UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C.  20549

FORM 6-K

Report of Foreign Issuer

Pursuant to Rule 13a-16 or 15d-16 of

the Securities Exchange Act of 1934

Dated  May 11, 2011

Commission file number 001-15254

ENBRIDGE INC.

(Exact name of Registrant as specified in its charter)

3000, 425 – 1st Street S.W.
Calgary, Alberta, Canada  T2P 3L8

(Address of principal executive offices and postal code)

(403) 231-3900

(Registrants telephone number, including area code)

Indicate by check mark whether the Registrant files or will file annual reports under cover of Form 20-F or Form 40-F.

Indicate by check mark if the Registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1):

Indicate by check mark if the Registrant is submitting the Form 6-K in paper as permitted by regulation S-T Rule 101(b)(7):

Indicate by check mark whether the Registrant by furnishing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934.

If “Yes” is marked, indicate below the file number assigned to the Registrant in connection with Rule 12g3-2(b):

N/A

THIS REPORT ON FORM 6-K SHALL BE DEEMED TO BE INCORPORATED BY REFERENCE IN THE REGISTRATION STATEMENTS ON FORM S-8 (FILE NO. 333-145236, 333-127265, 333-13456, 333-97305 AND 333-6436), FORM F-3 (FILE NO. 33-77022) AND FORM F-10 (FILE NO. 333-152607 AND 333-170200) OF ENBRIDGE INC. AND TO BE PART THEREOF FROM THE DATE ON WHICH THIS REPORT IS FURNISHED, TO THE EXTENT NOT SUPERSEDED BY DOCUMENTS OR REPORTS SUBSEQUENTLY FILED OR FURNISHED.

The following documents are being submitted herewith:

·    Press Release dated May 11, 2011.

·    Interim Report to Shareholders for the three months ended March 31, 2011.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

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NEWS RELEASE

Enbridge reports first quarter adjusted earnings of $334 million or $0.89 per common share

HIGHLIGHTS

(all financial figures are unaudited and in Canadian dollars)

·                  First quarter earnings increased 15% to $393 million

·                  First quarter adjusted earnings increased 5% to $334 million

·                  Agreement reached with shippers for 10-year Competitive Toll Settlement on Canadian Mainline system

·                  $600 million of investments in renewable power, U.S. natural gas gathering and processing, Quebec gas distribution, and Ontario storage were initiated since the beginning of the year

·                  Enbridge named one of the Global 100 Most Sustainable Corporations, one of Canada’s Greenest Employers and a member of the FTSE4Good Index

CALGARY, ALBERTA, May 11, 2011 – Enbridge Inc. (TSX:ENB) (NYSE:ENB) “The steady performance of Enbridge’s liquids pipelines, gas transportation, gas distribution and green energy businesses continued to deliver solid earnings for the Company and its shareholders during the first quarter,” said Patrick D. Daniel, President and Chief Executive Officer. “With first quarter adjusted earnings of $334 million, or $0.89 per share, we are starting the year a little stronger than we had expected and so we are firmly on track to achieve our full year adjusted earnings guidance of $2.75 to $2.95 per share.

“The dividend paid in the first quarter of 2011 represented a 15% increase, reflecting sustained strong growth in 2010, and we expect future dividend growth to continue to benefit from strong growth in earnings and cash flow per share.”

A significant achievement in the first quarter, and one that is expected to contribute to the long-term sustainability of earnings from Enbridge’s Canadian Mainline system, was the agreement reached with shippers on a 10-year Competitive Toll Settlement (CTS).

“We are very pleased with the settlement we’ve reached. The CTS builds on what has been a long-standing history of successful incentive arrangements between Enbridge and the shipping community, and will even further align the interests of Enbridge and our shippers for the next 10 years,” said Mr. Daniel. “The CTS will provide a stable and competitive toll to shippers. Compared to competing alternatives, the CTS will ensure Western Canadian producers receive the strongest pricing and Midwestern US refiners the lowest supply cost. As such, the CTS reinforces the competitive position of our mainline system, enabling us to preserve and enhance throughput.”

CTS provides Enbridge with a powerful strategic tool to capture incremental volumes through market extensions that can be accessed from Enbridge’s mainline system through new or existing downstream pipelines.

Forward-Looking Information

This news release contains forward-looking information. Significant related assumptions and risk factors are described under the Forward-Looking Information section of this news release.

“We’re confident that this agreement will enable us to continue to deliver attractive returns under conservative throughput assumptions, further reinforcing our expectation of a 10% average growth rate in adjusted earnings per share through the middle of this decade.”

Growth initiatives in the first quarter included the acquisition of the Amherstburg and Tilbury solar projects in Ontario, adding a combined 20 MW of renewable generating capacity to Enbridge’s green energy portfolio. In gas transportation, the Company announced the US$150 million expansion of the condensate processing capacity of its Venice, Louisiana facility to accommodate additional offshore natural gas production. Enbridge will increase its interests in gas distribution and gas pipelines in Quebec, and gas and electric power distribution and transmission assets in Vermont, through an increased investment in Noverco. The $145 million investment, which brings Enbridge’s total interest in Noverco to 38.9%, is expected to close later in the year once all regulatory approvals have been received. Enbridge Gas Distribution (EGD) commenced expansion of its unregulated natural gas storage capacity during the quarter. Last week, Enbridge Energy Partners, L.P. announced plans to invest an additional US$0.2 billion to expand its East Texas system.

“We have substantial balance sheet capacity for financing our large suite of secured projects plus those under development,” said Mr. Daniel. “We brought $12 billion in projects into service over the past three years, we have secured more than $6 billion in projects that will come into service between 2011 and 2014 and have another $30 billion under development. The recently announced proposed transfer of three of our Ontario renewable energy projects to Enbridge Income Fund for $1.3 billion would further reinforce our financial capacity to undertake the large suite of attractive investment opportunities we are developing.”

In January, Enbridge was recognized as one of the Corporate Knights Global 100 Most Sustainable Corporations, and in March, FTSE Group reaffirmed Enbridge’s membership in the FTSE4Good Index series which identifies companies that meet globally recognized corporate responsibility standards. In April, Enbridge was named one of Canada’s Greenest Employers.

“Over the course of 2011, and beyond, we expect to continue to deliver on our investment proposition. said Mr. Daniel. “Enbridge offers visible and sustained earnings growth, a substantial and growing dividend and a reliable business model – a unique and proven combination of attributes that delivers superior returns to our investors.”

Mr. Daniel will address investors at Enbridge’s Annual and Special Meeting of Shareholders this afternoon. Shareholders will vote on various matters including a proposed two-for-one stock split.

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FIRST QUARTER 2011 OVERVIEW

For more information on Enbridge’s growth projects and operating results, please see the Management’s Discussion and Analysis (MD&A) which is filed on SEDAR and EDGAR and also available on the Company’s website at www.enbridge.com/InvestorRelations.aspx.

·                  Enbridge’s first quarter results included earnings from assets placed into service in 2010, including Alberta Clipper and Southern Lights Pipeline, as well as the Enbridge Energy Partners, L.P. (EEP) acquisition of the Elk City System in September 2010. The Company benefited from positive or stable earnings contributions from all of its business segments.

·                  On May 4, 2011, a proposal by Enbridge to Enbridge Income Fund (the Fund) to transfer three renewable energy assets to the Fund at an aggregate price of $1.3 billion was announced. The proposed transfer is subject to all necessary approvals including approval by the Board of Trustees of the Fund, the Board of Directors of Enbridge Income Fund Holdings Inc. (ENF) and regulatory approval. ENF and the Fund have formed a joint special committee comprised of independent trustees and directors to review the proposal and make recommendations to their respective Boards. If approved and completed, the transfer would further reinforce Enbridge’s financial capacity to undertake attractive investment opportunities under development.

·                  On April 28, 2011, EEP announced that it plans to invest an additional $0.2 billion to expand its East Texas system. EEP has signed long-term agreements with several major natural gas producers on the Texas side of the Haynesville shale to provide gathering, treating and transmission services. The projects involve construction of gathering and related market outlet pipelines and related treating facilities.

·                  On March 16, 2011, Enbridge announced that agreement had been reached with shippers on its Canadian Mainline system with respect to the principal terms of a 10-year CTS. The CTS, which remains subject to approval by the National Energy Board (NEB), was filed with the NEB on May 2, 2011 and is intended to be effective July 1, 2011.

The CTS covers local tolls to be charged for service on the Canadian Mainline and supersedes all existing toll agreements on the Canadian Mainline during the term of the CTS. Under the terms of the CTS, the initial Canadian local toll will be based on the 2011 Incentive Tolling Settlement (ITS) recently approved by the NEB. The Canadian local toll will then be adjusted by 75% of the Canada Gross Domestic Product at Market Price Index for each of the remaining nine years of the settlement. Local tolls for service on the Lakehead System (the portion of the mainline in the United States that is owned by the Company’s affiliate EEP) will not be affected by the CTS and will continue to be established by EEP’s existing toll agreements. The CTS also provides for an International Joint Tariff (IJT) for crude oil shipments originating in Canada on the Canadian Mainline and delivered in the United States off the Lakehead System and into Eastern Canada. The IJT is designed to provide mainline shippers with a stable and competitive long-term toll, preserving and enhancing throughput on both the Canadian Mainline and Lakehead System. If the CTS is approved by the NEB, the shippers who initiated the Alberta Clipper hearing request with the NEB will withdraw their complaints.

·                  In February, Enbridge announced that its Board of Directors will recommend that shareholders approve a two-for-one stock split at the Company’s Annual and Special Meeting of Shareholders on May 11, 2011. In addition to shareholder approval, the stock split is subject to regulatory approvals. Upon completion of the stock split, the number of outstanding common shares would double from approximately 387 million to approximately 774 million.

·                  Enbridge announced on February 3, 2011 that it will invest $0.1 billion to acquire an additional 6.8% interest in Noverco, bringing its total interest in Noverco to 38.9%. The transaction is expected to close later in the year once all regulatory approvals have been received. Noverco is a holding company that owns 71% of the Gaz Metro Limited Partnership which owns gas distribution and gas pipelines assets in the province of Quebec and gas and electric power distribution and transmission assets in the State of Vermont.

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·                  On February 1, 2011, Enbridge announced agreements to acquire two new solar energy projects totaling 20 MW generating capacity from First Solar Inc. (First Solar) for $0.1 billion. The 5-MW Tilbury Solar Project, completed in December 2010, is located in Tilbury, Ontario. The Amherstburg II Solar Project, located in Amherstburg, Ontario, consists of two separate facilities that, together, total 15 MW. First Solar constructed (and, in the case of the Amherstburg II Solar Project, is constructing) the projects for Enbridge under fixed price engineering, procurement and construction contracts. The Amherstburg II Solar Project is expected to be complete in the third quarter of 2011. Enbridge will sell the facilities’ power output to the Ontario Power Authority pursuant to 20-year Power Purchase Agreements under the terms of the Ontario Government’s Renewable Energy Standard Offer Program.

·                  On January 31, 2011, Enbridge announced plans for an estimated US$0.2 billion expansion of the condensate processing capacity of its Venice, Louisiana facility within its offshore gas business. The expanded condensate processing capacity will be required to accommodate additional natural gas production from the recently sanctioned Olympus offshore oil and gas development. Natural gas production from Olympus will move to Enbridge’s onshore facility at Venice via Enbridge’s Mississippi Canyon offshore pipeline where it will be processed to separate and stabilize the condensate. The expansion, which will more than double the capacity of the facility to approximately 12,000 barrels of condensate per day, is expected to be in service in late 2013.

·                  During the first quarter of 2011, Enbridge commenced execution of the Nexus Project, which is a 4.5 billion cubic feet (bcf) expansion of EGD’s unregulated natural gas storage facility at Tecumseh, near Sarnia, Ontario. The project is secured by a long-term commercial contract and construction will begin in the second quarter of 2011 and finish early in the fourth quarter of 2011. The project, with an expected capital cost of $42 million, has received regulatory approval and is currently on schedule.

DIVIDEND DECLARATION

On April 28, 2011, the Enbridge Board of Directors declared quarterly dividends of $0.49 per common share and $0.34375 per Series A Preferred Share. Both dividends are payable on June 1, 2011 to shareholders of record on May 13, 2011.

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CONFERENCE CALL

Enbridge will hold a conference call on Wednesday, May 11, 2011 at 9:00 a.m. Eastern time (7:00 a.m. Mountain time) to discuss the first quarter 2011 results. Analysts, members of the media and other interested parties can access the call at +617-614-3922 or toll-free at 1-800-291-5365 using the access code of 96103684. The call will be audio webcast live at www.enbridge.com/InvestorRelations.aspx. A webcast replay and podcast will be available approximately two hours after the conclusion of the event and a transcript will be posted to the website within 24 hours. The replay at toll-free 1-888-286-8010 or +617-801-6888 (access code 29951201) will be available until May 18, 2011.

The conference call will begin with a presentation by the Company’s Chief Executive Officer and Chief Financial Officer followed by a question and answer period for investment analysts. A question and answer period for members of the media will immediately follow.

The unaudited interim Consolidated Financial Statements and MD&A, which contain additional notes and disclosures, are available on the Enbridge website at www.enbridge.com/InvestorRelations.aspx.

Enbridge Inc., a Canadian company, is a North American leader in delivering energy and one of the Global 100 Most Sustainable Corporations. As a transporter of energy, Enbridge operates, in Canada and the U.S., the world’s longest crude oil and liquids transportation system. The Company also has a growing involvement in the natural gas transmission and midstream businesses, and is expanding its interests in renewable and green energy technologies including wind and solar energy, hybrid fuel cells and carbon dioxide sequestration. 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. Enbridge employs approximately 6,400 people, primarily in Canada and the U.S., and is ranked as one of Canada’s Greenest Employers and one of the Top 100 Companies to Work for in Canada. Enbridge’s common shares trade on the Toronto and New York stock exchanges under the symbol ENB. For more information, visit www.enbridge.com

Forward-Looking Information

Forward-looking information, or forward-looking statements, have been included in this news release 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

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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 news release 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 news release 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.

Non-GAAP Measures

This news release contains references to adjusted earnings/(loss), which represent earnings or loss attributable to common shareholders adjusted for non-recurring or non-operating factors on both a consolidated and segmented basis. These factors are reconciled and discussed in the financial results sections for the affected business segments. Management believes that the presentation of adjusted earnings/(loss) provides useful information to investors and shareholders as it provides increased transparency and predictive value. Management uses adjusted earnings/(loss) to set targets, assess performance of the Company and set the Company’s dividend payout target. Adjusted earnings/(loss) and adjusted earnings/(loss) for each of the segments are not measures that have a standardized meaning prescribed by Canadian generally accepted accounting principles (Canadian GAAP) and are not considered GAAP measures; therefore, these measures may not be comparable with similar measures presented by other issuers. See Non-GAAP Reconciliations for a reconciliation of the GAAP and non-GAAP measures.

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HIGHLIGHTS

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1                  Adjusted earnings represent earnings attributable to common shareholders adjusted for non-recurring or non-operating factors. Adjusted earnings and adjusted earnings per common share are non-GAAP measures that do not have any standardized meaning prescribed by GAAP.

2                  Canadian Mainline includes deliveries in Western Canada and to the Lakehead System at the United States border as well as Line 8 and Line 9 in Eastern Canada.

3                  Volumes are for the Athabasca mainline and Waupisoo Pipeline and exclude laterals on the Regional Oil Sands System.

4                  Number of active customers is the number of natural gas consuming Enbridge Gas Distribution customers at the end of the period.

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

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ENBRIDGE INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS

March 31, 2011

MANAGEMENT’S DISCUSSION AND ANALYSIS

FOR THE THREE MONTHS ENDED MARCH 31, 2011

This Management’s Discussion and Analysis (MD&A) dated May 10, 2011 should be read in conjunction with the unaudited consolidated financial statements and notes thereto of Enbridge Inc. (Enbridge or the Company) as at and for the three months ended March 31, 2011, which are prepared in accordance with Part V - Pre-changeover Accounting Standards of the Canadian Institute of Chartered Accountants (CICA) Handbook (Canadian GAAP or Part V). It should also be read in conjunction with the audited consolidated financial statements and MD&A contained in the Company’s Annual Report for the year ended December 31, 2010. All financial measures presented in this MD&A are expressed in Canadian dollars, unless otherwise indicated. Additional information related to the Company, including its Annual Information Form, is available on SEDAR at www.sedar.com and on the Company’s website at www.enbridge.com.

CONSOLIDATED EARNINGS

Earnings attributable to common shareholders were $393 million for the three months ended March 31, 2011, or $1.05 per common share, compared with $342 million, or $0.93 per common share, for the three months ended March 31, 2010. This increase primarily reflected increased earnings from Enbridge Gas Distribution (EGD) due to colder weather as well as higher earnings in Sponsored Investments. Earnings from net unrealized fair value gains related to the revaluation of financial derivatives used to risk manage commodity price and foreign exchange rate fluctuations also contributed to the increase in consolidated earnings

FORWARD-LOOKING INFORMATION

Forward-looking information, or forward-looking statements, have been included in this MD&A 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

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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 MD&A 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 MD&A 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.

NON-GAAP MEASURES

This MD&A contains references to adjusted earnings/(loss), which represent earnings or loss attributable to common shareholders adjusted for non-recurring or non-operating factors on both a consolidated and segmented basis. These factors are reconciled and discussed in the financial results sections for the affected business segments. Management believes that the presentation of adjusted earnings/(loss) provides useful information to investors and shareholders as it provides increased transparency and predictive value. Management uses adjusted earnings/(loss) to set targets, assess performance of the Company and set the Company’s dividend payout target. Adjusted earnings/(loss) and adjusted earnings/(loss) for each of the segments are not measures that have a standardized meaning prescribed by Canadian GAAP and are not considered GAAP measures; therefore, these measures may not be comparable with similar measures presented by other issuers. See Non-GAAP Reconciliations for a reconciliation of the GAAP and non-GAAP measures.

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ADJUSTED EARNINGS

Adjusted earnings were $334 million, or $0.89 per common share, for the three months ended March 31, 2011 compared with $318 million, or $0.86 per common share, for the three months ended March 31, 2010. The increase resulted from positive contributions from almost all of the Company’s business segments, including the following:

·                  Within Liquids Pipelines, increased contributions from Regional Oil Sands System and Spearhead Pipeline partially offset by lower earnings from Canadian Mainline, Southern Lights Pipeline and Feeder Pipelines and Other.

·                  Continued positive performance at EGD reflecting favourable operating performance under the current Incentive Regulation (IR) term.

·                  Higher earnings for Sponsored Investments as a result of increased earnings from Alberta Clipper entering service in April 2010 as well as an increased contribution from Enbridge Income Fund (the Fund).

RECENT DEVELOPMENTS

LIQUIDS PIPELINES

Competitive Toll Settlement

On March 16, 2011, Enbridge announced that agreement had been reached with shippers on its Canadian Mainline system with respect to the principal terms of a 10-year Competitive Toll Settlement (CTS). The CTS, which remains subject to approval by the National Energy Board (NEB), was filed with the NEB on May 2, 2011 and is intended to be effective July 1, 2011.

The CTS covers local tolls to be charged for service on the Canadian Mainline and supersedes all existing toll agreements on the Canadian Mainline during the term of the CTS. Under the terms of the CTS, the initial Canadian local toll will be based on the 2011 Incentive Tolling Settlement (ITS) recently approved by the NEB. The Canadian local toll will then be adjusted by 75% of the Canada Gross Domestic Product at Market Price Index for each of the remaining nine years of the settlement. Local tolls for service on the Lakehead System (the portion of the mainline in the United States that is owned by the Company’s affiliate Enbridge Energy Partners, L.P. (EEP)) will not be affected by the CTS and will continue to be established by EEP’s existing toll agreements. The CTS also provides for an International Joint Tariff (IJT) for crude oil shipments originating in Canada on the Canadian Mainline and delivered in the United States off the Lakehead System and into Eastern Canada. The IJT is designed to provide mainline shippers with a stable and competitive long-term toll, preserving and enhancing throughput on both the Canadian Mainline and Lakehead System. If the CTS is approved by the NEB, the shippers who initiated the Alberta Clipper hearing request with the NEB will withdraw their complaints.

Christina Lake Lateral Project

The Christina Lake Lateral Project includes a new pipeline terminal and blended products pipeline, which will allow the Cenovus and ConocoPhillips partnership to deliver increased Christina Lake production volumes directly into the Athabasca Pipeline. The expansion project will add two 375,000 barrel tanks and

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26 kilometres (16 miles) of 30-inch diameter pipeline to the existing Christina Lake lateral and terminal facilities, which include two eight-inch lateral lines plus 240,000 barrels of tankage, that connect to the Athabasca Pipeline. The estimated cost of the additional facilities is approximately $0.3 billion, with expenditures to date of approximately $0.1 billion. The facilities are expected to be in service in the third quarter of 2011.

Woodland Pipeline

Enbridge entered into a joint venture agreement with Imperial Oil Resources Ventures Limited (Imperial Oil) and ExxonMobil Canada Properties (ExxonMobil) to provide for the transportation of blended bitumen from the Kearl oil sands mine to crude oil hubs in the Edmonton, Alberta area. The project will be phased with the mine expansion, with the first phase involving construction of a new 140-kilometre (87-mile) 36-inch diameter pipeline from the mine to the Cheecham Terminal, and service on Enbridge’s existing Waupisoo Pipeline from Cheecham to the Edmonton area. The new Woodland Pipeline may be extended from Cheecham to Edmonton as part of future industry expansions. The Woodland Pipeline is being undertaken as a joint venture between Enbridge, Imperial Oil and ExxonMobil. Regulatory approval for the Phase I facilities was received from the Energy Resources Conservation Board (ERCB) in June 2010 and construction is underway. The total estimated cost of the Phase I pipeline from the mine to the Cheecham Terminal and related facilities is approximately $0.5 billion, with expenditures to date of approximately $0.1 billion. Enbridge expects the pipeline will come into service in late 2012.

Edmonton Terminal Expansion

The Edmonton Terminal Expansion Project involves expanding the tankage of the mainline terminal at Edmonton, Alberta by one million barrels at an estimated cost of $0.3 billion. The expansion is required to accommodate growing oil sands production receipts both from Enbridge’s Waupisoo Pipeline and other non-Enbridge pipelines. The expansion will be conducted over two phases and will consist of the construction of four tanks and the installation of three booster pumps and related infrastructure. With regulatory approval received in the first quarter of 2011, the expansion is expected to be completed in 2012.

Wood Buffalo Pipeline

Enbridge entered into an agreement with Suncor Energy Inc. to construct a new, 95-kilometre (59-mile) 30-inch diameter crude oil pipeline, connecting the Athabasca Terminal, which is adjacent to Suncor’s oil sands plant, to the Cheecham Terminal, which is the origin point of Enbridge’s Waupisoo Pipeline. The Waupisoo Pipeline already delivers crude oil from several oil sands projects to the Edmonton mainline hub. The new Wood Buffalo pipeline will parallel the existing Athabasca Pipeline between the Athabasca and Cheecham Terminals. The estimated capital cost is approximately $0.4 billion. With regulatory approval received in the first quarter of 2011, the new pipeline is expected to be in service by late 2012.

Norealis Pipeline

In order to provide pipeline and terminaling services to the proposed Husky-operated Sunrise Oil Sands Project, the Company will construct a new originating terminal (Norealis Terminal), a 112-kilometre (66-mile) 24-inch diameter pipeline (Norealis Pipeline) from the proposed Norealis Terminal to the Cheecham Terminal, and additional tankage at Cheecham. The estimated cost of the project is approximately $0.5 billion. Subject to regulatory approval, the facilities are expected to be in service in late 2013.

Waupisoo Pipeline Expansion

The Waupisoo Pipeline Expansion, which received regulatory approval in November 2010, will provide 65,000 barrels per day (bpd) of additional capacity in the second half of 2012 and an estimated 190,000 bpd of additional capacity in the second half of 2013 when the expansion is fully in service. The project will accommodate recent additional shipper commitments of 229,000 bpd. The estimated cost of the project is approximately $0.4 billion.

Athabasca Pipeline Capacity Expansion

The Company will undertake an expansion of its Athabasca Pipeline to its full capacity to accommodate additional contractual commitments including recent incremental shipping commitments by the Christina Lake Oilsands Project operated by Cenovus. This expansion will increase the capacity of the Athabasca

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Pipeline to its maximum capacity of approximately 570,000 bpd, depending on crude slate. The estimated cost of this full expansion is approximately $0.4 billion with an expected in service date of 2013 for an initial 430,000 bpd of capacity with the balance of the capacity expected to be available by early 2014, subject to regulatory approval. The Athabasca Pipeline transports crude oil from various oil sands projects to the mainline hub at Hardisty, Alberta.

Northern Gateway Project

The Northern Gateway Project involves constructing a twin 1,177-kilometre (731-mile) pipeline system from near Edmonton, Alberta, to a new marine terminal in Kitimat, British Columbia. One pipeline would transport crude oil for export from the Edmonton area to Kitimat and is proposed to be a 36-inch diameter line with an initial capacity of 525,000 bpd. The other pipeline would be used to import condensate and is proposed to be a 20-inch diameter line with an initial capacity of 193,000 bpd.

Northern Gateway submitted an application to the NEB on May 27, 2010. The Joint Review Panel (JRP) established to review the proposed project, pursuant to the NEB Act and the Canadian Environmental Assessment Act, has a broad mandate to assess the potential environmental effects of the project and to determine if it is in the public interest. The JRP conducted sessions with the public, including Aboriginal groups, to receive comments on the draft List of Issues, additional information which Northern Gateway should be required to file and locations for the oral hearings. The JRP decided to obtain these comments prior to issuing a Hearing Order or initiating further procedural steps in the joint review process. On January 19, 2011, the JRP advised that prior to issuing a procedural order it requires additional detail on the design and risk assessment of the pipelines. This information, together with other updates regarding the project, was provided to the JRP in March 2011. The JRP subsequently issued a Hearing Order outlining the procedures to be followed and has indicated that hearing will be held starting in January 2012.

Subject to continued commercial support, regulatory and other approvals, and adequately addressing landowner and local community concerns (including those of Aboriginal communities), the Company estimates that Northern Gateway could be in service by late 2016 at the earliest, at an estimated cost of $5.5 billion. Expenditures to date, which relate primarily to the regulatory process, are approximately $0.2 billion, including $0.1 billion in funding secured from Western Canada producers and Pacific Rim refiners toward the costs of seeking the necessary regulatory approvals for the project. Given the many uncertainties surrounding the Northern Gateway Project, including final ownership structure, the potential financial impact of the project cannot be determined at this time.

The JRP posts public filings related to Northern Gateway on its website at http://gatewaypanel.review-examen.gc.ca/clf-nsi/hm-eng.html and Enbridge also maintains a Northern Gateway Project website in addition to information available on www.enbridge.com. The full regulatory application submitted to the NEB and the 2010 Enbridge Northern Gateway Corporate Social Responsibility Report are available on www.northerngateway.ca. None of the information contained on, or connected to, the JRP website, the Northern Gateway Project website or Enbridge’s website is incorporated in or otherwise part of this MD&A.

GAS DISTRIBUTION

Nexus Project

The Nexus Project is a 4.5 billion cubic feet (bcf) expansion of EGD’s unregulated natural gas storage facility at Tecumseh, near Sarnia, Ontario. The project is secured by a long-term commercial contract and construction will begin in the second quarter of 2011 and finish early in the fourth quarter of 2011. The project, with an expected capital cost of $42 million, has received regulatory approval and is currently on schedule.

GAS PIPELINES, PROCESSING AND ENERGY SERVICES

Greenwich Wind Energy Project

The Company is developing the 99-megawatt (MW) Greenwich Wind Energy Project on the northern shore of Lake Superior in Ontario with Renewable Energy Systems Canada Inc. (RES Canada). Enbridge has a 90% interest in the project and an option to acquire the remaining 10% interest. RES Canada is constructing the project under a fixed price, turnkey, engineering, procurement and construction agreement. The project utilizes 43 Siemens 2.3-MW wind turbines and, under a multi-year fixed price agreement, Siemens will provide operations and maintenance services for the wind turbines. The Greenwich Wind Energy Project will deliver energy to the Ontario Power Authority (OPA) under a 20-year power purchase agreement. The project is on schedule and is expected to be completed in the third quarter of 2011. Enbridge’s total estimated cost of construction is $0.3 billion, with expenditures to date of approximately $0.2 billion.

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Cedar Point Wind Energy Project

Enbridge is developing the 250-MW Cedar Point Wind Energy Project near Denver, Colorado with Renewable Energy Systems America Inc. (RES Americas), at an expected cost of approximately US$0.5 billion. RES Americas is constructing the wind project under a fixed price, turnkey, engineering, procurement and construction agreement. The project is comprised of 139 Vestas V90 1.8-MW wind turbines on 20,000 acres of leased private land. The Cedar Point Wind Energy Project will deliver electricity into the Public Service Company of Colorado grid under a 20-year, fixed price power purchase agreement. The project is on schedule and is expected to be completed in the fourth quarter of 2011, with expenditures to date of approximately US$0.4 billion.

Neal Hot Springs Geothermal Project

The Company has partnered with U.S. Geothermal Inc. to develop the 35-MW Neal Hot Springs Geothermal Project located in Malheur County, Oregon. U.S. Geothermal is constructing the plant and will operate the facility. The project is anticipated to be completed in the second quarter of 2012 and will deliver electricity to the Idaho Power grid under a 25-year power purchase agreement. Construction on the project has begun and Enbridge will invest up to approximately $24 million for a 20% interest in the project.

Amherstburg and Tilbury Solar Projects

The Company has entered into agreements to acquire two new solar energy projects totaling 20-MW generating capacity from First Solar Inc. (First Solar) for approximately $0.1 billion. The 5-MW Tilbury Solar Project, completed in December 2010, is located in Tilbury, Ontario. The Amherstburg II Solar Project, located in Amherstburg, Ontario, consists of two separate projects of 10-MW and 5-MW each. First Solar constructed (and, in the case of the Amherstburg II Solar Project, is constructing) the projects for Enbridge under fixed price engineering, procurement and construction contracts. The Amherstburg II Solar Project is expected to be complete in the third quarter of 2011. Enbridge will sell the facilities’ power output to the OPA pursuant to 20-year power purchase agreements.

Venice Gas Processing Facility

In January 2011, the Company announced plans for an estimated US$0.2 billion expansion of the condensate processing capacity of its Venice, Louisiana facility within its offshore gas business. The expanded condensate processing capacity will be required to accommodate additional natural gas production from the recently sanctioned Olympus offshore oil and gas development. Natural gas production from Olympus will move to Enbridge’s onshore facility at Venice via Enbridge’s Mississippi Canyon offshore pipeline where it will be processed to separate and stabilize the condensate. The expansion, which will more than double the capacity of the facility to approximately 12,000 barrels of condensate per day, is expected to be in service in late 2013.

Walker Ridge Gas Gathering System

The Company executed definitive agreements in the last quarter of 2010 with Chevron USA Inc. and Union Oil Company of California to expand its central Gulf of Mexico offshore pipeline system. Under the terms of the agreements, Enbridge will construct, own and operate the Walker Ridge Gas Gathering System (WRGGS) to provide natural gas gathering services to the proposed Jack, St. Malo and Big Foot ultra-deepwater developments. The WRGGS includes 274 kilometres (170 miles) of 8-inch or 10-inch diameter pipeline at depths of up to approximately 2,150 meters (7,000 feet) with capacity of 0.1 billion cubic feet per day (bcf/d). WRGGS is expected to be in service in 2014 and is expected to cost approximately US$0.4 billion.

Big Foot Oil Pipeline

The Company executed definitive agreements in March 2011 with Chevron USA, Inc., Statoil Gulf of Mexico LLC and Marubeni Oil & Gas (USA) Inc. to construct and operate a 64-kilometre (40-mile) 20-inch oil pipeline with capacity of 100,000 bpd from the proposed Big Foot ultra-deepwater development in the Gulf of Mexico. This crude oil pipeline project is complementary to Enbridge’s plans to construct the WRGGS. The estimated cost of the Big Foot Oil Pipeline, which will be located about 274 kilometres (170 miles) south of the coast of Louisiana, is approximately US$0.2 billion and it is expected to be in service in 2014.

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SPONSORED INVESTMENTS

Bakken Expansion Program

EEP and the Fund will proceed, subject to regulatory approvals, with a joint project to further expand crude oil pipeline capacity to accommodate growing production from the Bakken and Three Forks formations located in Montana, North Dakota, Saskatchewan and Manitoba. The Bakken Expansion Program will increase takeaway capacity from the Bakken area by an initial 145,000 bpd, which can be readily expanded to 325,000 bpd. The Bakken Expansion Program will involve United States projects undertaken by EEP at a cost of approximately US$0.4 billion and Canadian projects undertaken by the Fund at a cost of approximately $0.2 billion. As of August 2010, EEP and the Fund had received sufficient long-term shipping commitments from anchor shippers to enable the Bakken Expansion Program to proceed. A binding open season subsequently conducted to enable other shippers to secure capacity on the expansion at the same terms as the anchor shippers was successfully concluded in February 2011 with commitments received for an aggregate of 100,000 bpd of capacity. The Bakken Expansion Program is expected to be completed in the first quarter of 2013.

Enbridge Energy Partners, L.P.

South Haynesville Shale Expansion

On April 28, 2011, EEP announced that it plans to invest an additional US$0.2 billion to expand its East Texas system. EEP has signed long-term agreements with several major natural gas producers on the Texas side of the Haynesville shale to provide gathering, treating and transmission services. The projects involve construction of gathering and related market outlet pipelines and related treating facilities.

Two-for-One Stock Split

On April 25, 2011, EEP announced the completion of a two-for-one split of its Common Unit and i-Units. The two-for-one split was effected by a distribution of one unit for each unit outstanding and held by holder of record on April 7, 2011. The units started trading on a post-split basis on the New York Stock Exchange beginning at the opening of trading on April 25, 2011. Enbridge Energy Management (EEM) also announced the completion of a two-for-one split of its listed shares and voting shares.

Cushing Terminal Storage Expansion Project

EEP is constructing nine new storage tanks at the Cushing Terminal with an approximate shell capacity of 3.2 million barrels. The estimated cost of the expansion is US$0.1 billion. The project is expected to be in service in early 2012.

Enbridge Income Fund

On May 4, 2011, a proposal by Enbridge to the Fund to transfer three renewable energy assets to the Fund at an aggregate price of $1.3 billion was announced. The proposed transfer is subject to all necessary approvals including approval by the Board of Trustees of the Fund, the Board of Directors of Enbridge Income Fund Holdings Inc. (ENF) and regulatory approval. ENF and the Fund have formed a joint special committee comprised of independent trustees and directors to review the proposal and make recommendations to their respective Boards. If approved and completed, the transfer would further reinforce Enbridge’s financial capacity to undertake attractive investment opportunities under development.

EEP LAKEHEAD SYSTEM LINE 6B AND 6A CRUDE OIL RELEASES

Enbridge holds an approximate 25.3% 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 Crude Oil Release

EEP continues to make progress on the clean up, remediation and restoration of the areas affected by the Line 6B crude oil release. A significant portion of the effort to clean up, remediate and restore the areas affected by the Line 6B release was performed by the end of 2010; however, remediation of the identified sites continues. EEP expects to make payments for additional costs associated with remediation and restoration of the area, air and groundwater monitoring, along with other legal, professional and regulatory costs through future periods. All of the initiatives EEP undertakes in the monitoring and restoration phases are intended to restore the incident area to the satisfaction of the appropriate regulatory authorities.

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EEP did not revise its US$550 million ($96 million after-tax net to Enbridge) cost estimate for this incident at March 31, 2011 based on a review of costs and commitments incurred as well as evaluation of additional information regarding requirements for environmental restoration and remediation. The expected losses associated with the Line 6B crude oil release includes those costs that are considered probable and that could be reasonably estimated at March 31, 2011. The estimates do not include amounts capitalized or any unasserted fines, penalties and claims associated with the release that may later become evident. Despite the efforts EEP has made to ensure the reasonableness of its estimates, changes to the recorded amounts associated with this release are reasonably possible as more reliable information becomes available. EEP has the potential of incurring additional costs in connection with this incident due to variations in any or all of the cost categories including modified or revised requirements from regulatory agencies in addition to fines and penalties as well as expenditures associated with litigation and settlement of claims.

Line 6A Crude Oil Release

EEP has substantially completed the clean up, remediation and restoration of the areas affected by the crude oil release from Line 6A of its Lakehead System. In connection with this incident, EEP has not changed its original estimate that it will incur aggregate costs of approximately US$45 million ($7 million after-tax net to Enbridge), before insurance recoveries and excluding fines and penalties. EEP has the potential to incur additional costs in connection with this incident, including fines and penalties as well as expenditures associated with litigation.

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 releases from Lines 6A and 6B, excluding costs for fines and penalties. EEP is included in Enbridge’s comprehensive insurance program that has an aggregate limit of US$650 million for pollution liability through the policy renewal date of May 1, 2011. Apart from the amounts for which EEP is not insured, it is anticipated that substantially all of the costs incurred from the releases will ultimately be recoverable under the Company’s existing insurance policies. In the first quarter of 2011, EEP recognized US$35 million ($5 million after-tax net to Enbridge) of insurance recoveries for claims filed in connection with the Line 6B release. EEP expects to record a receivable for any additional 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 release, 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 with the United States Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (PHMSA), EEP completed remediation of those pipeline anomalies it identified between 2007 and 2009 that were scheduled for refurbishment, including anomalies identified for action in a July 2010 PHMSA notification, on schedule within 180 days of the September 27, 2010 restart of Line 6B, as required. In addition to the required integrity measures, EEP also agreed to replace a 3,600 foot section of the Line 6B pipeline that lies underneath the St. Clair River in Michigan within one year of the restart of Line 6B, subject to obtaining required permits. A new line was installed beneath the St. Clair River in March 2011 and is scheduled for tie-in during June 2011. Additional integrity expenditures, which could be significant, may be required after this initial remediation program. The pipeline integrity and replacement costs will be capitalized or expensed in accordance with EEP’s capitalization policies as these costs are incurred, the majority of which are expected to be capital in nature.

In February 2011, EEP filed a tariff supplement with the Federal Energy Regulatory Commission (FERC), to be effective April 1, 2011, for recovery of US$175 million of capital costs and US$5 million of operating costs which are related to the 2010/2011 Line 6B integrity program. These costs include costs associated with the PHMSA Corrective Action Order and other required integrity work.

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Legal and Regulatory Proceedings

A number of United States governmental agencies and regulators have initiated investigations into the Line 6A and Line 6B incidents. Currently, approximately 25 actions or claims have been filed against Enbridge, EEP or their affiliates in United States federal and state courts in connection with the Line 6B incident, including direct actions, actions seeking class status and actions seeking derivative status. With respect to the Line 6B incident, no penalties or fines have been assessed against Enbridge, EEP or their affiliates to-date. One claim related to the Line 6A incident has been filed against Enbridge, EEP or their affiliates by the State of Illinois in a United States state court. The parties are operating under an agreed interim order which is expected to mature into a final order in the near future, thereby resolving the proceeding.

FINANCIAL RESULTS

LIQUIDS PIPELINES

Earnings for the three months ended March 31, 2011 were $136 million compared with $134 million for the three months ended March 31, 2010. The earnings increase was due to higher contributions from Regional Oil Sands System and Spearhead Pipeline partially offset by lower earnings from the Canadian Mainline, Southern Lights Pipeline and Feeder Pipelines and Other.

Canadian Mainline earnings were $82 million for the three months ended March 31, 2011 compared with $84 million for the three months ended March 31, 2010. Current period earnings are comparable with the prior year reflecting similar ITS terms and operating performance in both years as well as an increase in revenue from allowance oil sales offset by lower throughput and average tolls on Line 9. Also included in Canadian Mainline earnings for the first quarter of 2011 were in-service earnings from Alberta Clipper compared with AEDC recognized while the project was under construction in the first quarter of 2010. Canadian Mainline earnings for the first quarter of 2011 were governed by the 2011 ITS which will remain in effect until it is superseded by the CTS.

Regional Oil Sands System earnings increased as a result of higher shipped volumes and increased tolls on certain laterals as well as an increased contribution from Hardisty Caverns Limited Partnership which is now wholly-owned by the Company. Other factors contributing to the increase included lower depreciation expense due to extended estimated useful lives of certain assets reflecting increased probable reservoir supply and commercial viability.

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The decrease in Southern Lights Pipeline earnings reflected a decrease in leasing income from the light sour pipeline which was transferred to the Canadian Mainline effective May 1, 2010. This decrease was partially offset by operating earnings in the first quarter of 2011 which were higher than the amount of AEDC recognized in 2010 while the project was under construction. Both the Canadian and United States portions of the tariff for uncommitted shippers on the Southern Lights Pipeline have been challenged. Accordingly, a FERC hearing process was initiated and a hearing has been scheduled for January 10, 2012. The NEB set a date of September 20, 2011 for the Canadian Southern Lights toll hearing. No material financial impacts to the Company are anticipated from either of these proceedings.

Spearhead Pipeline earnings for the three months ended March 31, 2011 increased compared with the corresponding period of 2010 as a result of higher uncommitted throughputs and committed volumes in excess of contracted amounts triggering the recognition of unused shipper makeup rights.

The earnings decrease in Feeder Pipelines and Other was due to a decreased contribution from Toledo Pipeline, which was impacted by integrity work on Lines 6A and 6B of EEP’s Lakehead System, as well as an increase in business development costs.

GAS DISTRIBUTION

Adjusted earnings from Gas Distribution were $92 million for the three months ended March 31, 2011 compared with $88 million for the three months ended March 31, 2010. The increase was mainly due to higher adjusted earnings at EGD.

EGD adjusted earnings were $79 million for the three months ended March 31, 2011 compared with $76 million for the three months ended March 31, 2010. Current period adjusted earnings reflected lower operating and administrative costs and favourable impacts from lower statutory income tax rates, partially offset by lower per unit volumetric charges. The progressive substitution of lower per unit volumetric charges with corresponding increases in fixed charges modifies EGD’s quarterly earnings profile relative to the prior year, but does not materially impact full year earnings as earnings are shifted from the colder winter months to the warmer summer months.

Gas Distribution earnings were impacted by the following non-recurring or non-operating adjusting item.

·                  EGD earnings are adjusted to reflect the impact of weather.

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GAS PIPELINES, PROCESSING AND ENERGY SERVICES

Adjusted earnings from Gas Pipelines, Processing and Energy Services were $39 million for both the three months ended March 31, 2011 and 2010.

The decrease in Offshore adjusted earnings was primarily due to volume declines including natural production declines in existing reserves. The slower regulatory permitting process has impacted the level and timing of drilling activity in the Gulf of Mexico and the resultant production volumes available to ship on the Company’s Offshore system. Offshore adjusted earnings for the three months ended March 31, 2010 included $2 million in insurance proceeds related to reimbursement for business interruption lost revenues and operating expenses associated with a hurricane in 2008.

Aux Sable adjusted earnings increased due to stronger realized fractionation margins which resulted in higher contributions from the upside sharing mechanism in its production sales agreement.

Gas Pipelines, Processing and Energy Services earnings were impacted by the following non-recurring or non-operating adjusting items.

·                  Offshore earnings for the first quarter of 2010 included insurance proceeds related to the replacement of damaged infrastructure as a result of a 2008 hurricane.

·                  Aux Sable earnings for each period reflected unrealized fair value changes on derivative financial instruments related to the Company’s forward gas processing risk management position.

·                  Energy Services earnings for each period reflected unrealized fair value gains and losses related to the revaluation of inventory and the revaluation of financial derivatives used to risk manage the profitability of forward transportation and storage transactions.

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SPONSORED INVESTMENTS

Sponsored Investments adjusted earnings were $57 million for the three months ended March 31, 2011 compared with $51 million for the three months ended March 31, 2010.

EEP adjusted earnings were $32 million for the three months ended March 31, 2011 compared with $30 million for the three months ended March 31, 2010. Adjusted earnings for the first quarter of 2011 included strong results from the liquids business as well as higher incentive income. The increased earnings from the liquids business was primarily due to the completion and start up of Alberta Clipper in April 2010 and higher average daily volumes delivered from all major liquids systems. The acquisition of the Elk City System in September 2010 also positively contributed to earnings in the first quarter of 2011. These positive impacts were partially offset by an increase in operating and administrative costs and depreciation expense as well as higher financing costs as a result of additional assets placed in service during 2010.

The increase in EELP earnings was due to the completion and start up of Alberta Clipper in April 2010.

Earnings for the Fund totaled $13 million for the first quarter of 2011 and reflected increased contributions from the Saskatchewan System following completion of their Phase II expansion project in December 2010.

Sponsored Investment earnings were impacted by the following non-recurring or non-operating adjusting items.

·                  Earnings from EEP included $5 million (net to Enbridge) of insurance recoveries associated with the Line 6B crude oil release. See Recent Developments – EEP Lakehead System Line 6B and 6A Crude Oil Releases.

·                  EEP earnings included an unfavourable effect of $1 million (net to Enbridge) related to decreased volumes due to uncharacteristically cold weather in February 2011.

·                  EEP earnings included proceeds of $1 million (net to Enbridge) from the settlement of a lawsuit.

·                  Earnings from EEP included a change in the unrealized fair value on derivative financial instruments in each period.

CORPORATE

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Total Corporate adjusted earnings were $10 million for the three months ended March 31, 2011 compared with $6 million for the three months ended March 31, 2010.

Noverco earnings reflected contributions from the Company’s preferred share investment and Noverco’s underlying gas distribution investments. Earnings from Noverco are seasonal in nature and will therefore vary from period-to-period. Earnings for the first quarter of 2011, although down from the same period of 2010, are representative of typical first quarter operating results.

The improvement in Other Corporate adjusted loss was primarily due to lower administrative charges, improved performance from other corporate investments and higher affiliate interest income.

Corporate costs were impacted by the following non-recurring or non-operating adjusting items.

·                  Earnings for each period included the change in the unrealized fair value gains of derivative financial instruments related to forward foreign exchange risk management positions.

·                  Earnings included net unrealized foreign exchange gains on the translation of foreign-denominated intercompany balances.

LIQUIDITY AND CAPITAL RESOURCES

The Company expects to utilize cash from operations and the issuance of replacement debt, commercial paper and/or credit facility draws to fund liabilities as they become due, finance capital expenditures, fund debt retirements and pay common share dividends. At March 31, 2011, excluding the Southern Lights project financing, the Company had $5,674 million of committed credit facilities of which $3,058 million was drawn or allocated to backstop commercial paper. Inclusive of unrestricted cash and cash equivalents of $271 million, the Company had net available liquidity at March 31, 2011 of $2,887 million. The net available liquidity is expected to be sufficient to finance all currently secured capital projects and to provide flexibility for new investment opportunities.

The Company actively manages its bank funding sources to ensure adequate liquidity and optimize pricing and other terms. The following table provides details of the Company’s credit facilities at March 31, 2011.

1                  Total facilities inclusive of $59 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.

OPERATING ACTIVITIES

Cash from operating activities was $957 million for the three months ended March 31, 2011 compared with $646 million for the three months ended March 31, 2010. Cash from operating activities was positively impacted in 2011 by colder weather within the EGD franchise area and by contributions from Alberta Clipper and Southern Lights Pipeline placed into service in April and July 2010, respectively. Also contributing to the increase were variations in working capital requirements, primarily natural gas inventory at EGD, the value of which is dependent on commodity prices and seasonal volumetric drawdown rates.

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There are no material restrictions on the Company’s cash with the exception of proportionately consolidated joint venture cash of $61 million, which cannot be accessed until distributed to the Company, restricted cash of $4 million related to Southern Lights project financing and cash in trust of $15 million for specific shipper commitments.

INVESTING ACTIVITIES

Cash used in investing activities for the three months ended March 31, 2011 was $465 million compared with $629 million for the three months ended March 31, 2010. While capital expenditures for growth projects and core maintenance were comparable with 2010, the lower use of cash reported in the current period was mainly due to a decrease in the use of cash for long-term investments and affiliate lending, reflecting the completion of Alberta Clipper in the previous year.

FINANCING ACTIVITIES

Cash used in financing activities was $378 million for the three months ended March 31, 2011 compared with cash generated from financing activities of $84 million for the three months ended March 31, 2010. The decrease in cash was primarily due to commercial paper and credit facility repayments as well as Southern Lights project financing repayments in the current period compared with draws in the first quarter of 2010. In 2011, there were also lower net repayments of short-term borrowings as a result of working capital requirements.

Participants in the Company’s Dividend Reinvestment and Share Purchase Plan receive a 2% discount on the purchase of common shares with reinvested dividends. For the three months ended March 31, 2011, dividends declared were $188 million (2010 - $161 million), of which $124 million (2010 - $105 million) were paid in cash and reflected in financing activities. The remaining $64 million (2010 - $56 million) of dividends declared were reinvested pursuant to the plan and resulted in the issuance of common shares rather than a cash payment. For the three months ended March 31, 2011, 34% (2010 - 35%) of total dividends declared were reinvested.

On April 28, 2011, the Enbridge Board of Directors declared quarterly dividends of $0.49 per common share and $0.34375 per Series A Preferred Share. Both dividends are payable on June 1, 2011 to shareholders of record on May 13, 2011.

Capital Expenditure Commitments

The Company has signed contracts for the purchase of services, pipe and other materials totaling $1,894 million.

CRITICAL ACCOUNTING ESTIMATES

ASSET RETIREMENT OBLIGATIONS

In May 2009, the NEB released a report on the financial issues associated with pipeline abandonment and established a goal for pipelines regulated under the NEB Act to begin setting aside funds for abandonment no later than January 1, 2015. Since then, the NEB has issued several revised “base case assumptions” based on feedback from member companies. Companies have the option to follow the base case assumptions or to submit pipeline specific applications.

The NEB is requiring both Group 1 and Group 2 companies to file for approval estimates of abandonment costs by November 30, 2011. The NEB is also requiring large pipeline companies to file a proposed process for collecting and setting aside the funds for abandonment by November 30, 2012 for Group 1 companies (including Enbridge Pipelines Inc.) and by May 31, 2013 for Group 2 companies (including Southern Lights Pipeline).

Both of the required submissions will require NEB approval and will result in increases to transportation tolls, the amount of which is uncertain at this time. Currently, for certain of the Company’s assets, it is not practical to make a reasonable estimate of asset retirement obligations for accounting purposes due to the indeterminate timing and the scope of the asset retirements.

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CHANGE IN ACCOUNTING POLICIES

BUSINESS COMBINATIONS

Effective January 1, 2011, the Company adopted Part V Section 1582, Business Combinations, which replaces Section 1581. The new standard requires assets and liabilities acquired in a business combination to be measured at fair value at the acquisition date and if applicable, any original equity interest in the investee to be re-measured to fair value through earnings on the date control is obtained. The standard also requires that acquisition-related costs, such as advisory or legal fees, incurred to effect a business combination be expensed in the period in which they are incurred. In accordance with the transitional provisions of this standard, Section 1582 was adopted prospectively and accordingly, assets and liabilities that arose from business combinations occurring before January 1, 2011 were not restated. The adoption of this standard has not impacted the Company’s earnings or cash flows for the three month period ended March 31, 2011.

CONSOLIDATED FINANCIAL STATEMENTS AND NONCONTROLLING INTERESTS

Effective January 1, 2011, the Company adopted Part V Sections 1601, Consolidated Financial Statements, and 1602, Noncontrolling Interests, which together replace the former consolidated financial statements standard. Under the revised standards, noncontrolling interests are classified as a component of equity, and earnings and comprehensive income are attributed to both the parent and noncontrolling interest. In accordance with the transitional provisions of these standards, Section 1601 was adopted prospectively and Section 1602 was adopted retroactively with restatement of prior periods. As the adoption of these standards impacts presentation only there has been no impact to the Company’s earnings or cash flows for the current or prior periods presented.

FUTURE ACCOUNTING POLICIES

United States Generally Accepted Accounting Principles (U.S. GAAP)

First-time adoption of Part I - International Financial Reporting Standards (Part I or IFRS) of the CICA Handbook is mandatory for Canadian publicly accountable enterprises on January 1, 2011, with the exception of certain qualifying entities. Part I applies to qualifying entities, including those with operations subject to rate regulation, for periods beginning on or after January 1, 2012. The Company is a qualifying entity for purposes of this deferral and it will continue to present its financial statements in accordance with Part V of the CICA Handbook during the 2011 deferral period.

There continues to be uncertainty with respect to the application of IFRS to the rate regulated operations of the Company, which are pervasive and central to its commercial environment and performance measurement. The Company does not expect a rate regulated accounting standard to be finalized by the International Accounting Standards Board in advance of 2012. The Company believes U.S. GAAP, which articulates specific guidance for entities subject to rate regulation, more faithfully represents the economic realities of its regulated businesses. As a United States Securities and Exchange Commission (SEC) registrant, Enbridge is permitted by Canadian securities regulation to prepare its financial statements in accordance with U.S. GAAP and will adopt U.S. GAAP for interim and annual financial statements beginning on January 1, 2012.

In preparation for the U.S. GAAP conversion, Enbridge has formed a U.S. GAAP project team and developed a transition plan and governance structure to monitor the progress of the transition. The Company has engaged a public accounting firm to assist with the project and to provide technical accounting advice on the interpretation and application of U.S. GAAP to its primary financial statements. Management will report regularly to the Audit, Finance and Risk Committee of the Board of Directors on the advancement of the conversion to U.S. GAAP.

Accounting and Reporting

The Company has commenced integrating known U.S. GAAP differences into its primary financial statements. The most significant differences impact the following areas:

·                  Consolidation of EEP;

·                  Equity accounting treatment of joint ventures;

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·                  Inventory valuation;

·                  Classification and valuation of redeemable noncontrolling interests;

·                  Pensions and other post employment benefits; and

·                  Presentation of deferred financing costs.

Under U.S. GAAP the Company is deemed to control EEP and will therefore consolidate its interest in the partnership.

The Company also commenced the preparation of model U.S. GAAP financial statements to identify the type of information and level of detail required to be disclosed under U.S. GAAP, with substantial completion anticipated in the third quarter of 2011. Certain changes to the Company’s existing systems and processes may be required as a result of the conversion.

Training

As an SEC registrant, the Company has experience reporting under U.S. GAAP and has reconciled its financial statements to U.S. GAAP for many years. Further, two of the Company’s affiliates, Enbridge Energy Management, L.L.C. and EEP are also registered with the SEC and currently prepare and file U.S. GAAP financial statements. The Company has a detailed plan to provide supplemental U.S. GAAP training to internal personnel impacted by the conversion. Training initiatives have commenced and will continue throughout 2011.

Information Systems and Business Processes

The Company is currently evaluating whether systems solutions are necessary to support the conversion to U.S. GAAP and to sustain U.S. GAAP reporting in 2012 and beyond. The Company expects to identify any substantial systems and process changes in the second quarter of 2011 with implementation of any required changes to commence shortly thereafter. Related impacts to internal controls over financial reporting and disclosure controls and procedures will be identified and addressed over the course of 2011.

Business Activities

The Company has reviewed the effect of the U.S. GAAP conversion on its debt covenants, compensation agreements and hedging activities and does not expect the conversion to U.S. GAAP to significantly impact these activities or requirements.

The detailed project plan and the expected timing of key activities identified above may change prior to the U.S. GAAP conversion date due to the issuance of new accounting standards or amendments to existing accounting standards, changes in regulation or economic conditions or other factors.

QUARTERLY FINANCIAL INFORMATION1

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1                  Quarterly financial information has been extracted from financial statements prepared in accordance with Canadian GAAP.

Several factors impact comparability of the Company’s financial results on a quarterly basis, including, but not limited to, seasonality in the Company’s gas distribution businesses, fluctuations in market prices such as foreign exchange rates and commodity prices, disposals of investments or assets and the timing of in-service dates of new projects.

EGD and the Company’s other gas distribution businesses are subject to seasonal demand. A significant portion of gas distribution customers use natural gas for space heating; therefore, 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 and other gas distribution businesses 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.

The Company actively manages its exposure to market price risks, including, but not limited to, commodity prices and foreign exchange rates. To the extent derivative instruments used to manage these risks are non-qualifying for the purposes of applying hedge accounting, unrealized fair value gains and losses on these instruments will impact earnings. The revaluation of foreign-denominated intercompany loans also impacts earnings each quarter.

Finally, the Company undertook a substantial capital program in recent years and the timing of construction and completion of growth projects may impact the comparability of quarterly results. The Company’s capital expansion initiatives, including construction commencement and in-service dates, are described in Recent Developments.

In addition to the impacts of EGD weather and unrealized gains and losses outlined above, significant items that impacted the quarterly earnings were as set forth below.

·                  First quarter 2011 earnings reflected positive contributions from gas gathering assets purchased in the fourth quarter of 2010.

·                  Fourth quarter 2010 earnings reflected a dilution gain on reduced ownership in EEP, partially offset by additional leak remediation costs and the elimination of annual performance metrics under the Liquids Pipelines 2010 interim toll agreement.

·                  Reflected in earnings for the third and fourth quarters of 2010 are leak remediation costs and lost revenue associated with the Line 6B and Line 6A crude oil releases in the amounts of $85 million and $21 million, respectively.

·                  In April and July of 2010, the Company completed Alberta Clipper and Southern Lights Pipeline, respectively, two of the largest projects in the Company’s history, and commenced recording in-service earnings from those dates forward. Previous quarters include AEDC while the projects were under construction.

·                  Fourth quarter 2009 earnings reflected decreased revenues from gas distribution businesses due to depressed natural gas prices throughout 2009.

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NON-GAAP RECONCILIATIONS

OUTSTANDING SHARE DATA1