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  August 1, 2014

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. 333-185591 AND 33-77022) AND FORM F-10 (FILE NO. 333-189157) 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 AND TO BE PART THEREOF FROM THE DATE ON WHICH THIS REPORT IS FURNISHED, TO THE EXTENT NOT SUPERSEDED BY DOCUMENTS OR REPORTS SUBSEQUENTLY FILED OR FURNISHED.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:

The following documents are being submitted herewith:

·                 Press Release dated August 1, 2014.

·                 Interim Report to Shareholders for the six months ended June 30, 2014.

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 adjusted earnings of $328 million or $0.40 per common share

HIGHLIGHTS

(all financial figures are unaudited and in Canadian dollars unless otherwise noted)

·                  Second quarter earnings were $756 million and six months earnings were $1,146 million, both including the impact of net unrealized non-cash mark-to-market gains and losses

·                  Second quarter and six months adjusted earnings were $328 million and $820 million, respectively, or $0.40 and $1.00 per common share, respectively

·                  Enbridge Inc. and Enbridge Energy Partners, L.P. announced an equity restructuring involving the General Partner’s incentive distributions rights within Enbridge Energy Partners, L.P.

·                  Enbridge Inc. continued to execute its long-term funding plan and raised approximately $3.3 billion since the end of the first quarter through a combination of debt and equity issuances

·                  Marathon Petroleum Corporation named anchor shipper and equity partner in the US$0.9 billion Southern Access Extension Project, and will fund 35% of the project

·                  Ontario Energy Board approved Enbridge Gas Distribution Inc. five-year incentive rate application

·                  Northern Gateway Project approved by the Government of Canada, subject to conditions

CALGARY, ALBERTA – August 1, 2014 – Enbridge Inc. (Enbridge or the Company) (TSX:ENB) (NYSE:ENB) – “Earnings for the first half of this year are in line with our expectations and our full year adjusted earnings per share guidance of $1.84 to $2.04 per share,” said Al Monaco, President and Chief Executive Officer. “More broadly, we are keenly focused on the implementation of our strategic plan and on our key priorities of safety and operational reliability, execution of our growth projects and extending and diversifying our growth beyond 2017. The plan, which now includes a growth capital program of $42 billion, of which $37 billion is commercially secured and expected to be put into service by 2017, gives us continued confidence in delivering average annual earnings per share growth of 10-12% through 2017, and there are a number of factors that bode very well for post 2017 growth.

“In Liquids Pipelines, our largest business, our strategy is driven by our customers’ need for incremental pipeline capacity and new market access to accommodate the continued strong growth of North American supply,” said Mr. Monaco. “Market access remains a strategic imperative and we are making good progress. Construction of the Seaway Twin is now mechanically complete and we expect to complete the Flanagan South project this fall, adding an incremental 600,000 barrels per day of heavy crude capacity to the key refining hub in the U.S. Gulf Coast. By the end of 2016, we expect to bring into service projects that will open up approximately 1.7 million barrels per day of incremental capacity.”

Enbridge remained active in the capital markets. Since the end of the first quarter, Enbridge has raised approximately $0.5 billion through a public common share offering. Proceeds from the offering will be used to fund the incremental capital required for the Line 3 Replacement Program and other general corporate purposes. In addition, the Company raised approximately $0.9 billion in cumulative redeemable preference shares, US$1.5 billion in senior notes and $0.3 billion in medium-term notes.

Forward-Looking Information and Non-GAAP Measures

This news release contains forward-looking information and references to non-GAAP measures. Significant related assumptions and risk factors, and reconciliations are described under the Forward-Looking Information and Non-GAAP Measures sections of this news release, respectively.

Effective July 1, 2014, Enbridge and Enbridge Energy Partners, L.P. (EEP) restructured the equity in EEP under which Enbridge as the General Partner (GP) of EEP will permanently waive its existing incentive distribution rights (IDR) in exchange for Class D units and new incentive distribution units (IDU). The GP share of incremental cash distributions will also decrease from 48% of all distributions in excess of US$0.4950 per unit per quarter down to 23% of all distributions in excess of the EEP’s current quarterly distribution of US$0.5435 per unit per quarter. The restructuring is intended to enhance the economics of EEP’s investment projects and growth opportunities, while at the same time re-establishing EEP as a strong sponsored vehicle and as an effective source of funding for Enbridge via future drop downs.

“This restructuring builds upon steps we initiated last year to re-establish EEP as a cost effective sponsored vehicle for Enbridge,” said Mr. Monaco. “A stronger EEP supports Enbridge’s strategic priorities of executing our growth capital program and extending growth beyond 2017.”

On July 1, 2014, EEP completed a drop down of additional interest in the natural gas and natural gas liquids (NGL) midstream business to Midcoast Energy Partners, L.P. (MEP) for cash proceeds of US$350 million, the first drop down of additional interests since the initial public offering of MEP units. As a new low cost funding vehicle, these drop downs to MEP improve EEP’s funding effectiveness and are another step to re-establishing EEP as a strong sponsored vehicle for Enbridge.

On June 17, the Canadian federal government approved the Northern Gateway Project (Northern Gateway). This approval comes after the most comprehensive review of a pipeline project in Canadian history and is subject to Northern Gateway meeting the 209 conditions issued by the Joint Review Panel (JRP).

“The federal government’s approval supports Enbridge’s view that the project can be built and operated safely, and that opening up new markets for Canadian energy is in our national interest,” said Mr. Monaco. “That said, we still have a lot of work to do. We will continue to focus on three priorities: meeting the JRP’s conditions; working with the Province of British Columbia on its five conditions for supporting oil pipelines; and continuing to engage Aboriginal communities to build further trust and support.”

Effective July 28, 2014, the Enbridge Board appointed as a director Marcel R. Coutu. Mr. Coutu is the past Chairman of Syncrude Canada Ltd., an integrated oil sands project, and the former President and Chief Executive Officer of Canadian Oil Sands Limited. He is currently a director of Brookfield Asset Management, Power Corporation of Canada, The Great-West Lifeco Inc. and IGM Financial Inc., as well as the Calgary Exhibition and Stampede Board, a non-profit organization.

Also in the second quarter, Enbridge announced that J. Richard Bird, Executive Vice President, Chief Financial Officer and Corporate Development, will retire by the end of the 2014. Upon his retirement, Mr. Bird’s role will be split into two roles: Chief Financial Officer and Chief Development Officer. In the interim, effective July 1, 2014, John Whelen has been appointed to the role of Senior Vice President, Finance, and Vern Yu has been appointed as Senior Vice President, Corporate Development.

“Richard has been a force at Enbridge for more than 20 years and has made a significant contribution to the Company’s success. While he will unquestionably be missed, our leadership succession process ensures that we have highly qualified individuals who are ready to fill critical senior roles in the Company,” said Mr. Monaco. “Richard will be supporting John and Vern in their new roles for the remainder of the year and we’re confident that his disciplined approach will carry forward.”

Results of Operations

Enbridge second quarter adjusted earnings increased by 5% to $0.40 per common share and remained at $1.00 per common share for the first half of 2014 compared with the respective 2013 comparative periods. The results were in line with management’s expectation, matching the prior year’s exceptionally strong first half. The Company remains on track to achieve its 2014 full year adjusted earnings per share guidance range.

Second quarter adjusted earnings growth was primarily driven in Liquids Pipelines and bolstered by strong supply from western Canada and increased downstream refinery demand leading to higher throughput on the Canadian Mainline. Likewise, higher throughput was also achieved on the Athabasca mainline in the Company’s Regional Oil Sands System, which also benefitted from contributions from new projects coming into service, in particular the Norealis Pipeline.

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Another key driver to the Company’s second quarter growth was contributions from the Company’s sponsored vehicles, as both EEP and Enbridge Income Fund (the Fund) delivered a second consecutive quarter of strong performance. EEP adjusted earnings growth was supported by higher throughput and tolls across the majority of its liquids pipeline assets. Earnings from the Fund also reflected strong results from its liquids business, in particular, the Saskatchewan System.

Enbridge Gas Distribution Inc. (EGD) continued to contribute to Enbridge’s reliable business model although the second quarter results were lower than the comparable period due to an increase in depreciation expense from an increased asset base and higher interest expense. EGD operated in the first half of 2014 under interim distribution rates pending approval of a five-year customized Incentive Rate (IR) application by the Ontario Energy Board (OEB). With the approval granted in July 2014, the difference in revenues under the interim rates and rates under the customized IR application will be adjusted as part of EGD’s October 2014 Quarterly Rate Adjustment Mechanism process.

Energy Services second quarter adjusted earnings were unfavourable compared with the exceptionally strong second quarter of 2013 and reflected narrowing location spreads and less favourable conditions in certain markets accessed by committed transportation capacity, with associated unrecovered demand charges.

The adjusted earnings discussed above excludes the impact of unusual, non-recurring or non-operating factors, the most significant of which are changes in unrealized derivative fair value gains and losses from the Company’s long-term hedging program, gains on the disposal of non-core assets and investments, as well as certain costs and related insurance recoveries arising from crude oil releases. See Non-GAAP Measures.

SECOND QUARTER 2014 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.

·                  Earnings attributable to common shareholders increased from $42 million in the second quarter of 2013 to $756 million in the second quarter of 2014. The Company delivered strong quarter-over-quarter earnings growth, however, the magnitude of this growth and the comparability of the Company’s quarterly results are impacted by a number of unusual, non-recurring or non-operating factors, the most significant of which is changes in unrealized derivative fair value gains and losses. The Company has a comprehensive long-term economic hedging program to mitigate interest rate, foreign exchange and commodity price exposures. The changes in unrealized mark-to-market accounting impacts from this program create volatility in short-term earnings, but the Company believes over the long-term it supports reliable cash flows and dividend growth. Other non-recurring factors impacting quarter-over-quarter comparability were remediation and long-term stabilization costs of approximately $40 million after-tax and before insurance recoveries recorded in the second quarter of 2013 related to the Line 37 crude oil release which occurred in June 2013.

·                  Enbridge’s adjusted earnings increased from $306 million in the second quarter of 2013 to $328 million in the second quarter of 2014. Liquids Pipelines adjusted earnings reflected higher contributions from Canadian Mainline and Regional Oil Sands System. Canadian Mainline adjusted earnings reflected higher throughput partially offset by the absence of revenues from Line 9B. Within Regional Oil Sands System, higher adjusted earnings were primarily attributable to higher throughput on the Athabasca mainline and contributions from the Norealis Pipeline. In Gas Distribution, EGD’s lower adjusted earnings reflected a gas transportation cost adjustment related to the first half of 2013 which was recorded in the third quarter of 2013 and higher depreciation expense due to the growth in asset base and higher interest expense. Energy Services adjusted earnings declined in the second quarter of 2014 compared with an exceptionally strong comparative 2013 period due to narrowing location spreads and less favourable conditions in certain markets accessed by committed transportation capacity. Both the Company’s sponsored vehicles, EEP and the Fund, contributed to the adjusted earnings increase and reflected strong results from their core assets. EEP adjusted earnings reflected higher contributions from the majority of its liquids business through higher throughput and tolls as well as the positive contribution from new assets placed into service. Adjusted earnings for the Fund also reflected higher earnings from its liquids business, in particular the Saskatchewan System.

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·                  On July 17, 2014, the OEB approved EGD’s five-year customized IR application, with modifications. The customized IR application establishes the methodology for establishing rates for the distribution of natural gas over a five-year period from 2014 through 2018 and will allow EGD to recover its capital investment amounts, as well as an opportunity to earn above the allowed return on equity. The OEB decision also allows for final 2014 rates to be implemented with the October 2014 Quarterly Rate Adjustment Mechanism with an effective date of January 1, 2014. EGD is currently operating under OEB approved interim distribution rates. The difference in revenues under the interim rates and rates under the customized IR will be adjusted as part of the October 2014 Quarterly Rate Adjustment Mechanism process.

·                  On July 1, 2014, Enbridge and EEP completed the equity restructuring, which was agreed to on June, 18, 2014, under which Enbridge Energy Company, Inc., a wholly owned subsidiary of Enbridge and the GP of EEP, irrevocably waived its then existing IDR in excess of its 2% GP interest in exchange for 66.1 million Class D units and 1,000 IDU (collectively, the Equity Restructuring). The Class D units carry a distribution equal to the quarterly distribution on the Class A common units. The third quarter 2014 distribution on the Class D units will be adjusted to provide Enbridge with an aggregate distribution in 2014 equal to the distribution on its IDR as if the Equity Restructuring had not occurred. The IDU will not be entitled to a distribution initially, but will in the future be entitled to 23% of any amount in excess of EEP’s current quarterly Class A common unit distribution of US$0.5435 per unit. In the event of any decrease in the Class A common unit distribution below US$0.5435 per unit in any quarter during the next five years, the distribution on the Class D units will be reduced to the amount which would have been received by Enbridge under the existing IDR as if the Equity Restructuring had not occurred.

·                  Also on July 1, 2014, Enbridge and Marathon Petroleum Corporation (MPC) reached an agreement to admit MPC as a 35% equity interest partner in the Southern Access Extension project (Southern Access Extension). MPC will also make additional cash contributions in accordance with the Southern Access Extension spend profile in proportion to its 35% interest. The Southern Access Extension was announced as part of Enbridge’s Light Oil Market Access Program in December 2012 and will involve the construction of a new 265-kilometre (165-mile) 24-inch diameter crude oil pipeline from Flanagan, Illinois to Patoka, Illinois, for an initial capacity of approximately 300,000 barrels per day, as well as additional tankage and two new pump stations. Subject to regulatory and other approvals, Southern Access Extension is expected to be placed into service in mid-2015 and Enbridge’s share of the project is expected to be approximately US$0.6 billion.

·                  On June 18, 2014, Enbridge announced that J. Richard Bird, Executive Vice President, Chief Financial Officer and Corporate Development, plans to retire by the end of 2014. Upon Mr. Bird’s retirement, his responsibilities will be split into two separate roles of Chief Financial Officer and Chief Development Officer. Enbridge also announced the appointment of John Whelen as Senior Vice President, Finance and Vern Yu as Senior Vice President, Corporate Development, effective July 1, 2014.

·                  Since the end of the first quarter of 2014, the Company completed the following financing transactions:

·                  On July 17, 2014, Enbridge completed an offering of 14 million Cumulative Redeemable Preference Shares, Series 13 for gross proceeds of $350 million.

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·                  On June 24, 2014, Enbridge completed an offering of 7.9 million Common Shares for gross proceeds of approximately $400 million and on July 8, 2014 issued a further 1.2 million

Common Shares pursuant to the underwriters’ over-allotment option for gross process of approximately $60 million.

·                  On June 4, 2014, Enbridge issued senior notes of US$500 million with a three-year maturity, US$500 million with a 10-year maturity and US$500 million with a 30-year maturity.

·                  On May 22, 2014, Enbridge completed an offering of 20 million Cumulative Redeemable Preference Shares, Series 11, for gross proceeds of $500 million.

·                  On April 22, 2014, Enbridge issued medium-term notes of $300 million with a three-year maturity through its subsidiary EGD.

DIVIDEND DECLARATION

On July 29, 2014, the Enbridge Board of Directors declared the following quarterly dividends. All dividends are payable on September 1, 2014 to shareholders of record on August 15, 2014.

1                  This first dividend declared for the Preference Shares, Series 11 includes accrued dividends from May 22, 2014, the date the shares were issued. The regular quarterly dividend of $0.275 per share will take effect on December 1, 2014.

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CONFERENCE CALL

Enbridge will hold a conference call on Friday, August 1, 2014 at 9:00 a.m. Eastern Time (7:00 a.m. Mountain Time) to discuss the second quarter 2014 results. Analysts, members of the media and other interested parties can access the call toll-free at 1-800-708-4540 from within North America and outside North America at 1-847-619-6397, using the access code of 37572724#. The call will be audio webcast live at http://www.media-server.com/m/p/86coq5ug. 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 will be available toll-free at 1-888-843-7419 within North America and outside North America at 1-630-652-3042 (access code 37572724#) until August 8, 2014.

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

Enbridge Inc., a Canadian Company, is a North American leader in delivering energy and has been included on the Global 100 Most Sustainable Corporations in the World ranking for the past six years. 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 significant and growing involvement in natural gas gathering, transmission and midstream businesses, and an increasing involvement in power transmission. As a distributor of energy, Enbridge owns and operates Canada’s largest natural gas distribution company, and provides distribution services in Ontario, Quebec, New Brunswick and New York State. As a generator of energy, Enbridge has interests in more than 1,800 megawatts of renewable and alternative energy generating capacity and is expanding its interests in wind and solar energy and geothermal. Enbridge employs more than 10,000 people, primarily in Canada and the U.S. and is ranked as one of Canada’s Top 100 Employers for 2014. Enbridge’s common shares trade on the Toronto and New York stock exchanges under the symbol ENB. For more information, visit www.enbridge.com. None of the information contained in, or connected to, Enbridge’s website is incorporated in or otherwise part of this news release.

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/(loss) or adjusted earnings/(loss); expected earnings/(loss) or adjusted earnings/(loss) per share; expected future cash flows; 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 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, NGL and renewable energy; prices of crude oil, natural gas, NGL and renewable energy; expected exchange rates; inflation; interest rates; the availability and price of labour and pipeline construction materials; operational reliability; customer and regulatory 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, NGL and renewable energy, 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, and 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/(loss) or adjusted earnings/(loss) 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 date and expected capital expenditures include: the availability and price of labour and 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.

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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, changes in tax law and tax rate increases, 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 unusual, non-recurring or non-operating factors on both a consolidated and segmented basis. These factors, referred to as adjusting items, are reconciled and discussed in the financial results sections for the affected business segments in the Company’s MD&A. Adjusting items referred to as changes in unrealized derivative fair value gains or loss are presented net of amounts realized on the settlement of derivative contracts during the applicable period. Management believes 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, including setting the Company’s dividend payout target, and to assess the performance of the Company. Adjusted earnings/(loss) and adjusted earnings/(loss) for each of the segments are not measures that have a standardized meaning prescribed by accounting principles generally accepted in the United States of America (U.S. 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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NON-GAAP RECONCILIATIONS

1                  Changes in unrealized derivative fair value gains and losses are presented net of amounts realized on the settlement of derivative contracts during the applicable period.

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HIGHLIGHTS

1                  Adjusted earnings represent earnings attributable to common shareholders adjusted for unusual, 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.

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2                  Canadian Mainline includes deliveries ex-Gretna, Manitoba which is made up of United States and eastern Canada deliveries originating from western 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 EGD 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 EGD’s franchise area. It is calculated by accumulating, for the fiscal period, the total number of degrees each day by which the daily mean temperature falls below 18 degrees Celsius. The figures given are those accumulated in the Greater Toronto Area.

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ENBRIDGE INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS

June 30, 2014

MANAGEMENT’S DISCUSSION AND ANALYSIS

FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2014

This Management’s Discussion and Analysis (MD&A) dated July 31, 2014 should be read in conjunction with the unaudited interim 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, 2014, prepared in accordance with accounting principles generally accepted in the United States of America (U.S. 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, 2013. 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.

CONSOLIDATED EARNINGS

Earnings attributable to common shareholders were $756 million for the three months ended June 30, 2014, or $0.92 per common share, compared with $42 million or $0.05 per common share, for the three months ended June 30, 2013. The Company delivered strong quarter-over-quarter earnings growth, however, the magnitude of this growth and the comparability of the Company’s quarterly results are impacted by a number of unusual, non-recurring or non-operating factors, the most significant of which is changes in unrealized derivative fair value gains and losses. The Company has a comprehensive long-term economic hedging program to mitigate interest rate, foreign exchange and commodity price exposures. The changes in unrealized mark-to-market accounting impacts from this program create volatility in short-term earnings, but the Company believes over the long-term it supports reliable cash flows and dividend growth. Other non-recurring factors impacting quarter-over-quarter comparability were remediation and long-term stabilization costs of approximately $40 million after-tax and before insurance recoveries recorded in the second quarter of 2013 related to the Line 37 crude oil release which occurred in June 2013.

Earnings attributable to common shareholders were $1,146 million for the six months ended June 30, 2014, or $1.39 per common share, compared with $292 million, or $0.37 per common share, for the six months ended June 30, 2013. In addition to the trends experienced in the three month period discussed above, earnings for the six months ended June 30, 2014 reflected a $43 million after-tax gain recognized on the disposal of non-core assets within Enbridge Offshore Pipelines (Offshore) and a $14 million after-tax gain on the sale of an Alternative and Emerging Technologies investment within the Corporate segment. Also impacting the comparability between the two periods were accruals related to the Line 6B crude oil release. For the six months ended June 30, 2014, the Company recognized an accrual of US$35 million ($5 million after-tax attributable to Enbridge) compared with US$215 million ($30 million after-tax attributable to Enbridge) for the six months ended June 30, 2013. Also reflected in earnings for the first half of 2013 was US$42 million ($6 million after-tax attributable to Enbridge) of insurance recoveries recognized as a reduction to environmental costs for the Line 6B crude oil release. For discussion on Line 6B leak remediation costs and associated insurance recoveries refer to Recent Developments – Sponsored Investments – Enbridge Energy Partners, L.P. – Line 6B Crude Oil Release.

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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 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/(loss) or adjusted earnings/(loss); expected earnings/(loss) or adjusted earnings/(loss) per share; expected future cash flows; 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 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, natural gas liquids (NGL) and renewable energy; prices of crude oil, natural gas, NGL and renewable energy; expected exchange rates; inflation; interest rates; the availability and price of labour and pipeline construction materials; operational reliability; customer and regulatory 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, NGL and renewable energy, 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, and 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/(loss) or adjusted earnings/(loss) 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 date and expected capital expenditures include: the availability and price of labour and 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, changes in tax law and tax rate increases, 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.

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NON-GAAP MEASURES

This MD&A contains references to adjusted earnings/(loss), which represent earnings or loss attributable to common shareholders adjusted for unusual, non-recurring or non-operating factors on both a consolidated and segmented basis. These factors, referred to as adjusting items, are reconciled and discussed in the financial results sections for the affected business segments. Adjusting items referred to as changes in unrealized derivative fair value gains or loss are presented net of amounts realized on the settlement of derivative contracts during the applicable period. Management believes 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, including setting the Company’s dividend payout target, and to assess the performance of the Company. Adjusted earnings/(loss) and adjusted earnings/(loss) for each of the segments are not measures that have a standardized meaning prescribed by U.S. 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.

ADJUSTED EARNINGS

Adjusted earnings were $328 million, or $0.40 per common share, for the three months ended June 30, 2014 compared with $306 million, or $0.38 per common share, for the three months ended June 30, 2013. Adjusted earnings were $820 million, or $1.00 per common share, for the six months ended June 30, 2014 compared with $794 million, or $1.00 per common share, for the six months ended June 30, 2013.

The following factors impacted adjusted earnings:

·                  Within Liquids Pipelines, higher throughput on Canadian Mainline drove an increase in adjusted earnings. The increase in throughput was attributable to several factors: increased oil sands production; volumes diverted from competing systems; strong refinery demand in the midwest market partly due to a start-up of a midwest refinery’s conversion to heavy oil processing in the second quarter of 2014; and successful efforts by the Company to optimize capacity and throughput and to enhance scheduling efficiency with shippers. Canadian Mainline adjusted earnings continued to be impacted by the absence of revenues from Line 9B, which was idled in late 2013. As part of the Company’s Eastern Access initiative, Line 9B is being reversed and expanded and is expected to return to service in the fourth quarter of 2014.

·                  Also within Liquids Pipelines, Regional Oil Sands System adjusted earnings increased due to contributions from the Norealis Pipeline, which was completed in April 2014, and higher throughput on the Athabasca mainline which were partially offset by higher operating and administrative, depreciation, interest and tax expenses.

·                  Within Gas Distribution, Enbridge Gas Distribution Inc.’s (EGD) lower adjusted earnings primarily reflected a gas transportation cost adjustment related to the first half of 2013 which was recorded in the third quarter of 2013. Excluding the impact of the gas transportation adjustment, EGD’s results were moderately lower and reflected higher depreciation expense due to the growth in asset base.

·                  Within Gas Pipelines, Processing and Energy Services, the decrease in adjusted earnings reflected lower Energy Services results compared with an exceptionally strong second quarter and first half of 2013. Narrowing location spreads and less favourable conditions in certain markets accessed by committed transportation capacity resulted in lower adjusted earnings in the second quarter of 2014. For the six months ended June 30, 2014, in addition to the second quarter trends noted above, adjusted earnings decreased as a result of losses realized on certain financial contracts intended to hedge the value of committed transportation capacity, but which were not effective in doing so. Partially offsetting the decrease in adjusted earnings within Energy Services in the first half of 2014 were favourable natural gas location differentials caused by abnormal winter weather conditions in the first quarter of 2014.

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·                  Within Sponsored Investments, Enbridge Energy Partners, L.P. (EEP) adjusted earnings reflected increased contributions from EEP’s liquids business due to higher throughput and tolls, as well as contributions from new assets placed into service. Partially offsetting these positive contributions were lower volumes within EEP’s natural gas and NGL businesses.

·                  Also within Sponsored Investments, Enbridge Income Fund (the Fund) earnings reflected strong performance in the Fund’s liquids business, in particular the Saskatchewan System during the second quarter of 2014 and the Bakken Expansion Pipeline during the first quarter of 2014. Also contributing to period-over-period growth in earnings for the first half of 2014 was the absence of an after-tax charge of $12 million ($4 million after-tax attributable to Enbridge) related to the write-off of a regulatory deferral balance which occurred in the first quarter of 2013.

·                  Within the Corporate segment, Noverco Inc. (Noverco) adjusted earnings decreased in the first half of 2014 due to the impact of a small one-time gain on a sale of an investment and an equity earnings true-up adjustment, both of which were captured in the first quarter of 2013. Excluding the impacts of these two items, Noverco adjusted earnings were comparable between periods.

·                  Also within Corporate segment, a higher Other Corporate loss was recognized in the second quarter of 2014 due to higher preference share dividends from an increase in the number of preference shares outstanding, partially offset by lower net Corporate segment financing costs.

RECENT DEVELOPMENTS

CHIEF FINANCIAL OFFICER SUCCESSION PLANS

On June 18, 2014, the Company announced that J. Richard Bird, Executive Vice President, Chief Financial Officer and Corporate Development, plans to retire by the end of 2014. Upon Mr. Bird’s retirement, his responsibilities will be split into two separate roles of Chief Financial Officer and Chief Development Officer. Enbridge also announced the appointment of John Whelen as Senior Vice President, Finance and of Vern Yu as Senior Vice President, Corporate Development effective July 1, 2014.

LIQUIDS PIPELINES

Seaway Pipeline

Seaway Crude Pipeline System (Seaway Pipeline) filed an application for market-based rates in December 2011. Initially the Federal Energy Regulatory Commission (FERC) rejected the application in March 2012 and Seaway Pipeline appealed to the District of Columbia Circuit. In response, the FERC set the application for further proceedings and the appeal was stayed. Since the FERC had not issued a ruling on this application, Seaway Pipeline filed for initial rates in order to have rates in effect by the in-service date. The uncommitted rate on Seaway Pipeline was challenged by several shippers. During the evidentiary stage, FERC staff filed evidence stating that the committed and uncommitted rates are subject to review and adjustment. Seaway Pipeline filed a Petition for Declaratory Order (PDO) requesting the FERC confirm that it will honour and uphold existing contracts. The FERC issued a decision denying the PDO on procedural grounds but stated that it will uphold its longstanding policy of honouring contracts.

FERC hearings concluded with all parties filing their respective briefs. In September 2013, a decision from the Administrative Law Judge (ALJ) was released finding that the committed and uncommitted rates on Seaway Pipeline should be reduced to reflect the ALJ’s findings on the various cost of service inputs. Seaway Pipeline filed a brief with the FERC on October 15, 2013 challenging the ALJ’s decision and asking for expedited ruling by the FERC on the committed rates. In February 2014, the FERC issued its decision upholding its policy to honour contracts and ordered the ALJ to revise its decision accordingly. On May 9, 2014, the ALJ issued an initial decision on remand reiterating its previous findings and did not change its decision. Briefings have concluded and the full record will be sent to the FERC for its final decision. It is expected that the FERC’s decision will be expedited.

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In relation to the original market based rate application, the FERC issued its decision rejecting Seaway Pipeline’s application for market based rates in February 2014 and announced a new methodology for determining whether a pipeline has market power and invited Seaway Pipeline to refile its market based rate application consistent with the new policy. Seaway Pipeline is currently evaluating whether it will file a new market based rate application under the new methodology.

GAS DISTRIBUTION

Enbridge Gas Distribution – Incentive Regulation

On July 17, 2014, the Ontario Energy Board (OEB) approved EGD’s five-year customized Incentive Rate (IR) application, with modifications. The customized IR application establishes the methodology for establishing rates for the distribution of natural gas over a five-year period from 2014 through 2018 and will allow EGD to recover its capital investment amounts, as well as an opportunity to earn above the allowed return on equity. The OEB decision also allows for final 2014 rates to be implemented with the October 2014 Quarterly Rate Adjustment Mechanism with an effective date of January 1, 2014. EGD is currently operating under OEB approved interim distribution rates. The difference in revenues under the interim rates and rates under the customized IR will be adjusted as part of the October 2014 Quarterly Rate Adjustment Mechanism process on a prospective basis.

Enbridge Gas New Brunswick – Regulatory Matter

In 2012, the Government of New Brunswick enacted final rates and tariff regulation that affected the franchise agreement between Enbridge Gas New Brunswick Inc. (EGNB) and the province of New Brunswick, including the ability for EGNB to recover a deferred regulatory asset.

Also in 2012, EGNB commenced legal proceedings against the Government of New Brunswick seeking damages for breach of contract and commenced a separate application to quash the Government of New Brunswick’s rate and tariffs regulation. EGNB’s appeal was ultimately successful in part, as the Court of Appeal ruled that the rates and tariffs regulation that caps rates according to a maximum revenue-to-cost ratio was beyond the regulation-making authority of the New Brunswick Lieutenant Governor in Council. The Court upheld the portion of the regulation that requires EGNB to charge customers the lower of market or cost-based rates. Following a series of decisions by the New Brunswick Energy and Utilities Board that enabled EGNB to recover its revenue requirement from August 2013 to the next rate period, EGNB filed its 2014 rate application in October 2013. The application was approved in April 2014.

On February 4, 2014, EGNB commenced a further legal proceeding against the Government of New Brunswick. The action seeks damages for improper extinguishment of the deferred regulatory asset that was previously eliminated from EGNB’s Consolidated Statements of Financial Position.

There is no assurance that any of EGNB’s legal proceedings against the Province of New Brunswick will be successful or will result in any recovery.

SPONSORED INVESTMENTS – ENBRIDGE ENERGY PARTNERS, L.P.

Enbridge Energy Partners, L.P. Equity Restructuring

In June 2014, EEP and Enbridge announced an agreement to restructure EEP’s equity with the objective of enhancing the economics of EEP’s investment projects and growth opportunities, while at the same time re-establishing EEP as a strong sponsored vehicle and as an effective source of funding for Enbridge via future drop downs.

Effective July 1, 2014, Enbridge Energy Company, Inc., a wholly owned subsidiary of Enbridge and the General Partner (GP) of EEP, irrevocably waived its then existing incentive distribution rights (IDR) in excess of its 2% GP interest in exchange for 66.1 million Class D units and 1,000 Incentive Distribution Units (IDU) (collectively, the Equity Restructuring). The GP share of incremental cash distributions will also decrease from 48% of all distributions in excess of US$0.4950 per unit per quarter down to 23% of all distributions in excess of EEP’s quarterly distribution of US$0.5435 per unit per quarter. The Class D units carry a distribution equal to the quarterly distribution on the Class A common units. The third quarter 2014 distribution on the Class D units will be adjusted to provide Enbridge with an aggregate distribution in 2014 equal to the distribution on its IDR as if the Equity Restructuring had not occurred. The IDU will not be entitled to a distribution initially and in the event of any decrease in the Class A common unit distribution below US$0.5435 per unit in any quarter during the next five years, the distribution on the Class D units will be reduced to the amount which would have been received by Enbridge under the existing IDR as if the Equity Restructuring had not occurred.

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The Class D units have a notional value per unit equivalent to the closing market price of the Class A Common units on June 17, 2014 (Notional Value) and have the same voting rights as the Class A units. The Class D units are convertible on a one-for-one basis into Class A common units at any time on or after the fifth anniversary of the closing date, at the holder’s option. In the event of a liquidation event (or any merger or other extraordinary transaction), the Class D unitholders will have a preference in liquidation equal to 20% of the Notional Value, with such preference being increased by an additional 20% on each anniversary of the closing date, resulting in a liquidation preference equal to 100% of the Notional Value on the fourth anniversary of the closing date. The Class D units will be redeemable in 30 years in whole or in part at EEP’s option for either a cash amount equal to the Notional Value per unit or newly issued Class A common units with an aggregate market value at redemption equal to 105% of the aggregate Notional Value of the Class D units being redeemed.

EEP Drop Down of Additional Interest to Midcoast Energy Partners, L.P.

On July 1, 2014, EEP completed the sale of an additional 12.6% limited partnership interest in its natural gas and NGL midstream business to Midcoast Energy Partners, L.P. (MEP) for cash proceeds of US$350 million. Since finalization of this transaction, EEP held an approximate 48% direct interest in entities or partnerships holding the natural gas and NGL midstream operations, with the remaining ownership held by MEP. The balance of EEP’s interest in the natural gas and NGL midstream operations is held indirectly through ownership of a GP interest, an approximate 52% limited partner interest and all incentive distribution rights of MEP. The completion of this transaction resulted in a partial monetization of EEP’s natural gas and NGL midstream business through sale to noncontrolling interests (being MEP’s public unitholders). The proceeds from the drop down provided EEP a cost-effective funding alternative to execute its current liquids pipeline organic growth program.

Line 6B Crude Oil Release

EEP continues to perform necessary remediation, restoration and monitoring of the areas affected by the Line 6B crude oil release. All the initiatives EEP is undertaking in the monitoring and restoration phase are intended to restore the crude oil release area to the satisfaction of the appropriate regulatory authorities. On March 14, 2013, EEP received an order from the Environmental Protection Agency (EPA) which defined the scope requiring additional containment and active recovery of submerged oil relating to the Line 6B crude oil release. EEP submitted its initial proposed work plan required by the EPA on April 4, 2013 and resubmitted the work plan on April 23, 2013 and again on May 1, 2013 based on EPA comments. The EPA approved the Submerged Oil Recovery and Assessment (SORA) work plan with modification on May 8, 2013. EEP incorporated the modification and submitted an approved SORA on May 13, 2013. At this time, EEP has completed substantially all of the SORA, with the exception of required dredging in and around Morrow Lake and its delta.

EEP is also working with the Michigan Department of Environmental Quality (MDEQ) to transition submerged oil reassessment, sheen management and sediment trap monitoring and maintenance activities from the EPA to the MDEQ, through a Kalamazoo River Residual Oil Monitoring and Maintenance Work Plan.

As at June 30, 2014, EEP’s total cost estimate for the Line 6B crude oil release was US$1,157 million ($186 million after-tax attributable to Enbridge), which is an increase of US$35 million ($5 million after-tax attributable to Enbridge) as compared with December 31, 2013 and March 31, 2014. On May 28, 2014, the MDEQ’s Water Resource Division approved EEP’s Schedule of Work for the remainder of 2014. Approximately US$30 million of the increase in the total cost estimate during the three months ended June 30, 2014 is primarily related to the finalization of the MDEQ approved Schedule of Work and other costs related to the on-going river restoration activities near Ceresco.

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Expected losses associated with the Line 6B crude oil release included those costs that were considered probable and that could be reasonably estimated at June 30, 2014. Despite the efforts EEP has made to ensure the reasonableness of its estimates, there continues to be the potential for EEP to incur additional costs in connection with this crude oil release due to variations in any or all of the cost categories, including modified or revised requirements from regulatory agencies, in addition to fines and penalties and expenditures associated with litigation and settlement of claims.

Insurance Recoveries

EEP is included in the comprehensive insurance program that is maintained by Enbridge for its subsidiaries and affiliates which renews throughout the year. On May 1 of each year, the insurance program is up for renewal and includes commercial liability insurance coverage that is consistent with coverage considered customary for its industry and includes coverage for environmental incidents excluding costs for fines and penalties.

A majority of the costs incurred in connection with the crude oil release for Line 6B are covered by Enbridge’s comprehensive insurance policy that expired on April 30, 2011, which had an aggregate limit of US$650 million for pollution liability. Including EEP’s remediation spending through June 30, 2014, Enbridge and its affiliates have exceeded the limits of their coverage under this insurance policy. Additionally, fines and penalties would not be covered under the existing insurance policy. As at June 30, 2014, EEP has recorded total insurance recoveries of US$547 million ($80 million after-tax attributable to Enbridge) for the Line 6B crude oil release out of the US$650 million aggregate limit. EEP will record receivables for additional amounts it claims for recovery pursuant to its insurance policies during the period it deems recovery to be probable.

In March 2013, EEP and Enbridge filed a lawsuit against the insurers for the then remaining US$145 million coverage, as one particular insurer is disputing the recovery eligibility for costs related to EEP’s claim on the Line 6B crude oil release and the other remaining insurers assert that their payment is predicated on the outcome of the recovery from that insurer. EEP received a partial recovery payment of US$42 million from the other remaining insurers. Of the remaining US$103 million coverage limit, US$85 million is the subject matter of the lawsuit Enbridge filed in March 2013 against one particular insurer who is disputing EEP’s recovery eligibility for costs related to its claim on the Line 6B oil release. The recovery of the remaining US$18 million is awaiting resolution of this lawsuit. While EEP believes those costs are eligible for recovery, there can be no assurance that EEP will prevail in this lawsuit.

Enbridge renewed its comprehensive property and liability insurance programs under which the Company is insured through April 30, 2015 with a liability aggregate limit of US$700 million, including sudden and accidental pollution liability. The deductible applicable to oil pollution events was increased to US$30 million per event, from the previous US$10 million. In the unlikely event multiple insurable incidents occur which exceed coverage limits within the same insurance period, the total insurance coverage will be allocated among Enbridge entities on an equitable basis based on an insurance allocation agreement among Enbridge and its subsidiaries.

Legal and Regulatory Proceedings

A number of United States governmental agencies and regulators have initiated investigations into the Line 6B crude oil release. Approximately 17 actions or claims are pending against Enbridge, EEP or their affiliates in United States federal and state courts in connection with the Line 6B crude oil release, including direct actions and actions seeking class status. Based on the current status of these cases, the Company does not expect the outcome of these actions to be material.

As at June 30, 2014, included in EEP’s estimated costs related to the Line 6B crude oil release is US$30 million in fines and penalties. Due to the absence of sufficient information, EEP cannot provide a reasonable estimate of the liability for potential additional fines and penalties that could be assessed in connection with the Line 6B release. Discussions with governmental agencies regarding fines and penalties are ongoing.

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CORPORATE

Preference Share Issuance

Series 9

On March 13, 2014, the Company issued 11 million Preference Shares, Series 9 for gross proceeds of $275 million. The 4.4% Cumulative Redeemable Preference Shares, Series 9 are entitled to receive a fixed, cumulative, quarterly preferential dividend of $1.10 per share per annum. The Company may, at its option, redeem all or a portion of the outstanding Preference Shares for $25.00 per share plus all accrued and unpaid dividends on December 1, 2019 and on December 1 of every fifth year thereafter. The holders of Preference Shares, Series 9 will have the right to convert their shares into Cumulative Redeemable Preference Shares, Series 10, subject to certain conditions, on December 1, 2019 and on December 1 of every fifth year thereafter. The holders of Preference Shares, Series 10 will be entitled to receive quarterly floating rate cumulative dividends at a rate equal to the sum of the then 90-day Government of Canada treasury bill rate plus 2.7%.

Series 11

On May 22, 2014, the Company issued 20 million Preference Shares, Series 11 for gross proceeds of $500 million. The 4.4% Cumulative Redeemable Preference Shares, Series 11 are entitled to receive a fixed, cumulative, quarterly preferential dividend of $1.10 per share per annum. The Company may, at its option, redeem all or a portion of the outstanding Preference Shares for $25.00 per share plus all accrued and unpaid dividends on March 1, 2020 and on March 1 of every fifth year thereafter. The holders of Preference Shares, Series 11 will have the right to convert their shares into Cumulative Redeemable Preference Shares, Series 12, subject to certain conditions, on March 1, 2020 and on March 1 of every fifth year thereafter. The holders of Preference Shares, Series 12 will be entitled to receive quarterly floating rate cumulative dividends at a rate equal to the sum of the then 90-day Government of Canada treasury bill rate plus 2.6%.

Series 13

On July 17, 2014, the Company issued 14 million Preference Shares, Series 13 for gross proceeds of $350 million. The 4.4% Cumulative Redeemable Preference Shares, Series 13 are entitled to receive a fixed, cumulative, quarterly preferential dividend of $1.10 per share per annum. The Company may, at its option, redeem all or a portion of the outstanding Preference Shares for $25.00 per share plus all accrued and unpaid dividends on June 1, 2020 and on June 1 of every fifth year thereafter. The holders of Preference Shares, Series 13 will have the right to convert their shares into Cumulative Redeemable Preference Shares, Series 14, subject to certain conditions, on June 1, 2020 and on June 1 of every fifth year thereafter. The holders of Preference Shares, Series 14 will be entitled to receive quarterly floating rate cumulative dividends at a rate equal to the sum of the then 90-day Government of Canada treasury bill rate plus 2.7%.

Common Share Issuance

On June 24, 2014, the Company completed the issuance of 7.9 million Common Shares for gross proceeds of approximately $400 million and on July 8, 2014, issued a further 1.2 million Common Shares pursuant to the underwriters’ over-allotment option for gross proceeds of approximately $60 million. The proceeds will be used to partially fund the Company’s capital projects, including the Line 3 Replacement Program (L3R Program), to reduce short term indebtedness and for other general corporate purposes. For further discussion on the L3R Program refer to Growth Projects – Commercially Secured Projects – Liquids Pipelines – Canadian Line 3 Replacement Program and Growth Projects – Commercially Secured Projects – Sponsored Investments – Enbridge Energy Partners, L.P. – United States Line 3 Replacement Program.

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GROWTH PROJECTS — COMMERCIALLY SECURED PROJECTS

The table below summarizes the current status of the Company’s commercially secured projects, organized by business segment.

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

2            Expenditures to date reflect total cumulative expenditures incurred from inception of the project up to June 30, 2014.

3            The Athabasca Pipeline Twinning is now expected to be delayed beyond its original in service date due to a change in the construction schedule to align with the shipper volume availability.

4            Enbridge will construct and operate the Norlite Pipeline System. Keyera Corp. will fund 30% of the project.

5            The Eastern Access and Lakehead System Mainline Expansion projects are funded 75% by Enbridge and 25% by EEP.

6            Enbridge will construct and operate the Sandpiper Project. Marathon Petroleum Corporation will fund 37.5% of the project.

LIQUIDS PIPELINES

Seaway Crude Pipeline System

Enbridge holds a 50% interest in the Seaway Pipeline which includes an 805-kilometre (500-mile) 30-inch diameter long-haul system between Cushing, Oklahoma and Freeport, Texas.

Reversal and Expansion

The flow direction of the Seaway Pipeline was reversed in 2012, enabling it to transport crude oil from the oversupplied hub in Cushing, Oklahoma to the Gulf Coast. Further pump station additions and modifications were completed in 2013, increasing capacity available to shippers to up to approximately 400,000 barrels per day (bpd), depending on crude oil slate.

Twinning and Extension

A second line to more than double the existing capacity of the Seaway Pipeline to approximately 850,000 bpd was mechanically completed in July 2014. This 30-inch diameter pipeline follows the same route as the existing Seaway Pipeline and was constructed to meet additional capacity commitments from shippers. Included in the project scope is the 105-kilometre (65-mile), 36-inch diameter pipeline lateral from the Seaway Jones Creek facility southwest of Houston, Texas to Enterprise Product Partners L.P.’s ECHO crude oil terminal (ECHO Terminal) in Houston, Texas. The lateral was placed into service in January 2014.

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In addition, a 161-kilometre (100-mile) pipeline is being constructed from the ECHO Terminal to the Port Arthur/Beaumont, Texas refining centre to provide shippers access to the region’s heavy oil refining capabilities. This extension will provide capacity of 750,000 bpd and was substantially completed in July 2014.

Including the acquisition of the initial 50% interest, Enbridge’s total expected cost for the Seaway Pipeline is now approximately US$2.5 billion. The acquisition, reversal and expansion were completed at an approximate cost of US$1.3 billion, with the twinning, extension and lateral components of the project expected to cost approximately US$1.2 billion. Total expenditures incurred to date are approximately US$2.4 billion.

Eastern Access

The Eastern Access initiative includes a series of Enbridge and EEP crude oil pipeline projects to provide increased access to refineries in the upper midwest United States and eastern Canada. Projects being undertaken by Enbridge include a partial reversal of Line 9A, a full reversal and expansion of Line 9B and expansion of the Toledo Pipeline. For discussion on EEP’s portion of Eastern Access refer to Growth Projects – Commercially Secured Projects – Sponsored Investments – Enbridge Energy Partners, L.P. – Eastern Access.

In 2013, Enbridge completed the 80,000 bpd expansion of its Toledo Pipeline (Line 17), which connects with the EEP mainline at Stockbridge, Michigan and serves refineries at Toledo, Ohio and Detroit, Michigan. The project was completed at an approximate cost of US$0.2 billion.

In 2013, Enbridge also completed the reversal of a portion of its Line 9A in western Ontario to permit crude oil movements eastbound from Sarnia as far as Westover, Ontario. Enbridge is also undertaking a full reversal of its 240,000 bpd Line 9B from Westover, Ontario to Montreal, Quebec to serve refineries in Quebec. The Line 9B reversal was expected to be completed at an estimated cost of approximately $0.3 billion. Following an open season held on the Line 9B reversal project, further commitments were received that required additional delivery capacity within Ontario and Quebec, resulting in the Line 9B capacity expansion project. The Line 9B capacity expansion will increase the annual capacity of Line 9B from 240,000 bpd to 300,000 bpd at an estimated cost of approximately $0.1 billion.

Both the Line 9B reversal and Line 9B capacity expansion projects were approved by the National Energy Board (NEB) in March 2014 subject to 30 conditions. The conditions imposed by the NEB, including costs associated with additional NEB mandated integrity testing increased the total expected cost of the projects to $0.7 billion, inclusive of costs related to the previously discussed Line 9A reversal. Enbridge is currently in discussions with shippers to recover the incremental costs of Line 9B through tolls. Subject to fulfillment of the NEB conditions, both projects are expected to be available for service in the fourth quarter of 2014. Total expenditures to date on the Line 9A and Line 9B projects are approximately $0.4 billion.

Eddystone Rail Project

In April 2014, under a joint venture agreement with Canopy Prospecting Inc., the Company completed the development of a unit-train unloading facility and related local pipeline infrastructure near Philadelphia, Pennsylvania to deliver Bakken and other light sweet crude oil to Philadelphia area refineries. The Eddystone Rail Project (Eddystone) included leasing portions of a power generation facility and involved replacing and twinning the existing track to accommodate 120-car unit-trains, installing crude oil offloading equipment, refurbishing an existing 200,000 barrel tank and upgrading an existing barge loading facility. Eddystone is capable of receiving and delivering an initial capacity of 80,000 bpd, and could be expanded to 160,000 bpd. Based on its 75% joint venture interest, Enbridge’s investment in the project was approximately US$0.1 billion.

Norealis Pipeline

In order to provide pipeline and terminalling services to the Husky Energy Inc. operated Sunrise Energy Project that is currently under development, Enbridge constructed a new originating terminal (Norealis Terminal), a 112-kilometre (66-mile) 24-inch diameter pipeline from the Norealis Terminal to the Cheecham Terminal and additional tankage at Cheecham. The Norealis Pipeline project was completed in April 2014 at a total cost of approximately $0.5 billion. Enbridge expects to receive first oil in the second half of 2014, commensurate with the start-up of the Sunrise Energy project.

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Flanagan South Pipeline Project

The 950-kilometre (590-mile) Flanagan South Pipeline (Flanagan South) will have an initial design capacity of approximately 600,000 bpd; however, in the initial years it is not expected to operate at its full design capacity. Flanagan South will transport crude oil from the Company’s terminal at Flanagan, Illinois to Cushing, Oklahoma. The 36-inch diameter pipeline is being installed adjacent to the Company’s Spearhead Pipeline for the majority of the route. Flanagan South is expected to be mechanically complete by mid-October 2014. The estimated cost of the project is approximately US$2.8 billion, with expenditures to date of approximately US$2.5 billion.

The Sierra Club and National Wildlife Federation (the Plaintiff) filed a complaint for Declaratory and Injunctive Relief (the Complaint) with the United States District Court for the District of Columbia (the Court) in August 2013. The Complaint was filed against multiple federal agencies (the Defendants) and included a request that the Court issue a preliminary injunction suspending previously granted federal permits and ordering Enbridge to discontinue construction of the project on the basis that the Defendants failed to comply with environmental review standards of the National Environmental Protection Act. Enbridge obtained intervener status and joined the Defendants in filing a response in opposition to the motion for preliminary injunction in September 2013. The Plaintiff’s request for preliminary injunction was denied by the Court in November 2013. A court hearing was held on February 21, 2014 concerning the merits of the Complaint against the federal agencies, but no decision has yet been released.

Canadian Mainline Expansion

Enbridge is undertaking an expansion of the Alberta Clipper line between Hardisty, Alberta and the Canada/United States border near Gretna, Manitoba. The scope of the project consists of two phases which involve the addition of pumping horsepower to raise the capacity of the Alberta Clipper line from 450,000 bpd to 800,000 bpd. The initial phase to increase capacity from 450,000 bpd to 570,000 bpd is expected to be substantially complete in September 2014 at an estimated capital cost of approximately $0.2 billion. Delays in receipt of the applicable regulatory approvals on EEP’s portion of the mainline system expansion are expected to delay the full operation of the first phase of the Canadian Mainline Expansion. However, a number of temporary system optimization actions are being undertaken to substantially mitigate any impact on throughput associated with the initial 120,000 bpd capacity increase. See Growth Projects – Commercially Secured Projects – Sponsored Investments – Enbridge Energy Partners, L.P. – Lakehead System Mainline Expansion.

The second phase to increase capacity from 570,000 bpd to 800,000 bpd is expected to be placed into service in 2015. The second phase is expected to cost approximately $0.5 billion following the completion of a detailed engineering review conducted in the first quarter of 2014. The revised estimate reflected enhanced tanking, terminalling and connectivity to optimize pipeline operation at the full 800,000 bpd design capacity. The estimated cost of the entire expansion is approximately $0.7 billion, with expenditures to date of approximately $0.2 billion.

Surmont Phase 2 Expansion

The Company entered into a terminal services agreement with ConocoPhillips Canada Resources Corp. (ConocoPhillips) and Total E&P Canada Ltd. (the ConocoPhillips Partnership) to expand the Cheecham Terminal to accommodate incremental bitumen production from Surmont’s Phase 2 expansion. The Company is constructing two new 450,000 barrel blend tanks and converting an existing tank from blend to diluent service. The expansion is expected to come into service in two phases, with the blended product system expected in the fourth quarter of 2014 and the diluent system expected in the first quarter of 2015. The estimated cost of the project is approximately $0.3 billion with expenditures to date of approximately $0.1 billion.

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Athabasca Pipeline Twinning

This project involves twinning the southern section of the Athabasca Pipeline from Kirby Lake, Alberta to the Hardisty, Alberta crude oil hub to provide additional capacity to serve expected oil sands growth in the Kirby Lake producing region. The expansion project, with an estimated cost of approximately $1.2 billion, and expenditures to date of approximately of $0.9 billion, will include 346 kilometres (215 miles) of 36-inch diameter pipeline adjacent to the existing Athabasca Pipeline right-of-way. The line is now expected to be delayed beyond its original in service date of 2015 due to a change in the construction schedule to align with shipper volume availability.

Edmonton to Hardisty Expansion

The Company is undertaking an expansion of the Canadian Mainline system between Edmonton, Alberta and Hardisty, Alberta. The expansion project will include 181 kilometres (112 miles) of new 36-inch diameter pipeline and will provide an initial capacity of approximately 570,000 bpd, expandable to 800,000 bpd. The new line is expected to generally follow the same route as Enbridge’s existing Line 4 pipeline. Also included in the project scope are connections into existing infrastructure at the Hardisty Terminal and new terminal facilities in Edmonton which include five new 500,000 barrel tanks. The new pipeline is expected to be placed into service in the first quarter of 2015, with additional tankage requirements expected to be completed by the end of 2015 at an expected total cost of approximately $1.8 billion. Expenditures incurred to date are approximately $0.5 billion.

Southern Access Extension

The Southern Access Extension project (Southern Access Extension) will involve the construction of a new 265-kilometre (165-mile) 24-inch diameter crude oil pipeline from Flanagan, Illinois to Patoka, Illinois, for an initial capacity of approximately 300,000 bpd, as well as additional tankage and two new pump stations. Effective July 1, 2014, the Company entered into an agreement with Lincoln Pipeline LLC (Lincoln), an affiliate of Marathon Petroleum Corporation (MPC), to, among other things, admit Lincoln as a partner and participate in Southern Access Extension. Lincoln has purchased a 35% equity interest in the project and will make additional cash contributions in accordance with the Southern Access Extension spend profile in proportion to its 35% interest. Subject to regulatory and other approvals, the project is expected to be placed into service in mid-2015. Southern Access Extension is expected to cost approximately US$0.9 billion with Enbridge’s share of the estimated capital cost expected to be approximately US$0.6 billion. Enbridge’s expenditures to date on the project is approximately US$0.1 billion.

AOC Hangingstone Lateral

The Company entered into an agreement with Athabasca Oil Corporation (AOC) to provide pipeline and terminalling services to the proposed AOC Hangingstone Oil Sands Project (AOC Hangingstone) in Alberta. Phase I of the project will involve the construction of a new 49-kilometre (31-mile) 16-inch diameter pipeline from the AOC Hangingstone project site to Enbridge’s existing Cheecham Terminal, and related facility modifications at Cheecham. Phase I of the project will provide an initial capacity of 16,000 bpd and is expected to be placed into service in the third quarter of 2015 at an estimated cost of approximately $0.1 billion. Phase 2 of the project, which is subject to commercial approval, would provide up to an additional 60,000 bpd for a total capacity of 76,000 bpd.

Sunday Creek Terminal Expansion

In January 2014, the Company announced it will construct additional facilities at its existing Sunday Creek Terminal, located in the Christina Lake area of northern Alberta, to support production growth from the Christina Lake oil sands project operated by Cenovus Energy Inc. and jointly owned with ConocoPhillips. The expansion includes development of a new site adjacent to the existing terminal, construction of a new 350,000 barrel tank with associated piping, pumps and measurement equipment, as well as civil construction work for a future tank. The estimated cost for the expansion is approximately $0.2 billion, with expenditures to date of approximately $0.1 billion and a targeted in-service date of the third quarter of 2015.

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Canadian Mainline System Terminal Flexibility and Connectivity

As part of the Light Oil Market Access Program initiative, the Company is undertaking the Canadian Mainline System Terminal Flexibility and Connectivity project in order to accommodate additional light oil volumes and enhance the operational flexibility of the Canadian mainline terminals. The modifications are comprised of upgrading existing booster pumps, additional booster pumps and new tank line connections. These projects have varying completion dates from 2013 through 2015. The cost of the project is expected to be approximately $0.7 billion following the completion of a detailed engineering review. The revised estimate reflects enhanced tankage, terminalling and connectivity in conjunction with the Company’s Canadian Mainline Expansion project. Refer to Growth Projects – Commercially Secured Projects – Liquids Pipelines – Canadian Mainline Expansion. Expenditures to date total approximately $0.2 billion.

Woodland Pipeline Extension

The joint venture Woodland Pipeline Extension Project will extend the Woodland Pipeline south from Enbridge’s Cheecham Terminal to its Edmonton Terminal. The extension is a proposed 388-kilometre (241-mile) 36-inch diameter pipeline with an initial capacity of 400,000 bpd, expandable to 800,000 bpd. Enbridge’s share of the estimated capital cost of the project is approximately $0.6 billion, with expenditures incurred to date of approximately $0.2 billion. Subject to finalization of scope and a definitive cost estimate, the project has a target in-service date of the third quarter of 2015.

JACOS Hangingstone Project

Enbridge will undertake the construction of facilities and provide transportation services to the Japan Canada Oil Sands Limited (JACOS) Hangingstone Oil Sands Project (JACOS Hangingstone). JACOS and Nexen Energy ULC, a wholly owned subsidiary of China National Offshore Oil Corporation Limited, are partners in the project which is operated by JACOS. Subject to regulatory approval, Enbridge plans to construct a new 53-kilometre (33-mile) 12-inch lateral pipeline to connect the JACOS Hangingstone project site to Enbridge’s existing Cheecham Terminal. The project will provide capacity of 40,000 bpd at an estimated cost of approximately $0.1 billion and is expected to enter service in 2016.

Wood Buffalo Extension

In 2013, Enbridge was selected by Suncor Energy Inc., Total E&P Canada Ltd. and Teck Resources Limited (the Fort Hills Partners), as well as the Suncor Energy Oil Sands Limited Partnership (Suncor Partnership), to develop a new pipeline to transport crude oil production to Enbridge’s mainline hub at Hardisty, Alberta. The proposed Wood Buffalo Extension will extend Enbridge’s existing Wood Buffalo Pipeline and includes construction of a new 450-kilometre (281-mile) 30-inch pipeline from Enbridge’s Cheecham Terminal to its Battle River Terminal at Hardisty, as well as associated terminal upgrades. The completed project will provide capacity of 490,000 bpd of diluted bitumen to be transported for the proposed Fort Hills Partners’ oil sands project (Fort Hills Project) in northeastern Alberta and Suncor Partnership’s oil sands production in the Athabasca region. Subject to regulatory approvals, the project is expected to be completed in 2017 at an estimated cost of approximately $1.6 billion.

Norlite Pipeline System

Enbridge is undertaking the development of Norlite Pipeline System (Norlite), a new industry diluent pipeline originating from Edmonton to meet the needs of multiple producers in the Athabasca oil sands region. The scope of the project was increased to a 24-inch diameter pipeline, which will provide an initial capacity of approximately 224,000 bpd of diluent, with the potential to be further expanded to approximately 400,000 bpd of capacity with the addition of pump stations. Norlite will be anchored by throughput commitments from both the Fort Hills Partners for production from the proposed Fort Hills Project and from Suncor Partnership’s proprietary oil sands production. Norlite will involve the construction of a new 449-kilometre (278-mile) pipeline from Enbridge’s Stonefell Terminal to its Cheecham Terminal with an extension to Suncor Partnership’s East Tank Farm, which is adjacent to Enbridge’s existing Athabasca Terminal. A potential 40-kilometre (25-mile) lateral pipeline to Enbridge’s Norealis Terminal is also being considered.

Under an agreement with Keyera Corp. (Keyera), Norlite has the right to access certain existing capacity on Keyera’s pipelines between Edmonton and Stonefell and, in exchange, Keyera has elected to participate in the new pipeline infrastructure project as a 30% non-operating owner. Subject to regulatory and other approvals as well as finalization of scope, Norlite is expected to be completed in 2017 at an estimated cost of approximately $1.4 billion.

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Canadian Line 3 Replacement Program

In March 2014, Enbridge and EEP jointly announced that shipper support was received for investment in the L3R Program. The Canadian portion of the Line 3 Replacement Program (Canadian L3R Program) will complement existing integrity programs by replacing approximately 1,084-kilometres (673-miles) of the remaining line segments of the existing Line 3 pipeline between Hardisty, Alberta and Gretna, Manitoba. While the L3R Program will not provide an increase in the overall capacity of the mainline system, it will support the safety and operational reliability of the system, enhance flexibility and allow the Company to optimize throughput. The L3R Program is expected to achieve an equivalent 34-inch diameter pipeline capacity of approximately 760,000 bpd.

Subject to regulatory and other approvals, the Canadian L3R Program is targeted to be completed in the second half of 2017. Following the completion of a definitive cost estimate in the second quarter of 2014, the estimated capital cost of the Canadian L3R Program is approximately $4.9 billion, with expenditures to date of approximately $0.1 billion. Costs of the Canadian L3R Program will be recovered through a 15-year toll surcharge mechanism under the Competitive Toll Settlement (CTS). For discussion on EEP’s portion of the Line 3 Replacement Program refer to Growth Projects – Commercially Secured Projects – Sponsored Investments – Enbridge Energy Partners, L.P. – United States Line 3 Replacement Program.

GAS DISTRIBUTION

Greater Toronto Area Project

EGD will undertake the expansion of its natural gas distribution system in the Greater Toronto Area (GTA) to meet the demands of growth and to continue the safe and reliable delivery of natural gas to current and future customers. At an expected cost of approximately $0.7 billion, the GTA project will involve the construction of two new segments of pipeline, a 27-kilometre (17-mile) 42-inch diameter pipeline and a 23-kilometre (14-mile) 36-inch diameter pipeline in Toronto, Ontario, as well as related facilities to upgrade the existing distribution system that delivers natural gas to several municipalities in Ontario. With the OEB approval received in January 2014, construction is targeted to start in late 2014 and completion of the project is expected by the end of 2015.

GAS PIPELINES, PROCESSING AND ENERGY SERVICES

Pipestone and Sexsmith Project

In 2012, the Company acquired from Encana Corporation (Encana) certain sour gas gathering and compression facilities located in the Peace River Arch (PRA) region of northwest Alberta (collectively, Pipestone and Sexsmith). These facilities were either in service (Sexsmith) or under construction (Pipestone) at the time of acquisition. Construction of new gathering lines and NGL handling facilities were completed in June 2014. Enbridge’s investment in Pipestone and Sexsmith is approximately $0.3 billion. Enbridge also retains an exclusive right to work with Encana on facility scoping for development of additional major midstream facilities in the liquids-rich PRA region.

Blackspring Ridge Wind Project

In 2013, Enbridge secured a 50% interest in the development of the 300-megawatt (MW) Blackspring Ridge Wind Project (Blackspring Ridge), located 50 kilometres (31 miles) north of Lethbridge, Alberta in Vulcan County. The project was constructed under a fixed price engineering, procurement and construction contract and commercial operations commenced in May 2014. Renewable Energy Credits generated from Blackspring Ridge are contracted to Pacific Gas and Electric Company under a 20-year purchase agreement. The electricity is being sold into the Alberta power pool with pricing fixed on 75% of production through long-term price swap arrangements. The Company’s total investment in the project is approximately $0.3 billion.

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Walker Ridge Gas Gathering System

The Company has agreements with Chevron USA Inc. (Chevron) and Union Oil Company of California to expand its central Gulf of Mexico offshore pipeline system. Under the terms of the agreements, Enbridge is constructing and will own and operate the Walker Ridge Gas Gathering System (WRGGS) to provide natural gas gathering services to the Jack St. Malo and Big Foot ultra-deep water 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 100 million cubic feet per day (mmcf/d). The Jack St. Malo portion of the WRGGS is expected to be placed into service in the fourth quarter of 2014 and the Big Foot Oil Pipeline (Big Foot Pipeline) portion is expected to be placed into service in mid-2015. The total WRGGS project is expected to cost approximately US$0.4 billion, with expenditures to date of approximately US$0.3 billion.

Big Foot Oil Pipeline

Under agreements with Chevron, Statoil Gulf of Mexico LLC and Marubeni Oil & Gas (USA) Inc., Enbridge is constructing a 64-kilometre (40-mile) 20-inch oil pipeline with capacity of 100,000 bpd from the Big Foot ultra-deep water development in the Gulf of Mexico. This crude oil pipeline project is complementary to Enbridge’s undertaking of the WRGGS construction, discussed above. Upon completion of the project, Enbridge will operate the Big Foot Pipeline, located approximately 274 kilometres (170 miles) south of the coast of Louisiana. The estimated capital cost of the project is approximately US$0.2 billion, with expenditures to date of approximately US$0.1 billion. The Big Foot Pipeline is expected to enter service mid-2015.

Keechi Wind Project

In January 2014, Enbridge announced it had entered into an agreement with Renewable Energy Systems Americas Inc. (RES Americas) to own and operate the 110-MW Keechi Wind Project (Keechi), located in Jack County, Texas, at an investment of approximately US$0.2 billion, with expenditures incurred to date of approximately US$0.1 billion. RES Americas is constructing the wind project under a fixed price, engineering, procurement and construction agreement, with expected completion in the first quarter of 2015. Keechi will deliver 100% of the electricity generated into the Electric Reliability Council of Texas, Inc. market under a 20-year power purchase agreement with Microsoft Corporation.

Heidelberg Lateral Pipeline

The Company will construct, own and operate a crude oil pipeline in the Gulf of Mexico to connect the proposed Heidelberg development, operated by Anadarko Petroleum Corporation, to an existing third-party system. The Heidelberg Lateral Pipeline (Heidelberg), a 58-kilometre (36-mile), 20-inch diameter pipeline with capacity of 100,000 bpd, will originate in Green Canyon Block 860, approximately 320 kilometres (200 miles) southwest of New Orleans, Louisiana, and in an estimated 1,600 metres (5,300 feet) of water. Heidelberg is expected to be operational by 2016 at an approximate cost of US$0.1 billion.

SPONSORED INVESTMENTS – ENBRIDGE ENERGY PARTNERS, L.P.

Line 6B 75-Mile Replacement Program

The Line 6B 75-Mile Replacement Program included the replacement of 120 kilometres (75 miles) of non-contiguous sections of Line 6B of EEP’s Lakehead System. The Line 6B pipeline runs from Griffith, Indiana through Michigan to the international border at the St. Clair River. The new segments were completed in components, with approximately 104 kilometres (65 miles) of segments placed in service in 2013. The two remaining 8-kilometre (5-mile) segments in Indiana were placed in service in March 2014. The total cost of the replacement program was approximately US$0.4 billion and EEP is recovering these costs through a tariff surcharge that is part of the system-wide rates for the Lakehead System.

Eastern Access

The Eastern Access initiative includes a series of Enbridge and EEP crude oil pipeline projects to provide increased access to refineries in the upper midwest United States and eastern Canada. Projects being undertaken by EEP include an expansion of its Line 5 and expansions of the United States mainline involving the Spearhead North Pipeline (Line 62) and further segments of Line 6B. For discussion on Enbridge’s portion of Eastern Access refer to Growth Projects – Commercially Secured Projects – Liquids Pipelines – Eastern Access.

In 2013, EEP completed and placed into service the expansion of its Line 5 light crude oil line between Superior, Wisconsin and the international border at the St. Clair River. The Line 5 expansion increased capacity by 50,000 bpd at an approximate cost of US$0.1 billion. Also in 2013, EEP completed and placed into service the expansion of Line 62 between Flanagan, Illinois and Griffith, Indiana, which increased capacity by 105,000 bpd.

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EEP is also replacing additional sections of Line 6B in Indiana and Michigan, including the addition of new pumps and terminal upgrades at Hartsdale, Griffith and Stockbridge, as well as tanks at Flanagan, Stockbridge and Hartsdale, to increase capacity from 240,000 bpd to 500,000 bpd. Portions of the existing 30-inch diameter pipeline are being replaced with 36-inch diameter pipe. The Line 6B project is split into two phases. The segment between Griffith and Stockbridge was completed in May 2014 and the segment from Ortonville, Michigan to the international border at the St. Clair River is now expected to be completed in the fourth quarter of 2014. The replacement of the Line 6B sections is in addition to the Line 6B 75-mile Replacement Program discussed previously. Following detailed engineering estimates completed in the first quarter of 2014 which reflect issues with local ground terrain conditions including tie-ins, the expected cost of the United States mainline expansions is approximately US$2.4 billion, and includes the US$0.1 billion cost of the previously discussed Line 5 expansion.

The Eastern Access initiative also includes a further upsizing of EEP’s Line 6B. The Line 6B capacity expansion from Griffith, Indiana to Stockbridge, Michigan will increase capacity from 500,000 bpd to 570,000 bpd and will include pump station modifications at Griffith, Niles and Mendon stations, additional modifications at the Griffith and Stockbridge terminals and breakout tankage at Stockbridge. Following the completion, in the first quarter of 2014, of a detailed engineering estimate and a scope revision that removed a proposed tank, the total cost of the projects is approximately US$0.3 billion. The projects are expected to be placed into service in 2016.

The total estimated cost of the projects being undertaken by EEP as part of the Eastern Access initiative including the United States mainline expansions, the Line 5 expansion and the Line 6B capacity expansion project, is approximately US$2.7 billion, with expenditures to date of approximately US$1.8 billion. The Eastern Access projects undertaken by EEP are being funded 75% by Enbridge and 25% by EEP. Within one year of the final in-service date of the collective projects, EEP will have the option to increase its economic interest held at that time by up to an additional 15%.

Lakehead System Mainline Expansion

The Lakehead System Mainline Expansion includes several projects to expand capacity of the Lakehead System mainline between its origin at the Canada/United States border, near Neche, North Dakota, to Flanagan, Illinois. These projects are in addition to expansions of the Lakehead System mainline being undertaken as part of the Eastern Access initiative and includes the expansion of Alberta Clipper (Line 67) and Southern Access (Line 61).

The current scope of the Alberta Clipper expansion between the border and Superior, Wisconsin consists of two phases. The initial phase will increase capacity from 450,000 bpd to 570,000 bpd at an estimated capital cost of approximately US$0.2 billion. The second phase of the expansion will increase capacity from 570,000 bpd to 800,000 bpd, at an estimated capital cost of approximately US$0.2 billion. Both phases of the Alberta Clipper expansion require only the addition of pumping horsepower and no pipeline construction. Subject to regulatory and other approvals, including an amendment to the current Presidential border crossing permit to allow for operation of Line 67 at its currently planned operating capacity of 800,000 bpd, the initial phase is expected to be substantially complete in September 2014 and the second phase is expected to be in-service in 2015. It is now anticipated that obtaining regulatory approval will take longer than originally planned though approval is expected in mid-2015. A number of temporary system optimization actions are being undertaken to substantially mitigate any impact on throughput associated with the initial 120,000 bpd capacity increase.

The current scope of the Southern Access expansion between Superior, Wisconsin and Flanagan, Illinois also consists of two phases. The initial phase includes an increase in capacity from 400,000 bpd to 560,000 bpd at an estimated capital cost of approximately US$0.2 billion. EEP also plans to undertake a further expansion of the Southern Access line between Superior and Flanagan to increase capacity from 560,000 bpd to 1,200,000 bpd. Following completion of a more detailed engineering estimate in the first quarter of 2014, the second phase of the Southern Access expansion is expected to cost approximately US$1.2 billion. Both phases of the expansion would require only the addition of pumping horsepower and crude oil tanks at existing sites, with no pipeline construction. The target in-service date for the first phase of the expansion is the third quarter 2014. For the second phase of the expansion, which remains subject to regulatory and other approvals, the pump station expansion is expected to be available for service in 2015, with additional tankage requirements expected to be completed in 2016.

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As part of the Light Oil Market Access Program, EEP also plans to expand the capacity of the Lakehead System between Flanagan, Illinois and Griffith, Indiana. This section of the Lakehead System will be expanded by constructing a 127-kilometre (79-mile), 36-inch diameter twin of the existing Spearhead North Pipeline (Line 62). The project is expected to be completed at an estimated cost of approximately US$0.5 billion. Subject to regulatory and other approvals, the new line will have an initial capacity of 570,000 bpd and is expected to be placed into service in late 2015.

The projects collectively referred to as the Lakehead System Mainline Expansion are expected to cost approximately US$2.3 billion, with expenditures incurred to date of approximately US$0.5 billion. EEP will operate the project on a cost-of-service basis. The Lakehead System Mainline Expansion is funded 75% by Enbridge and 25% by EEP. Within one year of the final in-service date of the collective projects, EEP will have the option to increase its economic interest held at that time by up to an additional 15%.

Beckville Cryogenic Processing Facility

EEP and its partially owned subsidiary MEP are constructing a cryogenic natural gas processing plant near Beckville (the Beckville Plant) in Panola County, Texas. The Beckville Plant will offer incremental processing capacity for existing and future customers in the 10-county Cotton Valley shale region, where the East Texas system is located. The Beckville Plant has a planned natural gas processing capability of 150 mmcf/d and is also expected to produce 8,500 bpd of NGL. The Beckville Plant is expected to be placed into service in the first quarter of 2015 at an estimated cost of approximately US$0.1 billion.

Sandpiper Project

As part of the Light Oil Market Access Program initiative, EEP plans to undertake the Sandpiper project (Sandpiper) which will expand and extend EEP’s North Dakota feeder system. The Bakken takeaway capacity of the North Dakota System will be expanded by 225,000 bpd to a total of 580,000 bpd. The proposed expansion will involve construction of a 965-kilometre (600-mile) line from Beaver Lodge Station near Tioga, North Dakota to the Superior, Wisconsin mainline system terminal. The new line will twin the existing 210,000 bpd North Dakota System mainline, which now terminates at Clearbrook Terminal in Minnesota by adding 250,000 bpd of capacity between Tioga and Berthold, North Dakota and 225,000 bpd of capacity between Berthold and Clearbrook, both with new 24-inch diameter pipelines, as well as adding 375,000 bpd of capacity between Clearbrook and Superior with a new 30-inch diameter pipeline. Sandpiper is expected to cost approximately US$2.6 billion, with expenditures incurred to date of approximately US$0.2 billion.

MPC has been secured as an anchor shipper for Sandpiper. As part of the arrangement, EEP, through its subsidiary, North Dakota Pipeline Company LLC (NDPC) (formerly known as Enbridge Pipelines (North Dakota) LLC), and Williston Basin Pipeline LLC (Williston), an affiliate of MPC, entered into an agreement to, among other things, admit Williston as a member of NDPC. Williston will fund 37.5% of Sandpiper construction and will have the option to participate in other growth projects within NDPC, unless specifically excluded by the agreement; this investment is not to exceed US$1.2 billion in aggregate. In return for funding part of Sandpiper’s construction, Williston will obtain an approximate 27% equity interest in NDPC at the in-service date of Sandpiper, targeted for early 2016.

A petition was filed with the FERC to approve recovery of Sandpiper’s costs through a surcharge to the NDPC rates between Beaver Lodge and Clearbrook and a cost of service structure for rates between Clearbrook and Superior. In March 2013, the FERC denied the petition on procedural grounds. In late 2013, EEP held an open season to solicit commitments from shippers for capacity created by Sandpiper. The open season closed in late January 2014 with the receipt of a further capacity commitment which can be accommodated within the planned incremental capacity identified above. EEP re-filed its petition with the FERC on February 12, 2014 and received a FERC declaratory order in May 2014 approving the tariffs structure for the project. The pipeline is expected to begin service in early 2016, subject to obtaining regulatory and other approvals.

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United States Line 3 Replacement Program

In March 2014, Enbridge and EEP jointly announced that shipper support was received for investment in the L3R Program. EEP will undertake the United States portion of the Line 3 Replacement Program (U.S. L3R Program) which will complement existing integrity programs by replacing approximately 576-kilometres (358-miles) of the remaining line segments of the existing Line 3 pipeline between Neche, North Dakota and Superior. While the L3R Program will not provide an increase in the overall capacity of the mainline system, it will support the safety and operational reliability of the system, enhance flexibility and allow the Company to optimize throughput. The L3R Program is expected to achieve an equivalent 34-inch diameter pipeline capacity of approximately 760,000 bpd.

Subject to regulatory and other approvals, the U.S. L3R Program is targeted to be completed in the second half of 2017 at an estimated capital cost of approximately US$2.6 billion. The U.S. L3R Program will be jointly funded by Enbridge and EEP at participation levels that are subject to finalization. EEP will recover the costs based on its existing Facilities Surcharge Mechanism with the initial term of the agreement being 15 years. For the purpose of the toll surcharge, the agreement specifies a 30-year recovery of the capital based on a cost of service methodology.

GROWTH PROJECTS – OTHER PROJECTS UNDER DEVELOPMENT

The following projects have been announced by the Company, but have not yet met Enbridge’s criteria to be classified as commercially secured. The Company also has significant additional attractive projects under development which have not yet progressed to the point of public announcement. In its long-term funding plans, the Company makes full provision for all commercially secured projects and makes provision for projects under development based on an assessment of the aggregate securement success anticipated. Actual securement success achieved could exceed or fall short of the anticipated level.

LIQUIDS PIPELINES

Northern Gateway Project

Northern Gateway Project (Northern Gateway) 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 transport imported condensate from Kitimat to the Edmonton area and is proposed to be a 20-inch diameter line with an initial capacity of 193,000 bpd.

On December 19, 2013, the Joint Review Panel (JRP) issued its report on Northern Gateway. The report found that the petroleum industry is a significant driver of the Canadian economy and an important contributor to the Canadian standard of living. The JRP found that the potential economic effects of Northern Gateway on local, regional and national economies would be positive and would likely be significant. The JRP is also of the view that the Company’s commitments break new ground by providing an unprecedented level of long-term economic, environmental and social benefits to Aboriginal groups. It noted that the benefits of Northern Gateway outweigh its burdens and that “Canadians would be better off with the Enbridge Northern Gateway Project than without it.”

The JRP found that Northern Gateway provided appropriate and effective opportunities for the public and potentially-affected parties to learn about the project and to provide their views and concerns to the Company. The JRP was satisfied that Northern Gateway considered, and was responsive to, the input it received regarding the design, construction and operation of the project.

The JRP found Northern Gateway applied a careful and precautionary approach to its environmental assessment and that Northern Gateway had presented a level of engineering design information that met, or exceeded, regulatory requirements for a thorough and comprehensive review in terms of whether or not it can construct and operate the project in a safe and responsible manner that protects people and the environment. The JRP found that Northern Gateway followed good engineering practice in determining a route that avoids or minimizes exposure to geohazards, had taken all reasonable steps to design a project that would minimize risks of project malfunctions and accidents due to naturally occurring events and that mandatory and voluntary measures outlined by the Company would reduce the potential for human error to the greatest extent possible.

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The JRP also referenced the conclusions of the TERMPOL committee and the evidence of various expert witnesses appearing on behalf of Northern Gateway and the Government of Canada in its assessment of the safety of marine transport and concluded that shipping along the north coast of British Columbia could be accomplished safely the vast majority of the time even in the absence of many of the mitigation measures that would be in place for Northern Gateway. These additional mitigation measures would include reduced vessel speeds, escort tugs, redundant navigational systems and avoiding congestion in the narrower parts of the shipping channels. The JRP noted Northern Gateway’s commitments represent a substantial increase in spill response capabilities beyond those required by existing legislation and currently existing on the west coast of British Columbia, that they are based on international best practice and continual advances in technology and spill response planning. The JRP included an appendix with 209 conditions that the JRP recommended be included in any certificate that was issued.

The JRP recommended to the Governor in Council that Certificates of Public Convenience and Necessity for the oil and condensate pipelines, incorporating the terms and conditions in their report, be issued to Northern Gateway pursuant to Part III of the NEB Act. The Government of Canada has consulted with Aboriginal groups on the JRP report and its recommendations prior to making its decision on whether to direct the NEB to issue the certificates for the pipelines. Of the 45 Aboriginal groups eligible to participate as equity owners, 26 have signed up to do so.

On June 17, 2014, the Northern Gateway received Governor in Council approval, subject to the 209 conditions recommended by the JRP. The NEB issued the Certificates of Public Convenience and Necessity on June 18, 2014.

The cost estimate included in the Northern Gateway filing with the JRP reflects a preliminary estimate prepared in 2004 and escalated to 2010. A detailed estimate based on full engineering analysis of the pipeline route and terminal location is currently being prepared. The detailed estimate will reflect a larger proportion of high cost terrain, longer tunnelling requirements and more extensive terminal site rock excavation than provided for in the preliminary estimate, which is expected to result in a significant increase in the cost estimate.

Five applications for judicial review were filed with the Federal Court and the Federal Court of Appeal; three from Aboriginal groups and two from environmental groups following the release of the JRP report in December. Those applications have now been withdrawn and the same parties along with a number of additional Aboriginal groups and UNIFOR have filed applications to challenge the Governor in Council decision and the subsequent issuance of the Certificates. On July 3, 2014, the Federal Court of Appeal issued a Procedural Direction for Applications for Leave to Appeal the decision of the NEB.

Subject to continued commercial support, regulatory and other approvals and adequately addressing landowner and local community concerns (including those of Aboriginal communities), the Company currently estimates that Northern Gateway could be in service in 2018 at the earliest. The timing and outcome of judicial reviews could also impact the start of construction or other project activities, which may lead to a delay in the start of operations beyond the current forecast.

Expenditures to date, which relate primarily to the regulatory process, are approximately $0.5 billion, of which approximately half is being funded by potential shippers on Northern Gateway. Given the many uncertainties surrounding Northern Gateway, including final ownership structure, the potential financial impact of the project cannot be determined at this time.

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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 Northern Gateway also maintains a website at www.northerngateway.ca where the full regulatory application submitted to the NEB, the 2010 Enbridge Northern Gateway Community Social Responsibility Report and the December 19, 2013 Report of the JRP on the Northern Gateway Application are available. None of the information contained on, or connected to, the JRP website or the Northern Gateway website is incorporated in or otherwise part of this MD&A.

GAS PIPELINES, PROCESSING AND ENERGY SERVICES

NEXUS Gas Transmission Project

In 2012, Enbridge, DTE Energy Company (DTE) and Spectra Energy Corp. (Spectra) announced the execution of a Memorandum of Understanding ( MOU) to jointly develop the NEXUS Gas Transmission System, a project that would move growing supplies of Ohio Utica shale gas to markets in the United States midwest, including Ohio and Michigan, and Ontario, Canada. The MOU has expired and Enbridge is in discussions with Spectra and DTE regarding the terms of its continued participation in the project.

FINANCIAL RESULTS

LIQUIDS PIPELINES

Canadian Mainline

Canadian Mainline adjusted earnings for the three and six months ended June 30, 2014 increased compared with the second quarter and the first half of 2013. Higher adjusted earnings were primarily driven by higher throughput supported by several factors: increased oil sands production; volumes diverted from competing systems; strong refinery demand in the midwest market partly due to a start-up of a midwest refinery’s conversion to heavy oil processing in the second quarter of 2014; and successful efforts by the Company to optimize capacity and throughput and to enhance scheduling efficiency with shippers. Higher terminalling revenues as well as lower operating and administrative costs were also positive factors relative to the comparative periods.

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On a year-to-date basis, partially offsetting these positive impacts was a lower Canadian Mainline International Joint Tariff (IJT) Residual Benchmark Toll in the first quarter of 2014 compared with the equivalent 2013 period. Changes in the Canadian Mainline IJT Residual Benchmark Toll are inversely related to the Lakehead System Toll, which was higher in the first quarter of 2014 due to the recovery of incremental costs associated with EEP’s growth projects. Tolls were not a significant driver of the second quarter variance as the Canadian Mainline IJT Residual Benchmark Toll was US$1.81 per barrel for both the second quarter of 2014 and 2013. Higher power costs associated with incremental throughput as well as higher depreciation from an increased asset base also impacted adjusted earnings for the first half of 2014. Finally, Canadian Mainline adjusted earnings for the first half of 2014 continued to be impacted by the absence of revenues from Line 9B, which was idled in late 2013 and is being reversed and expanded as part of the Company’s Eastern Access initiative. Line 9B is expected to resume service in the fourth quarter of 2014. For further information on Line 9B refer to Growth Projects – Commercially Secured Projects – Liquids Pipelines – Eastern Access.

EEP delayed its annual April 1 tariff filing for its Lakehead System as it was in negotiations with the Canadian Association of Petroleum Producers (CAPP) concerning certain components of the tariff rate structure. The toll application was filed with the FERC on June 27, 2014, and effective August 1, 2014, the Lakehead System Toll will increase to US$2.49 per barrel. The IJT Benchmark Toll, which is adjusted annually on July 1, increased from US$3.98 per barrel to US$4.02 per barrel effective July 1, 2014. The Canadian Mainline IJT Residual Benchmark Toll, which represents the difference between the IJT Benchmark Toll and the Lakehead System Local Toll, will increase to US$1.85 per barrel effective July 1, 2014 and will subsequently decrease to US$1.53 per barrel effective August 1, 2014 when the revised Lakehead System Toll becomes effective.

Supplemental information on Canadian Mainline adjusted earnings for the three and six months ended June 30, 2014 and 2013 is provided below:

1                  Inclusive of realized gains and losses on foreign exchange derivative financial instruments.

2                  The IJT Benchmark Toll is per barrel of heavy crude oil transported from Hardisty, Alberta to Chicago, Illinois. A separate distance adjusted toll applies to shipments originating at receipt points other than Hardisty and lighter hydrocarbon liquids pay a lower toll than heavy crude oil. Effective July 1, 2013, the IJT Benchmark Toll increased from US$3.94 to US$3.98.

3                 The Lakehead System Local Toll is per barrel of heavy crude oil transported from Neche, North Dakota to Chicago, Illinois. Effective July 1, 2013, this toll increased from US$2.13 to US$2.18. Effective January 1, 2014, this toll decreased to US$2.17.

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4                  The Canadian Mainline IJT Residual Benchmark Toll is per barrel of heavy crude oil transported from Hardisty, Alberta to Gretna, Manitoba. For any shipment, this toll is the difference between the IJT Benchmark Toll for that shipment and the Lakehead System Local Toll for that shipment. This toll decreased from US$1.81 to US$1.80 effective July 1, 2013. Effective January 1, 2014, this toll increased to US$1.81.

1                  Throughput volume, presented in kbpd, represents mainline deliveries ex-Gretna, Manitoba which is made up of United States and eastern Canada deliveries originating from western Canada.

Regional Oil Sands System

Regional Oil Sands System adjusted earnings increased for the three and six months ended June 30, 2014 compared with the corresponding 2013 periods. Adjusted earnings growth was primarily driven by contributions from the Norealis Pipeline which was completed in April 2014, as well as higher throughput on the Athabasca mainline. Partially offsetting the increase in adjusted earnings were higher depreciation expense from a larger asset base and higher operating and administrative, interest and tax expenses from increased operational activities.

Southern Lights Pipeline

Southern Lights Pipeline earnings for the three and six months ended June 30, 2014 increased compared with the comparative 2013 periods and reflected higher recoveries of depreciation expense under the cost of service model.

Seaway Pipeline

Seaway Pipeline earnings for the first half of 2014 decreased compared with the comparative 2013 period. Higher financing and administrative costs as well as higher power costs were partially offset by higher throughput and a more favourable crude mix transported on Seaway Pipeline.

Feeder Pipelines and Other

Feeder Pipelines and Other adjusted earnings for the six month period ended June 30, 2014 were higher compared with the same period of 2013 due to lower business development costs not eligible for capitalization during the first quarter of 2014.

Liquids Pipelines earnings/(loss) were impacted by the following adjusting items:

·                  Canadian Mainline earnings/(loss) for each period reflected changes in unrealized fair value gains and losses on derivative financial instruments used to risk manage exposures inherent within the CTS, namely foreign exchange, power cost variability and allowance oil commodity prices.

·                  Canadian Mainline earnings for 2014 included depreciation and interest expense charged to Line 9B while it was idled and undergoing a reversal as part of the Company’s Eastern Access initiative.

·                  Regional Oil Sands System earnings for the second quarter of 2014 included a make-up rights adjustment.