EX-99.7 8 a12-4695_1ex99d7.htm EX-99.7 MD&A OF THE REGISTRANT FOR THE YEAR ENDED DECEMBER 31, 2011 DATED FEBRUARY 21, 2012.

Exhibit 99.7

ENBRIDGE INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS

December 31, 2011

MANAGEMENT’S DISCUSSION AND ANALYSIS

This Management’s Discussion and Analysis (MD&A) dated February 21, 2012 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, 2011, prepared in accordance with Part V – Pre-changeover Accounting Standards of the Canadian Institute of Chartered Accountants (CICA) Handbook (Canadian GAAP or Part V). 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.

OVERVIEW

Enbridge is a North American leader in delivering energy. 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 significant involvement in the natural gas transmission and midstream businesses. 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 clean energy generator, Enbridge is expanding its interests in renewable and green energy technologies, including wind, solar and geothermal energy, as well as hybrid fuel cells. Enbridge employs approximately 6,900 people, primarily in Canada and the United States.

The Company’s activities are carried out through five business segments: Liquids Pipelines, Gas Distribution, Gas Pipelines, Processing and Energy Services, Sponsored Investments and Corporate, as discussed below.

LIQUIDS PIPELINES

Liquids Pipelines consists of common carrier and contract crude oil, natural gas liquids (NGL) and refined products pipelines and terminals in Canada and the United States, including Canadian Mainline, Regional Oil Sands System, Southern Lights Pipeline, Spearhead Pipeline, Seaway Crude Pipeline (Seaway Pipeline) interest and other feeder pipelines.

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 and processing facilities, green energy projects, Canadian midstream businesses, the Company’s energy services 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), the Vector Pipeline and transmission and gathering pipelines in the Gulf of Mexico. Investments in natural gas processing include the Company’s interest in Aux Sable, a natural gas fractionation and extraction business and an interest in the development of Cabin Gas Plant (Cabin) in northeastern British Columbia, and processing facilities connected to the Gulf of Mexico system. The energy services businesses manage the Company’s volume commitments on Alliance and Vector Pipelines, as well as perform natural gas, NGL and crude oil storage, transport and supply management services, as principal and agent.

SPONSORED INVESTMENTS

Sponsored Investments includes the Company’s 23.0% 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, Limited Partnership (EELP) and an overall 69.2% economic interest in Enbridge Income Fund (the Fund), held both directly, and indirectly through Enbridge Income Fund

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Holdings Inc. (ENF). 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 the Fund include a crude oil and liquids pipeline and gathering system, a 50% interest in the Canadian portion of Alliance Pipeline (Alliance Pipeline Canada) and interests in renewable power generation projects.

CORPORATE

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

PERFORMANCE OVERVIEW

|  | Three Months Ended |  | Year Ended |
|  | December 31, |  | December 31, |
|  | 2011 |  |  | 2010 |  | 2011 |  |  | 2010 |  | 2009 |
(millions of Canadian dollars, except per share amounts) |  |  |  |  |  |  |  |  |  |  |  |  |
Earnings attributable to common shareholders |  |  |  |  |  |  |  |  |  |  |  |  |
Liquids Pipelines |  | 203 |  |  | 117 |  | 505 |  |  | 512 |  | 445 |
Gas Distribution |  | 34 |  |  | 60 |  | 176 |  |  | 155 |  | 186 |
Gas Pipelines, Processing and Energy Services |  | 157 |  |  | 32 |  | 293 |  |  | 121 |  | 428 |
Sponsored Investments |  | 159 |  |  | 56 |  | 344 |  |  | 137 |  | 141 |
Corporate |  | (218 | ) |  | 61 |  | (327 | ) |  | 38 |  | 355 |
|  | 335 |  |  | 326 |  | 991 |  |  | 963 |  | 1,555 |
Earnings per common share 1 |  | 0.44 |  |  | 0.44 |  | 1.32 |  |  | 1.30 |  | 2.14 |
Diluted earnings per common share 1 |  | 0.44 |  |  | 0.43 |  | 1.30 |  |  | 1.29 |  | 2.12 |
Adjusted earnings 2 |  |  |  |  |  |  |  |  |  |  |  |  |
Liquids Pipelines |  | 126 |  |  | 117 |  | 536 |  |  | 512 |  | 454 |
Gas Distribution |  | 46 |  |  | 54 |  | 175 |  |  | 167 |  | 154 |
Gas Pipelines, Processing and Energy Services |  | 41 |  |  | 31 |  | 163 |  |  | 123 |  | 116 |
Sponsored Investments |  | 78 |  |  | 48 |  | 253 |  |  | 209 |  | 151 |
Corporate |  | (16 | ) |  | (12) |  | (17 | ) |  | (27 | ) | (20 | )
|  | 275 |  |  | 238 |  | 1,110 |  |  | 984 |  | 855 |
Adjusted earnings per common share 1,2 |  | 0.37 |  |  | 0.32 |  | 1.48 |  |  | 1.33 |  | 1.17 |
Cash flow data |  |  |  |  |  |  |  |  |  |  |  |  |
Cash provided by operating activities |  | 452 |  |  | 375 |  | 2,703 |  |  | 1,851 |  | 2,017 |
Cash used in investing activities |  | (2,179 | ) |  | (746) |  | (4,017 | ) |  | (2,674 | ) | (3,306 | )
Cash provided by financing activities |  | 1,221 |  |  | 60 |  | 1,380 |  |  | 766 |  | 1,082 |
Dividends |  |  |  |  |  |  |  |  |  |  |  |  |
Common share dividends declared |  | 190 |  |  | 163 |  | 759 |  |  | 648 |  | 555 |
Dividends paid per common share 1 |  | 0.2450 |  |  | 0.2125 |  | 0.98 |  |  | 0.85 |  | 0.74 |
Revenues |  |  |  |  |  |  |  |  |  |  |  |  |
Commodity sales |  | 4,132 |  |  | 3,280 |  | 15,676 |  |  | 11,990 |  | 9,720 |
Transportation and other services |  | 1,304 |  |  | 863 |  | 3,726 |  |  | 3,137 |  | 2,746 |
|  | 5,436 |  |  | 4,143 |  | 19,402 |  |  | 15,127 |  | 12,466 |
Total assets |  | 34,343 |  |  | 30,220 |  | 34,343 |  |  | 30,220 |  | 28,169 |
Total long-term liabilities |  | 19,796 |  |  | 18,542 |  | 19,796 |  |  | 18,542 |  | 16,392 |

1 Comparative amounts were restated to reflect two-for-one stock split which was effective May 25, 2011.

2 Adjusted earnings and adjusted earnings per common share are non-GAAP measures that do not have any standardized meaning prescribed by generally accepted accounting principles. For more information on non-GAAP measures see pages 8 and 76.

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EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS

Earnings attributable to common shareholders were $991 million, or $1.32 per common share, for the year ended December 31, 2011, compared with $963 million, or $1.30 per common share, for the year ended December 31, 2010. Earnings for 2011 reflected strong earnings growth from substantially all of the Company’s business segments and also included the effect of non-cash, unrealized fair value derivative and foreign exchange gains and losses. Earnings for 2011 were also negatively impacted by non-recurring income taxes of $98 million incurred on an intercompany gain on sale to the Fund, not eliminated for accounting purposes.

Significant contributors to increased earnings included, within Liquids Pipelines, the Regional Oil Sands System which realized an increase in earnings in 2011 relative to prior year due to higher shipped volumes, increased tolls, the continued positive impact of terminal infrastructure additions and lower depreciation expense. Similarly, the Canadian Mainline delivered year-over-year growth on increasing volumes and favourable operating performance. Effective July 1, 2011, tolls on the mainline system are governed by the Competitive Toll Settlement (CTS), under which earnings are now subject to variability associated with throughput volume and capital and operating costs, subject to various protection mechanisms.

Within the Gas Pipelines, Processing and Energy Services segment, Energy Services benefited from favourable market conditions, as did Aux Sable which realized stronger fractionation margins compared with prior years. Also within this segment, earnings contributions were realized from newly sanctioned renewable energy projects including the Sarnia Solar and Talbot Wind projects, later transferred to the Fund, within Sponsored Investments, in the fourth quarter of the year, and the Cedar Point and Greenwich wind projects.

EEP earnings, within Sponsored Investments, increased for the year ended December 31, 2011, largely due to higher volumes both within EEP’s liquids business and its natural gas business, which was bolstered by the addition of the Elk City Gathering and Processing System (Elk City System) acquired in September 2010, and higher incentive income.

Offsetting these increases in earnings were lower contributions from Southern Lights Pipeline and Spearhead Pipeline, which is experiencing lower volumes due to market pricing dynamics at Cushing, Oklahoma, and higher Corporate costs. Enbridge Offshore Pipelines (Offshore) earnings declined $30 million in 2011 relative to the prior year due to a slower regulatory permitting process and delayed drilling programs by producers in the Gulf of Mexico.

Earnings attributable to common shareholders were $963 million, or $1.30 per common share, for the year ended December 31, 2010, compared with $1,555 million, or $2.14 per common share, for the year ended December 31, 2009. The Company’s earnings for 2010 included the positive impacts of projects coming into service in 2010, including Alberta Clipper, Southern Lights Pipeline and the Sarnia Solar Project. Compared with 2009, earnings have increased further due to customer growth in Gas Distribution and improved contributions from green energy, partially offset by less favourable weather conditions in the Company’s gas distribution franchise areas. In 2009, significant one-time favourable items impacted earnings, including a $329 million gain on the disposal of Oleoducto Central S.A. (OCENSA) and unrealized derivative and intercompany foreign exchange gains.

Additionally, 2011 and 2010 results were impacted by the 2010 Line 6A and 6B crude oil releases. Earnings for the year ended December 31, 2011 and 2010 included the Company’s share of EEP’s costs, before insurance recoveries and excluding fines and penalties, of $33 million and $103 million, respectively, related to these incidents. Lost revenue associated with downtime on both Line 6A and 6B of $3 million (net to Enbridge) further contributed to the decrease in earnings in 2010 compared with 2009. Earnings for the year ended December 31, 2011 included insurance recoveries of $50 million (net to Enbridge) related to the Line 6B crude oil release. See Sponsored Investments – Enbridge Energy Partners – EEP Lakehead System Line 6A and 6B Crude Oil Releases.

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Comparability of earnings attributable to common shareholders for the year ended December 31, 2011 with the prior years is impacted by the effect of unrealized derivative and intercompany foreign exchange gains and losses which totaled a loss of $132 million in 2011, a gain of $59 million in 2010 and 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 or 2011.

Earnings attributable to common shareholders for the three months ended December 31, 2011 were $335 million compared with $326 million for the fourth quarter of 2010. Fourth quarter earnings drivers are largely consistent with year-to-date trends and continued to include non-cash, unrealized fair value derivative and foreign exchange gains and losses. Unique to the fourth quarter of 2011 are reduced earnings from Gas Distribution due to warmer than normal weather, leak insurance recoveries of $29 million (net to Enbridge) and $98 million of income taxes on the intercompany gain on sale to the Fund not eliminated for accounting purposes.

ADJUSTED EARNINGS

Adjusted earnings for the year ended December 31, 2011 were $1,110 million, or $1.48 per common share, compared with $984 million, or $1.33 per common share, for the year ended December 31, 2010, an increase of 11% in adjusted earnings per common share. Adjusted earnings, which excludes the impact of non-recurring or non-operating items, for the year ended December 31, 2011 surpassed $1.0 billion for the first time in the Company’s history, with higher contributions from substantially all of the Company’s business segments driving strong overall earnings growth in the year. Significant drivers of the increase in adjusted earnings included increased volumes on the Company’s liquids pipelines assets both in Canada and the United States, supported by robust activity in the oil sands region of Alberta, favourable fractionation margins and market conditions benefiting the Aux Sable and Energy Services businesses and increased contributions from a growing portfolio of renewable power generation assets. Areas of the Company’s operations which realized year-over-year declines in adjusted earnings included Offshore, due to a slower regulatory permitting process and delayed drilling programs by producers in the Gulf of Mexico, and Spearhead Pipeline, which experienced lower volumes due to market pricing dynamics at Cushing, Oklahoma.

Adjusted earnings were $984 million, or $1.33 per common share, for the year ended December 31, 2010, compared with $855 million, or $1.17 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 higher contributions from EEP as a result of expansions and the acquisition of the Elk City System completed in 2010.

Adjusted earnings were $275 million, or $0.37 per common share, for the three months ended December 31, 2011, compared with $238 million, or $0.32 per common share, for the three months ended December 31, 2010. Positive contributors to increased adjusted earnings in the quarter included Gas Pipelines, Processing and Energy Services, whose Aux Sable and Energy Services businesses continued to benefit from favourable margins in the period, and Regional Oil Sands System which realized higher shipped volumes. Adjusted earnings from Sponsored Investments increased in the fourth quarter of 2011 due to strong results from EEP’s natural gas business and higher general partner incentive income. Partially offsetting these items are lower adjusted earnings from Gas Distribution owing to lower other income. Commencing the fourth quarter of 2011, adjusted earnings from the Ontario Wind, Sarnia Solar and Talbot Wind projects are included within Sponsored Investments following the transfer of these assets to the Fund. These assets were previously reported under Gas Pipelines, Processing and Energy Services.

CASH FLOWS

The Company’s strong operating results from its core assets and stable cash flow generation from growth projects placed into service in recent years resulted in cash provided by operating activities of $2,703

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million for the year ended December 31, 2011, an increase over $1,851 million generated in the prior year. Operating cash flow, together with cash provided by financing activities, funded the Company’s ongoing growth initiatives in 2011, including capital expenditures of $2,516 million and the strategic acquisition of a 50% interest in the Seaway Pipeline for $1.2 billion.

Financing activities for 2011 included normal course short-term borrowings and term note issuances, as well as the issuance of $926 million of preference shares. The partial monetization of Enbridge’s interest in several renewable power generation assets through a transfer to the Fund generated net cash proceeds of $210 million that will be reinvested in further growth projects. These transactions are in keeping with the Company’s strategy to diversify its funding sources and derive greater value for its investors through maintaining a low cost of capital.

DIVIDENDS

The Company has paid common share dividends since its public inception in 1953. Based on estimated 2012 dividends, the annual rate of increase has averaged 11.5% since 2002 and 10.2% since inception. In December 2011, the Company announced a 15% increase in its quarterly dividend to $0.2825 per common share, or $1.13 annualized, effective March 1, 2012. The Company continues to target a payout of approximately 60% to 70% of adjusted earnings as dividends and, with the most recent dividend increase, the 2012 payout is expected to be near the upper end of the range. In 2011, dividends paid per share were 66% of adjusted earnings per share (2010 - 64%; 2009 - 63%).

The chart shows dividends per common share for the last 10 years, as well as estimated dividends for 2012, based on the quarterly dividend of $0.2825 per common share declared by the Board of Directors on December 7, 2011.

REVENUES

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

Commodity sales revenue of $15,676 million (2010 - $11,990 million; 2009 - $9,720 million) is earned through the Company’s natural gas distribution and energy services activities. 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 services activities do not directly impact earnings since such earnings reflect a margin or percentage of revenue which depends more on differences in commodity prices between locations and points in time than on the absolute level of prices. 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 services revenue has increased from $2,746 million in 2009 to $3,137 million in 2010 and $3,726 million in 2011. This increasing trend reflects contributions from the Company’s growth projects placed into service in recent years as well as increasing volumes within the Company’s core liquids and natural gas businesses. Significant growth projects placed in service over this time period include the initial phase of the Sarnia Solar Project in December 2009 followed by an expansion in 2010, Alberta Clipper in April 2010 and the Southern Lights Pipeline in July 2010. The Talbot Wind Energy Project

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commenced operations near the end of 2010, as did several Bakken-area expansion projects completed by the Company’s Sponsored Investments.

FORWARD-LOOKING INFORMATION

Forward-looking information, or forward-looking statements, have been included in this MD&A to provide the Company’s shareholders and potential investors with information about the Company and its subsidiaries and affiliates, including management’s assessment of Enbridge’s and its subsidiaries’ future plans and operations. This information may not be appropriate for other purposes. Forward-looking statements are typically identified by words such as ‘‘anticipate’’, ‘‘expect’’, ‘‘project’’, ‘‘estimate’’, ‘‘forecast’’, ‘‘plan’’, ‘‘intend’’, ‘‘target’’, ‘‘believe’’ and similar words suggesting future outcomes or statements regarding an outlook. Forward-looking information or statements included or incorporated by reference in this document include, but are not limited to, statements with respect to: expected earnings or adjusted earnings; expected earnings or adjusted earnings per share; expected costs related to projects under construction; expected in-service dates for projects under construction; expected tariffs for pipelines; 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 NGLs; prices of crude oil, natural gas and NGLs; 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 NGLs, and the prices of these commodities, are material to and underlie all forward-looking statements. These factors are relevant to all forward-looking statements as they may impact current and future levels of demand for the Company’s services. Similarly, exchange rates, inflation and interest rates impact the economies and business environments in which the Company operates, may impact levels of demand for the Company’s services and cost of inputs, and are therefore inherent in all forward-looking statements. Due to the interdependencies and correlation of these macroeconomic factors, the impact of any one assumption on a forward-looking statement cannot be determined with certainty, particularly with respect to expected earnings or adjusted earnings and associated per share amounts, or estimated future dividends. The most relevant assumptions associated with forward-looking statements on projects under construction, including estimated in-service dates, and expected capital expenditures include: the availability and price of labour and pipeline construction materials; the effects of inflation and foreign exchange rates on labour and material costs; the effects of interest rates on borrowing costs; and the impact of weather and customer and regulatory approvals on construction schedules.

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

NON-GAAP MEASURES

This MD&A contains references to adjusted earnings/(loss), which represent earnings or loss attributable to common shareholders adjusted for non-recurring or non-operating factors on both a consolidated and segmented basis. These factors are reconciled and discussed in the financial results sections for the affected business segments. Management believes that the presentation of adjusted earnings/(loss)

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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

Enbridge’s vision is to be the leading energy delivery company in North America. The Company transports, generates and distributes energy. By doing so, we deliver value to shareholders. The Company’s objective is to generate superior economic value for shareholders through securing, constructing and operating energy infrastructure projects that are consistent with its investment value proposition: visible growth, a reliable business model and a growing income stream. Consistently applied, such stewardship should continue to generate attractive returns on invested capital and, in turn, provide for growing dividend distributions and capital appreciation to its shareholders.

At Enbridge, we integrate our core values into our daily activities, helping us work toward achieving our collective vision. Our values include integrity, safety and respect.

CORPORATE STRATEGY

In support of its long-term vision, the Company employs six key strategies that guide decision making across the enterprise:

1. Focusing on Operations and System Integrity;

2. Strengthening Our Core Businesses;

3. Developing New Platforms for Growth and Diversification;

4. Developing People;

5. Responding to Environmental Priorities; and

6. Preserving Financial Strength and Flexibility.

Enbridge’s strategies are reviewed annually with direction from its Board of Directors and incorporate perspectives on macroeconomic conditions in North America and globally, evolving energy supply and demand fundamentals, changing customer demands, stakeholder expectations and competitor behaviors.

1. FOCUSING ON OPERATIONS AND SYSTEM INTEGRITY

Effective management of operations and project execution is the foundation of Enbridge’s strategic plan. The overarching objective and priority of the business is to ensure the safety and reliability of our delivery systems for our customers, the public and our employees. To support this objective and to emphasize the operational focus of our business, the Company has organized its operations along functional lines and has substantially increased the amount of capital that will be directed towards maintenance and integrity programs.

Timely and cost-effective execution of an existing slate of $13 billion commercially secured projects continues to be a key priority for Enbridge. 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 focuses on project execution success factors such as cost estimation, regulatory permitting, material and labour sourcing and project governance.

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2. STRENGTHENING OUR CORE BUSINESSES

The Company has an established history of serving the transportation needs of key North American crude oil and natural gas markets and our Liquids Pipelines and natural gas segments will continue to be central to delivering our value proposition to investors. However, faced with evolving supply and demand fundamentals and increased competition, strategies to strengthen the Company’s core businesses and to expand and extend our asset base in these areas are critical to meet the Company’s long-term objectives.

Within the Liquids Pipelines segment, strategies are focused on maintaining the competitiveness of mainline assets, pursuing new market access opportunities and strengthening the Company’s position in the Alberta oil sands and Bakken regions. The 10-year CTS reached with shippers in 2011 was an important first step in executing this broader strategy. The CTS provides a stable and competitive toll to shippers and preserves and enhances throughput on the Canadian mainline system for Enbridge. The CTS provides the foundation to support further extensions off the mainline system and the Company continues to pursue opportunities to provide its customers broader market access for Canadian bitumen and synthetic crude oil, including expansion initiatives to the Texas Gulf Coast. In late 2011, the Company announced it had acquired a 50% interest in the Seaway Pipeline system and that it was proceeding with the Gulf Coast Access initiative, which will offer shippers access to the Gulf Coast refining complex. The Company’s efforts to expand market access and provide the highest netback for producers also include eastern market access opportunities and development of the proposed Northern Gateway pipeline, which would provide access to markets off the Pacific coast of Canada.

Regional liquids pipeline development involves projects which connect new oil sands production to existing hubs on the Canadian mainline. Enbridge, the largest pipeline operator in the oil sands region of Alberta, is currently is developing close to $3.4 billion in commercially secured regional oil sands transportation facilities that are being placed into service between 2011 and 2015. The Company also has $0.8 billion of secured system expansion projects in Saskatchewan and North Dakota where the Company is strategically located to capture increased production from the Bakken play.

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 strategies include leveraging the competitive advantages of existing assets and expanding its footprint in these emerging areas, including establishment of a Canadian midstream position. Alliance Pipeline is well positioned to service developing regions in northeast British Columbia and the Bakken play, and is continuously evaluating opportunities to expand its service offerings in those areas as well as strategies to attract liquids rich gas onto the system. Development of the Montney and Horn River shale plays is also creating the need for additional Canadian midstream infrastructure; an opportunity which fits with the Company’s investment value proposition and which can leverage existing operational expertise. The Company made a significant investment in the Canadian midstream business in October 2011 with the acquisition of a majority stake in Cabin in the Horn River basin. Within the United States, strategic priorities include expanding gathering and processing capacity, particularly in the Granite Wash area, and seeking opportunities to expand its service offerings, including NGL transportation. In addition to these onshore strategies, the Company continues to pursue crude oil and natural gas gathering expansion opportunities for ultra-deep projects in the Gulf of Mexico.

3. 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 source of new growth as government initiatives and changing social beliefs focused on lower carbon emissions are creating opportunities to deliver green energy solutions with risk and return characteristics consistent with Enbridge’s investment value proposition. Renewable energy is also an important part of Enbridge’s environmental and corporate social responsibility (CSR) strategies. Enbridge has advanced its green energy strategy over the last several years and has interests in a renewable energy portfolio of close to 1,000-megawatts (MW). Near term priorities will focus on expansion of existing sites and pursuit of relationships with existing developers that have a suite of development projects. The Company is also assessing opportunities to invest in gas-fired generation which is projected to grow significantly over the long-term based on natural gas supply fundamentals.

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Power transmission is also an attractive growth opportunity for the Company and a complement to its renewable energy strategy. Substantial transmission needs exist in North America with risk and return profiles that fit Enbridge’s investment value proposition. The Company’s strategy in this area is to establish an initial base of assets and an experienced management team. Enbridge’s first step in this regard was achieved in late 2011 with the acquisition of the Montana-Alberta Tie-Line (MATL) transmission project and integration of the project development management team into Enbridge.

Internationally, there is a growing need for energy infrastructure which provides further opportunities for Enbridge to grow and diversify. Enbridge’s international business development strategy focuses on select regions with strong supply and demand fundamentals and favourable investment climates.

Enbridge’s Alternative and Emerging Technology program continues to identify early stage energy technologies that complement the Company’s core businesses and provide potential for further growth.

4. DEVELOPING PEOPLE

Attracting, developing and retaining high performing and effective employees and leaders continue to be strategic priorities for Enbridge. Key priorities related to building and improving Enbridge’s organizational and workforce capabilities include:

· Developing workforce optimization strategies and determining optimal staffing models;

· Ensuring leadership continuity and readiness with an increased focus on succession management, leadership development and mentorship;

· Refreshing Enbridge’s core values and embedding them within all talent management practices;

· Implementing an enterprise wide change management approach and building change management capability within the organization; and

· Standardizing processes and systems.

5. RESPONDING TO ENVIRONMENTAL PRIORITIES

Enbridge believes it must have effective strategies to respond to environmental and other corporate responsibilities. Enbridge adheres to a strong set of corporate values, has adopted a number of corporate responsibility policies and practices and has made significant investments in renewable and alternative energy technologies.

Enbridge defines CSR as conducting business in an ethical and responsible manner, protecting the environment and the safety of people, providing economic and other benefits to the communities in which we operate, supporting universal human rights and employing a variety of policies, programs and practices to manage corporate governance and ensure fair, full and timely disclosure. Enbridge’s 2011 CSR Report can be found at http://csr.enbridge.com/. None of the information contained on, or connected to, the Enbridge website is incorporated or otherwise part of this MD&A.

The Company’s Neutral Footprint plan includes commitments to counteract the environmental impact of Enbridge’s operations since January 2009 within five years of their occurrence. Enbridge Neutral Footprint commitments include:

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

· conserving an acre of land for every acre of wilderness we permanently impact; and

· generating a kilowatt of renewable energy for every kilowatt our operations consume.

To achieve its Neutral Footprint goal, Enbridge is working with the Nature Conservancy of Canada, The Conservation Fund in the United States and others. As reported in Enbridge’s 2011 CSR Report, progress on the Company’s Neutral Footprint initiatives (which are subject to change based on changes in the Company’s operations) includes:

· 589,850 trees removed; 246,000 tree seedlings planted;

· 1,598 acres disturbed; 3,955 acres conserved through the Nature Conservancy of Canada;

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· forecasted growth in power consumption (from 2008 to 2015) is 1,852 gigawatts per hour (GWh); power currently generated from renewable sources is approximately 1,900 GWh.

6. PRESERVING FINANCIAL STRENGTH AND FLEXIBILITY

The maintenance of adequate financial strength and flexibility is fundamental to Enbridge’s growth strategy. 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 or improve Enbridge’s credit ratings, diversify its funding sources and maintain substantial bank credit facilities and 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. The Company has robust risk management processes which ensure earnings volatility from market price risk is managed within the parameters of its earnings-at-risk policy. Enbridge will continue to proactively hedge interest rate, foreign exchange and commodity price exposures. Management of counterparty credit risk also remains an ongoing priority.

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 benchmarks before being pursued.

INDUSTRY FUNDAMENTALS

SUPPLY AND DEMAND FOR LIQUIDS

Canadian crude oil exports to the United States continue to grow, further solidifying Canada as its number one supplier. Combined conventional and oil sands established reserves of approximately 173 billion barrels suggest that this trend will continue, albeit against growing concern over the environmental footprint of oil sands crude. The National Energy Board (NEB) estimates that total Western Canadian Sedimentary Basin (WCSB) production averaged approximately 2.8 million barrels per day (bpd) in 2011 (2010 - 2.6 million bpd; 2009 - 2.4 million bpd).

Other than the WCSB, significant growth is forecasted to come from the Bakken Play in North Dakota and eastern Montana. Despite production problems as a result of severe weather in early 2011, production from this area grew from 371 thousand barrels per day (kbpd) in 2010 to an estimated 466 kbpd in 2011. Starting in July 2011, with the reversal of the Portal Link connecting EEP’s North Dakota System with the Saskatchewan System, the Canadian Mainline began to receive up to 25 kbpd of United States Bakken crude at Cromer, Manitoba. This volume will increase to a maximum of 145 kbpd with the completion of the Bakken Expansion program in 2013.

Sustained oil prices have led to a resurgence in oil sands project announcements that had slowed during the economic downturn. These announcements provide optimism for oil sands production growth in the medium term. The question remains whether industry can avoid the capital cost inflation which overwhelmed projects during the most recent boom as companies competed for resources. The Canadian Association of Petroleum Producers’ June 2011 growth case estimates indicate that future WCSB production is expected to steadily increase by 5.3% annually to approximately 4.6 million bpd by 2025. This forecasted growth is largely attributed to increased oil sands production in Alberta.

World crude oil demand was approximately 700 kbpd higher in 2011 relative to 2010, with China being the major contributor of demand growth. Although North American demand growth remains relatively flat, and is projected to remain that way in the near future, Canadian crude exports to the United States Midwest are growing while United States overall crude imports from other countries have declined relative to past years. Planned reconfiguration of refineries in the Midwest will increase the demand for Canadian crude in one of Enbridge’s key markets. Further, the Company’s planned incremental pipeline

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capacity into the Texas Gulf Coast refining complex will serve to expand market access and improve netbacks for Canadian producers. While improved Gulf Coast access is an important step to diversify markets for Canadian crude, an industry solution to efficiently access growing Asian markets off the west coast of Canada is needed and is currently under development by Enbridge with industry support.

With the expected increase in heavy oil production in western Canada, there is an increasing requirement for condensate 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 byproduct of natural gas production. Production of this commodity is decreasing in western Canada but, with the increasing demand for diluents from heavy oil producers, there is an increasing need to import condensate. Currently, volumes are transported via Enbridge’s Southern Lights condensate pipeline, via rail to Alberta from the United States and from international sources via tankers and rail from the West Coast.

SUPPLY AND DEMAND FOR NATURAL GAS

Evolving drilling and completion technologies have unlocked vast gas resources from unconventional reservoirs, primarily shale plays, and have led to oversupplied markets in North America. Recent estimates of gas resources for the United States and Canada total approximately 2,600 trillion cubic feet (tcf). With current combined annual gas production of approximately 27 tcf, the United States and Canada have almost 100 years of gas supply. Moreover, as producers continue to improve well productivity and drilling efficiency for unconventional gas, the average unit cost of developing gas supply has fallen over the past few years. Considering the abundant resource base and lower development costs, North America is expected to experience a relatively low gas price environment for the foreseeable future.

With the expectation of weak gas prices over the near-term, producers are expected to continue their shift in focus away from dry gas to more competitive liquids-rich gas and oil targets. The Marcellus, Eagle Ford and Granite Wash rich-gas plays remain prime targets in the United States. As well, activity is picking up in the offshore Gulf of Mexico as an increasing number of drilling permits are issued focused on oil production, which would lead to additional associated gas production. In Canada, drilling strategies are similar with the focus on liquids-rich gas plays in northeast British Columbia and the Alberta Deep Basin.

Gas supply is expected to continue to outpace demand growth as the North American economy struggles to advance. In contrast to low gas prices, oil prices are expected to be strong, driven by demand growth in developing countries. As such, the wide disparity between gas and oil prices should continue to support the extraction of NGL with favorable fractionation spreads.

Growth in industrial gas demand has been sluggish as the economic recovery has been slow. While economic growth is expected to continue to be weak over the next few years, low gas prices should enable a larger amount of coal-fired generation to be displaced by more competitive gas units. Further, proposed environmental regulations in the Lower 48 would cause the retirement of some older, less efficient coal generators and potentially increase gas-fired generation’s share of the overall power production portfolio. Growth in gas-fired generation is expected to lead overall gas demand in North America. Canadian gas demand will also be driven by the development of oil sands projects. The United States Energy Information Administration (EIA) and the NEB estimate North American gas demand to be approximately 31 tcf in 2035; a 15% increase from 2010.

The prospect of relatively low domestic gas prices continuing over the longer-term have spurred the progress of multiple projects to export liquefied natural gas from North America to higher-priced global markets, which are primarily linked to oil prices. Export authorization has been granted to several Canadian and United States projects with first deliveries occurring as early as mid-decade.

SUPPLY AND DEMAND FOR GREEN ENERGY

Traditional forms of energy are expected to represent the major source of future North American energy supply; however, a shift to a lower carbon intensive economy, prompted mainly by government policy, exists. As overall North American energy needs continue to grow, particularly the need for electricity to meet industrial and residential demand, opportunities arise for renewable energy projects to capture a significant portion of incremental and replacement generation capacity over the next 25 years.

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Growth in North American electricity demand is expected to average approximately 1% annually. The EIA forecasts that new United States generating capacity of over 200 gigawatts (GW) will be required by 2035, with renewable sources playing an increasing role. Growth in nuclear and coal-fired generation is expected to be limited due to permitting challenges, long lead times, capital cost and uncertainty of environmental regulations, leaving opportunity for renewable sources to meet a critical portion of the incremental demand.

The United States National Renewable Energy Laboratory reports that North America has significant wind and solar resources, with wind alone having the potential for over 10,000 GW of power generation. Solar resources in south western states such as Arizona, California, Colorado and Nevada are the best in the world for large-scale solar plants. In Canada, Environment Canada reports an abundance of wind resources, particularly in the north eastern regions.

Expanding renewable energy infrastructure in North America is not without challenges. Projects are typically capital intensive and renewable technology is in the early stages relative to mature energy sources. Further, renewable projects must balance the benefit of reduced carbon emissions with land disturbances and project aesthetics. High quality wind and solar resources are often found in regions at long distances from high demand markets, introducing the need for new transmission capacity.

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. Alternative energy sources are expected to play an increasingly important role in meeting future North American energy demand with a continued drive to develop and promote green energy.

GROWTH PROJECTS

In 2010, Enbridge was successful in placing almost $7 billion of new growth projects into service, 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. In 2011, the Company was very successful in re-stocking its growth project inventory by securing close to $8 billion in new infrastructure growth projects across many of its businesses, including Liquids Pipelines, Canadian gas midstream, Texas gathering and processing, offshore Gulf of Mexico gas processing, renewable power generation and power transmission. The Company now has approximately $13 billion in commercially secured growth projects that have or are expected to come into service between 2011 and 2015. Further, the Company has identified an additional $35 billion of potential opportunities for development over the 2011-2020 time horizon.

The table below summarizes the current status of the Company’s commercially secured projects, separated into the Company’s business segments. This inventory of growth projects provides confidence to Enbridge management that the Company will be able to achieve an average annual earnings per share growth of 10% through the middle of this decade, based on conservative assumptions.

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|  | Actual/ Estimated Capital Cost 1 |  | Expenditures to Date |  | Expected In-Service Date |  | Status
(Canadian dollars, unless stated otherwise) |  |  |  |  |  |  |  |
LIQUIDS PIPELINES |  |  |  |  |  |  |  |
1. | Christina Lake Lateral Project |  | $0.2 billion |  | $0.2 billion |  | 2011 |  | Substantially complete
2. | Edmonton Terminal Expansion |  | $0.3 billion |  | $0.1 billion |  | 2012 |  | Under construction
3. | Woodland Pipeline |  | $0.3 billion |  | $0.2 billion |  | 2012 |  | Under construction
4. | Wood Buffalo Pipeline |  | $0.4 billion |  | $0.2 billion |  | 2012 |  | Under construction
5. | Seaway Crude Pipeline System (including reversal and extension) |  | US$1.5 billion |  | US$1.2 billion |  | 2012-2013 (in phases) |  | Pre- construction
6. | Waupisoo Pipeline Capacity Expansion |  | $0.4 billion |  | $0.1 billion |  | 2012-2013 (in phases) |  | Under construction
7. | Norealis Pipeline |  | $0.5 billion |  | No significant expenditures to date |  | 2013 |  | Under construction
8. | Athabasca Pipeline Capacity Expansion |  | $0.4 billion |  | $0.1 billion |  | 2013-2014 (in phases) |  | Pre- construction
9. | Flanagan South Pipeline Project |  | US$1.9 billion |  | No significant expenditures to date |  | 2014 |  | Pre- construction
10. | Athabasca Pipeline Twinning |  | $1.2 billion |  | No significant expenditures to date |  | 2015 |  | Pre- construction
GAS PIPELINES, PROCESSING AND ENERGY SERVICES
11. | Amherstburg Solar Project |  | $0.1 billion |  | $0.1 billion |  | 2011 |  | Complete
12. | Cedar Point Wind Energy Project 2 |  | US$0.5 billion |  | US$0.5 billion |  | 2011 |  | Complete
13. | Greenwich Wind Energy Project |  | $0.3 billion |  | $0.3 billion |  | 2011 |  | Complete
14. | Prairie Rose Pipeline and Palermo Conditioning Plant |  | US$0.1 billion |  | US$0.1 billion |  | 2011 |  | Complete
15. | Lac Alfred Wind Project |  | $0.3 billion |  | $0.1 billion |  | 2012-2013 (in phases) |  | Under construction
16. | Cabin Gas Plant |  | $1.1 billion |  | $0.4 billion |  | 2012-2014 (in phases) |  | Under construction
17. | Tioga Lateral Pipeline |  | US$0.1 billion |  | No significant expenditures to date |  | 2013 |  | Pre- construction
18. | Venice Condensate Stabilization Facility |  | US$0.2 billion |  | No significant expenditures to date |  | 2013 |  | Pre- construction
19. | Walker Ridge Gas Gathering System |  | US$0.4 billion |  | No significant expenditures to date |  | 2014 |  | Pre- construction
20. | Big Foot Oil Pipeline |  | US$0.2 billion |  | No significant expenditures to date |  | 2014 |  | Pre- construction
SPONSORED INVESTMENTS
21. | EEP - Bakken Expansion Program |  | US$0.4 billion |  | US$0.1 billion |  | 2013 |  | Under construction
22. | The Fund - Bakken Expansion Program |  | $0.2 billion |  | No significant expenditures to date |  | 2013 |  | Pre- construction
23. | EEP - Allison Cryogenic Processing Plant |  | US$0.1 billion |  | US$0.1 billion |  | 2011 |  | Complete
24. | EEP - Cushing Terminal Storage Expansion Project |  | US$0.1 billion |  | No significant expenditures to date |  | 2011-2012 (in stages) |  | Under construction
25. | EEP - South Haynesville Shale Expansion |  | US$0.3 billion |  | US$0.2 billion |  | 2012+ |  | Under construction
26. | EEP - Eastern Market Expansion |  | US$0.1 billion |  | No significant expenditures to date |  | 2013 |  | Pre- construction

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|  | Actual/ Estimated Capital Cost 1 |  | Expenditures to Date |  | Expected In-Service Date |  | Status
27. | EEP - Ajax Cryogenic Processing Plant |  | US$0.2 billion |  | No significant expenditures to date |  | 2013 |  | Under construction
28. | EEP - Bakken Access Program |  | US$0.1 billion |  | No significant expenditures to date |  | 2013 |  | Under construction
29. | EEP- Berthold Rail Project |  | US$0.1 billion |  | No significant expenditures to date |  | 2013 |  | Pre- construction
30. | EEP - Texas Express Pipeline |  | US$0.4 billion |  | No significant expenditures to date |  | 2013 |  | Pre- construction
31. | EEP - Line Replacement Program |  | US$0.3 billion |  | No significant expenditures to date |  | 2013 |  | Pre- construction
CORPORATE
32. | Noverco |  | $0.1 billion |  | $0.1 billion |  | 2011 |  | Complete
33. | Montana-Alberta Tie-Line |  | US$0.3 billion |  | US$0.2 billion |  | 2012-2013 (in stages) |  | Under construction

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 reflected total expenditures before receipt of US$0.1 billion payment from the United States Treasury. See Growth Projects – Gas Pipelines, Processing and Energy Services – Cedar Point Wind Energy Project.

Risks related to the development and completion of growth projects are described under Risk Management and Financial Instruments.

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LIQUIDS PIPELINES

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. Upon substantial completion in August 2011, the expansion project added 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 and 240,000 barrels of tankage, that connect to the Athabasca Pipeline. The final cost of the additional facilities is approximately $0.2 billion.

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 will be conducted over two phases and will consist of the construction of four tanks and the installation of three booster pumps and related infrastructure. Regulatory approval was received in the first quarter of 2011 and, subject to receipt of other approvals, the expansion is expected to be completed in 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 new Woodland Pipeline may be extended from Cheecham to Edmonton as part of future industry expansions. Regulatory approval for the Phase I facilities was received in June 2010 and construction is underway. The total estimated cost of the Phase I pipeline from the mine to the Cheecham Terminal and related facilities is approximately $0.5 billion, with expenditures to date of approximately $0.2 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 mainline hub. The new Wood Buffalo Pipeline will parallel the existing Athabasca Pipeline between the Athabasca and Cheecham Terminals. The estimated capital cost is approximately $0.4 billion, with expenditures to date of approximately $0.2 billion. With regulatory approval received in the first quarter of 2011, the new pipeline is expected to be in service by late 2012.

Seaway Crude Pipeline System

In December 2011, Enbridge completed the acquisition of 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 Freeport, Texas to Cushing, Oklahoma long-haul system, as well as the Texas City Terminal and Distribution System which serves refineries in the Houston and Texas City areas. Seaway Pipeline also includes 6.8 million barrels of crude oil tankage on the Texas Gulf Coast and four import docks at two locations. The other 50% interest in the Seaway Pipeline system is owned by Enterprise Products Partners L.P. (Enterprise).

Enbridge and Enterprise have announced plans to reverse the flow direction of the 805-kilometre (500-mile) 30-inch diameter Seaway Pipeline, enabling it to transport crude oil from the oversupplied hub in Cushing, Oklahoma to the U.S. Gulf Coast. The initial 150,000 bpd of capacity on the reversed system is expected to be available by the second quarter of 2012. Following pump station additions and modifications, which are expected to be completed by the first quarter of 2013, capacity would increase to 400,000 bpd assuming a mix of light and heavy grades of crude oil.

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In addition, a proposed 137-kilometre (85-mile) pipeline is expected to be built from Enterprise’s ECHO crude oil terminal southeast of Houston to the Port Arthur/Beaumont, Texas refining center to provide shippers access to the region’s heavy oil refining capabilities. This lateral could offer incremental capacity in excess of 400,000 bpd and is expected to be available in early 2014. Enbridge’s investment in the joint venture, including its share of reversal expenditures and the Port Arthur lateral, is expected to be approximately US$1.5 billion. Open Seasons were held from January 4, 2012 through February 10, 2012 to solicit capacity commitments from shippers for potential expansion of the Seaway Pipeline through looping or twining, and for service on the Port Arthur lateral.

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 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 is expected to accommodate additional shipper commitments of 229,000 bpd. The estimated cost of the project is approximately $0.4 billion, with expenditures to date of approximately $0.1 billion.

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. With regulatory approval received in the second quarter of 2011, the facilities are expected to be in service in late 2013.

Athabasca Pipeline Capacity Expansion

The Company will undertake an expansion of its Athabasca Pipeline to its full capacity to accommodate additional contractual commitments, including production from the Christina Lake Oilsands Project operated by Cenovus. This expansion is expected to increase the capacity of the Athabasca Pipeline to its maximum capacity of approximately 570,000 bpd, depending on type of crude oil. The estimated cost of full expansion is approximately $0.4 billion, with expenditures to date of approximately $0.1 billion and an expected in service date 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 Flanagan South Pipeline will transport crude oil from the Company’s terminal at Flanagan, Illinois to Cushing, Oklahoma. The common carrier pipeline is expected to have an initial annual capacity of 350,000 bpd at an expected cost of approximately US$1.9 billion and is designed to be expandable to 540,000 bpd. A binding Open Season that was held in the fourth quarter of 2011 resulted in sufficient customer commitment to move forward with this project. A second Open Season was held concurrent with that for Seaway Pipeline, and commitments from that Open Season will determine the final design scope and capacity. Subject to regulatory and other approvals, the pipeline is expected to be in service by mid-2014. Both the Seaway and Flanagan South pipelines are included in the Company’s Gulf Coast Access initiative to offer crude oil transportation from its terminal at Flanagan to the United States Gulf Coast.

Athabasca Pipeline Twinning

In September 2011, Enbridge announced plans to twin the southern section of its Athabasca Pipeline from Kirby Lake, Alberta to the Hardisty, Alberta crude oil hub to accommodate the need for additional capacity to serve Kirby Lake area expected oil sands growth. The expansion project, with an estimated cost of approximately $1.2 billion, will include 345 kilometres (210 miles) of 36-inch pipeline within the existing Athabasca Pipeline right-of-way. The initial annual capacity of the twin pipeline will be approximately 450,000 bpd, with expansion potential to 800,000 bpd. The line is expected to enter service in 2015.

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

In June 2011, Northern Gateway filed additional materials with the JRP including, but not limited to, details of its extensive program of consultation with over 40 Aboriginal communities between December 2009 and March 2011. The update summarized the information provided to Aboriginal groups, the engagement activities that have occurred, the interests and concerns that have been expressed to Northern Gateway, commitments and mitigation measures in response to those concerns and an update on the status of Aboriginal Traditional Knowledge study programs. 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 a Procedural Direction issued in December 2011, the JRP indicated it expects to hold final hearings in September and October 2012 where Northern Gateway, intervenors, government participants and the JRP will question those who have presented oral or written evidence. Based on this projected schedule, the JRP would anticipate releasing the Environmental Assessment in the fall of 2013 and its final decision on this project near the end of 2013. 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 by 2017 at the earliest, at an estimated cost of $5.5 billion. Expenditures to date, which relate primarily to the regulatory process, are approximately $0.2 billion, including $0.1 billion in funding secured from Western Canada producers and Pacific Rim refiners toward the costs of seeking the necessary regulatory approvals for the project. Given the many uncertainties surrounding the Northern Gateway Project, including final ownership structure, the potential financial impact of the project cannot be determined at this time.

The JRP posts public filings related to Northern Gateway on its website at http://gatewaypanel.review-examen.gc.ca/clf-nsi/hm-eng.html and Enbridge also maintains a Northern Gateway Project website in addition to information available on www.enbridge.com. The full regulatory application submitted to the NEB and the 2010 Enbridge Northern Gateway CSR 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.

Fort Hills Pipeline System

In late 2008, Fort Hills Energy L.P. (FHELP) announced that its final investment decision for the mining portion of its 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. FHELP has now completed its re-evaluation

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and while it is proceeding with the mining portion of the project, FHELP has decided not to proceed with the original pipeline project. Expenditures incurred to date under the original contractual arrangement of approximately $0.1 billion have been substantially collected from FHELP. Discussions on a new pipeline project to meet the new needs of the mining project are ongoing, with no commitments currently in place.

GAS DISTRIBUTION

Nexus Project

The Nexus Project is a 4.5 billion cubic feet expansion of EGD’s unregulated natural gas storage facility near Sarnia, Ontario. The project, which has received regulatory approval for construction, is secured by a long-term commercial contract. Construction began in the second quarter of 2011 and was completed in 2011 at an approximate capital cost of $34 million. Additional remediation and close-out activities are expected to be performed in 2012 to bring the total capital cost to approximately $38 million.

GAS PIPELINES, PROCESSING AND ENERGY SERVICES

Amherstburg Solar Project

The Amherstburg II Solar Project, located in Amherstburg, Ontario, consists of both a 10-MW facility and a 5-MW facility. First Solar constructed both facilities for Enbridge under fixed price engineering, procurement and construction contracts. The Amherstburg II Solar Project was completed in the third quarter of 2011 at a cost of approximately $0.1 billion, at which time commercial operations commenced. Power output from the facilities is sold to the Ontario Power Authority (OPA) pursuant to 20-year power purchase agreements.

Cedar Point Wind Energy Project

Enbridge developed the 250-MW Cedar Point Wind Energy Project near Denver, Colorado with Renewable Energy Systems America Inc. (RES Americas), at a cost of approximately US$0.5 billion. RES Americas constructed 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 delivers electricity into the Public Service Company of Colorado grid under a 20-year, fixed price power purchase agreement. Project construction was completed in September 2011 and commercial operation began in November 2011. In December 2011, 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.

Greenwich Wind Energy Project

The Company developed the 99-MW Greenwich Wind Energy Project on the northern shore of Lake Superior in Ontario with Renewable Energy Systems Canada Inc. (RES Canada). Enbridge has a 90% interest in the project and an option to acquire the remaining 10% interest. RES Canada constructed 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 provides operations and maintenance services for the wind turbines. The Greenwich Wind Energy Project delivers energy to the OPA under a 20-year power purchase agreement. The project was completed and commenced commercial operations in October 2011 with expenditures of approximately $0.3 billion.

Prairie Rose Pipeline and Palermo Conditioning Plant

In July 2011, an affiliate of Aux Sable acquired the Prairie Rose Pipeline and the Palermo Conditioning Plant for US$0.2 billion. The Palermo Conditioning Plant removes condensate and will have a capacity of 80 mmcf/d. The 12-inch diameter, 134-kilometre (83-mile) Prairie Rose Pipeline, with an estimated capacity of 110 mmcf/d, connects the plant to the Alliance Pipeline, which then delivers high energy content gas to Aux Sable’s Channahon, Illinois plant for further processing. Enbridge has a 42.7% equity interest in Aux Sable and a 50% interest in Alliance Pipeline US.

Lac Alfred Wind Project

In December 2011, Enbridge secured a 50% interest in the development of the 300-MW Lac Alfred Wind Project (Lac Alfred). The project, located 400 kilometres (250 miles) northeast of Quebec City in Quebec’s Bas-Saint-Laurent region, will consist of 150 wind turbines. The project is being constructed under a fixed price,

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turnkey, engineering, procurement and construction agreement and will take place in two phases: Phase 1, which began construction in June 2011, 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 power purchase agreement and will construct the 30-kilometre transmission line to connect the 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.

Cabin Gas Plant

In December 2011, the Company secured a 71% interest in the development of 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 is expected to be approximately $1.1 billion.

Phase 1 of the development is to have 400 million cubic feet per day (mmcf/d) of processing capacity. The plant is currently under construction and is expected to be in-service in late 2012. Phase 2, which is to provide an additional 400 mmcf/d of capacity, has been sanctioned by the producers and has also received regulatory approval. Phase 2 is expected to be ready for service in the third quarter of 2014. Capacity for both phases 1 and 2 has been fully subscribed by Horn River producers. These producers can request the Company to expand Cabin up to an additional four phases, under agreed terms.

Tioga Lateral Pipeline

In September 2011, Alliance Pipeline US announced plans to develop 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. Alliance Pipeline US has executed a precedent agreement with Hess Corporation (Hess) as an anchor shipper on the Tioga Lateral Pipeline. Aux Sable Liquids Products 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 high-energy, 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 120 mmcf/d, which can be expanded based on shipper demand. Subject to regulatory and other required approvals, the pipeline is expected to be in service by the third quarter of 2013.

Venice Condensate Stabilization Facility

In January 2011, the Company announced plans for an estimated US$0.2 billion expansion of the Venice Condensate Stabilization Facility (Venice) at its Venice, Louisiana facility within its Offshore 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 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 the last quarter of 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-deepwater developments. The WRGGS includes 274 kilometres (170 miles) of 8-inch or 10-inch diameter pipeline at depths of up to approximately 2,150 meters (7,000 feet) with capacity of 0.1 billion cubic feet per day (bcf/d). WRGGS is expected to be in service in 2014 and is expected to cost approximately US$0.4 billion.

Big Foot Oil Pipeline

The Company executed definitive agreements in March 2011 with Chevron, Statoil Gulf of Mexico LLC and Marubeni Oil & Gas (USA) Inc. to construct and operate a 64-kilometre (40-mile) 20-inch oil pipeline

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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 (Big Foot), which will be located about 274 kilometres (170 miles) south of the coast of Louisiana, is approximately US$0.2 billion and it is expected to be in service in 2014.

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 increase takeaway capacity from the Bakken area by an initial 145,000 bpd, which can be expanded to 325,000 bpd. The Bakken Expansion Program will involve United States projects undertaken by EEP at a cost of approximately US$0.4 billion and Canadian projects undertaken by the Fund at a cost of approximately $0.2 billion. 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$0.1 billion. In Canada, NEB approval was secured in December 2011. Subject to other approvals in respect of the Canadian portion, the Bakken Expansion Program is expected to be completed in the first quarter of 2013.

Enbridge Energy Partners, L.P.

Allison Cryogenic Processing Plant

In April 2010, EEP announced plans to construct a cryogenic processing plant and other facilities on its Anadarko System. The Allison Plant has a capacity of 150 mmcf/d and is intended to accommodate the resurgence of horizontal drilling activity that exists in the Granite Wash formation in the Texas Panhandle, where the Anadarko System is located. The Allison Plant was constructed at an approximate capital cost of US$0.1 billion and placed into service in November 2011. EEP is awaiting the completion of additional third party NGL takeaway capacity to the Allison Plant, expected to be in place during the first quarter of 2012, which will allow EEP to fully utilize its capacity.

Cushing Terminal Storage Expansion Project

EEP is constructing 13 new storage tanks at its Cushing Terminal with an approximate shell capacity of 4.2 million barrels. The total estimated cost of the expansion is approximately US$0.1 billion. Five tanks went into service in December 2011 and the remaining tanks are expected to come into service by December 2012.

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, with an estimated cost of approximately US$0.1 billion, is expected to increase capacity of EEP’s East Texas system by 900 mmcf/d once completed in the first quarter of 2012.

In April 2011, EEP announced plans to invest an additional US$0.2 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. In light of weak gas prices and lower levels of producer activity, EEP is evaluating deferral of portions of its Haynesville natural gas expansion.

Eastern Market Expansion

In October 2011, Enbridge and EEP announced two projects that will 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. The 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 on reversing a portion of its Line 9 in western Ontario to permit crude oil movements eastbound from Sarnia as far as Westover, Ontario at a cost of approximately $20 million. Subject to regulatory and other approvals, the Line 5 expansion is targeted to be in service during the first quarter of 2013, while the Line 9 reversal is targeted to be in service in late 2013.

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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. The Ajax Plant, with a planned capacity of 150 mmcf/d, is expected to be in service in early 2013. The Ajax Plant, when operational, in addition to the Allison Plant, is expected to increase total processing capacity on the Anadarko System to approximately 1,200 mmcf/d.

Bakken Access Program

In October 2011, EEP announced the Bakken Access Program, a series of projects totaling approximately US$0.1 billion, which represents an upstream expansion that will further complement its 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, construction of additional storage tanks and the addition of truck access facilities at multiple locations in western North Dakota, is expected to be in service by early 2013.

Berthold Rail Project

In December 2011, EEP announced that it will be 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 is expected to 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 facilities. Conditional approval was received in early December subject to securing remaining shipper commitments. A regulatory filing is in progress and detailed design is proceeding to enable construction to commence in April 2012 with an expected in-service date by early 2013.

Texas Express Pipeline

In September 2011, EEP announced a joint venture with Enterprise and Anadarko Petroleum Corporation 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 Texas Express Pipeline (TEP), which will originate in Skellytown, Texas and extend approximately 935 kilometres (580 miles) to NGL fractionation and storage facilities in Mont Belvieu, Texas. TEP is expected to have an initial capacity of approximately 280,000 bpd and will be expandable to approximately 400,000 bpd. 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 Replacement Program

In May 2011, EEP announced plans to replace 120 kilometres (75 miles) of non-contiguous sections of Line 6B of its Lakehead System at an estimated cost of US$286 million. The Line 6B pipeline runs from Griffith, Indiana through Michigan to the international border at the St. Clair River. Subject to regulatory approvals, the new segments of pipeline will be constructed mostly in 2012 and are targeted to be placed in service by the first quarter of 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. EEP subsequently revised the scope of this project to increase the cost by approximately US$30 million, which will bring the total capital for this replacement program to an estimated cost of US$316 million. The US$30 million of additional costs do not currently have recovery under the tariff surcharge.

CORPORATE

Montana-Alberta Tie-Line

In October 2011, Enbridge acquired all outstanding common shares of Tonbridge Power Inc. (Tonbridge) for $20 million and assumed long-term debt of $182 million incurred by Tonbridge in the development of the MATL project that was repaid by Enbridge. The Company will also inject further funding to complete the first 300-MW phase of MATL and an expansion between 550-MW and 600-MW. The total expected cost for both phases of MATL is approximately US$0.3 billion, of which

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approximately half will be funded through a 30-year loan from the Western Area Power Administration of the United States Department of Energy. Expenditures to date are approximately US$0.2 billion.

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 the buoyant power demand in Alberta. While the permits required for construction have been obtained, the approval in Canada is currently being updated to reflect a number of design modifications which require further consultation with land owners. Subject to these approvals, the system’s north-bound capacity, which is fully contracted, is expected to be in-service in the fourth quarter of 2012.

Noverco

On June 30, 2011, the Company completed the acquisition of an additional 6.8% interest in Noverco for $144 million. Following the completion of the transaction, Enbridge and Trencap, a partnership managed by the Caisse de Depot et Placement du Quebec, became the sole shareholders of Noverco.

Neal Hot Springs Geothermal Project

The Company has partnered with U.S. Geothermal Inc. to develop the 35-MW Neal Hot Springs Geothermal Project located in Malheur County, Oregon. U.S. Geothermal is constructing the plant and will operate the facility. The project is anticipated to be completed in the second quarter of 2012 and will deliver electricity to the Idaho Power grid under a 25-year power purchase agreement. Construction on the project has commenced and Enbridge will invest up to approximately $27 million for a 29% interest in the project.

LIQUIDS PIPELINES

EARNINGS

|  | 2011 |  |  | 2010 |  | 2009 |
(millions of Canadian dollars) |  |  |  |  |  |  |  |
Canadian Mainline |  | 337 |  |  | 327 |  | 295 |
Regional Oil Sands System |  | 110 |  |  | 73 |  | 72 |
Southern Lights Pipeline |  | 75 |  |  | 82 |  | 58 |
Spearhead Pipeline |  | 17 |  |  | 29 |  | 17 |
Feeder Pipelines and Other |  | (3 | ) |  | 1 |  | 12 |
Adjusted earnings |  | 536 |  |  | 512 |  | 454 |
Canadian Mainline - shipper dispute settlement |  | 14 |  |  | - |  | - |
Canadian Mainline - Line 9 tolling adjustment |  | 10 |  |  | - |  | - |
Canadian Mainline - unrealized derivative fair value loss |  | (48 | ) |  | - |  | - |
Regional Oil Sands System - asset impairment write-off |  | (8 | ) |  | - |  | - |
Regional Oil Sands System - leak remediation costs |  | - |  |  | - |  | (9 | )
Spearhead Pipeline - unrealized derivative fair value gains |  | 1 |  |  | - |  | - |
Earnings |  | 505 |  |  | 512 |  | 445 |

Liquids Pipelines adjusted earnings were $536 million in 2011 compared with adjusted earnings of $512 million in 2010 and $454 million in 2009. The Company continued to realize earnings growth on the Canadian Mainline, primarily due to the CTS and the related change in tolling methodology, as well as on the Regional Oil Sands System; however, in 2011 such growth was partially offset by lower contributions from its Southern Lights and Spearhead pipelines as well as Feeder Pipelines and Other.

Liquids Pipelines earnings were impacted by the following non-recurring or non-operating adjusting items.

· Canadian Mainline earnings for 2011 included $14 million from the settlement of a shipper dispute related to oil measurement adjustments in prior years.

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· Canadian Mainline earnings for 2011 included a Line 9 tolling adjustment related to services provided in prior periods.

· Canadian Mainline earnings for 2011 reflected unrealized fair value losses on derivative financial instruments used to risk manage exposures inherent within the CTS, namely foreign exchange, power cost variability and allowance oil commodity prices.

· Regional Oil Sands System earnings for 2011 included the write-off of development expenditures on certain project assets.

· Cleanup and remediation costs related to a valve leak within the Enbridge Cheecham Terminal on the Regional Oil Sands System in January 2009.

· Spearhead Pipeline earnings included unrealized fair value gains on derivative financial instruments used to manage exposures to allowance oil commodity prices.

CANADIAN MAINLINE

The mainline system is comprised of Canadian Mainline and Lakehead System (the portion of the mainline in the United States that is operated by Enbridge and owned by EEP). Enbridge has operated, and frequently expanded, the mainline system since 1949. Through six adjacent pipelines with a combined capacity of approximately 2.5 million bpd, the system transports various grades of crude oil and diluted bitumen from western Canada to the midwest region of the United States and eastern Canada. Also included within the Canadian Mainline and located in eastern Canada are two crude oil pipelines and one refined products pipeline with a combined capacity of 0.4 million bpd.

Competitive Toll Settlement

On June 24, 2011, the NEB approved the 10-year CTS reached between Enbridge and shippers on its mainline system. The CTS, which took effect on July 1, 2011, covers local tolls, denominated in United States dollars, to be charged for service on the mainline system (with the exception of Lines 8 and 9). Under the terms of the CTS, the initial Canadian Local Toll (CLT), applicable to deliveries within western Canada, is based on the 2011 Incentive Tolling Settlement (ITS) toll and will be subsequently adjusted by 75% of the Canada Gross Domestic Product at Market Price Index, effective July 1 st, for each of the remaining nine years of the settlement. The CTS also provides for an International Joint Tariff (IJT) for crude oil shipments originating in Canada on the mainline system and delivered in the United States off the Lakehead System and into eastern Canada. The IJT, which is based on a fixed toll for the term of the settlement that was negotiated between Enbridge and shippers, will be adjusted annually by the same factor as the CLT. In other limited circumstances the shippers or Enbridge may elect to renegotiate the toll, including a shipper option to renegotiate if TransCanada’s Keystone XL pipeline project does not receive the required United States presidential permit by January 1, 2013. If a renegotiation of the toll is triggered, Enbridge and the shippers will meet and use reasonable efforts to agree on how the CTS can be amended to accommodate the event. Local tolls for service on the Lakehead System will not be affected by the CTS and will continue to be established by EEP’s existing toll agreements. To the extent the sum of the CLT and the Lakehead System local toll exceeds the IJT, the CLT will be adjusted to ensure the IJT is maintained. The IJT is designed to provide mainline shippers with a stable and competitive long-term toll, preserving and enhancing throughput on both the Canadian Mainline and Lakehead System. Although the Company may utilize derivative financial instruments to hedge foreign exchange rate risk on United States dollar denominated revenues and commodity price risk resulting from exposure to variable crude oil and power prices, earnings under the CTS are subject to variability in volume throughput, as well as capital and operating costs.

With NEB approval of the CTS, shippers who initiated the Alberta Clipper hearing request with the NEB formally withdraw their complaints and the hearing proceedings were terminated on July 7, 2011.

Incentive Tolling

Prior to the CTS taking effect, tolls on Canadian Mainline were governed by various agreements which were subject to NEB approval. These agreements included both the 2011 and 2010 ITS applicable to the Canadian Mainline (excluding Lines 8 and 9), the Terrace agreement, the SEP II Risk

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Sharing agreement, the Alberta Clipper agreement and the Southern Access Expansion agreement which were recovered via the Mainline Expansion Toll.

Results of Operations

Canadian Mainline adjusted earnings were $337 million for the year ended December 31, 2011 compared with $327 million for the year ended December 31, 2010.

As noted previously, effective July 1, 2011, Canadian Mainline earnings are governed by the CTS (with the exception of Lines 8 and 9) whereas earnings for the first six months of 2011 and for the year ended December 31, 2010 were governed by a series of agreements, the most significant being the ITS applicable to the mainline system and the Terrace and Alberta Clipper agreements. Earnings under the CTS are subject to variability in volume throughput and operating costs. Canadian Mainline volumes during the second half of 2011, for which the CTS was in effect, were higher than expected contributing to an increase in full year earnings relative to the prior year. The increased earnings contribution from volumes was partially offset by higher operating costs.

Supplemental information on Canadian Mainline adjusted earnings for the period from July 1, 2011, the date the CTS became effective, to December 31, 2011 is as follows.

|  | Six months ended December 31, 2011 |
(millions of Canadian dollars, unless otherwise noted) |  |  |
Revenues |  | 618 |
Expenses |  |  |
Operating and administrative |  | 189 |
Power |  | 54 |
Depreciation and amortization |  | 104 |
|  | 347 |
|  | 271 |
Other income |  | 5 |
Interest expense |  | (66 | )
|  | 210 |
Income taxes |  | (32 | )
Adjusted earnings |  | 178 |
IJT Benchmark Toll 1 (US dollars per barrel) |  | $3.85 |
Lakehead System Local Toll 2 (US dollars per barrel) |  | $2.01 |
Canadian Mainline IJT Residual Benchmark Toll 3 (US dollars per barrel) |  | $1.84 |
Effective United States dollar to Canadian dollar exchange rate 4 |  | 0.97 |
1 | The benchmark toll is per barrel of heavy crude oil transported from Hardisty, Alberta to Chicago, Illinois. A separate distance adjusted toll applies to shipments originating at receipt points other than Hardisty and lighter hydrocarbon liquids pay a lower toll than heavy crude oil.
2 | Per barrel of heavy crude oil transported from Neche, North Dakota to Chicago, Illinois.
3 | Per barrel of heavy crude oil transported from Hardisty to Gretna. The Canadian Mainline IJT residual toll for any shipment is the difference between the IJT toll for that shipment and the Lakehead System local toll for that shipment.
4 | Inclusive of realized gains or losses on foreign exchange derivative financial instruments.

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Throughput Volume 1

2011 |  | 2010
Q1 |  | Q2 |  | Q3 |  | Q4 |  | Total |  | Q1 |  | Q2 |  | Q3 |  | Q4 |  | Total |
1,602 |  | 1,457 |  | 1,565 |  | 1,594 |  | 1,554 |  | 1,515 |  | 1,629 |  | 1,468 |  | 1,537 |  | 1,537 |
1 | Throughput volume, presented in kbpd, represents mainline deliveries ex-Gretna, Manitoba and is exclusive of western Canadian deliveries and volumes originating at United States or eastern Canada locations.

Canadian Mainline revenues included the portion of the system covered by the CTS as well as revenues from Lines 8 and 9 in eastern Canada. Line 8 and Line 9 are currently tolled on a separate basis and comprise a relatively small proportion of total Canadian Mainline revenues. CTS revenues include transportation revenues, the largest component, as well as allowance oil and revenues from receipt and delivery charges. Transportation revenues include revenues for volumes delivered off the Canadian Mainline at Gretna and on to the Lakehead System, to which Canadian Mainline IJT residual benchmark tolls apply, and revenues for volumes delivered to other western Canada delivery points, to which the CLT applies. Despite the many factors which affect Canadian Mainline revenues, the primary determinants of those revenues will be throughput volume ex-Gretna, the United States dollar Canadian Mainline IJT residual benchmark toll applicable to those volumes and the effective foreign exchange rate at which resultant revenues are converted into Canadian dollars. The Company may utilize derivative financial instruments to hedge foreign exchange rate risk on United States dollar denominated revenues. The exact relationship between the primary determinants and actual Canadian Mainline revenues will vary somewhat from quarter to quarter but is expected to be relatively stable on average for a year, absent a systematic shift in receipt and delivery point mix or in crude oil type mix.

The largest components of operating and administrative expenses are employee related costs, pipeline integrity, repairs and maintenance, rents and leases and property taxes. Operating and administrative costs are relatively insensitive to throughput volumes. The primary drivers of future increases in operating costs are expected to be normal escalation in wage rates, prices for purchased services and tax rates, addition of new facilities and more extensive integrity and maintenance programs.

Power is the most significant variable operating cost and is subject to variations in operating conditions, including system configuration, pumping patterns and pressure requirements. However, the primary determinants of power cost are the level of power prices in various jurisdictions and throughput volume. The relationship of power consumption to throughput volume is expected to be roughly proportional over a moderate range of volumes. The Company may utilize derivative financial instruments to hedge power prices.

Depreciation and amortization expense will adjust over time as a result of changes in estimated depreciation rates and of additions to property, plant and equipment due to new facilities, as well as maintenance and integrity capital expenditures.

Canadian Mainline income taxes reflected current income taxes only. Under the CTS the Company retains the ability to recover future income taxes under an NEB order governing flow-through income tax treatment and, as such, an offsetting regulatory asset related to future income taxes is recognized as incurred.

The preceding financial overview includes expectations regarding future events and operating conditions that the Company believes are reasonable based on currently available information; however, such statements are not guarantees of future performance and are subject to change.

Prior to the implementation of the CTS, revenue on the Canadian Mainline was recognized in a manner consistent with the underlying agreements as approved by the regulator, in accordance with rate-regulated accounting. The Company discontinued the application of rate-regulated accounting to its Canadian Mainline (excluding Lines 8 and 9) on a prospective basis commencing July 1, 2011. The regulatory asset balance at the date of discontinuance related to tolling deferrals recognized in prior periods is being recovered through a surcharge to the CLT and IJT. While the CTS is based on previous

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tolling settlements and cost-of-service principles, earnings are subject to variability associated with throughput volume and capital and operating costs, subject to various protection mechanisms. As a result, the Canadian Mainline operations (excluding Lines 8 and 9) no longer meet all of the criteria required for the continued application of rate-regulated accounting treatment. The regulatory asset of approximately $470 million related to future income taxes recorded at the date of discontinuance will continue to be recognized as the Company retains the ability to recover future income taxes under an NEB order governing flow-through income tax treatment. In the same manner, the rate order provides for the recovery of future income taxes incurred subsequent to the date of discontinuance and, as such, regulatory assets related to future income taxes will continue to be recognized as incurred.

Canadian Mainline adjusted earnings were $327 million for the year ended December 31, 2010 compared with $295 million for the year ended December 31, 2009. The increase in adjusted earnings resulted from a higher Alberta Clipper contribution since entering service on April 1, 2010 and favourable operating performance. These positive factors were partially offset by higher taxes in the Terrace component.

REGIONAL OIL SANDS SYSTEM

Regional Oil Sands System includes two long haul pipelines, the Athabasca Pipeline and the Waupisoo Pipeline, as well as a variety of other facilities including the MacKay River, Christina Lake, Surmont and Long Lake facilities. It also includes Hardisty Caverns Limited Partnership (Hardisty Caverns), which provides storage service, and two large terminals: the Athabasca Terminal located north of Fort McMurray, Alberta and the Cheecham Terminal, located 95 kilometres (59 miles) south of Fort McMurray where the Waupisoo Pipeline initiates.

The Athabasca Pipeline is a 540-kilometre (335-mile) synthetic and heavy oil pipeline, built in 1999, that links the Athabasca oil sands in the Fort McMurray, Alberta region to a pipeline hub at Hardisty, Alberta. The Athabasca Pipeline has an ultimate design capacity of approximately 570,000 bpd, dependent on the viscosity of crude being shipped. It is currently configured to transport approximately 345,000 bpd.

The Company has a long-term (30-year) take-or-pay contract with the major shipper on the Athabasca Pipeline which commenced in 1999. Revenue is recorded based on the contract terms negotiated with the major shipper, rather than the cash tolls collected.

The Waupisoo Pipeline is a 380-kilometre (236-mile) synthetic and heavy oil pipeline that entered into service on May 31, 2008 and provides access to the Edmonton market for oil sands producers. The Waupisoo Pipeline initiates at Enbridge’s Cheecham Terminal and terminates at its Edmonton Mainline Terminal. The pipeline currently has a design capacity, dependent on crude slate, of up to 350,000 bpd, which can ultimately be expanded to 600,000 bpd.

Enbridge has a long-term (25-year) take-or-pay commitment with the four founding shippers on the Waupisoo Pipeline who collectively have contracted for approximately one-third of the initial capacity on the line. The associated revenues provide for a base return on equity (ROE) with significant upside potential as incremental founders and third party volumes are added.

In June 2010, the Company acquired the remaining 50% of the Hardisty Caverns previously owned by CCS Corporation for $52 million. The Hardisty Caverns facility, now wholly owned by Enbridge, also includes four salt caverns totaling 3.1 million barrels of capacity. The capacity at the facility is fully subscribed under long-term contracts that generate revenues from storage and terminaling fees.

Results of Operations

Adjusted earnings for the year ended December 31, 2011 were $110 million compared with $73 million for the year ended December 31, 2010 and $72 million for the year ended December 31, 2009. The increase in Regional Oil Sands System adjusted earnings reflected higher shipped volumes, increased tolls and the continued positive impact of terminal infrastructure additions. Adjusted earnings for 2011 also reflected lower depreciation expense due to extended estimated useful lives of certain assets reflecting increased probable reservoir supply and commercial viability.

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SOUTHERN LIGHTS PIPELINE

The 180,000 bpd, 20-inch diameter Southern Lights Pipeline was placed into service on July 1, 2010 transporting diluent from Chicago, Illinois to Edmonton, Alberta. Enbridge receives tariff revenues under long-term (15-year) contracts with committed shippers. Tariffs provide for recovery of all operating and debt financing costs plus a ROE of 10%. Uncommitted volumes, up to a specified amount, provide for tariff revenues that are fully credited to all shippers. Enbridge retains 25% of uncommitted tariff revenues on volumes above the specified amount, with the remainder being credited to shippers.

Both the Canadian and United States portions of the 2010, 2011 and 2012 rates for uncommitted shippers on Southern Lights Pipeline have been challenged. The Canadian Southern Lights toll hearing was held before NEB panel members in November 2011. On February 9, 2012, the NEB issued its decision rejecting the challenge from uncommitted shippers stating that tolls in place are just and reasonable. A Federal Energy Regulatory Commission (FERC) hearing was held in January 2012. Briefs will be filed February 27 and March 28, 2012 and an initial decision is expected on or before June 5, 2012. No material financial impact to the Company is anticipated to result from the FERC proceeding.

Results of Operations

Earnings for the year ended December 31, 2011 were $75 million compared with $82 million for the year ended December 31, 2010. Southern Lights Pipeline earnings for 2011 reflected a full year of in-service earnings. The decrease was primarily due to a decrease in leasing income from a pipeline which was transferred to the mainline system effective May 1, 2010.

Earnings for the year ended December 31, 2010 were $82 million compared with $58 million for the year ended December 31, 2009. Southern Lights Pipeline earnings for 2010 reflected operating earnings from its in-service date of July 1, 2010 in addition to allowance for equity funds used during construction (AEDC) recognized on a growing capital base while the project was under construction during the first six months of the year. The increase in 2010 earnings was partially offset by a decrease in earnings from the new light sour pipeline, which became operational during the first quarter of 2009 and was subsequently transferred to the mainline system effective May 1, 2010.

SPEARHEAD PIPELINE

Spearhead Pipeline delivers crude oil from Chicago, Illinois to Cushing, Oklahoma. The pipeline was originally placed into service in March 2006 and the Spearhead Pipeline Expansion was completed in May 2009. The expansion increased the capacity to Cushing from 125,000 bpd to 193,300 bpd from the new initiating point at Flanagan, Illinois.

Initial committed shippers and expansion shippers currently account for more than 70% of the 193,300 bpd capacity on Spearhead. Both the initial committed shippers and expansion shippers were required to enter into 10-year shipping commitments at negotiated rates that were offered during the open season process. The balance of the capacity is currently available to uncommitted shippers on a spot basis at FERC approved rates.

Results of Operations

Spearhead Pipeline adjusted earnings were $17 million for the year ended December 31, 2011 compared with $29 million for the year ended December 31, 2010. The decrease in Spearhead Pipeline adjusted earnings primarily reflected lower throughput volumes as a result of current market pricing dynamics at Cushing, Oklahoma, partially offset by the recognition of make-up rights which expired in the period.

Spearhead Pipeline adjusted earnings were $29 million for the year ended December 31, 2010 compared with $17 million for the year ended December 31, 2009. The earnings increase was due to a full year of higher volumes resulting from the expansion completed in May 2009. Earnings during 2010 were also positively impacted by the recognition of make-up rights which expired in the period, and lower operating costs.

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FEEDER PIPELINES AND OTHER

Feeder Pipelines and Other primarily includes the Company’s 85% interest in Olympic Pipe Line Company (Olympic Pipeline), the largest refined products pipeline in the State of Washington, transporting approximately 290,000 bpd of gasoline, diesel and jet fuel. It also includes the NW System, which transports crude oil from Norman Wells in the Northwest Territories (NWT) to Zama, Alberta; interests in a number of liquids pipelines in the United States; contract tankage facilities, including the Hardisty Contract Terminal, which is comprised of 19 tanks with a working capacity of approximately 7.5 million barrels of storage; and business development costs related to Liquids Pipelines activities.

Results of Operations

In 2011, Feeder Pipelines and Other incurred a loss of $3 million compared with earnings of $1 million in 2010 and earnings of $12 million in 2009. Earnings in 2011 primarily reflected an increase in business development costs which more than offset a higher contribution from Olympic Pipeline due to the Company’s increased ownership interest percentage, as well as a tariff increase and higher volumes.

The decrease in earnings from 2009 to 2010 was due to a number of small factors including a decrease in earnings from Toledo Pipeline due to the Line 6B shutdown and a decrease in earnings from Olympic Pipeline, as well as an increase in business development costs.

Norman Wells Pipeline Crude Oil Release

The Norman Wells Pipeline is a 12-inch, 39,400 bpd line transporting sweet crude oil that stretches 869 kilometres (540 miles) from Norman Wells, NWT to Zama, Alberta. 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, NWT. 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 reclamation work is anticipated to be completed in the summer of 2012. Monitoring of surface water and groundwater at the site will continue until remediation and reclamation goals have been achieved in accordance with plans filed with the regulator. Currently, Management does not believe this incident will have a material impact on the Company’s consolidated financial position or result of operations.

BUSINESS RISKS

The risks identified below are specific to the Liquids Pipelines business. General risks that affect the Company as a whole are described under Risk Management and Financial Instruments.

Supply and Demand

The profitability of the Company’s liquids pipelines depends to some extent on the volume of products transported on its pipeline systems. The volume of shipments depends primarily on the supply of, and demand for, crude oil and other liquid hydrocarbons from western Canada. Investment levels and related development activities by crude oil producers in conventional and oil sands production directly impacts the level of supply from the WCSB. Investment levels are influenced by crude oil producers’ expectations of crude oil and natural gas prices, future operating costs, United States demand and availability of markets for produced crude oil. Demand depends, among other things, on weather, gasoline price and consumption, manufacturing levels, alternative energy sources and global supply disruptions. Crude oil prices have been sustained at such levels that oil sands producers have recommenced projects that had been previously cancelled or deferred, creating increased demand in the WCSB for new pipeline infrastructure.

Volume Risk

A decrease in volumes transported by certain of the Company’s liquids pipelines, including the Company’s mainline system and the base Lakehead System owned by EEP, can directly and adversely affect revenues and results of operations. Shippers are not required to enter into long-term shipping commitments on Enbridge’s Canadian Mainline; rather, monthly volume nominations are accepted. A decline in volumes transported can be influenced by factors beyond the Company’s control, including

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competition, regulatory action, weather, storage levels, alternative energy sources, decreased demand, fluctuations in commodity prices, economic conditions, supply disruptions, availability of supply connected to the systems and adequacy of infrastructure to move supply into and out of the systems. The Company’s existing right-of-way for the Canadian Mainline provides a competitive advantage as it can be difficult and costly to obtain new rights of way for new pipelines. In addition, the CTS includes certain minimum threshold volumes to mitigate volume risk.

Market Price Risk

The replacement of the ITS agreement with the CTS agreement for the Company’s Canadian Mainline increases exposure to foreign exchange rates, commodity prices and interest rates. The most significant of these risks is foreign exchange as the Company’s International Joint Tolls under the CTS are charged in United States dollars. These risks have been substantially managed through the Company’s hedging program by using financial contracts to fix the prices of United States dollars, commodities and interest rates. Certain of these financial contracts do not qualify for cash flow hedge accounting and, therefore, the Company’s earnings are exposed to associated mark-to-market valuation changes.

Competition

Competition among existing pipelines is based primarily on the cost of transportation, access to supply, the quality and reliability of service, contract carrier alternatives and proximity to markets. Other competing carriers are available to ship western Canadian liquids hydrocarbons to markets in either Canada or the United States. Competition also arises from new pipeline proposals that provide access to market areas currently served by the Company’s liquids pipelines. One such competing project began commercial operations in early 2010 and serves markets at Wood River, Illinois and Cushing, Oklahoma. This pipeline has an initial capacity of 435,000 bpd and an ultimate stated capacity of 591,000 bpd. Commercial support has also been announced for the construction of additional ex-Alberta capacity of 500,000 bpd to Nederland, Texas, with an in-service date during 2015. Competing alternatives for delivering western Canadian liquid hydrocarbons into the United States or other markets could erode shipper support for current or future expansion. However, the Company believes that its liquids pipelines provide attractive options to producers in the WCSB due to its competitive tolls and multiple delivery and storage points. Increased competition could arise from new feeder systems servicing the same geographic regions as the Company’s feeder pipelines.

Potential Pressure Restrictions

The Company’s liquids systems consist of individual pipelines of varying ages. With appropriate inspection and maintenance, the physical life of a pipeline is indefinitely long; however, as pipelines age the level of expenditures required for inspection and maintenance may increase. Pressure restrictions may from time to time be established on the Company’s pipelines. Pressure restrictions reduce the available capacity of the applicable line segment and could result in a loss of throughput if and when the full capacity of that line segment would otherwise have been utilized. Certain of the Company’s liquids pipelines, including the Company’s Canadian Mainline, would be adversely affected by any pressure restrictions that do reduce volumes transported. Temporary pressure restrictions have been established on some sections of certain pipelines pending completion of specific inspection and repair programs.

Regulation

The Canadian Mainline and other liquids pipelines are subject to the actions of various regulators, including the NEB. Actions of the regulators related to tariffs, tolls and facilities impact earnings from those operations. The Company believes that regulatory risk is reduced through the negotiation of long-term agreements with shippers, such as the CTS, which govern the majority of the segment’s assets.

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GAS DISTRIBUTION

EARNINGS

|  | 2011 |  |  | 2010 |  |  | 2009 |
(millions of Canadian dollars) |  |  |  |  |  |  |  |  |
Enbridge Gas Distribution (EGD) |  | 137 |  |  | 135 |  |  | 129 |
Other Gas Distribution and Storage |  | 38 |  |  | 32 |  |  | 25 |
Adjusted earnings |  | 175 |  |  | 167 |  |  | 154 |
EGD - colder/(warmer) than normal weather |  | 1 |  |  | (12 | ) |  | 17 |
EGD - impact of tax rate changes |  | - |  |  | - |  |  | 21 |
EGD - interest income on GST refund |  | - |  |  | - |  |  | 7 |
Other Gas Distribution and Storage - asset impairment loss |  | - |  |  | - |  |  | (10 | )
Other Gas Distribution and Storage - adoption of new accounting |  |  |  |  |  |  |  |  |
standard |  | - |  |  | - |  |  | (3 | )
Earnings |  | 176 |  |  | 155 |  |  | 186 |

Adjusted earnings from Gas Distribution were $175 million for the year ended December 31, 2011 compared with $167 million for 2010 and $154 million for 2009. The increase in Gas Distribution adjusted earnings primarily resulted from continuing higher contributions from EGD under its Incentive Regulation (IR) arrangement and further growth in the Company’s other gas distribution businesses.

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

· | EGD earnings are adjusted to reflect the impact of weather.
· | In 2009, earnings from EGD reflected the impact of favourable tax rate changes.
· | Earnings from EGD for 2009 included interest income related to the recovery of excess GST remitted to Canada Revenue Agency.
· | Other Gas Distribution and Storage earnings for 2009 were impacted by an asset impairment loss which included goodwill.
· | Other Gas Distribution and Storage earnings for 2009 reflected the write-off of deferred development costs as a result of adopting a change in accounting standards, effective January 1, 2009.

ENBRIDGE GAS DISTRIBUTION

EGD is Canada’s largest natural gas distribution company and has been in operation for more than 160 years. It serves approximately 2 million customers in central and eastern Ontario and parts of northern New York State. EGD’s utility operations are regulated by the Ontario Energy Board (OEB) and by the New York State Public Service Commission.

Incentive Regulation

In 2007, the Company filed a rate application with the OEB requesting a revenue cap incentive rate mechanism calculated on a revenue per customer basis for the 2008 to 2012 period. The OEB approved the IR Settlement Agreement (the Settlement) with customer representatives.

The objectives of the Settlement are as follows:

· reduce regulatory costs;

· provide incentives for improved efficiency;

· provide more flexibility for utility management; and

· provide more stable rates to its customers.

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Under the Settlement, EGD is allowed to earn and fully retain 100 basis points (bps) over the base return. Any return over 100 bps must be shared with customers on an equal basis. EGD estimates the customer portion of 2011 earnings over the allowed threshold to be $14 million (2010 - $19 million). In preparation for the conclusion of the current IR term at the end of 2012, EGD filed a 2013 cost of service application, which they expect will be addressed by the OEB in 2012.

Rate Adjustment Applications

In September of each year, EGD files an application with the OEB to adjust rates for the next calendar year. Each of the 2012, 2011 and 2010 rate applications were filed pursuant to the approved IR formula. Out of the total distribution revenue applied for in the 2012 rate application, 98% was approved for recovery with the rate adjustment being effective January 1, 2012. The hearing with respect to the remaining 2% and related issues was held by the OEB in January 2012 with a decision expected in April 2012.

The total distribution revenue applied for in the 2011 rate application was approved by the OEB and the rate adjustment was effective January 1, 2011. In September 2009, EGD filed an application with the OEB to adjust rates for 2010 pursuant to the approved IR formula and to seek approval for specific changes to the Rate Handbook. Subsequent to filing a settlement agreement with ratepayer groups with the OEB, in March 2010, EGD received approval of a fiscal 2010 final rate order from the OEB. The 2010 final rate order approved the implementation of a rate change effective April 1, 2010, which enabled EGD to recover the approved revenues as if rates were effective January 1, 2010.

Results of Operations

Adjusted earnings for the year ended December 31, 2011 were $137 million compared with $135 million for the year ended December 31, 2010. The increase in EGD’s adjusted earnings was primarily due to customer growth, lower interest expense and lower taxes. These positive impacts were partially offset by higher customer support costs, as well as an increase in system integrity and employee related expenses. Depreciation expense also increased due to a higher overall asset base.

Adjusted earnings for the year ended December 31, 2010 were $135 million compared with $129 million for the year ended December 31, 2009. The increase in EGD adjusted earnings was primarily a result of continued favourable performance under IR, reflecting customer growth, higher distribution charges and lower taxes, partially offset by higher depreciation expense. Depreciation expense increased due to a higher overall asset base, including the implementation of a new customer billing system in late 2009.

Business Risks

The risks identified below are specific to EGD. General risks that affect the Company as a whole are described under Risk Management and Financial Instruments.

Regulatory Risk

The utility operations of EGD are regulated by the OEB. To the extent that the Regulator’s future actions are different from EGD’s current expectations, the timing and amount of recovery or refund of amounts recorded on the consolidated statement of financial position, or that would have been recorded on the consolidated statement of financial position in absence of the effects of regulation, could be different from the amounts that are eventually recovered or refunded.

The IR Framework permits EGD to recover, with OEB approval, certain costs that are beyond management control, but that are necessary for the maintenance of its services. The IR Framework also includes a mechanism to reassess the IR plan and return to cost of service if there are significant and unanticipated developments that threaten the sustainability of the IR plan. The above noted terms set out in the settlement mitigate EGD’s risk to factors beyond management’s control. The current IR Framework term expires after the rate year 2012.

Natural Gas Cost Risk

EGD does not profit from the sale of natural gas nor is it at risk for the difference between the actual cost of natural gas purchased and the price approved by the OEB. This difference is deferred as a receivable

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from or payable to customers until the OEB approves its refund or collection. EGD monitors the balance and its potential impact on customers and will request interim rate relief that will allow EGD to recover or refund the natural gas cost differential. EGD has a quarterly rate adjustment mechanism in place that allows for the quarterly adjustment of rates to reflect changes in natural gas prices. Adjustments are subject to prior approval by the OEB. However, the cost of natural gas does affect the amount of EGD’s investment in gas in storage.

Volume Risk

Since customers are billed on both a fixed charge and volumetric basis, EGD’s ability to collect its total IR formula revenue depends on achieving the forecast distribution volume established in the rate-making process. Under IR, volume forecasts are reviewed and approved by the OEB annually. The probability of realizing such volume is contingent upon four key forecast variables: weather, economic conditions, pricing of competitive energy sources and growth in the number of customers. Over the life of the current Settlement, the portion of fixed charges will increase annually thereby reducing this risk.

Weather is a significant driver of delivery volumes, given that a significant portion of EGD’s customer base uses natural gas for space heating. For the years ended December 31, 2011, 2010 and 2009, colder/(warmer) than normal weather resulted in an increase to earnings of $1 million, a reduction to earnings of $12 million and an increase to earnings of $17 million, respectively.

Distribution volume may also be impacted by the increased adoption of energy efficient technologies, along with more efficient building construction, that continues to place downward pressure on consumption. In addition, conservation efforts by customers further contribute to the decline in annual average consumption.

Sales and transportation of gas for customers in the residential and small commercial sectors account for approximately 80% (2010 - 80%; 2009 - 81%) of total distribution volume. Sales and transportation service to large volume commercial and industrial customers is more susceptible to prevailing economic conditions. As well, the pricing of competitive energy sources affects volume distributed to these sectors as some customers have the ability to switch to an alternate fuel. Customer additions are important to all market sectors as continued expansion adds to the total consumption of natural gas.

Even in those circumstances where EGD attains its total forecast distribution volume, it may not earn its expected ROE due to other forecast variables such as the mix between the higher margin residential and commercial sectors and the lower margin industrial sector.

This distribution volume risk for customers other than large volume transportation customers is mitigated by the average use true-up variance account that was established under the IR Framework. This variance account enables recovery from or repayment to customers of amounts representing variances in the actual and forecast average use by general service customers. EGD remains at risk from the variability of distribution volumes for large volume contract commercial and industrial customers.

OTHER GAS DISTRIBUTION AND STORAGE

Other Gas Distribution includes natural gas distribution utility operations in Quebec and New Brunswick, the most significant being Enbridge Gas New Brunswick (EGNB) (100% owned and operated by the Company), which owns the natural gas distribution franchise in the province of New Brunswick. EGNB is constructing a new distribution system and has approximately 11,000 customers. Approximately 790 kilometres (490 miles) of distribution main has been installed with the capability of attaching approximately 30,000 customers.

EGNB is regulated by the New Brunswick Energy and Utilities Board (EUB). As it is currently in the development period, EGNB’s cost of service exceeds its distribution revenues. The EUB had previously approved the deferral of the shortfall between distribution revenues and the cost of service during the development period for recovery in future rates. The recovery period is expected to commence at the end of the development period in 2013 and end no sooner than 2040. On December 31, 2011, the regulatory deferral asset was $180 million (2010 - $171 million).

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Enbridge Gas New Brunswick – Regulatory Matters

On December 9, 2011, the Government of New Brunswick tabled and subsequently passed legislation related to the regulatory process for setting rates for gas distribution within the province. The legislation permits 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. Significant details of the rate setting process were left to be established in the new regulations which have yet to be published.

As at December 31, 2011, the carrying value of EGNB’s regulatory asset and property, plant and equipment totaled $180 million and $264 million, respectively (2010 - $171 million and $254 million, respectively). Earnings from EGNB approximate $20 million per year. As the details of the regulations have not yet been made available, the effect of such regulations is not determinable as at February 21, 2012. While EGNB continues to engage in discussions with the province about the potential effect of the regulations, EGNB will preserve its legal rights.

Results of Operations

Other Gas Distribution and Storage adjusted earnings were $38 million for the year ended December 31, 2011 compared with $32 million for the year ended December 31, 2010 and $25 million for the year ended December 31, 2009, primarily due to an increased contribution from Enbridge’s Ontario unregulated gas storage business.

GAS PIPELINES, PROCESSING AND ENERGY SERVICES

EARNINGS

|  | 2011 |  |  | 2010 |  | 2009 |
(millions of Canadian dollars) |  |  |  |  |  |  |  |
Enbridge Offshore Pipelines (Offshore) |  | (7 | ) |  | 23 |  | 29 |
Alliance Pipeline US |  | 26 |  |  | 25 |  | 27 |
Vector Pipeline |  | 18 |  |  | 15 |  | 16 |
Aux Sable |  | 55 |  |  | 37 |  | 26 |
Energy Services |  | 55 |  |  | 20 |  | 29 |
Other |  | 16 |  |  | 3 |  | (11 | )
Adjusted earnings |  | 163 |  |  | 123 |  | 116 |
Offshore - property insurance recoveries from hurricanes |  | - |  |  | 2 |  | 4 |
Aux Sable - unrealized derivative fair value gains/(loss) |  | (7 | ) |  | 7 |  | (36 | )
Aux Sable - loan forgiveness |  | - |  |  | - |  | 7 |
Energy Services - unrealized derivative fair value gains/(loss) |  | 113 |  |  | (12 | ) | 3 |
Energy Services - Lehman and SemGroup credit recovery |  | - |  |  | 1 |  | 1 |
Other - unrealized derivative fair value gains |  | 24 |  |  | - |  | - |
Other - gain on sale of investments |  | - |  |  | - |  | 329 |
Other - impact of tax rate changes |  | - |  |  | - |  | 4 |
Earnings |  | 293 |  |  | 121 |  | 428 |

Adjusted earnings from Gas Pipelines, Processing and Energy Services were $163 million for the year ended December 31, 2011 compared with $123 million for the year ended December 31, 2010. The increase was primarily due to higher adjusted earnings from Aux Sable, Energy Services and Other, which includes the Company’s green energy projects, partially offset by losses in Offshore.

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Adjusted earnings were $123 million for the year ended December 31, 2010 compared with $116 million for the year ended December 31, 2009. The increase resulted from improved contributions from Aux Sable and new green energy investments.

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

· Offshore earnings for 2010 and 2009 included insurance proceeds related to the replacement of damaged infrastructure as a result of a 2008 hurricane.

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

· Earnings for the year ended December 31, 2009 from Aux Sable reflected a gain from a loan forgiveness related to a negotiated settlement with a counterparty in bankruptcy proceedings.

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

· Energy Services earnings for 2010 and 2009 included partial recoveries from the sale of its receivable from Lehman Brothers and from SemGroup.

· Other earnings for 2011 reflected unrealized fair value changes on derivative financial instruments.

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

· Other earnings for 2009 reflected the impact of favourable tax rate changes.

ENBRIDGE OFFSHORE PIPELINE

Offshore is comprised of 13 natural gas gathering and FERC-regulated transmission pipelines and one oil pipeline with a capacity of 60,000 bpd, in five major corridors in the Gulf of Mexico, extending to deepwater developments. These pipelines include almost 2,400 kilometres (1,500 miles) of underwater pipe and onshore facilities with total capacity of approximately 7.2 bcf/d. Offshore currently moves approximately 40% of offshore deepwater gas production through its systems in the Gulf of Mexico.

Transportation Contracts

The primary shippers on the Offshore systems are producers who execute life-of-lease commitments in connection with transmission and gathering service contracts. In exchange, Offshore provides firm capacity for the contract term at an agreed upon rate. The firm capacity made available generally reflects the lease’s maximum sustainable production. The transportation contracts allow the shippers to define a maximum daily quantity (MDQ), which corresponds with the expected production life. The contracts typically have minimum throughput volumes which are subject to take-or-pay criteria, but also provide the shippers with flexibility, subject to advance notice criteria, to modify the projected MDQ schedule to match current delivery expectations. The majority of long-term transport rates are market-based, with revenue generation directly tied to actual production deliveries. Some of the systems operate under a cost-of-service methodology while others have minimum take-or-pay obligations.

The business model utilized on a go forward basis and included in the WRGGS, Big Foot and Venice commercially secured projects differs from the historic model. These new projects have a base level return which is locked in through take or pay commitments. If volumes reach producer anticipated levels the return on these projects will increase. In addition, Enbridge has minimal capital cost risk on these projects and commercial agreements continue to contain life-of-lease commitments. The WRGGS and Big Foot project agreements provide for recovery of actual capital costs to complete the project in fees payable by producers over the contract term. The Venice project provides for a capital cost risk sharing mechanism, whereby Enbridge is exposed to a portion of the capital costs in excess of an agreed upon target. Conversely, Enbridge can recover in fees from producers a portion of the capital cost savings below the agreed upon target.

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Results of Operations

For the year ended December 31, 2011, Offshore incurred a loss of $7 million compared with adjusted earnings of $23 million for the year ended December 31, 2010. The decrease in Offshore adjusted earnings reflected continued volume declines due to the slower regulatory permitting process and delayed drilling programs by producers. Increased operating and administrative costs, including higher insurance premiums and employee benefits, as well as increased depreciation expense, also contributed to the decrease in earnings from the prior year.

Adjusted earnings from Offshore for the year ended December 31, 2010 were $23 million compared with $29 million for the year ended December 31, 2009. The Company experienced volume declines due to the slower regulatory permitting process. In July 2010, the Secretary of the Interior suspended deepwater drilling in the Gulf of Mexico. Subsequently, in October 2010, the deepwater drilling suspension was lifted, allowing a return to deepwater drilling, but subject to increased regulation and approval. Other factors contributing to the adjusted earnings decrease were higher operating and administrative costs, including insurance and higher depreciation expense.

Business Risks

The risks identified below are specific to Offshore. General risks that affect the Company as a whole are described under Risk Management and Financial Instruments.

Weather

Adverse weather, such as hurricanes, may impact Offshore’s financial performance directly or indirectly. Direct impacts may include damage to Offshore facilities resulting in lower throughput, as well as inspection and repair costs. Indirect impacts may include damage to third party production platforms, onshore processing plants and pipelines that may decrease throughput on Offshore systems. Effective June 2011, Offshore’s insurance policy includes specific coverage related to named windstorms, such as hurricanes, for all systems. The occurrence of hurricanes in the United States Gulf Coast increases the cost and availability of insurance coverage, so Enbridge may not be able, or may choose not, to insure against this risk in the future.

Competition

There is competition for new and existing business in the Gulf of Mexico. Offshore has been able to capture key opportunities, allowing it to more fully utilize existing capacity. Offshore’s gas pipelines serve a majority of the strategically located deepwater host platforms, positioning it favourably to make incremental investments for new platform connections and receive additional transportation volumes from sub-sea development of smaller fields tied back to existing host platforms. Offshore is also able to construct pipelines to transport crude oil, diversifying the risk of declining gas production, as demonstrated with the Neptune crude oil lateral and the planned Big Foot. Given rates of decline, offshore pipelines typically have available capacity, resulting in significant competition for new developments in the Gulf of Mexico.

Supply and Demand

Low natural gas prices, in part due to the prevalence of shale gas, have resulted in reduced investment in exploration activities and producing infrastructure. Offshore diversifies its risk of declining gas production through the construction of crude oil pipelines as noted above.

Regulation

The transportation rates on many of Offshore’s transmission pipelines are generally based on a regulated cost of service methodology and are subject to regulation by the FERC. These rates are subject to challenge from time-to-time.

The Macondo oil spill in 2010 has altered the offshore regulatory environment. Although the moratorium on deepwater drilling was lifted, future deepwater drilling activity will be subject to heightened regulation and oversight. Increased regulation may impact the levels and timing of future exploration and drilling activity in the region and the resultant production volumes available to ship on the Offshore system. The shifting business environment could result in increases in available capacity, resulting in heightened

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competition.

Other Risks

Other risks directly impacting financial performance include underperformance relative to expected reservoir production rates, delays in project start-up timing, changes in plans by shippers and capital expenditures in excess of those estimated. Capital risk is mitigated in some circumstances by having area producers as joint venture partners or through cost of service tolling arrangements or other pre-arranged terms in commercial agreements. Start-up delays are mitigated by the right to collect stand-by fees.

ALLIANCE PIPELINE US

The Alliance System (Alliance), which includes both the Canadian and United States portions of the pipeline system, consists of an approximately 3,000-kilometre (1,864-mile) integrated, high-pressure natural gas transmission pipeline system and an approximately 730-kilometre (454-mile) lateral pipeline system and related infrastructure. Alliance transports liquids-rich natural gas from northeast British Columbia, northwest Alberta and the Bakken area in North Dakota to Channahon, Illinois. Alliance Pipeline US and Alliance Pipeline Canada have firm service shipping contract capacity to deliver 1.405 bcf/d and 1.325 bcf/d, respectively. Enbridge owns 50% of Alliance Pipeline US, while the Fund, described under Sponsored Investments, owns 50% of Alliance Pipeline Canada.

Alliance connects with Aux Sable, (of which Enbridge owns 42.7%), an NGL extraction and fractionation facility in Channahon, Illinois. The natural gas may then be transported to two local natural gas distribution systems in the Chicago area and five interstate natural gas pipelines, providing shippers with access to natural gas markets in the midwestern and northeastern United States and eastern Canada. Alliance Pipeline US is adjacent to the Bakken oil formation in North Dakota which offers new incremental sources of liquids-rich natural gas for delivery to downstream markets. In February 2010, a new receipt point on the pipeline near Towner, North Dakota was placed into service. The receipt point connects to the Prairie Rose Pipeline, which initially provided access to a shipper operating out of the Bakken formation with firm transportation contract for an initial contract capacity of 40 mmcf/d under a 10-year contract. An additional 40 mmcf/d of firm transportation capacity at this same receipt point became effective February 2011. The Prairie Rose Pipeline was acquired by Aux Sable in 2011.

Transportation Contracts

Alliance Pipeline US has long-term, take-or-pay contracts to transport substantially all its 1.405 bcf/d of natural gas capacity with terms ending on December 1, 2015. A small percentage of natural gas is being contracted on a short-term basis with an annual renewal option. These contracts permit Alliance Pipeline US, whose operations are regulated by the FERC, to recover the cost of service, which includes operating and maintenance costs, the cost of financing, an allowance for income tax, an annual allowance for depreciation and an allowed ROE of 10.88%.

Depreciation expense included in the cost of service is based on negotiated depreciation rates contained in the transportation contracts, while depreciation expense under Canadian GAAP is recorded on a straight-line basis at 4% per annum. Negotiated depreciation expense is generally less than the Canadian GAAP amount at the beginning of the contract and higher than straight-line depreciation in the later years of the shipper transportation agreements. This difference results in recognition of a long-term receivable, referred to as deferred transportation revenue, which began being recovered from shippers starting in 2009 for Alliance Pipeline US and in 2012 for Alliance Pipeline Canada. As at December 31, 2011, $103 million (US$101 million) (2010 - $122 million (US$123 million)) was recorded as Enbridge’s share of deferred transportation revenue for Alliance Pipeline US.

Results of Operations

Alliance Pipeline US earnings were $26 million for the year ended December 31, 2011 comparable with $25 million for the year ended December 31, 2010 and $27 million for the year ended December 31, 2009.

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VECTOR PIPELINE

The Vector Pipeline (Vector) system, which includes both the Canadian and United States portions of the pipeline system, consists of 560 kilometres (348 miles) of mainline natural gas transmission pipeline between the Chicago, Illinois hub and the storage complex at Dawn, Ontario. Vector’s primary sources of supply are through interconnections with Alliance and the Northern Border Pipeline in Joliet, Illinois. Vector has the capacity to deliver a nominal 1.3 bcf/d and is operating at or near capacity. The Company provides operating services to and holds a 60% joint venture interest in Vector.

Transportation Contracts

The total long haul capacity of Vector is approximately 87% committed through 2015. Approximately 55% of the long haul capacity is committed through firm transportation contracts at rates negotiated with the shippers and approved by the FERC, while the remaining committed capacity is sold at market rates. Transportation service is provided through a number of different forms of service agreements such as Firm Transportation Service and Interruptible Transportation Service. Vector is an interstate natural gas pipeline with FERC and NEB approved tariffs that establish the rates, terms and conditions governing its service to customers. On the United States portion of Vector, tariff rates are determined using a cost of service methodology and tariff changes may only be implemented upon approval by the FERC. For 2011, the FERC approved maximum tariff rates include an underlying weighted average after-tax ROE component of 11.18% (2010 - 11.18%; 2009 - 11.07%). On the Canadian portion, Vector is required to file its negotiated tolls calculation with the NEB on an annual basis. Tolls are calculated on a levelized basis that include a rate of return incentive mechanism based on construction costs and are subject to a rate cap. In 2011, maximum tariff tolls include a ROE component of 10.48% after-tax.

Depreciation expense prescribed in the negotiated transportation contracts is different than the depreciation expense used for financial statement purposes. Negotiated depreciation expense is less than the financial statement amount at the beginning of the contract and higher than the financial statement amount in the later years of the negotiated transportation contracts. This difference results in the recognition of a long-term receivable, referred to as unbilled transportation revenue, which began to be recovered from shippers in 2008 for Vector US and 2006 for Vector Canada. As at December 31, 2011 $21 million (US$21 million) (2010 - $27 million (US$27 million)) was recorded as Enbridge’s share of unbilled transportation revenue for Vector.

Results of Operations

Vector Pipeline earnings were $18 million for the year ended December 31, 2011 comparable with $15 million for the year ended December 31, 2010 and $16 million for the year ended December 31, 2009.

Business Risks

The risks identified below are specific to both Alliance Pipeline US and Vector. General risks that affect the entire Company are described under Risk Management and Financial Instruments.

Supply and Demand

Currently, natural gas pipeline capacity out of the WCSB exceeds supply. Alliance Pipeline US and Vector have been unaffected by this excess capacity environment mainly because of long-term capacity contracts extending primarily to 2015; however, excess capacity could negatively impact re-contracting beyond this term. Re-contracting risk is mitigated to some extent as Alliance Pipeline US is well positioned to deliver incremental liquids-rich gas production from new developments in the Montney and Bakken regions. Alliance Pipeline US is also engaged with market participants in developing new receipt facilities and services to expand its reach in transporting liquids-rich gas to premium markets. In addition, Aux Sable, through its participation in midstream businesses upstream of Alliance Pipeline US, attracts liquids-rich gas to Alliance Pipeline US by offering incremental value for producers’ NGL. Vector’s interruptible capacity could be negatively impacted by the basis (location) differential in the price of natural gas between Chicago, Illinois and Dawn, Ontario relative to the transportation toll.

Competition

Alliance Pipeline US faces competition for pipeline transportation services to the Chicago area from both existing and proposed pipeline projects. Competing pipelines provide natural gas transportation services

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from the WCSB and the Bakken to natural gas markets in the midwestern United States. In addition, there are several proposals to upgrade existing pipelines or to build new pipelines serving these markets. Any new or upgraded pipelines could either allow shippers greater access to natural gas markets or offer natural gas transportation services that are more desirable than those provided by Alliance Pipeline US because of location, facilities or other factors. In addition, these pipelines could charge rates or provide transportation services to locations that result in greater net profit for shippers, with the effect of forcing Alliance Pipeline US to realize lower revenues and cash flows. Shippers on Alliance Pipeline US have access to additional high compression delivery capacity at no additional cost, other than fuel requirements, serving to enhance the competitive position of Alliance Pipeline US.

Vector faces competition for pipeline transportation services to its delivery points from new supply sources and traditional low cost pipelines, which could offer transportation that is more desirable to shippers because of cost, supply location, facilities or other factors. Vector has mitigated this risk by entering into long-term firm transportation contracts, which expire starting in November 2015, for approximately 87% of its capacity. The remaining contracts expire at various times starting in April 2012. Certain long-term firm contracts (55% of capacity) provide for additional compensation to Vector if shippers do not extend their contracts beyond the initial term ending November 2015. The effectiveness of these mitigating factors is evidenced by the increased utilization of the pipeline since its construction, despite the presence of transportation alternatives.

Vector and Alliance Pipelines also face potential competition from new sources of natural gas such as the Marcellus shale formation, which is among the largest gas play in North America. The Marcellus shale formation is in close proximity to the Chicago Hub. The development of the Marcellus shale formation could provide an alternate source of gas to the Chicago Hub as well as decrease the northeastern region of the United States’ reliance on natural gas imports from Canada.

Regulation

Both the United States portion of Vector and Alliance Pipeline US operations are subject to regulation by the FERC. If tariff rates are protested, the timing and amount of recovery or refund of amounts recorded on the consolidated statement of financial position could be different from the amounts that are eventually recovered or refunded. In addition, future profitability of the entities could be negatively impacted. On a yearly basis, following consultation with shippers, Alliance Pipeline US files its annual rates with the FERC for approval.

FERC has intensified its oversight of financial reporting, risk standards and affiliate rules and has issued new standards on managing gas pipeline integrity. The Company continues ongoing dialogue with regulatory agencies and participates in industry lobby groups to ensure it is informed of emerging issues in a timely manner.

AUX SABLE

Enbridge owns 42.7% of Aux Sable, an NGL extraction and fractionation business, which owns and operates a plant near Chicago, Illinois at the terminus of Alliance. The plant extracts NGLs from the liquids-rich natural gas transported on Alliance, as necessary to meet gas quality specifications of downstream transmission and distribution companies and to take advantage of positive fractionation spreads.

Aux Sable sells its NGL production to BP under a long-term contract. BP pays Aux Sable a fixed annual fee and a share of any net margin generated from the business in excess of specified natural gas processing margin thresholds (the upside sharing mechanism). In addition, BP compensates Aux Sable for all operating, maintenance and capital costs associated with the Aux Sable facilities subject to certain limits on capital costs. BP supplies, at its cost, all make-up gas and fuel gas requirements of the Aux Sable plant and pays market rates for the capacity on the Alliance Pipeline held by an Aux Sable affiliate. The BP agreement is for an initial term of 20 years, expiring March 31, 2026, and may be extended by mutual agreement for 10-year terms.

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Aux Sable also owns and operates facilities upstream of the Alliance Pipeline that deliver liquids-rich gas volumes into the pipeline for further processing at the Aux Sable plant. These facilities include the Prairie Rose Pipeline and the Palermo Conditioning Plant in the Bakken area of North Dakota and the Septimus Gas Plant and the Septimus Pipeline in the Montney area of British Columbia.

Results of Operations

Aux Sable adjusted earnings were $55 million for the year ended December 31, 2011 compared with $37 million for the year ended December 31, 2010. Aux Sable adjusted earnings increased primarily due to stronger realized fractionation margins which resulted in higher contributions from the upside sharing mechanism in its production sales agreement, as well as increased earnings contribution from new assets including Septimus Pipeline and Gas Plant, Prairie Rose Pipeline and Palermo Conditioning Plant.

Aux Sable adjusted earnings increased from $26 million in 2009 to $37 million in 2010 primarily due to enhanced plant performance and stronger fractionation margins.

ENERGY SERVICES

Energy Services provides energy supply and marketing services to North American refiners, producers and other customers. Crude oil and NGL marketing services are provided by Tidal Energy. This business transacts at many North American market hubs and provides its customers with various services, including transportation, storage, supply management, flexible pricing, hedging programs and product exchanges. Tidal Energy is primarily a physical barrel marketing company and in the course of its market activities can create commodity exposures. Any residual open positions created from this physical business are closely monitored and must comply with the Company’s formal risk management policies.

Natural gas marketing services are provided by Tidal Energy and Gas Services. Tidal Energy markets natural gas to optimize Enbridge’s commitments on the Alliance and Vector pipelines. Capacity commitments at December 31, 2011 and 2010 were 30 mmcf/d on Alliance and 156 mmcf/d on Vector. Earnings from these commitments are dependent upon the basis (location) differentials between Alberta and Chicago, Illinois for Alliance, and between Chicago and Dawn, Ontario for Vector. To the extent transportation costs exceed the basis (location) differential, earnings will be negatively affected. Tidal Energy also provides fee-for-service arrangements for third parties, leveraging its natural gas marketing expertise and access to transportation capacity. Gas Services markets natural gas to commercial and industrial customers in the upper mid-west area of the United States.

Results of Operations

Energy Services adjusted earnings were $55 million for the year ended December 31, 2011 compared with $20 million for the year ended December 31, 2010. This increase was primarily attributable to crude oil marketing strategies designed to capture basis (location) differentials and tank management revenue when opportunities arise. Energy Services employs such strategies in compliance with and under the oversight of the Company’s formal risk management policies and procedures. Partially offsetting positive earnings contributions from crude oil services were declines in natural gas marketing due to narrower natural gas basis (location) spreads, which impact the Company’s merchant capacity on certain natural gas pipelines. Earnings from Energy Services are dependent on market conditions, including but not limited to, location and grade basis spreads, and may not be indicative of results to be achieved in future periods.

Energy Services adjusted earnings decreased to $20 million for the year ended December 31, 2010 from $29 million in 2009 as a result of reduced volume and margin opportunities in liquids marketing.

OTHER

Other includes operating results from the Company’s investments in green energy projects, net of business development expenses associated with international and Canadian gas activities.

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In October 2011, ownership of the Sarnia Solar, Ontario Wind and Talbot Wind energy projects was transferred to the Fund. Effective October 21, 2011, earnings contributions from these assets, net of noncontrolling interest, will be reflected within the Sponsored Investments segment. Green energy projects remaining in the Gas Pipelines, Processing and Energy Services segment include Greenwich Wind Energy, Cedar Point Wind Energy, Amherstburg Solar and Tilbury Solar.

In 2009, the Company sold its 24.7% interest in OCENSA, a crude oil export pipeline in Colombia. This investment was sold at a very attractive price and proceeds were utilized in the funding of the North American expansion projects discussed earlier. There are currently minimal operations in International; however, Enbridge continues to actively monitor the international business environment to identify potential new investment opportunities.

Results of Operations

Other adjusted earnings for the year ended December 31, 2011 were $16 million compared with $3 million for the year ended December 31, 2010 and an adjusted loss of $11 million for the year ended December 31, 2009. The increase reflected strong contributions primarily from the Sarnia Solar expansion and Talbot Wind Energy Project, both of which were completed in the latter part of 2010. In addition, adjusted earnings from 2011 reflected several newly constructed green energy projects, including Cedar Point Wind Energy, Greenwich Wind Energy and Amherstburg Solar.

SPONSORED INVESTMENTS

EARNINGS

|  | 2011 |  | 2010 |  | 2009 |
(millions of Canadian dollars) |  |  |  |  |  |  |
Enbridge Energy Partners (EEP) |  | 152 |  | 122 |  | 99 |
Enbridge Energy, Limited Partnership - Alberta Clipper US (EELP) |  | 42 |  | 42 |  | 7 |
Enbridge Income Fund (the Fund) |  | 59 |  | 45 |  | 45 |
Adjusted Earnings |  | 253 |  | 209 |  | 151 |
EEP - leak insurance recoveries |  | 50 |  | - |  | - |
EEP - leak remediation costs and lost revenue |  | (33) |  | (106) |  | - |
EEP - unrealized derivative fair value gains/(loss) |  | 3 |  | (1) |  | (2) |
EEP - NGL trucking and marketing prior period adjustment |  | (3) |  | - |  | - |
EEP - shipper dispute settlement |  | 8 |  | - |  | - |
EEP - lawsuit settlement |  | 1 |  | - |  | - |
EEP - impact of unusual weather conditions |  | (1) |  | - |  | - |
EEP - Lakehead System billing correction |  | - |  | 1 |  | 4 |
EEP - dilution gain on Class A unit issuance |  | 66 |  | 36 |  | - |
EEP - asset impairment loss |  | - |  | (2) |  | (12) |
Earnings |  | 344 |  | 137 |  | 141 |

Adjusted earnings from Sponsored Investments were $253 million for the year ended December 31, 2011 compared with $209 million for the year ended December 31, 2010. The increase in adjusted earnings resulted from increased contributions from both EEP and the Fund.

Adjusted earnings from Sponsored Investments were $209 million for the year ended December 31, 2010 compared with $151 million in 2009. The increase in adjusted earnings resulted primarily from increased contributions from EEP as a result of positive operating factors, including growth projects, as well as the Company’s investment in EELP.

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

· EEP 2011 earnings included insurance recoveries associated with the Line 6B crude oil release. See EEP Lakehead System Line 6A and 6B Crude Oil Releases.

· Earnings from EEP for 2011 and 2010 included a charge related to estimated costs, before insurance recoveries, associated with the Line 6A and 6B crude oil releases. EEP earnings from 2010 also included a charge of $3 million (net to Enbridge) related to lost revenue as a result of the crude oil releases. See EEP Lakehead System Line 6A and 6B Crude Oil Releases.

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

· Earnings from EEP included an unfavourable prior period adjustment related to NGL trucking and marketing.

· EEP earnings for 2011 included proceeds from the settlement of a shipper dispute related to oil measurement adjustments in prior years.

· EEP earnings for 2011 included proceeds related to the settlement of a lawsuit during the first quarter.

· EEP earnings for 2011 included an unfavourable effect related to decreased volumes due to uncharacteristically cold weather in February 2011 that disrupted normal operations.

· EEP earnings for 2010 and 2009 included Lakehead System billing corrections.

· EEP 2011 and 2010 earnings included dilution gains (after tax and noncontrolling interest) as Enbridge did not fully participate in EEP’s issuances of Class A units.

· EEP earnings for 2010 and 2009 included charges related to asset impairment losses.

ENBRIDGE ENERGY PARTNERS

EEP owns and operates crude oil and liquid petroleum transportation and storage assets and natural gas and NGL gathering, treating, processing, transportation and marketing assets in the United States. Significant assets include the Lakehead System, which is the extension of the Canadian Mainline in the United States, the Mid-Continent crude oil system consisting of an interstate crude oil pipeline and storage facilities, a crude oil gathering system and interstate pipeline system in North Dakota and natural gas assets located primarily in Texas. Subsidiaries of Enbridge provide services to EEP in connection with the operation of its liquids assets, including the Lakehead System.

In September 2010, EEP acquired the entities that comprise the Elk City System from Atlas Pipeline Partners for US$686 million. The Elk City System extends from southwestern Oklahoma to Hemphill County in the Texas Panhandle and consists of approximately 1,290 kilometres (800 miles) of natural gas gathering and transportation pipelines, one carbon dioxide treating plant and three cryogenic processing plants with a total capacity of 370 mmcf/d and a combined NGL production capability of 20,000 bpd. The acquisition of the Elk City System complements EEP’s existing Anadarko natural gas system by providing additional processing capacity and expansion capability.

Ownership Interest

Enbridge’s ownership interest in EEP is impacted by EEP’s issuance and sale of its Class A common units. To the extent Enbridge does not fully participate in these offerings, the Company’s ownership interest in EEP is reduced. At December 31, 2011, Enbridge’s ownership interest in EEP was 23.0% (2010 - 25.5%; 2009 - 27.0%). The Company’s average ownership interest in EEP during 2011 was 24.4% (2010 - 26.7%; 2009 - 27.0%).

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Distributions

EEP makes quarterly distributions of its available cash to its common unitholders. Under the Partnership Agreement, Enbridge Energy Company, Inc. (EECI), a wholly owned subsidiary of Enbridge, as general partner (GP), receives incremental incentive cash distributions, which represent incentive income on the portion of cash distributions (on a per unit basis) that exceed certain target thresholds as follows:

|  | Unitholders including Enbridge |  | GP Interest |
Quarterly cash distributions per unit 1: |  |  |  |  |
Up to $0.295 per unit |  | 98% |  | 2% |
First target - $0.295 per unit up to $0.350 per unit |  | 85% |  | 15% |
Second target - $0.350 per unit up to $0.495 per unit |  | 75% |  | 25% |
Over second target - cash distributions greater than $0.495 per unit |  | 50% |  | 50% |

1 Distributions restated to reflect EEP’s two-for-one stock split which was effective April 2011.

In 2009, EEP paid a quarterly distribution of $0.495 per unit to its common unitholders. This quarterly distribution remained in effect through the first quarter of 2010 when, effective April 2010, EEP increased it to $0.50125 per unit. In July 2010, EEP further increased its quarterly distribution to $0.51375 per unit and in July 2011 the quarterly distribution was increased to $0.5325. Of the $152 million Enbridge recognized as adjusted earnings from EEP during 2011, $46 million (2010 - $33 million; 2009 - $27 million) were GP incentive earnings, while the remainder was Enbridge’s limited partner share of EEP’s earnings.

Results of Operations

After adjusting EEP earnings for non-recurring or non-operating items, including the impact of the 2010 Line 6A and Line 6B crude oil releases, EEP adjusted earnings increased to $152 million for the year ended December 31, 2011 compared with $122 million for the year ended December 31, 2010. The increase was primarily attributable to strong results from its natural gas business as a result of higher natural gas and NGL volumes, including those associated with the acquisition of the Elk City System in September 2010, as well as higher general partner incentive income. Increased volumes in liquids pipelines and a full year contribution from Alberta Clipper also drove higher earnings in 2011. These positive factors were partially offset by an increase in operating and administrative costs and higher financing costs.

EEP adjusted earnings were $122 million for the year ended December 31, 2010 compared with $99 million for the year ended December 31, 2009. The increase was largely attributable to strong results from the liquids business as well as higher incentive income. The liquids improvement was generated largely from higher delivered volumes and increased average transportation rates, partially offset by increased operating costs.

EEP Lakehead System Line 6A and 6B Crude Oil Releases

Line 6B Crude Oil Release

On July 26, 2010, a release of crude oil on Line 6B of EEP’s Lakehead System was reported near Marshall, Michigan. EEP estimates that approximately 20,000 barrels of crude oil were leaked at the site, a portion of which reached the Talmadge Creek, a waterway that feeds the Kalamazoo River. The pipelines in the vicinity were shut down, appropriate United States federal, state and local officials were notified and emergency response crews were dispatched to oversee containment of the released crude oil and cleanup of the affected areas. The released crude oil affected approximately 61 kilometres (38 miles) of area along the Talmadge Creek and Kalamazoo River waterways, including residential areas, businesses, farmland and marshland between Marshall and downstream of Battle Creek, Michigan. The cause of the release remains the subject of an investigation by the National Transportation Safety Board and other United States federal and state regulatory agencies.

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Pursuant to an administrative order issued by the Environmental Protection Agency (EPA) under the United States Clean Water Act, EEP was directed to clean up the released oil and remediate and restore the affected areas – a process EEP had begun upon discovering the release.

As at December 31, 2010, EEP estimated that before insurance recoveries, and not including fines and penalties, costs of approximately US$550 million ($96 million after-tax net to Enbridge), excluding lost revenue of approximately US$13 million ($2 million after-tax net to Enbridge), would be incurred in connection with this incident. These costs included emergency response, environmental remediation and cleanup activities associated with the crude oil release, as well as potential claims by third parties.

As at December 31, 2011, EEP revised its total estimate for this crude oil release to US$765 million ($129 million after-tax net to Enbridge), an increase of US$215 million ($33 million after-tax net to Enbridge) from December 31, 2010. The change in estimate was primarily based on a review of costs and commitments incurred, and additional information concerning the reassessment of the overall monitoring area, related cleanup, including submerged oil recovery operations, and remediation activities, including the estimated costs related to the additional scope of work set forth in its response to the directive it submitted to the EPA on October 20, 2011. During the fourth quarter of 2011, EEP resubmitted a revised work plan which was approved by the EPA on December 19, 2011.

EEP continues to make progress on the cleanup, remediation and restoration of the areas affected by the Line 6B crude oil release. All of the initiatives EEP undertakes in the monitoring and restoration phases are intended to restore the crude oil release area to the satisfaction of the appropriate regulatory authorities.

Expected losses associated with the Line 6B crude oil release include those costs that are considered probable and that could be reasonably estimated at December 31, 2011. The estimates do not include amounts capitalized or any fines, penalties or claims associated with the release that may later become evident and are before insurance recoveries. Despite the efforts EEP has made to ensure the reasonableness of its estimates, changes to the recorded amounts associated with this release are possible as more reliable information becomes available. 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 as well as expenditures associated with litigation and settlement of claims.

Line 6A Crude Oil Release

A crude oil release from Line 6A of EEP’s Lakehead System was reported in an industrial area of Romeoville, Illinois on September 9, 2010. The pipeline in the vicinity was immediately shut down and emergency response crews were dispatched to oversee containment, cleanup and replacement of the pipeline segment. EEP estimated approximately 9,000 barrels of crude oil were released, of which approximately 1,400 barrels were removed from the pipeline as part of the repair. Excavation and replacement of the pipeline segment were completed and the pipeline was returned to service on September 17, 2010. The cause of the crude oil release remains subject to investigation by United States federal and state environmental and pipeline safety regulators.

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

As at December 31, 2010, EEP estimated that before insurance recoveries, and not including fines and penalties, costs for emergency response, environmental remediation and cleanup activities associated

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with the Line 6A crude oil release would be approximately US$45 million ($7 million after-tax net to Enbridge), excluding lost revenue of approximately US$3 million ($1 million after-tax net to Enbridge).

As at December 31, 2011, EEP revised its cost estimate for this crude oil release to US$48 million ($7 million after-tax net to Enbridge), before insurance recoveries and excluding fines and penalties. The US$3 million increase was based on a refinement of future costs based on additional information.

EEP included those costs it considered probable and that it could reasonably estimate for purposes of determining its expected losses associated with the Line 6A crude oil release. The estimates do not include consideration of any unasserted claims associated with the release that later may become evident, nor has EEP considered any potential recoveries from third-parties that may later be determined to have contributed to the release. 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 increased estimate of costs associated with the crude oil releases, Enbridge and its affiliates will exceed the limits of its coverage under this insurance policy. Additionally, fines and penalties would not be covered under the existing insurance policy.

EEP recognized US$335 million ($50 million after-tax net to Enbridge) in insurance recoveries for the year ended December 31, 2011 for insurance claims filed in connection with the Line 6B crude oil release. EEP expects to record a receivable for additional amounts claimed for recovery pursuant to insurance policies during the period it deems realization of the claim for recovery is probable.

During the second quarter of 2011, the Company renewed its comprehensive insurance program. The current coverage year has an aggregate limit of US$575 million for pollution liability for the period from May 1, 2011 through April 30, 2012.

Line 6B Pipeline Integrity Plan

In connection with the restart of Line 6B, EEP committed to accelerate a process initiated prior to the crude oil release to perform additional inspections, testing and refurbishment of Line 6B within and beyond the immediate area of the July 26, 2010 crude oil release. Pursuant to this agreement with the United States Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (PHMSA), EEP completed remediation of those pipeline anomalies it identified between 2007 and 2009 that were scheduled for refurbishment, and anomalies identified for action in a July 2010 PHMSA notification, on schedule within 180 days of the September 27, 2010 restart of Line 6B, as required. In addition to the required integrity measures, EEP also agreed to replace a 3,600 foot section of the Line 6B pipeline that lies underneath the St. Clair River in Michigan within one year of the restart of Line 6B, subject to obtaining required permits. A new line was installed beneath the St. Clair River in March 2011 and was tied into Line 6B during June 2011.

In February 2011, EEP filed a tariff supplement with the FERC, which became effective on April 1, 2011, for recovery of US$175 million of capital costs and US$5 million of operating costs for the 2010 and 2011

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Line 6B Pipeline Integrity Plan. The costs associated with the Line 6B Pipeline Integrity Plan, which include an equity return component, interest expense and an allowance for income taxes will be recovered over a 30-year period, while operating costs will be recovered through EEP’s annual tolls for actual costs incurred. These costs include costs associated with the PHMSA Corrective Action Order and other required integrity work.

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 25 actions or claims have been filed against Enbridge, EEP or their affiliates in United States federal and state courts in connection with the Line 6B crude oil release, including direct actions and actions seeking class status. With respect to the Line 6B crude oil release, no penalties or fines have been assessed against Enbridge, EEP or their affiliates as at December 31, 2011. 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 ENERGY, L.P. - ALBERTA CLIPPER US

In July 2009, the Company committed to fund 66.7% of the cost to construct the United States segment of the Alberta Clipper Project. The Company funded 66.7% of the project’s equity requirements through EELP, while 66.7% of the debt funding was made through EEP. EELP - Alberta Clipper US earnings are the Company’s earnings from its investment in EELP which undertook the project. The Alberta Clipper Project was placed into service on April 1, 2010.

Results of Operations

Adjusted earnings from EELP - Alberta Clipper US were $42 million for the year ended December 31, 2011 compared with $42 million for the year ended December 31, 2010 and $7 million for the year ended December 31, 2009. These earnings represent the Company’s earnings from its 66.7% investment in a series of equity within EELP which owns the United States segment of Alberta Clipper. In 2010, earnings were favourably impacted by lower operating costs, predominantly property tax rates applicable during the construction phase relative to the deemed recovery permitted in tolls. Earnings for 2009 and for the first quarter of 2010, in advance of the in service date of April 1, 2010, were attributable to AEDC recognized while the project was under construction.

Business Risks

The risks identified below are specific to EEP and EELP. General risks that affect the Company as a whole are described under Risk Management and Financial Instruments.

Competition

EEP’s Lakehead System, the United States portion of the Liquids Pipelines mainline, is a major crude oil export conduit from the WCSB. Other existing competing carriers and pipeline proposals to ship western Canadian liquids hydrocarbons to markets in the United States represent competition for the Lakehead System. Further details on such competing projects are described within Business Risks under Liquids Pipelines. EEP’s Mid-Continent and North Dakota systems also face competition from existing competing pipelines, proposed future pipelines and alternative gathering facilities (being predominately rail), available to producers or the ability of the producers to build such gathering facilities. Competition for EEP’s storage facilities includes large integrated oil companies and other midstream energy partnerships.

Other interstate and intrastate natural gas pipelines (or their affiliates) and other midstream businesses that gather, treat, process and market natural gas or NGLs represent competition to EEP’s natural gas segment. The level of competition varies depending on the location of the gathering, treating and processing facilities. However, most natural gas producers and owners have alternate gathering, treating and processing facilities available to them, including those owned by competitors that are substantially larger than EEP.

EEP’s marketing segment has numerous competitors, including large natural gas marketing companies, marketing affiliates of pipelines, major oil and natural gas producers, independent aggregators and

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regional marketing companies.

Supply and Demand

The profitability of EEP depends to some extent on the volume of products transported on its pipeline systems. The volume of shipments on EEP’s Lakehead System depends primarily on the supply of western Canadian crude oil and the demand for crude oil in the Great Lakes and Midwest regions of the United States and eastern Canada. Investment levels and related development activities by crude oil producers in conventional and oil sands production directly impacts the level of supply from the WCSB. Investment levels are influenced by crude oil producers’ expectations of crude oil and natural gas prices, future operating costs, United States demand and availability of markets for produced crude oil. Demand depends, among other things, on weather, gasoline price and consumption, manufacturing levels, alternative energy sources and global supply disruptions. Crude oil prices have been sustained at such levels that oil sands producers have recommenced projects that had been previously cancelled or deferred, creating increased demand in the WCSB for new pipeline infrastructure.

EEP’s natural gas gathering assets are also subject to changes in supply and demand for natural gas, NGLs and related products. Commodity prices impact the willingness of natural gas producers to invest in additional infrastructure to produce natural gas. These assets are also subject to competitive pressures from third-party and producer-owned gathering systems.

Supply for the marketing segment depends to a large extent on the natural gas reserves and rate of drilling within the areas served by the natural gas business. Demand is typically driven by weather-related factors, with respect to power plant and utility customers, and industrial demand. EEP’s marketing business uses third party storage to balance supply and demand factors.

Volume Risk

A decrease in volumes transported by EEP’s systems can directly and adversely affect revenues and results of operations. A decline in volumes transported can be influenced by factors beyond EEP’s control including competition, regulatory actions, government actions, weather, storage levels, alternative energy sources, decreased demand, fluctuations in commodity prices, economic conditions, supply disruptions, availability of supply connected to the systems and adequacy of infrastructure to move supply into and out of the systems.

Regulation

In the United States, the interstate oil pipelines owned and operated by EEP and certain activities of EEP’s intrastate natural gas pipelines are subject to regulation by the FERC or state regulators and its financial condition and results of operations could worsen if tariff rates were protested. While gas gathering pipelines are not currently subject to active rate regulation, proposals to more actively regulate intrastate gathering pipelines are currently being considered in certain of the states in which EEP operates. In addition, the FERC has also taken an interest in regulating gas gathering systems that connect into interstate pipelines.

Market Price Risk

EEP’s gas processing business is subject to commodity price risk arising from movements in natural gas and NGL prices and differentials. These risks have been managed by using physical and financial contracts to fix the prices of natural gas and NGLs. Certain of these financial contracts do not qualify for cash flow hedge accounting and, therefore, EEP’s earnings are exposed to associated mark-to-market valuation changes.

ENBRIDGE INCOME FUND

The Fund is involved in the generation and transportation of energy through its 50% interest in Alliance Pipeline Canada, its crude oil and liquids pipelines business in Saskatchewan (the Saskatchewan System) and interests in more than 400 MW of renewable power generation capacity. The Saskatchewan System operates a crude oil gathering system and trunkline pipeline in southern Saskatchewan and southwestern Manitoba, connecting to Enbridge’s mainline pipeline to the United States. The Fund’s renewable power portfolio includes the 190-MW Ontario Wind Project, the 99-MW Talbot Wind Project

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and the 80-MW Sarnia Solar Project, which were acquired from a wholly-owned subsidiary of Enbridge in October 2011, as well as interests in three wind power joint ventures and a business that operates waste-heat power generation projects at Alliance Pipeline Canada compressor stations.

Corporate Restructuring

On December 17, 2010, a plan of arrangement (the Plan) to restructure the Fund took effect. Under the Plan all publicly held trust units and five million units held by Enbridge were exchanged on a one-for-one basis for shares of a taxable Canadian corporation, ENF. The business of ENF is generally limited to investment in the Fund. Following completion of the Plan, the Company retained its overall 72% economic interest in the Fund and remained the primary beneficiary of the Fund both before and after the Plan through a combined direct and indirect investment in the Fund voting units and a non-voting preferred unit investment. As such, Enbridge continues to consolidate the Fund under variable interest entity accounting rules.

Renewable Energy Assets Transfer

In October 2011, the Fund acquired the Ontario Wind, Sarnia Solar and Talbot Wind energy projects from a wholly-owned subsidiary of Enbridge for an aggregate price of approximately $1.2 billion. The transaction was financed by the Fund through a combination of debt and equity, including the issuance of additional ordinary trust units of the Fund to ENF and preferred units to Enbridge. ENF in turn issued additional common shares to the public and to Enbridge. Enbridge’s overall economic interest in the Fund was reduced from 72% to 69% upon completion of the transaction and associated financing.

As the transaction occurred between entities under common control of Enbridge, the intercompany gain realized as a result of this transfer has been eliminated from the consolidated financial statements of Enbridge, although cash income taxes incurred of $98 million remain as a charge to consolidated earnings. The Company retains the benefit of cash taxes paid in the form of increased tax basis of its investment in the underlying partnerships; however, accounting recognition of such benefit is not permitted until such time as the partnerships are sold outside of the consolidated group.

Through this transaction, which essentially resulted in a partial monetization of these assets by Enbridge through sale to non-controlling interests (being ENF’s public shareholders), Enbridge realized a source of funds of $210 million, as presented within Financing Activities on the Consolidated Statement of Cash Flows for the year ended December 31, 2011.

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 Fund was not adequate to allow 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 February 6, 2012, the Fund continues to discuss the reasonableness of its Westspur tolls with shippers.

Incentive and Management Fees

Enbridge receives an annual base management fee for administrative and management services it provides to the Fund, plus incentive fees. Incentive fees are paid to Enbridge based on cash distributions by the Fund that exceed a base distribution amount. In 2011, the Company received intercompany incentive fees of $10 million (2010 - $8 million; 2009 - $8 million) before income taxes. Enbridge also provides management services to ENF. No additional fee is charged to ENF for these services provided the Fund is paying a fee to Enbridge.

Results of Operations

Earnings from the Fund totaled $59 million for the year ended December 31, 2011 compared with $45 million for the year ended December 31, 2010.The increased earnings from the Fund reflected continued increased contributions from the Saskatchewan System following substantial completion of its Phase II expansion project in December 2010, as well as contribution from the renewable assets

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acquired by the Fund in October 2011. These positive impacts were partially offset by higher operating and administrative costs as a result of the asset acquisition and an increase in interest expense and taxes.

Earnings from the Fund were $45 million for both the years ended December 31, 2010 and 2009. Earnings for both years reflected growth attributable to Phase II of the Saskatchewan System Capacity Expansion, which was placed into service in December 2010, offset by a reduced contribution from the wind power assets and increased corporate costs related to the corporate restructuring completed in December 2010. The Fund’s interest in Alliance Pipeline Canada continued to contribute stable adjusted earnings in both 2010 and 2009.

Business Risks

Risks for Alliance Pipeline Canada are similar to those identified for Alliance Pipeline US in the Gas Pipelines, Processing and Energy Services segment. The following risks generally relate to the Saskatchewan System and the wind and solar business, as indicated. General risks that affect the Company as a whole are described under Risk Management and Financial Instruments.

Competition

The Saskatchewan System faces competition in pipeline transportation from other pipelines as well as other forms of transportation, most notably trucking. These alternative transportation options could charge rates or provide service to locations that result in greater net profit for shippers and thereby potentially reduce shipping on the Saskatchewan System or result in possible toll reductions. The Saskatchewan System manages exposure to loss of shippers by ensuring the shipping rates are competitive and by providing a high level of service. Furthermore, the Saskatchewan System’s right-of-way and expansion efforts have created a competitive advantage. The Saskatchewan System will continue to focus on increasing efficiencies through its expansion projects in order to meet its shippers’ growing demand.

Regulation

The Fund’s 50% interest in Alliance Pipeline Canada and certain pipelines within the Saskatchewan System are subject to the actions of various regulators, including the NEB. Actions of the regulators related to tariffs, tolls and facilities impact earnings and the success of expansion projects. Delays in regulatory approvals could result in cost escalations and construction delays. Changes in regulation, including decisions by regulators on the applicable tariff structure or changes in interpretations of existing regulations by courts or regulators, could adversely affect the results of operations of the Fund.

Volume Risk

Operations and tolls for the Saskatchewan Gathering and the Westspur Systems are, in general, based on volumes transported and are on terms similar to a common carrier basis with no specific on-going volume commitments. There is no assurance that shippers will continue to utilize these systems in the future or transport volumes on similar terms or at similar tolls.

Wind and Solar Resources

There is risk that the wind or solar resource at specific locations is lower than expected leading to lower than expected power generation revenue. Extensive long term wind studies were completed prior to committing capital to the selected sites in order to mitigate this risk.

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CORPORATE

EARNINGS

|  | 2011 |  | 2010 |  | 2009 |
(millions of Canadian dollars) |  |  |  |  |  |  |
Noverco |  | 24 |  | 21 |  | 19 |
Other Corporate |  | (41) |  | (48) |  | (39) |
Adjusted loss |  | (17) |  | (27) |  | (20) |
Noverco - impact of tax rate changes |  | - |  | - |  | 6 |
Other Corporate - unrealized derivative fair value gains/(loss) |  | (87) |  | 25 |  | 207 |
Other Corporate - unrealized foreign exchange gains/(loss) on translation of intercompany balances, net |  | (131) |  | 40 |  | 133 |
Other Corporate - impact of tax rate changes |  | 6 |  | - |  | 4 |
Other Corporate - gain on sale of investment in NetThruPut (NTP) |  | - |  | - |  | 25 |
Other Corporate - tax on intercompany gain on sale |  | (98) |  | - |  | - |
Earnings/(loss) |  | (327) |  | 38 |  | 355 |

Total adjusted loss from Corporate was $17 million for the year ended December 31, 2011 compared with $27 million for the year ended December 31, 2010. The decrease in adjusted loss was due to both an increase in adjusted earnings from the Company’s investment in Noverco and a decrease in adjusted loss from Other Corporate.

Total adjusted loss from Corporate was $27 million for the year ended December 31, 2010 compared with $20 million for the year ended December 31, 2009. The increase in adjusted loss was primarily due to the Company recording foreign exchange gains realized on hedge settlements and on residual United States dollar cash balances in 2009, whereas no similar gains occurred in 2010. Other factors contributing to the increased adjusted loss included higher administrative costs and higher interest costs, partially offset by an increased corporate income tax recovery.

Corporate earnings/(loss) was impacted by the following non-recurring or non-operating adjusting items.

· Noverco earnings for 2009 included a benefit related to favourable tax rate changes.

· Earnings/(loss) for each year included a change in the unrealized fair value gains and losses on derivative financial instruments related to forward foreign exchange risk management positions.

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

· Earnings/(loss) for the 2011 and 2009 were impacted by tax rate changes.

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

· Earnings/(loss) for 2011 were impacted by tax on an intercompany gain on sale.

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NOVERCO

At December 31, 2011, Enbridge owned an equity interest in Noverco through ownership of 38.9% (2010 - 32.1%; 2009 - 32.1%) of its common shares and a cost investment in preferred shares. Noverco is a holding company that owns approximately 71% of Gaz Metro Limited Partnership (Gaz Metro), a natural gas distribution company operating in the province of Quebec with interests in subsidiary companies operating gas transmission, gas distribution and power distribution businesses in the province of Quebec and the state of Vermont. Effective September 2010, Gaz Metro became a privately held limited partnership as a result of a reorganization of its publicly held partnership units, which were exchanged on a one-for-one basis for common shares in Valener Inc., a new publicly listed corporation.

Noverco also holds, directly and indirectly, an investment in Enbridge common shares aggregating 69.4 million shares. The substantial increase in the value of these shares over the last decade has resulted in a significant shift in the balance of Noverco’s asset mix. The board of directors of Noverco has authorized the Caisse De Depot et Placement de Quebec, as manager of Noverco, to rebalance Noverco’s asset mix through the sale of up to 22.5 million Enbridge shares, by way of private placement, secondary offering or stock market sales, from time to time as market conditions permit, and to distribute the proceeds to shareholders, subject to compliance with restrictions under applicable law and credit facilities. Enbridge’s share of such proceeds would be up to approximately $300 million, which would be applied to the funding of Enbridge’s growth program.

Weather variations do not affect Noverco’s earnings as Gaz Metro is not exposed to weather risk. A significant portion of the Company’s earnings from Noverco is in the form of dividends on its preferred share investments which are based on the yield of 10-year Government of Canada bonds plus a weighted average spread of approximately 4.38%.

Results of Operations

Noverco adjusted earnings were $24 million for the year ended December 31, 2011 compared with $21 million for the year ended December 31, 2010 and $19 million for the year ended December 31, 2009. Noverco earnings for each year reflected contributions from the Company’s increased preferred share investment and Noverco’s underlying gas distribution investments.

OTHER CORPORATE

Corporate also consists of the new business development activities, general corporate investments and financing costs not allocated to the business segments.

Results of Operations

Other Corporate adjusted loss was $41 million for the year ended December 31, 2011 compared with $48 million for the year ended December 31, 2010. The decreased adjusted loss reflected an increase in preference share dividends following the issuance of 38 million preference shares during the year and higher tax expense which were more than offset by lower interest expense.

Adjusted loss from Corporate was $48 million for the year ended December 31, 2010 compared with $39 million for the year ended December 31, 2009. The increase was primarily due to the Company recording foreign exchange gains realized on hedge settlements and on residual United States dollar cash balances in 2009, whereas no similar gains occurred in 2010. Other factors contributing to the increase included higher administrative costs and higher interest costs, partially offset by an increased income tax recovery.

LIQUIDITY AND CAPITAL RESOURCES

The Company expects to utilize cash from operations and the issuance of debt, commercial paper and/or credit facility draws to fund liabilities as they become due, finance capital expenditures, fund debt retirements and pay common and preferred share dividends. At December 31, 2011, excluding the Southern Lights project financing, the Company had $7,170 million of committed credit facilities of which $3,682 million were drawn or allocated to backstop commercial paper. Inclusive of unrestricted cash and cash equivalents of $77 million, the Company had net available liquidity at December 31, 2011 of $3,682 million. The net available liquidity, together with cash from operations and anticipated future access to capital markets, is expected to be sufficient to finance all currently secured capital projects and to provide flexibility for new investment opportunities.

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

|  | Maturity Dates 1 | Total Facilities |  | Credit Facility Draws 2 |  | Available |
(millions of Canadian dollars) |  |  |  |  |  |  |  |
Liquids Pipelines |  | 2013 | 300 |  | 26 |  | 274 |
Gas Distribution |  | 2012-2013 | 717 |  | 556 |  | 161 |
Sponsored Investments |  | 2013 | 500 |  | 268 |  | 232 |
Corporate 4 |  | 2012-2016 | 5,653 |  | 2,832 |  | 2,821 |
|  |  | 7,170 |  | 3,682 |  | 3,488 |
Southern Lights project financing 3 |  | 2013-2014 | 1,576 |  | 1,466 |  | 110 |
Total credit facilities |  |  | 8,746 |  | 5,148 |  | 3,598 |

1 Total facilities include $30 million in demand facilities with no maturity date.

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

3 Total facilities inclusive of $61 million for debt service reserve letters of credit.

4 In January 2012, the Company secured additional revolving facilities of US$1.3 billion with a maturity date of 2015.

The Company’s credit facility agreements include standard default and covenant provisions whereby accelerated repayment may be required if the Company were to default on payment or violate certain covenants. As in prior years, the Company expects to continue to comply with these provisions and therefore not trigger any early repayments. As at December 31, 2011, the Company was in compliance with all debt covenants.

The Company continues to manage its debt to capitalization ratio to maintain a strong balance sheet. The Company’s debt to capitalization ratio at December 31, 2011, including short-term borrowings but excluding non-recourse debt, was 63.2%, compared with 65.1% at the end of 2010. Including all debt, the debt to capitalization ratio was 64.7% at December 31, 2011 compared with 66.9% at December 31, 2010.

The Company invests its surplus cash in short-term investment grade instruments with credit worthy counterparties. Short-term investments were $77 million at December 31, 2011 (2010 - $99 million).

Excluding current maturities of long-term debt, the Company has a negative working capital position, compared with a positive position at December 31, 2010. Working capital includes the current portion of unrealized fair value derivative gains and losses related to the Company’s risk management activities. Of the $821 million change in working capital in 2011 compared with the prior year, $573 million relates to an increase in current derivative liabilities. Actual cash outflows to be incurred to settle these liabilities depend on foreign exchange rates, interest rates or commodity prices in effect when derivative contracts outstanding mature; therefore, working capital at a point in time may not be representative of actual future cash flows. The Company maintains adequate liquidity at all times, through committed credit facilities and other sources, to fund liabilities as they come due. Further, working capital will fluctuate from time to time due to changes in natural gas inventory and borrowing levels at EGD, as well as activity levels within, among others, the Company’s Energy Services businesses.

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|  | 2011 |  | 2010
(millions of Canadian dollars) |  |  |  |
Cash and cash equivalents 1 |  | 420 |  | 342
Accounts receivable and other |  | 3,136 |  | 2,706
Inventory |  | 739 |  | 813
Bank indebtedness |  | (102) |  | (100)
Short-term borrowings |  | (548) |  | (326)
Accounts payable and other |  | (3,722) |  | (2,688)
Interest payable |  | (114) |  | (117)
Working capital |  | (191) |  | 630

1 Includes short-term investments, restricted cash of amounts in trust and proportionately consolidated cash from joint ventures.

Changes in commodity prices impact accounts receivable and other, inventory and accounts payable and other within Energy Services and EGD.

OPERATING ACTIVITIES

Cash provided by operating activities for the year ended December 31, 2011 was $2,703 million compared with $1,851 million for the year ended December 31, 2010. The growth in cash from operating activities represented favourable operating performance from the Company’s core liquids and natural gas assets, increased contributions from a growing portfolio of renewable power generation assets and increased cash flow generated by the Energy Services and Aux Sable business. Also contributing to the increase in cash from operating activities was a variance of $544 million in changes in operating assets and liabilities due to increased transaction volume in the Energy Services business.

Cash provided by operating activities for the year ended December 31, 2010 was $1,851 million compared with $2,017 million for the year ended December 31, 2009. Cash from operating activities was positively impacted in 2010 by contributions from growth projects placed in service, including Alberta Clipper and Southern Lights Pipeline. Alberta Clipper includes contributions from both the Canadian portion as well as cash distributions received on the Company’s 66.7% equity investment in EELP which owns the United States segment of Alberta Clipper. Variances in working capital balances, primarily due to changes in commodity prices and sales volumes within Energy Services, as well as changes in natural gas prices at EGD, resulted in the decline in cash from operating activities in 2010 compared with 2009.

There are no material restrictions on the Company’s cash with the exception of proportionately consolidated joint venture cash of $224 million, which cannot be accessed until distributed to the Company, restricted cash of $7 million related to Southern Lights project financing and cash in trust of $10 million for specific shipper commitments.

INVESTING ACTIVITIES

Cash used in investing activities was $4,017 million for the year ended December 31, 2011 compared with $2,674 million for 2010, an increase of $1,343 million. Cash used in investing activities included $2,516 million (2010 - $2,357 million) of additions to property, plant and equipment for the year ended December 31, 2011. Capital expenditures on growth projects included Cabin, Athabasca Pipeline Capacity Expansion and Cedar Point Wind Energy Project, as well as a number of other projects under construction. Investing activities also includes several acquisitions, including a 50% interest in Seaway Pipeline for $1.2 billion (US$1.2 billion).

In 2010, cash used for investing activities was $2,674 million compared with $3,306 million in 2009, a decrease of $632 million. Cash used in investing activities included $2,357 million of additions to property, plant and equipment for the year ended December 31, 2010 and $3,225 million of additions to property, plant and equipment for the year ended December 31, 2009. Additions to property, plant and equipment declined compared with 2009 given the completion of several significant projects – Alberta Clipper,

54

Southern Lights Pipeline and Hardisty Contract Terminal, among others. The Company also completed three acquisitions in 2010 resulting in a use of cash of $116 million.

Investing activities also include long-term investments and affiliate lending, which in 2009 and 2010 consisted primarily of the Company’s investing in and funding of EELP which holds the Company’s interest in the United States segment of Alberta Clipper. The higher use of cash used in investing activities reported in 2009 was partially offset by proceeds received on the sale of the Company’s investments in OCENSA and NTP.

Capital Expenditures and Investments

|  |  | Expected 2012 |  | Actual 2011 |  | Actual 2010
(millions of Canadian dollars) |  |  |  |  |  |
Liquids Pipelines |  | 2,080 |  | 977 |  | 765
Gas Distribution |  | 480 |  | 483 |  | 387
Gas Pipelines, Processing and Energy Services |  | 910 |  | 953 |  | 1,153
Sponsored Investments 1 |  | - |  | 122 |  | 253
Corporate |  | 250 |  | 33 |  | -
|  | 3,720 |  | 2,568 |  | 2,558

1 Includes the Company’s investment in sponsored vehicles.

The Company’s capital expansion initiatives are described in Growth Projects. The Company also requires capital for ongoing core maintenance and capital improvements in many of its businesses. In total, Enbridge expects to spend approximately $3,720 million during 2012 on maintenance and growth capital projects which are substantially secured, including increased spending on integrity programs. The Company expects to finance these expenditures through cash from operating activities and available liquidity. The Company may also raise capital through the monetization or disposition of selected assets, or through accessing capital markets as required.

The decision to finance with debt or equity is based on the capital structure for each business and the overall capitalization of the consolidated enterprise. Certain of the regulated pipeline and gas distribution businesses issue long-term debt to finance capital expenditures. This external financing may be supplemented by debt or equity injections from the parent company. Debt, and equity when required, has been issued by the Company to finance business acquisitions, investments in subsidiaries and long-term investments. Funds for debt retirements are generated through cash provided from operating activities as well as through the issuance of replacement debt.

FINANCING ACTIVITIES

In 2011, cash provided by financing activities was $1,380 million compared with $766 million and $1,082 million in 2010 and 2009, respectively. Significant financing activities included an increase in short term borrowings, issuances and repayment of debentures and term notes, and issuances of preference shares.

Short-term borrowings are primarily used to finance near term working capital requirements, including gas inventories at EGD. In 2011, short-term borrowings increased to also fund long-term debt repayments and increased investing activities. In 2010, EGD had lower net repayments of short-term borrowings compared with 2009.

Medium-term note issuances included the following:

· Enbridge - $600 million (2010 - $800 million; 2009 - $1,000 million)

· Enbridge Pipelines Inc. - nil (2010 - $900 million; 2009 - $500 million)

· EGD - $100 million (2010 - $400 million; 2009 - nil)

· The Fund - $125 million (2010 - $200 million; 2009 - nil)

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Contributions from noncontrolling interests increased to $214 million in 2011 compared with distributions of $1 million in 2010 and $33 million in 2009. The increase of contributions from noncontrolling interests was primarily a result of the share issuances at ENF and EEM. In 2011, Enbridge transferred three renewable energy assets to the Fund at an aggregate price of $1.2 billion. To acquire those assets, the Fund issued additional trust units to ENF, which in turn issued equity of $220 million to public shareholders.

In 2011, the proceeds from these term note issuances were used in part to fund term note repayments of $203 million (2010 - $600 million; 2009 - $616 million). In 2010, the proceeds from the issuance of term notes were also used to fund the repayment of commercial paper and credit facility of $347 million.

In 2011, the Company issued redeemable preference shares. Net proceeds from the issuance of Series B and Series D preference shares were $926 million (2010 and 2009 - nil).

In 2008, the Company secured financing that is non-recourse to the Company specific to the Canadian and United States segments of the Southern Lights Pipeline. In 2011, the repayment of Southern Lights Pipeline project financing was $62 million. For the years ended December 31, 2010 and 2009, the net proceeds on Southern Lights financing were $14 million and $343 million, respectively.

Participants in the Company’s Dividend Reinvestment and Share Purchase Plan receive a 2% discount on the purchase of common shares with reinvested dividends. For the year ended December 31, 2011, dividends declared were $759 million (2010 - $648 million), of which $530 million (2010 - $426 million) were paid in cash and reflected in financing activities. The remaining $229 million of dividends declared were reinvested pursuant to the plan and resulted in the issuance of common shares rather than a cash payment. For the years ended December 31, 2011 and 2010, 30% and 34%, respectively, of total dividends declared were reinvested.

Outstanding Share Data 1

|  |  | Number
Preference Shares, Series A (non-voting equity shares) |  | 5,000,000
Preference Shares, Series B (non-voting equity shares)2 |  | 20,000,000
Preference Shares, Series D (non-voting equity shares)3 |  | 18,000,000
Preference Shares, Series F (non-voting equity shares)4 |  | 20,000,000
Common Shares - issued and outstanding (voting equity shares) |  | 782,270,762
Total issued and outstanding stock options (18,269,393 vested) |  | 30,973,891

1 Outstanding share data information is provided as at February 15, 2012.

2 On June 1, 2017, and on June 1 every five years thereafter, the holders of Preference Shares, Series B will have the right to elect to convert (subject to certain provisions) any or all of their Preference Shares, Series B into an equal number of Cumulative Redeemable Preference Shares, Series C.

3 On March 1, 2018, and on March 1 every five years thereafter, the holders of Preference Shares, Series D will have the right to elect to convert (subject to certain provisions) any or all of their Preference Shares, Series D into an equal number of Cumulative Redeemable Preference Shares, Series E.

4 On June 1, 2018, and on June 1 every five years thereafter, the holders of Preference Shares, Series F will have the right to elect to convert (subject to certain provisions) any or all of their Preference Shares, Series F into an equal number of Cumulative Redeemable Preference Shares, Series G.

Effective May 25, 2011, a two-for-one stock split of the Company’s common shares was completed. All references to the number of shares outstanding, earnings per common share, diluted earnings per common share, adjusted earnings per common share, dividends per common share and outstanding option information have been retroactively restated to reflect the impact of the stock split.

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COMMITMENTS AND CONTINGENCIES

COMMITMENTS

The Company has signed contracts for the purchase of services, pipe and other materials, as well as transportation, totaling $4,120 million which are expected to be paid over the next five years.

CONTRACTUAL OBLIGATIONS

Payments due for contractual obligations over the next five years and thereafter are as follows:

|  |  | Total |  | Less than 1 year |  | 1-3 years |  | 3-5 years |  | After 5 years
(millions of Canadian dollars) |  |  |  |  |  |  |  |  |  |
Long-term debt 1 |  | 14,495 |  | 251 |  | 1,347 |  | 1,615 |  | 11,282
Non-recourse long-term debt 1 |  | 1,048 |  | 120 |  | 154 |  | 143 |  | 631
Capital and operating leases |  | 147 |  | 20 |  | 37 |  | 37 |  | 53
Long-term contracts 2,3 |  | 4,318 |  | 2,247 |  | 1,515 |  | 361 |  | 195
Pension obligations 4 |  | 105 |  | 105 |  | - |  | - |  | -
Total contractual obligations |  | 20,113 |  | 2,743 |  | 3,053 |  | 2,156 |  | 12,161

1 Excludes interest. Changes to the planned funding requirements are dependent on the terms of any debt refinancing agreements.

2 Approximately $2,776 million of these contracts are commitments for materials related to the construction of growth projects. Changes to the planned funding requirements, including cancellation, are dependent on changes to the related projects.

3 Contracts totaling $62 million are within proportionately consolidated joint venture entities and contracts totaling $125 million are between the Company and proportionately consolidated joint venture entities.

4 Assumes only required payments will be made into the pension plans in 2012. Contributions are made in accordance with the independent actuarial valuations as at December 31, 2011. Contributions, including discretionary payments, may vary pending future benefit design and asset performance.

UNITED STATES LEGAL AND REGULATORY PROCEEDINGS - LINE 6A AND 6B INCIDENTS

A number of United States governmental agencies and regulators have initiated investigations into the Line 6A and Line 6B crude oil releases; however, currently no penalties or fines have been assessed against EEP in connection with the incidents. In addition, a number of actions or claims have been filed against Enbridge, EEP or their affiliates in the United States federal and state courts in connection with these incidents. See Sponsored Investments - Enbridge Energy Partners - EEP Lakehead System Line 6A and 6B Crude Oil Releases.

ENBRIDGE GAS DISTRIBUTION INC.

Bloor Street Incident

EGD was charged under both the Ontario Technical Standards and Safety Act (TSSA) and the Ontario Occupational Health and Safety Act (OHSA) in connection with an explosion that occurred in April 2003 on Bloor Street West in Toronto. In December 2011, EGD pleaded guilty before the Ontario Court of Justice to one charge under the OHSA and one charge under the TSSA. The Court imposed a fine of $350,000 in connection with each charge. With the application of a required 25% Victim Fine Surcharge, the total amount payable by EGD was $875,000, which management believes concludes this matter.

ENBRIDGE GAS NEW BRUNSWICK INC.

Regulatory Matters

On December 9, 2011, the Government of New Brunswick tabled and subsequently passed legislation related to the regulatory process for setting rates for gas distribution within the province. The legislation permits 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. Significant details of the rate setting process were left to be established in the new regulations which have yet to be published.

As at December 31, 2011, the carrying value of EGNB’s regulatory asset and property, plant and equipment totaled $180 million and $264 million, respectively (2010 - $171 million and $254 million, respectively). Earnings from EGNB approximate $20 million per year. As the details of the regulations have not yet been made available, the effect of such regulations is not determinable as at February 21, 2012. While EGNB continues to engage in discussions with the province about the potential effect of the regulations, EGNB will preserve its legal rights.

TAX MATTERS

Enbridge and its subsidiaries maintain tax liabilities related to uncertain tax positions. While fully supportable in the Company’s view, these tax positions, if challenged by tax authorities, may not be fully sustained on review.

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OTHER LEGAL AND REGULATORY PROCEEDINGS

The Company and its subsidiaries are subject to various other legal and regulatory actions and proceedings which arise in the normal course of business, including interventions in regulatory proceedings and challenges to regulatory approvals and permits by special interest groups. While the final outcome of such actions and proceedings cannot be predicted with certainty, Management believes that the resolution of such actions and proceedings will not have a material impact on the Company’s consolidated financial position or results of operations.

QUARTERLY FINANCIAL INFORMATION 1 |  |  |  |  |  |  |  |
2011 |  | Q1 |  | Q2 |  | Q3 |  | Q4 |  | Total
(millions of Canadian dollars, except for per share amounts) |  |  |  |  |  |  |  |  |  |
Revenues |  | 4,713 |  | 4,981 |  | 4,272 |  | 5,436 |  | 19,402
Earnings attributable to common shareholders |  | 393 |  | 259 |  | 4 |  | 335 |  | 991
Earnings per common share 2 |  | 0.52 |  | 0.35 |  | 0.01 |  | 0.44 |  | 1.32
Diluted earnings per common share 2 |  | 0.52 |  | 0.34 |  | 0.01 |  | 0.44 |  | 1.30
Dividends per common share 2 |  | 0.2450 |  | 0.2450 |  | 0.2450 |  | 0.2450 |  | 0.98
EGD - warmer/(colder) than normal weather |  | (11) |  | (2) |  | - |  | 12 |  | (1)
Net unrealized derivative fair value and intercompany foreign exchange (gains)/losses |  | (43) |  | 27 |  | 235 |  | (87) |  | 132
2010 |  | Q1 |  | Q2 |  | Q3 |  | Q4 |  | Total
(millions of Canadian dollars, except for per share amounts) |  |  |  |  |  |  |  |  |  |
Revenues |  | 3,977 |  | 3,505 |  | 3,502 |  | 4,143 |  | 15,127
Earnings attributable to common shareholders |  | 342 |  | 138 |  | 157 |  | 326 |  | 963
Earnings per common share 2 |  | 0.47 |  | 0.19 |  | 0.21 |  | 0.44 |  | 1.30
Diluted earnings per common share 2 |  | 0.46 |  | 0.18 |  | 0.21 |  | 0.43 |  | 1.29
Dividends per common share 2 |  | 0.2125 |  | 0.2125 |  | 0.2125 |  | 0.2125 |  | 0.85
EGD - warmer/(colder) than normal weather |  | 8 |  | 10 |  | - |  | (6) |  | 12
Net unrealized derivative fair value and intercompany foreign exchange (gains)/losses |  | (30) |  | 87 |  | (45) |  | (71) |  | (59)

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

2 Comparative amounts were restated to reflect two-for-one stock split which was effective May 25, 2011.

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

EGD and the Company’s other gas distribution businesses are subject to seasonal demand. A significant portion of gas distribution customers use natural gas for space heating; therefore, volumes delivered and resulting revenues and earnings typically increase during the winter months of the first and fourth quarters of any given year. Revenues generated by EGD and other gas distribution businesses also vary from quarter-to-quarter with fluctuations in the price of natural gas, although earnings remain neutral due to the pass through nature of these costs.

The Company actively manages its exposure to market price risks including, but not limited to, commodity prices and foreign exchange rates. To the extent derivative instruments used to manage these risks are non-qualifying for the purposes of applying hedge accounting, unrealized fair value gains and losses on these instruments will impact earnings. In 2011, Corporate earnings were impacted by unrealized derivative fair value changes of a $16 million gain, a $65 million loss, $83 million loss and a $45 million gain in the first, second, third and fourth quarters, respectively. Most comparably, earnings were positively impacted by unrealized derivative fair value gains of $26 million, $39 million and $48 million in the first,

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third and fourth quarters of 2010, respectively, and negatively impacted by an unrealized derivative fair value loss of $88 million in the second quarter of 2010. The revaluation of foreign-denominated intercompany loans impacts earnings each quarter, with most notable impacts being the recognition of gains of $68 million and $50 million in the second and third quarters of 2009.

Reflected in 2011 earnings are the Company’s share of leak remediation costs and lost revenue associated with the Line 6A and Line 6B crude oil releases in the amounts of $6 million, $21 million (2010 - $85 million) and $6 million (2010 - $21 million) in the second, third and fourth quarters, respectively. Earnings for 2011 also reflected insurance recoveries associated with the Line 6B crude oil release of $5 million, $3 million, $13 million and $29 million in the first, second, third and fourth quarters, respectively.

Finally, the Company is in the midst of a substantial capital program and the timing of construction and completion of growth projects may impact the comparability of quarterly results. The Company’s capital expansion initiatives, including construction commencement and in-service dates, are described in Growth Projects.

RELATED PARTY TRANSACTIONS

All related party transactions are undertaken in the normal course of business and, unless otherwise noted, measured at the exchange amount, which is the amount of consideration established and agreed to by the related parties.

EEP, an equity investee, does not have employees and uses the services of the Company for managing and operating its businesses. Vector, a joint venture, contracts the services of Enbridge to operate the pipeline. Amounts for these services, which are charged at cost in accordance with service agreements, for the year ended December 31, 2011 are $380 million (2010 - $332 million; 2009 - $342 million) to EEP and $6 million (2010 - $7 million; 2009 - $6 million) to Vector. At December 31, 2011, the Company has accounts receivable of $35 million (2010 - $29 million) from EEP and nil (2010 - nil) from Vector.

The Company had previously provided EEP with an unsecured revolving credit agreement for general liquidity support. The credit facility provided for a maximum principle amount of US$500 million for a three-year term maturing in December 2010. In March 2010, the unsecured revolving credit agreement was cancelled in accordance with the terms of the agreement and without penalty.

EGD, a subsidiary of the Company, has contracts for gas transportation services from Alliance and Vector. EGD is charged market prices for these services. For the year ended December 31, 2011, EGD was charged $42 million (2010 - $42 million; 2009 - $42 million) for services from Alliance and $25 million (2010 - $28 million; 2009 - $29 million) from Vector.

Tidal Energy Marketing (US) L.L.C., a subsidiary of the Company, purchases and sells gas at prevailing market prices with Enbridge Marketing (US) Inc., a subsidiary of EEP. For the year ended December 31, 2011, amounts purchased were $1 million (2010 - $2 million; 2009 - $16 million) and sales were $nil (2010 - nil; 2009 - $6 million).

Tidal Energy Marketing Inc. and Tidal Energy Marketing (US) L.L.C, subsidiaries of the Company, have transportation commitments, measured at market value, through 2015 on Alliance Pipeline Canada, Alliance Pipeline US and Vector. For the year ended December 31, 2011, amounts paid to Alliance Pipeline Canada were $17 million (2010 - $13 million; 2009 - $9 million), amounts paid to Alliance Pipeline US were $11 million (2010 - $9 million; 2009 - $7 million) and amounts paid to Vector were $11 million (2010 - $10 million; 2009 - $16 million).

Tidal Energy Marketing Inc., a subsidiary of the Company, purchases and sells commodities at prevailing market prices with EEP and a subsidiary of EEP. For the year ended December 31, 2011, amounts purchased were $122 million (2010 - $151 million; 2009 - $80 million) and sales were $4 million (2010 - $3 million; 2009 - $7 million).

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ALBERTA CLIPPER PROJECT

The Company funded 66.7% of the United States segment of Alberta Clipper’s equity requirements through EELP, an equity investee. The Company also provided a $348 million (US$342 million) (2010 - $346 million (US$347 million)) loan to EEP for debt financing related to the construction. At December 31, 2011, $336 million (2010 - $334 million) is included in Deferred amounts and other assets with the remaining $12 million (2010 - $12 million) included in Accounts receivable and other. The loan, denominated in United States dollars, matures on March 15, 2020, bears interest at a fixed rate of 5.20% and has a maximum loan amount of $400 million. Semi-annual payments of principal and accrued interest are required. Semi-annual principal payments are based upon a straight-line amortization of the principal balance over a 30 year period.

During the year the Board of Directors of Enbridge Energy Management, L.L.C. declared distributions of $74 million (US$76 million) (2010 - $40 million (US$39 million)) payable to the Company relating to its Series AC interests in the Alberta Clipper Project.

SPEARHEAD NORTH PIPELINE

In May 2009, the Company sold a section of the Spearhead Pipeline to its affiliate EEP for proceeds of US$75 million. This related party transaction has been recorded at the exchange amount which was equal to the carrying amount.

SOUTHERN LIGHTS PIPELINE

In February 2009, as part of its Southern Lights Pipeline project, the Company transferred the United States section of a newly constructed light sour pipeline to EEP in exchange for a pipeline referred to as Line 13. This non-monetary transaction has been recorded at the carrying amount.

In connection with the exchange discussed above, EEP entered into an arrangement to lease Line 13 from the Company for monthly payments of US$2 million to ensure adequate southbound pipeline capacity prior to the completion of the Alberta Clipper Project. The lease arrangement, which was effective in February 2009, expired in April 2010. For the year ended December 31, 2010, EEP paid $5 million (2009 - $21 million) to the Company to lease Line 13.

LONG-TERM RECEIVABLE FROM AFFILIATE

An affiliate long-term note receivable of $159 million (US$130 million) was repaid by EEP in November 2009. Interest income for the year ended December 31, 2009 related to the note receivable was $11 million.

LAKEHEAD LINE 6B CRUDE OIL RELEASE

In connection with the Lakehead Line 6B crude oil release, the Company provided personnel support and other services to its affiliate, EEP, to assist in the clean-up and remediation efforts. These services, which were charged at cost, totaled $6 million for the year ended December 31, 2011 (2010 - $18 million).

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

Enbridge’s proven investment value proposition is based on maintaining a reliable business model. More than 90% of the Company’s revenues come from investment grade customers. Other risks, such as capital cost and inflation, are generally transferred to customers through contractual arrangements. In addition to contractually reducing the majority of its business risk, the Company has formal risk

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management policies, procedures and systems designed to mitigate any residual risks, such as market price risk, credit risk and operational risk. In addition, the Company performs an annual corporate risk assessment to scan its environment for all potential risks. Risks are ranked based on severity and likelihood and results are considered in the Company’s strategic and operating plans. Through this process, a range of ongoing mitigants are identified and implemented.

MARKET PRICE RISK

The Company’s earnings, cash flows and other comprehensive income (OCI) are subject to movements in foreign exchange rates, interest rates, commodity prices and the Company’s share price (collectively, market price risk). Given the Company’s desire to maintain a stable and consistent earnings profile, it has implemented a Market Price Risk Management Policy which outlines a risk management governance framework and specific exposure limits to minimize the likelihood that adverse earnings fluctuations arising from movements in market prices across all of its businesses will exceed a defined tolerance.

Earnings at Risk (EaR), a variant of Value at Risk, is the principal risk management metric used to quantify market price risk sensitivity at Enbridge. EaR is an objective, statistically derived risk metric that measures the maximum adverse change in projected 12-month earnings that could result from market price risk over a one-month period within a 97.5% confidence interval. The philosophy behind this metric is to identify the potential risk to the Company’s annual earnings target, taking into account the illiquidity of certain exposure positions. The Company’s policy is to limit EaR to a maximum of 5% of the next 12 months of forecasted earnings. Earnings exposure to market price risk is managed within the overall consolidated EaR limits of the Company. Further, commodity price risk is managed within business unit EaR sub-limits. The Company’s Corporate Financial Risk Management Committee (CFRMC) establishes and monitors the EaR limits on a monthly basis. Compliance with the EaR limits are reported to the CFRMC and variances are remediated as necessary.

Various hedging programs have been put into place to help ensure that the residual market price risks remain within policy limits, and thus help provide the Company with a general stability of earnings over a short and medium term horizon. The following section summarizes the primary types of market price risks to which the Company is exposed, and outlines the financial derivative hedging programs implemented.

The following table summarizes the EaR as a percentage of forecast earnings from the main groups of market price risk after impact of the Company’s hedging programs. These EaR numbers are based on business conditions and hedging programs as of December 31, 2011 and may not be applicable to other periods.

Risk | EaR
(% of forecast 12 month forward earnings) |
Foreign exchange | 0.8%
Interest rate | 0.2%
Commodity | 1.5%
Total EaR | 2.5%

Foreign Exchange Risk

The Company’s earnings, cash flows and OCI are subject to foreign exchange rate variability, primarily arising from the performance of its United States dollar denominated subsidiaries and investments, and certain revenues and expenses denominated in United States dollars. The Company has implemented a policy where it must hedge a minimum level of foreign currency denominated earnings exposures identified over the next five year period. The Company currently has economically hedged over 85% of its forecast adjusted earnings through 2016 at an average rate of approximately $1.05C$/US$. The Company may also use foreign exchange forward contracts to hedge anticipated foreign currency denominated purchases or sales and foreign currency denominated debt, as well as certain equity investment balances and net investments in foreign denominated subsidiaries.

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Interest Rate Risk

The Company’s earnings and cash flows are exposed to short-term interest rate variability due to the regular repricing of its variable rate debt, primarily commercial paper. Pay fixed-receive floating interest rate swaps and options are used to hedge against the effect of future interest rate movements. The Company has implemented a hedging program to significantly mitigate the volatility to variable rate interest expense through 2016 at an average swap rate of 2.27%.

The Company’s earnings and cash flows are also exposed to variability in longer term interest rates on future fixed rate debt issuances. Forward starting interest rate swaps are used to hedge against the effect of future interest rate movements. The Company has implemented a hedging program to significantly mitigate its exposure to long term interest rate variability on select forecast term debt issuances through 2015. A total of $5,200 million of future fixed rate term debt issuances have been hedged at an average swap rate of 3.86%. Further, many of the Company’s existing commercial arrangements and certain construction projects provide for the full recovery of financing costs through tolls.

The Company also monitors its debt portfolio mix of fixed and variable rate debt instruments to ensure the consolidated portfolio of debt stays within the Board of Directors’ approved policy limit band of a maximum of 25% floating rate debt as a percentage of total debt outstanding.

Commodity Price Risk

The Company’s earnings and cash flows are exposed to changes in commodity prices as a result of ownership interest in certain assets and investments, as well as through the activities of its energy services subsidiaries. These commodities include natural gas, power, crude oil and NGLs. The Company employs financial derivative instruments to fix a portion of the variable price exposures that arises from physical transactions involving these commodities.

The Company has implemented a program to mitigate the volatility from fractionation spreads (natural gas/NGLs) that impact earnings from its ownership interest in the Aux Sable natural gas processing plant and its indirect ownership of the gathering and processing business held by EEP.

Equity Price Risk

Equity price risk is the risk of earnings fluctuations due to changes in the Company’s share price. The Company has exposure to its own common share price through the issuance of various forms of stock based compensation, which affect earnings through revaluation of the outstanding units every period. The Company uses equity derivatives to manage the earnings volatility derived from one form of stock based compensation, Restricted Share Units.

CREDIT RISK

The Company’s earnings and cash flows could be exposed to the risk of payment default by its shippers or other counterparties. Given the Company’s desire to maintain a stable and consistent earnings profile, it has implemented a Counterparty Credit Risk Policy outlining a governance framework and specific exposure limits to minimize the likelihood that adverse earnings fluctuations arise from counterparty defaults across any of its businesses.

Further initiatives to mitigate credit exposure include ensuring that all counterparties shipping on the regulated oil pipelines that have credit ratings below investment grade provide the carrier with a form of credit assurance, for example, a creditworthy parental guarantee, letter of credit or cash.

Credit risk in the Gas Distribution segment is mitigated by its large and diversified customer base and its ability to recover an estimate for doubtful accounts through the ratemaking process. The Company actively monitors the financial strength of large industrial customers and, in select cases, has tightened credit terms, including obtaining additional security, to minimize the consequences of the risk of default on receivables. Generally, the Company classifies receivables older than 30 days as past due. The Company minimizes credit risk applicable to derivatives counterparties by entering into risk management transactions only with institutions that possess investment grade credit ratings or which have provided the Company with an acceptable form of credit protection. The Company has no significant concentration

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with any single counterparty. For transactions with terms greater than five years, the Company may also require a counterparty that would otherwise meet the Company’s credit criteria to provide collateral. During 2010 and 2011, despite challenging market conditions, the Company did not suffer any material credit losses.

FINANCING RISK

The Company’s financing risk relates to the price volatility and availability of debt to finance organic growth projects and refinance existing debt maturities. This risk is directly influenced by market factors, as Canadian and United States financial market conditions can change dramatically, affecting capital availability.

To address this risk, the Company maintains sufficient liquidity through committed credit facilities with its diversified banking groups designed to enable the Company to fund all anticipated requirements for one year without accessing the capital markets. In addition, the Company strives to ensure that it can readily access the Canadian and United States public capital markets by maintaining current shelf prospectuses with the securities regulators.

LIQUIDITY RISK

Liquidity risk is the risk that the Company will not be able to meet its financial obligations, including commitments and guarantees. To manage this risk, the Company forecasts the cash requirements over a twelve month rolling time period to determine whether sufficient funds will be available. The Company’s primary sources of liquidity and capital resources are funds generated from operations, the issuance of commercial paper and draws under committed credit facilities, as well as access to capital markets. The Company maintains current shelf prospectuses with the securities regulators, which enable, subject to market conditions, ready access to either the Canadian or United States public capital markets.

MATURITIES OF DERIVATIVE FINANCIAL INSTRUMENTS

For the years ending December 31, 2012 through 2016, and thereafter, the Company has estimated the following undiscounted cash flows will arise from its derivative instruments based on the valuations at the balance sheet date:

|  | 2012 |  | 2013 |  | 2014 |  | 2015 |  | 2016 |  | Thereafter
(millions of Canadian dollars) Cash inflows | 440 |  | 213 |  | 180 |  | 69 |  | 74 |  | 105
Cash outflows | (401) |  | (133) |  | (124) |  | (77) |  | (65) |  | (610)
Net cash flows | 39 |  | 80 |  | 56 |  | (8) |  | 9 |  | (505)

The maturity profile of non-derivative financial liabilities is presented in Liquidity and Capital Resources.

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FINANCIAL INSTRUMENTS

December 31, 2011 |  | Held for Trading |  | Available for Sale |  | Loans and Receivables |  | Held to Maturity |  | Other Financial Liabilities |  | Qualifying Derivatives |  | Non- Financial Instruments |  | Total |  | Fair Value 1
(millions of Canadian dollars) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Cash and cash equivalents |  | 420 |  | - |  | - |  | - |  | - |  | - |  | - |  | 420 |  | 420
Accounts receivable and other |  | 443 |  | - |  | 2,392 |  | - |  | - |  | 22 |  | 279 |  | 3,136 |  | 2,857
Long-term investments |  | - |  | 56 |  | - |  | 285 |  | - |  | - |  | 2,199 |  | 2,540 |  | 285
Deferred amounts and other assets |  | 450 |  | - |  | 4 |  | - |  | - |  | 99 |  | 2,667 |  | 3,220 |  | 553
Liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Bank indebtedness |  | 102 |  | - |  | - |  | - |  | - |  | - |  | - |  | 102 |  | 102
Short-term borrowings |  | - |  | - |  | - |  | - |  | 548 |  | - |  | - |  | 548 |  | 548
Accounts payable and other |  | 365 |  | - |  | - |  | - |  | 2,728 |  | 346 |  | 283 |  | 3,722 |  | 3,439
Interest payable |  | - |  | - |  | - |  | - |  | 114 |  | - |  | - |  | 114 |  | 114
Long-term debt |  | - |  | - |  | - |  | - |  | 14,509 |  | - |  | - |  | 14,509 |  | 16,772
Non-recourse long-term debt |  | - |  | - |  | - |  | - |  | 1,073 |  | - |  | - |  | 1,073 |  | 1,248
Other long-term liabilities |  | 88 |  | - |  | - |  | - |  | - |  | 345 |  | 1,459 |  | 1,892 |  | 433

December 31, 2010 |  | Held for Trading |  | Available for Sale |  | Loans and Receivables |  | Held to Maturity |  | Other Financial Liabilities |  | Qualifying Derivatives |  | Non- Financial Instruments |  | Total |  | Fair Value 1
(millions of Canadian dollars) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Cash and cash equivalents |  | 342 |  | - |  | - |  | - |  | - |  | - |  | - |  | 342 |  | 342
Accounts receivable and other |  | 145 |  | - |  | 2,113 |  | - |  | - |  | 25 |  | 423 |  | 2,706 |  | 2,283
Long-term investments |  | - |  | 54 |  | 339 |  | 181 |  | - |  | - |  | 1,624 |  | 2,198 |  | 520
Deferred amounts and other assets |  | 277 |  | - |  | 334 |  | - |  | - |  | 185 |  | 2,090 |  | 2,886 |  | 462
Liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Bank indebtedness |  | 100 |  | - |  | - |  | - |  | - |  | - |  | - |  | 100 |  | 100
Short-term borrowings |  | - |  | - |  | - |  | - |  | 326 |  | - |  | - |  | 326 |  | 326
Accounts payable and other |  | 62 |  | - |  | - |  | - |  | 2,393 |  | 76 |  | 157 |  | 2,688 |  | 2,531
Interest payable |  | - |  | - |  | - |  | - |  | 117 |  | - |  | - |  | 117 |  | 117
Long-term debt |  | - |  | - |  | - |  | - |  | 13,715 |  | - |  | - |  | 13,715 |  | 14,770
Non-recourse long-term debt |  | - |  | - |  | - |  | - |  | 1,131 |  | - |  | - |  | 1,131 |  | 1,298
Other long-term liabilities |  | 6 |  | - |  | - |  | - |  | - |  | 127 |  | 1,340 |  | 1,473 |  | 133

1 Fair value does not include non-financial instruments, which includes investments accounted for under the equity method, available for sale equity instruments held at cost that do not trade on an actively quoted market and affiliate long-term notes receivable resulting from related party transactions carried at historical cost.

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Fair Value of Financial Instruments

The fair value of financial instruments reflects the Company’s best estimates of market value based on generally accepted valuation techniques or models and supported by observable market prices and rates. When such prices are not available, the Company uses discounted cash flow analysis from applicable yield curves based on observable market inputs to estimate fair value. The fair value of financial instruments, other than derivatives, represents the amounts that would have been received from or paid to counterparties to settle these instruments at the reporting date.

The fair value of cash and cash equivalents and short-term borrowings approximates their carrying value due to their short-term maturities. The fair value of the Company’s long-term investments, other than those classified as available for sale, approximates their carrying value due to interest terms which approximate floating interest rates. The fair value of the Company’s long-term debt and non-recourse long-term debt is based on quoted market prices for instruments of similar yield, credit risk and tenure. The fair value of other financial assets and liabilities other than derivative instruments approximate their cost due to the short period to maturity. Changes in the fair value of financial liabilities other than derivative instruments are due primarily to fluctuations in interest rates.

DERIVATIVE INSTRUMENTS

The following table summarizes the maturity and total notional principal or quantity outstanding related to the Company’s derivative instruments.

|  | 2011 |  | 2010 |
December 31, |  | Maturity |  | Notional Principal or Quantity Outstanding |  | Maturity |  | Notional Principal or Quantity Outstanding |
U.S. dollar forwards - purchase (millions of United |  |  |  |  |  |  |  |  |
States dollars) |  | 2012-2020 |  | 1,281 |  | 2011-2020 |  | 1,185 |
U.S. dollar forwards - sell (millions of United |  |  |  |  |  |  |  |  |
States dollars) |  | 2012-2020 |  | 10,866 |  | 2011-2020 |  | 3,516 |
Interest rate contracts (millions of Canadian dollars) |  | 2012-2029 |  | 16,540 |  | 2011-2029 |  | 10,772 |
Commodity contracts - energy (bcfe) |  | 2012-2013 |  | 2 |  | 2011-2013 |  | 41 |
Commodity contracts - power (MW/H) |  | 2012-2024 |  | 53 |  | 2011-2024 |  | 2 |
Equity contracts (millions of shares) |  | 2011-2013 |  | 2 |  | 2011-2012 |  | 1 |

The Company has also designated a US$300 million (2010 - US$300 million) medium-term note and US$15 million (2010 - US$15 million) of commercial paper as hedges of certain United States dollar investments.

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The following table summarizes the fair value of the Company’s derivative instruments.

December 31, 2011 |  | Derivative Instruments used as Cash Flow Hedges |  | Derivative Instruments used as Net Investment Hedges |  | Non-Qualifying Derivative Instruments |  | Total Derivative Instruments
(millions of Canadian dollars) |  |  |  |  |  |  |  |
Accounts receivable and other |  |  |  |  |  |  |  |
Foreign exchange contracts |  | 4 |  | 15 |  | 315 |  | 334
Interest rate contracts |  | - |  | - |  | 7 |  | 7
Commodity contracts |  | - |  | - |  | 114 |  | 114
Equity contracts |  | 3 |  | - |  | 7 |  | 10
|  | 7 |  | 15 |  | 443 |  | 465
Deferred amounts and other |  |  |  |  |  |  |  |
Foreign exchange contracts |  | 15 |  | 79 |  | 203 |  | 297
Interest rate contracts |  | 1 |  | - |  | 22 |  | 23
Commodity contracts |  | 1 |  | - |  | 223 |  | 224
Equity contracts |  | 3 |  | - |  | 2 |  | 5
|  | 20 |  | 79 |  | 450 |  | 549
Accounts payable and other |  |  |  |  |  |  |  |
Foreign exchange contracts |  | (4) |  | - |  | (275) |  | (279)
Interest rate contracts |  | (341) |  | - |  | (3) |  | (344)
Commodity contracts |  | (1) |  | - |  | (87) |  | (88)
|  | (346) |  | - |  | (365) |  | (711)
Other long-term liabilities |  |  |  |  |  |  |  |
Foreign exchange contracts |  | (35) |  | (5) |  | (51) |  | (91)
Interest rate contracts |  | (303) |  | - |  | (18) |  | (321)
Commodity contracts |  | (2) |  | - |  | (19) |  | (21)
|  | (340) |  | (5) |  | (88) |  | (433)
Total net derivative asset/(liability) |  |  |  |  |  |  |  |
Foreign exchange contracts |  | (20) |  | 89 |  | 192 |  | 261
Interest rate contracts |  | (643) |  | - |  | 8 |  | (635)
Commodity contracts |  | (2) |  | - |  | 231 |  | 229
Equity contracts |  | 6 |  | - |  | 9 |  | 15
|  | (659) |  | 89 |  | 440 |  | (130)

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December 31, 2010 |  | Derivative Instruments used as Cash Flow Hedges |  | Derivative Instruments used as Net Investment Hedges |  | Non- Qualifying Derivative Instruments |  | Total Derivative Instruments
(millions of Canadian dollars) |  |  |  |  |  |  |  |
Accounts receivable and other |  |  |  |  |  |  |  |
Foreign exchange contracts |  | 4 |  | 15 |  | 111 |  | 130
Interest rate contracts |  | 6 |  | - |  | - |  | 6
Commodity contracts |  | - |  | - |  | 33 |  | 33
Equity contracts |  | - |  | - |  | 1 |  | 1
|  | 10 |  | 15 |  | 145 |  | 170
Deferred amounts and other |  |  |  |  |  |  |  |
Foreign exchange contracts |  | 18 |  | 100 |  | 275 |  | 393
Interest rate contracts |  | 67 |  | - |  | - |  | 67
Commodity contracts |  | - |  | - |  | 2 |  | 2
|  | 85 |  | 100 |  | 277 |  | 462
Accounts payable and other |  |  |  |  |  |  |  |
Foreign exchange contracts |  | (4) |  | - |  | (11) |  | (15)
Interest rate contracts |  | (72) |  | - |  | - |  | (72)
Commodity contracts |  | - |  | - |  | (51) |  | (51)
|  | (76) |  | - |  | (62) |  | (138)
Other long-term liabilities |  |  |  |  |  |  |  |
Foreign exchange contracts |  | (47) |  | - |  | (3) |  | (50)
Interest rate contracts |  | (80) |  | - |  | - |  | (80)
Commodity contracts |  | - |  | - |  | (3) |  | (3)
|  | (127) |  | - |  | (6) |  | (133)
Total net derivative asset/(liability) |  |  |  |  |  |  |  |
Foreign exchange contracts |  | (29) |  | 115 |  | 372 |  | 458
Interest rate contracts |  | (79) |  | - |  | - |  | (79)
Commodity contracts |  | - |  | - |  | (19) |  | (19)
Equity contracts |  | - |  | - |  | 1 |  | 1
|  | (108) |  | 115 |  | 354 |  | 361

The fair value of derivative instruments has primarily been estimated using models or other industry standard valuation techniques derived from observable market information. This market information includes published market prices for commodities, interest rate yield curves, foreign exchange rates and equity prices. When possible, financial instruments are valued using quoted market prices.

An unrealized fair value loss of $593 million (2010 - $82 million) related to derivative instruments used as cash flow and net investment hedges was recognized in OCI for the year ended December 31, 2011. An unrealized fair value gain related to non-qualifying derivative instruments of $78 million (2010 - $26 million) was recognized in transportation revenues, commodity costs, other investment income and interest expense for the year ended December 31, 2011.

Additional information about the Company’s Risk Management and Financial Instruments is included in Notes 23 and 24 of the 2011 Annual Consolidated Financial Statements.

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GENERAL BUSINESS RISKS

Strategy and Execution Risks

Project Execution

The Company’s ability to successfully execute the development of its organic growth projects may be influenced by capital constraints, third-party opposition, changes in shipper support over time, delays in or changes to government and regulatory approvals, cost escalations, construction delays, inadequate resources and in-service delays (collectively, Execution Risk). Customer trends are toward expecting the Company to assume more risk and accept lower returns. Early stage project risks include right-of-way procurement, special interest group opposition, Crown consultation and environmental and regulatory permitting. Cost escalations may impact project economics. Construction delays due to regulatory delays, contractor or supplier non-performance and weather conditions may impact project development.

The Company has a centralized and clearly defined governance structure and process for all major projects with dedicated resources organized to lead and execute each major project. Capital constraints and cost escalation risks are mitigated through structuring of commercial agreements, typically where shippers retain complete or a share of capital cost excess. Early stage project risks are mitigated by early assessment of stakeholder issues to develop proactive relationships and specific action plans. Detailed cost tracking and centralized purchasing is used on all major projects to facilitate optimum pricing and service terms. Strategic relationships have been developed with suppliers and contractors.

Investment Analysis

The Company evaluates the value proposition for expansion projects, new acquisitions or divestitures on an ongoing basis. Investment analysis may be ineffective in terms of earnings projections, cost estimates, project scoping, and risk assessment resulting in a loss in profits for the Company. Large scale acquisitions may involve significant pricing and integration risk.

A centralized corporate development group which is appropriately staffed rigorously evaluates all major investment proposals with consistent due diligence processes including a thorough review of the asset quality, systems and financial performance of the assets being assessed.

Reputation Risk

The Company’s reputation is one of its most valuable assets. Reputation risk is the risk of negative impacts on the Company’s business, operations or financial condition resulting from changes in the Company’s reputation with stakeholders and other entities. These potential impacts may include loss of business, legal action, increased regulatory oversight and costs.

Reputation risk often arises as a consequence of some other risk event, such as in connection with operational, regulatory or legal risks. Therefore, reputation risk cannot be managed in isolation from other risks. The Company manages reputation risk by:

· having formal risk management policies, procedures and systems in place to identify, assess and mitigate risks to the Company;

· operating to the highest ethical standards, with integrity, honesty and transparency, and maintaining positive relationships with customers, investors, employees, partners, regulators and other stakeholders;

· having health, safety and environment management systems in place, as well as policies, programs and practices for conducting safe and environmentally sound operations;

· having strong corporate governance practices, including a Statement on Business Conduct, with which all employees are required to certify their compliance on an annual basis, and whistleblower procedures, which allow employees to report suspected ethical concerns on a confidential and anonymous basis; and

· pursuing socially responsible operations as a longer-term corporate strategy (implemented through the Company’s CSR Policy, Climate Change Policy, Aboriginal and Native American

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Policy and initiatives such as the Neutral Footprint Initiative and the Company’s commitment to Green Energy).

Operational Risks

System Integrity

Pipeline leaks are an inherent risk of operations. Other operating risks include: the breakdown or failure of equipment, information systems or processes; the performance of equipment at levels below those originally intended (whether due to misuse, unexpected degradation or design, construction or manufacturing defects); failure to maintain adequate supplies of spare parts; operator error; labour disputes; disputes with interconnected facilities and carriers; and catastrophic events such as natural disasters, fires, explosions, fractures, acts of terrorists and saboteurs and other similar events, many of which are beyond the control of the pipeline systems. The occurrence or continuance of any of these events could increase the cost of operating and insuring the Company’s assets or reduce revenues, thereby impacting earnings.

The Company has an extensive program to manage system integrity, which includes the development and use of in-line inspection tools. Maintenance, excavation and repair programs are directed to the areas of greatest benefit and pipe is replaced or repaired as required and are supported by operating and capital budgets directed to pipeline integrity. Emergency response plans, operator training and landowner education programs are included in the Company’s response preparedness. The Company also maintains comprehensive insurance coverage for significant pipeline leaks and has a comprehensive security program designed to reduce security-related risks. While the Company feels the level of insurance is adequate, it may not be sufficient to cover all potential losses.

Environmental, Health and Safety Risk

The Company’s operations, facilities and petroleum product shipments are subject to extensive national, regional and local environmental, health and safety laws and regulations governing, among other things, discharges to air, land and water, the handling and storage of petroleum compounds and hazardous materials, waste disposal, the protection of employee health, safety and the environment and the investigation and remediation of contamination. The Company’s facilities, or facilities to which it provides operating services, could experience incidents, malfunctions or other unplanned events that result in spills or emissions in excess of permitted levels and result in personal injury, fines, penalties or other sanctions and property damage. The Company could also incur liability in the future for environmental contamination associated with past and present activities and properties. The facilities and pipelines must maintain a number of environmental and other permits from various governmental authorities in order to operate and these facilities are subject to inspection from time to time. Failure to maintain compliance with these requirements could result in operational interruptions, fines or penalties, or the need to install potentially costly pollution control technology. Compliance with current and future environmental laws and regulations, which are likely to become more stringent over time, including those governing greenhouse gas (GHG) emissions, may impose additional capital costs and financial expenditures and affect the demand for the Company’s services, which could adversely affect operating results and profitability. Restrictions on other resources, such as water or electricity, may affect the Company’s upstream customers’ ability to produce crude oil and natural gas. The Company could be targeted, along with the oil sands industry, by environmental groups attempting to draw attention to GHG emissions.

Enbridge is committed to protecting the health and safety of employees, contractors and the general public, and to sound environmental stewardship. The Company believes that prevention of incidents and injuries, and protection of the environment, benefits everyone and delivers increased value to shareholders, customers and employees. Enbridge has health and safety and environmental management systems and has established policies, programs and practices for conducting safe and environmentally sound operations. Ongoing training is provided to ensure employee and contractor competency as well as to enhance the safety culture at Enbridge. Regular reviews and audits are conducted to assess compliance with legislation and Company policy.

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Information Systems

The Company’s infrastructure, applications and data are becoming more integrated, creating increased risk that a failure in one system could lead to a failure of another system. Major systems development involves project management risks including implementation delays, scope creep, cost overruns or failure of systems to meet original project requirements. Disruption to business operations due to inadequate information security safeguards is also a risk.

The Company has a centralized information office which supports the development of standardized systems, use of industry proven packages where feasible, use of an information security risk management strategy and disaster recovery plans for critical operations. Back-up computers are installed in business units for enterprise-wide fail protection. Project management risks are mitigated through both a strict value proposition evaluation and a robust pre-implementation testing process with high quality requirements.

Business Environment Risks

Aboriginal Relations

Canadian judicial decisions have recognized that Aboriginal rights and treaty rights exist in proximity to the Company’s operations and future project developments. The courts have also confirmed that the Crown has a duty to consult with Aboriginal peoples when its decisions or actions may adversely affect Aboriginal rights and interests or treaty rights. Crown consultation has the potential to delay regulatory approval processes and construction, which may affect project economics. In some cases, respecting Aboriginal rights may mean regulatory approval is denied or made economically challenging.

Given this environment and the breadth of relationships across the Company’s geographic span, Enbridge has implemented the Aboriginal and Native American Policy. This Policy promotes the achievement of participative and mutually beneficial relationships with Aboriginal and Native American groups affected by the Company’s projects and operations. Specifically, the Policy sets out principles governing the Company’s relationships with Aboriginal and Native American peoples and makes commitments to work with Aboriginal peoples and Native Americans so they may realize benefits from the Company’s projects and operations. Notwithstanding the Company’s efforts to this end, the issues are complex and the impact of Aboriginal relations on Enbridge’s operations and development initiatives is uncertain.

Special Interest Groups including Non-Governmental Organizations

The Company is exposed to the risk of higher costs, delays or even project cancellations due to increasing pressure on governments and regulators by special interest groups, including non-governmental organizations. Recent Supreme Court decisions have increased the ability of special interest groups to make claims and oppose projects in regulatory and legal forums. In addition to issues raised by groups focused on particular project impacts, the Company and others in the energy and pipeline businesses are facing opposition from organizations opposed to oil sands development and shipment of production from oil sands regions.

The Company works proactively with special interest groups and non-governmental organizations to identify and develop appropriate responses to their concerns regarding its projects. The Company is investing significant resources in these areas. Its CSR program also reports on the Company’s responsiveness to environmental and community issues. Please see Enbridge’s annual CSR report, available online at csr.enbridge.com for further details regarding the CSR program. None of the information contained on, or connected to, Enbridge’s website is incorporated in or otherwise part of this MD&A.

Regulatory and Compliance Risks

Unfavourable Rulings

Many of the Company’s pipeline operations are regulated and are subject to regulatory risk. The nature and degree of regulation and legislation affecting energy companies in Canada and the United States has changed significantly in past years and there is no assurance that further substantial changes will not occur. These changes may adversely affect toll structures or other aspects of pipeline operations or the

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operations of shippers. Recently shippers have challenged toll increases on various pipelines owned by Enbridge and some of Enbridge’s competitors. Enbridge retains dedicated professional staff and maintains strong relationships with customers, interveners and regulators to help minimize regulatory risk.

Climate Change Legislation

Uncertainty continues with respect to GHG regulations in Canada and the United States. The federal governments of both countries have signaled their intention to develop sector specific carbon related regulations but are reluctant to implement measures that might slow economic recovery. As a result, it is uncertain how climate legislation could affect the industry.

Enbridge has voluntarily reported its GHG emissions for over ten years. The Company is on track to deploy a new emissions data management system to ensure compliance with reporting requirements mandated in Canada and the United States. The Company will continue to monitor GHG regulatory developments and publicly report its GHG emissions as well as develop internal procedures to reduce these emissions.

Renewable Energy

Enbridge has significant interests in wind, solar and geothermal power generation and is well positioned to expand this portfolio. Many programs to encourage and advance renewable energy exist in Canada and the United States as well as individual provinces and states. Enbridge continues to assess and advance renewable energy opportunities and monitor potential changes to government policies and incentives that may positively or negatively impact existing or future renewable energy projects.

CRITICAL ACCOUNTING ESTIMATES

DEPRECIATION

Depreciation of property, plant and equipment, the Company’s largest asset with a net book value at December 31, 2011 of $22,623 million (2010 - $20,332 million), or 66% of total assets, is generally provided on a straight-line basis over the estimated service lives of the assets commencing when the asset is placed in service. When it is determined that the estimated service life of an asset no longer reflects the expected remaining period of benefit, prospective changes are made to the estimated service life. Estimates of useful lives are based on third party engineering studies, experience and/or industry practice. There are a number of assumptions inherent in estimating the service lives of the Company’s assets including the level of development, exploration, drilling, reserves and production of crude oil and natural gas in the supply areas served by the Company’s pipelines as well as the demand for crude oil and natural gas and the integrity of the Company’s systems. Changes in these assumptions could result in adjustments to the estimated service lives, which could result in material changes to depreciation expense in future periods in any of the Company’s business segments. For certain rate-regulated operations, depreciation rates are approved by the regulator and the regulator may require periodic studies or technical updates on useful lives which may change depreciation rates.

REGULATORY ASSETS AND LIABILITIES

Certain of the Company’s businesses are subject to regulation by various authorities, including but not limited to, the NEB, the FERC, the Energy Resources Conservation Board and the OEB. Regulatory bodies exercise statutory authority over matters such as construction, rates and ratemaking and agreements with customers. To recognize the economic effects of the actions of the regulator, the timing of recognition of certain revenues and expenses in operations may differ from that otherwise expected under GAAP for non rate-regulated entities. Also, the Company records regulatory assets and liabilities to recognize the economic effects of the actions of the regulator. Regulatory assets represent amounts that are expected to be recovered from customers in future periods through rates. Regulatory liabilities represent amounts that are expected to be refunded to customers in future periods through rates. On refund or recovery of this difference, no earnings impact is recorded. Effectively, the income statement captures only the approved costs and the related revenue rather than the actual costs and related revenue. As of December 31, 2011, the Company’s significant regulatory assets totaled $1,337 million (2010 - $1,368 million) and significant regulatory liabilities totaled $931 million (2010 - $1,014 million). To

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the extent that the regulator’s actions differ from the Company’s expectations, the timing and amount of recovery or settlement of regulatory balances could differ significantly from those recorded.

On December 9, 2011, the Government of New Brunswick tabled and subsequently passed legislation related to the regulatory process for setting rates for gas distribution within the province. Significant details of the rate setting process were left to be established in the new regulations which have yet to be published. As the details of the regulations have not yet been made available, the effect of such regulations is not determinable as at February 21, 2012. See Gas Distribution – Other Gas Distribution and Storage – Enbridge Gas New Brunswick Regulatory Matters.

POST-EMPLOYMENT BENEFITS

The Company maintains pension plans, which provide defined benefit and/or defined contribution pension benefits and post-employment benefits other than pensions (OPEB) to eligible retirees. Pension costs and obligations for the defined benefit pension plans are determined using the universal method. This method involves complex actuarial calculations using several assumptions including discount rates, which were determined using the discount rate curve developed by the Canadian Institute of Actuaries, expected rates of return on plan assets, health-care cost trend rates, projected salary increases, retirement age, mortality and termination rates. These assumptions are determined by management and are reviewed annually by the Company’s actuaries. Actual results that differ from assumptions are amortized over future periods and therefore could materially affect the expense recognized and the recorded obligation in future periods. The Company remains able to pay the current benefit obligations using cash from operations, reflecting strong capital market performance recovery. The shortfall from expected return on plan assets was $76 million for the year ended December 31, 2011 (2010 - $47 million excess) as disclosed in Note 27 to the 2011 Annual Consolidated Financial Statements. The difference between the actual and expected return on plan assets is amortized over the remaining service period of the active employees.

The following sensitivity analysis identifies the impact on the December 31, 2011 Consolidated Financial Statements of a 0.5% change in key pension and OPEB assumptions.

|  | Pension Benefits |  | OPEB |
|  | Obligation |  | Expense |  | Obligation |  | Expense |
(millions of Canadian dollars) |  |  |  |  |  |  |  |  |
Decrease in discount rate |  | 126 |  | 14 |  | 18 |  | 1 |
Decrease in expected return on assets |  | - |  | 6 |  | - |  | - |
Decrease in rate of salary increase |  | (25) |  | (5) |  | - |  | - |

CONTINGENT LIABILITIES

Provisions for claims filed against the Company are determined on a case by case basis. Case estimates are reviewed on a regular basis and are updated as new information is received. The process of evaluating claims involves the use of estimates and a high degree of management judgment. Claims outstanding, the final determination of which could have a material impact on the financial results of the Company and certain of the Company’s subsidiaries and investments, including EGD and EECI, are detailed in the Commitments and Contingencies section of this report and are disclosed in Note 31 of the 2011 Annual Consolidated Financial Statements. In addition, any unasserted claims that later may become evident could have a material impact on the financial results of the Company and certain of the Company’s subsidiaries and investments.

ASSET RETIREMENT OBLIGATIONS

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

On November 29, 2011, as required by NEB, the Company filed the applications for its regulated pipelines systems within Enbridge Pipelines Inc. and Enbridge Pipelines (NW) Inc. (Group 1 companies) and Enbridge Southern Lights GP Inc., Enbridge Bakken Pipeline Company Inc., Enbridge Pipelines (Westspur) Inc., and Vector Pipelines Limited Partnership (Group 2 companies). The Company is seeking NEB approval of its preliminary calculations, which were largely based on the base case assumptions issued by NEB specifically for the purpose of this filing. The NEB is also requiring regulated pipeline companies to file a proposed process for collecting and setting aside the funds for abandonment by

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November 30, 2012 for Group 1 companies and by March 31, 2013 for Group 2 companies.

Both of the required submissions will require NEB approval and will result in increases to transportation tolls and regulatory liabilities, the amount of which is uncertain at this time. Currently, for certain of the Company’s assets, there is insufficient data or information to reasonably determine the timing and/or method of settlement for estimating the fair value of the asset retirement obligation (ARO). In these cases, the ARO cost is considered indeterminate for accounting purposes, as there is no data or information that can be derived from past practice, industry practice or the estimated economic life of the asset.

CHANGES IN ACCOUNTING POLICIES

BUSINESS COMBINATIONS

Effective January 1, 2011, the Company adopted Part V Section 1582, Business Combinations, which replaces Section 1581. The new standard requires assets and liabilities acquired in a business combination to be measured at fair value at the acquisition date and if applicable, any original equity interest in the investee to be re-measured to fair value through earnings on the date control is obtained. The standard also requires that acquisition-related costs, such as advisory or legal fees, incurred to effect a business combination be expensed in the period in which they are incurred. In accordance with the transitional provisions of this standard, Section 1582 was adopted prospectively and accordingly, assets and liabilities that arose from business combinations occurring before January 1, 2011 were not restated. The application of this standard decreased Earnings attributable to Enbridge Inc. by $37 million, net of income taxes of $5 million for dilution gains for subsidiaries, which are now recognized in equity for the year ended December 31, 2011. The application of this standard had no material impact to the Company’s cash flows for the year ended December 31, 2011.

CONSOLIDATED FINANCIAL STATEMENTS AND NONCONTROLLING INTERESTS

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

FUTURE ACCOUNTING POLICIES

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

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

As a rate regulated accounting standard model has not been finalized by the International Accounting Standards Board, the Company does not intend to adopt IFRS in 2012 but rather U.S. GAAP. As a United States Securities and Exchange Commission (SEC) registrant, Enbridge is permitted by Canadian securities regulation to prepare its financial statements in accordance with U.S. GAAP and will adopt U.S. GAAP for interim and annual financial statements beginning on January 1, 2012.

In preparation for the U.S. GAAP conversion, Enbridge has formed a U.S. GAAP project team and developed a transition plan and governance structure to monitor the progress of the transition. The

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Company has engaged a public accounting firm to assist with the project and to provide technical accounting advice on the interpretation and application of U.S. GAAP to its primary financial statements. Management reports regularly to the Audit, Finance and Risk Committee of the Board of Directors on the advancement of the conversion to U.S. GAAP.

Accounting and Reporting

The Company is in the process of integrating known U.S. GAAP differences into its primary financial statements. The most significant U.S. GAAP differences impact the following areas:

· consolidation of EEP;

· equity accounting treatment of joint ventures;

· inventory valuation;

· common control transactions;

· classification and valuation of redeemable noncontrolling interests;

· pensions and OPEB; and

· presentation differences, including the presentation of deferred financing costs.

Under U.S. GAAP the Company is deemed to control EEP and will therefore consolidate its interest in the partnership. The Company will commence reporting using U.S. GAAP as its primary basis of accounting in the first quarter of 2012. To facilitate users understanding of the transition, subsequent to filing its Canadian GAAP financial statements for the year ended December 31, 2011 and before filing its first interim report under U.S. GAAP, the Company will provide, for information purposes, its 2011 financial statements restated under U.S. GAAP along with comparative periods and related note disclosures.

Training

As an SEC registrant, the Company has experience reporting under U.S. GAAP and has reconciled its financial statements to U.S. GAAP for many years. Further, two of the Company’s affiliates, EEM and EEP are also registered with the SEC and currently prepare and file U.S. GAAP financial statements. The Company has provided supplemental U.S. GAAP training to internal personnel impacted by the conversion. U.S. GAAP training will continue into and beyond 2012 as a regular business activity.

Information Systems and Business Processes

The Company has completed testing system changes necessary to support the conversion to U.S GAAP and to sustain U.S. GAAP reporting in 2012 and beyond. Implementation of these changes will take place in the first quarter of 2012. Impacts to internal controls over financial reporting and disclosures have been evaluated and no significant impacts were noted.

Business Activities

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

The detailed project plan and the expected timing of key activities identified above may change prior to the U.S. GAAP conversion date due to economic conditions or other factors.

Future Accounting Standards under U.S. GAAP

The following standards will be effective for the Company beginning on January 1, 2012. Management does not expect the adoption of any of these standards to significantly impact the consolidated financial statements.

Fair Value Measurement

In May 2011, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) 2011-04, which revises the existing guidance on fair value measurement under U.S. GAAP as part of the FASB’s joint project with the International Accounting Standards Board. Under the revised standard, the Company will be required to provide additional disclosures about fair value measurements, including information about the unobservable inputs and assumptions used in Level 3 fair value measurements, a description of the valuation methodologies used in Level 3 fair value measurements, and the level in the fair value hierarchy of items that are not measured at fair value but whose fair value disclosure is required. The adoption of this pronouncement is not anticipated to have a material impact on the Company’s financial statements. This accounting update is effective for the first reporting period beginning after December 15, 2011.

Statement of Comprehensive Income

In June 2011, the FASB issued ASU 2011-05, which updates the existing guidance on comprehensive income under U.S. GAAP, requiring presentation of net income and OCI either in one continuous statement, referred to as the Statement of Comprehensive Income, or in two separate but consecutive statements of net income and OCI. The adoption of this pronouncement does not affect the Company’s presentation of comprehensive income, and will not have an impact on the Company’s financial statements. This accounting update is effective for the first reporting period beginning after December 15, 2011.

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Goodwill Impairment

In September 2011, the FASB issued ASU 2011-08, which is intended to reduce the overall costs and complexity of goodwill impairment testing. The standard allows an entity to first assess qualitative factors to determine whether it is necessary to perform the current two-step goodwill impairment test. An entity will not be required to calculate the fair value of a reporting unit unless the entity determines, based on a qualitative assessment, that it is more likely than not that its fair value is less than its carrying amount. The standard does not change the current two-step test and applies to all entities that have goodwill reported in their financial statements. The adoption of this pronouncement is not anticipated to have a material impact on the Company’s financial statements. This accounting update is effective for annual and interim goodwill impairment tests performed for fiscal years beginning after December 15, 2011.

Balance Sheet Offsetting

In December 2011, the FASB issued ASU 2011-11, which provides enhanced disclosures on the effect or potential effect of netting arrangements on an entity’s financial position. The adoption of the pronouncement affects financial statement disclosures only and is not anticipated to have a material impact on the Company’s financial statements. This accounting update is effective for annual and interim beginning on or after January 1, 2013.

CONTROLS AND PROCEDURES

DISCLOSURE CONTROLS AND PROCEDURES

Disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed in reports filed with, or submitted to, securities regulatory authorities is recorded, processed, summarized and reported within the time periods specified under Canadian and United States securities law. As of the year ended December 31, 2011, an evaluation was carried out under the supervision of and with the participation of Enbridge’s management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operations of Enbridge’s disclosure controls and procedures (as defined in Rule 13a-15(e) under the Securities Exchange Act of 1934).

Based on that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the design and operation of these disclosure controls and procedures were effective in ensuring that information required to be disclosed by Enbridge in reports that it files with or submits to the SEC and the Canadian Securities Administrators is recorded, processed, summarized and reported within the time periods required.

Management’s Report on Internal Control over Financial Reporting

Management of Enbridge is responsible for establishing and maintaining adequate internal control over financial reporting as such term is defined in the rules of the SEC and the Canadian Securities Administrators. The Company’s internal control over financial reporting is a process designed under the supervision and with the participation of executive and financial officers to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company’s financial statements for external reporting purposes in accordance with Canadian GAAP.

The Company’s internal control over financial reporting includes policies and procedures that:

· pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of assets of the Company;

· provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles; and

· provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the financial statements.

The Company’s internal control over financial reporting may not prevent or detect all misstatements because of inherent limitations. Additionally, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions or deterioration in the degree of compliance with the Company’s policies and procedures.

Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2011, based on the framework established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, Management concluded that the Company maintained effective internal control over financial reporting as of December 31, 2011.

During the year ended December 31, 2011, there has been no material change in the Company’s internal control over financial reporting.

The effectiveness of the Company’s internal control over financial reporting as of December 31, 2011 has been audited by PricewaterhouseCoopers LLP, independent auditors appointed by the shareholders of the Company.

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NON-GAAP RECONCILIATIONS

|  | 2011 |  | 2010 |  | 2009 |
(millions of Canadian dollars) |  |  |  |  |  |  |
GAAP earnings as reported |  | 991 |  | 963 |  | 1,555 |
Significant after-tax non-recurring or non-operating factors and variances: |  |  |  |  |  |  |
Liquids Pipelines |  |  |  |  |  |  |
Canadian Mainline - shipper dispute settlement |  | (14) |  | - |  | - |
Canadian Mainline - Line 9 tolling adjustment |  | (10) |  | - |  | - |
Canadian Mainline - unrealized derivative fair value loss |  | 48 |  | - |  | - |
Regional Oil Sands System - asset impairment loss |  | 8 |  | - |  | - |
Regional Oil Sands System - leak remediation costs |  | - |  | - |  | 9 |
Spearhead Pipeline - unrealized derivative fair value gains |  | (1) |  | - |  | - |
Gas Distribution |  |  |  |  |  |  |
EGD - warmer/(colder) than normal weather |  | (1) |  | 12 |  | (17 | )
EGD - impact of tax rate changes |  | - |  | - |  | (21 | )
EGD - interest income on GST refund |  | - |  | - |  | (7 | )
Other Gas Distribution and Storage - asset impairment loss |  | - |  | - |  | 10 |
Other Gas Distribution and Storage - adoption of new accounting standard |  | - |  | - |  | 3 |
Gas Pipelines, Processing and Energy Services |  |  |  |  |  |  |
Offshore - property insurance recovery from hurricanes |  | - |  | (2 | ) | (4 | )
Aux Sable - unrealized derivative fair value (gains)/loss |  | 7 |  | (7 | ) | 36 |
Aux Sable - loan forgiveness |  | - |  | - |  | (7 | )
Energy Services - unrealized derivative fair value (gains)/loss |  | (113) |  | 12 |  | (3 | )
Energy Services - Lehman and SemGroup credit recovery |  | - |  | (1 | ) | (1 | )
Other - unrealized derivative fair value gains |  | (24) |  | - |  | - |
Other - gain on sale of investments |  | - |  | - |  | (329 | )
Other - impact of tax rate changes |  | - |  | - |  | (4 | )
Sponsored Investments |  |  |  |  |  |  |
EEP - leak insurance recoveries |  | (50) |  | - |  | - |
EEP - leak remediation costs and lost revenue |  | 33 |  | 106 |  | - |
EEP - unrealized derivative fair value (gains)/loss |  | (3) |  | 1 |  | 2 |
EEP - NGL trucking and marketing prior period adjustment |  | 3 |  | - |  | - |
EEP - shipper dispute settlement |  | (8) |  | - |  | - |
EEP - lawsuit settlement |  | (1) |  | - |  | - |
EEP - impact of unusual weather conditions |  | 1 |  | - |  | - |
EEP - Lakehead System billing correction |  | - |  | (1 | ) | (4 | )
EEP - dilution gain on Class A unit issuance |  | (66) |  | (36 | ) | - |
EEP - asset impairment loss |  | - |  | 2 |  | 12 |
Corporate |  |  |  |  |  |  |
Noverco - impact of tax rate changes |  | - |  | - |  | (6 | )
Other Corporate - unrealized derivative fair value (gains)/loss |  | 87 |  | (25 | ) | (207 | )
Other Corporate - unrealized foreign exchange (gains)/loss on translation of intercompany balances, net |  | 131 |  | (40 | ) | (133 | )
Other Corporate - impact of tax rate changes |  | (6) |  | - |  | (4 | )
Other Corporate - tax on intercompany gain on sale |  | 98 |  | - |  | - |
Other Corporate - gain on sale of investment in NTP |  | - |  | - |  | (25 | )
Adjusted earnings |  | 1,110 |  | 984 |  | 855 |

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