MANAGEMENT’S DISCUSSION AND ANALYSIS

This Management’s Discussion and Analysis (MD&A) dated February 18, 2010 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, 2009, which are prepared in accordance with Canadian generally accepted accounting principles (GAAP). All financial measures presented in this MD&A are expressed in Canadian dollars, unless otherwise indicated. Additional information related to the Company, including its Annual Information Form, is available on SEDAR at www.sedar.com.

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 a 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 and solar energy, and hybrid fuel cells. Enbridge employs approximately 6,000 people, primarily in Canada and the United States.

The Company’s activities are carried out through four business segments, Liquids Pipelines, Natural Gas Delivery and Services, Sponsored Investments and Corporate, as discussed below.

LIQUIDS PIPELINES

Liquids Pipelines includes the operation and construction of the Enbridge crude oil mainline system and feeder pipelines that transport crude oil and other liquid hydrocarbons. Liquids Pipelines consists of crude oil, natural gas liquids (NGLs) and refined products pipelines and terminals in Canada and the United States.

NATURAL GAS DELIVERY AND SERVICES

Natural Gas Delivery and Services consists of natural gas utility operations, investments in natural gas pipelines, the Company’s commodity marketing businesses and international activities.

The core of the Company’s natural gas utility operations is Enbridge Gas Distribution Inc. (EGD) which serves residential, commercial, industrial and transportation 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.

Investments in natural gas pipelines include the Company’s interests in the United States portion of Alliance Pipeline (Alliance Pipeline US), Vector Pipeline and transmission and gathering pipelines in the Gulf of Mexico.

This segment also includes the Company’s investment in Aux Sable, a natural gas fractionation and extraction business.

The commodity marketing businesses manage the Company’s volume commitments on Alliance and Vector Pipelines, as well as perform commodity storage, transport and supply management services, as principal and agent.

SPONSORED INVESTMENTS

Sponsored Investments includes the Company’s 27% ownership interest in Enbridge Energy Partners, L.P. (EEP), Enbridge’s funding of 66.7% of the United States segment of the Alberta Clipper Project through EEP and Enbridge Energy, L.P. (EELP) and a 72% economic interest (41.9% voting interest) in Enbridge Income Fund (EIF). Enbridge manages the day-to-day operations 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. EIF is a publicly traded income fund whose primary operations include a crude oil and liquids pipeline and gathering system, a 50% interest in the Canadian portion of Alliance Pipeline (Alliance Pipeline Canada) and partial interests in several green energy investments.

CORPORATE

Corporate consists of new business development activities as well as investing and financing activities, including general corporate investments and financing costs not allocated to the business segments. Corporate also includes the Company’s investments in green energy projects.

PERFORMANCE OVERVIEW

	Three Months Ended December 31,				Year Ended December 31,
(millions of Canadian dollars, except per share amounts)	2009		2008		2009		2008		2007
Earnings Applicable to Common Shareholders
Liquids Pipelines	141		102		445		328		287
Natural Gas Delivery and Services	96		143		635		958		344
Sponsored Investments	38		32		141		111		97
Corporate	25		(13	)	334		(76	)	(28	)
	300		264		1,555		1,321		700
Earnings per Common Share	0.81		0.72		4.27		3.67		1.97
Diluted Earnings per Common Share	0.80		0.71		4.25		3.64		1.95
Adjusted Earnings1
Liquids Pipelines	141		106		454		332		286
Natural Gas Delivery and Services	84		90		289		302		324
Sponsored Investments	39		27		151		101		86
Corporate	(25	)	(21	)	(39	)	(58	)	(59	)
	239		202		855		677		637
Adjusted Earnings per Common Share1	0.64		0.55		2.35		1.88		1.79
Cash Flow Data
Cash provided by operating activities	182		431		2,017		1,372		1,362
Cash used in investing activities	(1,162	)	(2,091	)	(3,306	)	(2,853	)	(2,229	)
Cash provided by financing activities	912		1,930		1,109		1,840		904
Dividends
Common Share Dividends Declared	139		123		555		489		453
Dividends Per Common Share	0.37		0.33		1.48		1.32		1.23
Revenues
Commodity Sales	2,491		3,116		9,720		13,432		9,536
Transportation and other services	696		808		2,746		2,699		2,383
	3,187		3,924		12,466		16,131		11,919
Total Assets	28,169		24,701		28,169		24,701		19,907
Total Long-Term Liabilities	16,392		13,179		16,392		13,179		10,467

1 Adjusted earnings and adjusted earnings per common share are non-GAAP measures that do not have any standardized meaning prescribed by GAAP. For more information on non-GAAP measures see pages 7 and 66.

EARNINGS APPLICABLE TO COMMON SHAREHOLDERS

Earnings applicable to common shareholders for the three months ended December 31, 2009 were $300 million, or $0.81 per common share, an increase of $36 million compared with $264 million, or $0.72 per common share, for the three months ended December 31, 2008. The increase primarily resulted from allowance for equity funds used during construction (AEDC) in Liquids Pipelines and EELP, within Sponsored Investments, as well as a higher contribution from EEP, also within Sponsored Investments. Other factors contributing to the increase include favourable tax rate changes and net unrealized fair value gains on derivative financial instruments used to risk manage foreign exchange variability. These earnings increases were partially offset by decreased earnings from Aux Sable due to unrealized derivative fair value losses of $25 million recognized in the fourth quarter of 2009 compared with similar gains of $35 million recognized in the fourth quarter 2008.

Earnings applicable to common shareholders were $1,555 million for the year ended December 31, 2009, or $4.27 per common share, compared with $1,321 million, or $3.67 per common share, for the year ended December 31, 2008. Included in earnings for the year ended December 31, 2009 was a $329 million gain related to the sale of the Company’s investment in Oleoducto Central S.A (OCENSA) and a $25 million gain related to the sale of NetThruPut (NTP). Earnings for the year ended December 31, 2008 included a gain of $556 million related to the sale of the Company’s investment in Compañía Logística de Hidrocarburos CLH, S.A. (CLH). Excluding the impact of these dispositions, earnings for the year ended December 31, 2009 were $436 million higher than for the year ended December 31, 2008. The increase in earnings resulted from similar factors as for the three months results as well as unrealized foreign exchange gains on the translation of foreign-denominated intercompany loans.

Earnings applicable to common shareholders were $1,321 million for the year ended December 31, 2008, compared with $700 million for the year ended December 31, 2007. The increase in earnings resulted from AEDC in Liquids Pipelines, a higher contribution from EGD and unrealized fair value gains on derivative financial instruments in Aux Sable, Energy Services and Corporate, partially offset by decreased earnings from International as the Company sold its interest in CLH in the second quarter of 2008. Earnings for the year ended December 31, 2008 also reflected a $556 million gain on the sale of CLH, partially offset by the recognition of a $32 million income tax charge as a result of an unfavourable court decision related to previously owned United States pipeline assets.

ADJUSTED EARNINGS

Adjusted earnings were $239 million, or $0.64 per common share, for the three months ended December 31, 2009, compared with $202 million, or $0.55 per common share, for the months ended December 31, 2008. Adjusted earnings were $855 million, or $2.35 per common share, for the year ended December 31, 2009, compared with $677 million, or $1.88 per common share, for the year ended December 31, 2008.

The increase in adjusted earnings for both the fourth quarter and full year primarily resulted from increased contributions from a number of the Company’s assets as follows:

· AEDC on both Alberta Clipper (within Enbridge System and EELP) and Southern Lights Pipeline.

· An increased contribution from EEP resulting from additional assets placed in service and related tariff surcharges for recent expansions, the Company’s increased ownership interest and a more favourable exchange rate.

· Increased adjusted earnings from Enbridge Offshore Pipelines (Offshore) due to higher volumes and a more favourable exchange rate.

· Increased adjusted earnings from Energy Services due to higher volumes and the impact of realizing favourable storage and transportation margins.

These increases were partially offset by decreased earnings from International as a result of the sale of OCENSA in the first quarter of 2009 and CLH in the second quarter of 2008.

Adjusted earnings for the year ended December 31, 2008 were $677 million, or $1.88 per common share, compared with $637 million, or $1.79 per common share, for the year ended December 31, 2007. The $40 million, or $0.09 per common share, increase was primarily a result of:

· New facilities within Liquids Pipelines as well as AEDC on Southern Lights Pipeline and, within Enbridge System, on both Southern Access Mainline Expansion and Alberta Clipper Project.

· Increased Aux Sable adjusted earnings due to strong fractionation margins.

· Higher incentive income and increased earnings at EEP primarily due to higher gas and crude oil delivery volumes, tariff surcharges for recent expansions and a greater ownership interest following an additional subscription of Class A units in December 2008.

· Improved earnings in Energy Services resulting from market conditions which enabled higher margins to be captured on storage and transportation contracts as well as increased transportation and storage volumes.

These significant operating factors that increased 2008 adjusted earnings were partially offset by decreased earnings from International as a result of the sale of CLH in the second quarter of 2008 and lost revenue from Offshore as a result of Hurricanes Gustav and Ike.

CASH FLOWS

The Company increased cash generated by operating activities each year from 2007 through 2009 on the success of its growth projects and strong operating results, culminating with cash provided by operating activities of $2,017 million for the year ended December 31, 2009. Operating cash flow, together with cash provided by financing activities and proceeds from the sale of an international investment in 2009, funded the Company’s ongoing growth initiatives in 2009, including capital expenditures of $3,225 million.

For the three months ended December 31, 2009, cash provided by operating and financing activities of $182 million and $912 million, respectively, funded investing activities of $1,162 million, which consisted primarily of capital expenditures. The decline in additions to property, plant and equipment in the fourth quarter of 2009 compared with the fourth quarter of 2008 reflects the completion of several, substantial construction projects that were under development in 2008, including Southern Access Mainline Expansion, Line 4 Extension, Spearhead Pipeline Expansion and Hardisty Terminal projects.

DIVIDENDS

The Company has paid, and consistently increased, common share dividends since its public inception in 1953. Based on estimated 2010 dividends, the annual rate of increase has averaged 10.3% since 2000 and 10.0% since inception. In December 2009, the Company announced a 15% increase in its quarterly dividend to $0.425 per common share, or $1.70 annualized, effective March 1, 2010. The Company’s dividend payout policy and ratio reflects a strong and stable long-term outlook for its business. The Company continues to target a pay out of approximately 60% to 70% of adjusted earnings as dividends and, with the most recent dividend increase, the 2010 pay out is expected to be near the midpoint of the range. In 2009, dividends paid per share were 63% of adjusted earnings per share (2008 - 70%, 2007 - 69%).

The following chart shows dividends per share for the last 10 years, as well as estimated dividends for 2010, based on the quarterly dividend of $0.425 per common share declared by the Board of Directors on December 3, 2009.

REVENUES

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

Commodity sales revenue is earned through the Company’s natural gas distribution and energy marketing activities and is subject to fluctuations in commodity prices. While revenues generated by the natural gas distribution business vary with the price of natural gas, earnings remain neutral due to the pass through nature of these costs. Similarly, the impact of commodity prices on revenues derived from the Company’s energy marketing activities do not directly impact earnings since commodity prices also affect input costs associated with such activities. Commodity sales revenue for the year ended December 31, 2009 totaled $9,720 million compared with $13,432 million for the year ended December 31, 2008 and $9,536 for the year ended December 31, 2007. Commodity sales revenue totaled $2,491 million in the fourth quarter of 2009, a 20% decline from the fourth quarter of 2008. Similar trends were experienced in commodity costs over these same periods. The period-over-period variances are primarily driven by natural gas and crude oil commodity prices, both of which increased notably in 2008 over 2007, only to experience subsequent declines in 2009 amidst global economic uncertainty.

Transportation and other services includes revenues derived from the Company’s liquids transportation and natural gas transmission services, renewable energy generation and related services. Transportation and other services revenue for the year ended December 31, 2009 totaled $2,746 million compared with revenues of $2,699 million for the year ended December 31, 2008. Main contributors to this variance include:

· Increased contributions from Liquids Pipelines growth projects that entered service in 2009, including the Line 4 Extension, Spearhead Expansion, LSr Pipeline (constructed in conjunction with the Southern Lights Pipeline Project) and Hardisty Terminal projects.

· Full year contributions from Waupisoo Pipeline and Ontario Wind Project that entered service at various stages throughout 2008.

· Completion of the Shenzi Lateral project within Offshore in April 2009.

· Unfavourable variances in realized and unrealized gains and losses on derivative instruments used to manage natural gas processing margins in Aux Sable.

Transportation and other services revenue for the three months ended December 31, 2009 was $696 million compared with $808 million for the corresponding period of 2008. The decline is primarily due to variances in realized and unrealized gains and losses on derivative instruments used to manage natural gas processing margins in Aux Sable.

For the year ended December 31, 2008, transportation and other services revenue increased 13% to $2,699 million compared with $2,383 million in 2007. Segment highlights include:

· Revenues in the Liquids Pipelines segment increased due to higher base tolls on Enbridge System and the new Waupisoo Pipeline included in the Enbridge Regional Oil Sands System.

· Natural Gas Delivery and Services transportation revenue included higher Alliance Pipeline US tolls, the impact of Vector Pipeline expansion and revenues from Neptune within Offshore.

· EIF revenue, within Sponsored Investments, increased due to higher tolls at Alliance Pipeline Canada and higher allowance oil revenue from the Saskatchewan System.

FORWARD-LOOKING INFORMATION

Forward-looking information, or forward-looking statements, have been included in this MD&A to provide the Company’s shareholders and potential investors with information about the Company and its subsidiaries, including management’s assessment of Enbridge’s and its subsidiaries’ future plans and operations. This information may not be appropriate for other purposes. Forward-looking statements are typically identified by words such as ‘‘anticipate’’, ‘‘expect’’, ‘‘project’’, ‘‘estimate’’, ‘‘forecast’’, ‘‘plan’’, ‘‘intend’’, ‘‘target’’, ‘‘believe’’ and similar words suggesting future outcomes or statements regarding an outlook. Forward-looking information or statements included or incorporated by reference in this document include, but are not limited to, statements with respect to: expected earnings or adjusted earnings; expected earnings or adjusted earnings per share; expected costs related to

projects under construction; expected in-service dates for projects under construction; expected capital expenditures; and estimated future dividends.

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

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

NON-GAAP MEASURES

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

CORPORATE VISION AND KEY OBJECTIVE

Enbridge’s vision is to be the leading energy delivery company in North America. While the Company may be viewed as having achieved elements of this vision, enhancing and sustaining this position remains a continuing, long-term pursuit. The Company’s objective is to generate superior economic value for shareholders through investing capital in a low-risk and disciplined manner. Consistently applied, such stewardship could continue to generate attractive risk adjusted returns and in turn, provide for consistent and growing dividend distributions and related capital appreciation.

CORPORATE STRATEGY

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

· leveraging the strategic location of its existing asset base;

· developing new platforms for growth and diversification;

· focusing on execution and operating excellence;

· maintaining financial strength and flexibility; and

· development of people, safety and environmental stewardship and corporate social responsibility.

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

STRENGTHENING OUR CORE BUSINESS

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

Extending the reach of the current asset base is a multi-faceted objective. Key strategies within the Liquids Pipelines segment include regional pipeline development, gathering system and storage infrastructure expansion and new market access. Regional pipeline development primarily includes projects which connect new oil sands lease production to existing hubs upstream of the Canadian mainline. The commercial agreement and ongoing development activity related to the Woodland Pipeline represents a recent success in realizing this objective. The Company is working with several other oil sands customers in developing further transportation options for other projects in the oil sands region of northern Alberta. The Company is also expanding its gathering systems in Saskatchewan and North Dakota which are strategically located to capture increased production from the Bakken play. As transportation needs grow so too do terminal and storage infrastructure requirements throughout the network, and the Company’s strategy will seek opportunities to provide additional capacity in the Fort McMurray and Hardisty, Alberta regions as well as in the Cushing, Oklahoma area. The Company continues to pursue opportunities to provide its customers broader market access for Canadian bitumen and synthetic crudes and provide new sources of supply for refiners. These efforts include leveraging existing pipeline networks into additional United States markets as well as developing the proposed Northern Gateway pipeline to provide access to markets off the Pacific Coast of Canada.

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

DEVELOPING NEW PLATFORMS FOR GROWTH AND DIVERSIFICATION

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

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

The Company’s Pathfinding group will also continue to explore other longer-term energy technologies and facilitate innovations to assist its customers and sustain its favorable position.

FOCUSING ON EXECUTION AND OPERATIONS

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

Successful execution of the existing slate of commercially secured projects is a significant driver of Enbridge’s near-term earnings and cash flow growth, and, therefore, a strategic priority. Project execution is a core competency at Enbridge and the Company continues to build upon its project management skills and processes, primarily through the Major Projects support team which was established in early 2008. Major Projects now manages projects above $50 million for all liquids, natural gas and renewable projects and continues to deliver projects on time and on budget. Major Projects focuses on success factors such as cost estimation, regulatory permitting, material and labour sourcing and project governance. This competency is highly valued and represents another Enbridge strength when competing for new business.

Cost efficiency and operating performance is becoming an increasing driver of value in a deregulated world with increased competition. Under the incentive programs in place in certain of the Company’s business units, rates and tolls, as well as the Company’s earnings, depend on cost and operating performance. Returns in the Company’s natural gas gathering and processing business are also directly impacted by operating costs. Key initiatives within the business units to manage costs include: upgrading management information and reporting systems; rigorous cost tracking performance against relevant benchmarks; and implementing best practice procurement strategies and enhanced “change management” processes to ensure anticipated savings are realized from new programs.

Superior service, safety and reliability are integral to Enbridge’s customer value proposition. As always, cost management initiatives are balanced with the safe and reliable operation of the Company’s system and the need to ensure ongoing customer satisfaction. Throughout the organization, the Company is placing increased emphasis on understanding customers and their decision processes, and on regular

measurement and management of service quality.

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

PRESERVING FINANCIAL STRENGTH AND FLEXIBILITY

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

A key tenet of the Company’s low-risk business model is mitigation of exposure to certain market price risks. As a result, the Company has developed a robust risk management process which ensures earnings volatility from manageable risk remains contained within the Company’s approved guideline of 5% of adjusted earnings. Enbridge will continue to proactively hedge interest rate, foreign exchange and commodity price exposures. As well, the continued management of counterparty credit risk remains an ongoing priority.

ENVIRONMENTAL STEWARDSHIP AND CORPORATE SOCIAL RESPONSIBILITY

Enbridge has strong corporate social responsibility practices. Enbridge defines corporate social responsibility as conducting business in a socially responsible way, protecting the environment and the health and safety of people, supporting human rights and engaging, respecting and supporting the communities and cultures with which the Company works. Enbridge’s complete 2009 Corporate Social Responsibility Report can be found at www.enbridge.com/csr2009. None of the information contained on, or connected to, the Enbridge website is incorporated or otherwise part of this MD&A.

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

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

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

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

To achieve its neutral footprint goal, Enbridge will work with nature conservancies in Canada and the United States to help purchase natural wilderness lands throughout North America. The land that Enbridge conserves will be similar to the areas that have been affected. The Company has also begun to plant trees. To mark the Company’s 60th anniversary, Enbridge planted more than 60,000 trees in 60 communities along its rights of way in Canada and the United States.

Enbridge’s community investments are also noteworthy. The Company launched three major community investment initiatives in 2009. School Plus, in partnership with the Assembly of First Nations, provides financial support to enrichment programming and extra-curricular activities in First Nations schools near major Enbridge rights of way; the Safe Community program serves to confirm the priority Enbridge places on health and safety in our right-of-way communities, by directly and visibly supporting those right-of-way organizations who would respond to an emergency on one or more of our lines or at one of our facilities; and, the Natural Legacy program focuses on tree planting and specific environmental initiatives in communities in proximity to our major rights of way.

To complement community investments in its Canadian and United States operating areas, Enbridge will also exercise leadership in extending the benefits of energy availability to underdeveloped countries. In 2009, Enbridge launched the energy4everyone Foundation, which has applied to the Canadian Revenue

Agency for charitable status, with a vision of empowering people and communities to improve their own lives by providing energy to everyone. The Foundation aims to leverage the expertise and resources of the Canadian energy industry to affect significant enhancement in quality of life through the delivery and deployment of affordable, reliable and sustainable energy services and technologies to communities in need around the world.

INDUSTRY FUNDAMENTALS

SUPPLY AND DEMAND FOR LIQUIDS

North American liquids infrastructure fundamentals remain favourable for the foreseeable future. The United States continues to be reliant on imported crude oil to satisfy its needs. Western Canada has surpassed both Mexico and Saudi Arabia to become the largest crude oil exporter to the United States. Canada’s oil sands, one of the largest oil reserves in the world, are becoming an increasingly prominent source of supply. Combined conventional and oil sands established reserves of approximately 174 billion barrels compare with Saudi Arabia’s proved reserves of approximately 260 billion barrels. The National Energy Board (NEB) estimates that total Western Canadian Sedimentary Basin (WCSB) production averaged approximately 2.5 million barrels per day (bpd) in 2009 (2008 - 2.4 million bpd; 2007 - 2.4 million bpd). Other sources of supply growth include deepwater Gulf of Mexico, which is also distant from market, and some of the shale plays like the Bakken in the midcontinent.

In connection with the global economic downturn, crude oil price weakness and volatility caused some crude oil producers to defer projects that were planned to commence over the next decade. More recently, improved macroeconomic conditions, higher oil prices and reduced development costs have spurred a number of oil sands projects to be revisited and sanctioned; however, a tempered rate of growth is expected in the near term relative to prior forecasts. The Canadian Association of Petroleum Producers’ (CAPP) June 2009 growth case estimates indicate that future WCSB production is expected to steadily increase to more than 3.6 million bpd by 2019. This forecasted growth of 1.1 million bpd is attributed to increased oil sands production in Alberta.

While global demand for crude oil is expected to resume its growth trajectory given the strength in emerging regions, North American demand for crude oil in the next few years is expected to remain relatively flat. Inventories of crude oil and refined product remain very high as influenced by the recent economic downturn and the emergence of biofuels. Refining economics have materially weakened over this period, contributing to the recent announcements of a variety of marginal refinery closures. Most of these closures are in regions that are not served by Enbridge infrastructure. Other more profitable refineries are growing and have reconfiguration projects under construction. Some of these refineries currently process Canadian crude and some are preparing to. Accordingly, there remain meaningful growth opportunities for Canadian crude oil into existing and new markets in the United States.

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

SUPPLY AND DEMAND FOR NATURAL GAS

Over the course of the last year the North American gas industry has evolved meaningfully. Shale gas is proving to be an enormous and wide spread resource that may alter continental gas flow directions. With robust supplies of shale gas located in the lower 48 United States, it may not be necessary to import large quantities of liquefied natural gas (LNG) into North America as previously envisioned, and pipelines to access northern gas may be deferred for many years. Growth expectations for shale gas are so strong that the industry’s greatest challenge now has transitioned to how to sustain development by extending

market demand.

Since the 1990s, production in the Rocky Mountain region of the United States, primarily from tight shale gas, has more than doubled to approximately 9 billion cubic feet per day (bcf/d). This amount of growth will likely repeat over the next 12 to 15 years. Established shale plays in the Midcontinent region such as the Barnett, Fayetteville and Woodford, along with emerging plays such as Haynesville in northwest Louisiana and Marcellus in Appalachia, have now become the continental gas development hotspots. After seeing a decline in drilling rig activity in some of these plays in the summer of 2009, activity in these regions has increased in recent months with the prospect of higher future prices. This increased drilling could contribute significantly to supply in 2010, extending the natural gas price weakness seen in 2009.

Additional shale plays exist throughout North America, such as the Horn River and Montney in British Columbia and Utica shale in Quebec. Shale plays located closer to populated markets, such as the Marcellus, are particularly notable in that they require limited infrastructure to access premium prices. If market area shale gas proves to be extensive, it may have a significant impact on the long haul transport business, displacing supplies from distant basins and offloading associated pipelines. On the other hand, opportunities abound for gathering, processing and short haul connectivity.

North American natural gas demand contracted in 2009 as a direct impact of the recession. Industrial demand weakened the most while low gas prices led to gas for coal substitution in power generation, supporting gas demand in that sector. Following the anticipated economic recovery, natural gas demand is expected to grow in all sectors but gas-fired generation may lead the group as natural gas is expected to be a preferred fuel in an increasingly carbon-conscious marketplace. While gas fired generation growth will occur, it will be restricted for the next several years as coal projects already under construction enter service and more renewable power projects come on line.

Even with an economic recovery, growth in unconventional gas supply is expected to be limited by growth in demand, resulting in North American prices remaining lower relative to recent years. This lower price level should be further supported by the relatively lower, and increasingly so, cost of developing shale gas supply. With a lower cost structure, North American gas is likely on a divergent path with oil, which should help support strong fractionation spreads.

Global LNG production is ramping up with several projects under construction. In the near term, LNG supply from these new projects will be seeking markets during a global recession. North American markets may be susceptible to dumping of LNG for short periods, impacting gas prices, at least until global economies recover.

Overall, abundant low cost gas supplies are anticipated to be positive news for North American gas markets and are likely to lead to renewed interest in natural gas as an economically priced, clean burning fuel.

GROWTH PROJECTS

Enbridge is in the midst of its largest capital program in the Company’s 60 year history. During 2008 and 2009, the Company has completed more than $4.5 billion of new growth projects and has $7 billion of additional commercially secured projects scheduled to come into service in 2010 and 2011, with a further $5 billion secured for post-2011 in service. In addition, the Company has a further $30 billion in growth opportunities under development, but not yet commercially secured, for the post-2011 period, of which it expects to be successful on a significant portion.

The following table summarizes commercially secured projects, within each of the Company’s business segments, which were recently completed, or are currently under active development or construction. These growth projects contribute to anticipated annual earnings per share growth rates expected to average 10% through 2013, with the inventory of projects under development expected to sustain this growth rate into the second half of the decade.

(in billions of Canadian dollars, unless stated otherwise)		Actual / Estimated Capital Cost1	Expenditures to Date	Actual / Expected In-Service Date	Status
LIQUIDS PIPELINES
1.	Southern Access Mainline Expansion - Canadian portion	$0.2 billion	$0.2 billion	2008	Complete
2.	Spearhead Pipeline Expansion	US$0.1 billion	US$0.1 billion	2009	Complete
3.	Line 4 Extension	$0.3 billion	$0.3 billion	2009	Complete
4.	Hardisty Contract Terminal	$0.6 billion	$0.6 billion	2009	Complete
5.	Alberta Clipper - Canadian portion	$2.3 billion	$2.1 billion	2010	Mechanically complete
6.	Southern Lights Pipeline	$0.5 billion + US$1.7 billion	$0.5 billion + US$1.4 billion	Light Sour Line - 2009; Diluent Line - 2010	Under construction
7.	Woodland Pipeline - Phase I	$0.5 billion	No significant expenditures to date	2012	Regulatory and pre-construction
8.	Fort Hills Pipeline System	~$2.0 billion	$0.1 billion	TBD	Commercially secured; pending customer timing
NATURAL GAS DELIVERY AND SERVICES
9.	Shenzi Lateral	US$0.1 billion	US$0.1 billion	2009	Complete
10.	Walker Ridge Gas Gathering System	US$0.5 billion	No significant expenditures to date	2014	Pre-construction
11.	Big Foot Oil Pipeline	US$0.3 billion	No significant expenditures to date	2014	Pre-construction
SPONSORED INVESTMENTS
12.	EEP - Southern Access Mainline Expansion – United States portion	US$2.1 billion	US$2.1 billion	2009	Complete
13.	EEP - North Dakota System Expansion	US$0.2 billion	US$0.1 billion	2010	Complete
14.	EEP/EELP - Alberta Clipper - United States portion	US$1.3 billion	US$0.9 billion	2010	Under construction
15.	EIF - Saskatchewan System Capacity Expansion	$0.1 billion	No significant expenditures to date	2010	Under construction
CORPORATE
16.	Ontario Wind Project	$0.5 billion	$0.5 billion	2009	Complete
17.	Talbot Wind Energy Farm	$0.3 billion	$0.1 billion	2010	Under construction
18.	Sarnia Solar Project	$0.4 billion	$0.1 billion	2010	Under construction

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

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

LIQUIDS PIPELINES

Southern Access Mainline Expansion Project

The Southern Access Mainline Expansion Project is complete, with only some restoration work remaining. It has added a total of 400,000 bpd incremental capacity to the mainline system. Construction of the second and final stage of the United States expansion project, which consisted of a new 224-kilometre (139-mile), 42-inch pipeline from Delavan, Wisconsin to Flanagan, Illinois, was completed on schedule in the first quarter of 2009. The pipeline was placed into service and the associated toll surcharge took effect on April 1, 2009. In Canada, upgrades at 18 pump stations to improve pumping effectiveness were completed in early 2009. The Company started collecting associated tolls in April 2008 on stage 1 facilities placed in-service.

The total cost of the project decreased to approximately US$2.3 billion (Enbridge - $0.2 billion, EEP - US$2.1 billion). The estimated capital cost for the Canadian portion was revised from $0.3 billion to $0.2 billion based on refinements to the scope of the project, agreed to with CAPP, to reflect the subsequent approval of the Alberta Clipper Project.

The Southern Access Expansion Project is an expansion of the mainline system. The cost of the project is recovered through tolls in Canada and the United States. A toll surcharge mechanism has been negotiated with shippers and approved by regulators to recover the costs of this expansion including a return on and of the capital investment. The recovery of costs and returns is independent of throughput.

Spearhead Pipeline Expansion

This US$0.1 billion expansion includes additional pumping stations to increase capacity from Flanagan, Illinois to Cushing, Oklahoma by 68,300 bpd to 193,300 bpd. The expansion began in September 2008 and was placed in service on May 1, 2009.

Sale of Spearhead North Pipeline

On May 1, 2009, the Company sold a section of the Spearhead Pipeline to EEP for proceeds of US$75 million. The section of the crude oil pipeline system sold, known as Spearhead North, includes approximately seven storage tanks and 121 kilometres (75 miles) of pipeline that was reversed to provide northbound service from Flanagan, Illinois to Griffith, Indiana. Spearhead North complements EEP’s existing Lakehead System interconnectivity at Flanagan, which is the terminus of the Southern Access Expansion.

Line 4 Extension Project

The $0.3 billion Line 4 Extension Project was substantially complete and ready to receive linefill at the end of March 2009, and associated tolls were collected starting April 1, 2009. Final restoration work was completed in the summer of 2009. The project expanded capacity from Edmonton to Hardisty by 880,600 bpd. Similar to the Southern Access and Alberta Clipper projects, the Line 4 project costs are recovered through surcharges on mainline tolls.

Hardisty Contract Terminal

Enbridge has completed its crude oil contract terminal at Hardisty, Alberta, adding tankage capacity of 7.5 million barrels. With all 19 new tanks in service, the $0.6 billion Hardisty Contract Terminal is one of the largest crude oil terminals in North America. Remaining seasonal and restoration work is expected to be completed in early 2010.

Alberta Clipper Project

The Alberta Clipper Project involves the construction of a new 36-inch diameter pipeline from Hardisty, Alberta to Superior, Wisconsin generally within or alongside EEP’s existing rights-of-way in the United States and Enbridge’s existing rights-of-way in Canada. The Alberta Clipper Project will interconnect with the existing mainline system in Superior where it will provide access to Enbridge’s full range of delivery points and storage options, including Chicago, Toledo, Sarnia, Patoka and Cushing. The project will have an initial capacity of 450,000 bpd, is expandable to 800,000 bpd and will form part of the existing Enbridge

System in Canada and the EEP Lakehead System in the United States. The Alberta Clipper Project is a full cost of service agreement with a return of 225 basis points (bps) over the NEB multi pipeline rate of return.

Construction on the Canadian segment of the line was mechanically completed in December 2009, and remains on schedule for an expected in-service date of April 1, 2010. This segment has an estimated cost of $2.3 billion, including allowance for funds used during construction (AFUDC), with expenditures to date totaling $2.1 billion. As of January 2010, construction is approximately 90% complete on the United States segment and it also remains on schedule to be ready for service by April 1, 2010. The cost of the United States segment is estimated at US$1.3 billion, with expenditures to date totaling US$0.9 billion. As announced in July 2009, Enbridge has committed to fund 66.7% of the United States segment of the Alberta Clipper project through EELP. Similar to the Southern Access project, the costs of the Alberta Clipper Project are recovered through surcharges on mainline tolls in both Canada and the United States.

For both the Canadian and United States segments of the Alberta Clipper Project, tariffs will be filed with the appropriate regulators to be effective on April 1, 2010, the date the project is expected to be ready for service. The tariff for the United States segment, and its effective date, will be filed on the basis of the Alberta Clipper US Term Sheet, despite a petition filed in January 2010 by a shipper requesting the Federal Energy Regulatory Commission (FERC) to delay the tariff. Following that petition filing, several shippers filed interventions requesting to be part of the process. The Alberta Clipper US Term Sheet was approved by CAPP on June 28, 2007 and by the FERC on August 28, 2008. We have reviewed and will respond to the shipper petition, which we believe to be without merit.

Southern Lights Pipeline

When completed, in the second half of 2010, the 180,000 bpd Southern Lights Pipeline will transport diluent from Chicago, Illinois to Edmonton, Alberta. The project involves reversing the flow of a portion of Enbridge’s Line 13, an existing crude oil pipeline which runs from Edmonton to Clearbrook, Minnesota. In order to replace the light crude capacity that would be lost through the reversal of Line 13, the Southern Lights Project also includes the construction of a new 20-inch diameter light sour crude oil pipeline (LSr Pipeline) from Cromer, Manitoba to Clearbrook, and modifications to existing Line 2. These changes to the existing crude oil system increased southbound light crude system capacity by approximately 45,000 bpd. The capacity replacement will permit Line 13 to be taken out of service and reversed for diluent service. The LSr Pipeline and Line 2 modifications, which allow Line 2 to operate at higher design rates, were completed and placed in service in the first quarter of 2009.

In the United States, construction of the LSr Pipeline and Line 2 modifications, as well as diluent pipeline construction between Superior, Wisconsin and Streator, Illinois, are complete. Remaining mainline construction includes approximately 305 kilometers (190 miles) of diluent segment, in conjunction with construction of the Alberta Clipper Project, between Clearbrook, Minnesota and Superior, Wisconsin. Construction of this remaining United States line segment commenced in the third quarter of 2009 and was 80% complete at year end. In addition, construction has commenced on diluent receipt tankage at Manhattan as well as pump station facilities along the newly constructed diluent line in the United States.

The total expected project cost is US$1.7 billion for the United States segment and $0.5 billion for the Canadian segment. Expenditures to date are US$1.4 billion and $0.5 billion for the United States and Canadian segments, respectively. Southern Lights is a contract pipeline backed by shippers with strong credit ratings.

Line 13 Exchange

In February 2009, the Company transferred the United States section of the newly constructed LSr Pipeline to EEP at book value in exchange for the United States portion of Line 13. The exchange was made on a basis considered to be fair to both parties and the tolls and earnings on the LSr Pipeline and Line 13 within EEP are expected to be substantially unchanged.

Woodland Pipeline

In June 2009, Enbridge entered into an agreement with Imperial Oil Resources Ventures Limited (Imperial Oil) and ExxonMobil Canada Properties (ExxonMobil) to provide for the transportation of blended bitumen from the Kearl oil sands mine to crude oil hubs in the Edmonton, Alberta area. The project will be phased with the mine expansion, with the first phase involving construction of a new 36-inch diameter pipeline from

the mine to the Cheecham Terminal, and service on Enbridge’s existing Waupisoo Pipeline from Cheecham to the Edmonton area. The new pipeline, to be called the Woodland Pipeline, will be extended from Cheecham to Edmonton in conjunction with the second phase of the Kearl project. The Woodland Pipeline is being undertaken as a joint venture between Enbridge, Imperial Oil and ExxonMobil. Enbridge filed regulatory applications for Phase I facilities at the end of 2009 and expects the pipeline will come into service in late 2012. The total estimated cost of the pipeline from the mine to the Cheecham Terminal and related facilities is $0.5 billion, but is subject to finalization based on scope, detailed engineering and regulatory approvals.

Fort Hills Pipeline System

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

Northern Gateway Project

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

The Company has secured $100 million funding from Western Canada producers and Pacific Rim refiners toward the costs of seeking the necessary regulatory approvals for the project.

The federal Minister of Environment and the Chairman of the NEB have established a Joint Review Panel (JRP) to consider the Northern Gateway application and make a recommendation to the Canadian federal government on whether the project should be approved and what terms and conditions should be attached to that approval. The JRP will review, among other things, the project’s economic, technical and financial feasibility and the environmental and socio-economic impacts of the project. The terms of reference for the JRP were released in December 2009.

Aboriginal consultation and accommodation is a constitutional requirement of the Crown based on established or asserted Aboriginal rights along the pipeline route and tanker waterway. The Canadian Environmental Assessment Agency (CEAA) is responsible for coordinating consultation with Aboriginal groups with respect to the potential impacts of the project on Aboriginal and Treaty rights. CEAA initially consulted with Aboriginal groups on the proposed regulatory process for the project. A number of Aboriginal groups made submission that the proposed consultation process did not meet the Crown’s consultation obligations and a separate Aboriginal review process was required for the project. The federal government did not accept these submissions and established the JRP process as the primary mechanism for Aboriginal groups to be consulted on the impacts of the project. The JRP process has no mandate to resolve Aboriginal land claims or issues of Aboriginal rights and title.

The federal government has also issued a project-specific Aboriginal Consultation Framework for Northern Gateway creating a consultation plan for the project. Funding is available from CEAA to assist Aboriginal groups with the costs of participating in the JRP process and a majority of the Aboriginal groups along the corridor have submitted applications for such funding. Nevertheless, it is anticipated that a number of Aboriginal groups will maintain their position that the current process does not meet the Crown’s duty to consult.

The project is also undertaking its own comprehensive public consultation program, which includes a series of community open houses and community advisory boards designed to gather input, answer questions and build public awareness and understanding about the project. The Company is committed to working with First Nations and Métis communities along the pipeline route to create opportunities for economic partnerships and to incorporate traditional knowledge into the planning and operations of the proposed project.

Notwithstanding this commitment, certain Aboriginal groups have publicly stated their opposition to the project and have indicated that they are considering all options to prevent the project. These options could include legal challenges to the consultation efforts of the Crown or to the JRP process or its outcomes. The result of such legal challenges would ultimately be decided by the courts, but even if unsuccessful, they could potentially increase the risk of project delay. See Aboriginal Relations.

Enbridge expects to file its regulatory application with the NEB in 2010. Subject to continued commercial support, regulatory and other approvals, and adequately addressing Aboriginal groups’ concerns, the Company estimates that Northern Gateway could be in-service as early as the 2016 time frame. The NEB posts public filings related to Northern Gateway on its website and Enbridge also maintains a Northern Gateway Project site in addition to information available on www.enbridge.com. None of the information contained on, or connected to, the NEB website, the Gateway Project website or Enbridge’s website is incorporated or otherwise part of this MD&A.

NATURAL GAS DELIVERY AND SERVICES

Shenzi Project

Enbridge completed construction of a natural gas lateral to connect the new deepwater Shenzi field to existing Enbridge infrastructure. The US$0.1 billion 18-kilometre (11-mile), 12-inch diameter gas pipeline has capacity of 0.1 bcf/d. The Shenzi lateral, which delivers natural gas through the Company’s 22%-owned Cleopatra Pipeline, the 74%-owned Manta Ray Pipeline and the 74%-owned Nautilus Pipeline, was placed into service in April 2009 concurrent with producer first volumes.

Walker Ridge Gas Gathering System

On July 29, 2009, Enbridge announced it had entered into Letters of Intent (LOI) with Chevron Corp. to expand its central Gulf of Mexico offshore pipeline system. Under the terms of the LOI, 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 is expected to include approximately 306 kilometres (190 miles) of 8-inch, 10-inch and/or 12-inch diameter pipeline at depths of up to approximately 2,150 metres (7,000 feet) and will have a capacity of 0.1 bcf/d. The estimated cost of the WRGGS is approximately US$0.5 billion, subject to finalization of scope and definitive cost estimates.

The terms of the LOI ensure a minimum rate of return to Enbridge with no volume risk. If volumes are achieved as expected by the producer, returns would improve from this base level. In addition, Enbridge takes no capital cost risk on the project.

Big Foot Oil Pipeline

On October 5, 2009, Enbridge announced it had entered into a LOI with Chevron USA, Inc., Statoil Gulf of Mexico LLC and Marubeni Oil & Gas (USA) Inc. to construct and operate a 64-kilometre (40-mile) 20-inch oil pipeline from the proposed Big Foot ultra-deepwater development in the Gulf of Mexico. This crude oil pipeline project is complementary to Enbridge's previously announced plans to construct the WRGGS. The estimated cost of the Big Foot Oil Pipeline, which will be located about 274 kilometres (170 miles) south of the coast of Louisiana, is approximately US$0.3 billion and the pipeline is expected to be in-service in 2014 and has the same commercial structure as noted under Walker Ridge Gas Gathering System. Combined with the WRGGS project, the proposed oil pipeline would bring the total Enbridge investment for the projects to US$0.8 billion.

LaCrosse Pipeline

In May 2009, the Company conducted a successful non-binding open season for the proposed LaCrosse Pipeline. This project, which is being commercially pursued, includes an interstate pipeline to transport natural gas from EEP’s Carthage Hub in Panola County, Texas, to Washington Parish in Southeastern Louisiana. The 483-kilometre (300-mile) pipeline would have a capacity in excess of 1.0 bcf/d and would provide an outlet for increasing supplies of natural gas originating in the East Texas and Fort Worth producing basins and the growing Haynesville Shale play. The next stage of the project involves confirming customer interest and the expected cost of the new construction.

SPONSORED INVESTMENTS

Enbridge Energy Partners

North Dakota System Expansion

EEP undertook a further expansion of the North Dakota Pipeline System at an approximate cost of US$0.2 billion during 2009. The expansion increased system capacity from 110,000 bpd to 161,000 bpd and consisted of upgrades to existing pump stations, additional tankage as well as infrastructure to facilitate extensive use of drag reducing agents that are injected into the pipeline. The commercial structure for this expansion is a cost-of-service based surcharge that has been added to the existing transportation rates. The related tolling surcharge has been adjusted to include costs of this phase of the expansion that became effective January 1, 2010. Approval for the expansion was received from the FERC in October 2008 and the expansion came into service in early 2010.

Enbridge Income Fund

Saskatchewan System Capacity Expansion

EIF has finalized the scope of Phase II of the Saskatchewan System Capacity Expansion to include three separate projects that will reduce capacity constraints at a variety of locations. Collectively, the projects will increase capacity across the system by approximately 125,000 bpd at an estimated cost of approximately $0.1 billion. Construction commenced during the third quarter of 2009 and all three projects are expected to be complete in the fourth quarter of 2010.

CORPORATE

Ontario Wind Project

The 190-megawatt (MW) Ontario Wind Project, located in the Municipality of Kincardine on the eastern shore of Lake Huron in Ontario, was completed in the fourth quarter of 2008, and 65 of the 115 wind turbines were operating and delivering power to the grid by the end of 2008. During the first quarter of 2009, the remaining 50 turbines were phased into service and the wind project attained full commercial operation. The project has demonstrated near design level operational performance through its net capacity factor and high availability of wind turbines. The final capital cost of the project is $0.5 billion.

Talbot Wind Energy Project

On November 19, 2009, Enbridge announced the development of the 99-MW Talbot Wind Energy Project near Chatham, Ontario with Renewable Energy Systems Canada Inc. (RES Canada). Enbridge will have a 90% interest in the project and an option to acquire the remaining 10% interest. RES Canada will construct the wind project under a fixed price, turnkey, engineering, procurement and construction agreement. The project utilizes 43 Siemens 2.3-MW wind turbines and, under a multi-year fixed price agreement, Siemens will provide operations and maintenance services for the wind turbines. The Talbot Wind Energy project will deliver energy to the Ontario Power Authority under a Renewable Energy Supply (RES) III 20-year power purchase agreement and is expected to be completed by December 2010 at a capital cost of $0.3 billion.

Sarnia Solar Project

On October 2, 2009, Enbridge announced the development of the 20-MW Sarnia Solar Project with First Solar, Inc. (First Solar). On December 8, 2009, the Company announced a 60-MW expansion of the project. After the completion of the expansion, the project will be the largest photovoltaic, solar energy facility in operation in North America. First Solar, a global leader in solar energy, is constructing the project

under a fixed price engineering, procurement and construction contract, utilizing its thin film photovoltaic technology. First Solar will also provide operations and maintenance services under a long-term contract. Power output of the facility will be sold to the Ontario Power Authority under a 20-year power purchase agreement. The initial 20-MW facility attained commercial operation in December 2009 and the 60-MW facility is expected to be in service by December 2010. The expected capital cost of both facilities is $0.4 billion.

Alberta Saline Aquifer Project

The 38-member Alberta Saline Aquifer Project (ASAP) completed Phase 1 of its three-phase CO2 storage project in March 2009. This phase focused on identifying saline aquifer locations in Alberta that would be suitable for a CO2 storage pilot project. The costs associated with this phase were covered by ASAP participants and a grant from the Alberta Energy Research Institute.

ASAP is now working on securing funding and a source of CO2 such that it can move on to Phase 2 of the project. Phase 2 will involve developing the pilot project, receiving all necessary regulatory approvals and actually injecting CO2 into the identified aquifers. The Phase 2 pilot project will give the ASAP team the opportunity to test the sequestration technologies and to demonstrate that the technologies are safe and reliable.

LIQUIDS PIPELINES

EARNINGS

(millions of Canadian dollars)	2009		2008		2007
Enbridge System	295		212		202
Enbridge Regional Oil Sands System	72		69		54
Southern Lights Pipeline	58		27		7
Spearhead Pipeline	17		12		10
Olympic Pipeline	9		7		10
Feeder Pipelines and Other	3		5		3
Adjusted Earnings	454		332		286
Enbridge System - impact of tax changes	-		-		1
Enbridge Regional Oil Sands System - Cheecham leak accrual	(9	)	-		-
Feeder Pipelines and Other - asset impairment loss	-		(4	)	-
Earnings	445		328		287

Liquids Pipelines adjusted earnings were $454 million in 2009 compared with $332 million in 2008. The increase was largely due to higher earnings from Enbridge System and Southern Lights Pipeline, including the impact of AEDC, partially offset by higher operating costs including compensation.

While under construction, certain regulated pipelines are entitled to recognize AEDC in earnings. These amounts will contribute to earnings throughout the Company’s significant growth period and will be collected in tolls once the pipelines are in service. The earnings impact of AEDC for the year ended December 31, 2009 was $74 million (2008 - $18 million) for Enbridge System, primarily relating to Alberta Clipper, and $44 million (2008 - $27 million) for Southern Lights Pipeline.

Liquids Pipelines adjusted earnings were $332 million in 2008 compared with $286 million in 2007. The increase was due primarily to strong contributions from the Enbridge and Enbridge Regional Oil Sands Systems, as well as the recognition of AEDC on Enbridge System and Southern Lights Pipeline.

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

· Enbridge System was affected by favorable tax rate changes in 2007.

· A $9 million after-tax expense resulting from clean up and remediation costs related to a valve leak within the Enbridge Cheecham Terminal on the Enbridge Regional Oil Sands System in January 2009, which is not indicative of the expected future performance of this asset.

· In the fourth quarter of 2008, the Company recorded an impairment loss of $4 million on Manyberries Pipeline, a small feeder pipeline located in Canada.

ENBRIDGE SYSTEM

The mainline system is comprised of Enbridge System 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 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 Enbridge System and located in eastern Canada are two crude oil pipelines and one refined products pipeline with a combined capacity of 0.4 million bpd. Average system utilization in 2009 was 80%; however, it is expected to decrease in 2010 due to a combination of additional pipeline capacity being added to the system by the Company and a new pipeline being brought into service by a competitor.

Incentive Tolling

Tolls on Enbridge System are governed by various agreements, which are subject to the approval of the NEB. The NEB’s jurisdiction over the Enbridge System includes statutory authority over matters such as construction, rates and ratemaking agreements and other contractual arrangements with customers. Significant agreements include the incentive tolling settlement (ITS) applicable to the Enbridge mainline system (excluding Line 8 and Line 9), the Terrace agreement, the SEP II Risk Sharing Agreement and the Southern Access Expansion Agreement which is recovered via the Mainline Expansion Toll. Tolls on the core mainline system have been governed by ITS since 1995, with the most recent ITS term effective through 2009. Discussions and negotiations are continuing for an extension to the ITS which will support a competitive toll structure. The Company anticipates that a settlement will be reached in early 2010. In the event that a settlement cannot be reached, the Company could file a cost of service application.

In 2009, the ITS allowed the sharing of earnings in excess of a stipulated threshold and provided a fixed annual mainline integrity allowance. In addition, performance metrics bonuses and penalties aligned the Company’s interests with its shippers.

Enbridge achieved total performance metrics bonuses of approximately $13 million for the year ended December 31, 2009, compared with approximately $15 million and $11 million for the years ended December 31, 2008 and 2007, respectively.

In conjunction with the Terrace agreement, the ITS continues the throughput protection provisions included in earlier incentive tolling arrangements, ensuring the Company is insulated from volume fluctuations beyond its control. The agreements govern both current and future shippers on the pipeline and establish tolls each year based on an agreed capacity and an allowed revenue requirement. Where actual volumes on the pipeline fall short of the agreed capacity and Enbridge is unable to fully collect its annual revenue requirement, the deficiency is rolled into the subsequent year’s tolls for collection from shippers at that time and a receivable, referred to as the Transportation Revenue Variance (TRV), is recognized. This basis may affect the timing of recognition of revenues compared with that otherwise expected under Canadian GAAP for companies that are not rate-regulated. As at December 31, 2009, $98 million (2008 - $114 million) was recorded as tolling deferrals.

Enbridge pays taxes each year only on the tolls collected in cash; therefore the tax payable on the TRV lags behind the recognition of the revenue. As the Terrace capacity is increasingly utilized, there will be less TRV recorded and more cash tolls collected. This will result in the Company paying taxes in future years on both the prior year’s TRV and the current year’s cash tolls.

Results of Operations

Enbridge System adjusted earnings were $295 million for the year ended December 31, 2009 compared with $212 million for the year ended December 31, 2008. Enbridge System adjusted earnings increased due to increased tolls from a higher rate base as a result of Line 4 entering service in April 2009, lower financing costs as well as higher AEDC on Alberta Clipper. These positive impacts were partially offset by

higher operating costs, including compensation, and costs related to leak remediation.

Enbridge System adjusted earnings were $212 million for the year ended December 31, 2008 compared with $202 million for the year ended December 31, 2007. This increase was due to increased tolls from a higher rate base as a result of Southern Access Mainline Expansion entering service on March 31, 2008 and the AEDC recognized while the project was under construction.

Enbridge System earnings for the year ended December 31, 2007 were impacted by $1 million as a result of favourable tax rate changes.

ENBRIDGE REGIONAL OIL SANDS SYSTEM

Enbridge 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 the Company’s interest in the Hardisty Caverns Limited Partnership, which provides crude oil tankage service; and three large terminals: the Athabasca Terminal located north of Fort McMurray, Alberta, the Cheecham Terminal, which is a new hub located 95 kilometres south of Fort McMurray where the Waupisoo Pipeline initiates, and the Hardisty Contract Terminal, one of the largest crude oil terminals in North America.

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 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 contract provides for volumes and tolls designed to achieve an underpinning return on equity (ROE) based on an assumed debt/equity ratio and level of operating costs. The committed volumes and the tolls specified in the contract do not generate sufficient cash revenues in the early years to compensate Enbridge for the debt and equity returns as well as the cost of providing service. As a result, Enbridge is recording a receivable in these years, which will be collected in tolls in future years. This treatment ensures that the revenue recognized each period is in accordance with the contract.

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 ROE with significant upside potential as incremental founders and third party volumes are added.

Results of Operations

Adjusted earnings for the year ended December 31, 2009 were $72 million compared with $69 million for the year ended December 31, 2008 and $54 million for the year ended December 31, 2007. In both the year ended December 31, 2009 and 2008, the increase in Enbridge Regional Oil Sands System adjusted earnings reflected contributions from the Waupisoo Pipeline that entered service in June 2008 and the continued positive impact of terminal infrastructure additions, partially offset by higher operating costs. Enbridge Regional Oil Sands System earnings for 2009 were impacted by a $9 million after-tax expense resulting from the clean up and remediation costs related to a valve leak within the Enbridge Cheecham Terminal in January 2009, which is not indicative of the expected future performance of this asset.

SOUTHERN LIGHTS PIPELINE

This pipeline received regulatory approval in Canada in the first quarter of 2008 and is currently under construction in both the United States and Canada. Upon completion, the 180,000 bpd, 20-inch diameter Southern Lights Pipeline will transport diluent from Chicago, Illinois to Edmonton, Alberta.

Enbridge will receive tariffs under long-term (15-year) contracts with committed shippers. Tariffs provide for recovery of all operating and debt financing costs, plus a ROE at a pre-determined rate. 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.

Results of Operations

Southern Lights Pipeline earnings for each of 2009, 2008 and 2007 reflected AEDC recognized on a growing capital base while the project continued to be under construction. In 2009, earnings from the new light sour pipeline, which became operational during the first quarter of 2009, were also reflected.

SPEARHEAD PIPELINE

Spearhead Pipeline delivers crude oil from Chicago, Illinois to Cushing, Oklahoma. The performance of this pipeline steadily increased and with further support of new committed shippers, the Spearhead Pipeline Expansion was completed in May 2009. This expansion increased the capacity from 125,000 bpd to 193,300 bpd from the new initiating point of Flanagan, Illinois to Cushing.

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 earnings increased to $17 million for the year ended December 31, 2009 compared with $12 million for the year ended December 31, 2008 due to increased volumes resulting from the expansion completed in May 2009.

Earnings increased to $12 million for the year ended December 31, 2008 compared with $10 million for the year ended December 31, 2007 as a result of higher throughputs and higher tolls on committed volumes.

OLYMPIC PIPELINE

Enbridge has a 65% interest in the Olympic Pipeline, the largest refined products pipeline in the State of Washington, transporting approximately 290,000 bpd of gasoline, diesel and jet fuel. The pipeline system extends approximately 480 kilometres (300 miles) from Blaine, Washington to Portland, Oregon, connecting four Puget Sound refineries to terminals in Washington and Portland. BP Pipelines (North America) Inc. (BP) is the operator of the pipeline.

Results of Operations

Olympic Pipeline earnings were $9 million, $7 million and $10 million for the years ended December 31, 2009, 2008 and 2007, respectively. Olympic’s cost of service tolling methodology requires annual toll adjustments for over or under collection of the cost of service in prior years. Olympic Pipeline earnings for both the years ended December 31, 2009 and 2008 reflected lower average tolls effective July 1st in each of those years to compensate for over collection in the previous year. Earnings for the year ended December 31, 2009 also reflected lower operating and administrative costs, which resulted in increased earnings in 2009, while earnings for the year ended December 31, 2008 also reflected an increase in pipeline integrity costs.

FEEDER PIPELINES AND OTHER

Feeder Pipelines and Other primarily includes the NW System, which transports crude oil from Norman Wells in the Northwest Territories to Zama, Alberta; interests in a number of liquids pipelines in the United States; contract tankage facilities; and business development costs related to Liquids Pipelines activities.

Results of Operations

Adjusted earnings for Feeder Pipelines and Other were $3 million in 2009 compared with $5 million in 2008 and $3 million in 2007. In 2009, adjusted earnings were impacted by increased business development costs.

Earnings for the year ended December 31, 2008 were impacted by an impairment loss of $4 million on Manyberries Pipeline.

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.

Supply and Demand

The expansion of the Company’s liquids pipelines depends on the supply of, and demand for, crude oil and other liquid hydrocarbons from Western Canada. Supply, in turn, depends on a number of variables, including the price of crude oil and bitumen, the availability and cost of capital and labour for oil sands projects, the price of natural gas used for steam production and changes in plans by shippers. Supply risk to existing facilities is largely mitigated given the Company’s throughput insensitive commercial terms or cost of service arrangements on many of its Liquids Pipelines assets. Demand depends, among other things, on weather, gasoline price and consumption, manufacturing levels, alternative energy sources and global supply disruptions. Crude oil price volatility has caused some oil sands producers to cancel or defer projects that were planned to commence over the next decade. If the rate of crude oil production from the WCSB declines, immediate need for new pipelines infrastructure will likely decline.

Also, shippers are not required to enter into long-term shipping commitments on Enbridge’s mainline system; rather, monthly volume nominations are accepted. The Company’s existing right-of-way provides a competitive advantage as it can be difficult and costly to obtain new rights of way for new pipelines. The ITS and Terrace Agreement as well as the Southern Access and Alberta Clipper agreements on the Enbridge System provide throughput protection which insulates the Company from negative volume fluctuations beyond its control. The Lakehead System, owned by EEP, has no similar throughput protection on its base or Terrace systems, but does on its SEP II, Southern Access and Alberta Clipper expansions.

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 is expected to begin commercial operations in early 2010 and will serve 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 to construct additional ex-Alberta capacity of 500,000 bpd to Nederland, Texas, for an in-service date during 2012. 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.

The Company continues to adapt to the changes in its business environment. Enbridge is committed to performance excellence and is focused on becoming more efficient, more collaborative, more innovative

NATURAL GAS DELIVERY AND SERVICES

EARNINGS

(millions of Canadian dollars)	2009		2008		2007
Enbridge Gas Distribution	129		123		115
Noverco	19		20		18
Other Gas Distribution	26		23		19
Enbridge Offshore Pipelines (Offshore)	29		7		22
Alliance Pipeline US	27		25		28
Vector Pipeline	16		14		15
Aux Sable	26		28		11
Energy Services	29		17		6
International	-		52		90
Other	(12	)	(7	)	-
Adjusted Earnings	289		302		324
EGD - colder than normal weather	17		23		14
EGD - interest income on GST refund	7		-		-
EGD - provision for one-time charges	-		(3	)	-
EGD - impact of tax changes	21		-		20
Noverco - impact of tax changes	6		-		7
Offshore - property insurance recoveries from hurricanes, net of costs incurred	4		-		5
Alliance Pipeline US - shipper claim settlement	-		2		-
Aux Sable - unrealized derivative fair value gains/(losses)	(36	)	56		(28	)
Aux Sable - loan forgiveness	7		-		-
Energy Services - unrealized derivative fair value gains/(losses)	3		23		(3	)
Energy Services - SemGroup and Lehman credit recovery/(loss)	1		(6	)	-
International - gain on sale of investments in OCENSA and CLH	329		556		5
Other - asset impairment loss	(10	)	-		-
Other - adoption of new accounting standard	(3	)	-		-
Other - gain on sale of investment in Inuvik Gas	-		5		-
Earnings	635		958		344

Adjusted earnings from Natural Gas Delivery and Services were $289 million for the year ended December 31, 2009 compared with $302 million for the year ended December 31, 2008. The decreased earnings were substantially due to the sale of CLH in June 2008 and OCENSA in March 2009, offset by higher volumes, including contributions from Shenzi, since its in-service date in April 2009, and Thunder Horse, both within Offshore, favourable foreign exchange, as well as increased adjusted earnings at EGD, Energy Services and Aux Sable.

Adjusted earnings from Natural Gas Delivery and Services were $302 million for the year ended December 31, 2008 compared with $324 million for the year ended December 31, 2007. The decrease in adjusted earnings was substantially due to continuing natural production declines and lost revenue and clean up costs related to Hurricanes Gustav and Ike in Offshore, as well as the sale of CLH in International on June 17, 2008. The decreased earnings for the year ended December 31, 2008 were partially offset by customer growth and higher ancillary revenues at EGD, customer growth at Enbridge Gas New Brunswick (EGNB) within Other Gas Distribution and improved financial performance at Energy Services and Aux Sable.

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

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

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

· Earnings from EGD for 2008 included a $3 million provision for one-time charges to better align certain operating practices with its strategy under incentive regulation (IR).

· In 2009 and 2007, earnings from EGD and Noverco reflect the impact of favourable tax rate changes.

· Earnings for the year ended December 31, 2008 were impacted by $2 million in proceeds received by Alliance Pipeline US from the settlement of a claim against a former shipper which repudiated its capacity commitment.

· Offshore earnings for the year ended December 31, 2009 and 2007 included insurance proceeds of $4 million and $5 million, respectively, related to the replacement of damaged infrastructure as a result of the 2008 and 2005 hurricanes.

· Aux Sable earnings for each period reflected unrealized fair value changes on derivative financial instruments used to risk manage fractionation margin upside on natural gas processing volumes. Similar to Energy Services, these non-cash items arose due to the revaluation of financial derivatives used to “lock in” the profitability of forward contracted prices.

· Earnings for the year ended December 31, 2009 from Aux Sable reflected a $7 million gain from a loan forgiveness related to a negotiated settlement with a counterparty in bankruptcy proceedings.

· Energy Services earnings for 2009 and 2008 reflected unrealized fair value gains and losses resulting from the revaluation of inventory and the revaluation of largely offsetting financial derivatives used to “lock-in” the profitability of forward transportation and storage transactions.

· Energy Services earnings for the year ended December 31, 2008 included a $6 million write-off as a result of bankruptcies by SemGroup and Lehman Brothers. In fiscal 2009, the Company received a $1 million recovery from SemGroup.

· On March 17, 2009, the Company sold its investment in OCENSA, a crude oil export pipeline in Colombia, for proceeds of $512 million, resulting in a gain of $329 million. On June 17, 2008, the Company sold its investment in CLH for proceeds of $1,380 million, resulting in a gain of $556 million.

· Other earnings for 2009 reflected a $10 million asset impairment loss, including goodwill.

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

· A $5 million gain on sale of investment in Inuvik Gas was reflected in earnings from Other for the year ended December 31, 2008.

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 1.9 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 2008, EGD moved to an IR methodology. The objectives of the IR plan are as follows:

· reduce regulatory costs;

· provide incentives for improved efficiency;

· provide more flexibility for utility management; and

· provide more stable rates.

Under the IR framework, Enbridge is allowed to earn 100 bps over the base regulated return. Through various productivity enhancements, any return over this 100 bps must be shared with customers on an equal basis. Enbridge estimates the customer portion of 2009 earnings over the allowed threshold at $19 million (2008 - $6 million).

Rate Adjustment Applications

In September 2009, EGD filed an application with the OEB to adjust rates for 2010 pursuant to the approved IR formula, to increase funding of its pension plans and to seek approval for specific changes to

the Rate Handbook. The OEB issued a first procedural order in October 2009, in which the OEB indicated that it would consider its jurisdiction with regard to inclusion of green energy related projects within the regulated operations of EGD. The OEB issued a decision in December 2009 which effectively prevents the inclusion of such activities in rate-making for the purposes of setting 2010 rates. As a result of this decision, in 2010, EGD will seek clarification of the OEB’s broader policies with respect to such investments and activities.

In September 2008, EGD filed an application with the OEB to adjust rates for 2009 pursuant to the approved IR formula and to seek approval for specific changes to the Rate Handbook. A settlement agreement containing all applied for aspects of the formulaic component of the IR rate setting process was approved by the OEB in December 2008. EGD received a fiscal 2009 final rate order from the OEB in February 2009 approving the implementation of a rate change effective April 1, 2009, which enabled EGD to recover the approved revenues as if rates were effective January 1, 2009.

New Customer Information System (CIS) Implemented

In September 2009, EGD successfully implemented its new CIS, which replaced the legacy system. EGD expects to fully recover in rates the total cost of the project in accordance with an agreement with customer groups that was approved by the OEB in 2007.

Green Energy Initiatives

In September 2009, Ontario’s Minister of Energy and Infrastructure issued a Directive that permits EGD to own and operate stationary fuel cells, wind, water, biomass, biogas, solar and geothermal energy generation facilities up to 10 MW in capacity. EGD will also be permitted to own and operate district and distributed energy systems, including facilities that produce power and thermal energy from a single source. Finally, the Minister’s Directive permits EGD to own and operate assets that would assist the Government of Ontario in achieving its goals in energy conservation, including assets related to solar-thermal water and ground source heat pumps.

In the absence of the Minister’s Directive, the Company’s Undertakings to the Lieutenant Governor in Council would not have permitted EGD to engage in the foregoing activities directly. EGD is well positioned to take on an increasing role in this area and is looking to expand its efforts to explore and pursue alternative and/or renewable energy technologies subject to OEB approval, where appropriate. While the Directive permits EGD to engage in such activities, in December 2009 the OEB determined that it would not allow such activities to be included in rate-making for the purposes of setting 2010 rates. As a result of this decision, EGD will seek clarification of the OEB’s broader policies with respect to such investments and activities in 2010.

Unregulated Storage Services

The deregulation of new natural gas storage in Ontario, coupled with the growing need for high-deliverability storage services by gas-fired power generators and other users, has created unregulated storage growth opportunities for EGD. As of December 31, 2009, EGD has expanded its storage capacity by 6% (5.5 bcf) and sold unregulated storage services into the storage market. A second expansion, amounting to an additional 2 bcf of capacity, is planned to be in service in 2010.

Results of Operations

Adjusted earnings for the year ended December 31, 2009 were $129 million compared with $123 million for the year ended December 31, 2008. The increase in EGD’s adjusted earnings was primarily due to customer growth and lower interest expense, offset by higher operating costs and estimated accrued earnings sharing with customers under the current IR term caused primarily by a reduced rate base resulting from lower cost gas in storage.

Adjusted earnings for the year ended December 31, 2008 were $123 million compared with $115 million for the year ended December 31, 2007. EGD’s increased adjusted earnings for 2008 reflect early success during its first of five years under IR, specifically through customer growth and higher ancillary revenues.

EGD earnings were impacted by the following non-recurring or non-operating adjusting items:

· Earnings for each period are adjusted to reflect the impact of colder weather. Weather is a significant driver of delivery volumes given that a significant portion of EGD customers use natural gas for space heating.

· Earnings for the year ended December 31, 2009 included interest income of $7 million related to the recovery of excess GST remitted to Canada Revenue Agency.

· In 2008, earnings included a $3 million provision for one-time charges to better align certain operating practices with its strategy under IR.

· Earnings for the year ended December 31, 2009 and 2007 reflected an increase of $21 million and $20 million, respectively, related to favourable tax rate changes.

Business Risks

The risks identified below are specific to EGD. General risks that affect the Company as a whole are described under RISK MANAGEMENT.

Regulatory Risk

The formula currently approved by the OEB for determination of the ROE, which is embedded and escalated within rates over the IR period, is based on the OEB’s risk assessment of EGD for the 2007 fiscal year.

The OEB issued a report in December 2009 indicating several changes to the cost of capital for Ontario’s regulated utilities. The new policy guidelines established a new base level ROE of 9.75% for all of Ontario’s utilities for the 2010 rate year. The treatment of deemed capital structure was left unchanged. A new annual adjustment formula was also established which will change annually with changes in the interest rates on long-term Canada bonds and Canadian A-Rated utility bonds.

EGD anticipates that the new ROE policy guidelines will be applied to the determination of the annual earnings sharing mechanism for 2010 and for the remainder of the IR term. The company also anticipates applying the new ROE policy guidelines to the determination of rates after the conclusion of the IR term, for the rate year beginning 2013.

The settlement allows certain categories of expense, added at cost of service base amounts, and uncontrollable external factors in the IR formula, which will permit EGD to recover, with OEB approval, certain costs that are beyond management control, but are necessary for the maintenance of its services. The settlement also includes a mechanism to end 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.

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 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 for the natural gas. This allows for the quarterly adjustment of rates to reflect changes in natural gas prices. Adjustments are subject to prior approval by the OEB.

Volume Risks

Since customers are billed on both a fixed charge and on a 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 IR agreement, the portion of fixed charges will increase 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, 2009, 2008 and 2007, colder than normal weather impacted earnings by $17 million, $23 million and $14 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. On average, EGD has seen a 1.3%annual decline in residential use year-over-year between 1998 and 2008. During the IR term, the ability of EGD to annually adjust distribution volumes for rate-setting provides a mechanism to protect the company from exposure to declining average use. Further, once rates are set for the year, any incremental decline or benefit (if any) in average use, compared to the basis used for rate-setting in the most recent year, is recorded as a regulatory deferral for future collection from, or refund to, customers, to the extent this relates to residential and small commercial customers.

Sales and transportation of gas for customers in the residential and commercial sectors account for approximately 81% (2008 - 79%) 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 general service customers is mitigated by the average use true-up variance account that was established under the IR Settlement Agreement. 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 of distribution volumes for large volume contract commercial and industrial customers.

NOVERCO

Enbridge owns an equity interest in Noverco through ownership of 32.1% of the common shares and a cost investment in preferred shares. Noverco is a holding company that owns approximately 71.0% of Gaz Metro Limited Partnership (Gaz Metro), a publicly traded gas distribution company operating in the province of Quebec and in the state of Vermont.

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 investment, which is based on the yield of 10-year Government of Canada bonds plus 4.34%.

Results of Operations

Noverco adjusted earnings were $19 million for the year ended December 31, 2009, comparable to $20 million for the year ended December 31, 2008 and $18 million for the year ended December 31, 2007. Noverco earnings for the year ended December 31, 2009 and 2007 reflected an increase of $6 million and $7 million, respectively, related to favourable tax rate changes.

OTHER GAS DISTRIBUTION

Other Gas Distribution includes natural gas distribution utility operations in Quebec, New Brunswick and northern New York State. The largest utility included in this group of assets is EGNB (70.9% 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 10,000 customers. Approximately 725 kilometres (450 miles) of distribution main has been installed with the capability of attaching approximately 30,000 customers.

Results of Operations

Other Gas Distribution earnings were $26 million for the year ended December 31, 2009, comparable to $23 million for the year ended December 31, 2008. Earnings for the year ended December 31, 2008 were $4 million higher than earnings for the year ended December 31, 2007, mainly as a result of franchise customer growth in EGNB.

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 has approved the deferral of the shortfall between distribution revenues and the cost of service during the development period for recovery in future rates. This recovery period is expected to start in 2010 and end no sooner than December 31, 2040. On December 31, 2009, the regulatory deferral asset was $155 million (2008 - $133 million).

ENBRIDGE OFFSHORE PIPELINE

Offshore is comprised of 13 natural gas gathering and FERC-regulated transmission pipelines and one oil pipeline in five major corridors in the Gulf of Mexico, extending to deepwater frontiers. These pipelines include almost 1,500 miles (2,400 kilometres) of underwater pipe and onshore facilities and transported approximately 2.3 bcf/d during 2009. Offshore currently moves approximately 50% 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 throughput volume 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 deliverability expectations.

Increasingly, and reflecting recent setbacks from hurricanes, transportation tariffs on our largest system includes surcharge recoveries to cover increased operating and repair costs.

The long-term transport rates established in the gathering and transmission service agreements are generally market-based but are established using a cost of service methodology, which includes operating cost, projected revenue generation directly tied to production deliverability and the appropriate cost of capital.

The business model utilized on a go forward basis and included in the WRGGS and Big Foot commercially secured projects differs from the historic model. These new projects have a base level return which is locked in by 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 still has the life-of-lease commitments included in commercial agreements.

Results of Operations

Adjusted earnings for the year ended December 31, 2009 in Offshore were $29 million compared with $7 million for the year ended December 31, 2008. Offshore adjusted earnings increased due to higher volumes, including contributions from Shenzi, since its in-service date in April 2009, and Thunder Horse, since its in-service date of June 2008, as well as favourable foreign exchange rates. Offshore adjusted earnings for 2009 included $4 million in insurance proceeds collected during the second and fourth quarters, which were partial reimbursement for business interruption lost revenues and operating expenses associated with Hurricane Ike in 2008.

Offshore adjusted earnings for the year ended December 31, 2008 were $7 million compared with $22 million for the year ended December 31, 2007. Offshore adjusted earnings decreased as a result of

continuing natural production declines as well as approximately $11 million in lost revenue and clean up costs related to Hurricanes Gustav and Ike. These decreases were partially offset by stand-by fees on the Neptune oil and gas pipelines which came into service in the fourth quarter of 2007, as well as contributions from Atlantis and Thunder Horse platform volumes. Also, adjusted earnings for the year ended December 31, 2008 included approximately $2 million (2007 - $6 million) from business interruption insurance proceeds related to lost revenue in 2005 and 2006 as a result of the 2005 hurricanes.

Earnings for 2009 and 2007 included insurance proceeds of $4 million and $5 million, respectively, related to the replacement of damaged infrastructure as a result of the 2008 and 2005 hurricanes.

Business Risks

The risks identified below are specific to Offshore. General risks that affect the Company as a whole are described under RISK MANAGEMENT.

Weather

Adverse weather, such as hurricanes, may impact Offshore financial performance directly or indirectly. Direct impacts may include damage to Offshore facilities resulting in lower throughput and inspection and repair costs. Indirect impacts include damage to third party production platforms, onshore processing plants and pipelines that may decrease throughput on Offshore systems.

Effective June 1, 2009, Offshore’s insurance policy no longer includes coverage related to named windstorms, such as hurricanes. The decision to exclude this coverage from the policy, pending future years’ analysis, was a result of significant increases in insurance premiums and deductibles. As a result of the change in coverage, damage caused by future hurricanes could more significantly impact Offshore’s financial performance. Partially offsetting this exposure, the Stingray Pipeline system implemented, as part of a 2009 FERC rate case settlement, an event surcharge mechanism to allow recovery from shippers for hurricane damage.

Competition

There is competition for new and existing business in the Gulf of Mexico. Offshore has been able to capture key opportunities, positioning it to more fully utilize existing capacity. Offshore serves a majority of the strategically located deepwater host platforms and its extensive presence in the deepwater Gulf of Mexico has Offshore well positioned to generate incremental revenues, with modest capital investment, by transporting production 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 production, as demonstrated with the newly constructed Neptune crude oil lateral and the recently announced Big Foot Oil Pipeline. Given rates of decline, Offshore pipelines typically have available capacity, resulting in significant competition for new developments in the Gulf of Mexico.

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.

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, through cost of service tolling arrangements and 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 (1,875-mile) integrated, high-pressure

natural gas transmission pipeline system and an approximately 730-kilometre (455-mile) lateral pipeline system and related infrastructure. Alliance transports liquids-rich natural gas from northeast British Columbia and northwest Alberta to Channahon, Illinois. The pipeline has firm service shipping contract capacity to deliver 1.325 bcf/d. Enbridge owns 50% of Alliance Pipeline US, while EIF, described under Sponsored Investments, owns 50% of Alliance Pipeline Canada.

Alliance connects with Aux Sable, of which Enbridge owns 42.7%, a NGLs extraction 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.

In 2009, Pecan Pipeline, a gathering pipeline owned by a third party, was connected to a new gas receipt point on Alliance near Towner, North Dakota. This pipeline will bring associated rich gas from the Bakken formation on to Alliance. The new receipt point went into service in January 2010, with an initial volume of 40 mmcf/d, which will increase to 80 mmcf/d one year after the initial in-service date.

Transportation Contracts

Alliance has long-term, take-or-pay contracts through 2015 to transport 1.305 bcf/d of natural gas or 98.5% of the total contracted capacity. Alliance has an additional 20 million cubic feet per day (mmcf/d) of natural gas contracted through 2010 which is expected to be remarketed upon expiry. These contracts permit Alliance 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 11.5%. Each long-term contract may be renewed upon five years notice for successive one-year terms beyond the original 15-year primary term. Alliance Pipeline US operations are regulated by the FERC.

Depreciation expense included in the cost of service is based on negotiated depreciation rates contained in the transportation contracts, while depreciation expense in the financial statements is recorded on a straight-line basis at 4% per annum. Negotiated depreciation expense is generally less than the financial statement 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, that is expected to be recovered from shippers beginning in 2009 for Alliance Pipeline US and 2011 for Alliance Pipeline Canada. As at December 31, 2009, $151 million (US$144 million) (2008 - $182 million (US$149 million)) was recorded as deferred transportation revenue.

Alliance Pipeline Recontracting Strategy

Alliance continues to be fully contracted on a firm service basis and is expected to run at or near full capacity until at least 2015 when existing long-term shipper contracts expire. Alliance is developing strategies to maximize its competitiveness, post-2015, in light of falling export production from western Canada and the potential for surplus export pipeline capacity. Alliance is well placed to benefit from incremental unconventional volumes from shale plays in British Columbia, and is currently evaluating opportunities to expand its service offerings in this area.

Results of Operations

Alliance Pipeline US adjusted earnings were $27 million for the year ended December 31, 2009, comparable to $25 million for the year ended December 31, 2008 and $28 million for the year ended December 31, 2007. The slight variability in adjusted earnings each year was primarily due to United States dollar foreign exchange fluctuations.

Earnings for the year ended December 31, 2008 included $2 million in proceeds received from the settlement of a claim against a former shipper which repudiated its capacity commitment.

VECTOR PIPELINE

The Company provides operating services to, and holds a 60% joint venture interest in, Vector Pipeline, which transports natural gas from Chicago, Illinois to Dawn, Ontario. Vector Pipeline has the capacity to

deliver a nominal 1.3 bcf/d and is operating at or near capacity.

Vector Pipeline’s primary sources of supply are through interconnections with Alliance and the Northern Border Pipeline in Joliet, Illinois. Approximately 55% of the long haul capacity of Vector Pipeline is committed through 15-year firm transportation contracts at rates negotiated with the shippers and approved by the FERC. The remaining capacity is sold at market rates and at various term lengths. The total long haul capacity of Vector is approximately 90% committed through 2015. Transportation service is provided through a number of different forms of service agreements such as Firm Transportation Service and Interruptible Transportation Service. Vector Pipeline is an interstate natural gas pipeline with FERC and NEB approved tariffs establishing 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 2009, the FERC approved maximum tariff rates include a weighted average after-tax ROE component of 11.07% (2008 - 11.04%; 2007 - 10.75%). On the Canadian portion, Vector Pipeline 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 2009, maximum tariff tolls include a ROE component of 10.48% after-tax.

Results of Operations

Vector Pipeline adjusted earnings were $16 million for the year ended December 31, 2009, comparable to $14 million for the year ended December 31, 2008 and $15 million for the year ended December 31, 2007.

Business Risks

The risks identified below are specific to both Alliance Pipeline US and Vector Pipeline. General risks that affect the entire Company are described under RISK MANAGEMENT.

Supply and Demand

Advances in clean-coal technology and nuclear power as sources of power generation may reduce growth in natural gas demand over the longer term. However, demand is supported by rising use of gas for power generation. Currently, pipeline capacity out of the WCSB exceeds supply. Alliance Pipeline US and Vector Pipeline have been unaffected by this excess capacity environment mainly because of long-term capacity contracts extending to 2015. Vector Pipeline’s interruptible capacity could be negatively impacted by the basis (location) differential in the price of natural gas between Chicago and Dawn, Ontario relative to the transportation toll.

Exposure to Shippers

The failure of shippers to perform their contractual obligations could have an adverse effect on the cash flows and financial condition of Alliance Pipeline US and Vector Pipeline. To reduce this risk, Alliance Pipeline US and Vector Pipeline monitor the creditworthiness of each shipper and receive collateral for future shipping tolls should a shipper’s credit position not meet tariff requirements. These pipelines also have diverse groups of long-term transportation shippers, which include various gas and energy distribution companies, producers and marketing companies, further reducing the exposure.

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 from the WCSB to distribution systems in the Midwestern United States. In addition, there are several proposals to upgrade existing 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. 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 Pipeline 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 Pipeline 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 Pipeline 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.

Regulation

Both Vector Pipeline and Alliance Pipeline US operations are regulated by the FERC. 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, a NGLs extraction and fractionation business near Chicago, Illinois. Aux Sable owns and operates a plant at the terminus of Alliance. The plant extracts NGLs from the energy-rich natural gas transported on Alliance, as necessary to meet the requirements of downstream distribution companies, which require natural gas with less NGLs, or lower heat content; and to take advantage of positive commodity price spreads.

Aux Sable has an agreement with BP to sell its NGLs production to BP. In return, 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 supply gas to the Aux Sable facilities and is responsible for the capacity on the Alliance Pipeline held by an Aux Sable affiliate, at market rates. The agreement is for an initial term of 20 years, expiring December 21, 2025 and may be extended by mutual agreement for 10-year terms.

Results of Operations

Adjusted earnings for the year ended December 31, 2009 were $26 million compared with $28 million for the year ended December 31, 2008. Aux Sable adjusted earnings decreased due to unexpected plant outages during the fourth quarter of 2009.

Adjusted earnings for the year ended December 31, 2008 were $28 million compared with earnings of $11 million for the year ended December 31, 2007. Aux Sable adjusted earnings increased due to strong fractionation margins and enhanced plant performance, in addition to favourable risk management positions, which enabled the Company to recognize earnings from the upside sharing mechanism.

Aux Sable earnings reflected the following non-recurring or non-operating adjusting items:

· Earnings for each period reflected unrealized fair value changes on derivative financial instruments used to risk manage fractionation margin upside on natural gas processing volumes. These non-cash amounts arose due to the revaluation of financial derivatives used to “lock in” the profitability of forward contracted prices.

· Earnings for 2009 included $7 million related to a negotiated settlement with a counterparty in bankruptcy proceedings.

ENERGY SERVICES

Energy Services includes Gas Services and Tidal Energy, the Company’s energy marketing businesses. Gas Services markets natural gas to optimize Enbridge’s commitments on the Alliance and Vector pipelines. It also has a growing business of providing fee-for-service arrangements for third parties, leveraging its marketing expertise and access to contracted transportation capacity. Capacity commitments as of December 31, 2009 were 33 mmcf/d on Alliance (3% of total capacity) and 104 mmcf/d on Vector Pipeline (9% of total capacity). Capacity commitments as of December 31, 2008 were 33 mmcf/d on Alliance (3% of total capacity) and 144 mmcf/d on Vector Pipeline (12% of total capacity).

Earnings from Gas Services are dependent upon the basis (location) differentials between Alberta and Chicago, for Alliance, and between Chicago and Dawn, for Vector Pipeline. To the extent the cost of transportation on these two pipelines exceeds the gas commodity basis differential, earnings will be negatively affected.

Tidal Energy provides crude oil and NGLs marketing services for the Company and its customers in a full range of condensate and crude oil types including light sweet, light and medium sours and several heavy grades. Tidal Energy transacts at many of the major North American market hubs and provides its customers with a variety of programs, including flexible pricing arrangements, hedging programs, product exchanges, physical storage programs and total supply management. Tidal Energy’s business involves buying, selling, transporting and storing condensate and crude oil. Tidal Energy is primarily a physical barrel marketing company and in the course of its market activities can create modest commodity exposures. Any residual open positions created from this physical business are tightly monitored and must comply with the Company’s formal risk management policies.

Results of Operations

Adjusted earnings from Energy Services increased from $6 million in 2007 to $17 million in 2008 and $29 million in 2009. The increase in adjusted earnings each year is due to higher volumes and the impact of realizing favourable storage and transportation margins.

Energy Services earnings were impacted by the following non-recurring or non-operating adjusting items:

· Earnings for each period reflect unrealized fair value gains and losses resulting from the revaluation of inventory and the revaluation of largely offsetting financial derivatives used to “lock-in” the profitability of forward transportation and storage transactions. During the first quarter of 2009, the Company adopted fair value accounting for inventory held at its commodity marketing businesses.

· Energy Services 2008 earnings included a $6 million write-off as a result of bankruptcies by SemGroup and Lehman Brothers - the full amount of all such receivables was provided for in 2008. In 2009, $1 million was recovered from the SemGroup bankruptcy.

INTERNATIONAL

In 2009, the Company sold its 24.7% interest in OCENSA, a crude oil export pipeline in Colombia. In 2008, the Company sold its 25% equity interest in CLH, Spain’s largest refined products transportation and storage business. Both of these investments were sold at very attractive prices and proceeds were utilized in the funding of the North American expansion projects discussed earlier.

Given the disposals of OCENSA and CLH, 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

International adjusted earnings for the years ended December 31, 2009, 2008 and 2007 were nil, $52 million and $90 million, respectively. The decrease in adjusted earnings was a result of the sale of OCENSA and CLH discussed above.

International earnings were impacted by the following non-recurring or non-operating adjusting items:

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

· In June 2008, the Company sold its investment in CLH for proceeds of $1,380 million, resulting in a gain of $556 million.

OTHER

Results of Operations

The adjusted loss in Other was $12 million in 2009 compared with $7 million in 2008 and nil in 2007. Losses in Other primarily reflected higher business development expenditures and lower earnings from CustomerWorks Limited Partnership (CustomerWorks) which resulted from a smaller customer base.

For the year ended December 31, 2009, Other reflected the write-off of $3 million in deferred development costs as a result of adopting a change in accounting standards, effective January 1, 2009, as well as a $10 million asset impairment loss, including goodwill. For the year ended December 31, 2008, Other included a $5 million gain on the sale of the Company’s investment in Inuvik Gas.

SPONSORED INVESTMENTS

EARNINGS

(millions of Canadian dollars)	2009		2008		2007
Enbridge Energy Partners (EEP)	99		60		47
Enbridge Energy, L.P. - Alberta Clipper US (EELP)	7		-		-
Enbridge Income Fund (EIF)	45		41		39
Adjusted Earnings	151		101		86
EEP - unrealized derivative fair value gains/(losses)	(2	)	6		(6	)
EEP - asset impairment loss	(12	)	-		-
EEP - Lakehead System billing correction	4		-		-
EEP - dilution gain on Class A unit issuance	-		5		12
EEP - impact of 2008 hurricanes and project write-offs	-		(2	)	-
EEP - gain on sale of Kansas Pipeline Company (KPC)	-		-		3
EIF - Alliance Canada shipper claim settlement	-		1		-
EIF - impact of tax rate changes	-		-		2
Earnings	141		111		97

Adjusted earnings from Sponsored Investments were $151 million for the year ended December 31, 2009 compared with $101 million in 2008 and $86 million in 2007. The increase in adjusted earnings resulted primarily from increased contributions from EEP as a result of positive operating factors and Enbridge’s higher ownership interest.

Sponsored Investments earnings were impacted by several non-recurring or non-operating adjusting items:

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

· EEP earnings for the year ended December 31, 2009 included an asset impairment loss of $12 million (net to Enbridge) related to the write-down of certain assets.

· Earnings from EEP for year ended December 31, 2009 included a Lakehead System billing correction of $4 million (net to Enbridge) related to services provided in prior periods.

· Earnings in 2008 and 2007 included EEP dilution gains arising because Enbridge did not fully participate in EEP’s Class A unit offerings, decreasing Enbridge’s ownership interest in EEP to 14.6% as at March 31, 2008. In December 2008, the Company purchased an additional US$500 million in Class A units increasing Enbridge’s ownership interest in EEP to 27.0%.

· 2008 earnings from EEP included non-routine costs associated with Hurricanes Gustav and Ike, of which Enbridge’s share is $2 million, as well as the write-off of certain projects cancelled due to

market conditions.

· In 2007, EEP earnings included Enbridge’s $3 million share of the gain on the sale of KPC.

· Earnings from EIF for the year ended December 31, 2008 included proceeds of $1 million from the settlement of a claim against a former shipper on Alliance Canada which repudiated its capacity commitment.

· For the year ended December 31, 2007, EIF earnings reflected $2 million which was due to favourable tax rate changes.

ENBRIDGE ENERGY PARTNERS

EEP owns and operates crude oil and liquid petroleum transportation and storage assets and natural gas gathering, treating, processing, transportation and marketing assets in the United States. Significant assets include the Lakehead System, which is the extension of the Enbridge System 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.

In the second quarter of 2007, EEP issued partnership units. Because Enbridge did not fully participate in these offerings, dilution gains of $12 million resulted and Enbridge’s ownership interest in the Partnership decreased from 16.6% to 15.1%. Enbridge’s average ownership interest in 2007 was 15.5%. In March 2008, Enbridge did not participate in EEP’s issuance of Class A units, resulting in a $5 million dilution gain and a decrease in ownership interest to 14.6%. In late 2008, Enbridge purchased 16.3 million Class A common units of EEP, resulting in an ownership increase to 27.0%. The Company’s average ownership interest in EEP during 2008 was 15.7%. At December 31, 2009, Enbridge’s ownership interest in EEP remained at 27.0%.

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:
Up to $0.59 per unit	98%	2%
First target - $0.59 per unit up to $0.70 per unit	85%	15%
Second target - $0.70 per unit up to $0.99 per unit	75%	25%
Over second target - cash distributions greater than $0.99 per unit	50%	50%

In the first three quarters of 2007, EEP paid quarterly distributions of $0.925 per unit and effective November 2007, EEP increased quarterly distributions to $0.95 per unit. In the first two quarters of 2008 EEP paid quarterly distributions of $0.95 per unit and effective August 2008, EEP increased quarterly distributions to $0.99 per unit. Of the $99 million Enbridge recognized as adjusted earnings from EEP during 2009, 27% (2008 – 37%; 2007 - 40%) were GP incentive earnings while 73% (2008 – 63%; 2007 - 60%) were Enbridge’s limited partner share of EEP’s earnings.

Results of Operations

Adjusted earnings from EEP were $99 million for the year ended December 31, 2009 compared with $60 million for the year ended December 31, 2008. EEP adjusted earnings increased due to the Company’s higher ownership interest in EEP resulting from the December 2008 Class A unit subscription; an increased contribution due to additional assets placed in service and related tariff surcharges for recent expansions; higher incentive income; and, a more favourable foreign exchange rate at which EEP’s earnings are translated to Canadian dollars for presentation purposes.

Adjusted earnings from EEP were $60 million for the year ended December 31, 2008 compared with $47 million for the year ended December 31, 2007. EEP adjusted earnings increased as a result of higher

incentive income and increased earnings at EEP due to higher gas and crude oil delivery volumes, tariff surcharges for recent expansions and additional revenue resulting from higher average crude oil prices associated with allowance oil. These increases were partially offset by increased operating and administrative costs and write downs of natural gas inventory to fair market value as a result of declines in the price of natural gas. Also, the Company’s ownership interest in EEP increased to 27.0% in December 2008.

EEP earnings were impacted by several non-recurring or non-operating adjusting items:

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

· Earnings for the year ended December 31, 2009 included an asset impairment loss of $12 million (net to Enbridge) related to the write-down of certain assets.

· Earnings from EEP for 2009 included a Lakehead System billing correction of $4 million (net to Enbridge) related to services provided in prior periods.

· Earnings in 2008 and 2007 included dilution gains because Enbridge did not fully participate in EEP’s Class A unit offerings in May 2007 and March 2008, decreasing Enbridge’s ownership interest in EEP to 14.6%. In December 2008, the Company purchased an additional US$500 million in Class A units, increasing Enbridge ownership interest in EEP to 27.0%.

· 2008 earnings included non-routine costs associated with Hurricanes Gustav and Ike as well as the write-off of certain projects cancelled due to market conditions, of which the Company’s share totals $2 million.

· In 2007, EEP earnings included Enbridge’s $3 million share of the gain on the sale of KPC.

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 will fund 66.7% of the project’s equity requirements through EELP, while 66.7% of the debt funding will be made through EEP. EELP – Alberta Clipper US earnings are the Company’s earnings from its investment in EELP which is undertaking the project and currently represent AEDC recognized while the project is under construction.

Results of Operations

Adjusted earnings from EELP - Alberta Clipper US were $7 million for the year ended December 31, 2009. These earnings relate to AEDC earned while the project is 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.

Competition

EEP’s Lakehead System, the United States portion of the Enbridge System, is a major crude oil export route 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 system and North Dakota system also face competition from existing competing pipelines, proposed future pipelines, and alternative gathering facilities available to producers or the ability of the producers to build such gathering facilities. Competition for EEP’s storage facilities include 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 competitors that are substantially larger than EEP.

Financing Risk

EEP has made and expects to continue making substantial capital expenditures for the construction and development of crude oil and natural gas infrastructure. EEP intends to finance its future capital expenditures by utilizing cash from operations, borrowings under existing credit facilities and lastly from borrowings under the US$500 million revolving credit agreement with Enbridge (see Liquidity and Capital Resources). EEP also expects to obtain permanent financing through the issuance of additional debt and equity securities through the capital markets, as necessary.

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.

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.

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 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.

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 revenues could decrease 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 for natural gas and NGLs. These risks have been managed by using physical and financial contracts, fixing the prices of natural gas and NGLs. Certain of these financial contracts do not qualify for cash flow hedge accounting and EEP’s earnings are exposed to associated mark-to-market valuation changes.

ENBRIDGE INCOME FUND

EIF’s primary assets include a 50% interest in Alliance Pipeline Canada and the 100%-owned Enbridge Saskatchewan System, both acquired from the Company in 2003. Alliance Pipeline Canada is the Canadian portion of Alliance previously described in the Natural Gas Delivery and Services segment. The Enbridge Saskatchewan System owns and operates crude oil and liquids pipelines systems from producing fields in southern Saskatchewan and southwestern Manitoba, connecting primarily with Enbridge’s mainline pipeline to the United States.

EIF also owns interests in three wind power generation projects purchased from Enbridge in October, 2006 and a business that develops and operates waste-heat power generation projects at Alliance Pipeline Canada compressor stations.

Proposed Corporate Restructuring

On November 2, 2009, EIF announced that Enbridge, as administrator of EIF, recommended to the EIF Board of Trustees a proposed restructuring of EIF to take effect prior to the imposition of the specified investment flow-through entity (SIFT) Canadian tax on January 1, 2011. The proposed restructuring would

involve the exchange by public unitholders of their trust units, which collectively represent a 28% economic interest in EIF, for shares of a taxable Canadian corporation to be called Enbridge Income Fund Holdings Inc. (EIFH), plus a small amount of cash. The scope of activities of EIFH would be limited to investment in EIF. A committee of independent Trustees of EIF, assisted by independent legal and financial advisors, is reviewing the administrator’s recommendation in light of potential alternatives and will provide their recommendations to public unitholders. The recommended restructuring would be subject to approval by unitholders.

The Company is expected to retain its current 72% economic interest in EIF following the proposed restructuring. EIF would cease to be a SIFT and would not be subject to the SIFT tax; however, the Company would continue to be subject to corporate income tax on taxable income received from EIF. The Company is expected to remain the primary beneficiary of EIF for accounting purposes following the proposed restructuring.

Incentive and Management Fees

Enbridge receives a base annual management fee for management services provided to EIF, plus incentive fees equal to 25% of annual cash distributions over $0.825 per trust unit. In 2009, the Company received incentive fees of $8 million (2008 - $5 million, 2007 - $4 million) before income taxes. The Company is the primary beneficiary of EIF through a combination of voting units and a non-voting preferred unit investment and, as such, EIF is consolidated under variable interest entity accounting rules. The preferred unit investment held by Enbridge is entitled to non-cumulative monthly distributions in an amount equal to the monthly distribution per ordinary voting unit of EIF. Management fees, incentive fees and preferred unit distributions (EIF Fees) earned by Enbridge positively impact consolidated earnings. EIF Fees received by Enbridge are subject to income taxes at corporate rates.

Results of Operations

Adjusted earnings from EIF were $45 million for the year ended December 31, 2009, compared with the prior year of $41 million. EIF adjusted earnings primarily reflected a year-over-year increase in incentive fees and preferred unit distributions, net of income taxes. In 2009, EIF declared preferred unit distributions of $1.152 per unit compared with $1.032 per unit in 2008. These distribution increases were supported primarily by increased cash flow from Phase I of the Saskatchewan System expansion completed in June 2008. Increased earnings in the year ended December 31, 2009 attributable to incentive fees and preferred unit distributions were partially offset by increased income taxes at EIF and increased corporate costs compared with 2008.

Adjusted earnings from EIF were $41 million for the year ended December 31, 2008, compared with adjusted earnings of $39 million for the year ended December 31, 2007. EIF adjusted earnings for the year ended December 31, 2008 reflected increased incentive fees and preferred unit distributions, to the extent of minority interest and net of income taxes, owing to the year-over-year increase in distributions declared by EIF. Increased earnings and distributions realized by EIF in 2008 over 2007 primarily reflect the impact of six months of operations of Phase I of the Saskatchewan System expansion completed in June 2008.

EIF earnings were impacted by a non-recurring shipper claim settlement of $1 million in 2008 and tax rate changes of $2 million in 2007. In 2007, EIF recognized future taxes within entities that will become taxable in 2011 as a result of the SIFT legislation. This future tax increase was more than offset by the revaluation of future income tax obligations previously recorded as a result of tax rate reductions in the second and fourth quarters of 2007.

Business Risks

Risks for Alliance Pipeline Canada are similar to those identified for Alliance Pipeline US in the Natural Gas Delivery and Services segment. The following risks relate to the Saskatchewan System. General risks that affect the Company as a whole are described under Risk Management.

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. Further, 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

EIF’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 EIF.

Demand for Services

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.

CORPORATE

EARNINGS

(millions of Canadian dollars)	2009		2008		2007
Adjusted Corporate Loss	(39	)	(58	)	(59)
Unrealized derivative fair value gains	207		26		-
Unrealized foreign exchange gains on translation of intercompany balances, net	133		-		-
Gain on sale of investment in NTP	25		-		-
Impact of tax rate changes	8		-		31
Gain on sale of corporate aircraft	-		5		-
U.S. pipeline tax decision	-		(32	)	-
Asset impairment loss	-		(17	)	-
Earnings/Loss	334		(76	)	(28)

Adjusted loss from Corporate was $39 million for the year ended December 31, 2009 compared with $58 million for the year ended December 31, 2008. The improvement in Corporate adjusted loss is a result of foreign exchange gains realized on hedge settlements and on residual United States dollar cash balances as the result of a stronger United States dollar, partially offset by higher operating costs, including compensation, and an increase in bank stand-by fees reflecting tighter credit markets.

Corporate loss before adjusting items was $58 million for the year ended December 31, 2008, comparable with $59 million for the year ended December 31, 2007.

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

Earnings for the years ended December 31, 2009 and 2008 included unrealized fair value gains on the revaluation of derivative financial instruments resulting from forward risk management positions. The Company entered into foreign exchange derivative contracts in late 2008 and early 2009 to minimize the volatility of future United States dollar earnings. Additional derivative contracts used to mitigate

	cash flow volatility due to future interest rate fluctuations were entered into starting in the second quarter of 2009.
·	Earnings for 2009 included net unrealized foreign exchange gains on the translation of foreign-denominated intercompany balances.
·	On May 1, 2009, the Company sold its investment in NTP, an internet-based crude oil trading and clearing platform, for proceeds of $32 million, resulting in a gain of $25 million.
·	Earnings for the year ended December 31, 2009 included an $8 million benefit related to favourable tax rate changes.
·	A $5 million gain on the sale of a corporate aircraft is included in Corporate costs for the year ended December 31, 2008.
·	An unfavourable court decision related to the tax basis of previously owned United States pipeline assets resulted in the recognition of a $32 million income tax expense in the year ended December 31, 2008.
·	A 2008 asset impairment loss arising from the write-off of goodwill related to the Company’s Ontario wind power assets, as well as a write-down of the Company’s investment in NSolv, a technology development venture.
·	Corporate costs for 2007 reflected a $31 million charge related to favourable legislated tax changes.

LIQUIDITY AND CAPITAL RESOURCES

The Company expects to utilize cash from operations, the issuance of commercial paper and credit facility draws and issuance of long-term debt to fund liabilities as they become due, finance capital expenditures and pay common share dividends. At December 31, 2009, excluding the Southern Lights project financing, the Company had $6,011 million of committed credit facilities of which $3,643 million was drawn or allocated to backstop commercial paper. At December 31, 2009, the Company has provided its affiliates EEP and EIF with liquidity support of US$500 million and $100 million, respectively, under revolving credit agreements. Drawings on the EEP and EIF facilities at December 31, 2009 were nil and $12 million, respectively. As a result, the Company had net available liquidity at December 31, 2009 of $2,024 million, inclusive of unrestricted cash and cash equivalents of $268 million. The net available liquidity is expected to be sufficient to finance all currently secured capital projects, including the investment in the United States portion of the Alberta Clipper project, and to provide flexibility for new investment opportunities.

The Company actively manages its bank funding sources to ensure adequate liquidity and optimize pricing and other terms. During the year, the following transactions occurred:

	·	In December 2009, the Company cancelled a credit facility and reduced an existing facility, decreasing credit facilities in Corporate by $517 million.
	·	Also in December 2009, EEP cancelled two credit facilities, decreasing its available credit by US$350 million.
	·	In July 2009, the Company secured additional committed credit facilities and amended existing credit facilities to increase total Corporate credit facilities by $70 million and decrease Natural Gas Delivery and Services credit facilities by $200 million.
	·	In June 2009, EIF secured additional credit facilities of $150 million of which the Company committed $100 million on the same terms as a third party bank lender. This additional credit supplements EIF’s liquidity to finance its capital program and funded a debt maturity in December 2009.
	·	In April 2009, EEP secured additional credit facilities of US$350 million of which the Company committed US$150 million on the same terms as the third party bank lenders. This additional liquidity supplemented EEP’s liquidity to manage its 2009 capital program.

On July 20, 2009, Enbridge announced that it will fund two-thirds of the estimated US$1,300 million United States segment of the Alberta Clipper project. As a result of this investment, in December 2009, the US$350 million credit facilities were cancelled. Further, in 2009, EEP repaid an affiliate loan owing to the Company in the amount of US$130 million.

The following table provides details of the Company’s credit facilities at December 31, 2009.

(millions of Canadian dollars)	Expiry Dates	Total Facilities	Credit Facility Draws2	Available
Liquids Pipelines	2011	1,300	876	424
Natural Gas Delivery and Services	2010 - 2011	813	512	301
Corporate	2011 - 2013	3,898	2,255	1,643
		6,011	3,643	2,368
Southern Lights project financing1	2014	1,796	1,531	265
Total Credit Facilities		7,807	5,174	2,633

1 Total facilities inclusive of $186 million which is available if certain conditions related to the project are met.

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

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, 2009, the Company was in compliance will 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, 2009, including short-term borrowings but excluding non-recourse debt and project financing, was 63.6%, compared with 63.6% at the end of 2008. Including all debt, the capitalization ratio was 66.1% at December 31, 2009 compared with 66.6% at December 31, 2008.

The Company invests its surplus cash in short-term investment grade instruments with credit worthy counterparties. Short-term investments were $143 million at December 31, 2009 (2008 - $474 million).

Excluding current maturities of long-term debt, the Company has a positive working capital position, consistent with December 31, 2008.

(millions of Canadian dollars)	2009		2008
Cash and cash equivalents1	327		542
Accounts receivable and other	2,484		2,322
Inventory	784		845
Short-term borrowings	(508	)	(874	)
Accounts payable and other	(2,463	)	(2,411	)
Interest payable	(104	)	(102	)
Working capital	520		322

1 Includes short-term investments.

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 increased to $2,017 million for the year ended December 31, 2009 from $1,372 million for the year ended December 31, 2008. The increase in cash provided by operating activities in 2009 compared with 2008 resulted primarily from increased contributions from the Company’s growth projects placed into service in 2009 and additional contributions from EEP as a result of the Company’s increased ownership. Cash provided by operating activities for the year ended December 31, 2008 of $1,372 million is comparable to cash provided by operating activities of $1,362 million for the year ended December 31, 2007.

There are no material restrictions on the Company’s cash with the exception of proportionately consolidated joint venture cash of $52 million, which cannot be accessed until distributed to the Company, and cash in trust of $7 million for specific shipper commitments.

Investing Activities

In 2009, cash used for investing activities was $3,306 million compared with $2,853 million in 2008, an increase of $453 million. Additions to property, plant and equipment of $3,225 million for the year ended December 31, 2009 related primarily to capital expenditures on growth projects, most notably Southern Lights and Alberta Clipper. Offsetting these expenditures in 2009 were proceeds on the sale of OCENSA of $535 million. In comparison, proceeds on the sale of the Company’s investment in CLH were $1,383 million for the year ended December 31, 2008.

Investing activities also include long-term investments and affiliate lending. Additions to long-term investments in 2009 include $357 million related primarily to the Company’s investment in EELP, which is constructing the United States segment of the Alberta Clipper Project. In 2009, the Company advanced US$270 million to EEP to fund its share of the debt component of the Alberta Clipper Project which was offset by the repayment by EEP of a US$130 million affiliate loan. In 2008, the Company increased its investment in EEP by subscribing for 16.3 million Class A common units for US$500 million.

Cash used for investing activities for the year ended December 31, 2008 was $2,853 million compared with $2,229 million in 2007. The increase was due to additional capital expenditures on growth projects and core capital maintenance expenditures in 2009 compared with 2008, as well as an additional investment in EEP in November 2008. Partially offsetting these increases was proceeds of $1,383 million on the sale of the Company’s investment in CLH in June 2008.

Capital Expenditures and Investments

	Expected	Actual	Actual
(millions of Canadian dollars)	2010	2009	2008
Liquids Pipelines	1,022	2,662	2,898
Natural Gas Delivery and Services	677	440	544
Sponsored Investments	258	400	700
Corporate	552	217	109
	2,509	3,719	4,251

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 $2,509 million during 2010 on maintenance and capital projects, including equity investments in EEP and EELP (within Sponsored Investments), which are substantially secured. While consistent or still in excess of longer term historic levels, the expected decline in 2010 expenditures relative to 2009 and 2008 reflects the completion of certain large multi-year construction projects. The 2010 expected corporate capital expenditures increase reflects new green investments in wind and solar power generation. 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 access to 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 2009, the Company generated cash of $1,109 million through financing activities compared with $1,840 million and $904 million in 2008 and 2007, respectively.

Significant financing activities in 2009 include medium-term note issues of $1,500 million compared with $498 million in 2008 and $1,342 million in 2007. In 2009, the Company issued both a $400 million seven-year and 10-year term note along with a $200 million 30-year term note. Enbridge Pipelines Inc. (EPI) issued $300 million and $200 million in 10-year and 30-year term notes, respectively. In comparison, in 2008 EGD issued a $200 million five-year term note and EPI closed a $300 million 10-year term note; 2007 included the issuance of US$1,100 million in term notes issued in the United States market by the Company and $200 million of term notes issued by EGD in the Canadian market. Cash generated through debenture and term note issues is partially offset by repayments of debentures and term notes which totaled $516 million, $602 million and $635 million for the years ended December 31, 2009, 2008 and 2007, respectively.

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 project. Net proceeds on Southern Lights financing were $343 million for the year ended December 31, 2009 and $1,238 million for the year ended December 31, 2008.

Short-term borrowings are used primarily to finance near term working capital requirements, including inventory at EGD. Due to the decline in natural gas commodity prices in 2009 compared with 2008, and the resultant decline in cash needed to finance inventory requirements, the Company made net repayments on short term borrowings totaling $366 million in 2009. In comparison, the net change in short-term borrowings provided cash of $329 million in 2008, and a net repayment of short-term borrowings of $262 million was made in 2007.

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, 2009, dividends declared were $555 million (2008 - $489 million), of which $414 million (2008 - $359 million) were paid in cash and reflected in financing activities. The remaining $141 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 year ended December 31, 2009 and December 31, 2008, 25% and 27%, respectively, of total dividends declared were reinvested.

Outstanding Share Data1

		Number
Preferred Shares, Series A (non-voting equity shares)		5,000,000
Common shares – issued and outstanding (voting equity shares)		378,351,456
Total issued and outstanding stock options (7,512,712 vested)		15,735,885

1 Outstanding share data information is provided as at February 10, 2010.

CONTINGENCIES AND COMMITMENTS

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 on Bloor Street West in Toronto in April 2003. In October 2007, all of the TSSA and OHSA charges against EGD were dismissed by the Ontario Court of Justice. The decision has been appealed by the Crown to the Ontario Superior Court of Justice and the appeal was heard by the Court during November and December 2009. The Court’s decision has been reserved and EGD expects it to be released in early 2010. EGD does not believe any fines that may be levied would have a material financial impact on EGD.

EGD has also been named as a defendant in a number of civil actions related to the explosion. All significant civil actions have been settled without any material financial impact on EGD. A Coroner’s Inquest in connection with the explosion is also possible.

OTHER 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.

OTHER LITIGATION

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.

COMMITMENTS

The Company has signed contracts for the purchase of services, pipe and other materials totaling $697 million. Of this amount, $406 million is to be used in the construction of several Liquids Pipelines projects including Southern Lights Pipeline.

On July 20, 2009, the Company committed to fund 66.7% of the United States segment of the Alberta Clipper Project through EEP and EELP. The total cost of the United States segment is estimated at US$1,300 million.

CONTRACTUAL OBLIGATIONS

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

(millions of Canadian dollars)	Total	Less than 1 year	1-3 years	3-5 years	After 5 years
Long-term debt1	12,168	600	151	1,269	10,148
Non-recourse long-term debt1	1,472	109	140	156	1,067
Capital and operating leases	176	18	40	35	83
Long-term contracts2,3	1,654	834	444	238	138
Post-employment benefit obligations4	74	74	-	-	-
Total Contractual Obligations	15,544	1,635	775	1,698	11,436

1 Excludes interest. Changes to the planned funding requirements dependent on the terms of any debt re-financing agreements.

2 Approximately $406 million of these contracts are commitments for materials related to the construction of Liquids Pipelines projects. Changes to the planned funding requirements are dependent on changes to the related projects.

3 Contracts totaling $138 million are between the Company and proportionately consolidated joint venture entities.

4 Assumes only required payments will be made into the pension plans in 2010. Contributions are made in accordance with the independent actuarial valuations as of December 31, 2009. Contributions, including discretionary payments, may vary pending future benefit design and asset performance.

QUARTERLY FINANCIAL INFORMATION1

(millions of Canadian dollars, except for per share amounts)

2009	Q1	Q2	Q3	Q4	Total
Revenues	3,783	2,868	2,629	3,186	12,466
Earnings applicable to common shareholders	558	393	304	300	1,555
Earnings per common share	1.54	1.08	0.83	0.81	4.27
Diluted earnings per common share	1.53	1.08	0.83	0.80	4.25
Dividends per common share	0.37	0.37	0.37	0.37	1.48

(millions of Canadian dollars, except for per share amounts)

2008	Q1	Q2	Q3	Q4	Total
Revenues	3,968	3,871	4,368	3,924	16,131
Earnings applicable to common shareholders	251	658	148	264	1,321
Earnings per common share	0.70	1.83	0.41	0.72	3.67
Diluted earnings per common share	0.70	1.81	0.41	0.71	3.64
Dividends per common share	0.33	0.33	0.33	0.33	1.32

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

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

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 resultant 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. Further, in EGD, as a result of continued changes in customer billing to increase the fixed charge portion and decrease the per unit volumetric charge, revenues and earnings will shift from the colder winter quarters progressively to the warmer summer quarters, with no material impact on full year revenue and earnings. This change will also impact the comparability of a given quarter from year to year. In each of the four quarters of 2009, revenues generated by EGD and other gas distribution businesses have declined compared with the corresponding quarters of 2008 primarily due to depressed natural gas prices throughout 2009 compared with the prior year.

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 hedge accounting, unrealized fair value gains and losses on these instruments will impact earnings. Most notably, earnings were negatively impacted by an unrealized derivative fair value loss of $43 million in the first quarter of 2009, and positively impacted by unrealized derivative fair value gains of $115 million, $102 million and $33 million for the second, third and fourth quarters of 2009, respectively. In comparison, earnings for the fourth quarter of 2008 included an unrealized derivative fair value gain of $26 million, while the first three quarters of 2008 had no similar impact. Further, second, third and fourth quarter earnings of 2009 include unrealized foreign exchange gains on translation of intercompany loans of $68 million, $50 million and $15 million, respectively, compared with nil in each of the corresponding periods of 2008.

Other significant items that impacted the quarterly results include a gain of $329 million on the disposition of the Company’s investment in OCENSA in the first quarter of 2009 and a gain on sale of the Company’s investment in CLH in the amount of $556 million in the second quarter of 2008.

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 provided 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 Pipeline, 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, 2009 are $342 million (2008 - $302 million; 2007 - $267 million) to EEP and $6 million (2008 - $6 million; 2007 - $5 million) to Vector Pipeline. At December 31, 2009, the Company has accounts receivable of $38 million (2008 - $41 million) from EEP and $1 million (2008 - $1 million) from Vector Pipeline.

The Company has provided EEP with an unsecured revolving credit agreement for general liquidity support. The credit facility provides for a maximum principle amount of US$500 million for a three-year term maturing in December 2010. At December 31, 2009 and 2008, there were no amounts outstanding on this facility.

EGD, a subsidiary of the Company, has contracts for gas transportation services from Alliance and Vector Pipeline. EGD is charged market prices for these services. For the year ended December 31, 2009, EGD was charged $42 million (2008 - $41 million; 2007 - $36 million) for services from Alliance Pipeline and $29 million (2008 - $27 million; 2007 - $25 million) from Vector Pipeline.

Enbridge Gas Services (US) Inc., 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, 2009, amounts purchased were $16 million (2008 - $52 million; 2007 - $43 million) and sales were $6 million (2008 - $7 million; 2007 - $4 million).

Enbridge Gas Services Inc. and Enbridge Gas Services (US) Inc., subsidiaries of the Company, have transportation commitments, measured at market value, through 2015 on Alliance Pipeline Canada, Alliance Pipeline US and Vector Pipeline. For the year ended December 31, 2009, amounts paid to Alliance Pipeline Canada were $9 million (2008 - $9 million; 2007 - $8 million), amounts paid to Alliance Pipeline US were $7 million (2008 - $7 million; 2007 - $7 million) and amounts paid to Vector Pipeline were $16 million (2008 - $16 million; 2007 - $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, 2009, amounts purchased were $80 million (2008 - $24 million; 2007 - $5 million) and sales were $7 million (2008 - $9 million; 2007 - $6 million).

CustomerWorks, a joint venture, provided customer care services to EGD under an agreement having a five-year term which expired in 2007 and was not renewed. EGD was charged market prices for these services. For the year ended December 31, 2009, amounts charged by CustomerWorks to EGD were nil (2008 – nil; 2007 - $26 million). CustomerWorks also rented an automated billing system from Enbridge Commercial Services Inc. (ECS), a subsidiary of the Company. For the year ended December 31, 2009, amounts charged by ECS to CustomerWorks were $2 million (2008 - $2 million; 2007 - $2 million).

Alberta Clipper PROJECT

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 total cost of the United States segment, which is expected to be ready for service on April 1, 2010, is estimated at US$1,300 million, with total expenditures to date of US$900 million. Further information on this project is included in GROWTH PROJECTS.

The Company is funding 66.7% of the project’s equity requirements through EELP, an equity investee. The Company has provided a $282 million (US$270 million) loan to EEP for debt financing related to the construction. At December 31, 2009, this amount is included in Accounts Receivable and Other. The loan, denominated in United States dollars, bears interest based on variable short-term rates.

In August 2008, the Company transferred $23 million, measured at market value, of 36 inch diameter line pipe to EEP for use in constructing the United States segment of 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 Project

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 was effective in February 2009 and can be terminated at any time with written notice.

LONG-TERM Receivable from Affiliate

The affiliate long-term note receivable of $159 million (US$130 million) as at December 31, 2008, included in Deferred Amounts and Other Assets, was repaid by EEP in November 2009. Interest income for the year ended December 31, 2009 related to the note receivable was $11 million (2008 - $12 million; 2007 - $10 million).

RISK MANAGEMENT

Enbridge’s value proposition is based on maintaining a very low risk profile. Over 85% of the Company’s earnings come from regulated businesses; over 80% of its revenues are volume protected under cost of service rate-making or long-term take-or-pay arrangements; and more than 95% 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 eliminating the majority of its business risk, the Company has formal risk 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 and commodity prices (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.

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.

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. 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 hedged over 80% of its forecast adjusted earnings through 2014 at an average rate of approximately $1.20 C$/US$. The Company may also hedge anticipated foreign currency denominated purchases or sales, foreign currency denominated debt, as well as certain equity investment balances and net investments in foreign denominated subsidiaries.

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 obligations. Floating to fixed interest rate swaps and options are used to hedge against the effect of future period interest rate movements. The Company has implemented a hedging program to significantly mitigate the volatility to variable rate interest expense through 2013 at an average rate of 2.2%.

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 2013. A total of $2,500 million of future fixed rate term debt issuances have been hedged at an average government bond rate of 4%. 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 that the consolidated portfolio of debt stays within its 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, as well as through the activities of its energy services subsidiaries. The Company uses natural gas, power, crude oil and NGL derivative instruments to fix a portion of the variable price exposures that may arise from commodity usage, storage, transportation and supply agreements.

The Company has implemented a hedging program, through 2011, to mitigate the volatility from fractionation spreads (natural gas/NGLs) that impact earnings from its ownership in the Aux Sable natural gas processing plant.

The following table summarizes the EaR as a percentage of forecast earnings from the main groups of market price risk after the impact of the Company’s hedging programs. These EaR numbers are based on business conditions and hedging programs as of December 31, 2009 and may not be applicable to other periods.

Risk		EaR
(% of forecast 12 month forward earnings)
Foreign Exchange		0.3%
Interest Rate		-%
Commodity		2.3%
Total		2.6%

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 Natural Gas Delivery and Services 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 to derivatives counterparties by entering into risk management transactions only with institutions that possess solid investment grade credit ratings or which have provided the Company with an acceptable form of credit protection. The Company has no significant

concentration with any single counterparty. During 2008, the Company reduced its exposure to certain financial counterparties through the discontinuance of certain hedges. 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 2009, despite the severe 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 the near and long term 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 medium-term notes. The Company maintains current shelf prospectuses with the securities regulators, which enables, subject to market conditions, ready access to either the Canadian or United States public capital markets.

Maturities of Derivative Financial Liabilities

For the years ending December 31, 2010 through 2014, and thereafter, the Company has estimated the following undiscounted cash flows will arise from its derivative instruments based on valuation at the balance sheet date.

(millions of Canadian dollars)	2010	2011	2012	2013	2014	Thereafter
Cash inflows	182	106	136	155	86	51
Cash outflows	(167)	(29)	(5)	(7)	(3)	(25)
Net cash flows	15	77	131	148	83	26

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

GENERAL BUSINESS RISKS

Execution Risk

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, shortages and in-service delays (collectively, Execution Risk). The Company’s growth plans may strain its resources and may be subject to high cost pressures in the North American energy sector. 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 slow delivery of materials, contractor non-performance, weather conditions and shortages may impact project development. Labour shortages, inexperience and productivity issues may also affect the successful completion of the projects.

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. The Company’s emphasis on corporate social responsibility promotes generally positive relationships with landowners, aboriginal groups and governments which help to facilitate right-of-way acquisition, permitting and schedule. 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. Compensation programs, communications and the working environment are aligned to attract, develop and retain qualified personnel.

Pipeline Operating Risk

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 the Company’s pipelines 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. 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.

Regulation

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 operations of shippers. Recently shippers have challenged toll increases on various pipelines owned by some of Enbridge’s competitors, and certain of Enbridge’s shippers have sought to delay the in-service date and implementation of the tariff on the Company’s Alberta Clipper Project. Enbridge retains dedicated professional staff and maintains strong relationships with customers, interveners and regulators to help minimize regulatory risk.

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 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 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. Regular reviews and audits are conducted to assess compliance with legislation and Company policy.

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 recently reviewed and updated its Indigenous Peoples Policy, which has been renamed the Aboriginal and Native American Policy. The new 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

The Company is exposed to the risk of higher costs, delays or even project cancellations due to increasing pressure on government and regulators by special interest groups. Recent Supreme Court decisions have increased the ability of special interest groups to make claims and oppose projects in regulatory and legal forums. The Company works proactively with special interest groups to identify and develop an appropriate response to concerns regarding its projects. The Company’s Corporate Social Responsibility (CSR) program also reports on the Company’s responsiveness to environmental and community issues. Please see Enbridge’s annual CSR report, available online at www.enbridge.com/csr2009 for further details regarding the CSR program.

Legislation Risk

Climate Change Legislation

The Canadian Federal Government has indicated that Canada will target a 17% reduction of GHG emissions by 2020, based on 2006 emission levels. It has also signaled that 90% of Canada’s electricity will be provided by non-emitting sources, such as hydro, nuclear, clean-coal, solar and wind, by 2020. Details of Canada’s GHG management plan will not be released until there is clarity in the United States about its intention to regulate GHG emissions. Canadian regulations will likely be compatible with those of the United States in order for Canadian businesses to remain competitive and avoid the potential for punitive trade sanctions. It is uncertain how climate legislation could affect the industry. Enbridge continues to monitor this activity.

Low Carbon Fuel Standards

California and Oregon have adopted Low Carbon Fuel Standards and other states (including the seven New England states) are considering the same. If widely adopted, such standards could limit United States refiners from importing oil sands products, as they are more energy-intensive to process than

conventional crude. Flow restrictions of oil sands products to the United States would increase interest in exports to Asia, and consequently increase interest in projects like Enbridge’s Northern Gateway Project.

Renewable Energy

Enbridge has significant interest in wind and solar power 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. For example, the Feed-in-Tariff program introduced by the Ontario Green Energy Act has created significant opportunities for renewable energy growth in Ontario. The extension of the Production Tax Credit, introduction of a federal cash grant and the potential for a nationwide minimum Renewable Portfolio Standard have accelerated renewable energy projects across the United 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 renewable energy projects in a particular province, state or federal jurisdiction.

Workforce Development

A lack of qualified and properly trained technical, professional and operational staff and leaders would increase the risk that the Company will not be able to implement its corporate strategy. This risk may be compounded by the increasing rates of retirement due to workforce demographics, turnover due to competition in certain markets and growing demand for staff to support business growth. The Company continues to monitor company-wide workforce planning. The Company offers competitive compensation programs, training, leadership development and succession planning. Further, the supply of human resources is balanced between hiring full-time employees and expanding the contractor workforce, particularly in the Major Projects’ department.

Terrorism

The risk of terrorism continues to be monitored due to the high profile of the petroleum industry in Canada and the reliance of the United States on Canadian exports. An act of terrorism may result in the loss of upstream supplies, pipelines, distribution or storage controls systems with safety and environmental implications. The Company manages this risk through its Human Resources Protection Program, Crisis Management Plan and insurance programs where available.

FINANCIAL INSTRUMENTS

	December 31, 2009
(millions of Canadian dollars)	Held for Trading	Available for Sale	Loans and Receivables	Held to Maturity	Other Financial Liabilities	Qualifying Derivatives	Non- Financial Instruments	Total		Fair Value1
Assets
Cash and cash equivalents	327	-	-	-	-	-	-	327		327
Accounts receivable and other	76	-	2,054	-	-	52	302	2,484		2,182
Long-term investments	-	54	6	181	-	-	2,071	2,312		187
Deferred amounts and other assets	288	-	-	-	-	197	1,940	2,425		485
Liabilities
Short-term borrowings	-	-	-	-	508	-	-	508		508
Accounts payable and other	36	-	-	-	2,177	87	163	2,463		2,300
Interest payable	-	-	-	-	104	-	-	104		104
Long-term debt	-	-	-	-	12,283	-	(101	)	12,182	13,450
Non-recourse long-term debt	-	-	-	-	1,515	-	(9	)	1,506	1,573
Other long-term liabilities	2	-	-	-	-	40	1,165	1,207		42

	December 31, 2008
(millions of Canadian dollars)	Held for Trading	Available for Sale	Loans and Receivables	Held to Maturity	Other Financial Liabilities	Qualifying Derivatives	Non- Financial Instruments	Total		Fair Value1
Assets
Cash and cash equivalents	542	-	-	-	-	-	-	542		542
Accounts receivable and other	41	-	1,869	-	-	31	381	2,322		1,948
Long-term investments	-	54	167	405	-	-	1,866	2,492		492
Deferred amounts and other assets	68	-	-	-	-	249	1,001	1,318		317
Liabilities
Short-term borrowings	-	-	-	-	874	-	-	874		874
Accounts payable and other	18	-	-	-	1,965	32	396	2,411		2,015
Interest payable	-	-	-	-	102	-	-	102		102
Long-term debt	-	-	-	-	10,795	-	(106	)	10,689	11,173
Non-recourse long-term debt	-	-	-	-	1,669	-	(10	)	1,659	1,672
Other long-term liabilities	11	-	-	-	-	36	212	259		47

1 Fair value does not include non-financial instruments, which includes investments accounted for under the equity method, and available for sale equity instruments held at cost that do not trade on an actively quoted market.

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. 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 the nature of the investments. 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 and time value.

Derivative Instruments

The following table summarizes the maturity and total notional principal or quantity outstanding related to the Company’s derivative instruments. The Company does not have any credit-risk related contingent features associated with its derivative instruments.

	December 31, 2009			December 31, 2008
		Maturity	Notional Principal or Quantity Outstanding	Maturity	Notional Principal or Quantity Outstanding
U.S. dollar cross currency swaps			-	2013-2022	138
(millions of Canadian dollars)
U.S. dollar forwards - purchase		2010-2019	1,078	2009-2017	1,118
(millions of United States dollars)
U.S. dollar forwards - sell		2010-2020	3,102	2009-2021	2,548
(millions of United States dollars)
Interest rate contracts		2010-2029	6,022	2009-2029	1,164
(millions of Canadian dollars)
Energy commodity (bcf)		2010-2011	464	2009-2010	530

Power commodity (MW/H)		2010-2024	38	2009-2024	57

Derivative Instruments

(millions of Canadian dollars) December 31, 2009	Derivative Instruments used as Cash Flow Hedges	Derivative Instruments used as Net Investment Hedges	Non- Qualifying Derivative Instruments	Total Derivative Instruments
Accounts receivable and other
U.S. dollar forwards	4	14	52	70
Interest rate contracts	34	-	2	36
Energy commodity	-	-	19	19
Power commodity	-	-	3	3
	38	14	76	128
Deferred amounts and other
U.S. dollar forwards	25	80	285	390
Interest rate contracts	90	-	-	90
Energy commodity	-	-	1	1
Power commodity	1	-	1	2
Other	1	-	1	2
	117	80	288	485
Accounts payable and other
U.S. dollar forwards	(2)	-	(3)	(5)
Interest rate contracts	(68)	-	-	(68)
Energy commodity	(17)	-	(32)	(49)
Power commodity	-	-	(1)	(1)
	(87)	-	(36)	(123)
Other long-term liabilities
U.S. dollar forwards	(21)	-	-	(21)
Interest rate contracts	(15)	-	-	(15)
Energy commodity	(4)	-	-	(4)
Power commodity	-	-	(2)	(2)
	(40)	-	(2)	(42)
Total net derivative asset/(liability)
U.S. dollar forwards	6	94	334	434
Interest rate contracts	41	-	2	43
Energy commodity	(21)	-	(12)	(33)
Power commodity	1	-	1	2
Other	1	-	1	2
	28	94	326	448

(millions of Canadian dollars) December 31, 2008	Derivative Instruments used as Cash Flow Hedges	Derivative Instruments used as Net Investment Hedges	Non- Qualifying Derivative Instruments	Total Derivative Instruments
Accounts receivable and other
U.S. dollar forwards	12	8	-	20
Interest rate contracts	1	-	-	1
Energy commodity	9	-	32	41
Power commodity	1	-	9	10
	23	8	41	72
Deferred amounts and other
U.S. dollar cross currency swaps	26	-	-	26
U.S. dollar forwards	153	63	56	272
Power commodity	7	-	12	19
	186	63	68	317
Accounts payable and other
U.S. dollar forwards	-	-	(14)	(14)
Interest rate contracts	(9)	-	-	(9)
Energy commodity	(22)	-	(4)	(26)
Power commodity	(1)	-	-	(1)
	(32)	-	(18)	(50)
Other long-term liabilities
U.S. dollar forwards	-	-	(8)	(8)
Interest rate contracts	(22)	-	-	(22)
Power commodity	(11)	-	(1)	(12)
Other	(3)	-	(2)	(5)
	(36)	-	(11)	(47)
Total net derivative asset/(liability)
U.S. dollar cross currency swaps	26	-	-	26
U.S. dollar forwards	165	71	34	270
Interest rate contracts	(30)	-	-	(30)
Energy commodity	(13)	-	28	15
Power commodity	(4)	-	20	16
Other	(3)	-	(2)	(5)
	141	71	80	292

The fair value of derivative instruments has been estimated using period end market information. This market information includes observable inputs such as published market prices for commodities, interest rate yield curves and foreign exchange rates. When possible, financial instruments are valued using quoted market prices.

An unrealized fair value loss of $53 million (2008 - $298 million) related to derivative instruments used as cash flow and net investment hedges was recognized in OCI for the year ended December 31, 2009. An unrealized fair value gain related to non-qualifying derivative instruments of $146 million (2008 - $157 million) was recognized in commodity costs, other investment income and interest expense for the year ended December 31, 2009.

Additional information about the Company’s Risk Management and Financial Instruments is included in Notes 23 and 24 of the 2009 Annual Consolidated Financial Statements.

critical accounting ESTIMATES

DEPRECIATION

Depreciation of property, plant and equipment, the Company’s largest asset with a net book value at December 31, 2009 of $18,850 million, or 67% 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 Liquids Pipelines and Natural Gas Delivery and Services businesses are subject to regulation by various authorities, including but not limited to, the NEB, the FERC, the Energy Resources Conservation Board (ERCB) 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, 2009, the Company’s regulatory assets totaled $1,411 million (2008 - $635 million) and regulatory liabilities totaled $1,038 million (2008 - $109 million). To 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.

Post Employment Benefits

The Company maintains pension plans, which provide defined benefit and/or defined contribution pension benefits and other post-employment benefits (OPEB) to eligible retirees. Pension costs and obligations for the defined benefit pension plans are determined using the projected benefit method. This method involves complex actuarial calculations using several assumptions including discount rates, 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 $24 million for the year ended December 31, 2009 (2008 - $288 million) as disclosed in Note 27 to the 2009 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.

Assuming no discretionary funding is made into the pension plans, funding in 2010 will be approximately $74 million, which is not considered significant to the Company.

The following sensitivity analysis identifies the impact on the December 31, 2009 Consolidated Financial Statements of a 0.5% change in key pension and OPEB assumptions.


(millions of Canadian dollars)	Pension Benefits		OPEB
	Obligation	Expense	Obligation	Expense
Decrease in discount rate	72	10	13	1
Decrease in expected return on assets	n/a	5	n/a	-
Decrease in rate of salary increase	(17)	(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 2009 Annual Consolidated Financial Statements.

Asset Retirement Obligations

In May 2009, the NEB released a report on the financial issues associated with pipeline abandonment. The NEB will require all companies to formally assess the timeline and cost of future abandonment and, if necessary, set aside funds to cover future abandonment costs. All pipelines regulated under the NEB Act will be required to comply with the report’s framework and action plan. The NEB began hosting technical meetings in September 2009 to evaluate how abandonment estimates will be calculated and submitted, as well as proposals for how funds will be collected and set aside. The NEB’s goal is for companies, as required, to begin setting aside funds for abandonment no later than the end of May 2014. Currently, for certain of the Company’s assets, it is not practical to make a reasonable estimate of asset retirement obligations for accounting purposes due to the indeterminate timing and the scope of asset retirements. However, should the NEB action plan result in a reasonable estimate of asset retirement obligations for accounting purposes, financial statement recognition of those obligations may be made in future periods. As a result, regulatory assets and liabilities may be recognized to the extent the timing of recovery from shippers differs from the recognition of abandonment costs for accounting purposes.

CHANGE IN ACCOUNTING POLICIES

ACCOUNTING FOR THE EFFECTS OF RATE REGULATION

Effective January 1, 2009, the Company adopted revisions to the Canadian Institute of Chartered Accountants (CICA) Handbook Section 1100, Generally Accepted Accounting Principles and Section 3465, Income Taxes. In accordance with the transitional provisions in these revised standards, the revisions to Section 1100 were adopted prospectively and, accordingly, prior periods were not restated, while the revisions to Section 3465 were applied retrospectively without restatement of prior periods. The adoption of the revised standards did not impact the Company’s earnings or cash flows.

Generally Accepted Accounting Principles

The revised standard no longer provides an exemption for rate-regulated entities to measure assets and liabilities on a basis other than in accordance with primary sources of Canadian GAAP. As a result, for the pension plans and OPEB included in EGD, the Company recognized post-employment benefit assets and liabilities for the amount of benefits expected to be included in future rates and recovered from, or paid to, customers. In addition, the Company reclassified certain EGD reserves for future removal and site restoration.

Pension Plans and OPEB

On adoption of the revised standard at January 1, 2009, the Company recognized a net pension asset of $157 million and a net OPEB liability of $75 million, with an offsetting long-term net pension regulatory liability and long-term net OPEB regulatory asset, respectively. At December 31, 2009, the Company had a net pension asset of $140 million and a net OPEB liability of $80 million, with an offsetting long-term net

pension regulatory liability and a long-term net OPEB regulatory asset, respectively.

Future Removal and Site Restoration Reserves

At January 1, 2009, on adoption of the revised standard, the Company reclassified amounts collected for future removal and site restoration of $657 million, which were previously netted against Property, Plant and Equipment, to a long-term regulatory liability. At December 31, 2009, this long-term regulatory liability was $710 million.

Income Taxes

The revised standard removes the exemption for rate-regulated entities to recognize future income taxes to the extent they were expected to be included in regulator-approved future rates and recovered from or refunded to future customers. As a result, on January 1, 2009, the Company recognized a future income tax liability of $816 million on regulatory assets, primarily property, plant and equipment, with an offsetting long-term regulatory asset. A regulatory asset has been recognized as the associated future income tax liability is expected to be recoverable in future rates. At December 31, 2009, the Company had a future income tax liability of $829 million related to regulatory assets with an offsetting long-term regulatory asset.

INTANGIBLE ASSETS

Effective January 1, 2009, the Company adopted CICA Handbook Section 3064, Goodwill and Intangible Assets, which establishes standards for the recognition, measurement, presentation and disclosure of goodwill and intangible assets. As a result of adopting this standard, the Company reclassified certain software costs from Property, Plant and Equipment to Intangible Assets. This standard has been applied retrospectively and affects presentation only.

As a result of adopting this standard, on January 1, 2009, the Company reclassified $233 million of net software costs from Property, Plant and Equipment to Intangible Assets. At December 31, 2009, the Company had $289 million of net software costs recorded in Intangible Assets.

COMMODITY INVENTORY

Effective January 1, 2009, the Company changed its accounting policy for inventory held by its energy marketing businesses and began measuring commodity inventory at fair value, as measured at the spot price less costs to sell, rather than lower of cost or net realizable value. This measurement basis is a more relevant measurement for commodity inventory used for marketing purposes and better matches the commodity inventory with the derivatives used to “lock in” the margin. This change in accounting policy has been accounted for retrospectively and did not result in restatements of the comparative Consolidated Statements of Earnings, Comprehensive Income, Shareholders’ Equity or Cash Flows for the years ended December 31, 2008 and 2007 and the comparative Consolidated Statement of Financial Position as at December 31, 2008 as the amounts were considered immaterial.

INVENTORIES

The CICA issued Handbook Section 3031, Inventories, effective January 1, 2008 which aligns accounting for inventories under Canadian GAAP with International Financial Reporting Standards (IFRS) and replaces Section 3030. The adoption of the revised standard did not have a significant effect on the Company.

CAPITAL DISCLOSURES AND FINANCIAL INSTRUMENTS – DISCLOSURES AND PRESENTATION

Effective January 1, 2008, the Company adopted new standards for Capital Disclosures (CICA Handbook Section 1535) and Financial Instruments – Disclosures and Presentation (CICA Handbook Sections 3862 and 3863). While the new standards did not change the Company’s accounting policies, they resulted in additional disclosures.

FINANCIAL INSTRUMENTS, COMPREHENSIVE INCOME AND HEDGING RELATIONSHIPS

Effective January 1, 2007, the Company adopted CICA Handbook Section 1530, Comprehensive Income, Section 3251, Equity, Section 3855, Financial Instruments – Recognition and Measurement, Section 3861, Financial Instruments – Disclosure and Presentation (subsequently replaced by Sections 3862 and

3863 adopted by the Company on January 1, 2008) and Section 3865, Hedges. In accordance with the transitional provisions in these new standards, these policies were adopted retrospectively without restatement. Prior period unrealized gains and losses related to the Company’s foreign currency translation adjustments and net investment hedges are now included in accumulated other comprehensive income (AOCI). The cumulative impact of adopting these changes in 2007 was an increase to AOCI of $48 million.

FUTURE ACCOUNTING POLICIES

Business Combinations

The CICA issued Handbook Section 1582, Business Combinations, which replaces Section 1581. This new standard aligns accounting for business combinations under Canadian GAAP with IFRS. The standard requires assets and liabilities acquired in a business combination to be measured at fair value at the acquisition date. The standard also requires acquisition-related costs, such as advisory or legal fees, incurred to effect a business combination to be expensed in the period in which they are incurred. The adoption of this standard will impact the accounting treatment of future business combinations. The revised standard is effective for business combinations occurring on or after January 1, 2011; however, earlier application is permitted.

Consolidated Financial Statements and Non-Controlling Interests

The CICA issued Handbook Sections 1601, Consolidated Financial Statements and 1602, Non-controlling Interests, which together replace the former consolidated financial statements standard. Under the revised standards, non-controlling interests will be classified as a component of equity, and earnings and comprehensive income will be attributed to both the parent and non-controlling interest. The adoption of these standards is not expected to have a material impact to the Company’s consolidated financial statements. The revised standards are effective January 1, 2011. Should the Company early adopt Section 1582, it would also be required to adopt Sections 1601 and 1602 at the same time.

International Financial Reporting Standards

The Canadian Accounting Standards Board (AcSB) confirmed in February 2008 that publicly accountable entities will be required to adopt IFRS for interim and annual financial statements beginning on January 1, 2011, including comparative financial statements for 2010.

Enbridge’s preparations for IFRS conversion include preparing IFRS compliant accounting policies, drafting model IFRS financial disclosures, identifying accounting differences, developing and implementing systems solutions and process changes that support the preparation of 2010 comparative data as well as a sustainable conversion to IFRS in 2011.

The Audit, Finance and Risk Committee of the Board of Directors receives regular reports on the advancement of the conversion to IFRS.

Accounting and Reporting

To date, detailed IFRS compliant accounting policies and model financial statement disclosures are complete. The Company’s IFRS compliant accounting policies differ in some regards from the Company’s current accounting policies. The most significant differences are expected to impact the following areas:

· property, plant and equipment

· decommissioning liabilities (asset retirement obligations)

· impairments

· consolidation

The Company is carefully monitoring the International Accounting Standards Board’s (IASB) project on Rate Regulated Activities. The IASB’s exposure draft on Rate Regulated Activities, published in July 2009, would allow the Company to continue to apply rate regulated accounting with some changes. It is not possible to determine with certainty the extent of the changes to the Company’s accounting for rate regulated activities until the final standard is available.

The IASB’s project on joint ventures proposes to eliminate the proportionate consolidation of joint ventures. If the project proceeds as proposed, the Company would apply equity accounting to its joint venture interests under IFRS instead of proportionate consolidation. A final standard is expected to be published during the first quarter of 2010 after which the Company will be able to determine the impact of conversion to IFRS on its accounting for joint ventures.

The Company has selected IFRS 1 elective exemptions which are practical and provide the most relevant presentation on conversion to IFRS. The primary result of the exemptions selected is to apply certain IFRS differences prospectively, minimizing adjustments to the IFRS opening balance sheet. The Company also expects to elect to reduce cumulative translation differences to zero on the date of adoption. This change would impact the Company’s retained earnings and AOCI balances, both within the equity section of the balance sheet. In addition, the IASB’s exposure draft on Rate Regulated Activities includes an IFRS 1 exemption which would allow the Company to use the carrying amount of rate regulated property, plant and equipment, as calculated under Canadian GAAP, as the deemed cost for IFRS on the date of adoption. This would reduce changes to property, plant and equipment on adoption and, if it’s available, the Company expects to use this exemption.

Information Systems and Business Processes

In January 2010, the Company implemented changes to information systems and processes which ensure that data needed for IFRS reporting of 2010 financial information for comparative purposes is gathered. The Company has also developed processes to derive the 2010 opening balance sheet under IFRS and is building processes and systems solutions to create 2010 IFRS compliant quarterly financial information for comparative purposes.

During the first quarter of 2010, the Company will determine the systems solution which will be implemented in 2011 to support and sustain IFRS changes after conversion. Process changes needed to sustain IFRS conversion starting in 2011 have been identified, and during 2010, process design and training is expected to be completed. Related impacts to internal controls over financial reporting and disclosure controls and procedures are expected to be identified during 2010.

Training and Communication

The Company has a comprehensive plan to train internal personnel who will be impacted by the conversion to IFRS. Training started during 2009 and is expected to continue throughout 2010. The Company has also commenced preparation of an external communication plan which will depend on the nature and magnitude of changes to the financial statements expected under IFRS.

Business Activities

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

The expected timing of key activities identified above may change prior to the IFRS conversion date due to changes in regulation, economic conditions or other factors and the issuance of new accounting standards or amendments to existing accounting standards, including and in addition to those noted above.

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, 2009, 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

NON-GAAP RECONCILIATIONS

(millions of Canadian dollars)	2009	2008	2007
GAAP earnings as reported	1,555	1,321	700
Significant after-tax non-recurring or non-operating factors and variances:
Liquids Pipelines
Enbridge System - impact of tax changes	-	-	(1)
Enbridge Regional Oil Sands System - leak remediation costs	9	-	-
Feeder Pipelines and Other - asset impairment loss	-	4	-
Natural Gas Delivery and Services
EGD - colder weather than normal	(17)	(23)	(14)
EGD - interest accrual on GST refund	(7)	-	-
EGD - provision for one-time charges	-	3	-
EGD - impact of tax changes	(21)	-	(20)
Noverco - impact of tax changes	(6)	-	(7)
Offshore - property insurance recovery from hurricanes, net of costs incurred	(4)	-	(5)
Alliance Pipeline US - shipper claim settlement	-	(2)	-
Aux Sable - unrealized derivative fair value (gains)/losses	36	(56)	28
Aux Sable - loan forgiveness gain	(7)	-	-
Energy Services - unrealized derivative fair value (gains)/losses	(3)	(23)	3
Energy Services - SemGroup and Lehman credit loss/(recovery)	(1)	6	-
International - gain on sale of investments in OCENSA and CLH	(329)	(556)	(5)
Other - asset impairment loss	10	-	-
Other - adoption of new accounting standard	3	-	-
Other - gain on sale of investment in Inuvik Gas	-	(5)	-
Sponsored Investments
EEP - unrealized derivative fair value (gains)/losses	2	(6)	6
EEP - asset impairment loss	12	-	-
EEP - Lakehead System billing correction	(4)	-	-
EEP - dilution gain on Class A unit issuance	-	(5)	(12)
EEP - gain on sale of KPC	-	-	(3)
EEP - impact of 2008 hurricanes and project write-offs	-	2	-
EIF - Alliance Canada shipper claim settlement	-	(1)	-
EIF - impact of tax changes	-	-	(2)
Corporate
Unrealized derivative fair value gains	(207)	(26)	-
Unrealized foreign exchange gains on translation of intercompany balances, net	(133)	-	-
Gain on sale of investment in NTP	(25)	-	-
Impact of tax rate changes	(8)	-	(31)
Gain on sale of corporate aircraft	-	(5)	-
U.S. pipeline tax decision	-	32	-
Asset impairment loss	-	17	-
Adjusted Earnings	855	677	637