Exhibit 99.7

** **

****

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

**ENBRIDGE INC.**

 

# **MANAGEMENT’S DISCUSSION AND ANALYSIS**

#  

# **December 31, 2009**

 

----

 

**MANAGEMENT’SDISCUSSION AND ANALYSIS**

 

ThisManagement’s Discussion and Analysis (MD&A) dated February 18, 2010should be read in conjunction with the audited consolidated financialstatements and notes thereto of Enbridge Inc. (Enbridge or the Company) for theyear ended December 31, 2009, which are prepared in accordance withCanadian generally accepted accounting principles (GAAP). All financial measurespresented in this MD&A are expressed in Canadian dollars, unless otherwiseindicated. Additional information related to the Company, including its AnnualInformation Form, is available on SEDAR at www.sedar.com.

 

## **OVERVIEW**

Enbridge is a NorthAmerican leader in delivering energy. As a transporter of energy, Enbridgeoperates, in Canada and the United States, the world’s longest crude oil andliquids transportation system. The Company also has a significant involvementin the natural gas transmission and midstream businesses. As a distributor ofenergy, Enbridge owns and operates Canada’s largest natural gas distributioncompany and provides distribution services in Ontario, Quebec, New Brunswickand New York State. As a clean energy generator, Enbridge is expanding itsinterests in renewable and green energy technologies, including wind and solarenergy, and hybrid fuel cells. Enbridge employs approximately 6,000 people,primarily in Canada and the United States.

 

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

 

**LIQUIDSPIPELINES**

Liquids Pipelinesincludes the operation and construction of the Enbridge crude oil mainline systemand feeder pipelines that transport crude oil and other liquid hydrocarbons. LiquidsPipelines consists of crude oil, natural gas liquids (NGLs) and refinedproducts pipelines and terminals in Canada and the United States.

 

**NATURAL GAS DELIVERY AND SERVICES**

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

 

The core of the Company’s natural gas utilityoperations is Enbridge Gas Distribution Inc. (EGD) which serves residential,commercial, industrial and transportation customers, primarily in central andeastern Ontario as well as northern New York State. This business segment alsoincludes natural gas distribution activities in Quebec and New Brunswick.

 

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

 

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

 

The commodity marketing businesses manage theCompany’s volume commitments on Alliance and Vector Pipelines, as well as performcommodity storage, transport and supply management services, as principal andagent.

 

**SPONSORED INVESTMENTS**

Sponsored Investments includes the Company’s 27%ownership interest in Enbridge Energy Partners, L.P. (EEP), Enbridge’s fundingof 66.7% of the United States segment of the Alberta Clipper Project throughEEP and Enbridge Energy, L.P. (EELP) and a 72% economic interest (41.9% votinginterest) in Enbridge Income Fund (EIF). Enbridge manages the day-to-dayoperations and develops and assesses opportunities for each of theseinvestments, including both organic growth and acquisition opportunities.

 

 

2

----

 

EEP transportscrude oil and other liquid hydrocarbons through common carrier and feederpipelines and transports, gathers, processes and markets natural gas and NGLs.EIF is a publicly traded income fund whose primary operations include a crudeoil and liquids pipeline and gathering system, a 50% interest in the Canadianportion of Alliance Pipeline (Alliance Pipeline Canada) and partial interestsin several green energy investments.

 

**CORPORATE**

Corporate consists of new businessdevelopment activities as well as investing and financing activities, includinggeneral corporate investments and financing costs not allocated to the businesssegments. Corporate also includes the Company’s investments in green energyprojects.

 

**PERFORMANCEOVERVIEW**

 
| * *                                                    | ** ** | 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 Earnings****1**                                  |       |                                  |       |                          |   |   |   |   |   |   |   |
| 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                  Adjustedearnings and adjusted earnings per common share are non-GAAP measures that donot have any standardized meaning prescribed by GAAP. For more information onnon-GAAP measures see pages 7 and 66.

 

 

3

----

 

**EARNINGS APPLICABLE TO COMMONSHAREHOLDERS**

Earnings applicable to commonshareholders for the three months ended December 31, 2009 were $300million, 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 endedDecember 31, 2008. The increase primarily resulted from allowance forequity funds used during construction (AEDC) in Liquids Pipelines and EELP,within Sponsored Investments, as well as a higher contribution from EEP, alsowithin Sponsored Investments. Other factors contributing to the increaseinclude favourable tax rate changes and net unrealized fair value gains onderivative financial instruments used to risk manage foreign exchangevariability. These earnings increases were partially offset by decreasedearnings from Aux Sable due to unrealized derivative fair value losses of $25million recognized in the fourth quarter of 2009 compared with similar gains of$35 million recognized in the fourth quarter 2008.

 

Earnings applicable to commonshareholders 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 commonshare, for the year ended December 31, 2008. Included in earnings for theyear ended December 31, 2009 was a $329 million gain related to the saleof the Company’s investment in OleoductoCentral S.A (OCENSA) and a $25 milliongain related to the sale of NetThruPut (NTP). Earnings for the year endedDecember 31, 2008 included a gain of $556 million related to the sale ofthe Company’s investment in Compañía Logística de Hidrocarburos CLH,S.A. (CLH). Excluding the impact of these dispositions, earnings for the yearended December 31, 2009 were $436 million higher than for the year endedDecember 31, 2008. The increase in earnings resulted from similar factorsas for the three months results as well as unrealized foreign exchange gains onthe translation of foreign-denominated intercompany loans.

 

Earnings applicable to commonshareholders were $1,321 million for the year ended December 31, 2008,compared with $700 million for the year ended December 31, 2007. Theincrease in earnings resulted from AEDC in Liquids Pipelines, a highercontribution from EGD and unrealized fair value gains on derivative financialinstruments in Aux Sable, Energy Services and Corporate, partially offset bydecreased earnings from International as the Company sold its interest in CLHin 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 bythe recognition of a $32 million income tax charge as a result of anunfavourable court decision related to previously owned United States pipelineassets.

 

**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 endedDecember 31, 2008. Adjusted earnings were $855 million, or $2.35 percommon share, for the year ended December 31, 2009, compared with $677million, or $1.88 per common share, for the year ended December 31, 2008.

 

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

 

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

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

·                  Increasedadjusted earnings from Enbridge Offshore Pipelines (Offshore) due to highervolumes and a more favourable exchange rate.

·                  Increasedadjusted earnings from Energy Services due to higher volumes and the impact ofrealizing favourable storage and transportation margins.

 

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

 

Adjusted earnings for the year endedDecember 31, 2008 were $677 million, or $1.88 per common share, comparedwith $637 million, or $1.79 per common share, for the year endedDecember 31, 2007. The $40 million, or $0.09 per common share, increasewas primarily a result of:

 

 

4

----

 

·                  Newfacilities within Liquids Pipelines as well as AEDC on Southern Lights Pipelineand, within Enbridge System, on both Southern Access Mainline Expansion andAlberta Clipper Project.

·                  IncreasedAux Sable adjusted earnings due to strong fractionation margins.

·                  Higherincentive income and increased earnings at EEP primarily due to higher gas andcrude oil delivery volumes, tariff surcharges for recent expansions and agreater ownership interest following an additional subscription of Class Aunits in December 2008.

·                  Improvedearnings in Energy Services resulting from market conditions which enabledhigher margins to be captured on storage and transportation contracts as wellas increased transportation and storage volumes.

 

These significant operating factorsthat increased 2008 adjusted earnings were partially offset by decreasedearnings from International as a result of the sale of CLH in the secondquarter of 2008 and lost revenue from Offshore as a result of Hurricanes Gustavand Ike.

 

**CASH FLOWS**

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

 

For the three months endedDecember 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 declinein additions to property, plant and equipment in the fourth quarter of 2009compared 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, SpearheadPipeline Expansion and Hardisty Terminal projects.

 

**DIVIDENDS**

The Company has paid, andconsistently increased, common share dividends since its public inception in1953. Based on estimated 2010 dividends, the annual rate of increase hasaveraged 10.3% since 2000 and 10.0% since inception. In December 2009, theCompany announced a 15% increase in its quarterly dividend to $0.425 per commonshare, or $1.70 annualized, effective March 1, 2010. The Company’sdividend payout policy and ratio reflects a strong and stable long-term outlookfor its business. The Company continues to target a pay out of approximately60% to 70% of adjusted earnings as dividends and, with the most recent dividendincrease, the 2010 pay out is expected to be near the midpoint of the range. In2009, dividends paid per share were 63% of adjusted earnings per share (2008 - 70%, 2007 - 69%).

 

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

 

 

 

5

----

 

**REVENUES**

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

 

Commodity sales revenue is earned through the Company’snatural gas distribution and energy marketing activities and is subject to fluctuationsin commodity prices. While revenues generated by the natural gas distributionbusiness vary with the price of natural gas, earnings remain neutral due to thepass through nature of these costs. Similarly, the impact of commodity priceson revenues derived from the Company’s energy marketing activities do notdirectly impact earnings since commodity prices also affect input costsassociated with such activities. Commodity sales revenue for the year endedDecember 31, 2009 totaled $9,720 million compared with $13,432 million forthe year ended December 31, 2008 and $9,536 for the year endedDecember 31, 2007. Commodity sales revenue totaled $2,491 million in thefourth quarter of 2009, a 20% decline from the fourth quarter of 2008. Similartrends were experienced in commodity costs over these same periods. Theperiod-over-period variances are primarily driven by natural gas and crude oilcommodity prices, both of which increased notably in 2008 over 2007, only toexperience subsequent declines in 2009 amidst global economic uncertainty.

 

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

 

·                  Increasedcontributions from Liquids Pipelines growth projects that entered service in2009, including the Line 4 Extension, Spearhead Expansion, LSr Pipeline(constructed in conjunction with the Southern Lights Pipeline Project) andHardisty Terminal projects.

·                  Full yearcontributions from Waupisoo Pipeline and Ontario Wind Project that enteredservice at various stages throughout 2008.

·                  Completion of theShenzi Lateral project within Offshore in April 2009.

·                  Unfavourablevariances in realized and unrealized gains and losses on derivative instrumentsused to manage natural gas processing margins in Aux Sable.

 

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

 

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

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

·                  Natural GasDelivery and Services transportation revenue included higher Alliance PipelineUS tolls, the impact of Vector Pipeline expansion and revenues from Neptunewithin Offshore.

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

 

**FORWARD-LOOKINGINFORMATION**

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

 

 

6

----

 

*projects under construction; expectedin-service dates for projects under construction; expected capitalexpenditures; and estimated future dividends.*

 

*Although Enbridge believes that theseforward-looking statements are reasonable based on the information available onthe date such statements are made and processes used to prepare theinformation, such statements are not guarantees of future performance andreaders are cautioned against placing undue reliance on forward-lookingstatements. By their nature, these statements involve a variety of assumptions,known and unknown risks and uncertainties and other factors, which may causeactual results, levels of activity and achievements to differ materially fromthose expressed or implied by such statements. Material assumptions includeassumptions about: the expected supply and demand for crude oil, natural gasand natural gas liquids; prices of crude oil, natural gas and natural gasliquids; expected exchange rates; inflation; interest rates; the availabilityand price of labour and pipeline construction materials; operationalreliability; customer project approvals; maintenance of support and regulatoryapprovals for the Company’s projects; anticipated in-service dates; andweather. Assumptions regarding the expected supply and demand of crude oil,natural gas and natural gas liquids, and the prices of these commodities, arematerial to and underlay all forward-looking statements. These factors arerelevant to all forward-looking statements as they may impact current andfuture levels of demand for the Company’s services. Similarly, exchange rates,inflation and interest rates impact the economies and business environments inwhich the Company operates, may impact levels of demand for the Company’sservices and cost of inputs, and are therefore inherent in all forward-lookingstatements. Due to the interdependencies and correlation of these macroeconomicfactors, the impact of any one assumption on a forward-looking statement cannotbe determined with certainty, particularly with respect to expected earnings oradjusted earnings and associated per share amounts, or estimated futuredividends.  The most relevant assumptionsassociated with forward-looking statements on projects under construction,including estimated in-service dates, and expected capital expendituresinclude: the availability and price of labour and pipeline constructionmaterials; the effects of inflation and foreign exchange rates on labour andmaterial costs; the effects of interest rates on borrowing costs; and theimpact of weather and customer and regulatory approvals on constructionschedules.*

 

*Enbridge’s forward-looking statements aresubject to risks and uncertainties pertaining to operating performance,regulatory parameters, project approval and support, weather, economic andcompetitive conditions, exchange rates, interest rates, commodity prices andsupply and demand for commodities, including but not limited to those risks anduncertainties discussed in this MD&A and in the Company’s other filingswith Canadian and United States securities regulators. The impact of any onerisk, uncertainty or factor on a particular forward-looking statement is notdeterminable with certainty as these are interdependent and Enbridge’s futurecourse of action depends on management’s assessment of all informationavailable at the relevant time. Except to the extent required by law, Enbridgeassumes no obligation to publicly update or revise any forward-lookingstatements made in this MD&A or otherwise, whether as a result of newinformation, future events or otherwise. All subsequent forward lookingstatements, whether written or oral, attributable to Enbridge or persons actingon the Company’s behalf, are expressly qualified in their entirety by thesecautionary statements.*

 

**NON-GAAP MEASURES**

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

 

 

7

----

 

**CORPORATE VISIONAND KEY OBJECTIVE**

 

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

 

**CORPORATE STRATEGY**

 

Insupport of its long-term vision, the Company employs several key strategiesthat guide decision making across the enterprise. The Company’s strategiesfocus on:

 

·                  leveraging the strategic location ofits existing asset base;

·                  developing new platforms for growthand diversification;

·                  focusing on execution and operatingexcellence;

·                  maintaining financial strength andflexibility; and

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

 

Enbridge’sstrategy is reviewed annually with direction from its Board of Directors. TheCompany continually assesses ways to generate value for shareholders, includingreviewing opportunities that may lead to acquisitions, dispositions or otherstrategic transactions, some of which may be material. Opportunities arescreened, analyzed and must meet operating, strategic and financial benchmarksbefore being pursued.

 

**STRENGTHENING OUR CORE BUSINESS**

TheCompany has an established history of serving the North American transportationneeds of key crude oil and natural gas markets. The Company is focused onadding value for customers and improving customers’ profitability. This focushas aligned the Company with its customers and relevant supply and demandfundamentals and has consistently formed a basis for the Company’s strategy.However, evolving supply and demand fundamentals and growing competition areserving to create new opportunities and challenges within the Company’s corebusinesses. Amid this changing business environment, the Company isstrengthening its core business position and aggressively pursuing newopportunities to expand and extend its current asset base.

 

Extendingthe reach of the current asset base is a multi-faceted objective. Keystrategies within the Liquids Pipelines segment include regional pipelinedevelopment, gathering system and storage infrastructure expansion and newmarket access. Regional pipeline development primarily includes projects whichconnect new oil sands lease production to existing hubs upstream of theCanadian mainline. The commercial agreement and ongoing development activityrelated to the Woodland Pipeline represents a recent success in realizing thisobjective. The Company is working with several other oil sands customers indeveloping further transportation options for other projects in the oil sandsregion of northern Alberta. The Company is also expanding its gathering systemsin Saskatchewan and North Dakota which are strategically located to captureincreased production from the Bakken play. As transportation needs grow so toodo terminal and storage infrastructure requirements throughout the network, andthe Company’s strategy will seek opportunities to provide additional capacityin the Fort McMurray and Hardisty, Alberta regions as well as in the Cushing,Oklahoma area. The Company continues to pursue opportunities to provide itscustomers broader market access for Canadian bitumen and synthetic crudes andprovide new sources of supply for refiners. These efforts include leveragingexisting pipeline networks into additional United States markets as well asdeveloping the proposed Northern Gateway pipeline to provide access to marketsoff the Pacific Coast of Canada.

 

 

8

----

 

Thefundamentals of the natural gas market in North America have been significantlyaltered in recent years with the emergence of unconventional shale gas plays.The Company’s natural gas strategy includes expanding its footprint in theseemerging areas. Alliance Pipeline is well positioned to service the Montneyplay in northeast British Columbia and is currently evaluating opportunities toexpand its service offerings in that area. Growth in the Haynesville shale innorthwest Louisiana will lend additional support to the Company’s proposedLaCrosse Pipeline. In addition to these onshore strategies, the Companycontinues to pursue and win natural gas gathering expansion opportunities forultra-deep projects in the Gulf of Mexico which improve the risk and returnprofile of its investment in this area.

 

**DEVELOPING NEW PLATFORMS FOR GROWTH AND DIVERSIFICATION**

Thedevelopment of new platforms to diversify and sustain long-term growth is animportant strategy for Enbridge. Renewable energy is a significant source ofpotential new growth as government initiatives and changing social beliefs arecreating new opportunities to deliver green energy solutions with risk andreturn characteristics consistent with Enbridge’s low-risk business model.Renewable energy projects can deliver stable cash flows and attractive returnsthough the use of long-term power purchase agreements and fixed priceengineering, procurement and construction contracts. Renewable energy is alsoan 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 cleanpower projects, including wind, solar, waste heat recovery and fuel cellinitiatives.

 

Similarto renewable energy, carbon dioxide (CO2) capture andsequestration not only supports Enbridge’s social investment strategy but alsorepresents a potentially significant investment opportunity, should the technologyprove viable.

 

TheCompany’s Pathfinding group will also continue to explore other longer-termenergy technologies and facilitate innovations to assist its customers andsustain its favorable position.

 

**FOCUSING ON EXECUTION AND OPERATIONS**

Effectiveproject execution and management of operations is a critical component ofEnbridge’s strategic plan. Operational excellence is particularly critical inan environment where customers have become increasingly cost conscious,competition in the Company’s core business has intensified and environmentalstewardship has heightened.

 

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

 

Costefficiency and operating performance is becoming an increasing driver of valuein a deregulated world with increased competition. Under the incentive programsin place in certain of the Company’s business units, rates and tolls, as wellas the Company’s earnings, depend on cost and operating performance. Returns inthe Company’s natural gas gathering and processing business are also directlyimpacted by operating costs. Key initiatives within the business units tomanage costs include: upgrading management information and reporting systems;rigorous cost tracking performance against relevant benchmarks; and implementingbest practice procurement strategies and enhanced “change management” processesto ensure anticipated savings are realized from new programs.

 

Superiorservice, safety and reliability are integral to Enbridge’s customer valueproposition. As always, cost management initiatives are balanced with the safeand reliable operation of the Company’s system and the need to ensure ongoingcustomer satisfaction. Throughout the organization, the Company is placingincreased emphasis on understanding customers and their decision processes, andon regular 

 

 

9

----

 

measurementand management of service quality.

 

Withrespect to safety, Enbridge strives to employ the best available practices andtechnologies for integrity management, systems maintenance and operations inorder to mitigate risks to the public, our employees and the environment.

 

**PRESERVING FINANCIAL STRENGTH AND FLEXIBILITY**

Disciplinedcapital management is a fundamental and company differentiating characteristic.As an asset-intensive business, Enbridge creates value for its investorsthrough maximizing the spread between its return on invested capital and itscost of funds. Enbridge’s financial strategies ensure the Company hassufficient liquidity to meet its capital requirements. To support thisobjective, the Company develops financing plans and strategies to maintain andimprove Enbridge’s credit ratings, diversify its funding sources and maintainready access to capital markets in both Canada and the United States.

 

Akey tenet of the Company’s low-risk business model is mitigation of exposure tocertain market price risks. As a result, the Company has developed a robustrisk management process which ensures earnings volatility from manageable riskremains contained within the Company’s approved guideline of 5% of adjustedearnings. Enbridge will continue to proactively hedge interest rate, foreignexchange and commodity price exposures. As well, the continued management ofcounterparty credit risk remains an ongoing priority.

 

**ENVIRONMENTAL STEWARDSHIP AND CORPORATE SOCIAL RESPONSIBILITY**

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

 

In2009, the Company launched an enterprise-wide goal of achieving a neutralenvironmental footprint by 2015. The goal consists of three key commitments:

 

·                  we will conserve an acre of naturalor wilderness land for every acre we permanently impact from the constructionof new facilities;

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

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

 

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

 

Enbridge’scommunity investments are also noteworthy. The Company launched three majorcommunity investment initiatives in 2009. School Plus, in partnership with the Assembly of First Nations,provides financial support to enrichment programming and extra-curricularactivities in First Nations schools near major Enbridge rights of way; the Safe Community program serves to confirmthe priority Enbridge places on health and safety in our right-of-waycommunities, by directly and visibly supporting those right-of-wayorganizations who would respond to an emergency on one or more of our lines orat one of our facilities; and, the NaturalLegacy program focuses on tree planting and specific environmentalinitiatives in communities in proximity to our major rights of way.

 

Tocomplement community investments in its Canadian and United States operatingareas, Enbridge will also exercise leadership in extending the benefits ofenergy availability to underdeveloped countries. In 2009, Enbridge launched theenergy4everyone Foundation, which has applied to the Canadian Revenue 

 

 

10

----

 

Agencyfor charitable status, with a vision of empowering people and communities toimprove their own lives by providing energy to everyone. The Foundation aims toleverage the expertise and resources of the Canadian energy industry to affectsignificant enhancement in quality of life through the delivery and deploymentof affordable, reliable and sustainable energy services and technologies tocommunities in need around the world.

 

#### **INDUSTRYFUNDAMENTALS**

#### ** **

#### **SUPPLY AND DEMAND FOR LIQUIDS**

North American liquids infrastructure fundamentals remainfavourable for the foreseeable future. The United States continues to bereliant on imported crude oil to satisfy its needs. Western Canada hassurpassed both Mexico and Saudi Arabia to become the largest crude oil exporterto the United States. Canada’s oil sands, one of the largest oil reserves inthe world, are becoming an increasingly prominent source of supply. Combinedconventional and oil sands established reserves of approximately 174 billionbarrels compare with Saudi Arabia’s proved reserves of approximately 260billion barrels. The National Energy Board (NEB) estimates that total WesternCanadian Sedimentary Basin (WCSB) production averaged approximately 2.5 millionbarrels 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 alsodistant from market, and some of the shale plays like the Bakken in themidcontinent.

 

In connection with the global economic downturn, crude oilprice weakness and volatility caused some crude oil producers to defer projectsthat were planned to commence over the next decade. More recently, improvedmacroeconomic conditions, higher oil prices and reduced development costs havespurred 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 priorforecasts. The Canadian Association of Petroleum Producers’ (CAPP)June 2009 growth case estimates indicate that future WCSB production isexpected to steadily increase to more than 3.6 million bpd by 2019. Thisforecasted growth of 1.1 million bpd is attributed to increased oil sandsproduction in Alberta.

 

While global demand for crude oil is expected to resume itsgrowth trajectory given the strength in emerging regions, North American demandfor 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 bythe recent economic downturn and the emergence of biofuels. Refining economicshave materially weakened over this period, contributing to the recentannouncements of a variety of marginal refinery closures. Most of theseclosures are in regions that are not served by Enbridge infrastructure. Othermore profitable refineries are growing and have reconfiguration projects underconstruction. Some of these refineries currently process Canadian crude andsome are preparing to. Accordingly, there remain meaningful growthopportunities for Canadian crude oil into existing and new markets in theUnited States.

 

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

 

#### **SUPPLY ANDDEMAND FOR NATURAL GAS**

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

 

 

11

----

 

market demand.

 

Since the 1990s, production in theRocky Mountain region of the United States, primarily from tight shale gas, hasmore than doubled to approximately 9 billion cubic feet per day (bcf/d). Thisamount of growth will likely repeat over the next 12 to 15 years. Establishedshale plays in the Midcontinent region such as the Barnett, Fayetteville andWoodford, along with emerging plays such as Haynesville in northwest Louisianaand Marcellus in Appalachia, have now become the continental gas developmenthotspots. After seeing a decline in drilling rig activity in some of theseplays in the summer of 2009, activity in these regions has increased in recentmonths with the prospect of higher future prices. This increased drilling couldcontribute significantly to supply in 2010, extending the natural gas priceweakness seen in 2009.

 

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

 

North American natural gas demandcontracted in 2009 as a direct impact of the recession. Industrial demandweakened the most while low gas prices led to gas for coal substitution inpower generation, supporting gas demand in that sector. Following theanticipated economic recovery, natural gas demand is expected to grow in allsectors but gas-fired generation may lead the group as natural gas is expectedto be a preferred fuel in an increasingly carbon-conscious marketplace. Whilegas fired generation growth will occur, it will be restricted for the nextseveral years as coal projects already under construction enter service andmore renewable power projects come on line.

 

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

 

Global LNG production is ramping upwith several projects under construction. In the near term, LNG supply fromthese new projects will be seeking markets during a global recession. NorthAmerican 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 suppliesare anticipated to be positive news for North American gas markets and arelikely to lead to renewed interest in natural gas as an economically priced,clean burning fuel.

 

**GROWTH PROJECTS**

 

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

 

Thefollowing table summarizes commercially secured projects, within each of theCompany’s business segments, which were recently completed, or are currentlyunder active development or construction. These growth projects contribute toanticipated annual earnings per share growth rates expected to average 10% through2013, with the inventory of projects under development expected to sustain thisgrowth rate into the second half of the decade. 

 

 

12

----

 
| *(in billions of  Canadian dollars, unless stated  otherwise)* | **Actual /  Estimated  Capital Cost****1**                             | **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 toupward or downward adjustment based on various factors.

 

Risks relatedto the development and completion of growth projects are described under RISKMANAGEMENT.

 

 

13

----

 

 

 

14

----

** **

**LIQUIDS PIPELINES**

** **

**Southern Access Mainline ExpansionProject**

The Southern Access Mainline Expansion Project iscomplete, with only some restoration work remaining. It has added a total of400,000 bpd incremental capacity to the mainline system. Construction of thesecond and final stage of the United States expansion project, which consistedof a new 224-kilometre (139-mile), 42-inch pipeline from Delavan, Wisconsin toFlanagan, Illinois, was completed on schedule in the first quarter of 2009. Thepipeline was placed into service and the associated toll surcharge took effecton April 1, 2009. In Canada, upgrades at 18 pump stations to improve pumpingeffectiveness were completed in early 2009. The Company started collectingassociated tolls in April 2008 on stage 1 facilities placed in-service.

 

The total cost of the project decreased toapproximately US$2.3 billion (Enbridge - $0.2 billion, EEP - US$2.1 billion).The estimated capital cost for the Canadian portion was revised from $0.3billion 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 ClipperProject.

 

The Southern Access Expansion Project is an expansionof the mainline system. The cost of the project is recovered through tolls inCanada and the United States. A toll surcharge mechanism has been negotiatedwith shippers and approved by regulators to recover the costs of this expansionincluding a return on and of the capital investment. The recovery of costs andreturns is independent of throughput.

 

**Spearhead Pipeline Expansion**

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

 

**Sale of Spearhead North Pipeline**

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

 

**Line 4 Extension Project**

The $0.3 billion Line 4 Extension Project wassubstantially complete and ready to receive linefill at the end of March 2009,and associated tolls were collected starting April 1, 2009. Final restorationwork was completed in the summer of 2009. The project expanded capacity fromEdmonton to Hardisty by 880,600 bpd. Similar to the Southern Access and AlbertaClipper projects, the Line 4 project costs are recovered through surcharges onmainline 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 tanksin service, the $0.6 billion Hardisty Contract Terminal is one of the largestcrude oil terminals in North America. Remaining seasonal and restoration workis expected to be completed in early 2010.

 

**Alberta Clipper Project**

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

 

 

15

----

 

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

 

Construction on the Canadian segment of the line wasmechanically completed in December 2009, and remains on schedule for anexpected in-service date of April 1, 2010. This segment has an estimated costof $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 italso remains on schedule to be ready for service by April 1, 2010. The cost ofthe United States segment is estimated at US$1.3 billion, with expenditures todate totaling US$0.9 billion. As announced in July 2009, Enbridge has committedto fund 66.7% of the United States segment of the Alberta Clipper projectthrough EELP. Similar to the Southern Access project, the costs of the AlbertaClipper Project are recovered through surcharges on mainline tolls in bothCanada and the United States.

 

For both the Canadian and United States segments ofthe Alberta Clipper Project, tariffs will be filed with the appropriateregulators to be effective on April 1, 2010, the date the project is expected tobe ready for service. The tariff for the United States segment, and itseffective date, will be filed on the basis of the Alberta Clipper US TermSheet, despite a petition filed in January 2010 by a shipper requesting the FederalEnergy Regulatory Commission (FERC) to delay the tariff. Following thatpetition filing, several shippers filed interventions requesting to be part ofthe 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 tothe shipper petition, which we believe to be without merit.

 

**Southern Lights Pipeline**

When completed, in the second half of 2010, the180,000 bpd Southern Lights Pipeline will transport diluent from Chicago,Illinois to Edmonton, Alberta. The project involves reversing the flow of aportion of Enbridge’s Line 13, an existing crude oil pipeline which runs fromEdmonton to Clearbrook, Minnesota. In order to replace the light crude capacitythat would be lost through the reversal of Line 13, the Southern Lights Projectalso includes the construction of a new 20-inch diameter light sour crude oilpipeline (LSr Pipeline) from Cromer, Manitoba to Clearbrook, and modificationsto existing Line 2. These changes to the existing crude oil system increasedsouthbound light crude system capacity by approximately 45,000 bpd. Thecapacity replacement will permit Line 13 to be taken out of service andreversed for diluent service. The LSr Pipeline and Line 2 modifications, whichallow Line 2 to operate at higher design rates, were completed and placed in servicein the first quarter of 2009.

 

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

 

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

 

**Line 13 Exchange**

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

 

**Woodland Pipeline**

In June2009, Enbridge entered into an agreement with Imperial Oil Resources VenturesLimited (Imperial Oil) and ExxonMobil Canada Properties (ExxonMobil) to providefor the transportation of blended bitumen from the Kearl oil sands mine tocrude oil hubs in the Edmonton, Alberta area. The project will be phased withthe mine expansion, with the first phase involving construction of a new36-inch diameter pipeline from

 

 

16

----

 

themine to the Cheecham Terminal, and service on Enbridge’s existing WaupisooPipeline from Cheecham to the Edmonton area. The new pipeline, to be called theWoodland Pipeline, will be extended from Cheecham to Edmonton in conjunctionwith the second phase of the Kearl project. The Woodland Pipeline is beingundertaken as a joint venture between Enbridge, Imperial Oil and ExxonMobil.Enbridge filed regulatory applications for Phase I facilities at the end of2009 and expects the pipeline will come into service in late 2012. The totalestimated cost of the pipeline from the mine to the Cheecham Terminal andrelated facilities is $0.5 billion, but is subject to finalization based onscope, detailed engineering and regulatory approvals.

 

**Fort Hills Pipeline System**

In November 2007, Enbridge was selected by Fort HillsEnergy L.P. (FHELP) as its pipeline and terminaling services provider for theinitial phase of the Fort Hills project and all subsequent expansions. In late2008, FHELP announced that its final investment decision for the mining portionof the project was being deferred until costs could be reduced, and commodityprices and financial markets strengthened. It also announced that the FortHills upgrader was put on hold and that a decision to proceed with the upgraderwould be made at a later date. Accordingly, the scope of the Fort HillsPipeline System is being reevaluated by FHELP and the planned in-service datefor 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 thepipeline. Expenditures to date are approximately $0.1 billion and arecommercially recoverable from FHELP.

 

**Northern Gateway Project**

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

 

The Company hassecured $100 million funding from Western Canada producers and Pacific Rimrefiners toward the costs of seeking the necessary regulatory approvals for theproject.

 

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

 

Aboriginalconsultation and accommodation is a constitutional requirement of the Crownbased on established or asserted Aboriginal rights along the pipeline route andtanker waterway. The Canadian Environmental Assessment Agency (CEAA) isresponsible for coordinating consultation with Aboriginal groups with respectto the potential impacts of the project on Aboriginal and Treaty rights. CEAAinitially consulted with Aboriginal groups on the proposed regulatory processfor the project. A number of Aboriginal groups made submission that theproposed consultation process did not meet the Crown’s consultation obligationsand a separate Aboriginal review process was required for the project. Thefederal government did not accept these submissions and established the JRPprocess as the primary mechanism for Aboriginal groups to be consulted on theimpacts of the project. The JRP process has no mandate to resolve Aboriginalland claims or issues of Aboriginal rights and title.

 

The federalgovernment has also issued a project-specific Aboriginal Consultation Frameworkfor Northern Gateway creating a consultation plan for the project. Funding isavailable from CEAA to assist Aboriginal groups with the costs of participatingin the JRP process and a majority of the Aboriginal groups along the corridorhave submitted applications for such funding. Nevertheless, it is anticipatedthat a number of Aboriginal groups will maintain their position that thecurrent process does not meet the Crown’s duty to consult.

 

 

17

----

 

The project is alsoundertaking its own comprehensive public consultation program, which includes aseries of community open houses and community advisory boards designed togather input, answer questions and build public awareness and understandingabout the project. The Company is committed to working with First Nations andMétis communities along the pipeline route to create opportunities for economicpartnerships and to incorporate traditional knowledge into the planning andoperations of the proposed project.

 

Notwithstandingthis commitment, certain Aboriginal groups have publicly stated theiropposition to the project and have indicated that they are considering alloptions to prevent the project. These options could include legal challenges tothe 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 projectdelay. See Aboriginal Relations.

 

Enbridge expects tofile its regulatory application with the NEB in 2010. Subject to continuedcommercial support, regulatory and other approvals, and adequately addressingAboriginal groups’ concerns, the Company estimates that Northern Gateway couldbe in-service as early as the 2016 time frame. The NEB posts public filingsrelated to Northern Gateway on its website and Enbridge also maintains aNorthern Gateway Project site in addition to information available onwww.enbridge.com. None of the information contained on, or connected to, theNEB website, the Gateway Project website or Enbridge’s website is incorporatedor otherwise part of this MD&A.

 

**NATURAL GAS DELIVERY AND SERVICES**

** **

**Shenzi Project**

Enbridge completedconstruction of a natural gas lateral to connect the new deepwater Shenzi fieldto 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, wasplaced 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) withChevron Corp. to expand its central Gulf of Mexico offshore pipeline system.Under the terms of the LOI, Enbridge will construct, own and operate the WalkerRidge Gas Gathering System (WRGGS) to provide natural gas gathering services tothe proposed Jack, St. Malo and Big Foot ultra-deepwater developments. TheWRGGS is expected to include approximately 306 kilometres (190 miles) of8-inch, 10-inch and/or 12-inch diameter pipeline at depths of up toapproximately 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 finalizationof scope and definitive cost estimates.

 

The terms ofthe LOI ensure a minimum rate of return to Enbridge with no volume risk. Ifvolumes are achieved as expected by the producer, returns would improve fromthis base level. In addition, Enbridge takes no capital cost risk on theproject.

 

**Big Foot Oil Pipeline**

On October 5, 2009,Enbridge announced it had entered into a LOI with Chevron USA, Inc., StatoilGulf of Mexico LLC and Marubeni Oil & Gas (USA) Inc. to construct andoperate a 64-kilometre (40-mile) 20-inch oil pipeline from the proposed BigFoot ultra-deepwater development in the Gulf of Mexico. This crude oil pipelineproject is complementary to Enbridge's previously announced plans to constructthe WRGGS. The estimated cost of the Big Foot Oil Pipeline, which will belocated about 274 kilometres (170 miles) south of the coast of Louisiana, isapproximately US$0.3 billion and the pipeline is expected to be in-service in2014 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 thetotal Enbridge investment for the projects to US$0.8 billion.

 

 

18

----

 

**LaCrosse Pipeline**

In May 2009, the Company conducted a successfulnon-binding open season for the proposed LaCrosse Pipeline. This project, whichis being commercially pursued, includes an interstate pipeline to transportnatural gas from EEP’s Carthage Hub in Panola County, Texas, to Washington Parishin Southeastern Louisiana. The 483-kilometre (300-mile) pipeline would have acapacity in excess of 1.0 bcf/d and would provide an outlet for increasingsupplies of natural gas originating in the East Texas and Fort Worth producingbasins and the growing Haynesville Shale play. The next stage of the projectinvolves confirming customer interest and the expected cost of the newconstruction.

 

**SPONSORED INVESTMENTS**

** **

**Enbridge Energy Partners**

**North Dakota System Expansion**

EEPundertook a further expansion of the North Dakota Pipeline System at anapproximate cost of US$0.2 billion during 2009. The expansion increased systemcapacity from 110,000 bpd to 161,000 bpd and consisted of upgrades to existingpump stations, additional tankage as well as infrastructure to facilitateextensive use of drag reducing agents that are injected into the pipeline. Thecommercial structure for this expansion is a cost-of-service based surchargethat has been added to the existing transportation rates. The related tolling surchargehas been adjusted to include costs of this phase of the expansion that becameeffective January 1, 2010. Approval for the expansion was received from theFERC in October 2008 and the expansion came into service in early 2010.

 

**Enbridge Income Fund**

**Saskatchewan System Capacity Expansion**

EIF hasfinalized the scope of Phase II of the Saskatchewan System Capacity Expansionto include three separate projects that will reduce capacity constraints at avariety of locations. Collectively, the projects will increase capacity acrossthe system by approximately 125,000 bpd at an estimated cost of approximately$0.1 billion. Construction commenced during the third quarter of 2009 and allthree 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 theeastern shore of Lake Huron in Ontario, was completed in the fourth quarter of2008, and 65 of the 115 wind turbines were operating and delivering power tothe grid by the end of 2008. During the first quarter of 2009, the remaining 50turbines were phased into service and the wind project attained full commercialoperation. The project has demonstrated near design level operational performancethrough its net capacity factor and high availability of wind turbines. Thefinal capital cost of the project is $0.5 billion.

 

**TalbotWind Energy Project**

On November19, 2009, Enbridge announced the development of the 99-MW Talbot Wind Energy Projectnear Chatham, Ontario with Renewable Energy Systems Canada Inc. (RES Canada).Enbridge will have a 90% interest in the project and an option to acquire theremaining 10% interest. RES Canada will construct the wind project under afixed price, turnkey, engineering, procurement and construction agreement. Theproject utilizes 43 Siemens 2.3-MW wind turbines and, under a multi-year fixedprice agreement, Siemens will provide operations and maintenance services forthe wind turbines. The Talbot Wind Energy project will deliver energy to theOntario Power Authority under a Renewable Energy Supply (RES) III 20-year powerpurchase agreement and is expected to be completed by December 2010 at acapital cost of $0.3 billion.

 

**SarniaSolar Project**

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

 

 

19

----

 

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

** **

**AlbertaSaline Aquifer Project**

The38-member Alberta Saline Aquifer Project (ASAP) completed Phase 1 of itsthree-phase CO2 storage project in March 2009.This phase focused on identifying saline aquifer locations in Alberta thatwould be suitable for a CO2 storage pilotproject. The costs associated with this phase were covered by ASAP participantsand a grant from the Alberta Energy Research Institute.

 

ASAP is nowworking on securing funding and a source of CO2 such that it can move on to Phase 2 of theproject. Phase 2 will involve developing the pilot project, receiving allnecessary regulatory approvals and actually injecting CO2 into the identified aquifers. The Phase 2pilot project will give the ASAP team the opportunity to test the sequestrationtechnologies 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      |       |

 

LiquidsPipelines adjusted earnings were $454 million in 2009 compared with $332million in 2008. The increase was largely due to higher earnings from EnbridgeSystem and Southern Lights Pipeline, including the impact of AEDC, partiallyoffset by higher operating costs including compensation.

 

While underconstruction, certain regulated pipelines are entitled to recognize AEDC inearnings. These amounts will contribute to earnings throughout the Company’ssignificant growth period and will be collected in tolls once the pipelines arein service. The earnings impact of AEDC for the year ended December 31, 2009was $74 million (2008 - $18 million) for Enbridge System, primarilyrelating to Alberta Clipper, and $44 million (2008 - $27 million) for SouthernLights Pipeline.

 

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

 

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

·                  Enbridge System was affected byfavorable tax rate changes in 2007.

·                  A $9 million after-tax expenseresulting from clean up and remediation costs related to a valve leak withinthe Enbridge Cheecham Terminal on the EnbridgeRegional Oil Sands System in January 2009, which is notindicative of the expected future performance of this asset.

 

 

20

----

 

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

 

###### **ENBRIDGESYSTEM**

Themainline system is comprised of Enbridge System and Lakehead System (theportion of the mainline in the United States that is operated by Enbridge andowned by EEP). Enbridge has operated, and frequently expanded, the mainlinesystem since 1949. Through six adjacent pipelines with a combined capacity ofapproximately 2 million bpd, the system transports various grades of crude oiland diluted bitumen from western Canada to the midwest region of the UnitedStates and eastern Canada. Also included within the Enbridge System and locatedin eastern Canada are two crude oil pipelines and one refined products pipelinewith a combined capacity of 0.4 million bpd. Average system utilization in 2009was 80%; however, it is expected to decrease in 2010 due to a combination ofadditional pipeline capacity being added to the system by the Company and a newpipeline being brought into service by a competitor.

 

**Incentive Tolling**

Tollson Enbridge System are governed by various agreements, which are subject to theapproval of the NEB. The NEB’sjurisdiction over the Enbridge System includes statutory authority over matterssuch as construction, rates and ratemaking agreements and other contractual arrangementswith customers. Significant agreements include the incentivetolling settlement (ITS) applicable to the Enbridge mainline system (excludingLine 8 and Line 9), the Terrace agreement, the SEP II Risk Sharing Agreementand the Southern Access Expansion Agreement which is recovered via the MainlineExpansion Toll. Tolls on the core mainline system have been governed by ITSsince 1995, with the most recent ITS term effective through 2009. Discussionsand negotiations are continuing for an extension to the ITS which will supporta competitive toll structure. The Company anticipates that a settlement will bereached in early 2010. In the event that a settlement cannot be reached, theCompany could file a cost of service application.

 

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

 

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

 

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

 

Enbridgepays taxes each year only on the tolls collected in cash; therefore the taxpayable on the TRV lags behind the recognition of the revenue. As the Terrace capacity is increasinglyutilized, there will be less TRV recorded and more cash tolls collected. Thiswill result in the Company paying taxes in future years on both the prior year’sTRV and the current year’s cash tolls.

 

**Results of Operations**

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

 

 

21

----

 

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

 

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

 

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

 

**ENBRIDGE REGIONAL OIL SANDS SYSTEM**

Enbridge Regional Oil Sands System includes two longhaul pipelines, the Athabasca Pipeline and the Waupisoo Pipeline, as well as avariety of other facilities including the MacKay River, Christina Lake, Surmontand Long Lake facilities. It also includes the Company’s interest in theHardisty Caverns Limited Partnership, which provides crude oil tankage service;and three large terminals: the Athabasca Terminal located north of FortMcMurray, Alberta, the Cheecham Terminal, which is a new hub located 95kilometres south of Fort McMurray where the Waupisoo Pipeline initiates, andthe Hardisty Contract Terminal, one of the largest crude oil terminals in NorthAmerica.

 

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

 

The Company has a long-term (30-year) take-or-pay contractwith the major shipper on the Athabasca Pipeline which commenced in 1999.Revenue is recorded based on the contract terms negotiated with the majorshipper, rather than the cash tolls collected. The contract provides forvolumes and tolls designed to achieve an underpinning return on equity (ROE) basedon an assumed debt/equity ratio and level of operating costs. The committedvolumes and the tolls specified in the contract do not generate sufficient cashrevenues in the early years to compensate Enbridge for the debt and equityreturns as well as the cost of providing service. As a result, Enbridge isrecording a receivable in these years, which will be collected in tolls infuture years. This treatment ensures that the revenue recognized each period isin 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 andprovides access to the Edmonton market for oil sands producers. The WaupisooPipeline initiates at Enbridge’s Cheecham Terminal and terminates at itsEdmonton Mainline Terminal. The pipeline currently has a design capacity,dependent on crude slate, of up to 350,000 bpd, which can ultimately beexpanded to 600,000 bpd.

 

Enbridge has a long-term (25-year) take-or-paycommitment with the four founding shippers on the Waupisoo Pipeline whocollectively have contracted for approximately one-third of the initialcapacity on the line. The associated revenues provide for a base ROE withsignificant upside potential as incremental founders and third party volumesare added.

 

**Results of Operations**

Adjustedearnings 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 yearended December 31, 2007. In both the year ended December 31, 2009 and 2008, theincrease in Enbridge Regional Oil Sands System adjusted earnings reflectedcontributions from the Waupisoo Pipeline that entered service in June 2008 andthe continued positive impact of terminal infrastructure additions, partiallyoffset 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 costsrelated to a valve leak within the Enbridge Cheecham Terminal in January 2009,which is not indicative of the expected future performance of this asset.

 

 

22

----

 

**SOUTHERN LIGHTS PIPELINE**

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

 

Enbridgewill receive tariffs under long-term (15-year) contracts with committedshippers. Tariffs provide for recovery of all operating and debt financingcosts, plus a ROE at a pre-determined rate. Uncommitted volumes, up to aspecified amount, provide for tariff revenues that are fully credited to allshippers. Enbridge retains 25% of uncommitted tariff revenues on volumes abovethe specified amount, with the remainder being credited to shippers.

 

**Results of Operations**

Southern Lights Pipeline earnings for each of 2009, 2008 and2007 reflected AEDC recognized on a growing capital base while the projectcontinued to be under construction. In 2009, earnings from the new light sourpipeline, which became operational during the first quarter of 2009, were alsoreflected.

 

**SPEARHEAD PIPELINE**

Spearhead Pipeline delivers crudeoil from Chicago, Illinois to Cushing, Oklahoma. The performance of thispipeline steadily increased and with further support of new committed shippers,the Spearhead Pipeline Expansion was completed in May 2009. This expansionincreased the capacity from 125,000 bpd to 193,300 bpd from the new initiatingpoint of Flanagan, Illinois to Cushing.

 

Initial committed shippers andexpansion shippers currently account for more than 70% of the 193,300 bpdcapacity on Spearhead. Both the initial committed shippers and expansionshippers were required to enter into 10 year shipping commitments at negotiatedrates that were offered during the open season process. The balance of thecapacity is currently available to uncommitted shippers on a spot basis at FERCapproved rates.

 

**Results of Operations**

Spearhead Pipeline earningsincreased to $17 million for the year ended December 31, 2009 comparedwith $12 million for the year ended December 31, 2008 due to increasedvolumes resulting from the expansion completed in May 2009.

 

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

 

**OLYMPIC PIPELINE**

Enbridgehas a 65% interest in the Olympic Pipeline, the largest refined productspipeline in the State of Washington, transporting approximately 290,000 bpd ofgasoline, diesel and jet fuel. The pipeline system extends approximately 480kilometres (300 miles) from Blaine, Washington to Portland, Oregon, connectingfour 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, $7million and $10 million for the years ended December 31, 2009, 2008 and2007, respectively. Olympic’s cost of service tolling methodology requiresannual toll adjustments for over or under collection of the cost of service inprior 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 overcollection in the previous year. Earnings for the year ended December 31,2009 also reflected lower operating and administrative costs, which resulted inincreased earnings in 2009, while earnings for the year ended December 31,2008 also reflected an increase in pipeline integrity costs.

 

 

23

----

 

**FEEDER PIPELINES AND OTHER**

Feeder Pipelines and Other primarilyincludes the NW System, which transports crude oil from Norman Wells in theNorthwest Territories to Zama, Alberta; interests in a number of liquidspipelines in the United States; contract tankage facilities; and businessdevelopment costs related to Liquids Pipelines activities.

 

**Results ofOperations**

Adjusted earnings for Feeder Pipelines and Other were $3million in 2009 compared with $5 million in 2008 and $3 million in 2007. In2009, 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 beloware specific to the Liquids Pipelines business. General risks that affect theCompany as a whole are described under RISK MANAGEMENT.**

** **

**Supply and Demand**

The expansion of the Company’sliquids pipelines depends on the supply of, and demand for, crude oil and otherliquid hydrocarbons from Western Canada. Supply, in turn, depends on a numberof variables, including the price of crude oil and bitumen, the availabilityand cost of capital and labour for oil sands projects, the price of natural gasused for steam production and changes in plans by shippers. Supply risk toexisting facilities is largely mitigated given the Company’s throughputinsensitive commercial terms or cost of service arrangements on many of itsLiquids Pipelines assets. Demand depends, among other things, on weather,gasoline price and consumption, manufacturing levels, alternative energysources and global supply disruptions. Crude oilprice volatility has caused some oil sands producers to cancel or deferprojects that were planned to commence over the next decade. If the rate ofcrude oil production from the WCSB declines, immediate need for new pipelinesinfrastructure will likely decline.

 

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

 

**Competition**

Competitionamong existing pipelines is based primarily on the cost of transportation,access to supply, the quality and reliability of service, contract carrieralternatives and proximity to markets. Other competing carriers are availableto ship western Canadian liquids hydrocarbons to markets in either Canada orthe United States. Competition also arises from new pipeline proposals thatprovide access to market areas currently served by the Company’s liquidspipelines. One such competing project is expected to begin commercialoperations in early 2010 and will serve markets at Wood River, Illinois andCushing, Oklahoma. This pipeline has an initial capacity of 435,000 bpd and anultimate stated capacity of 591,000 bpd. Commercial support has also beenannounced to construct additional ex-Alberta capacity of 500,000 bpd toNederland, Texas, for an in-service date during 2012. Competing alternativesfor delivering western Canadian liquid hydrocarbons into the United States orother markets could erode shipper support for current or future expansion. However,the Company believes that its liquids pipelines provide attractive options toproducers in the WCSB due to its competitive tolls and multiple delivery andstorage points. Increased competition could arise from new feedersystems servicing the same geographic regions as the Company’s feederpipelines.

 

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

 

 

24

----

 

and more costeffective so that the Company can pass those benefits on to its customersthrough service, savings, reliability and responsiveness.

 

**Potential Pressure Restrictions**

The Company’s liquids systemsconsist of individual pipelines of varying ages. With appropriate inspectionand maintenance, the physical life of a pipeline is indefinitely long; however,as pipelines age the level of expenditures required for inspection andmaintenance may increase. Temporary pressure restrictions have been establishedon some sections of certain pipelines pending completion of specific inspectionand repair programs. Pressure restrictions may from time to time be establishedon the Company’s pipelines. Pressure restrictions reduce the available capacityof the applicable line segment and could result in a loss of throughput if andwhen the full capacity of that line segment would otherwise have been utilized.Pressure restrictions to date have not given rise to any significant loss ofthroughput. While the Enbridge System is volume-protected, EEP’s LakeheadSystem and certain other pipelines would be adversely affected by any pressurerestrictions that do reduce volumes transported.

 

**Regulation**

The Enbridge System and otherliquids pipelines are subject to the actions of various regulators, includingthe NEB. Actions of the regulators related to tariffs, tolls and facilitiesimpact earnings from those operations. The NEB historically prescribed abenchmark multi-pipeline rate of return on common equity, which is 8.52% in2010 (2009 - 8.57%; 2008 – 8.71%). To the extent the NEB rate of returnfluctuates, a portion of the Enbridge System and other liquids pipelinesearnings will change. The Company believes that regulatory risk is reducedthrough the negotiation of long-term agreements with shippers, such as the ITS,Terrace Agreement and agreements for projects currently under construction,including Alberta Clipper, which will govern the majority of the segment’s assets.

 

**National Energy Board Decision**

In October 2009, the NEB released a decision statingthe generic multi-pipeline formula used to determine allowed ROE for pipelinecompanies is no longer in effect. The formula will not be replaced; insteadreturns will be determined through negotiated settlement between shippers andpipelines. As the formula is referenced in some current industry settlements,the NEB will continue to publish the generic ROE for 2010 and 2011, and ifrequested will continue to publish it post-2011.

 

Certain of the Company’s Liquids assets are regulated by theNEB and reference the multi-pipeline rate. The Company does not expect therewill be a material financial impact as a result of this decision.

 

 

25

----

 

**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 andServices were $289 million for the year ended December 31, 2009 comparedwith $302 million for the year ended December 31, 2008. The decreasedearnings were substantially due to the sale of CLH in June 2008 and OCENSAin March 2009, offset by higher volumes, including contributions fromShenzi, since its in-service date in April 2009, and Thunder Horse, both withinOffshore, favourable foreign exchange, as well as increased adjusted earningsat EGD, Energy Services and Aux Sable.

 

Adjusted earnings from Natural Gas Delivery andServices were $302 million for the year ended December 31, 2008 comparedwith $324 million for the year ended December 31, 2007. The decrease inadjusted earnings was substantially due to continuing natural productiondeclines and lost revenue and clean up costs related to Hurricanes Gustav andIke 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 werepartially offset by customer growth and higher ancillary revenues at EGD,customer growth at Enbridge Gas New Brunswick (EGNB) within Other GasDistribution and improved financial performance at Energy Services and AuxSable.

 

Natural Gas Delivery and Servicesearnings were impacted by the following non-recurring or non-operatingadjusting items:

·      EGD earningsare adjusted to reflect the impact of colder weather.

 

 

26

----

 

·      Earningsfrom EGD for 2009 included interest income of $7 million related to therecovery of excess GST remitted to Canada Revenue Agency.

·      Earningsfrom EGD for 2008 included a $3 million provision for one-time charges tobetter align certain operating practices with its strategy under incentiveregulation (IR).

·      In 2009 and2007, earnings from EGD and Noverco reflect the impact of favourable tax ratechanges.

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

·      Offshoreearnings for the year ended December 31, 2009 and 2007 included insuranceproceeds of $4 million and $5 million, respectively, related to the replacementof damaged infrastructure as a result of the 2008 and 2005 hurricanes.

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

·      Earnings forthe year ended December 31, 2009 from Aux Sable reflected a $7 milliongain from a loan forgiveness related to a negotiated settlement with acounterparty in bankruptcy proceedings.

·      EnergyServices earnings for 2009 and 2008 reflected unrealized fair value gains andlosses resulting from the revaluation of inventory and the revaluation oflargely offsetting financial derivatives used to “lock-in” the profitability offorward transportation and storage transactions.

·      EnergyServices earnings for the year ended December 31, 2008 included a $6million 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 inColombia, for proceeds of $512 million, resulting in a gain of $329 million. OnJune 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.

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

·      A $5 milliongain on sale of investment in Inuvik Gas was reflected in earnings from Otherfor the year ended December 31, 2008.

 

**ENBRIDGE GAS DISTRIBUTION**

EGD isCanada’s largest natural gas distribution company and has been in operation formore than 160 years. It serves approximately 1.9 million customers in centraland eastern Ontario and parts of northern New York State. EGD’s utilityoperations are regulated by the Ontario Energy Board (OEB) and by the New YorkState 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 earn100 bps over the base regulated return. Through various productivityenhancements, any return over this 100 bps must be shared with customers on anequal basis. Enbridge estimates the customer portion of 2009 earnings over theallowed threshold at $19 million (2008 - $6 million).

 

**Rate Adjustment Applications**

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

 

27

----

 

the Rate Handbook. The OEB issued a first procedural orderin October 2009, in which the OEB indicated that it would consider its jurisdictionwith regard to inclusion of green energy related projects within the regulatedoperations of EGD. The OEB issued a decision in December 2009 whicheffectively prevents the inclusion of such activities in rate-making for thepurposes of setting 2010 rates. As a result of this decision, in 2010, EGD willseek clarification of the OEB’s broader policies with respect to suchinvestments and activities.

 

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

 

**New Customer Information System(CIS) Implemented**

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

 

**Green Energy Initiatives**

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

 

In the absence of the Minister’sDirective, the Company’s Undertakings to the Lieutenant Governor in Councilwould 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 islooking to expand its efforts to explore and pursue alternative and/orrenewable energy technologies subject to OEB approval, where appropriate. Whilethe Directive permits EGD to engage in such activities, in December 2009the OEB determined that it would not allow such activities to be included inrate-making for the purposes of setting 2010 rates. As a result of thisdecision, EGD will seek clarification of the OEB’s broader policies withrespect to such investments and activities in 2010.

 

**Unregulated Storage Services**

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

 

**Results of Operations**

Adjustedearnings for the year ended December 31, 2009 were $129 million comparedwith $123 million for the year ended December 31, 2008. The increase inEGD’s adjusted earnings was primarily due to customer growth and lower interestexpense, offset by higher operating costs and estimated accrued earningssharing with customers under the current IR term caused primarily by a reducedrate 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 duringits first of five years under IR, specifically through customer growth andhigher ancillary revenues.

 

28

----

 

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

·      Earnings for each period areadjusted to reflect the impact of colder weather. Weather is a significantdriver of delivery volumes given that a significant portion of EGD customersuse natural gas for space heating.

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

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

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

 

**BusinessRisks**

**The risks identified beloware specific to EGD. General risks that affect the Company as a whole aredescribed under RISK MANAGEMENT.**

** **

**RegulatoryRisk**

Theformula currently approved by the OEB for determination of the ROE, which isembedded and escalated within rates over the IR period, is based on the OEB’srisk assessment of EGD for the 2007 fiscal year.

 

The OEB issued areport in December 2009 indicating several changes to the cost of capitalfor Ontario’s regulated utilities. The new policy guidelines established a newbase 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 annualadjustment formula was also established which will change annually with changesin the interest rates on long-term Canada bonds and Canadian A-Rated utilitybonds.

 

EGD anticipates thatthe new ROE policy guidelines will be applied to the determination of theannual earnings sharing mechanism for 2010 and for the remainder of the IRterm. The company also anticipates applying the new ROE policy guidelines tothe determination of rates after the conclusion of the IR term, for the rateyear beginning 2013.

 

Thesettlement allows certain categories of expense, added at cost of service baseamounts, and uncontrollable external factors in the IR formula, which willpermit EGD to recover, with OEB approval, certain costs that are beyondmanagement control, but are necessary for the maintenance of its services. Thesettlement also includes a mechanism to end the IR plan and return to cost ofservice if there are significant and unanticipated developments that threatenthe sustainability of the IR plan. The above noted terms set out in thesettlement mitigate EGD’s risk to factors beyond management’s control.

 

EGD doesnot profit from the sale of natural gas nor is it at risk for the differencebetween the actual cost of natural gas purchased and the price approved by theOEB. This difference is deferred as a receivable from or payable to customersuntil the OEB approves its refund or collection. EGD monitors the balance andits potential impact on customers and will request interim rate relief thatwill allow EGD to recover or refund the natural gas cost differential. EGD hasa quarterly rate adjustment mechanism in place for the natural gas. This allowsfor the quarterly adjustment of rates to reflect changes in natural gas prices.Adjustments are subject to prior approval by the OEB.

 

**VolumeRisks**

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

 

29

----

 

Weather is asignificant driver of delivery volumes, given that a significant portion of EGD’scustomer base uses natural gas for space heating. For the years ended December 31,2009, 2008 and 2007, colder than normal weather impacted earnings by $17million, $23 million and $14 million, respectively.

 

Distribution volume may also beimpacted by the increased adoption of energy efficient technologies, along withmore efficient building construction, that continues to place downward pressureon consumption. In addition, conservation efforts by customers furthercontribute to the decline in annual average consumption. On average, EGD hasseen a 1.3%annual decline in residential use year-over-year between 1998 and2008. During the IR term, the ability of EGD to annually adjust distributionvolumes for rate-setting provides a mechanism to protect the company fromexposure to declining average use. Further, once rates are set for the year,any incremental decline or benefit (if any) in average use, compared to thebasis used for rate-setting in the most recent year, is recorded as aregulatory deferral for future collection from, or refund to, customers, to theextent this relates to residential and small commercial customers.

 

Salesand transportation of gas for customers in the residential and commercialsectors account for approximately 81% (2008 - 79%) of total distributionvolume. Sales and transportation service to large volume commercial andindustrial customers is more susceptible to prevailing economic conditions. Aswell, the pricing of competitive energy sources affects volume distributed tothese sectors as some customers have the ability to switch to an alternatefuel. Customer additions are important to all market sectors as continuedexpansion adds to the total consumption of natural gas.

 

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

 

Thisdistribution volume risk for general service customers is mitigated by theaverage use true-up variance account that was established under the IRSettlement Agreement. This variance account enables recovery from or repaymentto customers of amounts representing variances in the actual and forecastaverage use by general service customers. EGD remains at risk of distributionvolumes for large volume contract commercial and industrial customers.

 

***NOVERCO***

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

 

Weather variations do not affect Noverco’s earningsas Gaz Metro is not exposed to weather risk. A significant portion of theCompany’s earnings from Noverco is in the form of dividends on its preferredshare investment, which is based on the yield of 10-year Government of Canadabonds plus 4.34%.

 

**Results of Operations**

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

 

**OTHER GAS DISTRIBUTION**

Other Gas Distribution includes natural gasdistribution utility operations in Quebec, New Brunswick and northern New YorkState. The largest utility included in this group of assets is EGNB (70.9%owned and operated by the Company) which owns the natural gas distributionfranchise in the province of New Brunswick. EGNB is constructing a newdistribution system and has approximately 10,000 customers. Approximately 725kilometres (450 miles) of distribution main has been installed with thecapability of attaching approximately 30,000 customers.

 

30

----

 

**Results of Operations**

Other Gas Distribution earnings were $26 millionfor the year ended December 31, 2009, comparable to $23 million for theyear 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 andUtilities Board (EUB). As it is currently in the development period, EGNB’scost of service exceeds its distribution revenues. The EUB has approved thedeferral of the shortfall between distribution revenues and the cost of serviceduring the development period for recovery in future rates. This recoveryperiod 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**

Offshoreis comprised of 13 natural gas gathering and FERC-regulated transmissionpipelines 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 transportedapproximately 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 Offshoresystems are producers who execute life-of-lease commitments in connection withtransmission and gathering service contracts. In exchange, Offshore providesfirm capacity for the contract term at an agreed upon rate. The throughputvolume generally reflects the lease’s maximum sustainable production. Thetransportation contracts allow the shippers to define a maximum daily quantity(MDQ), which corresponds with the expected production life. The contractstypically have minimum throughput volumes which are subject to take-or-paycriteria, but also provide the shippers with flexibility, subject to advancenotice criteria, to modify the projected MDQ schedule to match currentdeliverability expectations.

 

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

 

Thelong-term transport rates established in the gathering and transmission serviceagreements are generally market-based but are established using a cost ofservice methodology, which includes operating cost, projected revenuegeneration directly tied to production deliverability and the appropriate costof capital.

 

Thebusiness model utilized on a go forward basis and included in the WRGGS and BigFoot commercially secured projects differs from the historic model. These newprojects have a base level return which is locked in by take or paycommitments. If volumes reach producer anticipated levels the return on theseprojects will increase. In addition, Enbridge has minimal capital cost risk onthese projects and still has the life-of-lease commitments included incommercial agreements.

 

**Results of Operations**

Adjusted earnings for the year endedDecember 31, 2009 in Offshore were $29****millioncompared with $7 million for the year ended December 31, 2008. Offshoreadjusted earnings increased due to higher volumes, including contributions fromShenzi, since its in-service date in April 2009, and Thunder Horse, sinceits in-service date of June 2008, as well as favourable foreign exchangerates. Offshore adjusted earnings for 2009 included $4 million in insuranceproceeds collected during the second and fourth quarters, which were partialreimbursement for business interruption lost revenues and operating expensesassociated with Hurricane Ike in 2008.

 

Offshore adjusted earnings for theyear ended December 31, 2008 were $7 million compared with $22 million forthe year ended December 31, 2007. Offshore adjusted earnings decreased asa result of 

 

 

31

----

 

continuing natural productiondeclines as well as approximately $11 million in lost revenue and clean upcosts related to Hurricanes Gustav and Ike. These decreases were partiallyoffset by stand-by fees on the Neptune oil and gas pipelines which came intoservice in the fourth quarter of 2007, as well as contributions from Atlantisand Thunder Horse platform volumes. Also, adjusted earnings for the year ended December 31,2008 included approximately $2 million (2007 - $6 million) from businessinterruption insurance proceeds related to lost revenue in 2005 and 2006 as aresult of the 2005 hurricanes.

 

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

 

**Business Risks**

The risks identified below are specific toOffshore. General risks that affect the Company as a whole are described under RISKMANAGEMENT.

 

**Weather**

Adverse weather, such as hurricanes, may impactOffshore financial performance directly or indirectly. Direct impacts mayinclude damage to Offshore facilities resulting in lower throughput andinspection and repair costs. Indirect impacts include damage to third partyproduction platforms, onshore processing plants and pipelines that may decreasethroughput on Offshore systems.

 

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

 

**Competition**

There is competition for new and existing businessin the Gulf of Mexico. Offshore has been able to capture key opportunities,positioning it to more fully utilize existing capacity. Offshore serves amajority of the strategically located deepwater host platforms and itsextensive presence in the deepwater Gulf of Mexico has Offshore well positionedto generate incremental revenues, with modest capital investment, bytransporting production from sub-sea development of smaller fields tied back toexisting host platforms. Offshore is also able to construct pipelines to transportcrude oil, diversifying the risk of declining production, as demonstrated withthe newly constructed Neptune crude oil lateral and the recently announced BigFoot Oil Pipeline. Given rates of decline, Offshore pipelines typically haveavailable capacity, resulting in significant competition for new developmentsin the Gulf of Mexico.

 

**Regulation**

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

 

**Other Risks**

Otherrisks directly impacting financial performance include underperformancerelative to expected reservoir production rates, delays in project start-uptiming, changes in plans by shippers and capital expenditures in excess ofthose estimated. Capital risk is mitigated in some circumstances by having areaproducers as joint venture partners, through cost of service tollingarrangements and pre-arranged terms in commercial agreements. Start-up delaysare mitigated by the right to collect stand-by fees.

 

**ALLIANCE PIPELINEUS**

The Alliance System (Alliance),which includes both the Canadian and United States portions of the pipelinesystem, consists of an approximately 3,000-kilometre (1,875-mile) integrated,high-pressure 

 

 

32

----

 

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

 

Allianceconnects with Aux Sable, of which Enbridge owns 42.7%, a NGLs extractionfacility in Channahon, Illinois. The natural gas may then be transported to twolocal natural gas distribution systems in the Chicago area and five interstatenatural gas pipelines, providing shippers with access to natural gas markets inthe midwestern and northeastern United States and eastern Canada.

 

In2009, Pecan Pipeline, a gathering pipeline owned by a third party, wasconnected to a new gas receipt point on Alliance near Towner, North Dakota.This pipeline will bring associated rich gas from the Bakken formation on toAlliance. The new receipt point went into service in January 2010, with aninitial volume of 40 mmcf/d, which will increase to 80 mmcf/d one year afterthe initial in-service date.

 

**Transportation Contracts**

Alliance has long-term, take-or-pay contracts through 2015to 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 naturalgas contracted through 2010 which is expected to be remarketed upon expiry.These contracts permit Alliance to recover the cost of service, which includesoperating and maintenance costs, the cost of financing, an allowance for incometax, an annual allowance for depreciation and an allowed ROE of 11.5%. Eachlong-term contract may be renewed upon five years notice for successiveone-year terms beyond the original 15-year primary term. Alliance Pipeline USoperations are regulated by the FERC.

 

Depreciation expense included in the cost of service isbased on negotiated depreciation rates contained in the transportationcontracts, while depreciation expense in the financial statements is recordedon a straight-line basis at 4% per annum. Negotiated depreciation expense isgenerally less than the financial statement amount at the beginning of thecontract and higher than straight-line depreciation in the later years of theshipper transportation agreements. This difference results in recognition of along-term receivable, referred to as deferred transportation revenue, that isexpected to be recovered from shippers beginning in 2009 for Alliance PipelineUS and 2011 for Alliance Pipeline Canada. As at December 31, 2009, $151million (US$144 million) (2008 - $182 million (US$149 million)) was recorded asdeferred transportation revenue.

 

**Alliance Pipeline Recontracting Strategy**

Alliance continues to be fullycontracted on a firm service basis and is expected to run at or near fullcapacity 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 forsurplus export pipeline capacity. Alliance is well placed to benefit fromincremental unconventional volumes from shale plays in British Columbia, and iscurrently evaluating opportunities to expand its service offerings in thisarea.

 

**Results of Operations**

Alliance Pipeline US adjusted earnings were $27million for the year ended December 31, 2009, comparable to $25 millionfor 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 dueto 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 formershipper which repudiated its capacity commitment.

 

**VECTORPIPELINE**

TheCompany provides operating services to, and holds a 60% joint venture interestin, Vector Pipeline, which transports natural gas from Chicago, Illinois toDawn, Ontario. Vector Pipeline has the capacity to 

 

 

33

----

 

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

 

**Vector Pipeline’s primarysources of supply are through interconnections with Alliance and the NorthernBorder Pipeline in Joliet, Illinois. Approximately 55% of the long haulcapacity of Vector Pipeline is committed through 15-year firm transportationcontracts at rates negotiated with the shippers and approved by the FERC. Theremaining capacity is sold at market rates and at various term lengths. Thetotal long haul capacity of Vector is approximately 90% committed through 2015.Transportation service is provided through a number of different forms ofservice agreements such as Firm Transportation Service and InterruptibleTransportation Service.**VectorPipeline is an interstate natural gas pipeline with FERC and NEB approvedtariffs establishing rates, terms and conditions governing its service tocustomers. On the United States portion of Vector, tariff rates are determinedusing a cost of service methodology and tariff changes may only be implementedupon approval by the FERC. For 2009, the FERC approved maximum tariff ratesinclude 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 fileits negotiated tolls calculation with the NEB on an annual basis. Tolls arecalculated on a levelized basis that include a rate of return incentivemechanism 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.

** **

**Resultsof Operations**

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

 

**Business Risks**

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

 

**Supply andDemand**

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

 

**Exposure toShippers**

The failure of shippers to perform theircontractual obligations could have an adverse effect on the cash flows andfinancial condition of Alliance Pipeline US and Vector Pipeline. To reduce thisrisk, Alliance Pipeline US and Vector Pipeline monitor the creditworthiness ofeach shipper and receive collateral for future shipping tolls should a shipper’scredit position not meet tariff requirements. These pipelines also have diversegroups of long-term transportation shippers, which include various gas andenergy distribution companies, producers and marketing companies, further reducingthe exposure.

 

**Competition**

Alliance Pipeline US faces competition for pipelinetransportation services to the Chicago area from both existing and proposedpipeline projects. Competing pipelines provide natural gas transportationservices from the WCSB to distribution systems in the Midwestern United States.In addition, there are several proposals to upgrade existing pipelines servingthese markets. Any new or upgraded pipelines could either allow shippersgreater access to natural gas markets or offer natural gas transportationservices that are more desirable than those provided by Alliance. Shippers onAlliance Pipeline US have access to additional high compression deliverycapacity at no additional cost, other than fuel requirements, serving to enhancethe competitive position of Alliance Pipeline US.

 

 

34

----

 

Vector Pipeline faces competitionfor pipeline transportation services to its delivery points from new supplysources and traditional low cost pipelines, which could offer transportationthat is more desirable to shippers because of cost, supply location, facilitiesor other factors. Vector Pipeline has mitigated this risk by entering intolong-term firm transportation contracts, which expire starting in November 2015,for approximately 87% of its capacity. The remaining contracts expire atvarious times starting in April 2012. Certain long-term firm contracts(55% of capacity) provide for additional compensation to Vector Pipeline ifshippers do not extend their contracts beyond the initial term ending November 2015.The effectiveness of these mitigating factors is evidenced by the increasedutilization of the pipeline since its construction, despite the presence oftransportation alternatives.

 

**Regulation**

Both Vector Pipeline and Alliance Pipeline US operations areregulated 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 onmanaging gas pipeline integrity. The Company continues ongoing dialogue withregulatory agencies and participates in industry lobby groups to ensure it isinformed of emerging issues in a timely manner.

 

**AUX SABLE**

Enbridge owns 42.7% of Aux Sable, aNGLs extraction and fractionation business near Chicago, Illinois. Aux Sableowns and operates a plant at the terminus of Alliance. The plant extracts NGLsfrom the energy-rich natural gas transported on Alliance, as necessary to meetthe requirements of downstream distribution companies, which require naturalgas with less NGLs, or lower heat content; and to take advantage of positivecommodity price spreads.

 

Aux Sable has anagreement with BP to sell its NGLs production to BP. In return, BP pays AuxSable a fixed annual fee and a share of any net margin generated from thebusiness in excess of specified natural gas processing margin thresholds (theupside sharing mechanism). In addition, BP compensates Aux Sable for alloperating, maintenance and capital costs associated with the Aux Sablefacilities subject to certain limits on capital costs. BP supplies, at itscost, all make-up gas and fuel supply gas to the Aux Sable facilities and isresponsible for the capacity on the Alliance Pipeline held by an Aux Sableaffiliate, at market rates. The agreement is for an initial term of 20 years,expiring December 21, 2025 and may be extended by mutual agreement for10-year terms.

 

**Results of Operations**

Adjustedearnings for the year ended December 31, 2009 were $26 millioncompared with $28million for the year ended December 31, 2008. Aux Sable adjustedearnings decreased due to unexpected plant outages during the fourth quarter of2009.

 

Adjustedearnings for the year ended December 31, 2008 were $28 millioncompared with earnings of $11 million for the year ended December 31, 2007. Aux Sableadjusted earnings increased due to strong fractionation margins and enhancedplant performance, in addition to favourable risk management positions, whichenabled the Company to recognize earnings from the upside sharing mechanism.

 

Aux Sableearnings reflected the following non-recurring or non-operating adjustingitems:

·                  Earnings for each period reflected unrealized fair valuechanges on derivative financial instruments used to risk manage fractionationmargin upside on natural gas processing volumes. These non-cash amounts arosedue to the revaluation of financial derivatives used to “lock in” theprofitability of forward contracted prices.

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

 

 

35

----

 

**ENERGY SERVICES**

Energy Services includes Gas Services and TidalEnergy, the Company’s energy marketing businesses. Gas Services markets naturalgas to optimize Enbridge’s commitments on the Alliance and Vector pipelines. Italso has a growing business of providing fee-for-service arrangements for thirdparties, leveraging its marketing expertise and access to contractedtransportation capacity. Capacity commitments as of December 31, 2009 were33 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 were33 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 thebasis (location) differentials between Alberta and Chicago, for Alliance, andbetween Chicago and Dawn, for Vector Pipeline. To the extent the cost oftransportation on these two pipelines exceeds the gas commodity basisdifferential, earnings will be negatively affected.

 

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

 

**Results of Operations**

Adjustedearnings from Energy Services increased from $6 million in 2007 to $17 millionin 2008 and $29 million in 2009. The increase in adjusted earnings each year isdue to higher volumes and the impact of realizing favourable storage andtransportation margins.

EnergyServices earnings were impacted by the following non-recurring or non-operatingadjusting items:

·                  Earningsfor each period reflect unrealized fair value gains and losses resulting fromthe revaluation of inventory and the revaluation of largely offsettingfinancial derivatives used to “lock-in” the profitability of forwardtransportation and storage transactions. During the first quarter of 2009, theCompany adopted fair value accounting for inventory held at its commoditymarketing businesses.

·                  Energy Services 2008 earnings included a $6 million write-off as aresult of bankruptcies by SemGroup and Lehman Brothers - the full amount of all such receivables was provided for in2008. 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 inColombia. In 2008, the Company sold its 25% equity interest in CLH, Spain’slargest refined products transportation and storage business. Both of theseinvestments were sold at very attractive prices and proceeds were utilized inthe funding of the North American expansion projects discussed earlier.

 

Given thedisposals of OCENSA and CLH, there are currently minimal operations inInternational. However, Enbridge continues to actively monitor theinternational business environment to identify potential new investmentopportunities.

 

**Results of Operations**

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

 

 

36

----

 

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

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

·                  In June 2008, the Company soldits 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 in2008 and nil in 2007. Losses in Other primarily reflected higherbusiness development expenditures and lower earnings from CustomerWorks LimitedPartnership (CustomerWorks) which resulted from a smaller customer base.

 

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

 

**SPONSOREDINVESTMENTS**

 

**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 SponsoredInvestments were $151****million forthe year ended December 31, 2009 compared with $101 million in 2008 and$86 million in 2007. The increase in adjusted earnings resulted primarily fromincreased contributions from EEP as a result of positive operating factors andEnbridge’s higher ownership interest.

 

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

·                  Earnings from EEP included a changein the unrealized fair value on derivative financial instruments in eachperiod.

·                  EEP earnings for the year ended December 31,2009 included an asset impairment loss of $12 million (net to Enbridge) relatedto 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 toEnbridge) related to services provided in prior periods.

·                  Earnings in 2008 and 2007 includedEEP dilution gains arising because Enbridge did not fully participate in EEP’s Class Aunit 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 millionin Class A units increasing Enbridge’s ownership interest in EEP to 27.0%.

·                  2008 earnings from EEP includednon-routine costs associated with Hurricanes Gustav and Ike, of which Enbridge’sshare is $2 million, as well as the write-off of certain projects cancelled dueto 

 

 

37

----

 

market conditions.

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

·                  Earnings from EIF for the year endedDecember 31, 2008 included proceeds of $1 million from the settlement of aclaim against a former shipper on Alliance Canada which repudiated its capacitycommitment.

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

 

**ENBRIDGE ENERGY PARTNERS**

EEP owns andoperates crude oil and liquid petroleum transportation and storage assets andnatural gas gathering, treating, processing, transportation and marketingassets in the United States. Significant assets include the Lakehead System,which is the extension of the Enbridge System in the United States; theMid-Continent crude oil system consisting of an interstate crude oil pipelineand storage facilities; a crude oil gathering system and interstate pipelinesystem in North Dakota; and natural gas assets located primarily in Texas.

 

In thesecond quarter of 2007, EEP issued partnership units. Because Enbridge did notfully participate in these offerings, dilution gains of $12 million resultedand Enbridge’s ownership interest in the Partnership decreased from 16.6% to15.1%. 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, resultingin a $5 million dilution gain and a decrease in ownership interest to 14.6%. Inlate 2008, Enbridge purchased 16.3 million Class A common units of EEP,resulting in an ownership increase to 27.0%. The Company’s average ownershipinterest in EEP during 2008 was 15.7%. At December 31, 2009, Enbridge’sownership interest in EEP remained at 27.0%.

 

**Distributions**

EEP makesquarterly distributions of its available cash to its common unitholders. Underthe Partnership Agreement, Enbridge Energy Company, Inc. (EECI), a whollyowned subsidiary of Enbridge, as general partner (GP), receives incrementalincentive cash distributions, which represent incentive income, on the portionof cash distributions, on a per unit basis, that exceed certain targetthresholds 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 thefirst three quarters of 2007, EEP paid quarterly distributions of $0.925 perunit and effective November 2007, EEP increased quarterly distributions to$0.95 per unit. In the first two quarters of 2008 EEP paid quarterlydistributions of $0.95 per unit and effective August 2008, EEP increasedquarterly distributions to $0.99 per unit. Of the $99 million Enbridgerecognized as adjusted earnings from EEP during 2009, 27% (2008 – 37%; 2007 - 40%)were GP incentive earnings while 73% (2008 – 63%; 2007 - 60%) were Enbridge’slimited partner share of EEP’s earnings.

 

**Results of Operations**

Adjusted earnings from EEP were $99****million for the year ended December 31, 2009 comparedwith $60 million for the year ended December 31, 2008. EEP adjustedearnings increased due to the Company’s higher ownership interest in EEPresulting from the December 2008 Class A unit subscription; anincreased contribution due to additional assets placed in service and relatedtariff surcharges for recent expansions; higher incentive income; and, a morefavourable foreign exchange rate at which EEP’s earnings are translated toCanadian dollars for presentation purposes.

 

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

 

 

38

----

 

incentive income and increasedearnings at EEP due to higher gas and crude oil delivery volumes, tariffsurcharges for recent expansions and additional revenue resulting from higheraverage crude oil prices associated with allowance oil. These increases werepartially offset by increased operating and administrative costs and writedowns of natural gas inventory to fair market value as a result of declines inthe price of natural gas. Also, the Company’s ownership interest in EEPincreased to 27.0% in December 2008.

 

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

·                  Earnings included a change in the unrealizedfair 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) relatedto the write-down of certain assets.

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

·                  Earnings in 2008 and 2007 includeddilution gains because Enbridge did not fully participate in EEP’s Class Aunit offerings in May 2007 and March 2008, decreasing Enbridge’sownership interest in EEP to 14.6%. In December 2008, the Companypurchased an additional US$500 million in Class A units, increasingEnbridge ownership interest in EEP to 27.0%.

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

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

 

**ENBRIDGE ENERGY, L.P. – ALBERTA CLIPPER US**

In July 2009, the Companycommitted to fund 66.7% of the cost to construct the United States segment ofthe Alberta Clipper Project. The Company will fund 66.7% of the project’sequity requirements through EELP, while 66.7% of the debt funding will be madethrough EEP. EELP – Alberta Clipper US earnings are the Company’s earnings fromits investment in EELP which is undertaking the project and currently representAEDC recognized while the project is under construction.

 

**Results of Operations**

Adjusted earnings from EELP -Alberta Clipper US were $7****million forthe year ended December 31, 2009. These earnings relate to AEDC earnedwhile the project is under construction.

 

**BusinessRisks**

The risks identified below arespecific to EEP and EELP. General risks that affect the Company as a whole aredescribed under RISK MANAGEMENT.

 

**Competition**

EEP’s Lakehead System, the United States portion of theEnbridge System, is a major crude oil export route from the WCSB. Otherexisting competing carriers and pipeline proposals to ship western Canadianliquids hydrocarbons to markets in the United States represent competition forthe Lakehead System. Further details on such competing projects are describedwithin Business Risks under LIQUIDS PIPELINES. EEP’s Mid-Continent system andNorth Dakota system also face competition from existing competing pipelines,proposed future pipelines, and alternative gathering facilities available toproducers or the ability of the producers to build such gathering facilities.Competition for EEP’s storage facilities include large integrated oil companiesand other midstream energy partnerships.

 

Other interstate and intrastate natural gas pipelines ortheir affiliates and other midstream businesses that gather, treat, process andmarket 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 andowners have alternate gathering, treating and processing facilities availableto them, including competitors that are substantially larger than EEP.

 

39

----

** **

**Financing Risk**

EEP has made and expects to continue makingsubstantial capital expenditures for the construction and development of crudeoil and natural gas infrastructure. EEP intends to finance its future capitalexpenditures by utilizing cash from operations, borrowings under existingcredit facilities and lastly from borrowings under the US$500 million revolvingcredit agreement with Enbridge (see Liquidityand Capital Resources). EEP also expects to obtain permanent financingthrough the issuance of additional debt and equity securities through thecapital markets, as necessary.

 

**Supply and Demand**

The profitability of EEP dependsto some extent on the volume of products transported on its pipeline systems.The volume of shipments on EEP’s Lakehead System depends primarily on thesupply of western Canadian crude oil and the demand for crude oil in the GreatLakes and Midwest regions of the United States and eastern Canada.

 

EEP’s natural gas gathering assetsare also subject to changes in supply and demand for natural gas, NGLs andrelated products. Commodity prices impact the willingness of natural gasproducers to invest in additional infrastructure to produce natural gas. Theseassets are also subject to competitive pressures from third-party and producer-ownedgathering systems.

 

**Volume Risk**

A decrease in volumes transportedby EEP’s systems can directly and adversely affect revenues and results ofoperations. A decline in volumes transported can be influenced by factorsbeyond EEP’s control including: competition, regulatory action, weather,storage levels, alternative energy sources, decreased demand, fluctuations incommodity prices, economic conditions, supply disruptions, availability ofsupply connected to the systems and adequacy of infrastructure to move supplyinto and out of the systems.

 

**Regulation**

In the United States, theinterstate oil pipelines owned and operated by EEP and certain activities ofEEP’s intrastate natural gas pipelines are subject to regulation by the FERC orstate regulators and its revenues could decrease if tariff rates wereprotested. While gas gathering pipelines are not currently subject to activerate regulation, proposals to more actively regulate intrastate gatheringpipelines are currently being considered in certain of the states in which EEPoperates. In addition, the FERC has also taken an interest in regulating gasgathering systems that connect into interstate pipelines.

 

**Market Price Risk**

EEP’s gas processing business issubject to commodity price risk for natural gas and NGLs. These risks have beenmanaged by using physical and financial contracts, fixing the prices of naturalgas and NGLs. Certain of these financial contracts do not qualify for cash flowhedge accounting and EEP’s earnings are exposed to associated mark-to-marketvaluation changes.

 

**ENBRIDGE INCOME FUND**

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

 

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

 

**Proposed Corporate Restructuring**

On November2, 2009, EIF announced that Enbridge, as administrator of EIF, recommended tothe EIF Board of Trustees a proposed restructuring of EIF to take effect priorto the imposition of the specified investment flow-through entity (SIFT)Canadian tax on January 1, 2011. The proposed restructuring would

 

 

40

----

 

involve theexchange by public unitholders of their trust units, which collectivelyrepresent a 28% economic interest in EIF, for shares of a taxable Canadiancorporation to be called Enbridge Income Fund Holdings Inc. (EIFH), plus asmall amount of cash. The scope of activities of EIFH would be limited toinvestment in EIF. A committee of independent Trustees of EIF, assisted byindependent legal and financial advisors, is reviewing the administrator’srecommendation in light of potential alternatives and will provide theirrecommendations to public unitholders. The recommended restructuring would besubject to approval by unitholders.

 

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

 

**Incentive and Management Fees**

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

 

**Results ofOperations**

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

 

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

 

EIF earnings were impacted bya non-recurring shipper claim settlement of $1 million in 2008 and tax ratechanges of $2 million in 2007. In 2007, EIF recognized future taxes withinentities 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 futureincome tax obligations previously recorded as a result of tax rate reductionsin the second and fourth quarters of 2007.

 

**Business Risks**

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

 

 

41

----

 

**Competition**

TheSaskatchewan System faces competition in pipeline transportation from otherpipelines as well as other forms of transportation, most notably trucking.These alternative transportation options could charge rates or provide serviceto locations that result in greater net profit for shippers and therebypotentially reduce shipping on the Saskatchewan System or result in possibletoll reductions. The Saskatchewan System manages exposure to loss of shippersby ensuring the shipping rates are competitive and by providing a high level ofservice. Further, the Saskatchewan System’s right-of-way and expansion effortshave created a competitive advantage. The Saskatchewan System will continue tofocus on increasing efficiencies through its expansion projects in order tomeet its shippers’ growing demand.

 

**Regulation**

EIF’s 50% interest in Alliance Pipeline Canada andcertain pipelines within the Saskatchewan System are subject to the actions ofvarious regulators, including the NEB. Actions of the regulators related totariffs, tolls and facilities impact earnings and the success of expansionprojects. Delays in regulatory approvals could result in cost escalations andconstruction delays. Changes in regulation, including decisions by regulatorson the applicable tariff structure or changes in interpretations of existingregulations by courts or regulators, could adversely affect the results ofoperations of EIF.

** **

**Demand for Services**

Operationsand tolls for the Saskatchewan Gathering and the Westspur Systems are, ingeneral, based on volumes transported and are on terms similar to a commoncarrier basis with no specific on-going volume commitments. There is noassurance that shippers will continue to utilize these systems in the future ortransport 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 $39million for the year ended December 31, 2009 compared with $58 million for theyear ended December 31, 2008. The improvement in Corporate adjusted loss is aresult of foreign exchange gains realized on hedge settlements and on residualUnited States dollar cash balances as the result of a stronger United Statesdollar, partially offset by higher operating costs, including compensation, andan increase in bank stand-by fees reflecting tighter credit markets.

 

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

 

Corporate costs were impacted by thefollowing 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 |
|--------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|

 

 

42

----

 
|   | 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 ANDCAPITAL RESOURCES**

** **

The Company expectsto utilize cash from operations, the issuance of commercial paper and creditfacility draws and issuance of long-term debt to fund liabilities as theybecome due, finance capital expenditures and pay common share dividends. At December31, 2009, excluding the Southern Lights project financing, the Company had$6,011 million of committed credit facilities of which $3,643 million was drawnor allocated to backstop commercial paper. At December 31, 2009, the Companyhas provided its affiliates EEP and EIF with liquidity support of US$500million and $100 million, respectively, under revolving credit agreements.Drawings on the EEP and EIF facilities at December 31, 2009 were nil and $12million, respectively. As a result, the Company had net available liquidity atDecember 31, 2009 of $2,024 million, inclusive of unrestricted cash and cashequivalents of $268 million. The net available liquidity is expected to besufficient to finance all currently secured capital projects, including theinvestment in the United States portion of the Alberta Clipper project, and toprovide flexibility for new investment opportunities.

 

The Companyactively manages its bank funding sources to ensure adequate liquidity andoptimize pricing and other terms. During the year, the following transactionsoccurred:

 
|   | · | 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 willfund two-thirds of the estimated US$1,300 million United States segment of theAlberta Clipper project. As a result of this investment, in December 2009, theUS$350 million credit facilities were cancelled. Further, in 2009, EEP repaidan affiliate loan owing to the Company in the amount of US$130 million.

 

 

43

----

 

The following tableprovides 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 ifcertain conditions related to the project are met.

2                  Includesfacility draws and commercial paper issuances, net of discount, that areback-stopped by the credit facility.

 

The Company’scredit facility agreements include standard default and covenant provisionswhereby accelerated repayment may be required if the Company were to default onpayment or violate certain covenants. As in prior years, the Company expects tocontinue to comply with these provisions and therefore not trigger any earlyrepayments. As at December 31, 2009, the Company was in compliance will alldebt covenants.

** **

The Companycontinues to manage its debt to capitalization ratio to maintain a strongbalance sheet. The Company’s debt to capitalization ratio at December 31, 2009,including short-term borrowings but excluding non-recourse debt and projectfinancing, was 63.6%, compared with 63.6% at the end of 2008. Including alldebt, the capitalization ratio was 66.1% at December 31, 2009 compared with66.6% at December 31, 2008.

 

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

 

Excluding currentmaturities of long-term debt, the Company has a positive working capitalposition, 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-terminvestments.

 

Changes incommodity prices impact accounts receivable and other, inventory and accountspayable and other within Energy Services and EGD.

 

**OPERATINGACTIVITIES**

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

 

 

44

----

 

There are no material restrictions on the Company’s cashwith the exception of proportionately consolidated joint venture cash of $52million, which cannot be accessed untildistributed 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 $453million. Additions to property, plant and equipment of $3,225 million for theyear ended December 31, 2009 related primarily to capital expenditures ongrowth projects, most notably Southern Lights and Alberta Clipper. Offsettingthese 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-terminvestments and affiliate lending. Additions to long-term investments in 2009include $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 thedebt component of the Alberta Clipper Project which was offset by the repaymentby EEP of a US$130 million affiliate loan. In 2008, the Company increased itsinvestment in EEP by subscribing for 16.3 million Class A common units forUS$500 million.

 

Cash used for investing activities for the year endedDecember 31, 2008 was $2,853 million compared with $2,229 million in 2007. Theincrease was due to additional capital expenditures on growth projects and corecapital maintenance expenditures in 2009 compared with 2008, as well as anadditional investment in EEP in November 2008. Partially offsetting theseincreases was proceeds of $1,383 million on the sale of the Company’sinvestment 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 aredescribed in Growth Projects. TheCompany also requires capital for ongoing core maintenance and capitalimprovements in many of its businesses. In total, Enbridge expects to spendapproximately $2,509 million during 2010 on maintenance and capital projects, includingequity investments in EEP and EELP (within Sponsored Investments), which aresubstantially secured. While consistent or still in excess of longer termhistoric levels, the expected decline in 2010 expenditures relative to 2009 and2008 reflects the completion of certain large multi-year construction projects.The 2010 expected corporate capital expenditures increase reflects new greeninvestments in wind and solar power generation. The Company expects to financethese expenditures through cash from operating activities and availableliquidity. The Company may also raise capital through the monetization ordisposition of selected assets, or through access to capital markets asrequired.

 

The decision to finance with debt or equity is basedon the capital structure for each business and the overall capitalization ofthe consolidated enterprise. Certain of the regulated pipeline and gasdistribution businesses issue long-term debt to finance capital expenditures.This external financing may be supplemented by debt or equity injections fromthe parent company. Debt, and equity when required, has been issued by theCompany to finance business acquisitions, investments in subsidiaries andlong-term investments. Funds for debt retirements are generated through cashprovided from operating activities as well as through the issuance ofreplacement debt.

 

***FinancingActivities***

In 2009, the Company generated cash of $1,109 millionthrough financing activities compared with $1,840 million and $904 million in2008 and 2007, respectively.

 

 

45

----

 

Significant financing activities in 2009 includemedium-term note issues of $1,500 million compared with $498 million in 2008and $1,342 million in 2007. In 2009, the Company issued both a $400 million seven-yearand 10-year term note along with a $200 million 30-year term note. EnbridgePipelines Inc. (EPI) issued $300 million and $200 million in 10-year and30-year term notes, respectively. In comparison, in 2008 EGD issued a $200million 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 theUnited States market by the Company and $200 million of term notes issued byEGD in the Canadian market. Cash generated through debenture and term noteissues is partially offset by repayments of debentures and term notes whichtotaled $516 million, $602 million and $635 million for the years endedDecember 31, 2009, 2008 and 2007, respectively.

 

In 2008, the Company secured financing that isnon-recourse to the Company specific to the Canadian and United States segmentsof the Southern Lights project.  Netproceeds on Southern Lights financing were $343 million for the year endedDecember 31, 2009 and $1,238 million for the year ended December 31, 2008.

 

Short-term borrowings are used primarily to financenear term working capital requirements, including inventory at EGD. Due to thedecline in natural gas commodity prices in 2009 compared with 2008, and theresultant decline in cash needed to finance inventory requirements, the Companymade net repayments on short term borrowings totaling $366 million in2009.  In comparison, the net change inshort-term borrowings provided cash of $329 million in 2008, and a netrepayment of short-term borrowings of $262 million was made in 2007.

 

Participants in the Company’s Dividend Reinvestmentand Share Purchase Plan receive a 2% discount on the purchase of common shareswith reinvested dividends. For the year ended December 31, 2009, dividends declaredwere $555 million (2008 - $489 million), of which $414 million (2008 - $359million) were paid in cash and reflected in financing activities. The remaining$141 million of dividends declared were reinvested pursuant to the plan andresulted in the issuance of common shares rather than a cash payment. For theyear ended December 31, 2009 and December 31, 2008, 25% and 27%, respectively,of total dividends declared were reinvested.

 

**Outstanding Share Data****1**
|                                                                |   | 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 isprovided as at February 10, 2010.

 

***CONTINGENCIES AND COMMITMENTS***

*** ***

**Enbridge Gas Distribution INC.**

**Bloor Street Incident**

EGD was charged under both theOntario Technical Standards and Safety Act (TSSA) and the Ontario OccupationalHealth and Safety Act (OHSA) in connection with an explosion that occurred onBloor Street West in Toronto in April 2003. In October 2007, all of the TSSAand 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 Justiceand the appeal was heard by the Court during November and December 2009. TheCourt’s decision has been reserved and EGD expects it to be released in early2010. EGD does not believe any fines that may be levied would have a materialfinancial impact on EGD.

 

EGD has also beennamed as a defendant in a number of civil actions related to the explosion. Allsignificant civil actions have been settled without any material financialimpact on EGD. A Coroner’s Inquest in connection with the explosion is alsopossible.

 

**OTHER TAX MATTERS**

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

 

**OTHER LITIGATION**

The Company and itssubsidiaries are subject to various other legal and regulatory actions andproceedings which arise in the normal course of business, includinginterventions in regulatory proceedings and challenges to regulatory approvalsand permits by special interest groups. While the final outcome of such actionsand proceedings cannot be predicted with certainty, Management believes thatthe resolution of such actions and proceedings will not have a material impacton the Company's consolidated financial position or results of operations.

 

 

46

----

 

**COMMITMENTS**

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

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

 

**CONTRACTUAL OBLIGATIONS**

Payments due for contractual obligations over the next fiveyears 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 requirementsdependent on the terms of any debt re-financing agreements.

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

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

4      Assumesonly required payments will be made into the pension plans in 2010.Contributions are made in accordance with the independent actuarial valuationsas of December 31, 2009. Contributions, including discretionary payments, mayvary pending future benefit design and asset performance.

 

**QUARTERLYFINANCIAL INFORMATION****1**

 

*(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 beenextracted from financial statements prepared in accordance with Canadian GAAP.

 

Severalfactors impact comparability of the Company’s financial results on a quarterlybasis, including, but not limited to, seasonality in the Company’s gasdistribution businesses, fluctuations in market prices such as foreign exchangerates and commodity prices, disposals of investments or assets and the timingof in-service dates of new projects.

 

EGD and theCompany’s other gas distribution businesses are subject to seasonal demand. Asignificant portion of gas distribution customers use natural gas for spaceheating; therefore, volumes delivered and resultant revenues and earningstypically increase during the winter months of the first and fourth 

 

 

47

----

 

quarters ofany given year. Revenues generated by EGD and other gas distribution businessesalso vary from quarter-to-quarter with fluctuations in the price of naturalgas, although earnings remain neutral due to the pass through nature of thesecosts. Further, in EGD, as a result of continued changes in customer billing toincrease the fixed charge portion and decrease the per unit volumetric charge,revenues and earnings will shift from the colder winter quarters progressivelyto the warmer summer quarters, with no material impact on full year revenue andearnings. This change will also impact the comparability of a given quarterfrom year to year. In each of the four quarters of 2009, revenues generated byEGD and other gas distribution businesses have declined compared with thecorresponding quarters of 2008 primarily due to depressed natural gas pricesthroughout 2009 compared with the prior year.

 

The Companyactively manages its exposure to market price risks including, but not limitedto, commodity prices and foreign exchange rates. To the extent derivativeinstruments used to manage these risks are non-qualifying for the purposes ofhedge accounting, unrealized fair value gains and losses on these instrumentswill impact earnings. Most notably, earnings were negatively impacted by anunrealized derivative fair value loss of $43 million in the first quarter of2009, and positively impacted by unrealized derivative fair value gains of $115million, $102 million and $33 million for the second, third and fourth quartersof 2009, respectively. In comparison, earnings for the fourth quarter of 2008included an unrealized derivative fair value gain of $26 million, while thefirst three quarters of 2008 had no similar impact. Further, second, third andfourth quarter earnings of 2009 include unrealized foreign exchange gains ontranslation 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 again of $329 million on the disposition of the Company’s investment in OCENSAin the first quarter of 2009 and a gain on sale of the Company’s investment inCLH in the amount of $556 million in the second quarter of 2008.

 

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

 

**Related Party Transactions**

** **

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

 

EEP,an equity investee, does not have employees and uses the services of theCompany for managing and operating its businesses. Vector Pipeline, a jointventure, contracts the services of Enbridge to operate the pipeline. Amountsfor these services, which are charged at cost in accordance with serviceagreements, for the year ended December 31, 2009 are $342 million (2008 - $302million; 2007 - $267 million) to EEP and $6 million (2008 - $6 million; 2007 -$5 million) to Vector Pipeline. At December 31, 2009, the Company has accountsreceivable of $38 million (2008 - $41 million) from EEP and $1 million (2008 -$1 million) from Vector Pipeline.

 

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

 

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

 

 

48

----

 

Enbridge Gas Services (US) Inc., asubsidiary of the Company, purchases and sells gas at prevailing market priceswith Enbridge Marketing (US) Inc., a subsidiary of EEP. For the year endedDecember 31, 2009, amounts purchased were $16 million (2008 - $52 million; 2007- $43 million) and sales were $6 million (2008 - $7 million; 2007 - $4million).

 

Enbridge Gas Services Inc. andEnbridge Gas Services (US) Inc., subsidiaries of the Company, havetransportation commitments, measured at market value, through 2015 on AlliancePipeline Canada, Alliance Pipeline US and Vector Pipeline. For the year endedDecember 31, 2009, amounts paid to Alliance Pipeline Canada were $9 million(2008 - $9 million; 2007 - $8 million), amounts paid to Alliance Pipeline USwere $7 million (2008 - $7 million; 2007 - $7 million) and amounts paid toVector Pipeline were $16 million (2008 - $16 million; 2007 - $16 million).

 

Tidal Energy Marketing Inc., asubsidiary of the Company, purchases and sells commodities at prevailing marketprices 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) andsales were $7 million (2008 - $9 million; 2007 - $6 million).

 

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

 

**AlbertaClipper PROJECT**

In July 2009, the Company committed tofund 66.7% of the cost to construct the United States segment of the AlbertaClipper Project. The total cost of the United States segment, which is expectedto 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 thisproject is included in GROWTH PROJECTS.

 

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

 

InAugust 2008, the Company transferred $23 million, measured at market value, of36 inch diameter line pipe to EEP for use in constructing the United Statessegment of the Alberta Clipper Project.

 

**Spearhead NORTHPipeline**

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

 

**Southern Lights Project**

In February 2009, as part of its SouthernLights Pipeline Project, the Company transferred the United States section of anewly constructed light sour pipeline to EEP in exchange for a pipelinereferred to as Line 13. This non-monetary transaction has been recorded at thecarrying amount.

 

In connection with the exchange discussedabove, EEP entered into an arrangement to lease Line 13 from the Company formonthly payments of US$2 million to ensure adequate southbound pipelinecapacity prior to the completion of the Alberta Clipper Project. The leasearrangement was effective in February 2009 and can be terminated at any timewith written notice.

 

**LONG-TERM Receivable fromAffiliate**

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

 

 

49

----

 

**RISK MANAGEMENT**

 

Enbridge’s value proposition isbased on maintaining a very low risk profile. Over 85% of the Company’searnings come from regulated businesses; over 80% of its revenues are volumeprotected under cost of service rate-making or long-term take-or-payarrangements; and more than 95% of the Company’s revenues come from investmentgrade customers. Other risks, such as capital cost and inflation, are generallytransferred to customers through contractual arrangements. In addition tocontractually eliminating the majority of its business risk, the Company hasformal risk management policies, procedures and systems designed to mitigateany residual risks, such as market price risk, credit risk and operationalrisk. In addition, the Company performs an annual corporate risk assessment toscan its environment for all potential risks. Risks are ranked based onseverity and likelihood and results are considered in the Company’s strategicand operating plans. Through this process, a range of ongoing mitigants areidentified and implemented.

 

**Market Price Risk**

The Company’s earnings, cash flows and other comprehensiveincome (OCI) are subject to movements in foreign exchange rates, interest ratesand commodity prices (collectively, market price risk). Given the Company’sdesire to maintain a stable and consistent earnings profile, it has implementeda Market Price Risk Management Policy which outlines a risk managementgovernance framework and specific exposure limits to minimize the likelihoodthat adverse earnings fluctuations arising from movements in market pricesacross all of its businesses will exceed a defined tolerance.

 

Earnings at Risk (EaR), a variant ofValue at Risk, is the principal risk management metric used to quantify marketprice risk sensitivity at Enbridge. EaR is an objective, statistically derivedrisk metric that measures the maximum adverse change in projected 12-monthearnings that could result from market price risk over a one-month periodwithin a 97.5% confidence interval. The philosophy behind this metric is toidentify the potential risk to the Company’s annual earnings target, takinginto account the illiquidity of certain exposure positions. The Company’spolicy is to limit EaR to a maximum of 5% of the next 12 months of forecastedearnings. Earnings exposure to market price risk is managed within the overallconsolidated EaR limits of the Company. Further, commodity price risk ismanaged within business unit EaR sub-limits.

 

Various hedging programs have beenput into place to help ensure that the residual market price risks remainwithin policy limits, and thus help provide the Company with a generalstability of earnings over a short and medium term horizon. The followingsection summarizes the primary types of market price risks to which the Companyis 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 arisingfrom the performance of its United States dollar denominated subsidiaries. TheCompany has implemented a policy where it must hedge a minimum level of foreigncurrency denominated earnings exposures identified over the next five yearperiod. The Company currently has hedged over 80% of its forecast adjustedearnings through 2014 at an average rate of approximately $1.20 C$/US$. TheCompany may also hedge anticipated foreign currency denominated purchases orsales, foreign currency denominated debt, as well as certain equity investmentbalances and net investments in foreign denominated subsidiaries.

 

**Interest Rate Risk**

The Company’s earnings and cashflows are exposed to short term interest rate variability due to the regularrepricing of its variable rate debt obligations. Floating to fixed interestrate swaps and options are used to hedge against the effect of future periodinterest rate movements. The Company has implemented a hedging program tosignificantly mitigate the volatility to variable rate interest expense through2013 at an average rate of 2.2%.

 

The Company’s earnings and cashflows are also exposed to variability in longer term interest rates on futurefixed rate debt issuances. Forward starting interest rate swaps are used tohedge against the effect

 

 

50

----

 

of future interest rate movements.The Company has implemented a hedging program to significantly mitigate itsexposure to long term interest rate variability on select forecast term debtissuances through 2013. A total of $2,500 million of future fixed rate termdebt issuances have been hedged at an average government bond rate of 4%.Further, many of the Company’s existing commercial arrangements and certainconstruction projects provide for the full recovery of financing costs throughtolls.

 

The Company also monitors its debtportfolio mix of fixed and variable rate debt instruments to ensure that theconsolidated portfolio of debt stays within its Board of Directors’ approvedpolicy limit band of a maximum of 25% floating rate debt as a percentage oftotal debt outstanding.

 

**Commodity Price Risk**

The Company’s earnings and cashflows are exposed to changes in commodity prices as a result of ownershipinterest in certain assets, as well as through the activities of its energyservices subsidiaries. The Company uses natural gas, power, crude oil and NGLderivative instruments to fix a portion of the variable price exposures thatmay arise from commodity usage, storage, transportation and supply agreements.

 

The Company has implemented ahedging program, through 2011, to mitigate the volatility from fractionationspreads (natural gas/NGLs) that impact earnings from its ownership in the AuxSable natural gas processing plant.

 

The following table summarizes theEaR as a percentage of forecast earnings from the main groups of market pricerisk after the impact of the Company’s hedging programs. These EaR numbers arebased on business conditions and hedging programs as of December 31, 2009 andmay 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 tothe risk of payment default by its shippers or other counterparties. Given theCompany’s desire to maintain a stable and consistent earnings profile, it hasimplemented a Counterparty Credit Risk Policy outlining a governance frameworkand specific exposure limits to minimize the likelihood that adverse earningsfluctuations arise from counterparty defaults across any of its businesses.

 

Further initiatives to mitigatecredit exposure include ensuring that all counterparties shipping on theregulated oil pipelines that have credit ratings below investment grade providethe carrier with a form of credit assurance, for example, a creditworthyparental guarantee, letter of credit or cash.

 

Credit risk in the Natural GasDelivery and Services segment is mitigated by its large and diversified customerbase and its ability to recover an estimate for doubtful accounts through theratemaking process. The Company actively monitors the financial strength oflarge industrial customers and, in select cases, has tightened credit terms,including obtaining additional security, to minimize the consequences of therisk of default on receivables. Generally, the Company classifies receivablesolder than 30 days as past due.

 

The Company minimizes credit risk toderivatives counterparties by entering into risk management transactions onlywith institutions that possess solid investment grade credit ratings or whichhave provided the Company with an acceptable form of credit protection. TheCompany has no significant

 

 

51

----

 

concentration with any singlecounterparty. During 2008, the Company reduced its exposure to certainfinancial counterparties through the discontinuance of certain hedges. Fortransactions with terms greater than five years, the Company may also require acounterparty that would otherwise meet the Company’s credit criteria to providecollateral.****During 2009, despitethe severe market conditions, the Company did not suffer any material creditlosses.

 

**Financing Risk**

The Company’s financing risk relatesto the price volatility and availability of debt to finance organic growthprojects and refinance existing debt maturities. This risk is directlyinfluenced by market factors, as Canadian and United States financial marketconditions can change dramatically, affecting capital availability.

 

To address this risk, the Companymaintains sufficient liquidity through committed credit facilities with itsdiversified banking groups designed to enable the Company to fund allanticipated requirements for one year without accessing the capital markets. Inaddition, the Company strives to ensure that it can readily access the Canadianand United States public capital markets by maintaining current shelfprospectuses with the securities regulators.

 

**Liquidity Risk**

Liquidity risk is the risk that theCompany will not be able to meet its financial obligations, includingcommitments and guarantees. To manage this risk, the Company forecasts the cashrequirements over the near and long term to determine whether sufficient fundswill be available. The Company’s primary sources of liquidity and capitalresources are funds generated from operations, the issuance of commercial paperand draws under committed credit facilities, as well as medium-term notes. TheCompany maintains current shelf prospectuses with the securities regulators,which enables, subject to market conditions, ready access to either theCanadian or United States public capital markets.

 

**Maturities ofDerivative Financial Liabilities**

For the years ending December 31,2010 through 2014, and thereafter, the Company has estimated the followingundiscounted cash flows will arise from its derivative instruments based onvaluation 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 liabilitiesis presented in Liquidity and CapitalResources.

 

**GENERAL BUSINESSRISKS**

** **

**Execution Risk**

The Company’s ability tosuccessfully execute the development of its organic growth projects may beinfluenced by capital constraints, third-party opposition, changes in shippersupport 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 itsresources and may be subject to high cost pressures in the North Americanenergy sector. Early stage project risks include right-of-way procurement,special interest group opposition, Crown consultation, and environmental andregulatory permitting. Cost escalations may impact project economics.Construction delays due to slow delivery of materials, contractornon-performance, weather conditions and shortages may impact projectdevelopment. Labour shortages, inexperience and productivity issues may alsoaffect the successful completion of the projects.

 

 

52

----

 

The Company has a centralized andclearly defined governance structure and process for all major projects withdedicated resources organized to lead and execute each major project. Capitalconstraints and cost escalation risks are mitigated through structuring ofcommercial agreements, typically where shippers retain complete or a share ofcapital cost excess. The Company’s emphasis on corporate social responsibilitypromotes generally positive relationships with landowners, aboriginal groupsand governments which help to facilitate right-of-way acquisition, permittingand schedule. Detailed cost tracking and centralized purchasing is used on allmajor projects to facilitate optimum pricing and service terms. Strategic relationshipshave been developed with suppliers and contractors. Compensation programs,communications and the working environment are aligned to attract, develop andretain qualified personnel.

 

**Pipeline OperatingRisk**

Pipeline leaks are an inherent riskof operations. Other operating risks include: the breakdown or failure ofequipment, information systems or processes; the performance of equipment atlevels below those originally intended (whether due to misuse, unexpecteddegradation or design, construction or manufacturing defects); failure tomaintain adequate supplies of spare parts; operator error; labour disputes;disputes with interconnected facilities and carriers; and catastrophic eventssuch as natural disasters, fires, explosions, fractures, acts of terrorists andsaboteurs and other similar events, many of which are beyond the control of thepipeline systems. The occurrence or continuance of any of these events couldincrease the cost of operating the Company’s pipelines or reduce revenues, therebyimpacting earnings.

 

The Company has an extensive programto manage system integrity, which includes the development and use of in-lineinspection tools. Maintenance, excavation and repair programs are directed tothe areas of greatest benefit and pipe is replaced or repaired as required. TheCompany also maintains comprehensive insurance coverage for significantpipeline leaks and has a comprehensive security program designed to reducesecurity-related risks. While the Company feels the level of insurance isadequate, it may not be sufficient to cover all potential losses.

 

**Regulation**

Many of the Company’s pipelineoperations are regulated and are subject to regulatory risk. The nature anddegree of regulation and legislation affecting energy companies in Canada andthe United States has changed significantly in past years and there is noassurance that further substantial changes will not occur. These changes mayadversely affect toll structures or other aspects of pipeline operations or theoperations of shippers. Recently shippers have challenged toll increases onvarious pipelines owned by some of Enbridge’s competitors, and certain ofEnbridge’s shippers have sought to delay the in-service date and implementationof the tariff on the Company’s Alberta Clipper Project. Enbridge retainsdedicated 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, facilitiesand petroleum product shipments are subject to extensive national, regional andlocal environmental, health and safety laws and regulations governing, amongother things, discharges to air, land and water, the handling and storage ofpetroleum compounds and hazardous materials, waste disposal, the protection ofemployee health, safety and the environment, and the investigation andremediation of contamination. The Company’s facilities could experienceincidents, malfunctions or other unplanned events that result in spills oremissions in excess of permitted levels and result in personal injury, fines,penalties or other sanctions and property damage. The Company could also incurliability in the future for environmental contamination associated with past andpresent activities and properties. The facilities and pipelines must maintain anumber of environmental and other permits from various governmental authoritiesin order to operate and these facilities are subject to inspection from time totime. Failure to maintain compliance with these requirements could result inoperational interruptions, fines or penalties, or the need to installpotentially costly pollution control technology. Compliance with current andfuture environmental laws and regulations, which are likely to become morestringent over time, including those governing GHG emissions, may imposeadditional capital costs and financial expenditures and affect the demand forthe Company’s services, which could

 

 

53

----

 

adversely affect operating resultsand profitability. Restrictions on other resources, such as water orelectricity, may affect the Company’s upstream customers’ ability to producecrude oil and natural gas. The Company could be targeted, along with the oilsands industry, by environmental groups attempting to draw attention to GHGemissions.

 

Enbridge is committed to protectingthe health and safety of employees, contractors and the general public, and tosound environmental stewardship. The Company believes that prevention ofincidents and injuries, and protection of the environment, benefits everyoneand delivers increased value to shareholders, customers and employees. Enbridgehas health and safety and environmental management systems and has establishedpolicies, programs and practices for conducting safe and environmentally soundoperations. Regular reviews and audits are conducted to assess compliance withlegislation and Company policy.

 

**Aboriginal Relations**

Canadian judicial decisions have recognized that Aboriginalrights and treaty rights exist in proximity to the Company’s operations andfuture project developments. The courts have also confirmed that the Crown hasa duty to consult with Aboriginal peoples when its decisions or actions mayadversely affect Aboriginal rights and interests or treaty rights. Crownconsultation has the potential to delay regulatory approval processes andconstruction, which may affect project economics. In some cases, respectingAboriginal rights may mean regulatory approval is denied or made economicallychallenging.

 

Given this environment and the breadth of relationshipsacross the Company’s geographic span, Enbridge has recently reviewed andupdated its Indigenous Peoples Policy, which has been renamed the Aboriginaland Native American Policy. The new Policy promotes the achievement ofparticipative and mutually beneficial relationships with Aboriginal and NativeAmerican groups affected by the Company’s projects and operations.Specifically, the Policy sets out principles governing the Company’srelationships with Aboriginal and Native American peoples and makes commitmentsto work with Aboriginal peoples and Native Americans so they may realizebenefits from the Company’s projects and operations. Notwithstanding theCompany’s efforts to this end, the issues are complex and the impact ofAboriginal relations on Enbridge’s operations and development initiatives isuncertain.

 

**Special InterestGroups**

The Company is exposed to the riskof higher costs, delays or even project cancellations due to increasingpressure on government and regulators by special interest groups. RecentSupreme Court decisions have increased the ability of special interest groupsto make claims and oppose projects in regulatory and legal forums. The Companyworks proactively with special interest groups to identify and develop anappropriate response to concerns regarding its projects. The Company’sCorporate Social Responsibility (CSR) program also reports on the Company’sresponsiveness to environmental and community issues. Please see Enbridge’sannual CSR report, available online at www.enbridge.com/csr2009 for furtherdetails regarding the CSR program.

 

**Legislation Risk**

**Climate Change Legislation**

The Canadian Federal Government has indicated that Canadawill target a 17% reduction of GHG emissions by 2020, based on 2006 emissionlevels. It has also signaled that 90% of Canada’s electricity will be providedby non-emitting sources, such as hydro, nuclear, clean-coal, solar and wind, by2020. Details of Canada’s GHG management plan will not be released until thereis clarity in the United States about its intention to regulate GHG emissions.Canadian regulations will likely be compatible with those of the United Statesin order for Canadian businesses to remain competitive and avoid the potentialfor punitive trade sanctions. It is uncertain how climate legislation couldaffect the industry. Enbridge continues to monitor this activity.

 

**Low Carbon Fuel Standards**

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

 

 

54

----

 

conventional crude. Flow restrictions of oil sands productsto the United States would increase interest in exports to Asia, andconsequently increase interest in projects like Enbridge’s Northern GatewayProject.

 

**Renewable Energy**

Enbridge has significant interest in wind and solar powerand is well positioned to expand this portfolio. Many programs to encourage andadvance renewable energy exist in Canada and the United States as well asindividual provinces and states. For example, the Feed-in-Tariff programintroduced by the Ontario Green Energy Act has created significantopportunities for renewable energy growth in Ontario. The extension of theProduction Tax Credit, introduction of a federal cash grant and the potentialfor a nationwide minimum Renewable Portfolio Standard have acceleratedrenewable energy projects across the United States. Enbridge continues toassess and advance renewable energy opportunities and monitor potential changesto government policies and incentives that may positively or negatively impactrenewable energy projects in a particular province, state or federaljurisdiction.

 

**WorkforceDevelopment**

A lack of qualified and properlytrained technical, professional and operational staff and leaders wouldincrease the risk that the Company will not be able to implement its corporatestrategy. This risk may be compounded by the increasing rates of retirement dueto workforce demographics, turnover due to competition in certain markets andgrowing demand for staff to support business growth. The Company continues tomonitor company-wide workforce planning. The Company offers competitivecompensation programs, training, leadership development and succession planning.Further, the supply of human resources is balanced between hiring full-timeemployees and expanding the contractor workforce, particularly in the MajorProjects’ department.

 

**Terrorism**

The risk of terrorism continues tobe monitored due to the high profile of the petroleum industry in Canada andthe reliance of the United States on Canadian exports. An act of terrorism mayresult in the loss of upstream supplies, pipelines, distribution or storagecontrols systems with safety and environmental implications. The Companymanages this risk through its Human Resources Protection Program, CrisisManagement Plan and insurance programs where available.

 

**FINANCIALINSTRUMENTS**

 
| ** **                         | **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 ** |

 

 

55

----

 
| ** **                         | 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, whichincludes investments accounted for under the equity method, and available forsale equity instruments held at cost that do not trade on an actively quotedmarket.

 

**Fair Value ofFinancial Instruments**

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

 

The fair value of cash and cashequivalents and short-term borrowings approximates their carrying value due totheir short-term maturities. The fair value of the Company’s long-terminvestments, other than those classified as available for sale, approximatestheir carrying value due to the nature of the investments. The fair value ofthe Company’s long-term debt and non-recourse long-term debt is based on quotedmarket prices for instruments of similar yield, credit risk and tenure. Thefair value of other financial assets and liabilities other than derivativeinstruments approximate their cost due to the short period to maturity. Changesin the fair value of financial liabilities other than derivative instrumentsare due primarily to fluctuations in interest rates and time value.

 

 

56

----

 

 

**Derivative Instruments**

The following table summarizes the maturity and totalnotional principal or quantity outstanding related to the Company’s derivativeinstruments. The Company does not have any credit-risk related contingentfeatures 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 |

 

 

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                       |

 

 

58

----

 
| *(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 estimatedusing period end market information. This market information includesobservable inputs such as published market prices for commodities, interestrate yield curves and foreign exchange rates. When possible, financialinstruments are valued using quoted market prices.

 

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

 

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

 

 

59

----

 

 

**criticalaccounting ESTIMATES**

 

**DEPRECIATION**

Depreciationof property, plant and equipment, the Company’s largest asset with a net bookvalue at December 31, 2009 of $18,850 million, or 67% of total assets, isgenerally provided on a straight-line basis over the estimated service lives ofthe assets commencing when the asset is placed in service. When it isdetermined that the estimated service life of an asset no longer reflects theexpected remaining period of benefit, prospective changes are made to the estimatedservice life. Estimates of useful lives are based on third party engineeringstudies, experience and/or industry practice. There are a number of assumptionsinherent in estimating the service lives of the Company’s assets including thelevel of development, exploration, drilling, reserves and production of crudeoil and natural gas in the supply areas served by the Company’s pipelines aswell as the demand for crude oil and natural gas and the integrity of theCompany’s systems. Changes in these assumptions could result in adjustments tothe estimated service lives, which could result in material changes todepreciation expense in future periods in any of the Company’s businesssegments. For certain rate regulated operations, depreciation rates areapproved by the regulator and the regulator may require periodic studies ortechnical updates on useful lives which may change depreciation rates.

 

**Regulatory Assets and Liabilities**

Certain of the Company’s LiquidsPipelines and Natural Gas Delivery and Services businesses are subject toregulation by various authorities, including but not limited to, the NEB, theFERC, the Energy Resources Conservation Board (ERCB) and the OEB. Regulatorybodies exercise statutory authority over matters such as construction, ratesand ratemaking, and agreements with customers. To recognize the economiceffects of the actions of the regulator, the timing of recognition of certainrevenues and expenses in operations may differ from that otherwise expectedunder GAAP for non rate-regulated entities. Also, the Company recordsregulatory assets and liabilities to recognize the economic effects of theactions of the regulator. Regulatory assets represent amounts that are expectedto be recovered from customers in future periods through rates. Regulatoryliabilities represent amounts that are expected to be refunded to customers infuture periods through rates. On refund or recovery of this difference, noearnings impact is recorded. Effectively, the income statement captures only theapproved costs and the related revenue rather than the actual costs and relatedrevenue. As of December 31, 2009, the Company’s regulatory assets totaled$1,411 million (2008 - $635 million) and regulatory liabilities totaled $1,038million (2008 - $109 million). To the extent that the regulator’s actionsdiffer from the Company’s expectations, the timing and amount of recovery orsettlement of regulatory balances could differ significantly from thoserecorded.

 

**Post Employment Benefits**

The Company maintains pension plans,which provide defined benefit and/or defined contribution pension benefits andother post-employment benefits (OPEB) to eligible retirees. Pension costs andobligations for the defined benefit pension plans are determined using the projectedbenefit method. This method involves complex actuarial calculations usingseveral assumptions including discount rates, expected rates of return on planassets, health-care cost trend rates, projected salary increases, retirementage, mortality and termination rates. These assumptions are determined bymanagement and are reviewed annually by the Company’s actuaries. Actual resultsthat differ from assumptions are amortized over future periods and thereforecould materially affect the expense recognized and the recorded obligation infuture periods. The Company remains able to pay the current benefit obligationsusing cash from operations, reflecting strong capital market performancerecovery. The shortfall from expected return on plan assets was $24 million forthe year ended December 31, 2009 (2008 - $288 million) as disclosed in Note 27to the 2009 Annual Consolidated Financial Statements. The difference betweenthe actual and expected return on plan assets is amortized over the remainingservice period of the active employees.

 

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

 

The following sensitivity analysisidentifies the impact on the December 31, 2009 Consolidated FinancialStatements of a 0.5% change in key pension and OPEB assumptions.

 

 

60

----

 
|                                   |                 |        |
|----------------------------------------|----------------------|-------------|
| *(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 againstthe Company are determined on a case by case basis. Case estimates are reviewedon a regular basis and are updated as new information is received. The processof evaluating claims involves the use of estimates and a high degree ofmanagement judgment. Claims outstanding, the final determination of which couldhave a material impact on the financial results of the Company and certain ofthe Company’s subsidiaries and investments, including EGD and EECI, aredetailed in the Commitments and Contingencies section of this report and aredisclosed in Note 31 of the 2009 Annual Consolidated Financial Statements.

 

**Asset Retirement Obligations**

In May 2009, the NEB released a report on the financialissues associated with pipeline abandonment. The NEB will require all companiesto formally assess the timeline and cost of future abandonment and, ifnecessary, set aside funds to cover future abandonment costs. All pipelinesregulated under the NEB Act will be required to comply with the report’sframework and action plan. The NEB began hosting technical meetings inSeptember 2009 to evaluate how abandonment estimates will be calculated andsubmitted, 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 forabandonment no later than the end of May 2014. Currently, for certain of theCompany’s assets, it is not practical to make a reasonable estimate of assetretirement obligations for accounting purposes due to the indeterminate timingand the scope of asset retirements. However, should the NEB action plan resultin a reasonable estimate of asset retirement obligations for accountingpurposes, financial statement recognition of those obligations may be made infuture periods. As a result, regulatory assets and liabilities may berecognized to the extent the timing of recovery from shippers differs from therecognition of abandonment costs for accounting purposes.

 

**CHANGE IN ACCOUNTING POLICIES**

 

**ACCOUNTING FOR THE EFFECTS OF RATE REGULATION**

Effective January1, 2009, the Company adopted revisions to the Canadian Institute of CharteredAccountants (CICA) Handbook Section 1100, *GenerallyAccepted Accounting Principles* and Section 3465, *Income Taxes*. In accordance with thetransitional provisions in these revised standards, the revisions to Section1100 were adopted prospectively and, accordingly, prior periods were notrestated, while the revisions to Section 3465 were applied retrospectivelywithout restatement of prior periods. The adoption of the revised standards didnot impact the Company’s earnings or cash flows.

 

**Generally Accepted Accounting Principles**

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

 

**Pension Plans and OPEB**

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

 

 

61

----

 

pension regulatoryliability 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 collectedfor future removal and site restoration of $657 million, which were previouslynetted against Property, Plant and Equipment, to a long-term regulatoryliability. At December 31, 2009, this long-term regulatory liability was $710million.

 

**Income Taxes**

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

** **

**INTANGIBLE ASSETS**

Effective January1, 2009, the Company adopted CICA Handbook Section 3064, *Goodwill and Intangible Assets*, whichestablishes standards for the recognition, measurement, presentation anddisclosure of goodwill and intangible assets. As a result of adopting thisstandard, the Company reclassified certain software costs from Property, Plantand Equipment to Intangible Assets. This standard has been appliedretrospectively and affects presentation only.

 

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

 

**COMMODITY INVENTORY**

Effective January 1, 2009, theCompany changed its accounting policy for inventory held by its energymarketing businesses and began measuring commodity inventory at fair value, asmeasured at the spot price less costs to sell, rather than lower of cost or netrealizable value. This measurement basis is a more relevant measurement forcommodity inventory used for marketing purposes and better matches thecommodity inventory with the derivatives used to “lock in” the margin. Thischange in accounting policy has been accounted for retrospectively and did notresult in restatements of the comparative Consolidated Statements of Earnings,Comprehensive Income, Shareholders’ Equity or Cash Flows for the years endedDecember 31, 2008 and 2007 and the comparative Consolidated Statement ofFinancial Position as at December 31, 2008 as the amounts were consideredimmaterial.

 

**INVENTORIES**

The CICA issued Handbook Section3031, *Inventories,* effectiveJanuary 1, 2008 which aligns accounting for inventories under Canadian GAAPwith International Financial Reporting Standards (IFRS) and replaces Section3030. The adoption of the revised standard did not have a significant effect onthe Company.

 

**CAPITAL DISCLOSURES AND FINANCIAL INSTRUMENTS –DISCLOSURES AND PRESENTATION**

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

 

**FINANCIAL INSTRUMENTS, COMPREHENSIVE INCOME ANDHEDGING RELATIONSHIPS**

Effective January 1, 2007, theCompany adopted CICA Handbook Section 1530, *ComprehensiveIncome*, Section 3251, *Equity*,Section 3855, *Financial Instruments –Recognition and Measurement*, Section 3861, *Financial Instruments – Disclosure and Presentation (*subsequentlyreplaced by Sections 3862 and

 

 

62

----

 

3863**adopted by the Company on January 1, 2008) and Section 3865, *Hedges*. In accordance with thetransitional provisions in these new standards, these policies were adopted retrospectivelywithout restatement. Prior period unrealized gains and losses related to theCompany’s foreign currency translation adjustments and net investment hedgesare now included in accumulated other comprehensive income (AOCI). Thecumulative impact of adopting these changes in 2007 was an increase to AOCI of $48million.

 

**FUTURE ACCOUNTINGPOLICIES**

**Business Combinations**

The CICA issued Handbook Section 1582, *Business Combinations*, which replacesSection 1581. This new standard aligns accounting for business combinationsunder Canadian GAAP with IFRS. The standard requires assets and liabilitiesacquired in a business combination to be measured at fair value at theacquisition date. The standard also requires acquisition-related costs, such asadvisory or legal fees, incurred to effect a business combination to beexpensed in the period in which they are incurred. The adoption of thisstandard will impact the accounting treatment of future business combinations.The revised standard is effective for business combinations occurring on orafter January 1, 2011; however, earlier application is permitted.

** **

**Consolidated Financial Statements andNon-Controlling Interests**

The CICA issued Handbook Sections 1601, *Consolidated Financial Statements*and1602,*Non-controlling Interests,*whichtogether replace the former consolidated financial statements standard. Underthe revised standards, non-controlling interests will be classified as acomponent of equity, and earnings and comprehensive income will be attributedto both the parent and non-controlling interest. The adoption of thesestandards is not expected to have a material impact to the Company’sconsolidated financial statements. The revised standards are effective January1, 2011. Should the Company early adopt Section 1582, it would also be requiredto adopt Sections 1601 and 1602 at the same time.

 

**International Financial Reporting Standards**

The CanadianAccounting Standards Board (AcSB) confirmed in February 2008 that publiclyaccountable entities will be required to adopt IFRS for interim and annualfinancial statements beginning on January 1, 2011, including comparativefinancial statements for 2010.

 

Enbridge’spreparations for IFRS conversion include preparing IFRS compliant accountingpolicies, drafting model IFRS financial disclosures, identifying accounting differences,developing and implementing systems solutions and process changes that supportthe preparation of 2010 comparative data as well as a sustainable conversion toIFRS in 2011.

 

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

 

**Accounting and Reporting**

To date,detailed IFRS compliant accounting policies and model financial statementdisclosures are complete. The Company’s IFRS compliant accounting policiesdiffer in some regards from the Company’s current accounting policies. The mostsignificant differences are expected to impact the following areas:

 

·                  property,plant and equipment

·                  decommissioningliabilities (asset retirement obligations)

·                  impairments

·                  consolidation

 

The Companyis carefully monitoring the International Accounting Standards Board’s (IASB)project on Rate Regulated Activities. The IASB’s exposure draft on RateRegulated Activities, published in July 2009, would allow the Company tocontinue to apply rate regulated accounting with some changes. It is notpossible to determine with certainty the extent of the changes to the Company’saccounting for rate regulated activities until the final standard is available.

 

 

63

----

 

The IASB’sproject on joint ventures proposes to eliminate the proportionate consolidationof joint ventures. If the project proceeds as proposed, the Company would applyequity accounting to its joint venture interests under IFRS instead ofproportionate consolidation. A final standard is expected to be publishedduring the first quarter of 2010 after which the Company will be able todetermine the impact of conversion to IFRS on its accounting for jointventures.

 

The Companyhas selected IFRS 1 elective exemptions which are practical and provide themost relevant presentation on conversion to IFRS. The primary result of theexemptions selected is to apply certain IFRS differences prospectively,minimizing adjustments to the IFRS opening balance sheet. The Company alsoexpects to elect to reduce cumulative translation differences to zero on thedate of adoption. This change would impact the Company’s retained earnings and AOCIbalances, both within the equity section of the balance sheet. In addition, theIASB’s exposure draft on Rate Regulated Activities includes an IFRS 1 exemptionwhich would allow the Company to use the carrying amount of rate regulatedproperty, plant and equipment, as calculated under Canadian GAAP, as the deemedcost 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 touse this exemption.

 

**Information Systems and Business Processes**

In January2010, the Company implemented changes to information systems and processeswhich ensure that data needed for IFRS reporting of 2010 financial informationfor comparative purposes is gathered. The Company has also developed processesto derive the 2010 opening balance sheet under IFRS and is building processesand systems solutions to create 2010 IFRS compliant quarterly financialinformation for comparative purposes.

 

During thefirst quarter of 2010, the Company will determine the systems solution whichwill be implemented in 2011 to support and sustain IFRS changes afterconversion. Process changes needed to sustain IFRS conversion starting in 2011have been identified, and during 2010, process design and training is expectedto be completed. Related impacts to internal controls over financial reportingand disclosure controls and procedures are expected to be identified during2010.

 

**Training and Communication**

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

 

**Business Activities**

The Companyhas reviewed the effect of IFRS conversion on its debt covenants, compensationagreements and hedging activities and does not expect the conversion to IFRS tosignificantly impact these activities or requirements.

 

The expectedtiming of key activities identified above may change prior to the IFRSconversion date due to changes in regulation, economic conditions or otherfactors and the issuance of new accounting standards or amendments to existingaccounting standards, including and in addition to those noted above.

 

**CONTROLS ANDPROCEDURES**

 

**DisclosureControls and Procedures**

Disclosure controls and proceduresare designed to provide reasonable assurance that information required to bedisclosed in reports filed with, or submitted to, securities regulatoryauthorities is recorded, processed, summarized and reported within the timeperiods specified under Canadian and United States securities law. As of theyear ended December 31, 2009, an evaluation was carried out under the supervisionof and with the participation of Enbridge’s management, including the ChiefExecutive Officer and Chief Financial Officer, of the effectiveness of thedesign and operations of Enbridge’s disclosure controls and procedures (asdefined in Rule 13a-15(e) under the Securities Exchange Act of 1934). Based onthat evaluation, the Chief Executive Officer and Chief Financial Officerconcluded that the

 

 

64

----

 

design and operation of thesedisclosure controls and procedures were effective in ensuring that informationrequired to be disclosed by Enbridge in reports that it files with or submitsto the Securities and Exchange Commission is recorded, processed, summarizedand reported within the time periods required.

 

**Management’s Reporton Internal Controls over Financial Reporting**

Management of Enbridge isresponsible for establishing and maintaining adequate internal control overfinancial reporting as such term is defined in the rules of the United StatesSecurities and Exchange Commission and the Canadian Securities Administrators.The Company’s internal control over financial reporting is a process designedunder the supervision and with the participation of executive and financialofficers to provide reasonable assurance regarding the reliability of financialreporting and the preparation of the Company’s financial statements forexternal reporting purposes in accordance with GAAP.

 

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

·                  pertain to themaintenance of records that, in reasonable detail, accurately and fairlyreflect transactions and dispositions of assets of the Company;

·                  provide reasonableassurance that transactions are recorded as necessary to permit preparation offinancial statements in accordance with generally accepted accountingprinciples; and

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

 

The Company’s internal control overfinancial reporting may not prevent or detect all misstatements because ofinherent limitations. Additionally, projections of any evaluation ofeffectiveness to future periods are subject to the risk that controls maybecome inadequate because of changes in conditions or deterioration in thedegree of compliance with the Company’s policies and procedures.

 

Management assessed theeffectiveness of the Company’s internal control over financial reporting as ofDecember 31, 2009, based on the framework established in*Internal Control – Integrated Framework*issuedby the Committee of Sponsoring Organizations of the Treadway Commission (COSO).Based on this assessment, Management concluded that the Company maintainedeffective internal control over financial reporting as of December 31, 2009.

 

During the year ended December 31,2009, there has been no change in the Company’s internal control over financialreporting that has materially affected, or is reasonably likely to materiallyaffect, the Company’s internal control over financial reporting.

 

 

65

----

 

**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   |

 

 

66

----