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  July 28, 2010

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) 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 AND TO BE PART THEREOF FROM THE DATE ON WHICH THIS REPORT IS FURNISHED, TO THE EXTENT NOT SUPERSEDED BY DOCUMENTS OR REPORTS SUBSEQUENTLY FILED OR FURNISHED.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 July 28, 2010.

·                Interim Report to Shareholders for the six months ended June 30, 2010.

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 second quarter results

HIGHLIGHTS

·                  Second quarter and six month adjusted earnings increased 19% to $232 million, or $0.63 per common share, and $550 million, or $1.49 per common share, respectively

·                  Second quarter earnings were $138 million; six month earnings were $480 million, or $1.30 per common share

·                  Alberta Clipper and Southern Lights Pipelines both brought into service on time and on budget

·                  Enbridge expands Regional Oil Sands System through $400 million Waupisoo Pipeline Expansion

·                  Enbridge enters U.S. green energy sector with US$500 million investment in 250-MW Colorado wind energy project

·                  Enbridge joins the Project Pioneer carbon capture and sequestration pilot project

·                  Enbridge affiliate expands U.S. natural gas gathering and processing footprint with US$682 million acquisition

CALGARY, ALBERTA, July 28, 2010 – Enbridge Inc. (TSX:ENB) (NYSE:ENB) – “Enbridge’s liquids pipelines, natural gas transportation and distribution and green energy businesses all contributed to sustaining our track record of strong financial results,” said Patrick D. Daniel, President and Chief Executive Officer. “With new projects entering service on schedule and on budget, we are on track for the upper half of our 2010 full year adjusted earnings guidance of $2.50 to $2.70 per share.”

“While we’re very proud of our second quarter financial performance, unfortunately, we are reporting those results at the same time as members of our team are in Michigan doing their utmost to respond to the leak we experienced on the Lakehead System earlier this week,” said Mr. Daniel. “Isolation valves on the line have been closed, stopping the source of the leak, and we are now focusing all of our efforts on recovery and clean up. Enbridge places the highest priority on mitigation of impacts to the environment and affected members of the public, working closely with regulators and federal, state and local officials.”

On April 1, 2010, Enbridge’s Alberta Clipper Project was placed into service, with line fill expected to be completed and full operations commencing by the end of September 2010.

“The completion of our largest project ever, the Alberta Clipper Project, on time and on budget marked a significant milestone for Enbridge,” said Mr. Daniel. “With the July 1st in service date for our second largest project, the Southern Lights diluent pipeline, these two projects are now further strengthening Enbridge’s cash flow growth.

In its natural gas business, Enbridge Energy Partners, L.P. announced earlier today the US$682 million acquisition of the entities that comprise the Elk City Gathering and Processing System from Atlas Pipeline Partners. The acquisition is anticipated to close by late third quarter or early fourth quarter 2010.

“Strategically, this acquisition provides immediate synergies with our existing natural gas gathering assets and further solidifies Enbridge’s ability to capitalize on growth in the Granite Wash,” said Mr. Daniel.

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.

In early July 2010, Enbridge announced its investment in the 250 megawatt Cedar Point Wind Energy Project for approximately US$500 million, a significant step in the Company’s objective of growing its green energy business.

“The Cedar Point Wind Energy Project is our first green energy investment outside of Canada and, as such, it establishes a foothold for future investment into the growing U.S. green energy market,” said Mr. Daniel. “Cedar Point bolsters our already strong portfolio of green energy projects and is expected to be accretive to earnings per share in the first full year of operation in 2012.

Enbridge continues to pursue the advancement of alternative energy technologies, including carbon capture, transportation and sequestration (CCS), technologies that are expected to contribute to increasing the environmental sustainability of oil sands production. In June 2010, the Company announced it will participate in the TransAlta-led Project Pioneer.

“We believe CCS has potential to positively impact our industry and our ability to continue to grow sustainably and in an environmentally responsible manner,” said Mr. Daniel.

“Green energy aligns very well with our objective to profitably grow our energy infrastructure business. In addition to boosting our bottom line, green energy is a key component in our plan to achieve a neutral environmental footprint as we grow our operations.”

“Enbridge is well positioned to continue to grow in 2010 and through the middle of the decade, with a full slate of potential investment opportunities that fit within our business model focused on growth, reliability and income,” concluded Mr. Daniel.

SECOND QUARTER 2010 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.

·                  Many of the same factors which contributed to favourable results in the first quarter of 2010 continued to impact earnings in the second quarter. Specifically, results were positively affected by Alberta Clipper being placed into service in April 2010 as well as the continued benefit from the construction of the Southern Lights Pipeline. Strong results from Enbridge Energy Partners, L.P. (EEP) continued as a result of enhanced results within its liquids segment, primarily due to the Southern Access Phase II Expansion being placed in service in April 2009 as well as the North Dakota Phase VI expansion that entered service on budget and ahead of schedule on January 1, 2010. As was also noted in Enbridge’s first quarter results, these positive variances were offset by decreased earnings from the Energy Services segment of the Company which in 2009 achieved higher volumes and more favourable storage and transportation margins.

·                  On July 26, 2010, EEP confirmed a leak on Line 6B of its Lakehead System. The pipeline was shut down and isolation valves were closed, stopping the source of the oil. No one was injured. The cause of the release has not been determined and is being investigated. Enbridge is placing priority on the clean-up efforts; financial impacts have not yet been assessed. Line 6B is a 30-inch, 190,000 barrels per day (bpd) line transporting light synthetics, heavy and medium crude oil from Griffith, Indiana to Sarnia, Ontario.

·                  On July 28, 2010, EEP announced that it plans to acquire the entities that comprise the Elk City Gathering and Processing (ECOP) System from Atlas Pipeline Partners for US$682 million. The acquisition is anticipated to close by late third quarter or early fourth quarter 2010. Upon closing, this acquisition is expected to be immediately accretive to earnings. The ECOP System comprises 1,300 kilometers (800 miles) of natural gas gathering pipeline, one hydrogen sulfide treating plant, three cryogenic processing plants with a total capacity of 370 million cubic feet per day and a combined current natural gas liquids production of 20,000 bpd. Enbridge holds a 27% interest in EEP.

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·                  On June 29, 2010, Enbridge announced an agreement with Renewable Energy Systems Americas Inc. (RES Americas) under which a U.S. affiliate of Enbridge Inc. will own and operate the 250-megawatt (MW) Cedar Point Wind Energy Project. Enbridge’s investment in the project will be approximately US$500 million and the Colorado-based RES Americas will construct it under a fixed-price engineering, procurement and construction contract to Enbridge. The Cedar Point Wind Energy Project is located approximately 130 kilometers (80 miles) east of Denver. Construction of the project will begin shortly, with substantial completion expected in late 2011. The project will deliver electricity to the Public Service Company of Colorado electricity transmission grid under a 20-year, fixed-price power purchase agreement.

·                  Enbridge announced on June 28, 2010 additional shipper commitments totaling 229,000 bpd of capacity on the Waupisoo Pipeline, part of Enbridge’s Regional Oil Sands System. Enbridge will undertake an approximately $400 million expansion of the Waupisoo Pipeline to its maximum capacity in order to accommodate these commitments, which include the additional Leismer oil sands volumes announced in February 2010. The Waupisoo Pipeline expansion program will provide approximately 65,000 bpd of additional capacity in the second half of 2012 and approximately a further 190,000 bpd when fully in service in the second half of 2013. The new commitments allow for a three-year ramp up to the full commitment amount, with a corresponding ramp up in revenue to Enbridge.

·                  Also on June 28, 2010, Enbridge announced it will participate in the development of the TransAlta-led Project Pioneer, Canada’s first fully-integrated CCS project involving retro-fitting a coal-fired electricity plant. When complete, Project Pioneer is expected to be one of the largest CCS facilities in the world and among the first to have an integrated underground storage system. Enbridge brings to Project Pioneer expertise in the design and construction of pipeline infrastructure, as well as extensive knowledge in CO2 sequestration.

·                  On June 16, 2010 Enbridge Inc. announced the acquisition of the 50% of the Hardisty Caverns Limited Partnership previously owned by CCS Corporation for approximately $52 million. The Hardisty Caverns facility, now wholly owned by Enbridge, includes four salt caverns totaling 3.1 million barrels of capacity, and provides term storage services under long-term contracts.

·                  Enbridge filed an application with the National Energy Board for the construction and operation of the Enbridge Northern Gateway Pipeline on May 27, 2010. The $5.5 billion Northern Gateway Pipeline involves a new twin pipeline system between Edmonton, Alberta and a new marine terminal in Kitimat, British Columbia to export petroleum and import condensate.

DIVIDEND DECLARATION

On July 27, 2010, the Enbridge Board of Directors declared quarterly dividends of $0.425 per common share and $0.34375 per Series A Preferred Share. Both dividends are payable on September 1, 2010 to shareholders of record on August 13, 2010.

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CONFERENCE CALL

Enbridge will hold a conference call on Wednesday, July 28, 2010 at 9:00 a.m. Eastern time (7:00 a.m. Mountain time) to discuss the second quarter 2010 results. Analysts, members of the media and other interested parties can access the call at +857-350-1600 or toll-free at 1-866-783-2141 using the access code of 45571069. The call will be audio webcast live at www.enbridge.com/InvestorRelations/Events. A webcast replay will be available approximately two hours after the conclusion of the event and a transcript and MP3 replay will be posted to the website within 24 hours. The replay at toll-free 1-888-286-8010 or +617-801-6888 (access code 71134492) will be available until August 4, 2010.

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 follow the analysts’ session.

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.

About Enbridge Inc.

Enbridge Inc. (Enbridge or the Company), a Canadian company, is a North American leader in energy delivery 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 green energy technologies, including wind and solar energy projects, 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 6,000 people, primarily in Canada and the U.S. 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, including management’s assessment of Enbridge’s and its subsidiaries’ future plans and operations. This information may not be appropriate for other purposes. Forward-looking statements are typically identified by words such as ‘‘anticipate’’, ‘‘expect’’, ‘‘project’’, ‘‘estimate’’, ‘‘forecast’’, ‘‘plan’’, ‘‘intend’’, ‘‘target’’, ‘‘believe’’ and similar words suggesting future outcomes or statements regarding an outlook. Forward-looking information or statements included or incorporated by reference in this document include, but are not limited to, statements with respect to: expected earnings or adjusted earnings; expected earnings or adjusted earnings per share; expected costs related to projects under construction; expected in-service dates for projects under construction; expected tariffs for pipelines; expected capital expenditures; and estimated future dividends.

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 underlie all forward-looking statements. These factors are relevant to all forward-looking statements as they may impact current and future levels of demand for the Company’s services. Similarly, exchange rates, inflation and interest rates impact the economies and business environments in which the Company operates, may impact levels of demand for the Company’s services and cost of inputs, and are therefore inherent in all forward-looking statements. Due to the interdependencies and correlation of these macroeconomic factors, the impact of any one assumption on a forward-looking statement cannot be determined with certainty, particularly with respect to expected earnings or adjusted earnings and 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

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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 ongoing 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

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HIGHLIGHTS

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1.               Adjusted earnings represent earnings applicable 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.               Enbridge System includes Canadian mainline 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 the Waupisoo Pipeline and exclude laterals on the Enbridge 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.               Degree day deficiency 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

June 30, 2010

MANAGEMENT’S DISCUSSION AND ANALYSIS

FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2010

This Management’s Discussion and Analysis (MD&A) dated July 28, 2010 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 and six months ended June 30, 2010, which are prepared in accordance with Canadian generally accepted accounting principles (GAAP). 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, 2009. 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 applicable to common shareholders were $138 million for the three months ended June 30, 2010, or $0.37 per common share, compared with $393 million, or $1.08 per common share, for the three months ended June 30, 2009. This decrease primarily reflected the recognition of unrealized fair value losses on derivative financial instruments used to manage foreign exchange risk in the second quarter of 2010 compared with unrealized fair value gains recognized in the second quarter of 2009. The decrease was partially offset by increased earnings in Sponsored Investments as a result of higher volumes and tolls on the Enbridge Energy Partners, L.P. (EEP) Lakehead System and increased tolls in Liquids Pipelines due to placing Alberta Clipper in service in the second quarter of 2010.

Earnings applicable to common shareholders were $480 million for the six months ended June 30, 2010, or $1.30 per common share, compared with $951 million, or $2.62 per common share, for the same period of 2009. This decrease primarily reflected a $329 million after-tax gain recognized on the sale of the Company’s investment in Oleoducto Central S.A. (OCENSA) in March 2009, an after-tax gain of $25 million related to the sale of NetThruPut (NTP) in May 2009 as well as unrealized fair value losses on derivative financial instruments used to manage foreign exchange risk compared with unrealized gains in the first half of 2009. The decrease was partially offset by higher allowance for equity funds used during construction (AEDC) in Liquids Pipelines, primarily on Alberta Clipper and Southern Lights Pipeline, higher tolling revenues in both Liquids Pipelines and Sponsored Investments as a result of Alberta Clipper commencing operations on April 1, 2010 and higher volumes and tolls on the EEP Lakehead System.

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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, including management’s assessment of Enbridge’s and its subsidiaries’ future plans and operations. This information may not be appropriate for other purposes. Forward-looking statements are typically identified by words such as ‘‘anticipate’’, ‘‘expect’’, ‘‘project’’, ‘‘estimate’’, ‘‘forecast’’, ‘‘plan’’, ‘‘intend’’, ‘‘target’’, ‘‘believe’’ and similar words suggesting future outcomes or statements regarding an outlook. Forward-looking information or statements included or incorporated by reference in this document include, but are not limited to, statements with respect to: expected earnings or adjusted earnings; expected earnings or adjusted earnings per share; expected costs related to projects under construction; expected in-service dates for projects under construction; expected tariffs for pipelines; expected capital expenditures; and estimated future dividends.

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 underlie all forward-looking statements. These factors are relevant to all forward-looking statements as they may impact current and future levels of demand for the Company’s services. Similarly, exchange rates, inflation and interest rates impact the economies and business environments in which the Company operates, may impact levels of demand for the Company’s services and cost of inputs, and are therefore inherent in all forward-looking statements. Due to the interdependencies and correlation of these macroeconomic factors, the impact of any one assumption on a forward-looking statement cannot be determined with certainty, particularly with respect to expected earnings or adjusted earnings and 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 ongoing 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 applicable 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 section for a reconciliation of the GAAP and non-GAAP measures.

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ADJUSTED EARNINGS

Adjusted earnings were $232 million, or $0.63 per common share, for the three months ended June 30, 2010, compared with $195 million, or $0.54 per common share, for the three months ended June 30, 2009. Adjusted earnings were $550 million, or $1.49 per common share, for the six months ended June 30, 2010, compared with $463 million, or $1.28 per common share, for the six months ended June 30, 2009.

The adjusted earnings growth of 19% achieved in both the second quarter of 2010 and the six-month period ended June 30, 2010 reflects the successful execution of several growth projects in late 2009 and the first half of 2010, including Alberta Clipper, the largest liquids pipelines project in the Company’s history, as well as strong performance from the Company’s existing asset base.

Specifically, the following factors impacted adjusted earnings for both the three and six months ended June 30, 2010:

·                  AEDC on both the Canadian and United States segments of the Alberta Clipper Project while under construction as well as operating earnings from its in-service date of April 1, 2010.

·                  AEDC on Southern Lights Pipeline while the project remained under construction during the first half of 2010.

·                  An increased contribution from EEP resulting from higher volumes and tolls on the Lakehead System, the completion of Southern Access Expansion Phase II in April 2009 and the North Dakota System Expansion that entered service on January 1, 2010.

·                  Within Liquids Pipelines, higher volumes on certain laterals comprising the Enbridge Regional Oil Sands System and positive operating results on the Enbridge System.

These increases were partially offset by decreased earnings from Natural Gas Delivery and Services as a result of lower adjusted earnings from Energy Services as well as decreased earnings arising from the sale of OCENSA in the first quarter of 2009.

RECENT DEVELOPMENTS

LIQUIDS PIPELINES

Alberta Clipper Project

The Alberta Clipper Project, which was placed in service April 1, 2010 on schedule and on budget, involved the construction of a new 36-inch diameter pipeline from Hardisty, Alberta to Superior, Wisconsin generally within or alongside Enbridge’s existing rights-of-way in Canada and EEP’s existing rights-of-way in the United States. The new pipeline interconnects with the existing mainline system in Superior where it provides access to Enbridge’s full range of delivery points and storage options, including Chicago, Toledo, Sarnia, Patoka and Cushing. Alberta Clipper has an initial capacity of 450,000 barrels per day (bpd), is expandable to 800,000 bpd and now forms part of the existing Enbridge System in Canada and the EEP Lakehead System in the United States. The line fill process has begun and is expected to be complete by the end of September 2010.

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The total cost of the Canadian segment of the project is expected to be $2.3 billion, including allowance for funds used during construction (AFUDC), with expenditures to date of $2.2 billion. The cost of the United States segment is expected to be approximately US$1.2 billion, with expenditures to date totaling US$1.1 billion. Remaining costs are mainly commissioning work associated with the line fill process as well as right-of-way restoration. Enbridge has funded 66.7% of the United States segment of the Alberta Clipper project through Enbridge Energy, L.P. (EELP).

For the United States segment of Alberta Clipper, tariffs filed with the Federal Energy Regulatory Commission (FERC) were approved and became effective April 1, 2010. Filings in early 2010 by shippers requesting the FERC to delay the tariff were dismissed by the FERC in March 2010.

Interim tolls for the Enbridge mainline, including recovery of costs related to the Canadian segment of Alberta Clipper, went into effect April 1, 2010 and, as directed by the National Energy Board (NEB), reflected the forecasted toll presented in 2007. An NEB hearing has been scheduled for November 2010 to consider Enbridge’s final toll application, which includes Alberta Clipper at the full revenue requirement, as well as remaining aspects of the February 2010 filing made by certain shippers. In April 2010, the NEB denied a number of other aspects of the shippers’ filing, including the request to suspend the line fill requirement. The Company continues to believe the shippers’ filings to be without merit.

Southern Lights Pipeline

The Southern Lights Pipeline was completed ahead of schedule and was placed in service on July 1, 2010. The 180,000 bpd Southern Lights Pipeline transports diluent from Chicago, Illinois to Edmonton, Alberta. The project involved reversing the flow of a portion of Enbridge’s Line 13, an existing crude oil pipeline which runs from Edmonton to Clearbrook, Minnesota. In order to replace the light crude capacity that would be lost through the reversal of Line 13, the Southern Lights Project also included the construction of a new 20-inch diameter light sour crude oil pipeline (LSr Pipeline) from Cromer, Manitoba to Clearbrook, and modifications to existing Line 2. These changes to the existing crude oil system increased southbound light crude system capacity by approximately 45,000 bpd.

The total expected project cost is US$1.6 billion for the United States segment and $0.5 billion for the Canadian segment. Expenditures to date are US$1.5 billion and $0.5 billion for the United States and Canadian segments, respectively. Remaining costs primarily relate to right-of-way restoration and final work on the Line 13 facilities.

The United States portion of the tariff for uncommitted shippers on the Southern Lights Pipeline has been challenged. Accordingly, a FERC settlement and hearing process has been initiated. No material financial impacts to the Company are anticipated.

Christina Lake Lateral

Enbridge will construct, own and operate 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 26 kilometers of 30-inch diameter pipeline to Enbridge’s existing Christina Lake lateral and terminal facilities, which include two eight-inch lateral lines plus 240,000 barrels of tankage that connect to the Company’s Athabasca Pipeline. The estimated cost of the additional facilities is approximately $0.3 billion, with expenditures to date of $0.1 billion. The planned in-service date is late 2011.

Waupisoo Pipeline Expansion

The Waupisoo Pipeline Expansion will provide 65,000 bpd of additional capacity in the second half of 2012 and an estimated 190,000 bpd of additional capacity in the second half of 2013 when the expansion is fully in service. The project will accommodate shipper commitments of 229,000 bpd, including the additional Leismer oil sands volumes announced in February 2010. The estimated cost of the additional facilities is approximately $0.4 billion.

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Woodland Pipeline

In June 2009, Enbridge entered into an 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 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 pipeline, to be called the Woodland Pipeline, will be extended from Cheecham to Edmonton in conjunction with the second phase of the Kearl project. The Woodland Pipeline is being undertaken as a joint venture between Enbridge, Imperial Oil and ExxonMobil. Enbridge filed regulatory applications for Phase I facilities at the end of 2009. Regulatory approval from the Energy Resources Conservation Board was received in June 2010. The total estimated cost of the pipeline from the mine to the Cheecham Terminal and related facilities is $0.5 billion, but is subject to finalization based on scope, detailed engineering and regulatory approvals. Enbridge expects the pipeline will come into service in late 2012.

Hardisty Terminal

In June 2010, the Company announced the acquisition of the 50% of the Hardisty Caverns Limited Partnership previously owned by CCS Corporation for approximately $52 million. The Hardisty Caverns facility, now wholly owned by Enbridge, includes four salt caverns totaling 3.1 million barrels of capacity, and provides term storage services under long-term contracts.

Northern Gateway Project

The Northern Gateway Project involves constructing a twin 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 expected 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 expected 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 will conduct sessions with the public and Aboriginal groups to seek 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 is of the view that it would be appropriate to obtain these comments prior to issuing a Hearing Order or initiating further procedural steps in the joint review process. The Company has secured $100 million funding from Western Canada producers and Pacific Rim refiners toward the costs of seeking the necessary regulatory approvals for the project.

Subject to continued commercial support, regulatory and other approvals, and adequately addressing landowner, Aboriginal and local community concerns, the Company estimates that Northern Gateway could be in-service in approximately 2016 at an estimated cost of $5.5 billion. The NEB posts public filings related to Northern Gateway on its website and Enbridge also maintains a Northern Gateway Project site in addition to information available on www.enbridge.com. The full regulatory application submitted to the NEB is also available on www.notherngateway.ca. None of the information contained on, or connected to, the NEB website, the Northern Gateway Project website or Enbridge’s website is incorporated in or otherwise part of this MD&A.

NATURAL GAS DELIVERY AND SERVICES

LaCrosse Pipeline

The proposed LaCrosse Pipeline was to include an interstate pipeline to transport natural gas from EEP’s Carthage Hub in Panola County, Texas, to Washington Parish in Southeastern Louisiana, providing an outlet for increasing supplies of natural gas originating in the East Texas and Fort Worth producing basins and the growing Haynesville Shale play. The Company has decided that it will not be proceeding with plans to construct the proposed LaCrosse Pipeline.

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SPONSORED INVESTMENTS

Enbridge Energy Partners

Lakehead Line 6B Leak

On July 26, 2010, EEP confirmed a crude oil release on Line 6B of its Lakehead System near Marshall, Michigan. The pipeline was immediately shut down and emergency response crews were dispatched to oversee containment, cleanup and repair of the pipeline. The cause of the release is currently being investigated and, at this time, the economic impact this incident may have is indeterminable. EEP maintains commercial liability coverage that includes a deductible of approximately US$5 million, excluding fines and penalties, and limits of coverage that are expected to be adequate to fund the resulting costs and liabilities.

Enbridge Income Fund

Corporate Restructuring

In May 2010, Enbridge Income Fund (EIF) unitholders approved a plan of arrangement (the Plan) for restructuring EIF. The restructuring will involve an exchange by Enbridge of a portion of its interest in EIF for shares of a taxable Canadian corporation to be called Enbridge Income Fund Holdings Inc. (EIFH). Public unitholders will also exchange their trust units for shares of EIFH. The scope of activities of EIFH will be limited to investment in EIF and Enbridge will retain its 72% economic interest in EIF following completion of the Plan. Subject to final Toronto Stock Exchange approvals, the Plan will take effect prior to the end of 2010.

Saskatchewan System Capacity Expansion

Phase II of the Saskatchewan System Capacity Expansion includes three separate projects that will reduce capacity constraints at a variety of locations. Collectively, the projects will increase capacity across the system by approximately 125,000 bpd at an estimated cost of $0.1 billion. Regulatory approvals from the NEB and Saskatchewan Ministry of Energy & Resources have been received and construction began on the remaining components of the project in the second quarter of 2010. All three projects comprising the Saskatchewan System Phase II Expansion are currently targeted to be in-service in December 2010.

CORPORATE

Cedar Point Wind Energy Project

On June 29, 2010, Enbridge announced it had entered into an agreement with Renewable Energy Systems Americas Inc. (RES Americas) under which a United States affiliate of Enbridge will own and operate the 250-megawatt (MW) Cedar Point Wind Energy Project, near Denver, Colorado, at an investment of US$0.5 billion. RES Americas will construct the wind project under a fixed price, turnkey, engineering, procurement and construction agreement. The project will be 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 expected to be completed in the fourth quarter of 2011. Expenditures to date total US$0.1 billion.

Greenwich Wind Energy Project

On March 31, 2010, Enbridge announced the development of the 99-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 will construct the wind project under a fixed price, turnkey, engineering, procurement and construction agreement. The project utilizes 43 Siemens 2.3-MW wind turbines and, under a five-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 and is expected to be completed in the fourth quarter of 2011 at an estimated capital cost of $0.3 billion.

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Talbot Wind Energy Project

On November 19, 2009, Enbridge announced the development of the 99-MW Talbot Wind Energy Project near Chatham, Ontario with RES Canada. Enbridge will have a 90% interest in the project and an option to acquire the remaining 10% interest. RES Canada will construct the wind 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 Talbot Wind Energy Project will deliver energy to the OPA under a 20-year power purchase agreement and is expected to be completed by late 2010 at an estimated capital cost of $0.3 billion. Expenditures to date are $0.2 billion.

Sarnia Solar Project

On October 2, 2009, Enbridge announced the development of the 20-MW Sarnia Solar Project with First Solar, Inc. (First Solar). On December 8, 2009, the Company announced a 60-MW expansion of the project. After completion of the expansion, the project will be the largest photovoltaic, solar energy facility in operation in North America. First Solar, a global leader in solar energy, is constructing the project under a fixed price engineering, procurement and construction contract, utilizing its thin film photovoltaic technology. First Solar will also provide operations and maintenance services under a long-term contract. Power output of the facility will be sold to the OPA under a 20-year power purchase agreement. The initial 20-MW facility attained commercial operation in December 2009 and the 60-MW facility is now expected to be in service by September 2010, ahead of the original schedule. The expected capital cost of both facilities is $0.4 billion, with expenditures to date of $0.1 billion.

Project Pioneer

In June 2010, Enbridge announced it will participate in the development of the TransAlta-led Project Pioneer, Canada’s first fully-integrated carbon capture and storage (CCS) project involving retro-fitting a coal-fired electricity plant. When complete, Project Pioneer is expected to be one of the largest CCS facilities in the world and among the first to have an integrated underground storage system. Enbridge brings to Project Pioneer expertise in the design and construction of pipeline infrastructure as well as extensive knowledge in CO2 sequestration.

FINANCIAL RESULTS

LIQUIDS PIPELINES

Adjusted earnings for the three months ended June 30, 2010 were $133 million, an increase of $36 million compared with the three months ended June 30, 2009. Adjusted earnings for the six months ended June 30, 2010 were $267 million, an increase of $73 million compared with adjusted earnings of $194 million in the prior year comparable period. The adjusted earnings increase for both the three and six-month periods ended June 30, 2010 was supported by all segment assets, but primarily due to higher earnings from Enbridge System and the Southern Lights Pipeline.

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While under construction, certain regulated pipelines are entitled to recognize AEDC in earnings. These amounts will be collected in tolls once the pipelines are in service. The earnings impact of AEDC for the Enbridge System was $1 million (2009 - $15 million) for the three months ended June 30, 2010 and $27 million (2009 - $30 million) for the six months ended June 30, 2010, primarily related to Alberta Clipper. Recognition of AEDC on Alberta Clipper ceased following its in service date of April 1, 2010 when cash tolls commenced. The earnings impact of AEDC for the Southern Lights Pipeline was $14 million (2009 - $9 million) for the three months ended June 30, 2010 and $32 million (2009 - $20 million) for the six months ended June 30, 2010.

Factors positively impacting Enbridge System earnings in the three and six month periods included AEDC, cash tolls on Alberta Clipper entering service on April 1, 2010 and favourable operating performance.

During the second quarter of 2010, the NEB approved the Company’s Enbridge System final toll submission filed in the first quarter of 2010, which includes a one year Incentive Tolling Settlement (ITS) agreement that can be extended into 2011. The ITS agreement allows for continued throughput protection on the Canadian mainline, increases the relative percentage of flow through costs and updates depreciation rates for certain pipeline assets, reducing the associated toll for shippers.

Enbridge Regional Oil Sands System earnings increased as a result of higher volumes and increased tolls on certain laterals.

Higher Southern Lights Pipeline earnings reflected AEDC recognized on a growing capital base while the project continued to be under construction during the first six months of 2010. This increase in earnings was partially offset by a decrease in earnings from the new light sour pipeline, which became operational during the first quarter of 2009, and was transferred to the Enbridge System effective May 1, 2010.

Spearhead Pipeline earnings for both the three and six months ended June 30, 2010 increased, compared with the corresponding periods of 2009, as a result of higher throughputs on committed volumes, contracted volumes resulting from the expansion completed in May 2009 as well as the recognition of make-up rights which expired in the period.

Feeder Pipelines and Other earnings increased due to improved operating results on a number of feeder systems and lower business development costs.

Liquids Pipelines earnings were impacted by the following non-recurring or non-operating adjusting item:

·     A $6 million after-tax expense resulting from clean up and remediation costs related to a valve leak within the Enbridge Cheecham Terminal on the Enbridge Regional Oil Sands System in January 2009, which is not indicative of the expected future performance of this asset.

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NATURAL GAS DELIVERY AND SERVICES

Adjusted earnings from Natural Gas Delivery and Services were $48 million and $191 million for the three and six months ended June 30, 2010 respectively, compared with $51 million and $203 million for the three and six months ended June 30, 2009. The decrease was primarily due to lower adjusted earnings in Energy Services, partially offset by increased adjusted earnings from EGD.

EGD adjusted earnings were $22 million and $98 million for the three and six months ended June 30, 2010, respectively, compared with adjusted earnings of $16 million and $93 million for the three and six months ended June 30, 2009. The increase in EGD’s adjusted earnings for both the second quarter and the first six months of 2010 was primarily due to continued favorable performance under Incentive Regulation, specifically customer growth and lower taxes, partially offset by higher operating and administrative costs, interest expense, accrued customer earnings sharing and depreciation expense. Depreciation expense has increased due to an increase in the overall asset base, including the implementation of a new customer billing system in late 2009. Decreasing earnings in the first half of 2010 compared with 2009 was a negative variance of $6 million from higher fixed rate billings and corresponding lower variable charges. As initially reflected in the results for the first quarter of 2008, and in line with scheduled progressive changes contained in the five year Incentive Regulation terms, EGD’s fixed charge billing per customer increased with a corresponding decrease in the per unit volumetric charge. These changes modify EGD’s quarterly earnings profile relative to the prior year, but do not affect full year earnings as revenues are shifted from the colder winter quarters to the warmer summer quarters.

Offshore adjusted earnings for the six months ended June 30, 2010 reflected a higher contribution from Starfish Pipeline Company, LLC (Starfish) as well as lower operating costs. The Company purchased the additional 50% interest in Starfish effective December 31, 2009, increasing its ownership to 100%. For the six months ended June 30, 2010, Offshore adjusted earnings included $2 million (2009 - $4 million) in insurance proceeds related to reimbursement for business interruption lost revenues and operating expenses associated with Hurricane Ike in 2008.

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Reflecting improved insurance market pricing terms, effective June 1, 2010, Offshore’s insurance policy now includes coverage related to named windstorms, such as hurricanes. As a result of the change in coverage, physical damage caused by future hurricanes will not impact Offshore’s financial performance to the extent it otherwise would. On June 1, 2009, Offshore had chosen to eliminate this coverage due to significant increases in insurance premiums and deductibles as a result of the hurricanes that had taken place in the Gulf in previous years.

The decrease in Energy Services adjusted earnings is attributable to reduced volume and margin opportunities in liquids marketing and on merchant gas pipeline capacity.

Natural Gas Delivery and Services earnings were impacted by the following non-recurring or non-operating adjusting items:

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

·                  Earnings from EGD for 2009 included interest income of $7 million related to the recovery of excess GST remitted to Canada Revenue Agency.

·                  Offshore earnings included insurance proceeds related to the replacement of damaged infrastructure as a result of the 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.

·                  Energy Services earnings included a $1 million partial recovery from the sale of the Company’s receivable from Lehman Brothers previously written off.

·                  On March 17, 2009, the Company sold its investment in OCENSA, a crude oil export pipeline in Colombia, for proceeds of $512 million, resulting in a gain of $329 million.

·                  Other reflected the write-off of $3 million in deferred development costs as a result of adopting a change in accounting standards effective January 1, 2009.

SPONSORED INVESTMENTS

Sponsored Investments adjusted earnings were $51 million for the three months ended June 30, 2010 compared with $39 million for the three months ended June 30, 2009. For the six months ended June 30, 2010, adjusted earnings were $102 million compared with $70 million in the comparable prior period.

The increase in EEP adjusted earnings was largely attributable to strong results from the liquids business as well as higher incentive income. The liquids improvement was generated largely from higher delivered volumes as well as increased transportation rates, partially offset by increased power costs on such volumes, increased operating costs and depreciation. The completion of Southern Access Expansion Phase II in April 2009, the North Dakota System Expansion that entered service on January 1, 2010 and the start up of the Alberta Clipper Project on April 1, 2010 contributed to the higher volumes and tariffs.

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EELP – Alberta Clipper US earnings represent the Company’s earnings from its 66.7% investment in a series of equity within EELP which owns the United States segment of the Alberta Clipper Project. Earnings were attributable to AEDC recognized while the project was under construction as well as tolls since the Alberta Clipper Project went into service on April 1, 2010. On July 23, 2010, the Board of Directors of Enbridge Energy Management, L.L.C. declared a distribution of $18 million payable to the Company in relation to its investment in Alberta Clipper US.

Sponsored Investments earnings for the three and six months ended June 30, 2010 and 2009 were impacted by the following non-recurring or non-operating adjusting items:

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

·                  Earnings from EEP included Lakehead System billing corrections (net to Enbridge) related to services provided in prior periods.

·                  EEP earnings for the three months ended June 30, 2010 were favourably impacted by a dilution gain because Enbridge did not fully participate in EEP’s Class A unit offering.

CORPORATE

Corporate adjusted loss was $10 million for the six months ended June 30, 2010 compared with $4 million for the six months ended June 30, 2009, reflecting increased financing costs.

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

·                  Earnings included the change in the unrealized fair value of derivative financial instruments related to forward foreign exchange and interest rate risk management positions.

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

·                  On May 1, 2009, the Company sold its investment in NTP an internet-based crude oil trading and clearing platform, for proceeds of $32 million, resulting in a gain of $25 million.

·                  Earnings for the six months ended June 30, 2009 reflected a $6 million charge related to favourable legislated tax changes.

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 June 30, 2010, excluding the Southern Lights project financing, the Company had $5,272 million of committed credit facilities of which $3,223 million was drawn or allocated to backstop commercial paper. In June 2010, the $100 million revolving credit agreement through which the Company provided liquidity support to the Company’s affiliate EIF expired. In March 2010, the US$500 million revolving credit agreement through which the Company provided liquidity support to the Company’s affiliate EEP was cancelled. As a result, the Company had net available liquidity at June 30, 2010 of $2,374 million, inclusive of unrestricted cash and cash equivalents of $325 million. The net available liquidity and selective capital markets funding are expected to be

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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. During the year, the following transactions occurred:

·                  In June 2010, the Company reduced available credit under an existing credit facility to $350 million, decreasing available credit in Liquids Pipelines by $650 million.

·                  In May 2010, the Company reduced an existing facility, decreasing credit facilities in Liquids Pipelines by $100 million.

The following table provides details of the Company’s credit facilities at June 30, 2010.

1.               Total facilities inclusive of $188 million which is available if certain conditions related to the project are met.

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

OPERATING ACTIVITIES

Cash from operating activities was $511 million and $1,157 million for the three and six months ended June 30, 2010, respectively, compared with $710 million and $1,591 million for the three and six months ended June 30, 2009. Cash from operating activities was bolstered in 2010 by contributions from growth projects placed in service in late 2009 and in the first half of the year, including Alberta Clipper. Effective April 1, 2010, tolls on both Enbridge System and the EEP Lakehead System were revised as a result of Alberta Clipper coming into service. Improved operating performance in first half of 2010 also contributed to period-over-period growth in cash from operating activities. The decrease resulting from variations in working capital requirements more than offset these positive effects, resulting in period-over-period declines in cash from operating activities.

There are no material restrictions on the Company’s cash with the exception of proportionately consolidated joint venture cash of $78 million, which cannot be accessed until distributed to the Company, and cash in trust of $6 million for specific shipper commitments.

INVESTING ACTIVITIES

Cash used in investing activities for the three and six months ended June 30, 2010 was $558 million and $1,187 million, respectively, compared with $488 million and $851 million for the three and six months ended June 30, 2009. Cash used in investing activities included $490 million (2009 - $540 million) and $865 million (2009 - $1,350 million) of additions to property plant and equipment for the three and six months ended June 30, 2010, respectively. Additions to property, plant and equipment have declined compared with 2009 given the completion, or near completion, of Alberta Clipper, Southern Lights Pipeline and Hardisty Contract Terminal, among others. On June 16, 2010, the Company acquired the remaining 50% interest in Hardisty Caverns Limited Partnership for cash consideration of $52 million, increasing its ownership interest to 100%. Investing activities also include long-term investments and affiliate lending, primarily the Company’s investing in and funding of EELP which holds the United States segment of the Alberta Clipper Project. The lower use of cash used in investing activities reported in 2009 was enhanced by proceeds received on the sale of the investments in OCENSA and NTP.

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FINANCING ACTIVITIES

Cash generated from financing activities was $23 million for the three months ended June 30, 2010 compared with cash used in financing activities of $190 million for the three months ended June 30, 2009. For the six months ended June 30, 2010, cash provided by financing activities was $107 million compared with cash used in financing activities of $916 million for the comparable period of 2009. The increase in cash primarily resulted from medium-term note issuances of $500 million in March 2010 and $650 million in April 2010, which were partially offset by decreases in commercial paper and credit facility draws.

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 June 30, 2010, dividends declared were $161 million (2009 - $139 million), of which $104 million (2009 - $106 million) were paid in cash and reflected in financing activities. The remaining $57 million (2009 - $33 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 six months ended June 30, 2010, dividends declared were $322 million (2009 - $277 million), of which $209 million (2009 - $210 million) were paid in cash and reflected in financing activities. The remaining $113 million (2009 - $67 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 and six months ended June 30, 2010, 35% (2009 - 24%) and 35% (2009 - 24%) of total dividends declared were reinvested.

On July 27, 2010, the Enbridge Board of Directors declared quarterly dividends of $0.425 per common share and $0.34375 per Series A Preferred Share. Both dividends are payable on September 1, 2010 to shareholders of record on August 13, 2010.

Capital Expenditure Commitments

The Company has signed contracts for the purchase of services, pipe and other materials totaling $1,355 million which are expected to be paid over the next five years.

In July 2009, the Company committed to fund 66.7% of the United States segment of the Alberta Clipper Project through EEP and EELP. The total cost of the United States segment is estimated at US$1,200 million. As at June 30, 2010, the Company had funded 97% of the committed amount.

CRITICAL ACCOUNTING ESTIMATES

ASSET RETIREMENT OBLIGATIONS

In 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, as required, to begin setting aside funds for abandonment no later than the end of May 2014. In March 2010, the NEB issued a report revising certain ‘base case assumptions’ and, as such, large pipeline companies are required to file abandonment cost estimates by May 2011. The NEB is requiring large pipeline companies to file a proposed process for collecting and setting aside the funds for abandonment by May 2012. Both of the required submissions will need 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 scope of the asset retirements. However, should the NEB action plan result in a reasonable estimate of asset retirement obligations for accounting purposes, financial statement recognition of these amounts may be made in future periods.

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FUTURE ACCOUNTING POLICIES

INTERNATIONAL FINANCIAL REPORTING STANDARDS (IFRS)

The Canadian Accounting Standards Board (AcSB) has determined that IFRS will become the new Canadian accounting standards for publicly accountable entities for periods beginning on or after January 1, 2011. On July 23, 2010, the AcSB decided, subject to finalization of an exposure draft, to offer an optional two year deferral for adopting IFRS for qualifying entities with rate regulated activities and permit such entities to continue to apply the accounting standards in Part V of the Canadian Institute of Chartered Accountants (CICA) Handbook during that period. Enbridge is a qualifying entity for purposes of this deferral.

While the Company’s IFRS conversion project is on track to meet the original conversion deadline, the Company has elected to use the deferral offered by the AcSB. This decision was made given the continuing uncertainty with respect to the application of IFRS to the rate regulated operations of the Company, which are pervasive and central to its business model and a key driver of financial performance.

Enbridge and all of its reporting entities are subject to rate regulation and are currently accounted for as rate regulated enterprises in accordance with Canadian and U.S. GAAP. In 2009, the International Accounting Standards Board (IASB) initiated a project to create an IFRS standard on Rate Regulated Activities which would have allowed the Company to continue to apply rate regulated accounting with some changes. In July 2010, the IASB decided to continue its Rate Regulated Activities project with the intention to potentially create an accounting standard, but has not provided authoritative guidance on how rate regulated companies currently transitioning to IFRS should apply IFRS in the interim.

Accounting and Reporting

Depending on the progress and outcome of the IASB’s project, the Company will consider whether U.S. GAAP or IFRS would provide the most useful and reliable presentation of its financial results. United States Securities and Exchange Commission (SEC) registrants are permitted to prepare their financial statements in accordance with U.S. GAAP, including for purposes of fulfilling its Canadian regulatory filing requirements. Enbridge is registered with the SEC and thus already reconciles its financial position, earnings and comprehensive income to U.S. GAAP on a quarterly basis. If determined to be in its best interests, the Company could alternatively use U.S. GAAP as its basis of accounting.

QUARTERLY FINANCIAL INFORMATION1

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, including the impact of AEDC recognized during the construction period.

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Revenues include amounts billed to customers of EGD for natural gas, which varies with fluctuations in the commodity price and seasonal heating demand. Higher natural gas commodity prices increase revenues but would not similarly impact earnings as the cost of natural gas flows through to customers. Fluctuations in commodity prices impact revenues and earnings from Energy Services businesses.

Significant items that impacted the quarterly earnings and revenues were as follows:

·                  Second quarter 2010 earnings reflect the recognition of unrealized fair value losses on derivative financial instruments used to manage foreign exchange risk, partially offset by increased earnings as a result of higher volumes and tariffs on certain assets.

·                  First quarter 2010 earnings reflect unrealized fair value losses and gains on derivative financial instruments used to manage commodity price risk and foreign exchange rate risk, respectively.

·                  Fourth quarter 2009 earnings reflect decreased revenues from gas distribution businesses due to depressed natural gas prices throughout 2009 and unrealized fair value gains on derivative financial instruments used to manage commodity price risk and foreign exchange rate risk.

·                  Third quarter 2009 earnings reflect AEDC in Liquids Pipelines as well as unrealized fair value gains on derivative financial instruments used to risk manage foreign exchange and interest rate variability.

·                  Second quarter 2009 earnings reflect a higher contribution from EEP, AEDC in Liquids Pipelines as well as unrealized fair value gains on derivative financial instruments used to risk manage commodity, foreign exchange and interest rate variability.

·                  First quarter 2009 earnings reflect a gain of $329 million on the disposition of the Company’s investment in OCENSA. Revenues decreased due to lower average commodity prices relative to 2008.

·                  Fourth quarter earnings in 2008 reflect AEDC in Liquids Pipelines, a higher contribution from EGD and unrealized fair value gains on derivative financial instruments in Aux Sable and Energy Services.

·                  Third quarter earnings in 2008 reflect increased earnings from Athabasca System, EGD, Aux Sable and Energy Services. Revenues increased due to higher average commodity prices in 2008.

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NON-GAAP RECONCILIATIONS

OUTSTANDING SHARE DATA

Outstanding share data information is provided as at July 20, 2010.

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ENBRIDGE INC.

CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

June 30, 2010

CONSOLIDATED STATEMENTS OF EARNINGS