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 March 29, 2011

Commission file number 001-15254

ENBRIDGE INC.

(Exact name of Registrant as specified in its charter)

3000, 425 — 1st Street S.W.

Calgary, Alberta, Canada  T2P 3L8

(Address of principal executive offices and postal code)

(403) 231-3900

(Registrants telephone number, including area code)

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

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

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

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

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

N/A

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 AND TO BE PART THEREOF FROM THE DATE ON WHICH THIS REPORT IS FURNISHED, TO THE EXTENT NOT SUPERSEDED BY DOCUMENTS OR REPORTS SUBSEQUENTLY FILED OR FURNISHED.

The following document is being submitted herewith:

·      Annual Report for the year ended December 31, 2010.

SIGNATURES

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

2

LETTER TO SHAREHOLDERS

FINANCIAL HIGHLIGHTS

OPERATING HIGHLIGHTS

1        Enbridge System includes Canadian mainline deliveries in Western Canada and to the Lakehead System at the United States border, as well as Line 8 and Line 9 in Eastern Canada.

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

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

CORPORATE GOVERNANCE

MANAGEMENT’S DISCUSSION AND ANALYSIS

This Management’s Discussion and Analysis (MD&A) dated February 18, 2011 should be read in conjunction with the audited consolidated financial statements and notes thereto of Enbridge Inc. (Enbridge or the Company) for the year ended December 31, 2010, which are prepared in accordance with Canadian generally accepted accounting principles (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.

GAS DISTRIBUTION

Gas Distribution consists of the Company’s natural gas utility operations, the core of which is Enbridge Gas Distribution Inc. (EGD) which serves residential, commercial and industrial customers, primarily in central and eastern Ontario as well as northern New York State. This business segment also includes natural gas distribution activities in Quebec and New Brunswick.

GAS PIPELINES, PROCESSING AND ENERGY SERVICES

Gas Pipelines, Processing and Energy Services consists of investments in natural gas pipelines, processing and green energy projects, the Company’s commodity marketing businesses, and international activities.

Investments in natural gas pipelines include the Company’s interests in the United States portion of Alliance Pipeline (Alliance Pipeline US), Vector Pipeline and transmission and gathering pipelines in the Gulf of Mexico. Investments in processing includes the Company’s interest in Aux Sable, a natural gas fractionation and extraction business. The commodity marketing businesses manage the Company’s volume commitments on Alliance and Vector Pipelines, as well as perform commodity storage, transport and supply management services, as principal and agent.

SPONSORED INVESTMENTS

Sponsored Investments includes the Company’s 25.5% ownership interest in Enbridge Energy Partners, L.P. (EEP), Enbridge’s 66.7% investment in the United States segment of the Alberta Clipper Project through EEP and Enbridge Energy, L.P. (EELP) and an overall 72% economic interest in Enbridge Income Fund (EIF), held both directly and indirectly through Enbridge Income Fund Holdings Inc. (EIFH). Enbridge manages the day-to-day operations of, and develops and assesses opportunities for each of these investments, including both organic growth and acquisition opportunities.

EEP transports crude oil and other liquid hydrocarbons through common carrier and feeder pipelines and transports, gathers, processes and markets natural gas and NGLs. The primary operations of EIF include a crude oil and liquids pipeline and gathering system, a 50% interest in the Canadian portion of Alliance Pipeline (Alliance Pipeline Canada) and partial interests in several green energy investments.

CORPORATE

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

Performance Overview

EARNINGS APPLICABLE TO COMMON SHAREHOLDERS

Earnings applicable to common shareholders for the three months ended December 31, 2010 were $326 million, an increase of $26 million compared with $300 million for the fourth quarter of 2009. The increase was primarily attributable to higher Sponsored Investments earnings, including Alberta Clipper contributions and a dilution gain on reduced ownership in EEP, as well as increased unrealized foreign exchange and derivative gains in Corporate. Offsetting these increases were lower contributions from Liquids Pipelines due in part to the elimination of annual performance metrics under the 2010 interim toll agreement, lower contributions from Gas Distribution due to higher operating costs and additional remediation costs on the Line 6B and 6A crude oil releases as discussed below.

Additionally, 2010 results were impacted by the Line 6B and 6A crude oil releases. Earnings for the fourth quarter of 2010 and for the year ended December 31, 2010 reflected the Company’s share of EEP’s costs, before insurance recoveries and excluding fines and penalties, of $21 million and $103 million, respectively, related to these incidents. Lost revenue associated with downtime on both Line 6B and 6A of $3 million (net to Enbridge) further contributed to the year-over-year decrease in earnings. See Sponsored Investments – Enbridge Energy Partners – EEP Lakehead System Line 6B and 6A Crude Oil Releases.

Comparability of earnings applicable to common shareholders for the year ended December 31, 2010 with the prior year is impacted by the effect of unrealized derivative and intercompany foreign exchange gains and losses which totaled a gain of $59 million in 2010 compared with a gain of $305 million in 2009. Further, earnings for the year ended December 31, 2009 reflected gains on the disposition of investments, including OCENSA, of $354 million whereas no dispositions occurred in 2010.

Compared with 2008, earnings applicable to common shareholders for the year ended December 31, 2009 increased $234 million. Included in earnings for the year ended December 31, 2009 was a $329 million gain related to the sale of the Company’s investment in OCENSA and a $25 million gain related to the sale of NetThruPut (NTP). Earnings for the year ended December 31, 2008 included a gain of $556 million related to the sale of the Company’s investment in Compañía Logística de Hidrocarburos CLH, S.A. (CLH). The remaining variances primarily resulted from allowance for equity funds used during construction (AEDC) in Liquids Pipelines and Sponsored Investments, as well as a higher contribution from EEP, and movements in unrealized fair value gains and losses on derivative instruments and unrealized foreign exchange gains on the translation of foreign denominated intercompany loans.

Adjusted earnings were $984 million, or $2.66 per common share, for the year ended December 31, 2010, compared with $855 million, or $2.35 per common share, for the year ended December 31, 2009. The increase in adjusted earnings primarily reflected contributions from projects coming into service, including the Alberta Clipper Project, the Southern Lights Pipeline and the Sarnia Solar Project, as well as strong performance from the Company’s existing liquids and natural gas assets. The Company also realized improved adjusted earnings from Gas Distribution due to customer growth and favourable operating performance. Sponsored Investments further contributed to year-over-year increases in adjusted earnings, benefiting from EEP contributions and its expansions and acquisition completed in 2010.

Adjusted earnings for the year ended December 31, 2009 were $855 million, or $2.35 per common share, compared with $677 million, or $1.88 per common share, for the year ended December 31, 2008. The $178 million increase over 2008 was largely driven by higher adjusted earnings from Enbridge System and Southern Lights Pipeline, within Liquids Pipelines, including the impact of AEDC. Adjusted earnings in 2009 also include an increased contribution from EEP resulting from higher crude oil delivery volumes, tariff surcharges for recent expansions, and the Company’s increased ownership interest. Further positive contributions were realized by Enbridge Offshore Pipelines (Offshore) due to higher volumes and Energy Services due to higher volumes and the impact of realizing favourable storage and transportation margins.

CASH FLOWS

The Company’s strong operating results and the success of its growth projects resulted in cash provided by operating activities of $1,851 million for the year ended December 31, 2010. Operating cash flow, together with cash provided by financing activities, funded the Company’s ongoing growth initiatives in 2010, including capital expenditures of $2,357 million.

For the three months ended December 31, 2010, cash provided by operating and financing activities substantially funded investing activities of $746 million, which consisted primarily of capital expenditures. The decline in additions to property, plant and equipment in the fourth quarter of 2010 compared with the fourth quarter of 2009 reflected the completion of several substantial construction projects that were under development in 2009, including Alberta Clipper and Southern Lights Pipeline.

REVENUES

The Company generates revenue from two primary sources: commodity sales, and transportation and other services.

Commodity sales revenue of $11,990 million (2009 – $9,720 million) is earned through the Company’s natural gas distribution and energy marketing activities and is subject to fluctuations in commodity prices. While revenues generated by the natural gas distribution business vary with the price of natural gas, earnings are not affected due to the pass through nature of these costs. Similarly, the impact of commodity prices on revenues derived from the Company’s energy marketing activities do not directly impact earnings since commodity prices also affect input costs associated with such activities. The period-over-period variances in commodity sales are primarily driven by natural gas and crude oil commodity prices and similar trends were experienced in commodity costs over these periods.

Transportation and other services includes revenue derived from the Company’s liquids transportation and natural gas transmission services, renewable energy generation and related services. Contributing to the increase in transportation and other services revenue in 2010 are Alberta Clipper and Southern Lights Pipeline, which entered service in April 2010 and July 2010, respectively.

For the year ended December 31, 2010, transportation and other services revenue increased to $3,137 million compared with $2,746 million in 2009. Main contributors to this variance include increased contributions from Liquids Pipelines growth projects that entered service in 2010, including Alberta Clipper and Southern Lights Pipeline and full year contributions from the initial phase of the Sarnia Solar Project which entered service in December 2009 as well as the expansion which was completed in September 2010.

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”, “believ” and similar words suggesting future outcomes or statements regarding an outlook. Forward-looking information or statements included or incorporated by reference in this document include, but are not limited to, statements with respect to: expected earnings or adjusted earnings; expected earnings or adjusted earnings per share; expected costs related to projects under construction; expected in-service dates for projects under construction; expected capital expenditures; estimated future dividends; and expected costs related to leak remediation and potential insurance recoveries.

Although Enbridge believes that these forward-looking statements are reasonable based on the information available on the date such statements are made and processes used to prepare the information, such statements are not guarantees of future performance and readers are cautioned against placing undue reliance on forward-looking statements. By their nature, these statements involve a variety of assumptions, known and unknown risks and uncertainties and other factors, which may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Material assumptions include assumptions about: the expected supply and demand for crude oil, natural gas and natural gas liquids; prices of crude oil, natural gas and natural gas liquids; expected exchange rates; inflation; interest rates; the availability and price of labour and pipeline construction materials; operational reliability; customer project approvals; maintenance of support and regulatory approvals for the Company’s projects; anticipated in-service dates; and weather. Assumptions regarding the expected supply and demand of crude oil, natural gas and natural gas liquids, and the prices of these commodities, are material to and underlay all forward-looking statements. These factors are relevant to all forward-looking statements as they may impact current and future levels of demand for the Company’s services. Similarly, exchange rates, inflation and interest rates impact the economies and business environments in which the Company operates, may impact levels of demand for the Company’s services and cost of inputs, and are therefore inherent in all forward-looking statements. Due to the interdependencies and correlation of these macroeconomic factors, the impact of any one assumption on a forward-looking statement cannot be determined with certainty, particularly with respect to expected earnings or adjusted earnings and associated per share amounts, or estimated future dividends. The most relevant assumptions associated with forward-looking statements on projects under construction, including estimated in-service dates, and expected capital expenditures include: the availability and price of labour and pipeline construction materials; the effects of inflation and foreign exchange rates on labour and material costs; the effects of interest rates on borrowing costs; and the impact of weather and customer and regulatory approvals on construction schedules.

Enbridge’s forward-looking statements are subject to risks and uncertainties pertaining to operating performance, regulatory parameters, project approval and support, weather, economic and competitive conditions, exchange rates, interest rates, commodity prices and supply and demand for commodities, including but not limited to those risks and uncertainties discussed in this MD&A and in the Company’s other filings with Canadian and United States securities regulators. The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these are interdependent and Enbridge’s future course of action depends on management’s assessment of all information available at the relevant time. Except to the extent required by law, Enbridge assumes no obligation to publicly update or revise any forward-looking statements made in this MD&A or otherwise, whether as a result of new information, future events or otherwise. All subsequent forward looking statements, whether written or oral, attributable to Enbridge or persons acting on the Company’s behalf, are expressly qualified in their entirety by these cautionary statements.

NON-GAAP MEASURES

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

Corporate Vision and Key Objective

Enbridge’s vision is to be the leading energy delivery company in North America. While the Company may be viewed as having achieved elements of this vision, enhancing and sustaining this position remains a continuing long-term pursuit. The Company’s objective is to generate superior economic value for shareholders through investing capital in energy infrastructure businesses which generate reliable earnings and cash flow. Consistently applied, such stewardship should continue to generate attractive returns on invested capital and, in turn, provide for consistent and growing dividend distributions and related capital appreciation to its shareholders.

Corporate Strategy

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

·     focusing on project execution and operating excellence;

·     leveraging the strategic location of its existing asset base;

·     developing new platforms for growth and diversification;

·     maintaining financial strength and flexibility; and

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

Enbridge’s strategy is reviewed annually with direction from its Board of Directors. The Company continually assesses ways to generate value for shareholders, including reviewing opportunities that may lead to acquisitions, dispositions or other strategic transactions, some of which may be material. Opportunities are screened, analyzed and must meet operating, strategic and financial criteria before being pursued.

FOCUSING ON PROJECT EXECUTION AND OPERATIONS

Effective management of operations and project execution is the foundation of Enbridge’s strategic plan. Operational excellence is particularly critical in an environment where customers have become increasingly cost conscious, competition in the Company’s core business has intensified and environmental stewardship has heightened.

Successful execution of the existing slate of commercially secured projects is a significant driver of Enbridge’s near-term earnings and cash flow growth, and, therefore, a strategic priority. Project execution is a core competency at Enbridge and the Company continues to build upon its project management skills and processes, primarily through the Major Projects support team which was established in early 2008. Major Projects manages projects above $50 million for all liquids, natural gas and renewable projects and continues to deliver projects on time and on budget. Major Projects focuses on success factors such as cost estimation, regulatory permitting, material and labour sourcing and project governance. All Major Projects are governed through a formal, disciplined stage gating process which requires the completion of

pre-defined project deliverables, such as project execution and risk management plans, prior to management approving projects to proceed through predefined stage gates within the project lifecycle. This competency is highly valued and represents another Enbridge strength when competing for new business.

With respect to safety and system integrity, Enbridge employs the best available practices and technologies for integrity management, systems maintenance and operations in order to mitigate risks to the public, our employees and the environment.

STRENGTHENING OUR CORE BUSINESS

The Company has an established history of serving the North American transportation needs of key crude oil and natural gas markets. The Company is focused on adding value for customers and improving customers’ profitability. This focus has aligned the Company with its customers and relevant supply and demand fundamentals and has consistently formed a basis for the Company’s strategy. However, evolving supply and demand fundamentals and growing competition are serving to create new opportunities and challenges within the Company’s core businesses. Amid this changing business environment, the Company is strengthening its core business position and aggressively pursuing new opportunities to expand and extend its current asset base.

Extending the reach of the current asset base is a multi-faceted objective. Key strategies within the Liquids Pipelines segment include regional pipeline development, gathering system and storage infrastructure expansion and new market access. Regional pipeline development primarily includes projects which connect new oil sands lease production to existing hubs upstream of the Canadian mainline. Enbridge’s planned investment of $2.6 billion in commercially secured regional oil sands transportation facilities that are expected to go into service between 2011 and 2014 continue to advance this objective. The Company is also expanding its gathering systems in Saskatchewan and North Dakota which are strategically located to capture increased production from the Bakken play. As transportation needs grow so too do terminal and storage infrastructure requirements throughout the network, and the Company’s strategy is to seek opportunities to provide additional capacity in the Fort McMurray and Hardisty, Alberta regions as well as in the Cushing, Oklahoma area. The Company continues to pursue opportunities to provide its customers broader market access for Canadian bitumen and synthetic crudes and provide new sources of supply for refiners. These efforts include leveraging existing pipeline networks into additional United States markets as well as developing the proposed Northern Gateway pipeline to provide access to markets off the Pacific Coast of Canada.

The fundamentals of the natural gas market in North America have been altered significantly in recent years with the emergence of unconventional shale gas plays. The Company’s natural gas strategy includes expanding its footprint in these emerging areas. Alliance Pipeline is well positioned to service the Montney play in northeast British Columbia and the Bakken play, and is currently evaluating opportunities to expand its service offerings in that area. In addition to these onshore strategies, the Company continues to pursue and win natural gas gathering expansion opportunities for ultra-deep projects in the Gulf of Mexico which improve the risk and return profile of its investment in this area.

DEVELOPING NEW PLATFORMS FOR GROWTH AND DIVERSIFICATION

The development of new platforms to diversify and sustain long-term growth is an important strategy for Enbridge. Renewable energy is a significant source of potential new growth as government initiatives and changing social beliefs are creating new opportunities to deliver green energy solutions with risk and return characteristics consistent with Enbridge’s business model. Renewable energy projects can deliver stable cash flows and attractive returns through the use of long-term power purchase agreements and fixed price engineering, procurement and construction contracts. Renewable energy is also an important part of Enbridge’s corporate social responsibility strategies, particularly with respect to greenhouse gas emissions (GHG) and the environment. Business development efforts in renewable energy are focused primarily on clean power projects, including wind, solar, waste heat recovery, fuel cell, geothermal and natural gas fired generation initiatives.

Similar to renewable energy, carbon dioxide (CO2) capture and sequestration not only supports Enbridge’s social investment strategy but also represents a potentially significant investment opportunity, should the technology prove viable.

The Company’s Alternative and Emerging Technologies group is exploring other longer-term energy technologies to sustain the Company’s favourable position. In addition, the International group is actively seeking new opportunities outside of North America.

PRESERVING FINANCIAL STRENGTH AND FLEXIBILITY

Disciplined capital management is a fundamental and company differentiating characteristic. As an asset-intensive business, Enbridge creates value for its investors through maximizing the spread between its return on invested capital and its cost of funds. Enbridge’s financial strategies are designed to ensure the Company has sufficient liquidity to meet its capital requirements. To support this objective, the Company develops financing plans and strategies to maintain and improve Enbridge’s credit ratings, diversify its funding sources and maintain ready access to capital markets in both Canada and the United States.

A key tenet of the Company’s reliable business model is mitigation of exposure to market price risks. As a result, the Company has developed a robust risk management process which ensures earnings volatility from market price risk remains contained. Enbridge will continue to proactively hedge interest rate, foreign exchange and commodity price exposures. As well, the continued management of counterparty credit risk remains an ongoing priority.

DEVELOPING PEOPLE

Strong employees and leaders are the foundation of any successful company and developing its people remains a strategic priority for Enbridge. Key priorities related to building and improving Enbridge’s organizational and workforce capabilities and Human Resource services include:

·     strengthening the leadership culture;

·     enabling and accelerating career development for leaders and employees;

·     developing capability and capacity for effective change management;

·     reinforcing a values-based organization; and

·     ensuring human resource systems can provide strategic information for decision making.

RESPONDING TO ENVIRONMENTAL PRIORITIES

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

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

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

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

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

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

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

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

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

World crude oil demand was approximately 2 million bpd higher in 2010 relative to 2009, with China as the major contributor of demand growth. North American demand growth remains relatively flat and is projected to remain that way into the near future. The continued growth of biofuels further suppresses United States crude requirements. Canadian crude imports into the United States Midwest are growing while United States overall crude imports from other countries has declined relative to past years. Midwest refinery runs and margins are showing stability versus other markets. Planned reconfiguration of refineries in the Midwest will increase the demand for Canadian crude into one of Enbridge’s key markets.

With the expected increase in heavy oil production in western Canada, there is an increasing requirement for condensate (or similar light commodity) to be used as a blending agent in order to transport these high viscosity volumes to market. Condensate is a light hydrocarbon which is conventionally a bi-product of natural gas production or NGLs fractionation. Production of this commodity is decreasing in western Canada but, with the increasing demand for diluents from heavy oil producers, there has been an increasing need to import. Currently, volumes are transported via rail to Alberta from the United States as well as from international sources via tankers and rail from the West Coast. Also in mid-2010, Enbridge’s Southern Lights condensate pipeline began importing incremental volumes of condensate from the United States to Alberta to meet producer’s needs.

Regional production growth patterns have also impacted long-haul infrastructure. For example, rapid growth in production from the Marcellus shale play has contributed to sharply displace imports of Canadian gas into the northeast United States and has even spurred proposals to export gas into eastern Canada.

Weather extremes in both winter and summer seasons helped to propel North American natural gas demand in 2010. Gas demand was further supported by the recovering industrial sector following the recent economic recession, and an increased amount of gas for coal substitution in power generation as gas prices were comparatively weak. Although economic recovery was slowing in the second half of 2010, growth is expected to continue at a modest pace into 2011. Overall, natural gas demand should experience moderate growth over the next several years.

As growth in unconventional gas supply continues to outpace growth in demand, North America is expected to remain in a relatively low gas price environment. Moreover, gas prices will continue to experience downward pressure until gas drilling is reduced sufficiently to temper production growth. Oil prices, in contrast, are expected to increase; consequently, the wide disparity between gas and oil prices should continue to support strong gas processing and fractionation spreads.

SUPPLY AND DEMAND FOR GREEN ENERGY

While traditional forms of energy are expected to represent the major source of North American energy supply for years to come, a grass roots shift to a lower carbon intensive economy has commenced. As overall North American energy needs continue to grow, particularly the need for electricity to meet commercial and residential demand, opportunities arise for renewable energy projects driven by reduced reliance on carbon-intensive fuels and heightened environmental awareness. Renewable energy, including wind, solar and geothermal, is attractively positioned to capture a significant portion of incremental and replacement generation capacity over the next 25 years.

Electricity demand growth is expected to average approximately 1% to 2% annually to 2035. The Energy Information Administration (EIA) forecasts that United States generation capacity will increase by 220,000 megawatts (MW) or over 20% from 2010 to 2035, with the vast majority of new generation coming from gas-fired generation and renewable energy sources. According to the NEB, average Canadian electricity demand is expected to grow by 1% per year over the next ten years. Growth in nuclear and coal-fired generation is expected to be limited due to permitting challenges, long lead times and uncertainty of environmental regulations, leaving opportunity for incremental demand to be met by renewable sources and natural gas.

Expanding renewable energy infrastructure in North America is not without challenges. Projects are typically highly capital intensive and renewable technology is in early stages relative to mature energy sources. Further, renewable projects must balance the benefit of reduced carbon emissions with land disturbances and projects aesthetics. High quality wind and solar resources may often be found in regions at long distances from high demand markets, introducing the need for new transmission capacity to move the increasing supply of renewable power to markets. Renewable generation results in greater load variability, creating further opportunities for gas-fired generating capacity to support system reliability. Natural gas is abundant and low cost and will form a growing part of the generation supply mix in North America.

Many factors will impact the pace of future development in renewable energy, including, but not limited to, the pace of economic recovery, technological advances, future energy or climate change regulations and continued government support. The forecasted increase in power generation arising from renewable sources is in part supported by government incentives. The continuing ability to obtain tax or other government incentives, and the ability to secure long-term power purchase agreements through government or investor-owned power authorities is required to support project economics based on current costs and technologies. What is clear is that a mix of alternative energy sources will play an increasingly important role in the North American energy space for years to come and there will be a continued drive to develop and promote green energy.

Growth Projects

Over the last three years Enbridge has placed into service over $12 billion in growth projects. In 2010 alone, Enbridge placed into service $6.5 billion of growth projects, including the $3.5 billion Alberta Clipper project, the largest liquids pipeline project in the Company’s history, as well as the $2.3 billion Southern Lights Pipeline. Enbridge has also secured over $6 billion in new infrastructure growth projects in strategically significant areas including the Canadian Oil Sands and Bakken formation, mid-west Texas and Louisiana shale gas plays and offshore natural gas and oil, as well as wind, solar and other renewable projects. In addition, the Company has a further $30 billion in growth opportunities under development, but not yet commercially secured, for the post-2011 period, of which it expects to be successful on a significant portion.

The table below summarizes the current status of the Company’s commercially secured projects, separated into the Company’s business segments. These growth projects are expected to help Enbridge sustain its anticipated average annual earnings per share growth rate of 10% through the middle of this decade.

1     These amounts are estimates only and subject to upward or downward adjustment based on various factors.

Risks related to the development and completion of growth projects are described under

Risk Management and Financial Instruments.

LIQUIDS PIPELINES

Alberta Clipper Project

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

The cost of the project was $2.2 billion and US$1.2 billion, including allowance for funds used during construction (AFUDC), for the Canadian and United States segments, respectively. Enbridge funded 66.7% of the United States segment of the Alberta Clipper project through EELP.

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

Interim tolls for the Enbridge mainline, including recovery of costs related to the Canadian segment of Alberta Clipper, went into effect April 1, 2010 and, as directed by the NEB, reflected the forecasted Alberta Clipper toll presented in 2007. A NEB hearing was originally scheduled for November 2010 which would have considered Enbridge’s final toll application, including Alberta Clipper at the full revenue requirement based on it being used and useful, as well as remaining aspects of the February 2010 filing made by certain shippers. However, at the joint request of the primary intervenors and the Company, the NEB hearing has been suspended. The Company and the intervenors are currently in discussions that could, if successful, narrow the existing issues, minimize the scope of or eliminate the need for the hearing. The Company continues to believe the shippers’ Alberta Clipper filings to be without merit.

Southern Lights Pipeline

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

The total cost of the project was US$1.6 billion for the United States segment and $0.5 billion for the Canadian segment. Remaining costs primarily relate to right-of-way restoration and final work on the Line 13 facilities.

Both the Canadian and United States portion of the tariff for uncommitted shippers on the Southern Lights Pipeline has been challenged. Accordingly, a FERC hearing process has been initiated. The NEB has yet to confirm the process, if any, to be followed regarding the Canadian tariff challenge. No material financial impacts to the Company are anticipated.

Christina Lake Lateral Project

The Christina Lake Lateral Project includes a new pipeline terminal and blended products pipeline, which will allow the Cenovus and ConocoPhillips partnership to deliver increased Christina Lake production volumes directly into the Athabasca Pipeline. The expansion project will add two 375,000 barrel tanks and 26 kilometres (16 miles) of 30-inch diameter pipeline to the existing Christina Lake lateral and terminal facilities, which include two eight-inch lateral lines plus 240,000 barrels of tankage, that connect to the Athabasca Pipeline. The estimated cost of the additional facilities is approximately $0.3 billion, with expenditures to date of $0.1 billion. The facilities are expected to be in service in the third quarter of 2011.

Woodland Pipeline

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

Edmonton Terminal Expansion

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

Wood Buffalo Pipeline

Enbridge entered into an agreement with Suncor Energy Inc. to construct a new, 95-kilometre (59-mile) 30-inch diameter crude oil pipeline, connecting the Athabasca Terminal, which is adjacent to Suncor’s oil sands plant, to the Cheecham Terminal, which is the origin point of Enbridge’s Waupisoo Pipeline. The Waupisoo Pipeline already delivers crude oil from several oil sands projects to the Edmonton mainline hub. The new Wood Buffalo pipeline will parallel the existing Athabasca Pipeline between the Athabasca and Cheecham Terminals. The estimated capital cost is approximately $0.4 billion and, pending regulatory approval, the new pipeline is expected to be in service by mid-2013.

Norealis Pipeline

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

Waupisoo Pipeline Expansion

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

Athabasca Pipeline Capacity Expansion

The Company will undertake an expansion of its Athabasca Pipeline to its full capacity to accommodate additional contractual commitments including recent incremental shipping commitments by the Christina Lake Oilsands Project operated by Cenovus. This expansion will increase the capacity of the Athabasca Pipeline to its maximum capacity of approximately 570,000 bpd, depending on crude slate. The estimated cost of this full expansion is approximately $0.4 billion with an expected in service date of 2013 for an initial 430,000 bpd of capacity with the balance of the capacity expected to be available by early 2014, subject to regulatory approval. The Athabasca Pipeline transports crude oil from various oil sands projects to the mainline hub at Hardisty, Alberta.

Fort Hills Pipeline System

In November 2007, Enbridge was selected by Fort Hills Energy L.P. (FHELP) as its pipeline and terminaling services provider for the initial phase of the Fort Hills project and all subsequent expansions. In late 2008, FHELP announced that its final investment decision for the mining portion of the project was being deferred until costs could be reduced, and commodity prices and financial markets strengthened. It also announced that the Fort Hills upgrader was put on hold and that a decision to proceed with the upgrader would be made at a later date. Accordingly, the scope of the Fort Hills Pipeline System is being reevaluated by FHELP and the planned in-service date for the project has been deferred beyond the original planned date of mid-2011. FHELP has until June 2011 to give notice to proceed. Expenditures to date are approximately $0.1 billion and are commercially recoverable from FHELP.

Northern Gateway Project

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

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

Subject to continued commercial support, regulatory and other approvals, and adequately addressing landowner, Aboriginal and local community concerns, the Company estimates that Northern Gateway could be in-service by late 2016 at the earliest, at an estimated cost of $5.5 billion. Expenditures to date, which relate primarily to the regulatory process, are approximately $0.2 billion, including $0.1 billion

in funding secured from Western Canada producers and Pacific Rim refiners toward the costs of seeking the necessary regulatory approvals for the project. Given the many uncertainties surrounding the Northern Gateway Project, including final ownership structure, the potential financial impact of the project cannot be determined at this time.

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

GAS PIPELINES, PROCESSING AND ENERGY SERVICES

Sarnia Solar Project

The Company developed the 80-MW Sarnia Solar Project with First Solar, Inc. (First Solar). The initial 20-MW facility attained commercial operation in December 2009 and the 60-MW expansion was completed three months ahead of schedule in early September 2010. Power output of the facility is sold to the Ontario Power Authority (OPA) under a 20-year power purchase agreement. The final capital cost of both facilities was approximately $0.4 billion.

Talbot Wind Energy Project

Enbridge developed the 99-MW Talbot Wind Energy Project near Chatham, Ontario with Renewable Energy Systems Canada Inc. (RES Canada). The project was completed in December 2010. Enbridge has a 90% interest in the project and an option to acquire the remaining 10% interest. The project utilizes 43 Siemens 2.3-MW wind turbines and, under a multi-year fixed price agreement, Siemens is providing operations and maintenance services for the wind turbines. The Talbot Wind Energy Project power output is sold to the OPA under a 20-year power purchase agreement. The final capital cost of the project was approximately $0.3 billion.

Greenwich Wind Energy Project

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

Cedar Point Wind Energy Project

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

Neal Hot Springs Geothermal Project

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

Amherstburg and Tilbury Solar Projects

The Company entered into agreements to acquire two new solar energy projects totaling 20 MW generating capacity from First Solar for $0.1 billion. The 5-MW Tilbury Solar Project, completed in December 2010, is located in Tilbury, Ontario. The Amherstburg II Solar Project, located in Amherstburg, Ontario, consists of two separate projects of 10 MW and 5 MW each. First Solar constructed (and, in the case of the Amherstburg II Solar Project, will construct) the projects for Enbridge under fixed price engineering, procurement and construction contracts. Construction is expected to begin in March 2011 and is expected to be complete in the third quarter of 2011. Enbridge will sell the facilities’ power output to the Ontario Power Authority pursuant to 20-year power purchase agreements under the terms of the Ontario Government’s Renewable Energy Standard Offer Program.

Venice Gas Processing Facility

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

Walker Ridge Gas Gathering System

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

Big Foot Oil Pipeline

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

SPONSORED INVESTMENTS

Bakken Expansion Program

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

Enbridge Income Fund

Saskatchewan System Capacity Expansion

Phase II of the Saskatchewan System Capacity Expansion included three separate projects that served to reduce capacity constraints at a variety of locations. Collectively, the projects increased capacity across the system by approximately 125,000 bpd. Construction was substantially completed in December 2010. The final capital cost of the projects was approximately $0.1 billion.

CORPORATE

Project Pioneer

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

Liquids Pipelines

EARNINGS