, and three large terminals: the Athabasca Terminal located north of Fort McMurray, Alberta, the Cheecham Terminal, located 95 kilometres south of Fort McMurray where the Waupisoo Pipeline initiates, and the Hardisty Contract Terminal, one of the largest crude oil terminals in North America.

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 viscosity of crude being shipped. It is currently configured to transport approximately 345,000 bpd.

The Company has a long-term (30-year) take-or-pay contract with the major shipper on the Athabasca Pipeline which commenced in 1999. Revenue is recorded based on the contract terms negotiated with the major shipper, rather than the cash tolls collected.

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.

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 return on equity (ROE) with significant upside potential as incremental founders and third party volumes are added.

The Hardisty Contract Terminal, which is comprised of 19 tanks with a working capacity of approximately 7.5 million barrels of storage, was fully operational by October 1, 2009. In June 2010, the Company

acquired the remaining 50% of the Hardisty Caverns Limited Partnership (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 are generating revenues from storage and terminalling fees.

SOUTHERN LIGHTS PIPELINE

The 180,000 bpd, 20-inch diameter Southern Lights Pipeline was placed into service on July 1, 2010 and began transporting diluent from Chicago, Illinois to Edmonton, Alberta.

Enbridge receives tariffs under long-term (15-year) contracts with committed shippers. Tariffs provide for recovery of all operating and debt financing costs plus a ROE at a pre-determined rate. 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.

SPEARHEAD PIPELINE

Spearhead Pipeline delivers crude oil from Chicago, Illinois to Cushing, Oklahoma. The performance of this pipeline steadily increased and with further support of new committed shippers, the Spearhead Pipeline Expansion was completed in May 2009. This expansion increased the capacity from 125,000 bpd to 193,300 bpd from the new initiating point of Flanagan, Illinois to Cushing.

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 Pipeline 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 to Zama, Alberta; interests in a number of liquids pipelines in the United States; contract tankage facilities; and business development costs related to Liquids Pipelines activities.

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 will serve 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 to construct additional ex-Alberta capacity of 500,000 bpd to Nederland, Texas, for an in-service date during 2013. 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 Western Canadian Sedimentary Basin (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.

The Company continues to adapt to the changes in its business environment. Enbridge is committed to performance excellence and is focused on becoming more efficient, more collaborative, more innovative and more cost effective so that the Company can pass those benefits on to its customers through service, savings, reliability and responsiveness.

GAS DISTRIBUTION

Gas Distribution consists of the Company’s natural gas utility operations, the core of which is Enbridge Gas Distribution Inc. (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 2.0 million customers in central and eastern Ontario and parts of northern New York State. EGD’s utility operations are regulated by the Ontario Energy Board (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 resultant 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 impact 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, 2010, EGD acquired approximately 208 bcf (2009 – 194; 2008 - 194 bcf) of natural gas, of which 37% (2009 – 26%; 2008 - 27%) was acquired from Western Canadian producers, 42% (2009 – 46%; 2008 – 46%) was acquired from suppliers in Chicago and 22% (2009 – 29%; 2008 – 27%) was acquired on a delivered basis in Ontario.

Transportation

TransCanada Pipelines Ltd. (TransCanada) transports approximately 64.3% or 264 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 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.

EGD’s principal storage facilities are located in southwestern Ontario, near Dawn, and have a total working capacity of approximately 102 bcf.

Historical Operating Statistics

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

	2010		2009		2008
Gas supply and send out (million cubic feet (mmcf))
Natural gas purchased	206,511		195,268		193,315
Gas into storage	(101,279	)	(75,001	)	(100,019	)
Gas out of storage	90,512		79,536		97,719
Total gas sendout	195,744		199,803		191,015
Transportation of gas	214,736		223,503		246,170
	410,480		423,306		437,185
Gas sales to customers (mmcf)	195,921		194,679		188,780
Transportation of gas	197,121		213,117		243,878
Total sales	393,042		407,796		432,658
Used by EGD	212		205		148
Other volumetric variations	17,226		15,305		4,379
	410,480		423,306		437,185
Average daily sendout (mmcf)	1,130		1,158		1,197

Average use per residential customer (thousand cubic feet)	89		96		97
Heating degree days1
Actual	3,466		3,767		3,802
Forecast based on normal weather	3,546		3,514		3,543
Number of active customers at year end2
Residential	1,339,894		1,274,680		1,114,878
Commercial	117,461		111,276		105,056
Industrial	4,352		4,067		3,912
Wholesale	1		1		1
Transportation	518,716		547,241		674,382
	1,980,424		1,937,265		1,898,229
New customer additions3	37,023		32,275		41,297

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 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 Active customers is the number of 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 gas sales customers with no mark up, the composition of customers between gas sales and transportation service has no material impact on EGD’s earnings.

3 New customer additions 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 IR Framework) with customer representatives.

The objectives of the IR Framework 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.

Under the IR Framework, Enbridge 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. Enbridge estimates

the customer portion of 2010 earnings over the allowed threshold to be $19 million (2009 - $19 million).

Rate Adjustment Applications

In September 2010, EGD filed an application with the OEB to adjust rates for 2011 pursuant to the approved IR formula. The total distribution revenue applied for was approved by the OEB, with the rate adjustment being 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 Enbridge Gas New Brunswick (EGNB) (100% owned and operated by the Company), 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.

GAS PIPELINES, PROCESSING AND ENERGY SERVICES

Gas Pipelines, Processing and Energy Services consists of investments in natural gas pipelines, processing and green energy projects, the Company’s commodity marketing 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), Vector Pipeline and transmission and gathering pipelines in the Gulf of Mexico. Investments in processing includes the Company’s interest in Aux Sable, a natural gas fractionation and extraction business. The commodity marketing businesses manage the Company’s volume commitments on Alliance and Vector Pipelines, as well as perform commodity 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 in five major corridors in the Gulf of Mexico, extending to deepwater frontiers. These pipelines include almost 1,500 miles (2,400 kilometres) of underwater pipe and onshore facilities and transported approximately 2.2 bcf/d during 2010. Offshore currently moves approximately 50% 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 deliverability expectations.

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

The business model utilized on a go forward basis and included in the Walker Ridge Gas Gathering System and Big Foot commercially secured projects differs from the historic model. These new projects have a base level return which is locked in by 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.

Competitive Conditions

There is competition for new and existing business in the Gulf of Mexico. Offshore has been able to capture key opportunities, positioning it to more fully utilize existing capacity. Offshore serves a majority of the strategically located deepwater host platforms and its extensive presence in the deepwater Gulf of Mexico has Offshore well positioned to generate incremental revenues, with modest capital investment, by transporting production 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 recently announced Big Foot Oil Pipeline. Given rates of decline, offshore pipelines typically have available capacity, resulting in significant competition for new developments in the Gulf of Mexico. In July 2010, the Secretary of the Interior suspended deepwater drilling. Subsequently, in October 2010, the deepwater drilling suspension was lifted, allowing a return to deepwater drilling, but subject to increased regulation and approval.

ALLIANCE PIPELINE US

The Alliance System (Alliance), which includes both the Canadian and United States portions of the pipeline system, consists of an approximately 3,000-kilometre (1,875-mile) integrated, high-pressure natural gas transmission pipeline system and an approximately 730-kilometre (455-mile) lateral pipeline system and related infrastructure. Alliance transports liquids-rich natural gas from northeast British Columbia and northwest Alberta to Channahon, Illinois. Alliance Pipeline US and Alliance Pipeline Canada have firm service shipping contract capacity to deliver 1.365 bcf/d and 1.325 bcf/d, respectively. Enbridge owns 50% of Alliance Pipeline US, while EIF, described under Sponsored Investments, owns 50% of Alliance Pipeline Canada.

Alliance connects with Aux Sable, of which Enbridge owns 42.7%, a NGLs 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.

In September 2010, the Septimus Pipeline, a gathering pipeline owned by Aux Sable, was connected to a new receipt point on Alliance Pipeline Canada. This pipeline, with initial volumes of 20 million cubic feet per day (mmcf/d), sources liquids-rich gas from the Montney region. In 2009, Prairie Rose Pipeline, a gathering pipeline owned by a third party, was connected to a new gas receipt point on Alliance near Towner, North Dakota. This pipeline brings in associated rich gas from the Bakken formation on to Alliance. The new receipt point went into service in January 2010, with an initial firm transportation capacity of 40 mmcf/d, which will increase to 80 mmcf/d in 2011.

Transportation Contracts

Alliance Pipeline US has long-term, take-or-pay contracts to transport 1.345 bcf/d of natural gas or 98.5% of the total contracted capacity. Primary contract terms ending on December 1, 2015 are for 1.305 bcf/d, while contracts for 0.040 bcf/d have a contract term ending February 1, 2020. Alliance Pipeline US has an additional 20 mmcf/d of natural gas which is currently being contracted on a short term basis. These contracts permit Alliance 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%. Each long-term contract had the option of being renewed upon notice by November 30, 2010 for successive one-year terms beyond the original 15-year primary term. As noted below, shippers representing 8% of contracted capacity elected to extend their commitments. Alliance Pipeline US operations are regulated by the FERC.

Depreciation expense included in the cost of service is based on negotiated depreciation rates contained in the transportation contracts, while depreciation expense in the financial statements is recorded on a straight-line basis at 4% per annum. Negotiated depreciation expense is generally less than the financial statement amount at the beginning of the contract and higher than straight-line depreciation in the later

years of the shipper transportation agreements. This difference results in recognition of a long-term receivable, referred to as deferred transportation revenue that began being recovered from shippers, starting in 2009 for Alliance Pipeline US and 2012 for Alliance Pipeline Canada. As at December 31, 2010, $122 million (US$123 million) (2009 - $151 million (US$144 million)) was recorded as deferred transportation revenue for Alliance Pipeline US.

Alliance Pipeline Recontracting

In December 2010, shippers representing 8% of contracted capacity on the Alliance System elected to extend their existing contracts from December 1, 2015 to at least December 1, 2016. These shippers also retained the option of continuing to extend their capacity commitments on an annual basis. Remaining shippers, representing the balance of originally contracted capacity, have elected not to extend their commitments beyond 2015 under the terms of the original contracts. Alliance Pipeline US is entitled to additional compensation, in the form of accelerated depreciation recovered, from those shippers who have not elected to extend their contracts beyond 2015.

Currently, Alliance continues to be fully contracted on a firm service basis and is expected to run at or near full capacity for the foreseeable future given its geographic positioning and high pressure operating capability to move valuable liquids rich gas to market. Over the next five years, Alliance is expected to transition from a single-service, single toll export pipeline to a new multi-service business model, providing customers with a choice from an assortment of transportation services. Among other things, Alliance will seek to implement short-haul delivery and receipt services to complement its existing “bullet line” delivery service to Chicago and seek to provide greater shipper market liquidity through hub services. Also, Alliance is well placed to benefit from incremental unconventional volumes from shale gas plays in British Columbia, and is currently evaluating opportunities to expand its service offerings in this area. Rates for Alliance’s long haul service are expected to be favourable compared to other alternatives for reaching United States Midwest and eastern Canada markets.

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 to distribution systems in the Midwestern United States. In addition, there are several proposals to upgrade existing 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. 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 Company provides operating services to, and holds a 60% joint venture interest in, Vector Pipeline, which transports natural gas from Chicago, Illinois to Dawn, Ontario. Vector Pipeline has the capacity to deliver a nominal 1.3 bcf/d and is operating at or near capacity.

Vector Pipeline’s primary sources of supply are through interconnections with Alliance and the Northern Border Pipeline in Joliet, Illinois. 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; with the remaining capacity 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 Pipeline is an interstate natural gas pipeline with FERC and NEB approved tariffs establishing 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 2010, the FERC approved maximum tariff rates include an underlying weighted average after-tax ROE component of 11.18% (2009 - 11.07%; 2008 - 11.04%). On the Canadian portion, Vector Pipeline 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 2010, maximum tariff tolls include a ROE component of 10.48% after-tax.

Competitive Conditions

Vector Pipeline 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 Pipeline 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 Pipeline 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.

AUX SABLE

Enbridge owns 42.7% of Aux Sable, a NGLs extraction and fractionation business, which owns and operates a plant near Chicago, Illinois at the terminus of Alliance Pipeline. The plant extracts NGLs 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 commodity price 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 is responsible for the capacity on the Alliance Pipeline, held by an Aux Sable affiliate, at market rates. The BP agreement is for an initial term of 20 years, expiring December 21, 2025 and may be extended by mutual agreement for 10-year terms.

ENERGY SERVICES

Energy Services includes the Company’s energy marketing businesses. Tidal Energy provides crude oil and NGLs marketing services for the Company and its customers. This business involves buying, selling, transporting and storing crude oil and condensate. Tidal Energy 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 modest 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.

Energy Services’ natural gas marketing services are provided by both 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, 2010 and 2009 were 33 mmcf/d on Alliance (3% of capacity) and 156 mmcf/d on Vector Pipeline (12% of capacity). Earnings from these commitments are dependent upon the basis (location) differentials between Alberta and Chicago, for Alliance, and between Chicago and Dawn, for Vector Pipeline. 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, including Ontario Wind and Sarnia Solar, net of business development expenses associated with international activities.

In 2009, the Company sold its 24.7% interest in OCENSA, a crude oil export pipeline in Colombia. In 2008, the Company sold its 25% equity interest in CLH, Spain’s largest refined products transportation and storage business. Both of these investments were sold at very attractive prices 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 25.5% ownership interest in Enbridge Energy Partners, L.P. (EEP), Enbridge’s 66.7% investment in the United States segment of the Alberta Clipper Project through EEP and Enbridge Energy, L.P. (EELP) and an overall 72% economic interest in Enbridge Income Fund (EIF), held both directly and indirectly through Enbridge Income Fund Holdings Inc. (EIFH). 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 NGLs. The primary operations of EIF include a crude oil and liquids pipeline and gathering system, a 50% interest in the Canadian portion of Alliance Pipeline (Alliance Pipeline Canada) and partial interests in several green energy investments.

ENBRIDGE ENERGY PARTNERS

EEP owns and operates crude oil and liquid petroleum transportation and storage assets and natural gas gathering, treating, processing, transportation and marketing assets in the United States. Significant assets include the Lakehead System, which is the extension of the Enbridge System in the United States; 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.

In September 2010, EEP acquired the entities that comprise the Elk City Gathering and Processing System (Elk City System) from Atlas Pipeline Partners for US$700 million. The Elk City System extends from southwestern Oklahoma to Hemphill County in the Texas Panhandle. The Elk City System consists of approximately 1,290 kilometers (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 natural gas liquids production capability of 20,000 bpd.

In March 2008, Enbridge did not participate in EEP’s issuance of Class A units, resulting in a $5 million dilution gain and a decrease in ownership interest from 15.1% to 14.6%. In late 2008, Enbridge purchased 16.3 million Class A common units of EEP, resulting in an ownership increase to 27.0%. The Company’s average ownership interest in EEP during 2008 was 15.7%. At December 31, 2009, Enbridge’s ownership interest in EEP remained at 27.0%. In June 2010, EEP entered into an Equity Distribution Agreement (EDA) for the issue and sale of its Class A units up to an amount of $150 million. During 2010, EEP issued 1.1 million Class A units under the EDA. Enbridge did not fully participate resulting in a dilution gain of $4 million. In November 2010, Enbridge did not participate in EEP’s issuance of 6 million Class A units, resulting in a $32 million dilution gain and decreasing the Company’s ownership to 25.5%. The Company’s average ownership interest in EEP during 2010 was 26.7%.

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

Enbridge holds an approximate 25.5% combined direct and indirect ownership interest in EEP, which is accounted for as an equity investment. Subsidiaries of Enbridge provide services to EEP in connection with its operation of the Lakehead System.

Line 6B Leak

On July 26, 2010, a crude oil release on Line 6B of EEP’s Lakehead System was reported near Marshall, Michigan. EEP currently 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. Regulatory approval of the pipeline restart plan was obtained from the United States Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (PHMSA) and, on September 27, 2010, the pipeline was safely brought back into service. 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.

EEP previously estimated that before insurance recoveries, and not including fines and penalties, costs of approximately US$430 million ($75 million after-tax net to Enbridge), excluding lost revenue of approximately US$13 million ($2 million after-tax net to Enbridge), will be incurred in connection with this incident. These costs include emergency response, environmental remediation and cleanup activities associated with the crude oil release. EEP subsequently revised its estimate from US$430 million to US$550 million ($96 million after-tax net to Enbridge) based on a review of costs and commitments incurred, as well as additional information concerning the requirements for environmental restoration and remediation. The assumptions made including the scope of remediation efforts, the duration that resources will be required to complete the work, weather conditions and other similar factors underlying EEP’s estimates are subject to further modification and could result in additional revisions to EEP’s estimates. Although EEP met the deadlines established by the Environmental Protection Agency (EPA) for clean up and remediation of areas affected by the crude oil release, it has the potential of incurring additional costs in connection with this incident, including fines and penalties.

Line 6A Leak

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 currently estimates 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 will 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). Actual costs incurred may differ from the estimate due to variations in assumptions or in any or all of the categories described above, including modified or revised requirements from regulatory agencies or other factors.

Insurance Recoveries

The Company maintains commercial liability insurance coverage that is consistent with coverage considered customary for its industry. The commercial liability insurance covers costs associated with environmental incidents such as those incurred for the leaks from Line 6B and 6A, excluding costs for fines and penalties. EEP is included in Enbridge’s comprehensive insurance program that has an aggregate limit of US$650 million of pollution liability through the policy renewal date of May 1, 2011. The remaining coverage under the Company’s existing insurance policies is approximately US$70 million. The Company does not maintain insurance coverage for interruption of operations except for water crossings; therefore, EEP will not recover approximately US$16 million of revenues lost while Line 6B and 6A were not in service.

Apart from the amounts for which EEP is not insured, it is anticipated that substantially all of the costs incurred from the leaks will ultimately be recoverable under the Company’s existing insurance policies. EEP expects to record a receivable for any amounts claimed for recovery pursuant to its insurance policies during the period that it deems realization of the claim for recovery is probable.

Pipeline Integrity Commitment

In connection with the restart of Line 6B, EEP committed to accelerate a process, initiated prior to the leak, to perform additional inspections, testing and refurbishment of Line 6B within and beyond the immediate area of the July 26, 2010 incident. Pursuant to this agreement, EEP is remediating on schedule those pipeline anomalies it previously identified between 2007 and 2009 that were scheduled for refurbishment, including anomalies identified for action in a July 2010 PHMSA notification. EEP has agreed to complete all required work within 180 days of the September 27, 2010 restart of Line 6B. 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. The total cost to EEP for these integrity measures and pipeline replacement are estimated to approximate US$110 million, the majority of which is expected to be capital in nature. Additional significant integrity expenditures may be required after this initial remediation program. EEP is currently discussing with its customers recovery of these costs through the tolls on its Lakehead System.

Legal and Regulatory Proceedings

A number of United States governmental agencies and regulators have initiated investigations into the Line 6B and Line 6A incidents. Currently, approximately 20 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 incident; however, currently no penalties or fines have been assessed against EEP in connection with this incident. Currently, one action or claim related to the Line 6A incident has been filed against Enbridge, EEP or their affiliates in a United States state court. The Company believes this action or claim has been resolved pursuant to an agreed interim order.

Competitive Conditions

EEP’s Lakehead System, the United States portion of the Enbridge System, is a major crude oil export route 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 in the Company’s year end MD&A. EEP’s Mid-Continent system and North Dakota system also face competition from existing competing pipelines, proposed future pipelines, and alternative gathering facilities available to producers or the ability of the producers to build such gathering facilities. Competition for EEP’s storage facilities include 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 NGLs 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 competitors that are substantially larger than EEP.

ENBRIDGE ENERGY, L.P. – 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 and represented allowance for equity funds used during construction (AEDC) recognized while the project was under construction. The Alberta Clipper Project was placed into service on April 1, 2010.

ENBRIDGE INCOME FUND

EIF’s primary assets include a 50% interest in Alliance Pipeline Canada and the 100%-owned Saskatchewan System, both acquired from the Company in 2003. Alliance Pipeline Canada is the Canadian portion of Alliance previously described in the Gas Pipelines, Processing and Energy Services segment. The Saskatchewan System owns and operates crude oil and liquids pipelines systems in southern Saskatchewan and southwestern Manitoba, connecting primarily with Enbridge’s mainline pipeline to the United States. In December 2010, Phase II of the Saskatchewan System Capacity Expansion was completed, increasing capacity across the system by approximately 125,000 bpd.

EIF also owns interests in three wind power generation projects purchased from Enbridge in October 2006 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 EIF took effect. Under the Plan all publicly held trust units and 5 million units held by Enbridge, were exchanged on a one-for-one basis for shares of a taxable Canadian corporation, EIFH. The business of EIFH is limited to investment in EIF. In connection with this exchange, Enbridge as holder of Enbridge Commercial Trust (ECT) Preferred Units was granted a right of exchange whereby Enbridge may exchange such ECT Preferred Units for EIF

Trust Units on a one-for-one basis. Concurrently, the liquidity right which provided Enbridge as the holder of ECT Preferred Units the option to request redemption was terminated.

The Company retained its overall 72% economic interest in EIF and is the primary beneficiary of EIF both before and after the Plan through a combined direct and indirect investment in EIF voting units and a non-voting preferred unit investment. As such, Enbridge consolidates EIF under variable interest entity accounting rules.

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. Further, 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.

CORPORATE

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

NOVERCO

Enbridge owns an equity interest in Noverco through ownership of 32.1% of the common shares and a cost investment in preferred shares. Noverco is a holding company that owns approximately 71.0% 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 states of New England. 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. The reorganization was effective September 30, 2010.

The Company announced on February 3, 2011 that it will invest $145 million to acquire an additional 6.8% interest in Noverco from Laurentides Investissements (SAS), a subsidiary of GDF SUEZ, bringing its total interest in Noverco to 38.9%. Trencap, a partnership managed by the Caisse de Depot et Placement du Quebec, will acquire Laurentides Investissements’ remaining 10.8% interest in Noverco, following which Enbridge and Trencap will become the sole shareholders of Noverco. The transaction is expected to close later in the year once all regulatory approvals have been received.

Weather variations do not affect Noverco’s earnings as Gaz Metro is not exposed to weather risk. A significant portion of the Company’s earnings from Noverco is in the form of dividends on its preferred share investment, which is based on the yield of 10-year Government of Canada bonds plus 4.34%.

GENERAL

EMPLOYEES

At December 31, 2010, Enbridge employed 6,357 employees as set forth in the following table.

Liquids Pipelines		1,812
Gas Distribution1		2,105
Gas Pipelines, Processing and Energy Services		711
Sponsored Investments 2		1,467
Corporate		262
		6,357

1 Approximately 10% of the Company’s workforce is represented either by the Communications, Energy and Paperworkers Union, Local 975 (CEPU) or the International Brotherhood of Electrical Workers (IBEW), Local 97. A two-year collective agreement for CEPU expired on December 31, 2010 and the Company is continuing negotiations for a new agreement. The current collective agreement for IBEW expires February 2011 and a new four-year agreement has been negotiated with a term from February 19, 2011 to February 18, 2015.

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

CORPORATE SOCIAL RESPONSIBILITY

Enbridge has strong corporate social responsibility practices. Enbridge defines corporate social responsibility as conducting business in an ethical and responsible way, protecting the environment and the health and safety of people, supporting human rights and engaging, respecting and supporting the communities and cultures with which the Company works. Enbridge’s 2010 Corporate Social Responsibility Report can be found at http://www.enbridge.com/AboutEnbridge/CorporateSocialResponsibility/CSRReports.aspx. None of the information contained on, or connected to, the Enbridge website is incorporated or otherwise part of this AIF.

In 2009, the Company launched an enterprise-wide goal of achieving a neutral environmental footprint by 2015. The goal consists of three key commitments:

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

· we will conserve an acre of natural or wilderness land for every acre we permanently impact from the construction of new facilities; and

· we will generate a kilowatt hour of renewable energy, through our investments in renewable energy, for each kilowatt hour of power consumed by our operations.

Land impacts will be addressed as soon as practically possible, but within five years of the in-service date of the project responsible for triggering the neutral footprint obligation. To achieve its neutral footprint goal, Enbridge is working with the Nature Conservancy of Canada and will work with nature conservancies in the United States to help purchase natural wilderness lands throughout North America. Progress on the Company’s neutral footprint initiative include:

· 155,000 trees removed; 150,000 tree seedlings planted;

· 624 acres disturbed; 1,118 acres conserved through the Nature Conservancy of Canada; and

· electricity consumption is forecast to increase, over the 2008 consumption level, by 1,077 gigawatts per hour (GWh) by 2015; Enbridge’s existing renewable power generating facilities and those under construction will produce approximately 2,170 GWh.

ENVIRONMENTAL MATTERS

CLIMATE CHANGE LEGISLATION

The Canadian Federal Government has indicated that Canada will target a 17% reduction of GHG emissions by 2020, based on 2006 emission levels. It has also signaled that 90% of Canada’s electricity will be provided by non-emitting sources, such as hydro, nuclear, clean-coal, solar and wind, by 2020. Details of Canada’s GHG management plan will not be released until there is clarity in the United States about its intention to regulate GHG emissions. Canadian regulations are expected to be compatible with those of the United States in order for Canadian businesses to remain competitive and avoid the potential for punitive trade sanctions. It is uncertain how climate legislation could affect the industry. Enbridge continues to monitor developments.

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. Dividends on the Preferred Shares, Series A, are fixed and are paid quarterly.

There are no restrictions that currently prevent the Company from paying dividends. However, in the event of liquidation, dissolution or winding-up of the Company, the preferred shareholders have priority in the payment of dividends over the common shareholders. As well, restrictions in credit or financing agreements entered into by the Company or provisions of applicable law may preclude the payment of dividends in certain circumstances.

The following table shows dividends paid in 2010, 2009 and 2008:

(Canadian dollars per share)	2010	2009	2008
Common Shares	1.700	1.480	1.320
Preferred Shares, Series A	1.375	1.375	1.375

DESCRIPTION OF CAPITAL STRUCTURE

SHARE CAPITAL

Enbridge’s authorized share capital consists of an unlimited number of Common Shares with no par value and an unlimited number of preferred shares. At Year End, there were approximately 385 million Common Shares and five million Series A Preferred Shares issued and outstanding.

On February 18, 2011, the Company’s Board of Directors approved a recommendation that shareholders approve a two-for-one stock split at the Company’s Annual and Special Meeting of Shareholders on May 11, 2011. If approved by shareholders on May 11, 2011, and subject to regulatory approvals, the record date for the stock split is expected to be May 25, 2011.

Common Shares

Holders of Common Shares are entitled to receive dividends if, as and when declared by the Board of Directors of the Company. Holders of Common Shares are entitled to receive notice of and to attend all meetings of shareholders 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 Company’s outstanding common shares without complying with certain provisions set out in the plan, or without approval of the Company’s 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 of the Company at a 50% discount to the market price at that time. The plan was reconfirmed at the 2005 and 2008 annual meetings of shareholders and must be reconfirmed at every third annual meeting thereafter. The renewal of this plan will be proposed for approval at the 2011 shareholders’ meeting.

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.

Enbridge also has stock-based compensation plans that allow employees to purchase Common Shares of the Company. 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.

Preferred Shares

The five million 5.5% Cumulative Redeemable Preferred Shares, Series A are entitled to fixed, cumulative, quarterly preferential dividends of $1.375 per share per year. The Company may, at its option, redeem all or a portion of the outstanding preferred shares for $25 per share plus all accrued and unpaid dividends.

Preferred 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 Preferred Shares before the issue of such series. Holders of the Preferred Shares are not entitled to vote at any meeting of the shareholders of the Company, except as required by law. Preferred Shares are entitled to priority over the Common Shares of the Company with respect to the payment of dividends and the distribution of assets of the Company in the event of any liquidation, dissolution or winding up of the Company’s affairs.

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

Preferred Shares, Series A, 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
Preferred Shares, Series A	Pfd-2 (low)	Baa3	BBB
MTNs and Unsecured Debt	A	Baa1	A-
Commercial Paper	R-1 (low)	Not Rated	A-1 (low)
Rating Outlook	Stable	Stable	Stable

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 Enbridge’s Preferred 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 rating assigned to Enbridge’s MTNs and unsecured debentures is the third highest of eight categories for long-term debt. While A is a respectable rating, entities in this category may be vulnerable to future events, but qualifying negative factors that exist are considered manageable. Long-term debt rated A 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 different 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 Enbridge’s Preferred 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 Enbridge’s preferred 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 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

The Common Shares of the Company are traded on the Toronto Stock Exchange (TSX) in Canada, the principal market for Enbridge’s common shares, and on the New York Stock Exchange (NYSE) in the United States under the symbol ENB. The following table sets forth the monthly price range and volume traded for Enbridge’s Common Shares on the TSX and NYSE.

	TSX (ENB)				NYSE (ENB)
	High ($)	Low ($)	Close ($)	Volume Traded	High (US$)	Low (US$)	Close (US$)	Volume Traded
January 2010	49.00	46.15	46.41	15,860,985	47.24	43.25	43.47	2,724,063
February 2010	47.98	46.03	46.64	14,530,034	45.21	43.13	44.28	2,864,080
March 2010	49.64	46.48	48.44	18,293,025	48.84	44.43	47.75	2,072,424
April 2010	51.18	48.40	49.33	13,681,642	51.12	47.88	48.31	1,929,732
May 2010	50.00	46.10	47.62	23,235,065	49.44	42.59	44.84	4,396,979
June 2010	50.04	46.63	49.58	19,419,037	49.24	44.30	46.60	4,145,901
July 2010	52.32	48.50	50.04	19,146,185	50.52	45.70	48.64	3,279,048
August 2010	53.53	49.57	53.05	23,444,001	51.14	47.37	49.75	2,747,994
September 2010	54.15	51.03	53.89	24,636,581	52.52	49.32	52.30	2,812,408
October 2010	56.52	53.74	56.41	14,217,786	55.40	52.30	55.40	1,944,526
November 2010	57.47	54.16	57.14	20,274,361	56.92	53.51	55.69	2,097,028
December 2010	58.25	54.69	56.27	23,542,725	57.83	54.15	56.40	2,335,352

In addition, the Company’s Preferred Shares, Series A are traded on the TSX under the symbol ENB.PR.A. The following table sets forth the monthly price range and volume traded for Enbridge’s Preferred Shares.

	High ($)	Low ($)	Close ($)	Volume Traded
January 2010	25.97	24.75	25.19	230,286
February 2010	25.21	24.75	24.76	79,217
March 2010	25.11	24.45	24.45	82,779
April 2010	24.48	23.75	24.01	76,587
May 2010	24.88	23.67	23.70	73,262
June 2010	24.60	23.30	24.26	65,424
July 2010	25.10	24.29	24.80	48,120
August 2010	25.44	24.73	24.84	89,467
September 2010	25.49	25.05	25.36	44,427
October 2010	25.85	25.10	25.68	61,532
November 2010	25.85	25.20	25.31	56,079
December 2010	25.56	25.04	25.45	68,740

The following table outlines the securities issued by the Company and its wholly-owned subsidiaries that are reporting issuers during 2010 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 Inc.	$500	4.53%	March 8, 2010	March 9, 2020	$99.984
Enbridge Inc.	$200	4.26%	September 28, 2010	February 1, 2021	$99.955
Enbridge Inc.	$100	5.12%	September 28, 2010	September 28, 2040	$100.000
Enbridge Gas Distribution Inc.	$200	4.04%	November 22, 2010	November 23, 2020	$99.959
Enbridge Gas Distribution Inc.	$200	4.95%	November 22, 2010	November 22, 2050	$99.792
Enbridge Pipelines Inc.	$350	4.45%	April 6, 2010	April 6, 2020	$99.960
Enbridge Pipelines Inc.	$300	5.33%	April 6, 2010	April 6, 2040	$99.985
Enbridge Pipelines Inc.	$250	2.93%	September 7, 2010	September 8, 2015	$99.977

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. Enbridge also has credit facilities that bear interest at market rates.

CREDIT FACILITIES

Credit facilities carry a weighted average standby fee of 0.20% 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 2011 to 2014.

(millions of Canadian dollars)
December 31, 2010	Expiry Dates2	Total Facilities	Credit Facility Draws	3	Available
Liquids Pipelines	2012	200	26		174
Gas Distribution	2011 - 2012	717	334		383
Sponsored Investments	2012	300	130		170
Corporate	2012 - 2014	4,631	2,826		1,805
		5,848	3,316		2,532
Southern Lights project financing1	2012 - 2014	1,697	1,504		193
Total Credit Facilities		7,545	4,820		2,725

1 Total facilities inclusive of $60 million for debt service reserve letters of credit.

2 Includes $30 million in demand facilities with no maturity date.

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

DIRECTORS AND OFFICERS

As at December 31, 2010, the directors and all officers of Enbridge (including the executive officers listed below) as a group beneficially owned, directly or indirectly, 1,583,743 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 on February 18, 2011, 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 (except where otherwise noted). 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 Since1
David A. Arledge Naples, Florida USA	Corporate Director. Chair of the Board of Directors of Enbridge Inc. since 2005.	2002
James J. Blanchard2 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
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 Weston, 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. Leslie3 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. Group Vice President, Transportation South of Enbridge Inc., President of Enbridge Energy Company, Inc. and Enbridge Energy Management L.L.C. from 2001 to 2006.	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.

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 2010 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
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 18, 2011, their municipality 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.
Janet A. Holder Toronto, Ontario Canada	President, Gas Distribution	President, Gas Distribution since October 2010 and President, Enbridge Gas Distribution Inc. since January 2008. Vice President, Support Services, Enbridge Pipelines Inc. from April 2006 to January 2008. Vice President, Market Services from 2004 to April 2006.
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. Senior Vice President, Corporate Planning & Development from June 2003 to September 2006.
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. Group Vice President & Chief Financial Officer from April 2003 to May 2006.


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. Group Vice President, Liquids Pipelines from May 2005 to May 2006.
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 February 2010 to October 2010. Group Vice President, Corporate Law from June 2006 to February 2010. Partner, Stikeman Elliott LLP (law firm) from February 2004 to June 2006.
D. Guy Jarvis Calgary, Alberta Canada	Senior Vice President, Investor Relations & Enterprise Risk	Senior Vice President, Investor Relations & Enterprise Risk since October 2010. 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.
John K. Whelen Calgary, Alberta Canada	Senior Vice President, Corporate Development	Senior Vice President, Corporate Development since September 2006. Vice President & Treasurer from February 2002 to August 2006.

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 of Directors 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.

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 of Directors 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 of Directors 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 of Directors 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 of Directors 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 of Directors 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 and board 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 Canadian Oil Sands Limited since its inception and was Chairman until 2009.

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.

PRE-APPROVAL POLICIES AND PROCEDURES

The AFR Committee has adopted a policy that requires pre-approval by the Committee of any services to be provided by the external auditors, PricewaterhouseCoopers LLP (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 former employees of the auditors who provided more than 10 hours of audit, review or attest services for the Company or its subsidiaries within the one year preceding the commencement of the audit of the current year’s financial statements.

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 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, 2010 and 2009.


	2010	2009	Description of Fee Category
Audit Fees	$4,202,285	$4,085,718	Represents the aggregate fees for audit services.
Audit-Related Fees	151,501	822,734	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 2010 and 2009, the services provided in this category included due diligence related to prospectus offerings and other items. Services provided in fiscal 2009 also included work performed in relation to the new Customer Information System in EGD.
Tax Fees	712,742	388,091	Represents the aggregate fees for professional services rendered by the Company’s auditors for tax compliance, tax advice and tax planning.
All Other Fees	1,435,327	1,004,061	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 International Financial Reporting Standards (IFRS), Canadian Public Accountability Board fees, French translation work and process reviews.
Total Fees	$6,501,855	$6,300,604

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, 2010.

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 Company1:

In Canada:
CIBC Mellon Trust Company
P.O. Box 7010, Adelaide Street Postal Station
Toronto, Ontario M5C 2W9
Telephone: 1-800-387-0825 or
416-643-5500 outside of North America
Website: www.cibcmellon.com/investorinquiry

In the United States:
BNY Mellon Shareowner Services
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 Company’s Preferred Shares, Series A is CIBC Mellon Trust Company1:

In Canada:

CIBC Mellon Trust Company

P.O. Box 7010, Adelaide Street Postal Station

Toronto, Ontario M5C 2W9

Telephone: 1-800-387-0825 or

416-643-5500 outside of North America

Website: www.cibcmellon.com/investorinquiry

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 auditors are PricewaterhouseCoopers LLP, Chartered Accountants. PwC has issued an auditors’ report in respect of Enbridge’s consolidated financial statements, with accompanying notes, as at December 31, 2010 and 2009 and for each of the years in the three year period ended December 31, 2010. PwC has also provided an opinion on the effectiveness of internal control over financial reporting as at December 31, 2010. Both of these opinions are dated February 18, 2011.

PwC has advised that it is independent with respect to Enbridge within the meaning of the Rules of Professional Conduct of the Institute of Chartered Accountants of Alberta and the rules of the United States Securities and Exchange Commission.

ADDITIONAL INFORMATION

Additional information about Enbridge is available on our website at www.enbridge.com and on SEDAR (System for Electronic Document Analysis and Retrieval) 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 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 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 EIF can be found in its Annual Report and AIF filed with Canadian Securities Administrators in Canada. The AIF and the Annual Report, which includes Consolidated Financial Statements and MD&A, contain detailed disclosure with respect to the Enbridge Income Fund and are publicly available at www.sedar.com. EIF’s Annual Report, Consolidated Financial Statements, MD&A and AIF are not incorporated by reference into this AIF.

Enbridge Income Fund Holdings Inc.

Additional information about EIFH can be found in its Annual Report and AIF filed with Canadian Securities Administrators in Canada. The AIF and the Annual Report, which includes Consolidated Financial Statements and MD&A, contain detailed disclosure with respect to the Enbridge Income Fund Holdings Inc. and are publicly available at www.sedar.com. EIFH’s Annual Report, Consolidated Financial Statements, MD&A and AIF 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 available at www.sedar.com. These documents are not incorporated by reference into this AIF.

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.

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:

(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;

(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;

(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.

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; and

(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;

(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.