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  November 7, 2012

Commission file number 001-15254

ENBRIDGE INC.

(Exact name of Registrant as specified in its charter)

3000, 425 – 1st Street S.W.

Calgary, Alberta, Canada  T2P 3L8

(Address of principal executive offices and postal code)

(403) 231-3900

(Registrants telephone number, including area code)

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

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

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

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

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

N/A

THIS REPORT ON FORM 6-K SHALL BE DEEMED TO BE INCORPORATED BY REFERENCE IN THE REGISTRATION STATEMENTS ON FORM S-8 (FILE NO. 333-145236, 333-127265, 333-13456, 333-97305 AND 333-6436), FORM F-3 (FILE NO. 33-77022) AND FORM F-10 (FILE NO. 333-170200 and 333-181333) OF ENBRIDGE INC. AND TO BE PART THEREOF FROM THE DATE ON WHICH THIS REPORT IS FURNISHED, TO THE EXTENT NOT SUPERSEDED BY DOCUMENTS OR REPORTS SUBSEQUENTLY FILED OR FURNISHED.

The following documents are being submitted herewith:

·                 Press Release dated November 7, 2012

·                 Interim Report to Shareholders for the nine months ended September 30, 2012.

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 third quarter adjusted earnings of $269 million or

$0.34 per common share

HIGHLIGHTS

(all financial figures are unaudited and presented in Canadian dollars)

·                  Third quarter earnings were $189 million; nine month earnings were $464 million including unrealized non-cash mark-to-market losses

·                  Third quarter and nine months adjusted earnings increased 13% to $269 million and 11% to $922 million, respectively

·                  Al Monaco became President and Chief Executive Officer on October 1, 2012

·                  Alberta Energy Resources Conservation Board approved $1.0 billion to $1.4 billion Woodland Pipeline Extension Project

·                  Enbridge signed agreement with Suncor Energy Inc. for $0.2 billion expansion of Athabasca terminal facilities

·                  Enbridge approved a $0.6 billion investment in Greater Toronto Area natural gas distribution infrastructure expansion

·                  Enbridge entered into a midstream services relationship with Encana Corporation to develop gas gathering and compression facilities in the Peace River Arch region; deferred commissioning of Phase 1 and construction of Phase 2 of Cabin Gas Plant development

·                  Enbridge continued the execution of its financing plan with the issuance of preference shares totaling gross proceeds of $850 million

·                  Enbridge continued the execution of its sponsored vehicle drop down strategy with an agreement to transfer $1.2 billion of assets to Enbridge Income Fund

·     Enbridge selected to provide lateral pipeline for Heidelberg Gulf of Mexico offshore oil development

CALGARY, ALBERTA, November 7, 2012 – Enbridge Inc. (TSX:ENB) (NYSE:ENB) – “As we approach the end of 2012 with nine-month adjusted earnings of $922 million, or $1.20 per share, and a strong fourth quarter expected, we remain on track to achieve full year adjusted earnings per share well within our guidance range of $1.58 to $1.74,” said Al Monaco, President and Chief Executive Officer (CEO). “With $18 billion in corporate-wide commercially secured growth projects today, we expect strong average annual earnings per share growth of 10% to 2016. Further, an additional $12 billion of highly probable, unsecured projects would accelerate earnings per share growth to 12%-plus over the next five years, with continued momentum into the latter part of the decade.”

“North America is undergoing a transformation in crude oil and natural gas production, which is driving the need for significant new energy infrastructure. Enbridge is in the middle of that transformation and we’re uniquely positioned to benefit from new and emerging opportunities in energy infrastructure development. Our plate is very full and we expect this activity will continue to drive industry-leading growth. This exceptional array of attractive investments, coupled with our access to low-cost capital, supports our positive five-year growth outlook. Beyond that, we are gaining confidence that we will be able to sustain that growth through to the end of the decade given embedded growth in returns on secured investment opportunities, and the expected contribution from our new growth platforms, such as Canadian Midstream and electric power.”

2012 results reflected unrealized non-cash mark-to-market accounting impacts related to the comprehensive long-term economic hedging program Enbridge Inc. (Enbridge or the Company) has put in place to mitigate exposures to interest rate variability and foreign exchange, as well as commodity prices. These kinds of short-term non-cash impacts to reported earnings result from Enbridge’s hedging program, which the Company believes over the long-term will support reliable cash flows and dividend growth.

Forward-Looking Information

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

Mr. Monaco became President and CEO October 1, 2012, succeeding Patrick D. Daniel on his retirement. Mr. Monaco and the Enbridge leadership team presented the Company’s strategic plan and growth outlook to the investment community in early October, outlining the three priorities that underpin that plan.

“Our first priority is to focus on the safety, reliability and environmental sustainability of our systems. We are committed to achieving industry leadership in all of these areas,” said Mr. Monaco. “Second is to execute our slate of growth projects on time and on budget, adding value for our customers and delivering significant earnings and dividends growth for our shareholders. Key to achieving this priority will be to maintain our strong financial position. With confidence in our growth rate for the medium term, our third priority is to extend the growth rate beyond 2016 through our existing and new business platforms.”

Over the third quarter of 2012, Enbridge continued to add to its slate of growth opportunities. In Liquids Pipelines, Enbridge received regulatory approval to construct the Woodland Pipeline Extension project, a 36-inch diameter 385-kilometre (228-mile) line that will effectively twin Enbridge’s existing Waupisoo Pipeline. The Woodland Pipeline Extension project is estimated to require, subject to approval of final commercial arrangements, an investment of approximately $1.0 billion to $1.4 billion for an initial capacity of 400,000 barrels per day (bpd), expandable to 800,000 bpd. Enbridge also announced an agreement for a $0.2 billion expansion of the existing infrastructure at its Athabasca Terminal to accommodate the incremental bitumen volumes from Suncor Energy Inc.’s (Suncor) Firebag 3 and 4 developments.

“The scale and scope of our existing regional infrastructure enables us to offer oil sands and Bakken producers cost-effective and timely regional transportation and terminaling solutions,” said Mr. Monaco. “We also continue to work closely with our customers to meet their needs for access to new downstream markets, notably through our Gulf Coast Access and Eastern Access programs, and to enhance market connectivity which will help address significant North American price discounting.

In September, the Joint Review Panel (JRP) hearings on the Northern Gateway Pipeline project entered the formal questioning phase allowing for registered intervenors and Northern Gateway panel experts to be cross-examined on the project, under oath and in public, to fully investigate issues related to the project.

“The regulatory process is intended to consider all points of view and address concerns,” said Mr. Monaco. “All of Northern Gateway’s plans and assertions – whether environmental, social or economic – are being fully tested. We remain confident the JRP will conclude that Northern Gateway is in Canada’s national interest.”

Enbridge announced in October that it has entered into a midstream services relationship with Encana Corporation (Encana) to develop gas gathering and compression facilities in the Peace River Arch (PRA) region in northwest Alberta. Enbridge also announced it has agreed with the other partners of the Cabin Gas Plant (Cabin) development to defer the commissioning of Cabin Phase 1 and construction of Cabin Phase 2. Starting in December 2012, Enbridge expects to begin receiving fees for its investment made to date in Cabin, including costs expended on Phase 2 of the plant facilities.

“We expect our investment in Cabin and PRA will exceed the previous level of capital committed to Cabin Phases 1 and 2,” said Mr. Monaco. “The investment has the same attractive commercial underpinning as our original Cabin investment.”

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On November 6, 2012, Enbridge announced it has been selected by Anadarko Petroleum Corporation (Anadarko) to build, own and operate a crude oil pipeline in the Gulf of Mexico to connect the proposed Heidelburg development, operated by Anadarko, to an existing third party pipeline system. Construction of the pipeline, which is expected to be operational by 2016, is subject to finalization of definitive agreements and sanction of the development by Anadarko and its project co-owners.

“Enbridge has a significant presence in the United States Gulf, transporting approximately 40% of deepwater natural gas production. The Heidelburg lateral pipeline will be our second crude oil pipeline in the Gulf contributing to the diversification of our offshore business,” said Mr. Monaco.

In Gas Distribution, Enbridge announced investment of up to $0.6 billion to expand Enbridge Gas Distribution’s (EGD) natural gas distribution system in the Greater Toronto Area (GTA) to accommodate growth in the GTA, and continue the safe and reliable delivery of natural gas to current and future customers.

“Our proposed GTA project reflects the changing gas-supply landscape and represents the most significant upgrade to our distribution system in 20 years. The project will enable us to serve current and anticipated growth in our customers’ needs, enhance our flexibility to avoid customer impacts due to disruption of physical supply, and provide options to access additional supply sources for our customers,” said Mr. Monaco.

Over the third quarter, Enbridge continued to build liquidity in support of its five-year funding plan, issuing $850 million in Preference Shares and a $100 million Century Bond with a term to maturity of 100 years through its subsidiary, Enbridge Pipelines Inc., the second Century Bond ever issued by a Canadian corporation.

“We are the largest issuer of rate reset preference shares with $2.3 billion issued this year and $3.3 billion issued since July 2011. With a 4% yield, this is a very low cost and attractive source of capital for us,” said Mr. Monaco.

Enbridge also advanced its sponsored vehicle strategy announcing on October 25, 2012 an agreement with Enbridge Income Fund (the Fund) to transfer a group of crude oil storage, wind power and solar power assets valued at $1.2 billion to the Fund. The transfer is subject to approval by the public shareholders of Enbridge Income Fund Holdings Inc. (ENF) at a meeting to be held December 7, 2012, and to the closing of a $222 million public offering of subscription receipts by ENF.

“The Enbridge sponsored investments provide us with a supplementary source of debt and equity funding,” said Mr. Monaco. “With this transfer, Enbridge will receive initial net cash proceeds from the transaction of $222 million and a further $582 million when the Fund raises additional public term debt to refinance a bridge loan provided by Enbridge in connection with this transaction.”

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THIRD QUARTER 2012 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 of $189 million for the third quarter of 2012 have increased compared with the third quarter of 2011. This increase primarily reflected a significant reduction in the net unrealized fair value losses on financial derivatives recognized in the third quarter of 2012 compared with 2011. The most significant reductions were on derivatives related to foreign exchange risk management positions, partially offset by increased unrealized losses associated with the revaluation of financial derivatives used to risk manage the profitability of transportation and storage transactions. Continued favourable performance resulting from increased volumes for a number of the Liquids Pipelines assets also contributed to the increase in earnings.

·                  Enbridge’s third quarter adjusted earnings increased 13% to $269 million primarily as a result of increased contributions from Canadian Mainline and Spearhead Pipeline, which benefited from strong volumes, as well as contribution from the Company’s 50% interest in the Seaway Pipeline since the completion of the reversal in May 2012, partially offset by decreased earnings from Enbridge Gas New Brunswick and increased net Corporate segment costs.

·                  On November 6, 2012, Enbridge announced it will build, own and operate a crude oil pipeline in the Gulf of Mexico to connect the proposed Heidelberg development, operated by Anadarko, to an existing third-party system. The Heidelberg lateral, which will be 20 inches in diameter and approximately 55 kilometres (34 miles) in length, will originate in Green Canyon Block 860, approximately 320 kilometres (200 miles) southwest of New Orleans and in an estimated 1,600 metres (5,300 feet) of water. Subject to finalization of definitive agreements and sanction of the development by Anadarko and its project co-owners, the lateral pipeline is expected to be operational by 2016.

·                  On October 25, 2012, ENF and the Fund announced they had entered into an agreement with Enbridge pursuant to which Enbridge would transfer five entities, which comprise crude oil storage in Alberta and renewable energy assets in Ontario, to the Fund. The agreement contemplates that Hardisty Contract Terminal, Hardisty Storage Caverns, Greenwich Wind Project, and Amherstburg and Tilbury solar projects would be transferred for an aggregate price of approximately $1.2 billion, to be paid in part by the issuance of additional ordinary trust units of the Fund to ENF and additional Enbridge Commercial Trust preferred units to Enbridge. Under the agreement, Enbridge has agreed to provide bridge debt financing to the Fund for the balance of the price. The transaction is subject to all necessary approvals, including approval by the minority shareholders of ENF, as well as regulatory approval. If approved, and upon repayment of the bridge financing, the transaction is expected to provide Enbridge $0.8 billion of net funding for its large growth capital investment program.

·                  On October 22, 2012, the Company agreed, subject to finalization of definitive agreements, to acquire from Encana certain sour gas gathering and compression facilities. These facilities, which are either currently in service or under construction, are located in the PRA region of northwest Alberta. Closing of the transaction is scheduled for December 2012. Following the completion of construction in 2013, Enbridge’s investment in the PRA Gas Development is expected to be approximately $0.3 billion. Enbridge is also working exclusively with Encana on facility scoping for development of additional major midstream facilities in the liquids-rich PRA region, which is expected to grow significantly in the years to come. Financial terms of the PRA Gas Development are expected to parallel previously established terms of the Cabin development. Enbridge has also agreed with its Cabin partners to defer commissioning of Phase 1 of the plant and construction of Phase 2.

·                  On September 27, 2012, Enbridge announced that it had received approval from the Alberta Energy Resources Conservation Board to construct the Woodland Pipeline Extension Project. The project will involve construction of a 36-inch diameter line approximately 385 kilometres (228 miles) from Enbridge’s Cheecham regional oil sands terminal to its mainline hub terminal at Edmonton, effectively twinning Enbridge’s existing Waupisoo Pipeline. The project is estimated to require a total investment of approximately $1.0 billion to $1.4 billion for an initial capacity of 400,000 bpd, expandable to 800,000 bpd. The estimated investment remains subject to finalization of scope and a definitive cost estimate. The new line is expected to accommodate anticipated growth in production from the Kearl oil sands project, and is required for expected needs from other projects presently connected to or expected to be connected to Enbridge’s regional oil sands system. Enbridge has not yet received final commercial approval from shippers to initiate field construction, but anticipates it will do so in time to achieve a

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2015 in-service date. Pre-construction development costs are being backstopped by shippers pending final commercial approval.

·                  Also on September 27, 2012, Enbridge announced that it entered into an agreement with Suncor to expand the existing infrastructure at the Enbridge Athabasca Terminal to accommodate the incremental bitumen volumes from Suncor’s Firebag 3 and 4 developments. The approximately $0.2 billion expansion is expected to be in-service in the second quarter 2013. Enbridge will construct a new 350,000 barrel tank as well as additional infrastructure including new booster pumps, meters and modifications to existing piping and manifolds. Suncor has agreed to underpin Enbridge’s investment in these facilities through a long-term Services Agreement, under which Enbridge recovers all operating costs, a return on equity and all of its invested capital.

·                  On September 6, 2012, Enbridge announced plans to expand EGD’s natural gas distribution system in the GTA to meet demands of growth in the GTA and continue the safe and reliable delivery of natural gas to current and future customers. At an expected cost of up to $0.6 billion, the proposed GTA project will consist of two segments of pipeline and related facilities to upgrade the existing distribution system that delivers natural gas to several municipalities in Ontario. Subject to Ontario Energy Board approval, construction is targeted to start in 2014, with an expected completion date of early 2016.

·                  On July 27, 2012, a release of crude oil was detected on Line 14 of Enbridge Energy Partners, L.P.’s (EEP) Lakehead System near Grand Marsh, Wisconsin. The estimated volume of oil released was approximately 1,200 barrels. EEP received a Corrective Action Order (CAO) from the Pipeline and Hazardous Materials Safety Administration (PHMSA) on July 30, 2012, followed by an amended CAO on August 1, 2012. The CAOs required EEP to take certain corrective actions, some of which have already been completed and some are still ongoing, as part of an overall plan for its Lakehead System. A notable part of the CAOs was to hire an independent third party pipeline expert to review and assess EEP’s overall integrity program. An independent third party expert was contracted during the third quarter of 2012 and their work is currently ongoing. Upon restart of Line 14 on August 7, 2012, PHMSA restricted the operating pressure to 80% of the pressure in place at the time immediately prior to the incident. The pressure restrictions will remain in place until such time EEP can demonstrate that the root cause of the incident has been remediated.

EEP has updated the disclosed estimate for repair and remediation related costs associated with this crude oil release to approximately US$12 million ($2 million after-tax attributable to Enbridge), inclusive of approximately US$2 million of lost revenue, and excluding any fines and penalties. Despite the efforts EEP has made to ensure the reasonableness of its estimate, changes to the estimated amounts associated with this release are possible as more reliable information becomes available. EEP will be pursuing claims under Enbridge’s comprehensive insurance policy, although it does not expect any recoveries to be significant.

·                  On July 2, 2012, EEP received a Notice of Probable Violation from the PHMSA related to the July 26, 2010 Line 6B crude oil release, which resulted in payment of a US$3.7 million civil penalty in the third quarter of 2012. EEP included the amount of the penalty in its total estimated cost for the Line 6B crude oil release, which was increased from US$785 million ($131 million after-tax attributable to Enbridge) as at June 30, 2012 to US$810 million ($136 million after-tax attributable to

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Enbridge) as at September 30, 2012. In addition, on July 10, 2012 the National Transportation Safety Board presented the results of its investigation into the Line 6B crude oil release and subsequently publicly posted its final report on July 26, 2012. On October 3, 2012, EEP received a letter from the Environmental Protection Agency (EPA) regarding a Proposed Order for potential incremental containment and active recovery of submerged oil. EEP is in discussions with the EPA regarding the agency’s intent with respect to certain elements of the Proposed Order and the appropriate scope of these activities. As such, EEP has not included significant additional costs related to this Proposed Order in its total incident cost accrual and it is impracticable to provide an estimate at this time.

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

·                  On September 25, 2012, EEP completed the issuance of 16.1 million Class A Common Units for net proceeds of approximately US$447 million.

·                  On September 13, 2012, Enbridge completed an offering of 16 million Cumulative Redeemable Preference Shares, Series P for aggregate gross proceeds of $400 million.

·                  On July 18, 2012, Enbridge issued a $100 million Century Bond with a term to maturity of 100 years through its subsidiary, Enbridge Pipelines Inc., the second Century Bond ever issued by a Canadian corporation.

·                  On July 17, 2012, Enbridge completed an offering of 18 million Cumulative Redeemable Preference Shares, Series N for aggregate gross proceeds of $450 million.

·                  On July 6, 2012, a new US$675 million of credit facility was secured by EEP, bringing Enbridge’s enterprise-wide general purpose credit facilities to $11.6 billion.

DIVIDEND DECLARATION

On October 24, 2012, the Enbridge Board of Directors declared the following quarterly dividends. All dividends are payable on December 1, 2012 to shareholders of record on November 15, 2012.

1                  This is the first dividend declared for Preference Shares, Series N.

2                  This is the first dividend declared for Preference Shares, Series P.

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CONFERENCE CALL

Enbridge will hold a conference call on Wednesday, November 7, 2012 at 9:00 a.m. Eastern Time (7:00 a.m. Mountain Time) to discuss the third quarter 2012 results. Analysts, members of the media and other interested parties can access the call at (617) 213-4850 or toll-free at 1-888-679-8038 using the access code of 82312523. The call will be audio webcast live at www.enbridge.com/InvestorRelations/Events.aspx. A webcast replay and podcast will be available approximately two hours after the conclusion of the event and a transcript will be posted to the website within 24 hours. The replay at toll-free 1-888-286-8010 or (617) 801-6888 (access code 34744052) will be available until November 14, 2012.

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

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

Enbridge Inc., a Canadian company, is a North American leader in delivering energy and one of the Global 100 Most Sustainable Corporations. As a transporter of energy, Enbridge operates, in Canada and the United States, the world’s longest crude oil and liquids transportation system. The Company also has a significant and growing involvement in the 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 close to 1,000 megawatts of renewable and alternative energy generating capacity and is expanding its interest in wind and solar energy, geothermal and hybrid fuel cells. Enbridge employs more than 10,000 people, primarily in Canada and the United States and is ranked as one of Canada’s Greenest Employers and one of Canada’s Top 100 Employers for 2013. Enbridge is included on the 2012/2013 Dow Jones Sustainability World Index and the Dow Jones Sustainability North America Index and is also a constituent of the 2012/2013 FTSE4Good Index Series. Enbridge is also featured on the 2012 Carbon Disclosure Leadership Index. Our United States affiliate, Enbridge Energy Partners, is ranked as one of the 100 Most Trustworthy Companies in America. 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 or adjusted earnings; expected earnings or adjusted earnings per share; expected costs related to projects under construction; expected in-service dates for projects under construction; expected capital expenditures; estimated future dividends; and expected costs related to leak remediation and potential insurance recoveries.

Although Enbridge believes that these forward-looking statements are reasonable based on the information available on the date such statements are made and processes used to prepare the information, such statements are not guarantees of future performance and readers are cautioned against placing undue reliance on forward-looking statements. By their nature, these statements involve a variety of assumptions, known and unknown risks and uncertainties and other factors, which may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Material assumptions include assumptions about: the expected supply and demand for crude oil, natural gas and natural gas liquids (NGL); prices of crude oil, natural gas and NGL; expected exchange rates; inflation; interest rates; the availability and price of labour and

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pipeline construction materials; operational reliability; customer project approvals; maintenance of support and regulatory approvals for the Company’s projects; anticipated in-service dates; and weather. Assumptions regarding the expected supply and demand of crude oil, natural gas and NGL, and the prices of these commodities, are material to and underlie all forward-looking statements. These factors are relevant to all forward-looking statements as they may impact current and future levels of demand for the Company’s services. Similarly, exchange rates, inflation and interest rates impact the economies and business environments in which the Company operates, may impact levels of demand for the Company’s services and cost of inputs, and are therefore inherent in all forward-looking statements. Due to the interdependencies and correlation of these macroeconomic factors, the impact of any one assumption on a forward-looking statement cannot be determined with certainty, particularly with respect to expected earnings or adjusted earnings and 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, 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 (earnings/(loss)) adjusted for unique or 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. Management believes that the presentation of adjusted earnings/(loss) provides useful information to investors and shareholders as it provides increased transparency and predictive value. Management uses adjusted earnings/(loss) to set targets, assess performance of the Company and set the Company’s dividend payout target. Adjusted earnings/(loss) and adjusted earnings/(loss) for each of the segments are not measures that have a standardized meaning prescribed by U.S. GAAP and are not considered GAAP measures; therefore, these measures may not be comparable with similar measures presented by other issuers.

Enbridge Contacts:

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HIGHLIGHTS

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

2                  Canadian Mainline includes deliveries ex-Gretna, Manitoba which is made up of United States and eastern Canada deliveries originating from western Canada.

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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

September 30, 2012

MANAGEMENT’S DISCUSSION AND ANALYSIS

FOR THE THREE AND NINE MONTHS ENDED SEPTEMBER 30, 2012

This Management’s Discussion and Analysis (MD&A) dated November 6, 2012 should be read in conjunction with the unaudited consolidated financial statements and notes thereto of Enbridge Inc. (Enbridge or the Company) as at and for the three and nine months ended September 30, 2012, prepared in accordance with United States generally accepted accounting principles (U.S. GAAP). It should also be read in conjunction with the audited consolidated financial statements, which were prepared in accordance with Part V — Pre-changeover Accounting Standards of the Canadian Institute of Chartered Accountants Handbook (Part V), and MD&A contained in the Company’s Annual Report for the year ended December 31, 2011, as well as the consolidated financial statements and notes thereto for the year ended December 31, 2011 prepared in accordance with U.S. GAAP and filed on a voluntary basis (U.S. GAAP Consolidated Financial Statements) to facilitate understanding of the Company’s transition to U.S. GAAP. 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 $189 million for the three months ended September 30, 2012, or $0.24 per common share, compared with a loss of $5 million, or $0.01 per common share, for the three months ended September 30, 2011. This increase primarily reflected a significant reduction in the net unrealized fair value losses on financial derivatives recognized in the third quarter of 2012 compared with 2011. The most significant reductions were on derivatives related to foreign exchange risk management positions, partially offset by increased unrealized losses associated with the revaluation of financial derivatives used to risk manage the profitability of transportation and storage transactions. Increased earnings from Liquids Pipelines as a result of strong volumes and favourable operating performance under the Competitive Toll Settlement (CTS), as well as operating earnings from Seaway Pipeline, also contributed to the overall earnings increase. For the three months ended September 30, 2012, $19 million of insurance recoveries net of additional leak remediation costs associated with the Line 6B crude oil release was reflected in earnings from Enbridge Energy Partners, L.P. (EEP), compared with net leak remediation costs of $8 million for the third quarter of 2011.

Earnings attributable to common shareholders were $464 million for the nine months ended September 30, 2012, or $0.60 per common share, compared with $661 million, or $0.88 per common share, for the nine months ended September 30, 2011. The decrease in year-to-date earnings reflected the same drivers as the third quarter, although net unrealized fair value losses on financial derivatives increased significantly in 2012 compared with 2011. The most significant change, recognized in Energy Services, related to the revaluation of financial derivatives used to risk manage the profitability of transportation and storage transactions.

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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 or adjusted earnings; expected earnings or adjusted earnings 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 and natural gas liquids (NGL); prices of crude oil, natural gas and NGL; expected exchange rates; inflation; interest rates; the availability and price of labour and pipeline construction materials; operational reliability; customer project approvals; maintenance of support and regulatory approvals for the Company’s projects; anticipated in-service dates; and weather. Assumptions regarding the expected supply and demand of crude oil, natural gas and NGL, and the prices of these commodities, are material to and underlie all forward-looking statements. These factors are relevant to all forward-looking statements as they may impact current and future levels of demand for the Company’s services. Similarly, exchange rates, inflation and interest rates impact the economies and business environments in which the Company operates, may impact levels of demand for the Company’s services and cost of inputs, and are therefore inherent in all forward-looking statements. Due to the interdependencies and correlation of these macroeconomic factors, the impact of any one assumption on a forward-looking statement cannot be determined with certainty, particularly with respect to expected earnings or adjusted earnings and 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, exchange rates, interest rates, commodity prices and supply and demand for commodities, including but not limited to those risks and uncertainties discussed in this MD&A and in the Company’s other filings with Canadian and United States securities regulators. The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these are interdependent and Enbridge’s future course of action depends on management’s assessment of all information available at the relevant time. Except to the extent required by law, Enbridge assumes no obligation to publicly update or revise any forward-looking statements made in this MD&A or otherwise, whether as a result of new information, future events or otherwise. All subsequent forward-looking statements, whether written or oral, attributable to Enbridge or persons acting on the Company’s behalf, are expressly qualified in their entirety by these cautionary statements.

NON-GAAP MEASURES

This MD&A contains references to adjusted earnings/(loss), which represent earnings or loss attributable to common shareholders (earnings/(loss)) adjusted for unique or 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. Management believes that the presentation of adjusted earnings/(loss) provides useful information to investors and shareholders as it provides increased transparency and predictive value. Management uses adjusted earnings/(loss) to set targets, assess performance of the Company and set the Company’s dividend payout target. Adjusted earnings/(loss) and adjusted earnings/(loss) for each of the segments are not measures that have a standardized meaning prescribed by 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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ADJUSTED EARNINGS

Adjusted earnings were $269 million, or $0.34 per common share, for the three months ended September 30, 2012 compared with $239 million, or $0.32 per common share, for the three months ended September 30, 2011. Adjusted earnings were $922 million, or $1.20 per common share, for the nine months ended September 30, 2012 compared with $827 million, or $1.10 per common share, for the nine months ended September 30, 2011. The following factors impacted the increase in adjusted earnings for both the three and nine months ended September 30, 2012 compared with 2011.

·                  Within Liquids Pipelines, strong volumes on Canadian Mainline and Spearhead Pipeline contributed to an overall increase in adjusted earnings. Incremental oil sands crude production in Alberta and strong production growth out of the Bakken in North Dakota have bolstered supply to midwest markets and placed increased downward pressure on crude oil prices in this market. Enbridge believes this pressure will at least be partially reduced upon completion of its market access projects. This discounted crude oil, coupled with strong refining margins, is increasing demand in the midwest for Canadian and Bakken crude oil supply and driving increased long haul barrels on Canadian Mainline and the Lakehead System owned by EEP. Enbridge’s 50% interest in the Seaway Pipeline, acquired in late 2011, also favourably impacted earnings for the three and nine months ended September 30, 2012.

·                  Within Gas Distribution, Enbridge Gas Distribution’s (EGD) adjusted earnings were impacted by increased system integrity and operating and administrative costs, partially offset by customer growth and lower interest expense. Enbridge Gas New Brunswick (EGNB) continued to see decreased earnings as a result of changes in ratemaking regulations by the New Brunswick Government in April 2012. EGNB is now subject to variability in volumes delivered; therefore, earnings will fluctuate with seasonal demand.

·                  Within Sponsored Investments, increased EEP adjusted earnings primarily reflected higher average daily delivery volumes on all major liquids systems, partially offset by significantly lower natural gas and NGL prices affecting its natural gas business and additional operating and administrative costs.

·                  Also within Sponsored Investments, increased contributions from Enbridge Income Fund (the Fund) due to the acquisition and strong operating performance of its renewable energy assets were partially offset by associated financing costs and taxes.

·                 The increase in Corporate adjusted loss period-over-period was due to higher preference share dividends and higher taxes, partially offset by lower residual corporate interest costs.

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RECENT DEVELOPMENTS

CHIEF EXECUTIVE OFFICER SUCCESSION

On September 5, 2012, the Board of Directors (Board) announced the appointment of Al Monaco to the position of Chief Executive Officer (CEO), effective October 1, 2012. Mr. Monaco continues to serve as President and as a member of the Board. Also effective October 1, 2012, Patrick D. Daniel retired as CEO and from Enbridge’s Board. Prior to being appointed President in February 2012, Mr. Monaco held the role of President, Gas Pipelines, Green Energy and International. With Mr. Monaco’s appointment as President of Enbridge, Leon Zupan was appointed President, Gas Pipelines and Richard Bird, Executive Vice President, Chief Financial Officer and Corporate Development, assumed responsibility for Enbridge’s Green Energy, International and Energy Services businesses.

LIQUIDS PIPELINES

Southern Lights Pipeline

Both the Canadian and United States uncommitted rates on Southern Lights Pipeline for 2010, 2011 and 2012 were challenged by Exxon Mobil and Imperial Oil. The Canadian Southern Lights toll hearing was held before National Energy Board (NEB) panel members in November 2011. On February 9, 2012, the NEB issued its decision rejecting the challenge from uncommitted shippers and stating that tolls in place are just and reasonable, and more recently approved the 2010, 2011 and 2012 interim tolls as final. A Federal Energy Regulatory Commission (FERC) hearing was held in January 2012. Briefs were filed on February 27, 2012 and March 28, 2012 and an initial decision was issued on June 5, 2012. The initial decision found that the uncommitted rates were just and reasonable. The parties have filed briefs in response to this decision and the case is pending final decision from the FERC. No material financial impact to the Company is anticipated to result from the FERC proceeding.

Elk Point Pump Station Facility Oil Release

On June 19, 2012, Enbridge reported an oil release at its Elk Point pumping station on Line 19 (Athabasca Pipeline), approximately 70 kilometres (44 miles) south of Bonnyville, Alberta and approximately 24 kilometres (15 miles) from the town of Elk Point, Alberta. On June 24, 2012, the Company restarted the Elk Point pumping station after completing necessary repairs. The contaminated soil and free product has been removed from the site for processing and disposal. Further environmental testing and monitoring of the site is being conducted. Estimated volume of the release is approximately 1,400 barrels which were largely contained within the station. Management does not believe this incident will have a material impact on the Company’s consolidated financial position or results of operations.

Norman Wells Pipeline Crude Oil Release

On May 9, 2011, Enbridge reported a crude oil release from the Norman Wells Pipeline approximately 50 kilometres (31 miles) south of the community of Wrigley, Northwest Territories (NWT). The Norman Wells Pipeline is a 12-inch, 39,400 barrels per day (bpd) line transporting sweet crude oil that stretches 869 kilometres (540 miles) from Norman Wells, NWT to Zama, Alberta. On May 20, 2011, Enbridge returned the Norman Wells line to service after completing necessary repairs. Excavation of all contaminated soils from the spill site was completed in late November 2011. Based on the volume of contaminated materials removed from the site, the current estimate of volume released is approximately 1,600 barrels. Site remediation work was completed in the summer of 2012. Monitoring of surface water and groundwater at the site will continue until reclamation goals have been achieved in accordance with plans filed with the regulator. Management does not believe this incident will have a material impact on the Company’s consolidated financial position or results of operations.

GAS DISTRIBUTION

Enbridge Gas New Brunswick – Regulatory Matters

On December 9, 2011 the Government of New Brunswick tabled and then subsequently passed legislation related to the regulatory process for setting rates for gas distribution within the province. The legislation permitted the government to implement new regulations which could affect the franchise agreement between EGNB and the province, impact prior decisions by the province’s independent regulator and influence the regulator’s future decisions. However, significant details of the rate setting

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process were left to be established in the new regulations and, as such, the effect of such legislation was not determinable at that time.

A final rates and tariffs regulation was subsequently enacted by the Government of New Brunswick on April 16, 2012. Based on the amended rate setting methodology and specific conditions outlined therein, EGNB no longer met the criteria for the continuation of rate regulated accounting. As a result, the Company eliminated from its Consolidated Statements of Financial Position a deferred regulatory asset of $180 million and a regulatory asset with respect to capitalized operating costs of $103 million, net of an Income tax recovery of $21 million.

As the final rates and tariffs regulation published on April 16, 2012 provided further evidence of a condition that existed on December 31, 2011, a charge totaling $262 million, after tax, was reflected as a subsequent event in the Company’s U.S. GAAP Consolidated Financial Statements for the year ended December 31, 2011, which were filed with the Canadian Securities Administrators and the United States Securities and Exchange Commission (SEC) on May 2, 2012. The charge reflected Management’s best estimate based on facts available at the time and may be subject to further revision based on future actions or interpretations of the regulator, the Government of New Brunswick or other factors, including legal proceedings which Enbridge has commenced.

On April 26, 2012, the Company, Enbridge Energy Distribution Inc. (EEDI) and EGNB commenced an action against the Province of New Brunswick in the New Brunswick Court of Queen’s Bench, claiming damages in the amount of $650 million as a result of the continuing breaches by the province of the General Franchise Agreement it signed with Enbridge in 1999. Additionally, on May 2, 2012, the Company, EEDI and EGNB filed a Notice of Application with the New Brunswick Court of Queen’s Bench seeking a declaration from the Court that the rates and tariffs regulation is invalid. In a decision released on August 23, 2012, the Court dismissed EGNB’s Application. EGNB has filed a Notice of Appeal with the New Brunswick Court of Appeal but a hearing date for the appeal has not yet been scheduled. On September 20, 2012, the New Brunswick Energy and Utilities Board (EUB) issued a decision regarding EGNB’s rates that were to take effect as of October 1, 2012. The EUB’s decision applies the rate-setting methodology set out in the rates and tariffs regulation. EGNB has filed an application for judicial review of the EUB’s rate order with the New Brunswick Court of Appeal. There is no assurance these actions will be successful or will result in any recovery.

GAS PIPELINES, PROCESSING AND ENERGY SERVICES

Greenwich Wind Energy Project

In May 2012, the Company acquired from Renewable Energy Systems Canada Inc. the remaining 10% interest in the Greenwich Wind Energy Project (Greenwich) through Greenwich Windfarm, LP, for $27 million, increasing its ownership to 100%. See Recent Developments – Sponsored Investments – Enbridge Income Fund – Proposed Crude Oil Storage and Renewable Energy Assets Transfer.

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SPONSORED INVESTMENTS

ENBRIDGE ENERGY PARTNERS, L.P.

Class A Common Units Issuance

In September 2012, EEP issued 16.1 million Class A Common Units for net proceeds of approximately US$447 million. As a result of the Common Units issuance, Enbridge recognized a $27 million dilution gain in Equity and reduced its effective ownership interest in EEP from 23% to 22%.

Lakehead System Line 14 Crude Oil Release

On July 27, 2012, a release of crude oil was detected on Line 14 of EEP’s Lakehead System near Grand Marsh, Wisconsin. The estimated volume of oil released was approximately 1,200 barrels. EEP received a Corrective Action Order (CAO) from the Pipeline and Hazardous Materials Safety Administration (PHMSA) on July 30, 2012, followed by an amended CAO on August 1, 2012. The CAOs required EEP to take certain corrective actions, some of which have already been completed and some are still ongoing, as part of an overall plan for its Lakehead System. A notable part of the CAOs was to hire an independent third party pipeline expert to review and assess EEP’s overall integrity program. An independent third party expert was contracted during the third quarter of 2012 and their work is currently ongoing.

Upon restart of Line 14 on August 7, 2012, PHMSA restricted the operating pressure to 80% of the pressure in place at the time immediately prior to the incident. The pressure restrictions will remain in place until such time EEP can demonstrate that the root cause of the incident has been remediated.

EEP has updated the disclosed estimate for repair and remediation related costs associated with this crude oil release to approximately US$12 million ($2 million after-tax attributable to Enbridge), inclusive of approximately US$2 million of lost revenue, and excluding any fines and penalties. Despite the efforts EEP has made to ensure the reasonableness of its estimate, changes to the estimated amounts associated with this release are possible as more reliable information becomes available. EEP will be pursuing claims under Enbridge’s comprehensive insurance policy, although it does not expect any recoveries to be significant.

Lakehead System Line 6A and 6B Crude Oil Releases

Line 6B Crude Oil Release

During the second quarter of 2012, local authorities allowed the Kalamazoo River and Morrow Lake, which were affected by the Line 6B crude oil release, to be re-opened for recreational use. EEP continues to perform necessary remediation, restoration and monitoring of the areas affected by the Line 6B crude oil release. EEP expects to make payments for additional costs associated with submerged oil and sheen monitoring and recovery operations, including remediation and restoration of the area, containment management, air and groundwater monitoring, scientific studies and hydrodynamic modeling, along with legal, professional and regulatory costs through future periods. All of 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 July 2, 2012, EEP received a Notice of Probable Violation (NOPV) from the PHMSA related to the July 26, 2010 Line 6B crude oil release, which resulted in payment of a US$3.7 million civil penalty in the third quarter of 2012. EEP included the amount of the penalty in its total estimated cost for the Line 6B crude oil release. In addition, on July 10, 2012 the National Transportation Safety Board presented the results of its investigation into the Line 6B crude oil release and subsequently publicly posted its final report on July 26, 2012.

As at September 30, 2012, EEP had revised the total incident cost accrual to US$810 million ($136 million after-tax attributable to Enbridge), primarily due to an estimate of extended oversight by regulators and additional legal costs associated with various lawsuits, which is an increase of US$25 million ($5 million after-tax attributable to Enbridge) from its estimate at June 30, 2012. This total estimate is before insurance recoveries and excludes additional fines and penalties, which may be imposed by federal, state and local government agencies, other than the PHMSA civil penalty described above. On October 3, 2012, EEP received a letter from the Environmental Protection Agency (EPA) regarding a Proposed Order for potential incremental containment and active recovery of submerged oil. EEP is in discussions

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with the EPA regarding the agency’s intent with respect to certain elements of the Proposed Order and the appropriate scope of these activities. As such, EEP has not included significant additional costs related to this Proposed Order in its total incident cost accrual and it is impracticable to provide an estimate at this time.

Expected losses associated with the Line 6B crude oil release included those costs that were considered probable and that could be reasonably estimated at September 30, 2012. 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.

Line 6A Crude Oil Release

EEP continues to monitor the areas affected by the crude oil release from Line 6A of its Lakehead System near Romeoville, Illinois in September 2010 for any additional requirements; however, the cleanup, remediation and restoration of the areas affected by the release have been substantially completed.

In connection with this crude oil release, the cost estimate remains at approximately US$48 million ($7 million after-tax attributable to Enbridge), before insurance recoveries and excluding fines and penalties. EEP has the potential of incurring additional costs in connection with this crude oil release, including fines and penalties as well as expenditures associated with litigation. EEP is pursuing recovery of the costs associated with the Line 6A crude oil release from third parties; however, there can be no assurance that any such recovery will be obtained.

Insurance Recoveries

EEP is included in the comprehensive insurance program that is maintained by Enbridge for its subsidiaries and affiliates which renews in May of each year. The program includes commercial liability insurance coverage that is consistent with coverage considered customary for its industry and includes coverage for environmental incidents such as those incurred for the crude oil releases from Lines 6A and 6B, excluding costs for fines and penalties. The claims for the crude oil release for Line 6B are covered by Enbridge’s comprehensive insurance policy that expired on April 30, 2011, which had an aggregate limit of US$650 million for pollution liability. Based on EEP’s remediation spending through September 30, 2012, 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.

EEP recognized US$170 million ($24 million after-tax attributable to Enbridge) of insurance recoveries as reductions to Environmental costs, net of recoveries, for the Line 6B crude oil release in the Consolidated Statements of Earnings for the three and nine months ended September 30, 2012, compared with US$85 million ($13 million after-tax attributable to Enbridge) and US$135 million ($21 million after-tax attributable to Enbridge) for the three and nine months ended September 30, 2011, respectively. As at September 30, 2012, EEP had recorded total insurance recoveries of US$505 million ($74 million after-tax attributable to Enbridge) for the Line 6B crude oil release. EEP expects to record receivables for additional amounts claimed for recovery pursuant to insurance policies during the period it deems realization of the claim for recovery to be probable.

Effective May 1, 2012, Enbridge renewed its comprehensive insurance program, through April 30, 2013, with a current liability aggregate limit of US$660 million, including sudden and accidental pollution liability.

Legal and Regulatory Proceedings

A number of United States governmental agencies and regulators have initiated investigations into the Line 6A and Line 6B crude oil releases. Approximately 30 actions or claims have been filed against Enbridge, EEP or their affiliates in United States federal and state courts in connection with the Line 6B crude oil release, including direct actions and actions seeking class status. Based on the current status of these cases, EEP does not expect these actions to be material. As noted above, on July 2, 2012, PHMSA announced a NOPV related to the Line 6B crude oil release, including a civil penalty of US$3.7 million

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that EEP paid in the third quarter of 2012. One claim related to the Line 6A crude oil release has been filed against Enbridge, EEP or their affiliates by the State of Illinois in a United States state court. The parties are currently operating under an agreed interim order.

Enbridge Income Fund

Proposed Crude Oil Storage and Renewable Energy Assets Transfer

In October 2012, Enbridge Income Fund Holdings Inc. (ENF) and the Fund announced they had entered into an agreement with Enbridge pursuant to which Enbridge would transfer five entities, which comprise crude oil storage in Alberta and renewable energy assets in Ontario, to the Fund. The agreement contemplates that Hardisty Contract Terminal, Hardisty Storage Caverns, Greenwich, and Amherstburg and Tilbury solar projects would be transferred for an aggregate price of approximately $1.2 billion, to be paid in part by the issuance of additional ordinary trust units of the Fund to ENF and additional Enbridge Commercial Trust preferred units to Enbridge. Under the agreement, Enbridge has agreed to provide bridge debt financing to the Fund for the balance of the price. The transaction is subject to all necessary approvals, including approval by the minority shareholders of ENF, as well as regulatory approval. If approved, and upon repayment of the bridge financing, the transaction is expected to provide Enbridge $0.8 billion of net funding for its large growth capital investment program.

Saskatchewan System Shipper Complaint

On December 17, 2010, the Saskatchewan System filed amended Westspur tariffs with the NEB with an effective date of February 1, 2011. In January 2011, a shipper on the Westspur System requested the NEB make the tolls “interim” effective February 1, 2011 pending discussions between the shipper and the Saskatchewan System on information requests put forward by the shipper. Subsequently, the shipper filed a complaint with the NEB on the basis the information provided by the Saskatchewan System was not adequate to allow for an assessment to be made of the reasonableness of the tolls. Six parties have filed letters with the NEB supporting the shipper’s complaint. The NEB directed additional discussion among the parties and, as of November 6, 2012, the Fund continues to review the structure of its tolls with shippers.

CORPORATE

Noverco

Noverco Inc. (Noverco) holds, directly and indirectly, an investment in Enbridge common shares. In early 2012, Noverco advised Enbridge the substantial increase in the value of these shares over the last decade resulted in a significant shift in the balance of Noverco’s asset mix. The Board of Noverco authorized the Caisse de Depot et Placement de Quebec, as manager of Noverco, to sell a portion of its Enbridge common share holding and rebalance Noverco’s asset mix. On March 22, 2012, Noverco sold 22.5 million Enbridge common shares through a secondary offering. Enbridge’s share of the proceeds of approximately $317 million was received as a dividend from Noverco on May 18, 2012 and was used to pay a portion of the Company’s quarterly dividend on June 1, 2012. This portion of the quarterly dividend did not qualify for the enhanced dividend tax credit in Canada and accordingly, was not designated as an “eligible dividend”. For United States tax purposes, the dividend was a “qualified dividend”.

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Preference Share Issuances

Since January 1, 2012, the Company has issued 92 million preference shares for gross proceeds of approximately $2,310 million with the following characteristics. See Outstanding Share Data.

Common Share Issuance

On June 8, 2012, the Company issued 9.83 million Common Shares for gross proceeds of approximately $400 million.

GROWTH PROJECTS – COMMERCIALLY SECURED PROJECTS

The table below summarizes the current status of the Company’s commercially secured projects in each of the Company’s business segments.

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

2            Expenditures to date reflect total cumulative expenditures incurred from inception of project up to September 30, 2012.

3            See Growth Projects – Commercially Secured Projects – Sponsored Investments – Enbridge Energy Partners, L.P – Eastern Access Expansion for project discussion.

4           Expenditures to date reflect total expenditures before receipt of US$0.1 billion payment from the United States Treasury. See Growth Projects – Commercially Secured Projects – Gas Pipelines, Processing and Energy Services – Silver State North Solar Project.

LIQUIDS PIPELINES

Edmonton Terminal Expansion

The Edmonton Terminal Expansion Project involves expanding the tankage of the mainline terminal at Edmonton, Alberta by one million barrels at an estimated cost of $0.3 billion, with expenditures to date of approximately $0.1 billion. The expansion is required to accommodate growing oil sands production receipts both from Enbridge’s Waupisoo Pipeline and other non-Enbridge pipelines. The expansion is being conducted over two phases and consists of the construction of four tanks and the installation of three booster pumps and related infrastructure. Regulatory approval was received in the first quarter of 2011 and the expansion is expected to be completed by December 2012.

Woodland Pipeline

Enbridge entered into a joint venture agreement with Imperial Oil Resources Ventures Limited and ExxonMobil Canada Properties to provide for the transportation of blended bitumen from the Kearl oil sands mine to crude oil hubs in the Edmonton, Alberta area. The project will be phased with the mine expansion, with the first phase involving construction of a new 140-kilometre (87-mile) 36-inch diameter pipeline from the mine to the Cheecham Terminal, and service on Enbridge’s existing Waupisoo Pipeline from Cheecham to the Edmonton area. The total estimated cost of the Phase I pipeline from the mine to the Cheecham Terminal and related facilities is approximately $0.5 billion, of which Enbridge’s share is approximately $0.3 billion. Enbridge’s share of total project expenditures to date is approximately $0.3 billion. Enbridge expects the pipeline will come into service in late 2012.

Wood Buffalo Pipeline

Enbridge entered into an agreement with Suncor Energy Inc. (Suncor) to construct a new, 95-kilometre (59-mile) 30-inch diameter crude oil pipeline, connecting the Athabasca Terminal adjacent to Suncor’s oil sands plant to the Cheecham Terminal, which is the origin point of Enbridge’s Waupisoo Pipeline. The Waupisoo Pipeline already delivers crude oil from several oil sands projects to the Edmonton, Alberta mainline hub. The new Wood Buffalo Pipeline parallels the existing Athabasca Pipeline between the Athabasca and Cheecham Terminals. The estimated capital cost remains at approximately $0.4 billion, with expenditures to date of approximately $0.3 billion. Although construction was completed and the new pipeline entered service in October 2012, additional expenditures on testing and site restoration will continue to be incurred into 2013.

Waupisoo Pipeline Capacity Expansion

The Waupisoo Pipeline Capacity Expansion, which received regulatory approval in November 2010, is expected to provide 65,000 bpd of additional capacity in the fourth quarter of 2012 and an estimated 190,000 bpd of additional capacity in the second half of 2013 when the expansion is fully in service. The estimated cost of the project is approximately $0.4 billion, with expenditures to date of approximately $0.2 billion.

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Seaway Crude Pipeline System

Acquisition of Interest

In 2011, Enbridge acquired a 50% interest in the Seaway Pipeline system at a cost of approximately US$1.2 billion. The 1,078-kilometre (670-mile) Seaway Pipeline includes the 805-kilometre (500-mile), 30-inch diameter long-haul system from Freeport, Texas to Cushing, Oklahoma, as well as the Texas City Terminal and Distribution System which serves refineries in the Houston and Texas City areas. The Seaway Pipeline also includes 6.8 million barrels of crude oil tankage on the Texas Gulf Coast and four marine import facilities at two locations. The other 50% interest in the Seaway Pipeline system is owned by Enterprise Products Partners L.P. (Enterprise).

Including the acquisition of the 50% interest in the Seaway Pipeline, Enbridge’s total expected cost for the Seaway Crude Pipeline System is approximately US$2.4 billion. The joint Enbridge and Enterprise project, which consists of a reversal, an expansion and an extension, is expected to cost approximately US$1.2 billion, with expenditures incurred to date of approximately US$0.1 billion. Each of these components is discussed below.

Reversal

In December 2011, Enbridge and Enterprise announced plans to reverse the flow direction of the Seaway Pipeline, enabling it to transport crude oil from the oversupplied hub in Cushing, Oklahoma to the United States Gulf Coast. Included in the project scope is a 105-kilometre (65-mile), 36-inch new-build lateral from the Seaway Jones Creek facility southwest of Houston, Texas into Enterprise’s ECHO crude oil terminal (ECHO Terminal) southeast of Houston. The reversal of the pipeline and acceptance of first crude was completed in May 2012, providing initial capacity of 150,000 bpd. Following pump station additions and modifications, which are expected to be completed in the first quarter of 2013, capacity is anticipated to increase to approximately 400,000 bpd depending upon the mix of light and heavy grades of crude oil.

Expansion and Extension

In March 2012, Enbridge and Enterprise, based on additional capacity commitments from shippers, announced plans to proceed with an expansion of the Seaway Pipeline through construction of a second line that will more than double its capacity to 850,000 bpd in mid-2014. This 30-inch diameter pipeline, which will follow the same route, will twin the existing Seaway system.

In addition, a 137-kilometre (85-mile) pipeline will be constructed from the ECHO Terminal to the Port Arthur/Beaumont, Texas refining center to provide shippers access to the region’s heavy oil refining capabilities. This lateral will offer capacity of 560,000 bpd and, subject to regulatory approvals, is expected to be available in mid-2014.

South Cheecham Rail and Truck Terminal

The Company has partnered with Keyera Corp. to construct the South Cheecham Rail and Truck Terminal (the Terminal), located approximately 75 kilometres (47 miles) southeast of Fort McMurray, Alberta. The Terminal, to be developed in phases, will be a multi-purpose hydrocarbon rail and truck terminal, designed to support bitumen producers within the Athabasca oil sands area and facilitate product in and out. In addition to the facilities for handling diluent and diluted bitumen at the Terminal, the initial phase is planned to include a diluted bitumen pipeline connection to Enbridge’s existing Cheecham terminal. Construction is underway and completion of the first phase is expected to take place in the second quarter of 2013 for a total cost of approximately $90 million. Enbridge’s share of the project costs will be based upon its 50% joint venture interest.

Norealis Pipeline

In order to provide pipeline and terminaling services to the proposed Husky-operated Sunrise Oil Sands Project, the Company is undertaking construction of a new originating terminal (Norealis Terminal), a 112-kilometre (66-mile) 24-inch diameter pipeline (Norealis Pipeline) from the Norealis Terminal to the Cheecham Terminal and additional tankage at Cheecham. The estimated cost of the project is

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approximately $0.5 billion, with expenditures to date of approximately $0.2 billion. With regulatory approval received in the second quarter of 2011, the project is expected to be in service in late 2013.

Suncor Bitumen Blend

In September 2012, Enbridge entered into an agreement with Suncor for a Bitumen Blend project, which includes the construction of a new 350,000 barrel tank, new blend and diluent lines and pumping capacity to connect with Suncor’s lines just outside Enbridge’s Athabasca Tank Farm. These new facilities will enable Suncor to transport blended bitumen volumes from its Firebag production into the Wood Buffalo pipeline. The estimated cost for the project is approximately $0.2 billion, with expenditures to date of approximately $0.1 billion and in-service expected in the second quarter of 2013.

Athabasca Pipeline Capacity Expansion

The Company is undertaking an expansion of its Athabasca Pipeline to its full capacity to accommodate additional contractual commitments, including incremental production from the Christina Lake Oilsands Project operated by Cenovus Energy. This expansion is expected to increase the capacity of the Athabasca Pipeline to its maximum capacity of approximately 570,000 bpd, depending on the mix of crude oil types. The estimated cost of full expansion is approximately $0.4 billion, with expenditures to date of approximately $0.2 billion and an expected in-service date in the first quarter of 2013, for an initial 430,000 bpd of capacity. The balance of additional capacity is expected to be available by early 2014. The Athabasca Pipeline transports crude oil from various oil sands projects to the mainline hub at Hardisty, Alberta.

Flanagan South Pipeline Project

The 950-kilometre (590-mile) Flanagan South Pipeline will have an initial capacity of 585,000 bpd to transport crude oil from the Company’s terminal at Flanagan, Illinois to Cushing, Oklahoma. The 36-inch diameter pipeline will be installed adjacent to the Company’s Spearhead Pipeline for the majority of the route. Subject to regulatory and other approvals, the pipeline is expected to be in service by mid-2014. The estimated cost of the project is approximately US$2.8 billion, with expenditures to date of approximately US$0.1 billion.

Canadian Mainline Expansion

In May 2012, Enbridge announced an estimated $0.2 billion expansion of the Alberta Clipper line between Hardisty, Alberta and the Canada/United States border near Gretna, Manitoba. The current scope of the project involves the addition of pumping horsepower sufficient to raise the capacity of the Canadian mainline by 120,000 bpd to a capacity of 570,000 bpd and is expected to be in service by mid-2014. The expansion remains subject to NEB approval.

Athabasca Pipeline Twinning

This project involves the twinning of the southern section of the Company’s 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, will include 345 kilometres (210 miles) of 36-inch pipeline adjacent to the existing Athabasca Pipeline right-of-way. The initial annual capacity of the pipeline will be approximately 450,000 bpd, with expansion potential to 800,000 bpd. Subject to regulatory and other approvals, the line is expected to enter service in 2015.

GAS DISTRIBUTION

Greater Toronto Area Project

In September 2012, EGD announced plans to expand its natural gas distribution system in the Greater Toronto Area (GTA) to meet the demands of growth and continue the safe and reliable delivery of natural gas to current and future customers. At an expected cost of up to $0.6 billion, the proposed GTA project will consist of two segments of pipeline and related facilities to upgrade the existing distribution system that delivers natural gas to several municipalities in Ontario. Subject to Ontario Energy Board approval, construction is targeted to start in 2014, with an expected completion in early 2016.

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GAS PIPELINES, PROCESSING AND ENERGY SERVICES

Silver State North Solar Project

In March 2012, Enbridge acquired a 100% interest in the development of the 50-megawatt (MW) Silver State North Solar Project (Silver State), located 65 kilometres (40 miles) south of Las Vegas, Nevada. The project, which began commercial operation in May 2012, was constructed under a fixed-price engineering, procurement and construction agreement with First Solar. First Solar is providing operations and maintenance services under a long-term contract. Energy output is being delivered to NV Energy, Inc. under a 25-year power purchase agreement (PPA). The Company’s total investment in the project was approximately US$0.2 billion. In October 2012, the Company received a US$0.1 billion payment from the United States Treasury under a program which reimburses eligible applicants for a portion of costs related to installing specified renewable energy property.

Lac Alfred Wind Project

Enbridge secured a 50% interest in the development of the 300-MW Lac Alfred Wind Project (Lac Alfred), located 400 kilometres (250 miles) northeast of Quebec City in Quebec’s Bas-Saint-Laurent region. The project is being constructed under a fixed price, turnkey, engineering, procurement and construction agreement and will take place in two phases: Phase 1 is expected to be completed in December 2012; while Phase 2 is expected to be completed in December 2013. Hydro-Quebec will purchase the power under a 20-year PPA and will construct the 30-kilometre transmission line to connect Lac Alfred to the grid under an interconnection agreement. The Company’s total investment in the project is expected to be approximately $0.3 billion, with expenditures to date of approximately $0.2 billion.

Cabin Gas Plant

In 2011, the Company secured a 71% interest in the development of the Cabin Gas Plant (Cabin), located 60 kilometres (37 miles) northeast of Fort Nelson, British Columbia in the Horn River Basin. The Company’s total investment in phases 1 and 2 of Cabin was expected to be approximately $1.1 billion, with expenditures to date of approximately $0.7 billion. In October 2012, the Company and its partners announced plans to defer the commissioning of Phase 1 and the construction of Phase 2. Commencing in December 2012, Enbridge expects to begin receiving fees for its investment made to date in both Phases 1 and 2 of Cabin.

Peace River Arch Gas Development

In October 2012, the Company agreed, subject to finalization of definitive agreements, to acquire from Encana Corporation (Encana) certain sour gas gathering and compression facilities. These facilities, which are either currently in service or under construction, are located in the Peace River Arch (PRA) region of northwest Alberta. Closing of the transaction is scheduled for December 2012. Following the completion of construction in 2013, Enbridge’s investment in the PRA Gas Development is expected to be approximately $0.3 billion. Enbridge is also working exclusively with Encana on facility scoping for development of additional major midstream facilities in the liquids-rich PRA region, which is expected to grow significantly in the years to come. Financial terms of the PRA Gas Development are expected to parallel previously established terms of the Cabin development.

Tioga Lateral Pipeline

Alliance Pipeline US is constructing a natural gas pipeline lateral and associated facilities to connect production from the Hess Tioga field processing plant in the Bakken region of North Dakota to the Alliance mainline near Sherwood, North Dakota. Through its 50% ownership interest in Alliance Pipeline US, Enbridge’s expected cost related to the project is approximately US$0.1 billion. In October 2012, Alliance Pipeline US executed a contract with Hess Corporation (Hess), as an anchor shipper on the Tioga Lateral Pipeline. Aux Sable Liquids Products (Aux Sable) and Hess have reached a concurrent agreement for the provision of NGL services. The 124-kilometre (77-mile) Tioga Lateral Pipeline will facilitate movement of liquids-rich natural gas to NGL processing facilities owned by Aux Sable at the terminus of the Alliance mainline system. The pipeline will have an initial design capacity of approximately 106 million cubic feet per day (mmcf/d), which can be expanded based on shipper demand. Regulatory approval from FERC was received on September 20, 2012 and construction commenced early October 2012, with an expected in-service date of mid-2013.

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Venice Condensate Stabilization Facility

The Company is carrying out an estimated US$0.2 billion expansion of the Venice Condensate Stabilization Facility (Venice) at its Venice, Louisiana facility within its Offshore business. Expenditures to date are approximately US$0.1 billion. The expanded condensate processing capacity is required to accommodate additional natural gas production from the Olympus offshore oil and gas development. Natural gas production from Olympus will move to Enbridge’s onshore facility at Venice via Enbridge’s Mississippi Canyon offshore pipeline system where it will be processed to separate and stabilize the condensate. The expansion, which is expected to more than double the capacity of the facility to approximately 12,000 barrels of condensate per day, is expected to be in service in late 2013.

Walker Ridge Gas Gathering System

The Company executed definitive agreements in 2010 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 will construct, own and operate the Walker Ridge Gas Gathering System (WRGGS) to provide natural gas gathering services to the proposed Jack, St. Malo and Big Foot ultra-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 0.1 billion cubic feet per day. WRGGS is expected to be in service in 2014 and is expected to cost approximately US$0.4 billion, with expenditures to date of approximately US$0.1 billion.

Big Foot Oil Pipeline

The Company executed definitive agreements in 2011 with Chevron, Statoil Gulf of Mexico LLC and Marubeni Oil & Gas (USA) Inc. to construct and operate a 64-kilometre (40-mile) 20-inch oil pipeline with capacity of 100,000 bpd from the proposed Big Foot ultra-deep water development in the Gulf of Mexico. This crude oil pipeline project is complementary to Enbridge’s plans to construct the WRGGS. The estimated cost of the Big Foot Oil Pipeline, which will be located about 274 kilometres (170 miles) south of the coast of Louisiana, is approximately US$0.2 billion, with expenditures to date of approximately US$0.1 billion, and it is expected to be in service in 2014.

SPONSORED INVESTMENTS

Bakken Expansion Program

A joint project to further expand crude oil pipeline capacity to accommodate growing production from the Bakken and Three Forks formations located in Montana, North Dakota, Saskatchewan and Manitoba is being undertaken by EEP and the Fund. The Bakken Expansion Program is expected to provide capacity of 145,000 bpd. The Bakken Expansion Program involves United States projects undertaken by EEP at a cost of approximately US$0.4 billion and Canadian projects undertaken by the Fund at a cost of approximately $0.2 billion. Regulatory approval has been received and construction commenced in July 2011 on the United States portion of the project, with expenditures to date of approximately US$0.2 billion. In Canada, NEB approval was secured in December 2011 and expenditures to date are approximately $0.1 billion. The Bakken Expansion Program is expected to be completed in the first quarter of 2013.

Enbridge Energy Partners, L.P.

Cushing Terminal Storage Expansion Project

EEP is constructing 13 new storage tanks at its Cushing Terminal with an approximate shell capacity of 4.4 million barrels. To date, 11 tanks have been completed and placed into service, with the remaining two tanks expected to come into service by December 2012.

In July 2012, engineering design commenced on an additional three new tanks and associated infrastructure totaling 936,000 barrels of incremental shell capacity at EEP’s Cushing Terminal, at an estimated cost of US$39 million. The expected in-service date for the three tanks is August 2013. The total estimated cost to construct the 16 storage tanks and infrastructure, as required, is approximately US$0.2 billion, with expenditures to date of approximately US$0.1 billion.

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South Haynesville Shale Expansion

EEP is expanding its East Texas system by constructing three lateral pipelines into the East Texas portion of the Haynesville shale, together with a large diameter lateral pipeline from Shelby County to Carthage. The expansion, completed in the second quarter of 2012 at an approximate cost of US$0.1 billion, increased capacity of EEP’s East Texas system by 900 mmcf/d.

EEP plans to invest an additional US$0.2 billion, with expenditures to date of approximately US$0.1 billion, to expand its East Texas system, including the construction of gathering and related treating facilities. EEP has signed long-term agreements with four major natural gas producers along the Texas side of the Haynesville shale to provide gathering, treating and transmission services. Completion of the additional expansion is dependent on drilling plans of these producers. Due to lower levels of producer activity in light of weak gas prices, EEP has deferred portions of its Haynesville natural gas expansion pending increases in drilling activity.

Berthold Rail Project

EEP is proceeding with the Berthold Rail Project, a US$0.1 billion investment that will provide an interim solution to shipper needs in the Bakken region. The project will expand capacity into the Berthold Terminal by 80,000 bpd and includes the construction of a three-unit train loading facility, crude oil tankage and other terminal facilities adjacent to existing infrastructure. The first phase of terminaling facilities was completed in September 2012, providing an additional capacity of 10,000 bpd to the Berthold Terminal. The loading facility and crude oil tankage are expected to be placed into service in the first quarter of 2013. Project expenditures to date are approximately US$0.1 billion.

Ajax Cryogenic Processing Plant

EEP is constructing an additional processing plant and other facilities on its Anadarko System at an approximate cost of US$0.2 billion, with expenditures to date of approximately US$0.1 billion. The Ajax Plant, with a planned capacity of 150 mmcf/d, is now expected to be in service mid-2013. When operational, the Ajax Plant in conjunction with the Allison Plant, is expected to increase total processing capacity on the Anadarko System to approximately 1,200 mmcf/d.

Bakken Access Program

The Bakken Access Program, a series of projects totaling approximately US$0.1 billion, represents an upstream expansion that will further complement EEP’s Bakken expansion. This expansion program will enhance gathering capabilities on the North Dakota System by 100,000 bpd. The program, which involves increasing pipeline capacities, constructing additional storage tanks and adding truck access facilities at multiple locations in western North Dakota, is expected to be in service by early 2013.

Texas Express Pipeline

The Texas Express Pipeline (TEP) is a joint venture with Enterprise, Anadarko Petroleum Corporation and DCP Midstream LLC to design and construct a new NGL pipeline, as well as two new NGL gathering systems which EEP will build and operate. EEP will invest approximately US$0.4 billion in the TEP, which will originate in Skellytown, Texas and extend approximately 935 kilometres (580 miles) to NGL fractionation and storage facilities in Mont Belvieu, Texas. Expenditures to date are approximately US$0.1 billion. TEP is expected to have an initial capacity of approximately 280,000 bpd and will be expandable to approximately 400,000 bpd. Approximately 250,000 bpd of capacity has been subscribed on the pipeline.

One of the new NGL gathering systems will connect TEP to natural gas processing plants in the Anadarko/Granite Wash production area located in the Texas Panhandle and western Oklahoma, while the second will connect TEP to central Texas Barnett Shale processing plants. Subject to regulatory approvals and finalization of commercial terms, the pipeline and portions of the gathering systems are expected to begin service in mid-2013.

Line 6B Replacement Program

This program includes 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 are now targeted to be placed in service

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during 2013 in consultation with, and to minimize impact to, refiners and shippers served by Line 6B crude oil deliveries. These costs will be recovered through EEP’s tariff surcharge that is part of the system-wide rates of the Lakehead System. The total capital for this replacement program is estimated to be US$0.3 billion, with expenditures to date of approximately US$0.1 billion.

Eastern Access Expansion

As previously announced in 2011, Enbridge and EEP will undertake two projects to provide increased access to refineries in the United States upper mid-west and in Ontario for light crude oil produced in western Canada and the United States. One project involves the expansion of EEP’s Line 5 light crude oil line between Superior, Wisconsin and Sarnia, Ontario by 50,000 bpd, at a cost of approximately US$0.1 billion. Complementing the Line 5 expansion, Enbridge plans to reverse a portion of its Line 9 (Line 9A) in western Ontario to permit crude oil movements eastbound from Sarnia as far as Westover, Ontario at a cost of approximately $20 million. The Line 5 expansion is targeted to be in service during the first quarter of 2013 and, with NEB approval received in July 2012, the Line 9A reversal is expected to be in service in late 2013.

In May 2012, Enbridge announced that it had secured commercial support to proceed with additional Eastern Access projects. Enbridge and EEP also expect to proceed with supporting expansions of the United States mainline system between Flanagan, Illinois and Sarnia, Ontario. The additional Eastern Access projects include an 80,000 bpd expansion of Enbridge’s Toledo Pipeline (Line 17), which connects with the Enbridge mainline at Stockbridge, Michigan and serves refineries at Toledo, Ohio and Detroit, Michigan, and a reversal of Enbridge’s 240,000 bpd Line 9B from Westover, Ontario to Montreal, Quebec to serve refineries in Quebec. Sufficient capacity has been requested by refineries seeking to secure access to ample crude oil supplies from western Canada and the Bakken region in North Dakota to warrant proceeding with the project. The Eastern Access Line 9B reversal remains subject to NEB regulatory approval.

The Toledo Pipeline expansion is now expected to be available for service by the second quarter of 2013 at a cost of approximately US$0.2 billion. The Line 9B reversal is now expected to be available for service by mid-2014 at a cost of approximately $0.3 billion. Both the Toledo Pipeline and Line 9 assets are included in the Company’s Liquids Pipelines segment.

The supporting mainline expansions include expansion of the Spearhead North pipeline (Line 62) between Flanagan and Griffith, Indiana, an additional 330,000 barrel tank at Griffith and the replacement of additional sections of Line 6B in Indiana and Michigan not already scheduled for replacement as previously announced. The capacity of Spearhead North will increase by 105,000 bpd and the capacity of Line 6B will increase by 260,000 bpd. The expected cost of the mainline expansions is US$2.2 billion, including the US$0.1 billion cost of the previously announced Line 5 expansion, with expenditures to date of approximately US$0.2 billion. In addition, the supporting mainline expansions will be funded 60% by Enbridge and 40% by EEP, with EEP having the option to reduce its funding and associated economic interest in the projects by up to 15% before the end of 2012. Furthermore, within one year of the in-service date, scheduled for early 2014, EEP will also have the option to increase its economic interest held at that time by up to 15%.

Lakehead System Mainline Expansion

In May 2012, EEP announced 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. The current scope of the projects includes expansion of the Alberta Clipper line between the border and Superior, Wisconsin from 450,000 bpd to 570,000 bpd, and expansion of the Southern Access line between Superior and Flanagan, Illinois from 400,000 bpd to 560,000 bpd. The projects require only the addition of pumping horsepower and crude oil tanks at existing sites with no pipeline construction. Alberta Clipper and Southern Access are both held in Enbridge Energy, Limited Partnership (EELP), which will be fully funded by EEP for the cost of the expansions. The scope of the expansions remains under discussion, which could lead to an upward revision to capacity and cost.

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Subject to finalization of scope and regulatory and shipper approvals, the expansions will be undertaken by EELP on a full cost-of-service basis, and are expected to be available for service in mid-2014 at an estimated cost of US$0.4 billion. The expansions are designed to accommodate increased throughput on the Lakehead System for deliveries to certain of Enbridge’s pipelines, as well as growth in Chicago area refinery requirements. These expansions are incremental to those undertaken as part of the Eastern Access expansion.

CORPORATE

Montana-Alberta Tie-Line

Montana-Alberta Tie-Line (MATL) is a 345-kilometre (215-mile) transmission line from Great Falls, Montana to Lethbridge, Alberta, designed to take advantage of the growing supply of electric power in Montana and buoyant power demand in Alberta. The total expected cost for both the first 300-MW phase of MATL and the expansion for an additional 300-MW has been increased to approximately US$0.4 billion, with expenditures to date of approximately US$0.3 billion. While the permits required for construction have been obtained, the Alberta Utility Commission’s approval in Canada is currently being updated to reflect a number of design modifications. Subject to this approval, the system’s north-bound capacity, which is fully contracted, is now expected to be in service in the second quarter of 2013, with the expansion expected to be completed by the end of 2014.

Neal Hot Springs Geothermal Project

The Company has partnered with U.S. Geothermal Inc. (U.S. Geothermal) to develop the 35-MW (22-MW, net) Neal Hot Springs Geothermal Project located in Malheur County, Oregon. U.S. Geothermal is constructing the plant and will operate the facility. Completion of the project has been extended to the end of 2012 and, once operational, the facility will deliver electricity to the Idaho Power grid under a 25-year PPA. Enbridge will invest up to approximately US$33 million for a 41% interest in the project.

GROWTH PROJECTS – OTHER PROJECTS UNDER DEVELOPMENT

The following projects are also currently under development by the Company, but have not yet met Enbridge’s criteria to be classified as commercially secured.

LIQUIDS PIPELINES

Woodland Pipeline Extension

In September 2012, Enbridge received approval from the Alberta Energy Resources Conservation Board to construct the Woodland Pipeline Extension Project. The project will extend the Woodland Pipeline south from Enbridge’s Cheecham Terminal to its Edmonton Terminal. The extension is a proposed 385-kilometre (228-mile), 36-inch diameter pipeline, requiring an investment of approximately $1.0 billion to $1.4 billion for an initial capacity of 400,000 bpd, expandable to 800,000 bpd. The estimated investment remains subject to finalization of scope and a definitive cost estimate. More than 95% of the proposed route of the Woodland Pipeline Extension follows existing Enbridge right-of-way and will generally follow the existing Waupisoo Pipeline. The project will also include new pump stations at the existing Roundhill Station location and at the Cheecham Terminal. All major environmental and regulatory approvals have been received, and subject to final commercial approval, Enbridge anticipates a 2015 in-service date. Project expenditures to date are approximately $0.1 billion and pre-development costs are being backstopped by shippers pending final commercial approval.

Northern Gateway Project

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

Northern Gateway submitted an application to the NEB in May 2010. The Joint Review Panel (JRP) established to review the proposed project, pursuant to the NEB Act and the Canadian Environmental Assessment Act, has a broad mandate to assess the potential environmental effects of the project and to determine if it is in the public interest. Following sessions with the public, including Aboriginal groups, and

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the provision of additional information by Northern Gateway, the JRP issued a Hearing Order in May 2011 outlining the procedures to be followed.

In August 2011, Northern Gateway filed commercial agreements with the NEB which provide for committed long-term service and capacity on both the proposed crude oil export and condensate import pipelines. Capacity has also been reserved for use by uncommitted shippers.

In the fall of 2011, Northern Gateway responded to written questions by intervenors and government participants.

In a Procedural Direction issued in December 2011, the JRP indicated community hearings would be scheduled so the Panel would hear all oral evidence from registered intervenors first, followed by oral statements from registered participants. Community hearings for oral evidence and statements took place between January and August 2012 in various communities. A written record of what was said each day in the community hearings is available on the Panel’s website. Intervenors responded to questions by Northern Gateway on July 6, 2012. Northern Gateway filed reply evidence to the evidence of the intervenors on July 20, 2012. The final hearings commenced on September 4, 2012 where Northern Gateway, intervenors, government participants and the JRP will question those who have presented oral or written evidence.

The final hearings and the remaining oral statements from interested parties who do not reside along the pipeline corridor or shipping routes are expected to be completed by April 2013. Based on this projected schedule, the JRP expects to issue its reports and findings on the proposed project by December 2013. Of the 45 Aboriginal groups eligible to participate as equity owners, 26 have signed up to do so. 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. Expenditures to date, which relate primarily to the regulatory process, are approximately $0.3 billion, of which approximately half is secured in funding from Western Canada producers and Pacific Rim refiners toward the costs of seeking the necessary regulatory approvals for the project. Given the many uncertainties surrounding the Northern Gateway Project, including final ownership structure, the potential financial impact of the project cannot be determined at this time.

On February 23, 2012, Transport Canada published its TERMPOL Review Process Report of the Northern Gateway Project’s proposed marine operations. Transport Canada has filed the results of the study with the federal JRP tasked with assessing the project. The study reviewed the marine operations associated with the Northern Gateway terminal and associated tanker traffic in Canadian waters. The review concluded that: “While there will always be residual risk in any project, after reviewing the proponent’s studies and taking into account the proponent’s commitments, no regulatory concerns have been identified for the vessels, vessel operations, the proposed routes, navigability, other waterway users and the marine terminal operations associated with vessels supporting the Northern Gateway Project.” The TERMPOL report was prepared and approved by Canadian government authorities including Transport Canada; Environment Canada; Fisheries and Oceans Canada; Canadian Coast Guard; and Pacific Pilotage Authority Canada. Further review of the Northern Gateway application by the JRP, as well as other agencies, is ongoing.

As noted above, Northern Gateway filed reply evidence with the JRP on July 20, 2012 which contained details of further enhancements in pipeline design and operations. These extra measures, estimated to cost an additional $400 million to $500 million, together with additional marine infrastructure, result in a total estimated project cost of approximately $6.6 billion. The enhancements include: increasing pipeline wall thickness of the oil pipeline; additional pipeline wall thickness for water crossings such as major tributaries to the Fraser, Skeena and Kitimat Rivers; increasing the number of remotely-operated isolation valves by 50% within British Columbia to protect high-value fish habitat; increasing frequency of in-line inspection surveys across the entire Northern Gateway pipeline system by a minimum of 50% over and above current standards; installing dual leak detection systems; and staffing pump stations in remote

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locations on a 24 hour / 7 day basis for on-site monitoring, heightened security and rapid response to abnormal conditions.

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

GAS PIPELINES, PROCESSING AND ENERGY SERVICES

Heidelberg Lateral Pipeline

In November 2012, Enbridge announced it will build, own and operate a crude oil pipeline in the Gulf of Mexico to connect the proposed Heidelberg development, operated by Anadarko Petroleum Corporation (Anadarko), to an existing third-party system. The Heidelberg lateral, which will be 20 inches in diameter and approximately 55 kilometres (34 miles) in length, will originate in Green Canyon Block 860, approximately 320 kilometres (200 miles) southwest of New Orleans and in an estimated 1,600 metres (5,300 feet) of water. Subject to finalization of definitive agreements and sanction of the development by Anadarko and its project co-owners, the lateral pipeline is expected to be operational by 2016.

Nexus Gas Transmission Project

In September 2012, Enbridge, DTE Energy and Spectra Energy Corp (Spectra) announced the execution of a Memorandum of Understanding to jointly develop the Nexus Gas Transmission (Nexus) system, a project that will move growing supplies of Ohio Utica shale gas to markets in the United States midwest, including Ohio and Michigan, and Ontario, Canada. The proposed Nexus project will originate in northeastern Ohio, include approximately 400 kilometres (250 miles) of large diameter pipe, and be capable of transporting one billion cubic feet per day of natural gas. The line will follow existing utility corridors to an interconnect in Michigan and utilize the existing Vector Pipeline system to reach the Ontario market. Upon completion, Spectra will become a 20% owner in Vector Pipeline, a joint venture between DTE Energy and Enbridge. An open season was launched October 15, 2012 and the targeted in-service date is late 2016, depending on final market demand and contract commitments.

FINANCIAL RESULTS

LIQUIDS PIPELINES

Canadian Mainline

Since July 1, 2011, Canadian Mainline earnings are governed by the CTS, with the exception of Lines 8 and 9 that remain under a cost of service model. Prior to that, Canadian Mainline tolls were governed by a series of agreements, the most significant being the Incentive Tolling Settlement applicable to the

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mainline system and the Terrace and Alberta Clipper agreements. CTS tolls are not adjusted for volumes or operating costs; therefore, variations in these drivers cause variability in earnings. Canadian Mainline revenues increased by 13% to $355 million for the three months ended September 30, 2012 compared with the same period of 2011. This increase was primarily due to increased volumes and a higher Canadian Mainline International Joint Tariff (IJT) Residual Benchmark Toll which, under the IJT, is impacted by changes in the Lakehead System Local Toll. Higher revenues were partially offset by higher operating and administrative costs, primarily due to higher employee related costs and higher leak repairs. Incremental oil sands crude production in Alberta and strong production growth out of the Bakken in North Dakota have bolstered supply to midwest markets and placed increased downward pressure on crude oil prices in this market. Enbridge believes this pressure will at least be partially reduced upon completion of its market access projects. This discounted crude oil, coupled with strong refining margins, is increasing demand in the midwest for Canadian and Bakken crude oil supply and driving increased long haul barrels on Canadian Mainline and EEP’s Lakehead System.

Supplemental information on Canadian Mainline adjusted earnings is as follows: