**Exhibit 99.2**

| **Annual Report on**                |
|-------------------------------------|
| **Form 10-K**                  |
| **of**                              |
| **Enbridge  Energy Partners, L.P.** |

** **

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**UNITED STATES**

**SECURITIES AND EXCHANGE COMMISSION**

**Washington, D.C. 20549**

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**FORM 10-K**

**x**              ANNUALREPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIESEXCHANGE ACT OF 1934

**Forthe fiscal year ended DECEMBER 31, 2005**

**OR**

**o**                 TRANSITIONREPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIESEXCHANGE ACT OF 1934

**Forthe transition period from                    to                    **

**Commission File Number: 1-10934**

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**ENBRIDGE ENERGY PARTNERS, L.P.**

(Exact name of Registrant as specified in its charter)

| **Delaware**                                                    | **39-1715850**                       |
|-----------------------------------------------------------------|--------------------------------------|
| (State or other jurisdiction of  incorporation or organization) | (I.R.S. Employer Identification No.) |

 

**1100 LouisianaSuite 3300Houston, Texas 77002**

(Address of principal executive offices and zip code)

**(713) 821-2000**

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) ofthe Act:

| Title of each class           | ** ** | **Name  of each exchange on which registered** |
|-------------------------------|------------|------------------------------------------------|
| **Class A Common Units** | ** ** | **New York Stock Exchange**                    |

 

Securities registeredpursuant to Section 12(g) of the Act: NONE

Indicate by check mark if the registrant is awell-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No o

Indicate by check mark if the registrant is notrequired to file reports pursuant to Section 13 or Section 15(d) ofthe Act. Yes o  No x

Indicate by check mark whether the Registrant (1) hasfiled all reports required to be filed by Section 13 or 15(d) of theSecurities Exchange Act of 1934 during the preceding 12 months (or forsuch shorter period that the Registrant was required to file such reports), and(2) has been subject to such filing requirements for the past90 days. Yes x  No o

Indicate by check mark if disclosure of delinquentfilers pursuant to Item 405 of Regulation S-K is not contained herein, andwill not be contained, to the best of the Registrant’s knowledge, in definitiveproxy or information statements incorporated by reference in Part III ofthis Form 10-K or any amendment to this Form 10-K. x

Indicate by check mark whether the registrant is a largeaccelerated filer, an accelerated filer, or a non-accelerated filer. Seedefinition of “accelerated filer and large accelerated filer” in Rule 12b-2 ofthe Exchange Act.Large Accelerated Filer x    Accelerated Filer o    Non-Accelerated Filer o

Indicate by check mark whether the registrant is ashell company (as defined in Rule 12b-2 of the Exchange Act). Yes o  No x

The aggregate market value of the Registrant’s Class ACommon Units held by non-affiliates computed by reference to the price at whichthe common equity was last sold, or the average bid and asked price of suchcommon equity, as of June 30, 2005, was $2,503,940,919.

As of February 17, 2006, the Registrant has 49,938,834Class A common units outstanding.

**DOCUMENTS INCORPORATED BYREFERENCE: NONE**

 

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**TABLEOF CONTENTS**

|                                                | ** ** | ** **                                                                                        | ** ** | **Page** |
|------------------------------------------------|------------|---------------------------------------------------------------------------------------------------|------------|----------|
|                                           | ** ** | **PART I**                                                                                   |       |     |
| **Item 1.**                                    |       | Business                                                                                          |       | 5        |
| **Item 1A.**                                   |       | Risk Factors                                                                                      |       | 30       |
| **Item 1B.**                                   |       | Unresolved Staff Comments                                                                         |       | 40       |
| **Item 2.**                                    |       | Properties                                                                                        |       | 40       |
| **Item  3.**                                   |       | Legal Proceedings                                                                                 |       | 40       |
| **Item 4.**                                    |       | Submission of Matters to a Vote of Security Holders                                               |       | 40       |
|                                           | ** ** | **PART II**                                                                                  |       |     |
| **Item 5.**                                    |       | Market for Registrant’s Common Equity and Related  Unitholder Matters                        |       | 41       |
| **Item  6.**                                   |       | Selected  Financial Data                                                                          |       | 42       |
| **Item 7.**                                    |       | Management’s Discussion and Analysis of Financial  Condition and Results of Operations  |       | 44       |
| **Item 7A.**                                   |       | Quantitative and Qualitative Disclosures About Market  Risk                                       |       | 76       |
| **Item 8.**                                    |       | Financial Statements and Supplementary Data                                                       |       | 82       |
| **Item 9.**                                    |       | Changes in and Disagreements with Accountants on  Accounting and Financial Disclosure        |       | 82       |
| **Item 9A.**                                   |       | Controls and Procedures                                                                           |       | 82       |
| **Item  9B.**                                  |       | Other  Information                                                                                |       | 83       |
|                                           | ** ** | **PART III**                                                                                 |       |     |
| **Item 10.**                                   |       | Directors and Executive Officers of the Registrant                                                |       | 84       |
| **Item 11.**                                   |       | Executive Compensation                                                                            |       | 88       |
| **Item 12.**                                   |       | Security Ownership of Certain Beneficial Owners and  Management                                   |       | 93       |
| **Item  13.**                                  |       | Certain  Relationships and Related Transactions                                                   |       | 94       |
| **Item 14.**                                   |       | Principal Accountant Fees and Services                                                            |       | 95       |
|                                           | ** ** | **PART IV**                                                                                  |       |     |
| **Item 15.**                                   |       | Exhibits and Financial Statement Schedules                                                        |       | 96       |
| **Signatures**                                 |       | 97                                                                                                |
| **Index to Consolidated Financial Statements** |       | F-1                                                                                               |

 

*This Annual Reporton Form 10-K contains forward-looking statements. Theseforward-looking statements are identified as any statement that does notrelate strictly to historical or current facts. They use words such as “anticipate,”“believe,” “continue,” “estimate,” “expect,” “forecast,” “intend,” “may,” “plan,”“position,” “projection,” “strategy,” “could,” “should,” or “will” or thenegative of those terms or other variations of them or comparable terminology.In particular, statements, expressed or implied, concerning future actions,conditions or events or future operating results or the ability to generaterevenue, income or cash flow are forward-looking statements. Forward-lookingstatements are not guarantees of performance. They involve risks, uncertaintiesand assumptions. Future actions, conditions or events and future results ofoperations may differ materially from those expressed in these forward-lookingstatements. Many of the factors that will determine these results are beyondour ability to control or predict. For additional discussion of risks,uncertainties and assumptions, see “Item 1A. Risk Factors” included elsewherein this Form 10-K.*

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**Glossary**

Thefollowing abbreviations, acronyms, or terms used in this Form 10-K aredefined below:

| AEUB                 |   | Alberta Energy and Utilities Board                                                                                                                                            |
|----------------------|--------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| Anadarko system      |   | Natural gas gathering and processing assets located  in western Oklahoma and the Texas panhandle, which were acquired on  October 17, 2002                               |
| AOSP                 |   | Athabasca Oil Sands Project, located in northern  Alberta, Canada                                                                                                             |
| Bbl                  |   | Barrel of liquids (approximately 42 U.S. gallons)                                                                                                                             |
| BlackRock            |   | BlackRock Ventures Inc., an unrelated producer of  heavy oil in Western Canada                                                                                           |
| Bpd                  |   | Barrels per day                                                                                                                                                               |
| CAA                  |   | Clean Air Act                                                                                                                                                                 |
| Canadian Natural     |   | Canadian Natural Resources Limited, an unrelated  energy company                                                                                                              |
| CAPP                 |   | Canadian Association of Petroleum Producers, a trade  association representing a majority of the Lakehead system's customers                                                  |
| CERCLA               |   | Comprehensive Environmental Response, Compensation,  and Liability Act                                                                                                        |
| CAD                  |   | Amount denominated in Canadian dollars                                                                                                                                        |
| CWA                  |   | Clean Water Act                                                                                                                                                               |
| DOT                  |   | Department of Transportation                                                                                                                                                  |
| East Texas system    |   | Natural gas gathering, treating and processing  assets in East Texas acquired on November 30, 2001. Also includes a  system formerly known as the Northeast Texas system |
| Enbridge             |   | Enbridge Inc., of Calgary, Alberta, Canada, the  ultimate parent of the General Partner                                                                                       |
| Enbridge Management  |   | Enbridge Energy Management, L.L.C.                                                                                                                                            |
| Enbridge system      |   | Canadian portion of the System                                                                                                                                                |
| Enbridge Pipelines   |   | Enbridge Pipelines Inc.                                                                                                                                                       |
| EnCana               |   | EnCana Corporation, an unrelated producer of natural  gas                                                                                                                     |
| EP Act               |   | Energy Policy Act of 1992                                                                                                                                                     |
| EPA                  |   | Environmental Protection Agency                                                                                                                                               |
| Exchange Act         |   | Securities Exchange Act of 1934                                                                                                                                               |
| FASB                 |   | Financial Accounting Standards Board                                                                                                                                          |
| FERC                 |   | Federal Energy Regulatory Commission                                                                                                                                          |
| General Partner      |   | Enbridge Energy Company, Inc., general partner of  the Partnership                                                                                                            |
| HCA                  |   | High consequence area                                                                                                                                                         |
| ICA                  |   | Interstate Commerce Act                                                                                                                                                       |
| KPC                  |   | Kansas Pipeline system, acquired on October 17, 2002                                                                                                                          |
| Lakehead Partnership |   | Enbridge Energy, Limited Partnership, a subsidiary  of the Partnership                                                                                                        |

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| Lakehead system        |   | U.S. portion of the System                                                                                                                                                                                      |
|------------------------|--------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| LIBOR                  |   | London Interbank Offered Rate—British Bankers  Association's average settlement rate for deposits in U.S. dollars                                                                                          |
| M3                     |   | Cubic meters of liquid = 6.289811661 Bbl                                                                                                                                                                        |
| MLP                    |   | Master Limited Partnership                                                                                                                                                                                      |
| MMBtu/d                |   | Million British Thermal units per day                                                                                                                                                                           |
| MMcf/d                 |   | Million cubic feet per day                                                                                                                                                                                      |
| Midcoast system        |   | Natural gas gathering, treating, processing,  transmission and marketing assets acquired October 17, 2002                                                                                                  |
| Mid-Continent  system  |   | Crude oil pipelines and storage facilities located  in the mid-continent of the U.S. and acquired on March 1, 2004                                                                                         |
| NEB                    |   | National Energy Board, a Canadian federal agency  that regulates Canada’s energy industry                                                                                                                  |
| NGA                    |   | Natural Gas Act                                                                                                                                                                                                 |
| NGL or NGLs            |   | Natural gas liquids                                                                                                                                                                                             |
| NGPA                   |   | Natural Gas Policy Act                                                                                                                                                                                          |
| North Dakota system    |   | Liquids petroleum pipeline system in the Upper  Midwest United States acquired on May 18, 2001                                                                                                                  |
| Northeast Texas system |   | Natural gas gathering and processing assets acquired  on October 17, 2002 and integrated with the East Texas system                                                                                        |
| North Texas system     |   | Natural gas gathering and processing assets acquired  on December 31, 2003                                                                                                                                 |
| NYMEX                  |   | The New York Mercantile Exchange where natural gas  futures, options contracts, and other energy futures are traded                                                                                             |
| NYSE                   |   | New York Stock Exchange                                                                                                                                                                                         |
| OCSLA                  |   | Outer Continental Shelf Lands Act                                                                                                                                                                               |
| OSHA                   |   | Occupational Safety and Health Administration                                                                                                                                                                   |
| OPA                    |   | Oil Pollution Act                                                                                                                                                                                               |
| OPS                    |   | Office of Pipeline Safety                                                                                                                                                                                       |
| PADD                   |   | Petroleum Administration for Defense Districts                                                                                                                                                                  |
| PADD II                |   | Consists of Illinois, Indiana, Iowa, Kansas,  Kentucky, Michigan, Minnesota, Missouri, Nebraska, North Dakota, Ohio,  Oklahoma, South Dakota, Tennessee and Wisconsin                                           |
| PADD III               |   | Consists of Alabama, Arkansas, Louisiana,  Mississippi, New Mexico and Texas                                                                                                                                    |
| PADD IV                |   | Consists of Idaho, Montana, Wyoming and Colorado                                                                                                                                                                |
| PADD V                 |   | Consists of Washington, Oregon, California, Arizona,  Alaska, Hawaii and Nevada                                                                                                                                 |
| Palo Duro system       |   | Natural gas transmission and gathering pipeline  assets located in Texas between the Anadarko system and the North Texas  system acquired on March 1, 2004 and integrated with the Anadarko system  during 2005 |

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| Partnership Agreement |   | Third Amended and Restated Agreement of Limited  Partnership of the Partnership                                                                |
|-----------------------|--------|------------------------------------------------------------------------------------------------------------------------------------------------|
| Partnership           |   | Enbridge Energy Partners, L.P. and its consolidated subsidiaries                                                                               |
| PHMSA                 |   | Pipeline and Hazardous Materials Safety  Administration (formerly OPS)                                                                         |
| PPIFG                 |   | Producer Price Index for Finished Goods                                                                                                        |
| PSA                   |   | Pipeline Safety Act                                                                                                                            |
| PSI Act               |   | Pipeline Safety Improvement Act                                                                                                                |
| RCRA                  |   | Resource Conservation & Recovery Act                                                                                                       |
| SAGD                  |   | Steam assisted gravity drainage                                                                                                                |
| SEC                   |   | Securities and Exchange Commission                                                                                                             |
| SEP II                |   | System Expansion Program II, an expansion program on  the Lakehead system                                                                      |
| Settlement Agreement  |   | A FERC approved settlement agreement, signed October  1996                                                                                     |
| SFAS                  |   | Statement of Financial Accounting Standards                                                                                                    |
| SFAS No. 133          |   | Statement of Financial Accounting Standards No. 133,  *Accounting for Derivative Transactions and  Hedging Activities*                         |
| SFPP                  |   | Sante Fe Pacific Pipelines, L.P., an unrelated  company                                                                                        |
| Suncor                |   | Suncor Energy Inc., an unrelated company                                                                                                       |
| Syncrude              |   | Syncrude Canada Ltd., an unrelated company                                                                                                     |
| Synthetic crude oil   |   | Product that results from upgrading or blending bitumen  into a crude oil stream which can be readily refined by most conventional  refineries |
| System                |   | The combined liquid petroleum pipeline operations of  the Lakehead system and the Enbridge system                                              |
| Tariff Agreement      |   | A 1998 offer of settlement filed with the FERC                                                                                                 |
| Terrace               |   | Terrace Expansion Program, an expansion program on  the Lakehead system                                                                        |
| WCSB                  |   | Western Canadian  Sedimentary Basin                                                                                                            |

 

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**PART I**

**Item 1.—Business**

**OVERVIEW**

In this report, unless the context requires otherwise,references to “we,” “us,” “our,” or the “Partnership” are intended to meanEnbridge Energy Partners, L.P. and its consolidated subsidiaries. We are apublicly traded Delaware limited partnership that owns and operates crude oiland liquid petroleum transportation and storage assets, and natural gasgathering, treating, processing, transportation and marketing assets in theUnited States of America. Our Class A common units are traded on the NYSEunder the symbol “EEP.”

We were formed in 1991 by our general partner to ownand operate the Lakehead system, which is the U.S. portion of a crude oil andliquid petroleum pipeline system extending from western Canada through theupper and lower Great Lakes region of the United States to eastern Canada. Asubsidiary of Enbridge owns the Canadian portion of the System. Enbridge, whichis based in Calgary, Alberta, provides energy transportation, distribution andrelated services in North America and internationally. Enbridge is the ultimateparent of our general partner.

We are ageographically and operationally diversified partnership consisting of interestsand assets relating to the midstream energy sector. As of December 31,2005, our portfolio of assets include the following:

·       Approximately4,900 miles of crude oil gathering and transportation lines and 23.4 millionBbl of crude oil storage and terminaling capacity.

·       Naturalgas gathering and transportation lines totaling approximately 11,000 miles.

·       Eightactive natural gas treating and 15 active natural gas processing facilitieswith aggregate capacity of approximately 1,500 MMcf/d.

·       Trucks,trailers and railcars for transporting NGLs, crude oil and carbon dioxide.

·       Marketingassets that provide natural gas supply, transmission, storage and salesservices.

Enbridge Management is a Delaware limited liabilitycompany that was formed in May 2002 to manage our business and affairs. Undera delegation of control agreement, our general partner delegated substantiallyall of its power and authority to manage our business and affairs to EnbridgeManagement. The General Partner, through its direct ownership of the votingshares of Enbridge Management, elects all of the directors of EnbridgeManagement. Enbridge Management is the sole owner of a special class of ourlimited partner interests, which we refer to as “i-units.”

Ourownership at December 31, 2005 is comprised of the following:

| ** **                                              | ** ** | **2005** | ** ** |
|---------------------------------------------------------|------------|----------|------------|
| Class A  common units owned by the public          |       | 74.7     | %          |
| Class B  common units owned by our general partner |       | 5.8      | %          |
| i-units owned by  Enbridge Management                   |       | 17.5     | %          |
| General Partner  interest                               |       | 2.0      | %          |
|                                                    |       | 100.0    | %          |

 

**BUSINESS STRATEGY**

Our primary objectiveis to provide stable and sustainable cash distributions to our unitholders,while maintaining a relatively low investment risk profile. Our businessstrategies focus on creating value for our 

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customers,which we believe is the key to creating value for our investors. To accomplishour objective, we focus on the following key strategies:

1.                Expandexisting core asset platforms

·        We intend to develop andacquire energy transportation assets and related facilities that arecomplementary to our existing systems. Our core businesses provide plentifulopportunities to achieve our primary business objectives.

2.                Developnew asset platforms

·        We plan to develop newgathering, processing, transportation and storage assets to meet customer needs,by expanding capacity into new markets with favorable supply and demandfundamentals.

3.                Focuson operational excellence

·        Wewill continue to operate our existing infrastructure to maximize costefficiencies, provide flexibility for our customers and ensure the capacity isreliable and available when required. We will focus on safety, environmentalintegrity, innovation and effective stakeholder relations.

In our currentenvironment, our primary focus is on expanding and developing our existingassets. We are placing relatively less emphasis on acquisitions than in prioryears due to:

·        Acquisitionprices for the stable energy assets we seek have become inflated; and

·        Theexpansion and diversification of our asset base over the past few years hascreated opportunities for internal growth projects that are expected to enhance the value of services weprovide to our customers and returns to our investors.

While purchase prices remain high, our acquisitionswill likely be limited to situations where we have natural advantages, throughreduced costs or increased utilization of our services.

Our planned internalgrowth for both our liquids and natural gas businesses will require asignificant investment of expansion capital over the next few years. Whilethese major projects are under construction, our ability to increasedistributions, while also funding these projects, is likely to be limited. Ouroutlook is premised on a number of major assumptions regarding the scope andtiming of the projects, financing alternatives available to us and excludes thepotential of significant acquisitions during the period. We expect our largergrowth projects will be accretive to distributable cash flow when placed intoservice. These projects are discussed below in the respective business section.

***Liquids***

Western Canadian crude oil is an important source ofsupply for the United States. According to the latest available data for 2005from the U.S. Department of Energy’s Energy Information Administration, Canadasupplied approximately 1.6 million Bpd of crude oil to the U.S., the largestsource of U.S. imports. Of the Canadian crude oil moving into the U.S., about63% was transported on the System, which is the primary pipeline from westernCanada to the U.S. We are well positioned to develop additional infrastructureto deliver growing volumes of crude oil that are expected from the Alberta oilsands. With an estimated $55 billion of active or planned projects in the Albertaoil sands, new production is expected to grow steadily during the next 5 years,with an additional 700,000 Bpd available by 2010 according to the AEUB.

Our Southern Access project is the cornerstone of ourmainline expansion initiatives to address the expected increase in supply. Our$1.1 billion (in 2005 dollars) project will provide an additional 400,000Bpd of heavy oil capacity to the Chicago market and beyond by early 2009, withnearly half of this capacity 

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available in early 2008.The design will also permit a further 400,000 Bpd increase in capacity forminimal additional cost, in conjunction with a corresponding expansion upstreamof Superior, when required by shippers. The Southern Access project involvesnew pipeline construction on our Lakehead system along with expansion on theCanadian portion of the pipeline by Enbridge.

Along with Enbridge, weare actively working with our customers to develop options that will allowCanadian crude oil to access new markets. The market strategy we areundertaking is to provide timely, economical, integrated transportationsolutions to connect growing supplies of production from the Alberta oil sandsto key refinery markets in the United States. The strategy involves furtherpenetration into PADD II as well as entry into the vast refining center of theU.S. Gulf Coast. On April 28, 2005, the NEB approved two applications fromEnbridge Pipelines to recover the costs for the extension of service to othermarkets via Enbridge’s Spearhead pipeline and ExxonMobil’s Mobil Pipe Linethrough its Canadian tolls over the next 5 years. Through these initiatives, westernCanadian crude oil will be delivered into Cushing, Oklahoma and Beaumont, Texasrespectively in the first quarter 2006. We expect to benefit from theseinitiatives, as western Canadian crude oil will be carried on our Lakeheadsystem as far as Chicago and then transferred to these other pipelines toaccess the new markets.

***Natural Gas***

Our natural gas assets are primarily located in theU.S. Gulf Coast region, one of the most active natural gas producing areas inthe United States. Three of our larger systems in Texas are located in basinsthat have experienced recent growth in natural gas land leases, drilling andproduction. These core basins are known as: the East Texas basin, the BarnettShale area and the Anadarko basin. Our focus has been on acquiring assets withstrong growth prospects located in these areas and then to continue to develop thoseprospects.

One of our key objectives is to become the premiermidstream energy company in the U.S. Gulf Coast region. To achieve this end,the operations and commercial activities of our gathering and processing assetsand intrastate pipelines are integrated to provide better service to ourcustomers. From an operations perspective, our key strategy is to provide safereliable service at reasonable costs to our customers, to enhance ourreputation with our customers and to improve our competitiveness for capturingnew customers. From a commercial perspective, our focus is to improve the valueof service to our customers by providing them with a better value for theircommodity. We intend to achieve this objective by increasing customer access tothe natural gas markets. We have made significant progress on this objective byphysically connecting a number of our systems. The objective is to be able tomove significant quantities of natural gas from our Anadarko, North Texas andEast Texas systems to the major market hubs in Texas and Louisiana. From themarket hubs, natural gas can be transported to consumers in the Midwest andNortheast United States. Our trucking operations are used to enhance the valueof the NGLs produced at our processing plants by ensuring ready access tostrategic markets. Our marketing business also helps maximize the valuereceived for the natural gas we transport and purchase, by identifyingcustomers with consistent demand for natural gas.

The growth prospects in our core areas have beenimproving due to the sustained high commodity prices and improvements intechnology to produce natural gas from tight sand and shale formations. As aresult, many expansions and extensions have been made on three of our maingathering and processing systems in Texas, including well-connects, processingplant re-activations, new plant construction, added compression and newpipelines. During January 2005, we purchased additional natural gasgathering and processing assets in north Texas, which we have integrated withour existing North Texas assets.

We continue to workclosely with our customers to provide natural gas transportation solutions toavoid shut-in natural gas production from insufficient transportation capacity.During 2005, we completed construction of a new 500 MMcf/d intrastate transportationpipeline to carry increased volumes of natural 

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gas tothe pipeline hub at Carthage, Texas. Carthage access is important because itoffers a number of connections to interstate pipelines, which tend to supportmore favorable natural gas prices for our customers. In January 2006, weannounced another $530 million expansion and extension of our East Texassystem. This project is required to handle the strong growth occurring in EastTexas natural gas production, particularly from the Bossier Sands and otherregional producing formations. We coordinated extensively with our customers todevelop and enhance access for growing Texas natural gas production to majormarkets in southeast Texas. The project is designed to be expandable and ispositioned for potential upstream and downstream extension.

We are also working withEnbridge on its proposed interstate extension from our Texas natural gasmidstream business. Enbridge announced an Open Season on a proposed 330 mile, 1 billioncubic feet per day pipeline from Texas through Louisiana, to interconnects withother interstate systems in western Mississippi. This project, if supported byshippers, could draw additional volumes through our East Texas system and itsproposed expansion announced in January 2006.

**BUSINESS SEGMENTS**

We conduct ourbusiness through three business segments:

·       Liquids;

·       NaturalGas; and

·       Marketing.

These segments have uniquebusiness activities that require different operating strategies. Forinformation relating to revenues from external customers, operating income andtotal assets for each segment, refer to Note 16 of our consolidated financialstatements.

***Liquids Segment***

*Lakehead system*

The Lakehead system consists primarily of a crude oiland liquid petroleum common carrier pipeline and storage assets in the GreatLakes and Midwest regions of the United States. This system, together with theEnbridge system in Canada, forms the longest liquid petroleum pipeline systemin the world. The System, which spans approximately 3,300 miles, has been inoperation for over 50 years and is the primary transporter of crude oiland liquid petroleum from western Canada to the United States. The Systemserves all the major refining centers in the Great Lakes and Midwest regions ofthe United States and the Province of Ontario, Canada. Through itsinterconnection with the Enbridge system, the Lakehead system is wellpositioned to capitalize on expected increases in crude oil supplies frompreviously announced heavy crude oil and oil sands projects in the Province ofAlberta, Canada.

Our Lakehead system is a FERC-regulated interstatecommon carrier pipeline system. The Lakehead system spans a distance of approximately1,900 miles, and consists of approximately 3,500 miles of pipe with diametersranging from 12 inches to 48 inches, 59 pump station locations with a total ofapproximately 768,000 installed horsepower and 62 crude oil storage tanks withan aggregate working capacity of approximately 10.8 million barrels. TheSystem operates in a segregation, or batch mode, allowing the transport of 59crude oil commodities including light, medium and heavy crude oil (includingbitumen, which is a naturally occurring tar-like mixture of hydrocarbons),condensate and NGLs.

*Customers.*   OurLakehead system operates under month-to-month transportation arrangements withour shippers. During 2005, 42 shippers tendered crude oil and liquid petroleumfor delivery through the 

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Lakehead system. Ourcustomers include integrated oil companies, major independent oil producers,refiners and marketers.

*Supply and Demand.*   Our Lakehead system is wellpositioned as the primary transporter of western Canadian crude oil andcontinues to benefit from the growing production of crude oil from the Albertaoil sands. Similar to U.S. domestic conventional crude oil production, westernCanada’s conventional crude oil production is declining. Over the last several years, development ofthe Alberta oil sands resource has more than offset declining conventionalproduction. In 2005, due to a major disruption at Suncor’s oil sands productionfacilties, growth in Alberta oil sands production did not offset the decline inproduction from conventional resources. The NEB estimates the total WCSB 2005production will average 2.1 million Bpd. Despite the decline experiencedin 2005, WCSB crude oil production is comparable with production from key OPECmembers Kuwait and Venezuela.

Remaining establishedconventional oil reserves in western Canada were estimated to be approximately3.8 billion barrels at the end of 2004. During 2004, the latest period forwhich data is available, approximately 95%****ofconventional production was replaced with reserve additions. Remainingestablished reserves from the Alberta oil sands as of the end of 2004, stand atapproximately 174 billion barrels. Combined conventional and oil sandsestablished reserves of approximately 178 billion barrels compares with SaudiArabia’s proved reserves of approximately 260 billion barrels.

According to the CAPP, anestimated $30 billion has been spent on oil sands development from 1996 through2004. The Alberta government estimates that an additional $55 billion maybe spent by 2015, including approximately $15 billion in maintenance capital on existing projects. Thisestimate includes all announced and planned projects in the Alberta oil sands. While it isunlikely that all projects will proceed as planned, the magnitude of thepotential is significant. Separately, the AEUB estimates future production fromthe Alberta oil sands will increaseby more than 1.5 million barrels per day****by 2014 based on a subset of currently approved applications andannounced expansions.

The near-term growth in crudeoil supply comes from the completion of major expansion projects at existingsynthetic crude oil upgraders and growth of bitumen production from bothexisting and new SAGD facilities currently under construction in Alberta. Overthe next year, synthetic crude oil production capacity is expected to increaseby approximately 110,000 Bpd****at theexisting plants over 2005 levels. Syncrude, one of the original oil sandsproducers in northern Alberta, is expected to complete their Stage 3 expansion inmid-2006, increasing production capacity to 350,000 Bpd****from current capacity of 240,000 Bpd. Suncor,the other original oil sands producer in Alberta, returned to full productionafter a fire and completed an expansion of their existing plant both at theirupgrader and their SAGD production facility during the fourth quarter of 2005.The expansion increased their production capacity by 35,000 Bpd to 260,000 Bpd**.**

The AOSP, owned by ShellCanada Limited (60%), Chevron Canada Limited (20%) and Western Oil Sands L.P.(20%), is another oil sands project that reached full production capacity in2004. Over the next three years, AOSP is planning on a number of programs toincrease production by 2010 from 155,000 Bpd to 300,000 Bpd**.**Regulatory applications for this projectwere filed in April 2005. De-bottlenecking initiatives related to bitumenproduction increased output in the second and third quarters of 2005 to averageapproximately 165,000 Bpd.

Over the next two years,unblended bitumen production is expected to start or increase from nearly 20individual****projects. Notable projectsinclude the expansions at Canadian Natural’s Wolf Lake/Primrose area, EnCana’sFoster Creek, Suncor’s Firebag and BlackRock’s Seal project. Based on the AEUBforecast, unblended bitumen production is expected to increase by roughly120,000 Bpd by the end of 2007, more than offsetting the decline inconventional crude production.

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Although the crude oil andliquid petroleum delivered through the Lakehead system primarily originates inoilfields in western Canada, the Lakehead system also receives approximately 6%****of its receipts from domestic sourcesincluding:

·        UnitedStates production at Clearbrook, Minnesota through a connection with the NorthDakota system;

·        U.S.production at Lewiston, Michigan; and

·        bothU.S. and offshore production in the Chicago area.

Based on forecasted growth in western Canadian crudeoil production and completion of repairs by Suncor to its upgrader that wasdamaged in early 2005 by a fire, we expect the Lakehead system deliveries toaverage 1.58 million Bpd in 2006compared with 1.34 million Bpd in 2005. During December 2005, the Lakeheadsystem achieved deliveries averaging 1.49 million Bpd. The estimateddeliveries for 2006 are part of a forecast representing forward-lookinginformation and are subject to risks, uncertainties and factors beyond ourcontrol.

Our ability to increase deliveries and to expand ourLakehead system in the future will ultimately depend upon numerous factors. Theinvestment levels and related development activities by crude oil producers inconventional and oil sands production directly impacts the level of supply fromthe WCSB. Investment levels are influenced by crude oil producers’ expectationsof crude oil and natural gas prices, future operating costs, and availabilityof markets for produced crude. Higher crude oil production from the WCSB shouldresult in higher deliveries on the Lakehead system. Deliveries on the Lakeheadsystem are also affected by periodic maintenance, turnarounds and othershutdowns at producing plants that supply crude oil to, or refineries that takedelivery from, our Lakehead system.

We expect the demand for WCSB crude oil productionwill continue to increase in PADD II. PADD II refinery configurations and crude oil requirementscontinue to be an attractive market for western Canadian supply. According tothe U.S. Department of Energy’s Energy Information Administration, 2005 demandfor crude oil in PADD II remained relatively unchanged from 2004 with anaverage of 3.3 million Bpd.****At thesame time, production of crude oil within PADD II increased marginally by 3,000Bpd to 438,000 Bpd.   With the proximityof the WCSB to PADD II, the availability of capacity on the Lakehead system andlimited alternative markets for WCSB production, we expect deliveries on the Lakeheadsystem to increase along with increases in WCSB supply. Based on our industrysurvey, we expect refineries in the PADD II market to compete aggressively withnew markets for access to the growing supply from the WCSB.

After receiving strong shipper support during thesummer Open Season, the Partnership and Enbridge announced in December 2005,the approval of the 400,000 Bpd Southern Access expansion project. Theexpansion is endorsed by CAPP, which allows us and Enbridge to file negotiatedsettlements containing tariff rate surcharge terms with Canadian and U.S.regulatory authorities. Fieldwork on the expansion has commenced to ensurecompletion in early 2009, with capacity increases to start in 2007.

The U.S. portion of the expansion will be undertakenon our Lakehead system with the first stage to add 44,000 Bpd of capacity in2007 and up to an additional 146,000 Bpd by early 2008. The first stageincludes a new pipeline between Superior and Delavan, Wisconsin, along withpump station enhancements upstream and downstream of this segment. Theexpansion project’s second stage will add upstream pumping capacity and completeconstruction of a new pipeline from Delavan to Flanagan, Illinois, withcompletion in early 2009. The Southern Access expansion project will create anew 454-mile 36-inch diameter pipeline that will add 400,000 Bpd ofincremental heavy crude oil capacity to our Lakehead system. The design willalso permit a further 400,000 Bpd increase in capacity for minimal additionalcost, in conjunction with a corresponding expansion upstream of Superior, whenrequired by shippers. For the U.S. portion of the expansion, the total costsare currently estimated at approximately $1.1 billion (in 2005 

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dollars). Enbridge is alsoworking with CAPP and shippers to extend the pipeline further south to WoodRiver and Patoka, Illinois, to provide capacity for further Canadian crude oilmovements to the markets being served from these hubs, which is referred to asthe Southern Access extension. The Southern Access extension would be owned byEnbridge but integrated with the Lakehead system operationally and for tarifftolling purposes.

Enbridge recently announced plans to develop the400,000 Bpd Alberta Clipper Pipeline for a cost of $1.6 billion (2005 dollars),as an express heavy crude oil line from Hardisty, Alberta to Superior, where itwould connect with our Lakehead system. The Alberta Clipper Pipeline is notexpected to be integrated with the System for tolling purposes and would beseparate from our Lakehead system. However, we will have an opportunity todevelop the United States section of this line at an expected cost ofapproximately $570 million (in 2005 dollars). This expansion of capacityupstream of Superior would be timed to meet the need for further capacity overand above our Southern Access expansion. The current design of our SouthernAccess expansion permits further development downstream of Superior, and thiswould be undertaken in conjunction with the construction of the Alberta ClipperPipeline. The Alberta Clipper Pipeline together with further expansion of ourportion of the Southern Access project, provides a highly economical source ofadditional capacity from Alberta to the U.S. Midwest, and offers shippers thegreatest range of storage and delivery locations.

The Spearhead pipeline is a 650-mile crude oil pipelineoriginally flowing from Cushing to Chicago which Enbridge purchased in 2003. OnMarch 2, 2005, Enbridge received FERC approval to proceed with plans toreverse the direction of flow on the pipeline from a northerly flow to asoutherly flow. Shippers have contracted for 10-year shipping commitmentsof an initial 60,000 Bpd, increasing to 75,000 Bpd by 2009.****Enbridge expects to have the line inservice during the first quarter of 2006, with initial capacity of 125,000 Bpd.****The line could subsequently be expanded toaccommodate up to 160,000 Bpd. The reversed line will originate from theGriffith, Indiana terminal on our Lakehead system and the connection to thisnew market should support increased throughput on the Lakehead system.

During 2004, ExxonMobil Pipeline Company approachedCAPP and prospective shippers with a proposal to reverse the direction of flowon their Beaumont, Texas to Corsicana, Texas and their Corsicana, Texas toPatoka crude oil pipelines. The combined reversed pipeline will be linked to ourLakehead system at Chicago via the Mustang Pipe Line Partners system to Patoka.Mustang Pipe Line Partners system is 30% owned by an affiliate of Enbridge. Thereversed pipeline is expected to transport between 50,000 and 70,000 Bpd ofWCSB crude oil to the refinery market located in Beaumont on the U.S. GulfCoast. The connection of our Lakehead system with this new market should alsosupport increased throughput on our Lakehead system in early 2006; however, thereversed system will also be capable of transporting WCSB crude oil moved viaother competing pipelines into the Patoka market.

The previously announced closure of an Oakville,Ontario refinery was completed in April 2005. A portion of the facilitywas closed in the fall of 2004, resulting in a modest decline in the volume ofcrude oil delivered by our Lakehead system to the province of Ontario. FutureLakehead system deliveries into Ontario are expected to remain relativelyconstant at this 2004 reduced level.

*Competition.**  *Our Lakehead system, along with theEnbridge system, is the main crude oil export route from the WCSB. WCSBproduction in excess of western Canadian demand moves on existing pipelinesinto the Midwest area of the United States (PADD II), the Rocky Mountain states(PADD IV), and the Anacortes area of Washington State (PADD V). In each ofthese areas, WCSB crude oil competes with local and imported crude oil to feedrefineries to produce refined products (mainly gasoline, diesel, and jet fuel).As local crude oil production declines and refineries demand more importedcrude oil in each PADD, imports from the WCSB increase. For 2005, the latestdata available shows that PADD II demanded 3.3 million Bpd while producing438,000 Bpd, thus importing 2.9 million Bpd. For the first nine months of 2005,PADD II imported approximately 0.9 million Bpd of crude oil from Canada. The 

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remaining 2  millionBpd was imported from PADD III and offshore sources through the U.S. Gulf Coast.Of the crude oil imported from Canada, 2005 actual volumes transported on ourLakehead system averaged 995,000 Bpd. Deliveries of Canadian crude oil by ourLakehead system to PADD II declined by approximately 35,000 Bpd in 2005, a 3%decrease from 2004 volumes. Total deliveries on our Lakehead system averaged1.34 million Bpd in 2005, meeting approximately 81****percent of Minnesota refinery capacity; 57 percent of thegreater Chicago area; and 78 percent of Ontario’s refinery demand.

In 2005, the Enbridge system transported approximately65%****of western Canadian crude oilproduction to export markets, Ontario, and interconnecting pipelines. TheSystem also transported all of the NGL mix produced in western Canada. Theremaining production was transported by systems serving the British Columbia,PADD IV and PADD V markets. Considering all of the pipeline systems thattransport western Canadian crude oil out of Canada, the System transported approximately69% of the total western Canadian crude oil exports in 2005 to the UnitedStates.

Given the expectedincrease in crude oil production from the Alberta oil sands over the next 10years, alternative transportation proposals have been presented to producers byus together with Enbridge, Enbridge on its own, and other competing entities. Theseproposals range from expansions of existing pipelines in markets currentlyserved by western Canadian crude oil, to new pipeline construction, which wouldtake the growth in production to new markets. These proposals are in variousstages of development, with some at the concept stage, to others that areproceeding with regulatory approval. Each of these proposals could compete withour Lakehead system. The following provides an overview of these proposals putforth by Enbridge and competing entities:

·       Theexpansion of an existing pipeline which begins in Clearbrook, Minnesota andtransports western Canadian crude oil to St. Paul, Minnesota. This expansionwould have the potential to increase the existing transportation capacity ofthe pipeline to 350,000 Bpd. While throughput on our Lakehead system from theCanadian border to Clearbrook could benefit from this expansion, volumes movingon our Lakehead system downstream of Clearbrook could be negatively impacted.

·       Theexpansion of an existing pipeline that runs from Alberta to British Columbiaand Washington state. The first phase of this expansion to add 35,000 Bpd ofcapacity was approved by the NEB in 2005 and is expected to be in service in2007. The next phase would further increase capacity by another 40,000 Bpd bythe end of 2008. 

·       Constructionof the new Gateway Pipeline by Enbridge, which could transport western Canadiancrude oil from Alberta to the west coast of Canada, where it would then beshipped by tanker to China and other Asia-Pacific markets and California. InDecember 2005, Enbridge announced the successful conclusion of an Open Seasonfor the Gateway Pipeline, which resulted in non-binding indications of interestthat exceeded 400,000 Bpd. Enbridge is working with participating shippers tofinalize binding precedent agreements.

·       Constructionof a new 590,000 Bpd crude oil pipeline from Hardisty, Alberta to Patoka, withan expected in-service date of late 2009. This proposal has support oflong-term contracts for a total of 340,000 Bpd and is proceeding withregulatory filings in Canada and the United States.

·       Constructionof a new crude oil pipeline from northern Alberta directly to the U.S. GulfCoast. This conceptual pipeline proposal is subject to shipper support andregulatory approval.

These competing alternatives for delivery of westernCanadian crude oil into the United States and other markets could erode shippersupport for further expansion of our Lakehead system beyond our Southern Accessexpansion, and for the development of Enbridge’s Alberta Clipper Pipeline. Theycould also affect throughput on and utilization of the System. However, theSystem offers significant cost savings and flexibility advantages which areexpected to continue to favor us and Enbridge as the preferred alternative formeeting shipper transportation requirements to the midwest United States.

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The following table sets forth Lakehead system averagedeliveries per day and barrel miles for each of the five-year periods endedDecember 31, 2005.

| ** **                                      | ** ** | **Deliveries**                   | ** ** |
|-------------------------------------------------|------------|----------------------------------|------------|
| ** **                                      | ** ** | **2005**                         | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** | **2001** | ** ** |
| ** **                                      | ** ** | **(thousands of Bpd)** | ** ** |
| **United  States**                              |       |                             |       |   |   |   |   |   |   |   |   |
| Light crude oil                                 |       | 241                              |       | 275 |   | 258 |   | 266 |   | 292 |   |
| Medium and heavy crude oil                      |       | 791                              |       | 785 |   | 741 |   | 665 |   | 663 |   |
| NGL                                             |       | 4                                |       | 4 |   | 4 |   | 6 |   | 5 |   |
| Total United States                             |       | 1,036                            |       | 1,064 |   | 1,003 |   | 937 |   | 960 |   |
| **Ontario**                                     |       |                             |       |   |   |   |   |   |   |   |   |
| Light crude oil                                 |       | 146                              |       | 174 |   | 174 |   | 171 |   | 174 |   |
| Medium and heavy crude oil                      |       | 59                               |       | 81 |   | 68 |   | 83 |   | 77 |   |
| NGL                                             |       | 98                               |       | 103 |   | 109 |   | 111 |   | 104 |   |
| Total Ontario                                   |       | 303                              |       | 358 |   | 351 |   | 365 |   | 355 |   |
| **Total  Deliveries**                           |       | 1,339                            |       | 1,422 |   | 1,354 |   | 1,302 |   | 1,315 |   |
| **Barrel  miles**** **(billions  per year) |       | 363                              |       | 367 |   | 345 |   | 341 |   | 333 |   |

 

*Mid-Continentsystem*

Our Mid-Continent system, which we acquired in thefirst quarter of 2004, is located within the PADD II district and iscomprised of our Ozark pipeline, our West Tulsa pipeline and storage terminalsat Cushing and El Dorado, Kansas. It includes over 480 miles of crude oilpipelines and 11.9 million barrels of crude oil storage capacity. OurOzark pipeline transports crude oil from Cushing to Wood River where itdelivers to ConocoPhillips’ Wood River refinery and interconnects with theWoodPat Pipeline, and the Wood River Pipeline, each owned by unrelated parties.Our West Tulsa pipeline moves crude oil from Cushing to Tulsa, Oklahoma whereit delivers to Sinclair Oil Corporation’s Tulsa refinery.

The storage terminals consist of 97 individual storagetanks ranging in size from 55,000 to 575,000 barrels. We expect to add nine newtanks during 2006 to our existing storage facilities in Cushing, which willincrease our crude oil storage capacity by 3.2 million barrels. A portionof the storage facilities are used for operational purposes while we contractthe remainder of the facilities with various oil market participants forstorage capacity within the terminals. Contract fees include fixed monthlycapacity fees as well as utilization fees, which are charged for injectingcrude oil into and withdrawing crude oil from the storage facilities.

*Customers.**  *Our Mid-Continent system operatesunder month-to-month transportation arrangements and both long-term and spotstorage arrangements with its shippers. During 2005, 26 shippers tendered crudeoil for service by the Mid-Continent system. These customers include integratedoil companies, independent oil producers, refiners and marketers. Average dailydeliveries on the system were 236,000 Bpd for 2005. For 2006, we expectdeliveries to be approximately 210,000 Bpd.

*Supplyand Demand.**  *TheMid-Continent system is positioned to capture increasing near-term demand forimported crude oil from west Texas and the U.S. Gulf Coast as well as third-partystorage demand. In 2005, PADD II imported 2.9 million barrels per day fromoutside of the PADD II region. The Lakehead system supplied roughly 1.0 millionbarrels per day of crude from Canada leaving 2.0 million barrels per dayimported from PADD III and offshore sources. We expect the gap between localsupply and demand for crude oil in PADD II to continue to widen, encouragingimports of crude oil from Canada, PADD III and foreign sources.

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*Competition.**  *Our Ozark pipeline system currentlyserves an exclusive corridor between Cushing and Wood River. However,refineries connected to Wood River have crude supply options available fromCanada via the Lakehead system, with a connection to the Mustang pipeline, anEnbridge affiliated system, and through a third party pipeline, which runs fromwestern Canada and PADD IV. These same refineries also have access to U.S. GulfCoast and foreign supply through the Capline pipeline system, which is owned byan unrelated group of five owners. In addition, refineries located east ofPatoka with access to crude through the Ozark system, also have access to westTexas supply through the Texas Gulf pipeline owned by third parties. The Ozarkpipeline system could face a significant increase in competition if a proposednew pipeline from Hardisty, Alberta to Patoka is completed in 2009. However, ifthat situation occurs, we would consider potential alternative uses for ourOzark system.

In addition to movements into Wood River, crude oil inCushing is transported to Chicago and El Dorado on third-party pipelinesystems. With the reversal of the Spearhead pipeline, we expect western Canadiancrude oil moving on Spearhead to increase the importance of Cushing as aterminal and pipeline origination area.

The storage terminals rely on demand for storageservice from numerous oil market participants. Producers, refiners, marketersand traders rely on storage capacity for a number of different reasons: batchscheduling, stream quality control, inventory management, and speculativetrading opportunities. Competitors to our storage facilities at Cushing includelarge integrated oil companies and other midstream energy partnerships.

*North Dakota system*

Our North Dakota system is a crude oil gathering andinterstate transportation system servicing the Williston Basin in North Dakotaand Montana. Its crude oil gathering pipelines collect crude oil from pointsnear producing wells in approximately 36 oil fields in North Dakota and Montana.Most deliveries from the North Dakota system are made at Clearbrook, Minnesota,to the Lakehead system and to a third-party pipeline system. The NorthDakota system includes approximately 330 miles of crude oil gathering linesconnected to a transportation line that is approximately 620 miles long, with acapacity of approximately 80,000 barrels per day. The North Dakota system alsohas 17 pump stations and 11 terminaling facilities with an aggregate workingstorage capacity of approximately 700,000 barrels. We are beginning a$20 million expansion of this system to be complete in late 2006. Thisexpansion is necessary to meet increased crude oil production from the Montanaand North Dakota region.

*Customers.**  *Customers of the North Dakotasystem include producers of crude oil and purchasers of crude oil at thewellhead, such as marketers, that require crude oil gathering andtransportation services. Producers range in size from small independentowner/operators to the largest integrated oil companies.

*Supplyand Demand.**  *Likethe Lakehead system, the North Dakota system depends upon demand for crude oilin the Great Lakes and Midwest regions of the United States, and the ability ofcrude oil producers to maintain their crude oil production and explorationactivities.

*Competition.**  *Competitors of the North Dakotasystem include integrated oil companies, interstate and intrastate pipelines ortheir affiliates and other crude oil gatherers. Many crude oil producers in theoil fields served by the North Dakota system have alternative gatheringfacilities available to them or have the ability to build their own facilities.

***Natural Gas Segment***

We own and operate natural gas gathering, treating,processing and transportation systems as well as trucking operations. Wepurchase and/or gather natural gas from the wellhead, deliver it to plants fortreating and/or processing and to intrastate or interstate pipelines fortransmission, or to wholesale customers such as power plants, industrialcustomers and local distribution companies.

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Natural gas treating involves the removal of hydrogensulfide, carbon dioxide, water and other substances from raw natural gas sothat it will meet the standards for pipeline transportation. Natural gasprocessing involves the separation of raw natural gas into residue gas andNGLs. Residue gas is the processed natural gas that ultimately is consumed byend users. NGLs separated from the raw natural gas are either sold andtransported as NGL raw mix or further separated through a process known asfractionation, and sold as their individual components, including ethane,propane, butanes and natural gasoline. At December 31, 2005, we haveapproximately 8,500 miles of gathering pipelines, eight treating plants and 15processing plants, excluding plants that are inactive. Our treating facilitieshave a combined capacity exceeding 700 MMcf/d while the combined capacity ofour processing facilities is over 800 MMcf/d.

In January 2005, we acquired natural gasgathering and processing assets in north Texas. Facilities acquired includeapproximately 2,200 miles of gas gathering pipelines and four processing plantswith aggregate processing capacity of 121 MMcf/d of natural gas. This systempredominantly gathers gas produced from the Fort Worth Basin Conglomerate formationand is located in an area where future drilling is expected from producersextending the Barnett Shale play’s western flank. Most of the gas is gathered atthe wellhead and must be processed in order to meet downstream pipelinetransportation specifications.

Our natural gas segment consists of the followingmajor systems:

·       EastTexas system: Includes approximately 2,900 miles of natural gas gathering and transportationpipelines, six natural gas treating plants and three natural gas processingplants.

·       Anadarkosystem: Consists of approximately 1,200 miles of natural gas gathering andtransportation pipelines in southwest Oklahoma and the Texas panhandle, onenatural gas treating plant and four natural gas processing plants. The Anadarkosystem includes the Palo Duro system, which we acquired in March 2004.

·       NorthTexas system: Includes approximately 4,200 miles of natural gas gatheringpipelines and seven natural gas processing plants, including the additionalnatural gas gathering and processing assets we acquired for $164.6 million in January 2005.

·       Ourtransportation operations include FERC-regulated natural gas interstatepipeline systems and non-FERC regulated natural gas intrastate pipeline systems.Our four major FERC regulated systems are the KPC pipeline, Midla pipeline,AlaTenn pipeline and UTOS pipeline. We also have a number of smallernon-regulated pipelines as well as trucking operations which are discussedbelow. Each of our pipeline systems typically consists of a natural gaspipeline, compression, and various interconnects to other pipelines that servewholesale customers.

*Customers.**  *Customers of our natural gas pipelinesystems include both purchasers and producers of natural gas. Purchasersinclude marketers and large users of natural gas, such as power plants,industrial facilities and local distribution companies. Producers served by oursystems consist of small, medium and large independent operators and largeintegrated energy companies. We sell NGLs resulting from our processingactivities to a variety of customers ranging from large petrochemical andrefining companies to small regional retail propane distributors.

Our natural gas pipelines serve customers in the GulfCoast and Mid-Continent regions of the United States. Customers include largeusers of natural gas, such as power plants, industrial facilities, localdistribution companies, large consumers seeking an alternative to their localdistribution company, and shippers of natural gas, such as natural gasproducers and marketers.

*Supplyand Demand.**  *Demandfor our gathering, treating and processing services primarily depends upon the supplyof natural gas reserves and the drilling rate of new wells. The level ofimpurities in the 

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natural gas gathered alsoaffects treating services. Demand for these services also depends upon overalleconomic conditions and the prices of natural gas and NGLs. Three of our largersystems are located in basins that continue to experience growth in natural gasdrilling and production.

Our East Texas system is primarily located in the EastTexas Basin. While production from most regions within this basin has remainedflat for several years, the Bossier trend within the East Texas Basin continuesto experience substantial growth. The Bossier trend is located on the westernside of our East Texas system. Production in the Bossier trend has grown fromunder 390 MMcf/d in 1997 to over 1,100 MMcf/d in 2005. In 2005, we completedconstruction of the 107-mile expansion of our East Texas system toprovide customers with access to the Carthage Hub, an important outlet to majormarkets in the Midwest and Northeast United States. We expect the pipeline tobe fully utilized with flows of 500 MMcf/d during the second quarter of 2006. Wealso commenced a significant expansion of treating and processing capacity inthe region, a significant portion of which is already operational with theremaining facilities expected to be complete by mid-2006.

A substantial portion of natural gas on our NorthTexas system is produced in the Barnett Shale area within the Fort Worth BasinConglomerate. The Fort Worth Basin Conglomerate is a mature zone that isexperiencing slow production decline. In contrast, the Barnett Shale area isone of the most active natural gas plays in North America. While abundantnatural gas reserves have been known to exist in the Barnett Shale area sincethe early 1980s, recent technological development in fracturing the shaleformation allows commercial production of these natural gas reserves. BarnettShale production has risen from approximately 110 MMcf/d to over 1,200 MMcf/d since1999, with the drilling of over 3,800 wells. Growth in this region is expectedfor at least ten years.

Our Anadarko system is located within the AnadarkoBasin. Within that basin, recent growth is occurring in the Granite Wash play,particularly in Hemphill and Wheeler Counties, Texas. We completed constructionof our Zybach Processing Plant in the second quarter of 2005 and furtherexpansion of this facility will be complete in early 2006. We initiatedconstruction in late 2005 on a new 125 MMcf/d processing plant that isscheduled to be online in early 2006, which will accommodate expected volumegrowth from existing and future drilling activity.

We intend to expand our natural gas gathering andprocessing services primarily through internal growth projects designed toprovide exposure to incremental supplies of natural gas at the wellhead,increase opportunities to serve additional customers, including new wholesalecustomers, and allow expansion of our treating and processing businesses. Additionally,we will pursue acquisitions to expand our natural gas services in situationswhere we have natural advantages to create additional value for our existingassets.

Our natural gas pipelines generally serve differentgeographical areas, with differing supply and demand characteristics in eachmarket. We believe that demand and competition for natural gas in the areasserved by our natural gas assets generally will remain strong as a result ofbeing located in areas where industrial, commercial or residential growth isoccurring. The greatest demand for services in the markets served by ournatural gas assets occurs in the winter months.

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The table belowindicates the capacity in MMcf/d of the transportation and wholesale customerpipelines with firm transportation contracts as of December 31, 2005 andthe amount of capacity that is reserved under those contracts as of that date.

| **Major System** | ** ** | ** ** | ** ** | **Capacity  MMcf/d** | ** ** | **Percentage   Reserved Under  Contract as of  December 31, 2005** | ** ** |
|-----------------------|------------|------------|------------|----------------------|------------|--------------------------------------------------------------------------------------------------|------------|
| UTOS system      |       |       | 1,200      |                 |       |                                                                                             | 0          | % |   |
| Midla system          |       |       | 200        |                 |       |                                                                                             | 74         | % |   |
| AlaTenn system        |       |       | 200        |                 |       |                                                                                             | 40         | % |   |
| KPC system            |       |       | 160        |                 |       |                                                                                             | 96         | % |   |
| Bamagas system        |       |       | 450        |                 |       |                                                                                             | 61         | % |   |

 

Our UTOS system transports natural gas from offshoreplatforms on a fee for service basis to other pipelines onshore for furtherdelivery and does not have long-term reserve capacity. The UTOS system’saverage daily throughput during 2005 was 158,000 MMBtu/d. The FERC has approvedour negotiated settlement with UTOS shippers, keeping the current rates ineffect through 2006.

Our Midla, AlaTenn and Bamagas systems primarily serveindustrial corridors and power plants in Louisiana, Alabama and Tennessee.Industries in the area include energy intensive segments of the petrochemicaland pulp and paper industries. The Bamagas system in northern Alabama servestwo power plants and is contiguous with the AlaTenn system. We market theunused capacity on these systems under both short-term firm and interruptibletransportation contracts and long-term firm transportation contracts. Thesesystems are located in areas where opportunities exist to serve new industrialfacilities and to make delivery interconnects to alleviate capacity constraintson other third-party pipeline systems. As of December 31, 2005,approximately 74% of contracted capacity of the Midla system is under contractto our marketing business.

Our KPC system has 82% of its capacity reserved underfirm transportation contracts extending through 2009 and an additional 12% ofits capacity reserved under contracts extending through 2017. The KPC system’sprimary customers are local distribution companies.

Our long-term financial condition depends on thecontinued availability of natural gas for transportation to the markets servedby our systems. Existing customers may not extend their contracts if theavailability of natural gas from the Mid-continent and Gulf Coast producingregions was to decline and if the cost of transporting natural gas from otherproducing regions through other pipelines into the areas we serve were torender the delivered cost of natural gas uneconomical. We may be unable to findadditional customers to replace the lost demand or transportation fees.

*Competition.**  *Competitors of our gathering,treating and processing systems include interstate and intrastate pipelines ortheir affiliates and other midstream businesses that gather, treat, process andmarket natural gas or NGLs. Some of these competitors are substantially largerthan we are. Competition for the services we provide varies based upon thelocation of gathering, treating and processing facilities. Most natural gasproducers and owners have alternate gathering, treating and processingfacilities available to them. In addition, they have alternatives such asbuilding their own gathering facilities or in some cases, selling their naturalgas supplies without treating and processing. In addition to location,competition also varies based upon pricing arrangements and reputation. On thesour gas systems, such as our East Texas system, competition is more limiteddue to the infrastructure required to treat sour gas.

Competition for customers in the marketing of residuegas is based primarily upon the price of the delivered gas, the servicesoffered by the seller and the reliability of the seller in making deliveries.Residue 

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gas also competes on aprice basis with alternative fuels such as crude oil and coal, especially forcustomers that have the capability of using these alternative fuels, and on thebasis of local environmental considerations. Competition in the marketing ofNGLs comes from other NGL marketing companies, producers/traders, chemicalcompanies and other asset owners.

Because pipelines are generally the only practicalmode of transportation for natural gas over land, the most significantcompetitors of our natural gas pipelines are other pipelines. Pipelinestypically compete with each other based on location, capacity, price andreliability. Many of the large wholesale customers we serve have multiplepipelines connected or adjacent to their facilities. Accordingly, many of thesecustomers have the ability to purchase natural gas directly from a number ofpipelines or third parties that may hold capacity on the various pipelines.

***Trucking Operations***

We also include our trucking operations in our NaturalGas segment. Trucking operations include the transportation of NGLs, crude oiland carbon dioxide by truck and railcar from wellheads and treating, processingand fractionation facilities and to wholesale customers, such as distributors,refiners and chemical facilities. In addition, our trucking operations marketthese products. A key component of our business is ensuring market access forthe liquids extracted at our processing facilities. On average this accountsfor approximately 50% of the volume transported by our trucking business and isa major source of its growth in this area.

Our services are provided using trucks, trailers andrail cars, product treating and handling equipment and NGL storage facilities.In addition, our CO2 plant, with 250 tons per day of capacity,takes excess CO2 from hydrogen producers which we then sell toa variety of customers. At the end of 2004, we took 50% ownership of anunderground propane storage facility in Petal, Mississippi, which augments theservices we provide to our customers in the region. The total capacity of thisfacility is 5.6 million Bbls which increases our storage capabilities.

In late 2005, we began increasing our truck fleet byapproximately 25 percent to meet the growing supply of NGLs, crude oil andcarbon dioxide from our processing facilities, as well as to capitalize on theopportunity to better serve our Gulf Coast customers.

*Customers.**  *Most of the customers of ourtrucking operations are wholesale customers, such as refineries and propanedistributors. Our trucking operations also market products to wholesalecustomers such as petrochemical plants.

*Supplyand Demand.**  *Theareas served by our trucking operations are geographically diverse, and theforces that affect the supply of the products transported vary by region. Crudeoil and natural gas prices and production levels affect the supply of theseproducts. The demand for services is affected by the demand for NGLs and crudeoil by large industrial refineries, and similar customers in the regions servedby this business.

*Competition.**  *Our trucking operations have anumber of competitors, including other trucking and railcar operations,pipelines, and, to a lesser extent, marine transportation and alternativefuels. In addition, the marketing activities of our trucking operations have numerouscompetitors, including marketers of all types and sizes, affiliates ofpipelines and independent aggregators.

***Marketing Segment***

Our Marketing segment’s primary objective is tomaximize the value of the gas purchased by our gathering systems and thethroughput on our gathering and intrastate wholesale customer pipelines. Toachieve this objective, our Marketing segment transacts with variouscounterparties to provide natural gas supply, transportation, balancing,storage and sales services.

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Since our gathering and intrastate wholesale customerpipeline assets are geographically located within Texas, Oklahoma, Alabama andLouisiana, the majority of activities conducted by our Marketing segment arefocused within these areas.

*Customers.  *Natural gas purchased and sold by ourMarketing segment is sold to industrial, utility and power plant end usecustomers. In addition, gas is sold to marketing companies at various markethubs. These sales are typically priced based upon a published daily or monthly priceindex. Sales to end-use customers incorporate a pass-through charge for costsof transportation and additional margin to compensate us for associatedservices.

*Supply and Demand.  *Supplyfor our Marketing business depends to a large extent on the natural gasreserves and rate of drilling within the areas served by our Natural Gassegment. Demand is typically driven by weather-related factors with respect topower plant and utility customers, and industrial demand.

Our Marketing business usesstorage and the leasing of storage capacity to balance supply and demandfactors within its portfolio. Marketing pays third-party storagefacilities and pipelines for the right to store gas for various periods oftime. These contracts may be denoted as firm storage, interruptible storage, orparking and lending services. These various contract structures are used tomitigate risk associated with sales and purchase contracts, and to take advantageof price differential opportunities. Due to the increased volumes from ourgathering assets, our Marketing business leases third-party pipeline capacity downstreamfrom our Natural Gas assets under firm transportation contracts followingspecific, controlled guidelines. This capacity is leased for various lengths oftime and rates and allows our Marketing business to diversify its customer baseby expanding its service territory and provides assurance that our gas will notbe shut in due to capacity constraints on downstream pipelines.

*Competition*.*  *Our Marketing segment has numerouscompetitors, including large natural gas marketing companies, marketingaffiliates of pipelines, major oil and gas producers, independent aggregatorsand regional marketing companies.

**REGULATION**

***Regulation by the FERC of Interstate Common CarrierLiquids Pipelines***

The Lakehead, North Dakota, and Ozark systems are ourprimary interstate common carrier liquids pipelines subject to regulation bythe FERC under the ICA. As common carriers in interstate commerce, thesepipelines provide service to any shipper who requests transportation services,provided that products tendered for transportation satisfy the conditions andspecifications contained in the applicable tariff. The ICA generally requiresus to maintain tariffs on file with the FERC that set forth the rates we chargefor providing transportation services on our interstate common carrierpipelines, as well as the rules and regulations governing these services.

The ICA gives the FERC the authority to regulate therates we charge for service on our interstate common carrier pipelines. The ICArequires, among other things, that such rates be “just and reasonable” andnondiscriminatory. The ICA permits interested persons to challenge newlyproposed or changed rates and authorizes the FERC to suspend the effectivenessof such rates for a period of up to seven months and to investigate the ratesto determine if they are just and reasonable. If, upon completion of aninvestigation, the FERC finds that the new or changed rate is unlawful, it isauthorized to require the carrier to refund with interest the increasedrevenues in excess of the amount that would have been collected during the termof the investigation at the rate properly determined to be lawful. The FERCalso may investigate, upon complaint, or on its own motion, rates that arealready in effect and may order a carrier to change its rates prospectively.Upon an appropriate showing, a shipper may obtain reparations for damagessustained for a period of up to two years prior to the filing of a complaint.

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On October 24, 1992, Congress passed the EP Act,which deemed petroleum pipeline rates that were in effect for the 365-dayperiod ending on the date of enactment, or that were in effect on the 365th day preceding enactment and had not beensubject to complaint, protest or investigation during the 365 day period, to bejust and reasonable under the ICA (i.e., “grandfathered”). The EP Act alsolimited the circumstances under which a complaint can be made against suchgrandfathered rates. In order to challenge grandfathered rates, a party mustshow, 1) that it was contractually barred from challenging the ratesduring the relevant 365 day period; 2) that there has been a substantialchange after the date of enactment of the EP Act in the economic circumstancesof the pipeline or in the nature of the services that were the basis for the rate;or 3) that the rate is unduly discriminatory or unduly preferential.

The FERC has determined that the Lakehead system ratesare not covered by the grandfathering provisions of the EP Act because theywere subject to challenge prior to the effective date of the statute. Webelieve that the rates for the North Dakota and Ozark systems should be foundto be largely covered by the grandfathering provisions of the EP Act.

The EP Act required the FERC to issue rules establishinga simplified and generally applicable ratemaking methodology for petroleumpipelines, and to streamline procedures in petroleum pipeline proceedings. TheFERC responded to this mandate by issuing Order No. 561, which, amongother things, adopted an indexing rate methodology for petroleum pipelines.Under the regulations, which became effective January 1, 1995, petroleumpipelines are able to change their rates within prescribed ceiling levels thatare tied to an inflation index. Rate increases made within the ceiling levelsmay be protested, but such protests must show that the rate increase resultingfrom application of the index is substantially in excess of the pipeline’sincrease in costs. If the indexing methodology results in a reduced ceilinglevel that is lower than a pipeline’s filed rate, Order No. 561 requiresthe pipeline to reduce its rate to comply with the lower ceiling, although apipeline is not required to reduce its rate below the level grandfathered underthe EP Act. Under Order No. 561, a pipeline must, as a general rule,utilize the indexing methodology to change its rates. The FERC, however, usescost-of-service ratemaking, market-based rates and settlement rates asalternatives to the indexing approach in certain specified circumstances.

Under Order No. 561, the original inflation indexadopted by the FERC was the annual change in the PPIFG minus one percentagepoint. The index was subject to review every five years. In 2000, the FERCagain adopted the PPIFG index, but the FERC’s rationale for doing so wasoverturned by the United States Court of Appeals for the District of ColumbiaCircuit on appeal. On remand, the FERC adopted an index of PPIFG without theminus one percentage point adjustment, and that result was upheld on appeal. Asof 2005, the index remains the PPIFG with no adjustment. Based on the PPIFG for2004, the index increased by 3.6288% for the year beginning July 1, 2005. TheFERC has initiated another five-year review to determine the index to be ineffect from 2006-2010. The FERC’s initial proposal is that the index  remains at the PPIFG with no adjustment. TheAssociation of Oil Pipe Lines is seeking an index of the PPIFG plus 1.3percentage points. The issue of the index to be adopted for the next five yearsremains undecided at this time.

***Allowance for Income Taxes in Rates***

In a 1995 decision involving our Lakehead system,which we refer to as the *Lakehead ruling*,the FERC partially disallowed the inclusion of income taxes in the cost ofservice for the Lakehead system. A subsequent appeal of the *Lakehead ruling* was resolved by settlement and therefore wasnot adjudicated. In another FERC proceeding involving SFPP, the FERC initiallyrelied on its previous *Lakehead ruling*to hold that SFPP could not claim an income tax allowance for incomeattributable to non-corporate partners, both individuals and other entities. SFPPand other parties to the proceeding appealed the FERC’s orders to the UnitedStates Court of Appeals for the District of Columbia Circuit. On July 20,2004, in *BP West Coast Products LLC v. FERC*(No. 99-1020),which we refer to as the *BP West Coast decision*,the United States Court of Appeals for the District of Columbia Circuit issueda decision 

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upholding certain aspectsof the FERC’s orders regarding the SFPP case, but vacating the FERC’s rulingregarding the proper tax allowance for SFPP. The United States Court of Appealsfor the District of Columbia rejected the FERC’s rationale for its *Lakehead**ruling* andremanded the case to the FERC for further proceedings.

In the wake of the *BP West Coast*decision, the FERC initiated a notice and comment process to address taxallowance issues across a range of industries. We and many other companiescommented on the proceeding. On May 4, 2005, the FERC issued a policystatement on income tax allowances, in which it reinstated its earlier policyof providing a full tax allowance on all partnership and similar legalinterests in regulated companies if the owner of that interest has an actual orpotential tax liability on the income earned through that interest. Whether apipeline’s owners have such actual or potential income tax liability will bereviewed by the FERC on a case-by-case basis. On December 16, 2005, FERC issued its first case-specific oilpipeline review of the income tax allowance issue in the SFPP proceeding,reaffirming its new income tax allowance policy and directing SFPP to providecertain evidence necessary for the pipeline to determine its income taxallowance.  The new tax allowance policyand the December 16 order have been appealed to the D.C. Circuit, andrehearing requests have been filed with respect to the December 16order.  As a result, the ultimate outcomeof these proceedings is not certain and could result in changes to the FERC’streatment of income tax allowances in cost of service.Depending upon how the policy statement on income tax allowances is applied inpractice to MLP pipelines, and whether it is ultimately upheld or modified onjudicial review, could effect the tariffs of FERC-regulated pipelines.

A related issue is whether the FERC’s income taxallowance policy can be relied upon by shippers as a substantial change incircumstances sufficient to remove the grandfathering protection under the EPAct from an oil pipeline’s rates. The FERC determined in the SFPP case that itspolicy statement on income tax allowances does not represent a change from itspre-EP Act policy and therefore, cannot affect grandfathering of rates, aposition that is still potentially subject to further judicial review.

The effect of the FERC’s policy statement on incometax allowances on us is uncertain. The tariff rates on our common carrierinterstate liquids pipelines have been established under a variety of differentcircumstances including settlements and tariff indexing. Since an income taxallowance is only one of many elements supporting our pipeline rates forservice, we cannot predict with certainty what rates we will be allowed tocharge in the future, or the potential impact on us of the FERC’s policystatement on income tax allowances.

We believe that the rates we charge for transportationservices on our interstate common carrier liquids pipelines are just andreasonable under the ICA. However, because the rates that we charge are subjectto review upon an appropriately supported protest or complaint, we cannotpredict what rates we will be allowed to charge in the future for service onour interstate common carrier liquids pipelines. Furthermore, because ratescharged for transportation services must be competitive with those charged byother transporters, the rates set forth in our tariffs will be determined basedon competitive factors in addition to regulatory considerations.

***Accounting for Pipeline Assessment Costs***

In June 2005, the FERC issued an order in DocketAI05-1 describing how FERC-regulated companies should account for costsassociated with implementing the pipeline integrity management requirements ofthe United States Department of Transportation’s Office of Pipeline Safety. Theorder takes effect beginning on January 1, 2006. Under the order,FERC-regulated companies are generally required to recognize costs incurred inperforming pipeline assessments that are part of a pipeline integritymanagement program as maintenance expense in the period in which the costs areincurred. Costs for items such as rehabilitation projects designed to extendthe useful life of the system can continue to be capitalized to the extentpermitted under the existing rules. The FERC denied rehearing of its accountingguidance order on September 19, 2005.

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We have historically capitalized first time in-lineinspection programs, based on previous rulings by the FERC. Beginning in January 2006,we will prospectively account for pipeline assessment costs as maintenanceexpense for those systems applying SFAS No. 71, *Accountingfor the Effects of Certain Types of Regulation*. For non-SFAS No. 71pipelines we will continue to capitalize first time crack-detection tool runsconsistent with our prior practice; however, for regulatory reporting purposesthese costs will be expensed by our FERC-regulated crude oil pipelines.Crack-detection tool runs address defects in construction or pipe manufacturethat may not be readily evident at the time of construction. We will continueto expense other types of inspection tool runs as they primarily address conditionsthat develop from operations. Refer to Note 2: Summary of SignificantAccounting Policies of our consolidated financial statements and “RecentAccounting Developments” in Management’s Discussion and Analysis of FinancialCondition and Results of Operations for additional discussion.

***Regulation by the FERC of Interstate Natural GasPipelines***

Our AlaTenn, Midla,KPC and UTOS systems are interstate natural gas pipelines regulated by the FERCunder the NGA, and the NGPA. Each system operates under separate FERC-approvedtariffs that establish rates, terms and conditions under which each systemprovides service to its customers. In addition, the FERC’s authority overnatural gas companies that provide natural gas pipeline transportation servicesin interstate commerce includes:

·       certificationand construction of new facilities;

·       extensionor abandonment of services and facilities;

·       maintenanceof accounts and records;

·       acquisitionand disposition of facilities;

·       initiationand discontinuation of services;

·       conductand relationship with energy affiliates; and

·       variousother matters.

Tariff changes can only be implemented upon approvalby the FERC. Two primary methods are available for changing the rates, termsand conditions of service of an interstate natural gas pipeline. Under thefirst method, the company voluntarily seeks a tariff change by making a tarifffiling with the FERC justifying the proposed tariff change and providingnotice, generally 30 days, to the appropriate parties. If the FERCdetermines that a proposed change may not be just and reasonable as required bythe NGA, then the FERC may suspend such change for up to five months and setthe matter for an administrative hearing. Subsequent to any suspension periodordered by the FERC, the proposed change may be placed into effect by thecompany, pending final FERC approval. In most cases, a proposed rate increaseis placed into effect before a final FERC determination on such rate increase,and the proposed increase is collected subject to refund (plus interest). Underthe second method, the FERC may, on its own motion or based on a complaint,initiate a proceeding seeking to compel the company to change its rates, termsand/or conditions of service. If the FERC determines that the existing rates,terms and/or conditions of service are unjust, unreasonable, undulydiscriminatory or preferential, then any rate reduction or change that it ordersgenerally will be effective prospectively from the date of the FERC orderrequiring this change.

In November 2003, the FERC issued Order No. 2004governing the Standards of Conduct for Transmission Providers (interstatepipelines). The new standards provide that interstate pipeline employeesengaged in natural gas transmission system operations must functionindependently from any employees of their energy affiliates and marketingaffiliates; and that an interstate pipeline must treat all transmission customers,affiliated and non-affiliated, on a non-discriminatory basis, and cannotoperate its transmission system to benefit preferentially, an energy ormarketing affiliate. Order 2004 restricts access 

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to natural gastransmission customer data by marketing and other energy affiliates andprovides certain conditions on service provided by interstate pipelines totheir gas marketing and energy affiliates. We have implemented changes inbusiness processes to comply with this order.

Additional proposals and proceedings that might affectthe natural gas industry are pending before Congress, the FERC and the courts.The natural gas industry historically has been heavily regulated; therefore,there is no assurance that a more stringent regulatory approach will not be pursuedby the FERC and Congress, especially in light of alleged market power abuse bymarketing affiliates of certain pipeline companies engaged in interstatecommerce.

***Intrastate Pipeline Regulation***

Our intrastate liquids and natural gas pipelineoperations generally are not subject to rate regulation by the FERC, but theyare subject to regulation by various agencies of the states in which they arelocated. However, to the extent that our intrastate pipeline systems delivernatural gas into interstate commerce, the rates, terms and conditions of suchtransportation service are subject to FERC jurisdiction under Section 311of the NGPA, which regulates, among other things, the provision oftransportation services by an intrastate natural gas pipeline making deliverieson behalf of a local distribution company or an interstate natural gaspipeline. Most states have agencies that possess the authority to review andauthorize natural gas transportation transactions and the construction,acquisition, abandonment and interconnection of physical facilities. Somestates also have state agencies that regulate transportation rates, serviceterms and conditions and contract pricing to ensure their reasonableness and toensure that the intrastate pipeline companies that they regulate do notdiscriminate among similarly situated customers.

***Natural Gas Gathering Pipeline Regulation***

Section 1(b) of the NGA exempts natural gasgathering facilities from the jurisdiction of the FERC under the NGA. We owncertain natural gas pipelines that we believe meet the traditional tests theFERC has used to establish a pipeline’s status as a gatherer not subject to theFERC jurisdiction. State regulation of gathering facilities generally includesvarious safety, environmental and, in some circumstances, nondiscriminatorytake requirements, but historically has not entailed rate regulation. Recently theFERC has initiated an inquiry regarding the extent to which gathering (bothoffshore and onshore) systems, particularly those that have been previously transferredfrom a regulated entity should be regulated by the FERC. Further, some stateshave or are considering providing greater regulatory scrutiny over thecommercial regulation of natural gas gathering business. Many of the producingstates have previously adopted some form of complaint-based regulationthat generally allows natural gas producers and shippers to file complaintswith state regulators in an effort to resolve grievances relating to naturalgas gathering access and rate discrimination. Our gathering operations could beadversely affected should they be subject in the future to the application ofstate or federal regulation of rates and services. Our gathering operationsalso may be or become subject to safety and operational regulations relating tothe design, installation, testing, construction, operation, replacement andmanagement of gathering facilities. During 2005 a notice of proposed rulemakingexpanding federal safety regulation over portions of natural gas gatheringsystems was proposed. We cannot predict what effect, if any, such changes mighthave on our operations, but the industry could be required to incur additionalcapital expenditures and increased costs depending on future legislative andregulatory changes.

***Sales of Natural Gas, Crude Oil, Condensate andNatural Gas Liquids***

The price at which we sell natural gas currently isnot subject to federal or state regulation except for certain systems in Texas.Our sales of natural gas are affected by the availability, terms and cost ofpipeline transportation. As noted above, the price and terms of access topipeline transportation are subject to extensive federal and state regulation.The FERC is continually proposing and implementing new 

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rules and regulationsaffecting those segments of the natural gas industry, most notably interstatenatural gas transmission companies, that remain subject to the FERC’sjurisdiction. These initiatives also may affect the intrastate transportationof natural gas under certain circumstances. The stated purpose of many of theseregulatory changes is to promote competition among the various sectors of thenatural gas industry and these initiatives generally reflect more light-handedregulation. We cannot predict the ultimate impact of these regulatory changesto our natural gas marketing operations. Some of the FERC’s more recentproposals may adversely affect the availability and reliability ofinterruptible transportation service on interstate pipelines. We do not believethat we will be affected by any such FERC action in a manner that is materiallydifferent than other natural gas marketers with whom we compete.

Our sales of crude oil, condensate and natural gasliquids currently are not regulated and are made at market prices. In a numberof instances, however, the ability to transport and sell such products isdependent on pipelines whose rates, terms and conditions of service are subjectto the FERC’s jurisdiction under the ICA. Certain regulations implemented bythe FERC in recent years could increase the cost of transportation service oncertain petroleum products pipelines. However, we do not believe that theseregulations affect us any differently than other marketers of these products.

***Other Regulation***

The governments of the United States and Canada have,by treaty, agreed to ensure nondiscriminatory treatment for the passage of oiland natural gas through the pipelines of one country across the territory ofthe other. Individual border crossing points require U.S. government permitsthat may be terminated or amended at the will of the U.S. government. Thesepermits provide that pipelines may be inspected by or subject to orders issuedby federal or state government agencies.

***Tariffs and Rate Cases***

***Lakehead system***

Under published tariffs at December 31, 2005(including the tariff surcharges related to Lakehead system expansions) fortransportation on the Lakehead system, the rates for transportation of lightcrude oil from Neche, North Dakota, where the System enters the United States(unless otherwise stated), to principal delivery points are set forth below.

| ** **                                           | ** ** | **Published**                   | ** ** |
|------------------------------------------------------|------------|---------------------------------|------------|
| ** **                                           | ** ** | **Tariff Per Barrel** | ** ** |
| To Clearbrook, Minnesota                   |       |                            | $          | 0.186 |   |   |
| To Superior, Wisconsin                               |       |                            | $          | 0.363 |   |   |
| To Chicago, Illinois area                            |       |                            | $          | 0.742 |   |   |
| To Marysville, Michigan area                         |       |                            | $          | 0.888 |   |   |
| To Buffalo, New York area                            |       |                            | $          | 0.909 |   |   |
| Chicago to the  international border near Marysville |       |                            | $          | 0.329 |   |   |

 

The rates at December 31, 2005 for medium andheavy crude oils are higher, and those for NGL’s are lower than the rates setforth in the table to compensate us for differences in the costs of shippingdifferent types and grades of liquid hydrocarbons. We periodically adjust ourtariff rates as allowed under the FERC’s indexing methodology and the tariffagreements described below.

The base portion of the rates for the Lakehead systemare subject to the FERC’s indexing mechanism and are adjusted annually toconform to the FERC index. Under the Settlement Agreement with CAPP that theFERC approved in 1996 and reconfirmed in 1998, we implemented a tariffsurcharge related to 

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the second phase of ourSEP II project. This tariff surcharge, which is added to the base rates, is acost-of-service based calculation that is trued-up annually (usually in April)for actual costs and throughputs from the previous calendar year, and is notsubject to indexing. While the term of the 1996 settlement agreement hasexpired, we continue to abide by the spirit of the original agreement in our customerrelationships.

Under the Tariff Agreement approved by the FERC in1998, we also implemented a tariff surcharge for the Terrace expansion programof approximately $0.013 per barrel for light crude oil from the Canadian borderto Chicago. On April 1, 2001, pursuant to an agreement between us andEnbridge Pipelines, our share of the surcharge was increased to $0.026 perbarrel. This surcharge was in effect until April 1, 2004, when thesurcharge to us changed to $0.007 per barrel. This $0.007 surcharge is expectedto be in effect until 2010, after which time the surcharge will return to$0.013 per barrel through 2013, the term of the agreement. In addition to theTerrace surcharge, included in the 2005 tariff is the Terrace Schedule Cadjustment. Under the tariff agreement, when Terrace Phase III facilities arein service, and annual actual average pumping exiting Clearbrook are less than225,000 M3 per day, an adjustment is made to the Terracesurcharge. In 2005, this adjustment is $0.031 per barrel, based on annualactual average pumping exiting Clearbrook of 177,200 M3 perday in 2004.

On July 1, 2004, the FERC approved a settlementwith CAPP involving a Facilities Surcharge mechanism, which allows for therecovery of costs for enhancements or modifications to the system at shipperrequest and approved by CAPP. The Facilities Surcharge permits the Lakehead systemto recover the costs associated with particular shipper-requestedprojects through an incremental surcharge layered on top of the existing baserates and other FERC-approved surcharges already in effect. Like the SEP IIsurcharge, the Facilities Surcharge is a cost-of-service-based tariffmechanism that is trued-up each year for actual costs and throughput and,therefore, is not subject to adjustment either upwards or downwards underindexing. In 2005, the Facilities Surcharge was $0.007 per barrel for lightmovements from the U.S./Canada border near Neche, North Dakota to Chicago. TheFacilities Surcharge currently includes four projects that were agreed to withCAPP in 2004. Additional projects to be included in the Facilities Surchargewill be determined as the result of a negotiating process between management ofthe Lakehead system and CAPP.

In late 2005, we reached agreement with CAPP on atariff mechanism to recover the costs of the mainline expansion portion of theSouthern Access project. As agreed by CAPP, the proposed surcharge iscalculated using FERC Opinion 154-B methodology. The Opinion 154-B cost basedsurcharge is credited for incremental volumes utilizing the Lakehead systemcapacity in excess of the Lakehead system's Terrace configuration capacity.  This is a customary regulatory principle andassures recovery by the pipeline of no more than its allowed rate of return onthe Southern Access project.  If noincremental volumes are moved on the capacity then the credit is generallyzero, except**as follows.  The Southern Access project removes a Systemcapacity bottleneck at Superior that otherwise limits the earnings potential ofprevious expansion projects such as the Terrace expansion. Consequently, a50% revenue credit is provided if utilization of the Lakehead system capacitybetween Superior and Chicago is greater than the Lakehead system was otherwisecapable of without the Southern Access project. This ex-Superior tolling mechanism is designed to share with ourcustomers the benefits associated with the removal of the Terrace earningslimitation.  On December 21, 2005, we filed an offerof settlement with the FERC seeking FERC approval for the Southern Accessmainline expansion surcharge under the provisions of the previously approvedFacilities Surcharge mechanism. The FERC will accept comments from shippers andother interested parties on the offer of settlement before determining whetherto approve it. The FERC’s ultimate decision on this surcharge is uncertain atthis time, pending receipt of comments and any further proceedings that mayoccur in this docket. We have requested an expedited FERC decision on the offerof settlement.****If the FERC fails to approve the proposedtariff mechanism for the Southern Access mainline expansion, or if it attachedunacceptable conditions to such approval, that could have an adverse effect onour ability to proceed with the project or impact its timing.

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*Natural Gas Systems*

Tariff rates on the FERC-regulated natural gas pipelinesvary by pipeline and, in the case of KPC, by receipt point and delivery point.Competitive forces may prompt us to charge tariff rates below the FERC-approvedceiling rate on our interstate systems. The rates charged for transmission ofnatural gas on pipelines not regulated by the FERC, or a state agency, areestablished by competitive forces.

***Safety Regulation and Environmental***

*General*

Our transmission and gathering pipelines and storageand processing facilities are subject to extensive federal and stateenvironmental, operational and safety regulation. The added costs imposed byregulations are generally no different than those imposed on our competitors.The failure to comply with such rules and regulations can result insubstantial penalties and/or enforcement actions and added operational costs.

*Pipeline Safety andTransportation Regulation*

Our transmission and non-rural gathering pipelines aresubject to regulation by the DOT, under Title 49 United States Code (PipelineSafety Act) relating to the design, installation, testing, construction,operation, replacement and management of transmission and non-rural gatheringpipeline facilities. Periodically the PSA has been reauthorized and amended,imposing new mandates on the regulator to promulgate new regulations, imposingdirect mandates on operators of pipelines.

On December 17, 2002 the PSI Act of 2002 wasenacted reauthorizing and amending the PSA in several important respects.Following requirements of mandates in the PSA, the DOT has issued regulationsrequiring operators of hazardous liquid and natural gas transmission pipelinessubject to the regulations to assess, evaluate, repair and validate, through acomprehensive analysis, the integrity of pipeline segments that, in the eventof a leak or failure, could affect a high consequence area. HCA’s for liquidpipelines have been defined as: populated areas, areas unusually sensitive toenvironmental damage and commercially navigable waterways. For natural gaspipelines, HCA’s are defined as segments in proximity to population density orplaces of public congregation.

The DOT has issued rules on requirements tosubmit maps, additional reports and enhance operator personnel qualificationprograms. We anticipate new rules regulating pipeline security, contractordrug testing, inspection, public awareness programs and annual informationreporting. The 2002 amendments of the PSA also called for expanded regulationsfor qualification of workers performing safety-related tasks onpipelines, which we expect to be enacted by incorporation of an industryconsensus standard currently under development. We have incorporated many ofthe anticipated new requirements into procedures and budgets and, while weexpect to incur higher regulatory compliance costs, the increase is notexpected to be material. Additionally, revised regulations are anticipated thatmay impose new federal mandates on certain non-DOT jurisdictional pipelinescurrently classified as “rural gathering lines.” Pending specific proposedregulations, we are not certain of the effect or costs that the new requirementsmay have on our operations.

Various states in which we operate have authority toissue additional regulations affecting intrastate or gathering pipeline design,safety and operational requirements. In particular, during 2003 the State ofOklahoma passed legislation affecting gathering pipeline business activitiesand in early 2005, the State of Texas proposed new legislation that could, ifpassed, increase the commercial regulation of gathering pipelines. We are notcertain of the effect that passage of the final legislation, or any of thelegislation will have on our business operations or costs.

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Our trucking and railcar operations are also subjectto safety and permitting regulation by the DOT and state agencies with regardto the safe transportation of hazardous and other materials.

We believe that our pipeline, trucking and railcaroperations are in substantial compliance with applicable operational and safetyrequirements. In instances of non-compliance, we have taken actions toremediate the situations. Nevertheless, significant expenses could be incurredin the future if additional safety measures are required or if safety standardsare raised and exceed the capabilities of our current pipeline control systemor other safety equipment.

*PressureRestrictions on the Lakehead system*

Following a leak thatoccurred on our Lakehead system in July 2002, the federal Pipeline andHazardous Materials Safety Administration (PHMSA, formerly the OPS) imposedpressure restrictions on the entire line that was affected. At the time, weproposed a return-to-service plan, which included implementing certain internalinspections and other strategies to verify the integrity of the pipeline in theaffected area. During 2003, the PHMSA removed a majority of the restrictions,while directing that a small restriction remain in place in one area of theline in Minnesota. PHMSA has indicated that this restriction is expected to beremoved following another internal inspection and associated pipelinerehabilitation expenditures to be concluded in 2006, evaluation of the interimperformance of the line and assessment of our progress in implementing our riskmanagement plan.

*EnvironmentalRegulation*

*General.**  **Our operations are subject to complexfederal, state, and local laws and regulations relating to the protection ofhealth and the environment, including laws and regulations which govern thehandling, storage and release of crude oil and other liquid hydrocarbonmaterials or emissions from natural gas compression facilities. As with thepipeline and processing industry in general, complying with current andanticipated environmental laws and regulations increases our overall cost ofdoing business, including our capital costs to construct, maintain, and upgradeequipment and facilities. While these laws and regulations affect ourmaintenance capital expenditures and net income, we believe that they do notaffect our competitive position since the operations of our competitors aregenerally similarly affected.*

In addition to compliance costs, violations ofenvironmental laws or regulations can result in the imposition of significantadministrative, civil and criminal fines and penalties and, in some instances,injunctions banning or delaying certain activities. We believe that ouroperations are in substantial compliance with applicable environmental laws andregulations.

There are also risks of accidental releases into theenvironment associated with our operations, such as leaks or spills of crudeoil, liquids or natural gas or other substances from our pipelines or storagefacilities. Such accidental releases could, to the extent not insured, subjectus to substantial liabilities arising from environmental cleanup andrestoration costs, claims made by neighboring landowners and other thirdparties for personal injury and property damage, and fines, penalties, ordamages for related violations of environmental laws or regulations.

Although we are entitled, in certain circumstances, toindemnification from third parties for environmental liabilities relating toassets we acquired from those parties, these contractual indemnification rightsare limited and, accordingly, we may be required to bear substantialenvironmental expenses. However, we believe that through our due diligenceprocess, we identify and manage substantial issues.

*Airand Water Emissions.**  *Ouroperations are subject to the federal Clean Air Act and the federal Clean WaterAct and comparable state and local statutes. We anticipate, therefore, that wewill incur certain capital expenses in the next several years for air pollutioncontrol equipment and spill prevention 

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measures in connectionwith maintaining existing facilities and obtaining permits and approvals forany new or acquired facilities.

An operating permit excursion occurred at our Bryans’Mill Treating Plant in 2003 where a significant amount (approximately 7,000tons) of sulfur-dioxide (SO2) was released above permit limits. Weself-reported the incident to the applicable state agency. We found a plantcatalyst bed to be deficient and corrected the problem. We have augmented ouradministrative reporting systems and operations procedures to prevent futureoccurrences. In 2005 an administrative penalty of $68,158 was issued by thestate in the form of an Agreed Order which we accepted.

The Oil Pollution Act(OPA) was enacted in 1990 and amends parts of the CWA and other statutes asthey pertain to the prevention of and response to oil spills. Under the OPA, wecould be subject to strict, joint and potentially unlimited liability forremoval costs and other consequences of an oil spill from our facilities intonavigable waters, along shorelines or in an exclusive economic zone of theUnited States. The OPA also imposes certain spill prevention, control andcountermeasure requirements for many of our non-pipeline facilities, such asthe preparation of detailed oil spill emergency response plans and theconstruction of dikes or other containment structures to prevent contaminationof navigable or other waters in the event of an oil overflow, rupture or leak.For our liquid pipeline facilities, the OPA imposes requirements for emergencyplans to be prepared, submitted and approved by the DOT. For ournon-transportation facilities, such as storage tanks that are not integral topipeline transportation system, the OPA regulations are promulgated by the EPA.We believe we are in material compliance with these laws and regulations.

*Hazardous Substances andWaste Management.**  *Thefederal CERCLA (also known as the “Superfund” law), and similar state laws,impose liability without regard to fault or the legality of the originalconduct, on certain classes of persons, including the owners or operators ofwaste disposal sites and companies that disposed or arranged for disposal ofhazardous substances found at such sites. We may generate some wastes that fallwithin the definition of a “hazardous substance.” We may, therefore, be jointlyand severally liable under CERCLA for all or part of any costs required toclean up and restore sites at which such wastes have been disposed. Inaddition, it is not uncommon for neighboring landowners and other third partiesto file claims for personal injury and property damage allegedly caused byhazardous substances or other pollutants released into the environment.Analogous state laws may apply to a broader range of substances than CERCLAand, in some instances, may offer fewer exemptions from liability. We have notreceived any notification that we may be potentially responsible for materialcleanup costs under CERCLA or similar state laws.

*Employee Health and Safety.**  *The workplaces associated with ouroperations are subject to the requirements of the federal OSHA and comparablestate statutes that regulate worker health and safety. We have an ongoingsafety, procedure and training program for our employees and believe that ouroperations are in compliance with applicable occupational health and safetyrequirements, including industry consensus standards, record keepingrequirements, monitoring of occupational exposure to regulated substances, andhazard communication standards.

*Site Remediation.**  *We own and operate a number ofpipelines, gathering systems, storage facilities and processing facilities thathave been used to transport, distribute, store and process crude oil, naturalgas and other petroleum products. Many of our facilities were previously ownedand operated by third parties whose handling, disposal and release of petroleumand waste materials were not under our control. The age of the facilities,combined with the past operating and waste disposal practices, which werestandard for the industry and regulatory regime at the time, have resulted insoil and groundwater contamination at some facilities due to historical spillsand releases. Such contamination is not unusual within the natural gas andpetroleum industry. Historical contamination found on, under or originatingfrom our properties may be subject to CERCLA, RCRA and analogous state laws asdescribed above. 

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Under these laws,we could incur substantial expense to remediate such contamination, includingcontamination caused by prior owners and operators. In addition, EnbridgeManagement, as the entity with managerial responsibility for us, could also beliable for such costs to the extent that we are unable to fulfill ourobligations. We have conducted site investigations at some of our facilities toassess historical environmental issues, and we are currently addressing soiland groundwater contamination at various facilities through remediation andmonitoring programs, with oversight by the applicable government agencies whereappropriate.

In connection with ouracquisition of the Midcoast system from Enbridge, the General Partner agreed toindemnify us and other related persons for certain environmental liabilities ofwhich the General Partner had knowledge. Pursuant to the contribution agreementrelated to this acquisition, the General Partner will not be required toindemnify us until the aggregate liabilities, including environmental liabilities,exceed $20.0 million, and the General Partner’s aggregate liability,including environmental liabilities, may not exceed, with certain exceptions,$150.0 million. We will be liable for any environmental conditions relatedto the acquired systems that were not known to the General Partner or weredisclosed under the contribution agreement between the General Partner and us.In addition, we will be liable for all removal, remediation and disposal of allasbestos containing materials and all naturally occurring radioactive materialsassociated with the Northeast Texas system and for which the General Partner isliable to the prior owner of that system.

Although we believe theseindemnities and conditions provide valuable protection, it is possible that thesellers from whom these assets were purchased will not be able to satisfy theirindemnity obligations or their remedial obligations related to retainedliabilities or properties. In this case, it is possible that governmentalagencies or third party claimants could assert that we may be liable or bearsome responsibility for such obligations.

**EMPLOYEES**

Neither we nor EnbridgeManagement, has any employees. Our general partner has delegated to EnbridgeManagement, pursuant to a delegation of control agreement, substantially all ofthe responsibility for our day-to-day management and operation. Our general partner,however, retains certain functions and approval rights over our operations. Tofulfill its management obligations, Enbridge Management has entered intoagreements with Enbridge and several of its affiliates to provide EnbridgeManagement with the necessary services and support personnel, who act onEnbridge Management’s behalf as its agents. We are ultimately responsible for reimbursingthese service providers based on the costs that they incur in performing theseservices.

**INSURANCE**

Our operations are subjectto many hazards inherent in the liquid petroleum and natural gas gathering, treating,processing and transportation industry. We maintain insurance coverage for ouroperations and properties considered to be customary in the industry. There canbe no assurance, however, that insurance coverage we maintain will be availableor adequate for any particular risk or loss, or that we will be able tomaintain adequate insurance in the future at rates we consider reasonable.Although we believe that our assets are adequately covered by insurance, asubstantial uninsured loss could have a material adverse effect on our financialposition, results of operations and cash flows.

**CAPITALEXPENDITURES**

In 2005, we made capitalexpenditures of $344.8 million, of which $311.8 million was forpipeline system enhancements, and $33.0 million for core maintenance. Seealso “Item 7. Management’s Discussion and Analysis of Financial Conditionand Results of Operations—Liquidity and Capital Resources—Investing Activities.”

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**TAXATION**

For U.S. federal and stateincome tax purposes, we are not a taxable entity. Federal and state incometaxes on our taxable income are borne by our individual partners through theallocation of our taxable income. Such taxable income may vary substantiallyfrom net income reported in our consolidated statements of income.

**AVAILABLEINFORMATION**

We file annual, quarterlyand other reports, and any amendments to those reports, and information withthe SEC under the Exchange Act. You may read and copy any materials that wefile with the SEC at the SEC’s Public Reference Room at 100 F Street, NE,Washington, DC 20549. You may obtain additional information about the PublicReference Room by calling the SEC at 1-800-SEC-0330. Inaddition, the SEC maintains an Internet site *http://www.sec.gov*that contains reports, proxy and information statements, and other informationregarding issuers that file electronically with the SEC, including ours.

We also makes availablefree of charge on or through our Internet website *http://www.enbridgepartners.com* our Annual Report on Form 10-K,Quarterly Reports on Form 10-Q, Current Reports on Form 8-Kand other information statements, and if applicable, amendments to thosereports filed or furnished pursuant to Section 13(a) of the ExchangeAct, as soon as reasonably practicable after we electronically file suchmaterial with the SEC. Information contained on our website is not part of thisreport.

**Item 1A. RiskFactors**

We encourage you to readthe risk factors below in connection with the other sections of this AnnualReport on Form 10-K.

**RisksRelated to Our Business**

***Our financial performance could be adversely affectedif our pipeline systems are used less.***

Our financial performancedepends to a large extent on the volumes transported on our pipeline systems. Decreasesin the volumes transported by our systems, whether caused by supply or demandfactors in the markets these systems serve, competition or otherwise, candirectly and adversely affect our revenues and results of operations.

The volume of shipments onour Lakehead system depends heavily on the supplies of western Canadian crudeoil. Insufficient supplies of western Canadian crude oil will adversely affectour business by limiting shipments on our Lakehead system. Crude oil deliverieson our Lakehead system have declined from the prior year in each of the lastthree calendar years, because of decreases in conventional crude oilexploration and production activities in western Canada and other factorsincluding supply disruption and competition. In January 2005, deliveries on ourLakehead system were impacted by a fire at a Suncor facility. The volume ofcrude oil that we transport on the Lakehead system also depends on the demandfor crude oil in the Great Lakes and Midwest regions of the United States andthe delivery by others of crude oil and refined products into these regions andthe Province of Ontario. Pipeline capacity for the delivery of crude oil to theGreat Lakes and Midwest regions of the United States currently exceeds refiningcapacity.

In addition, our abilityto increase deliveries to expand the Lakehead system in the future depends onincreased supplies of western Canadian crude oil. We expect that growth infuture supplies of western Canadian crude oil will come from oil sands projectsin Alberta, Canada. Furthermore, full utilization of additional capacity as aresult of our current and future expansions of the Lakehead system, includingthe Terrace expansion program, will largely depend on these anticipatedincreases in crude oil production from oil sands projects.

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The volume of shipments onnatural gas systems depends on the supply of natural gas and NGLs available forshipment on those systems from the producing regions that supply these systems.Volumes shipped on these systems also are affected by the demand for naturalgas and NGLs in the markets these systems serve. Existing customers may notextend their contracts if the availability of natural gas from the Mid-Continent,Gulf Coast and East Texas producing regions was to decline or if the cost oftransporting natural gas from other producing regions through other pipelinesinto the markets served by the natural gas systems was to render the deliveredcost of natural gas on our systems uneconomical. We may be unable to findadditional customers to replace the lost demand or transportation fees.

***Changes in our tariff rates or challenges to ourtariff rates could have a material adverse effect on our financial conditionand results of operations; a*** recent FERC Policy Statement that limitedallowances for income tax in an unrelated pipeline’s cost of service, ifapplied to our FERC-regulated systems, could adversely affect our rates.

The tariff rates chargedby several of our existing pipeline systems are regulated by the FERC, orvarious state regulatory agencies. If one of these regulatory agencies, on itsown initiative or due to challenges by third parties, were to lower our tariffrates, the profitability of our pipeline businesses might suffer. If we werepermitted to raise our tariff rates for a particular pipeline, there might besignificant delay between the time the tariff rate increase is approved and thetime that the rate increase actually goes into effect, which delay couldfurther reduce our cash flow. Furthermore, competition from other pipelinesystems may prevent us from raising our tariff rates even if regulatoryagencies permit us to do so. The regulatory agencies that regulate our systemsperiodically propose and implement new rules and regulations, terms andconditions of services subject to their jurisdiction. New initiatives or ordersmay adversely affect the tariff rates charged for our services. Several states,including Oklahoma and Texas, are taking a more active role in the rate andservice regulation of gathering and intrastate transmission natural gas systems.Increased state regulation could adversely impact our natural gas systems.

The question of whether and to what extent an incometax allowance should be included in a regulated utility’s cost of service forrate-making purposes was a matter of uncertainty for a number of years. In a 2004decision involving an oil pipeline limited partnership, *BP West Coast, LLC v. FERC*, a UnitedStates Court of Appeals for the District of Columbia Circuit vacated the FERC’spolicy that allowed an oil pipeline limited partnership to include in its costsof service an income tax allowance to the extent that its unitholders werecorporations subject to income tax. In its Policy Statement on Income TaxAllowances issued on May 4, 2005, the FERC concluded that it would permitan income tax allowance for all entities or individuals owning public utilityassets, provided that such entities or individuals have an actual or potentialincome tax liability on the public utility income. The burden is on the entityseeking the income tax allowance in a specific rate proceeding to establishthat its partners have an actual or potential income tax obligation on theentity’s public utility income. Whether a pipeline’s owners have such actual orpotential income tax liability will be reviewed by the FERC on a case-by-casebasis. Although the new policy is generally favorable for pipelines that areorganized as pass-through entities, it still entails rate risk due to the case-by-casereview requirement.  On December 16,2005, FERC issued its first case-specific oil pipeline review of the income taxallowance issue in the SFPP proceeding, reaffirming its new income taxallowance policy and directing SFPP to provide certain evidence necessary forthe pipeline to determine its income tax allowance.  Further, in the December 16 order, FERCconcluded that for tax allowance purposes, FERC would apply a rebuttablepresumption that corporate partners of pass-through entities pay the maximum marginaltax rate of 35% and that non-corporate partners of pass-through entities pay amarginal tax rate of 28%. The new tax allowance policy as applied to the *BP West Coast* decision is subject torehearing and possible further action by the United States Court of Appeals forthe District of Columbia Circuit or another court on appeal. Further,application of the FERC’s policy statement in individual cases may be subjectto further FERC action or review in the appropriate Court of Appeals. Theultimate outcome of these proceedings, therefore, is not certain and couldresult in changes to the FERC’s 

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treatment of income taxallowances in cost of service. If we were to file for a cost of service-basedrate increase, we would be subject to FERC’s new policy and potential challenges of that policy. On ourLakehead system, base rates are subject to the FERC indexing mechanismconsistent with our expired settlement agreement and are not currently affectedby the tax allowance policy.  However,the original base rates calculated in accordance with the Settlement Agreementemployed a lower tax allowance than provided for by the new policy.  Were the Lakehead system, or any of our FERCregulated systems, subject to a cost-of-service regulatory proceeding in thefuture, the tax allowance issue would be one of the many factors which wouldaffect the resulting rates.

***Competition may reduce our revenues.***

Our Lakehead system faces current, and potentiallyfurther competition for transporting western Canadian crude oil from otherpipelines, which may reduce its revenues. Our Lakehead system competes withother crude oil and refined product pipelines and other methods of deliveringcrude oil and refined products to the refining centers of Minneapolis-St. Paul,Minnesota; Chicago, Illinois; Detroit, Michigan; Toledo, Ohio; Buffalo, NewYork; and Sarnia, Ontario and the refinery market and pipeline hub located inthe Patoka/Wood River area of southern Illinois. Refineries in the marketsserved by our Lakehead system compete with refineries in western Canada, theProvince of Ontario and the Rocky Mountain region of the United States forsupplies of western Canadian crude oil.

Our Ozark pipeline systemcould face a significant increase in competition if a proposed new pipelinefrom Hardisty, Alberta to Patoka is completed in 2009. However, if thatsituation occurs, we would consider potential alternative uses for our Ozarksystem.

We also encountercompetition in our natural gas gathering, treating, processing and transmissionbusinesses. Many of the large wholesale customers served by our systems’transmission and wholesale customer pipelines have multiple pipelines connectedor adjacent to their facilities. Thus, many of these wholesale customers havethe ability to purchase natural gas directly from a number of pipelines and/orfrom third parties that may hold capacity on other pipelines. Likewise, mostnatural gas producers and owners have alternate gathering and processingfacilities available to them. In addition, they have other alternatives, suchas building their own gathering facilities or, in some cases, selling theirnatural gas supplies without processing. Some of our natural gas marketingcompetitors have greater financial resources and access to larger supplies ofnatural gas than those available to us, which could allow those competitors toprice their services more aggressively than we do.

***Competition with Enbridge may reduce our revenues.***

Enbridgehas agreed with us that, so long as an affiliate of Enbridge is our generalpartner, Enbridge and its subsidiaries may not engage in or acquire anybusiness that is in direct material competition with our businesses, subject tothe following exceptions:

·       Enbridgeand its subsidiaries are not restricted from continuing to engage inbusinesses, including the normal development of such businesses, in which theywere engaged at the time of our initial public offering in December 1991;

·       suchrestriction is limited geographically only to those routes and products forwhich we provided transportation at the time of our initial public offering;

·       Enbridgeand its subsidiaries are not prohibited from acquiring any competitive businessas part of a larger acquisition, so long as the majority of the value of thebusiness or assets acquired, in Enbridge’s reasonable judgment, is notattributable to the competitive business; and

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·       Enbridgeand its subsidiaries are not prohibited from acquiring any competitive businessif that business is first offered for acquisition to us and we fail to approve,after submission to a vote of unitholders, the making of the acquisition.

Since we were not engagedin any aspect of the natural gas business at the time of our initial publicoffering, Enbridge and its subsidiaries are not restricted from competing withus in any aspect of the natural gas business. In addition, Enbridge and itssubsidiaries would be permitted to transport crude oil and liquid petroleumover routes that are not the same as our Lakehead system even if suchtransportation is in direct material competition with our business.

This agreement alsoexpressly permitted the reversal by Enbridge in 1999 of one of its pipelinesthat extends from Sarnia, Ontario to Montreal, Quebec. As a result of thisreversal, Enbridge competes with us to supply crude oil to the Ontario, Canadamarket. This competition from Enbridge has reduced our deliveries of crude oilto Ontario.

***Our gas marketing operations involve market andcertain regulatory risks.***

Aspart of our natural gas marketing activities, we purchase natural gas at pricesdetermined by prevailing market conditions. Following our purchase of naturalgas, we generally resell natural gas at a higher price under a sales contractthat is generally comparable in terms to our purchase contract, including anyprice escalation provisions. The profitability of our natural gas operationsmay be affected by the following factors:

·       ourability to negotiate on a timely basis natural gas purchase and salesagreements in changing markets;

·       reluctanceof wholesale customers to enter into long-term purchase contracts;

·       consumers’willingness to use other fuels when natural gas prices increase significantly;

·       timingof imbalance or volume discrepancy corrections and their impact on financialresults;

·       theability of our customers to make timely payment;

·       inabilityto match purchase and sale of natural gas on comparable terms; and

·       changes in, limitiationsupon, or elimination of the regulatory authorization required for our wholesalesales of  natural gas in interstatecommerce.

***Our results may be adversely affected by commodityprice volatility and risks associated with our hedging activities.***

We buy and sell naturalgas and NGLs in connection with our marketing activities. Commodity priceexposure is also inherent in gas purchase and resale activities and in gasprocessing. To the extent that we engage in hedging activities to reduce ourcommodity price exposure, we may be prevented from realizing the full benefitsof price increases above the level of the hedges. Further, hedging contractsare subject to the credit risk that the other party may prove unable orunwilling to perform its obligations under such contracts. In addition certainof the financial instruments we use to hedge our commodity risk exposures mustbe accounted for on a mark-to-market basis. This causes periodic earningvolatility due to turbulent commodity prices.

***Compliance with environmental and operational safetyregulations, including any remediation of soil or water pollution orhydrostatic testing of our pipeline systems, may increase our costs and/orreduce our revenues.***

Our pipeline, gathering,processing and trucking operations are subject to federal, state and local lawsand regulations relating to environmental protection and operational and workersafety. Liquid petroleum and natural gas transportation and processingoperations always involve the risk of costs or liabilities or operationalmodifications related to regulatory compliance as well as resulting fromhistorical 

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environmentalcontamination, accidental releases or upsets, regulatory enforcement,litigation or safety and health incidents. As a result, we may incur costs orliabilities of this type, or experience a reduction in revenues, in the future.We may also incur costs in the future due to changes in environmental andsafety laws and regulations, enforcement policies or claims for personal,property or environmental damage. We may not be able to recover these costsfrom insurance or through higher tariffs.

***Failure of pipeline operations due to unforeseeninterruptions or catastrophic events may adversely affect our business andfinancial condition.***

Operation of complexpipeline systems, gathering, treating, processing and trucking operationsinvolves many risks, hazards and uncertainties, such as operational hazards andunforeseen interruptions caused by events beyond our control. These eventsinclude adverse weather conditions, accidents, the breakdown or failure ofequipment or processes, the performance of the facilities below expected levelsof capacity and efficiency and catastrophic events such as explosions, fires,earthquakes, hurricanes, floods, landslides or other similar events beyond ourcontrol. A casualty occurrence might result in injury or loss of life orextensive property or environmental damage for which we may bear a part or allof the cost.

***Our acquisition strategy may be unsuccessful if weincorrectly predict operating results, are unable to identify and completefuture acquisitions and integrate acquired assets or businesses or are unable to raise financing on acceptableterms.***

Theacquisition of complementary energy delivery assets is a component of ourstrategy. Acquisitions present various risks and challenges, including:

·       therisk of incorrect assumptions regarding the future results of the acquiredoperations or expected cost reductions or other synergies expected to berealized as a result of acquiring such operations;

·       therisk of failing to effectively integrate the operations or management ofacquired assets or businesses or a significant delay in such integration; and

·       diversionof management’s attention from existing operations.

In addition, we may beunable to identify acquisition targets and consummate acquisitions in thefuture or be unable to raise, on terms we find acceptable, any debt or equityfinancing that may be required for any such acquisition.

***Our actual construction and development costs couldexceed our forecast and our cash flow from construction and developmentprojects may not be immediate which may limit our ability to increase cashdistributions.***

Ourstrategy contemplates significant expenditures for the development,construction or other acquisitions of energy infrastructure assets. Increaseddemand for the steel used to fabricate the pipe needed for our constructionprojects and increased competition for labor has resulted in increased costsfor these resources. As a result, we may not be able to complete our projectsat the costs currently estimated or within the time periods we have projected.If we experience material cost overruns, we will have to finance these overrunsusing one or more of the following methods:

·       usingcash from operations;

·       delayingother planned projects;

·       incurringadditional indebtedness; or

·       issuingadditional debt or equity.

Any or all of thesemethods may not be available when needed or may adversely affect our futureresults operations and cash flows.

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Our revenues and cash flowsmay not increase immediately on our expenditure of funds on a particularproject. For example, if we build a new pipeline or expand an existingfacility, the design, construction, development and installation may occur overan extended period of time and we may not receive any material increase inrevenue or cash flow from that project until after it is placed in service andcustomers begin using the systems. If our revenues and cash flow do notincrease at projected levels because of substantial unanticipated delays, orother factors, we may not meet our obligations as they become due and we mayneed to reduce or reprioritize our capital budget, sell non-strategic assets,access the capital markets or reassess our level of distributions tounitholders to meet our capital requirements.

***Oil measurementlosses on the Lakehead system can be materially impacted by changes inestimation, commodity prices and other factors.***

Oil measurementlosses occur as part of the normal operating conditions associated with ourliquid petroleum pipelines. The three types of oil measurement losses include:

·       physicallosses, which occur through evaporation, shrinkage, differences in measurementbetween receipt and delivery locations and other operational incidents;

·       degradationlosses, which result from mixing at the interface between higher quality lightcrude oil and lower quality heavy crude oil in pipelines; and

·       revaluationlosses, which are a function of crude oil prices and the level of the carrier’sinventory.

There are inherentdifficulties in quantifying oil measurement losses because physicalmeasurements of volumes are not practical due to the fact that productsconstantly move through the pipeline and virtually all of the pipeline systemis located underground. In our case, measuring and quantifying oil measurementlosses is especially difficult because of the length of the Lakehead system andthe number of different grades of crude oil and types of crude oil products itcarries. Accordingly, we utilize engineering-based models and operationalassumptions to estimate product volumes in our system and associated oilmeasurement losses.

***The interests ofEnbridge may differ from our interests and the interests of oursecurityholders, and the board of directors of Enbridge Management may considerthe interests of all parties to a conflict, not just the interests of oursecurityholders, in making important business decisions.***

Enbridge indirectly owns all of the stock of ourgeneral partner and all of the voting stock of Enbridge Management, and electsall of the directors of both companies. Furthermore, some of the directors andofficers of our general partners and Enbridge Management are also directors andofficers of Enbridge. Consequently, conflicts of interest could arise betweenour unitholders and Enbridge.

Our partnership agreement limits the fiduciary dutiesof our general partner to our unitholders. These restrictions allow our generalpartner to resolve conflicts of interest by considering the interests of all ofthe parties to the conflict, including Enbridge Management’s interests, ourinterests and those of our general partner. In addition, these limitationsreduce the rights of our unitholders under our partnership agreement to sue ourgeneral partner or Enbridge Management, its delegee, should its directors orofficers act in a way that, were it not for these limitations of liability,would constitute breaches of their fiduciary duties.

We do not have anyemployees. In managing our business and affairs, we will rely on employees ofEnbridge, and its affiliates, who will act on behalf of and as agents for us. Adecrease in the availability of employees from Enbridge could adversely affectus.

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***We are exposed to credit risks of some of ourcustomers***

Our Bamagas system has agreements to providetransportation of up to 276,000 MMBtu/d of natural gas for a remaining periodof 17 years to two utility plants that are indirectly owned by Calpine Corporation.The Bamagas system receives a fixed demand charge of $0.07 per MMBtu of naturalgas for 200,000 MMBtu/d, regardless of whether the capacity is used. Calpinehas recently declared bankruptcy and is in reorganization. Although we fullyexpect our customer to continue to meet its obligations to us under the termsof the transportation agreements, we are exposed to a potential assetimpairment of up to $55 million, representing the book value of thepipeline, if the customer is unable to fulfill its commitments. We are activelymonitoring Calpine’s bankruptcy and are evaluating alternate uses for thesystem.

As a result of the widespread damage caused by hurricanesKatrina and Rita, the major credit rating agencies have issued negative creditimplications for several of our industrial and utility customers. Although wedo not anticipate any significant deterioration in the credit standing of thesecustomers, we continue to monitor their financial condition and expectimprovement in their credit standing as system outages are restored andproperty damage repaired.

***Canada’s ratification of the Kyoto Protocol mayadversely impact our operations.***

In December 2002,Canada ratified the Kyoto Protocol, a 1997 treaty designed to reduce greenhousegas emissions to 6% below 1990 levels. We and Enbridge are monitoring theCanadian federal government’s approach to implementation. While the UnitedStates is not a signatory to the Kyoto Protocol, other environmental protectioninitiatives have been implemented regulating certain priority pollutants.During 2005, a proposed revision to the U.S. Energy Act was offered that wouldhave, if it had passed, expanded the regulation of certain greenhouse gasemissions requiring a cap and establishing a trade to facilitate compliance. Theprovision would have made natural gas pipelines the segment of the gas industryregulated by such an amendment. While this legislation did not pass in 2005,another proposal has been offered by the U.S. Congress early in 2006. While theoutcome is uncertain at this time, if the provision passes, the Partnershipcould be subject to additional costs to monitor and control emissions above andbeyond current practices and permits.

**Risksarising from Our Partnership Structure and Relationships with Our GeneralPartner and Enbridge Management**

***We can issueadditional common or other classes of units, including additional i-units toEnbridge Management when it issues additional shares, which would dilute yourownership interest.***

The issuance ofadditional common or other classes of units by us, including the issuance ofadditional i-units to Enbridge Management when it issues additional shares,other than our quarterly distributions to you, may have the following effects:

·       theamount available for distributions on each unit may decrease;

·       therelative voting power of each previously outstanding unit may decrease; and

·       themarket price of the Class A common units may decline.

Additionally, the public sale by our general partnerof a significant portion of the Class B common units that it currentlyowns could reduce the market price of the Class A common units. Ourpartnership agreement allows the general partner to cause us to register forpublic sale any units held by the general partner or its affiliates. A publicor private sale of the Class B common units currently held by our generalpartner could absorb some of the trading market demand for the outstanding Class Acommon units.

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***We are a holding company and depend entirely on ouroperating subsidiaries’ distributions to service our debt obligations.***

We are a holding company with no material operations.If we cannot receive cash distributions from our operating subsidiaries, wewill not be able to meet our debt service obligations. Our operatingsubsidiaries may from time to time incur additional indebtedness underagreements that contain restrictions, which could further limit each operatingsubsidiary’s ability to make distributions to us.

The debt securitieswe issue and any guarantees issued by the Subsidiary Guarantors will bestructurally subordinated to the claims of the creditors of any of ouroperating subsidiaries who are not guarantors of the debt securities. Holdersof the debt securities will not be creditors of our operating subsidiaries whohave not guaranteed the debt securities. The claims to the assets of thesenon-guarantor operating subsidiaries derive from our own ownership interest inthose operating subsidiaries. Claims of our non-guarantor operatingsubsidiaries’ creditors will generally have priority as to the assets of suchoperating subsidiaries over our own ownership interest claims and willtherefore have priority over the holders of our debt, including the debtsecurities. Our non-guarantor operating subsidiaries’ creditors may include:

·       generalcreditors;

·       tradecreditors;

·       securedcreditors;

·       taxingauthorities; and

·       creditorsholding guarantees.

***Enbridge Management’sdiscretion in establishing our cash reserves gives it the ability to reduce theamount of cash available for distribution to our unitholders.***

Enbridge Management mayestablish cash reserves for us that in its reasonable discretion are necessaryto fund our future operating and capital expenditures, provide for the properconduct of business, comply with applicable law or agreements to which we are aparty or to provide funds for future distributions to partners. These cashreserves affect the amount of cash available for distribution to our holders ofcommon units.

**RisksRelated to Our Debt and Our Ability to Distribute Cash**

***Agreements relatingto our debt restrict our ability to make distributions, which could adverselyaffect the value of our Class A Common Units, and our ability to incuradditional debt and otherwise maintain financial and operating flexibility.***

Our primaryoperating subsidiary is prohibited by its first mortgage notes from makingdistributions to us, and we are prohibited by our credit facility from makingdistributions to our unitholders, if a default exists under the respectivegoverning agreements. In addition, the agreements governing our credit facilityand our subsidiary’s first mortgage notes may prevent us from engaging intransactions or capitalizing on business opportunities that we believe could bebeneficial to us by requiring us to comply with various covenants, includingthe maintenance of certain financial ratios and restrictions on:

·       incurringadditional debt;

·       enteringinto mergers or consolidations or sales of assets; and

·       grantingliens.

Although the indenturesgoverning our senior notes do not limit our ability to incur additional debt,they impose restrictions on our ability to enter into mergers or consolidationsand sales of assets and to 

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incurliens to secure debt. A breach of any restriction under our credit facility orour indentures or our subsidiary’s first mortgage notes could permit theholders of the related debt to declare all amounts outstanding under thoseagreements immediately due and payable and, in the case of the credit facility,terminate all commitments to extend further credit. Any subsequent refinancingof our current debt or any new indebtedness incurred by us or our subsidiariescould have similar or greater restrictions.

**Tax Risks to Common Unitholders**

***We may beclassified as an association taxable as a corporation rather than as apartnership, which would substantially reduce the value of our Class Acommon units.***

We could betreated as a corporation for United States income tax purposes. Our treatmentas a corporation would substantially reduce the cash distributions on thecommon units that we distribute quarterly. Moreover, treatment of us as acorporation would materially and adversely affect our ability to make paymentson our debt securities. The anticipated benefit of an investment in our commonunits depends largely on the treatment of us as a partnership for federalincome tax purposes. Under current law, we are treated as a partnership forfederal income tax purposes and do not pay any federal income tax at the entitylevel. In order to qualify for this treatment, we must derive more than 90% ofour annual gross income from specified investments and activities. While webelieve that we currently do qualify and intend to meet this incomerequirement, we may not find it possible, regardless of our efforts, to meetthis income requirement or may inadvertently fail to meet this incomerequirement. Current law may change so as to cause us to be treated as acorporation for federal income tax purposes without regard to our sources ofincome or otherwise subject us to entity-level taxation. If we were to betreated as a corporation for federal income tax purposes, we would pay federalincome tax on our income at the corporate tax rate, which is currently a maximumof 35% and would pay state income taxes at varying rates. Under current law,distributions to unitholders would generally be taxed as a corporatedistribution. Because a tax would be imposed upon us as a corporation, the cashavailable for distribution to a unitholder would be substantially reduced. Treatmentof us as a corporation would cause a substantial reduction in the value of ourunits.

In addition, because of widespread state budgetdeficits, several states are evaluating ways to subject partnerships toentity-level taxation through the imposition of state income, franchise, orother forms of taxation. State tax legislation resulting in the imposition of apartnership-level income tax on us would reduce the cash distributions on thecommon units and the value of the i-units that we will distribute quarterly toEnbridge Management. The enactment of significant legislation imposingpartnership-level income taxes could cause a reduction in the value of ourunits.

***If the Internal Revenue Service does not respect ourcurative tax allocations, the after-tax return to our unitholders on theirinvestment in our Class A common units would be adversely affected.***

Our partnership agreementallows curative allocations of income, deduction, gain and loss by us toaccount for differences between the tax basis and fair market value of propertyat the time the property is contributed or deemed contributed to us and toaccount for differences between the fair market value and book basis of ourassets existing at the time of issuance of any Class A common units. Ifthe Internal Revenue Service, which we refer to as the IRS, does not respectour curative allocations, ratios of taxable income to cash distributionsreceived by the holders of Class A common units will be materially higherthan previously estimated

***The tax liabilityof our unitholders could exceed their distributions or proceeds from sales of Class Acommon units.***

The holders of our Class Acommon units will be required to pay United States federal income tax and, insome cases, state and local income taxes on their allocable share of ourincome, even if they do not receive cash distributions from us. They will notnecessarily receive cash distributions equal to the tax on 

38

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theirallocable share of our taxable income. Further, if we have a large amount ofnonrecourse liabilities, they may incur a tax liability that is greater thanthe money they receive when they sell their Class A common units.

***A unitholder may berequired to file tax returns with and pay income taxes to the states where weor our subsidiaries own property and conduct business.***

In some cases, aunitholder may be required to file income tax returns with and pay income taxesto the states in which we or our subsidiaries own property and conductbusiness, which are currently Alabama, Alaska, Arkansas, Florida, Georgia,Illinois, Indiana, Kansas, Kentucky, Louisiana, Michigan, Minnesota,Mississippi, Missouri, Montana, New York, South Carolina, North Carolina, NorthDakota, Oklahoma, Tennessee, Texas and Wisconsin. In the future, we may acquireproperty or do business in other states or in foreign jurisdictions. Inaddition to tax liabilities to such state and foreign jurisdictions, the ownerof a Class A common unit may also incur tax and filing responsibilities tolocalities within such jurisdictions.

***Ownership of Class Acommon units raises issues for tax-exempt entities and other investors.***

An investment in our Class Acommon units by tax-exempt entities, including employee benefit plans,individual retirement accounts, Keogh plans and other retirement plans,regulated investment companies and foreign persons raises issues unique tothem. Virtually all of the income derived from our Class A common units bya tax-exempt entity will be “unrelated business taxable income” and will betaxable to the tax-exempt entity. Additionally, no significant part of ourgross income will be considered qualifying income for purposes of determiningwhether a unitholder qualifies as a regulated investment company for its taxyears beginning on or prior to October 22, 2004 (before the American JobsCreation Act of 2004). Further, a unitholder who is a nonresident alien, aforeign corporation or other foreign person will be required to file afederal income tax return and pay tax on his share of our taxable incomebecause he will be regarded as being engaged in a trade or business in theUnited States as a result of his ownership of a Class A common unit.

***Our registrationwith the Secretary of the Treasury as a “tax shelter” may increase your risk ofan IRS audit.***

Because we are aregistered “tax shelter” with the Secretary of the Treasury, a unitholder mayface an increased risk of an IRS audit resulting in taxes payable on our incomeas well as income not related to us. We could be audited by the IRS andadjustments to our income or losses could be made. Any unitholder owning lessthan a 1% profit interest in us has very limited rights to participate in theincome tax and audit process. Further, any adjustments in our tax returns willlead to adjustments in the unitholders’ tax returns and may lead to audits ofunitholders’ tax returns and adjustments of items unrelated to us. Eachunitholder is responsible for any tax owed as the result of an examination oftheir personal tax return.

***Our treatment of apurchaser of Class A common units as having the same tax benefits as theseller could be challenged, resulting in a reduction in value of the Class Acommon units.***

Because we cannot matchtransferors and transferees of Class A common units, we are required tomaintain the uniformity of the economic and tax characteristics of these unitsin the hands of the purchasers and sellers of these units. We do so by adoptingcertain depreciation conventions that do not conform with all aspects of theUnited States Treasury regulations. An IRS challenge to these conventions couldadversely affect the tax benefits to a unitholder of ownership of the Class Acommon units and could have a negative impact on their value.

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**Item 1B. Unresolved Staff Comments**

None.

**Item 2. Properties**

We currently conduct business and/or own propertieslocated in 23 states: Alabama, Alaska, Arkansas, Florida, Georgia, Illinois,Indiana, Kansas, Kentucky, Louisiana, Michigan, Minnesota, Mississippi,Missouri, Montana, New York, North Carolina, North Dakota, Oklahoma, SouthCarolina, Texas, Tennessee and Wisconsin. In general, our systems are locatedon land owned by others and are operated under perpetual easements and rightsof way, licenses or permits that have been granted by private land owners,public authorities, railways or public utilities. The pumping stations, tanks,terminals and certain other facilities of our systems are located on land thatis owned by us, except for five pumping stations that are situated on landowned by others and used by us under easements or permits.

Substantially all of our Lakehead system assets aresubject to a first mortgage lien collateralizing indebtedness of our LakeheadPartnership.

Titles to our propertiesacquired in the Midcoast system acquisition are subject to encumbrances in somecases. We believe that none of these burdens should materially detract from thevalue of these properties or materially interfere with their use in the operationof our business.

**Item 3. Legal Proceedings**

We are a participant invarious legal proceedings arising in the ordinary course of business. Some ofthese proceedings are covered, in whole or in part, by insurance. We believethe outcome of all these proceedings will not, individually or in theaggregate, have a material adverse effect on our financial condition.

**Item 4. Submission of Matters to a Vote of SecurityHolders**

No matters were submitted to a vote of securityholders during the fourth quarter of 2005.

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**PART II**

**Item 5. Market for Registrant’s Common Equity andRelated Unitholder Matters**

Our Class Acommon units are listed and traded on the NYSE, the principal market for the Class Acommon units, under the symbol “EEP.” The quarterly price ranges per Class Acommon unit and cash distributions paid per unit for 2005 and 2004 aresummarized as follows:

| ** **               | ** ** | **First** | ** ** | **Second** | ** ** | **Third** | ** ** | **Fourth** | ** ** |
|--------------------------|------------|-----------|------------|------------|------------|-----------|------------|------------|------------|
| **2005 Quarters**        |       |      |       |       |       |      |       |       |       |
| High                     |       | $         | 55.66      |       | $          | 54.32     |       | $          | 57.08      |   | $ | 55.99 |   |
| Low                      |       | $         | 47.90      |       | $          | 48.75     |       | $          | 50.40      |   | $ | 42.00 |   |
| Cash distributions  paid |       | $         | 0.925      |       | $          | 0.925     |       | $          | 0.925      |   | $ | 0.925 |   |
| **2004  Quarters**       |       |      |       |       |       |      |       |       |       |
| High                     |       | $         | 51.33      |       | $          | 51.95     |       | $          | 49.75      |   | $ | 51.90 |   |
| Low                      |       | $         | 47.71      |       | $          | 41.35     |       | $          | 46.22      |   | $ | 45.60 |   |
| Cash distributions paid  |       | $         | 0.925      |       | $          | 0.925     |       | $          | 0.925      |   | $ | 0.925 |   |

 

On February 17, 2006,the last reported sales price of our Class A common units on the NYSE was$45.55. At February 17, 2006, there were approximately 78,000 Class Acommon unitholders, of which there were approximately 2,000 registered Class Acommon unitholders of record. There is no established public trading market forour Class B common units, all of which are held by the General Partner, orour i-units, all of which are held by Enbridge Management.

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**Item 6. Selected Financial Data**

Thefollowing table sets forth, for the periods and at the dates indicated, oursummary historical financial data. The table is derived, and should be read inconjunction with, our audited consolidated financial statements and notesthereto beginning at page F-1. See also “Item 7. Management’sDiscussion and Analysis of Financial Condition and Results of Operations.”

| ** **                                                                                      | ** ** | **Year ended December 31,**                                       | ** ** |
|-------------------------------------------------------------------------------------------------|------------|----------------------------------------------------------------------------------|------------|
| ** **                                                                                      | ** ** | **2005**                                                                         | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** | **2001** | ** ** |
| ** **                                                                                      | ** ** | **(dollars in millions, except per unit amounts)** | ** ** |
| **Income Statement Data:****(2)**                                                               |       |                                                                             |       |   |   |   |   |   |   |   |   |
| Operating revenue                                                                               |       | $                                                                                | 6,476.9    |   | $ | 4,291.7 |   | $ | 3,172.3 |   | $ | 1,185.5 |   | $ | 342.3 |   |
| Operating expenses                                                                              |       | 6,285.0                                                                          |       | 4,054.5 |   | 2,978.0 |   | 1,047.5 |   | 244.5 |   |
| Operating income                                                                                |       | 191.9                                                                            |       | 237.2 |   | 194.3 |   | 138.0 |   | 97.8 |   |
| Interest expense                                                                                |       | (107.7                                                                           | )          | (88.4 | ) | (85.0 | ) | (59.2 | ) | (59.3 | ) |
| Rate refunds                                                                                    |       | —                                                                           |       | (13.6 | ) | — |   | — |   | — |   |
| Other income (expense)                                                                          |       | 5.0                                                                              |       | 3.0 |   | 2.4 |   | (0.2 | ) | 0.9 |   |
| Minority interest                                                                               |       | —                                                                           |       | — |   | — |   | (0.5 | ) | (0.5 | ) |
| Net income                                                                                      |       | $                                                                                | 89.2       |   | $ | 138.2 |   | $ | 111.7 |   | $ | 78.1 |   | $ | 38.9 |   |
| Net income per common and i-unit(1)                                                             |       | $                                                                                | 1.06       |   | $ | 2.06 |   | $ | 1.93 |   | $ | 1.76 |   | $ | 0.98 |   |
| Cash distributions paid per unit                                                                |       | $                                                                                | 3.70       |   | $ | 3.70 |   | $ | 3.70 |   | $ | 3.60 |   | $ | 3.50 |   |
| **Financial  Position Data (at year end):****(2)**                                              |       |                                                                             |       |   |   |   |   |   |   |   |   |
| Property, plant and equipment, net                                                              |       | $                                                                                | 3,080.0    |   | $ | 2,778.0 |   | $ | 2,465.6 |   | $ | 2,253.3 |   | $ | 1,486.6 |   |
| Total assets                                                                                    |       | 4,428.4                                                                          |       | 3,770.7 |   | 3,231.8 |   | 2,834.9 |   | 1,649.2 |   |
| Long-term debt, excluding current  maturities(3)                                                |       | 1,682.9                                                                          |       | 1,559.4 |   | 1,155.8 |   | 1,011.4 |   | 715.4 |   |
| Loans from General Partner and affiliates                                                       |       | 151.8                                                                            |       | 142.1 |   | 133.1 |   | 444.1 |   | 176.2 |   |
| Partners’  capital:                                                                        |       |                                                                             |       |   |   |   |   |   |   |   |   |
| Class A common units(4)                                                                    |       | 1,142.4                                                                          |       | 1,021.6 |   | 914.9 |   | 604.8 |   | 577.0 |   |
| Class B common units                                                                       |       | 67.2                                                                             |       | 66.7 |   | 64.2 |   | 48.7 |   | 48.8 |   |
| i-units(5)                                                                                      |       | 421.7                                                                            |       | 399.4 |   | 370.7 |   | 335.6 |   | — |   |
| General Partner                                                                                 |       | 34.6                                                                             |       | 31.0 |   | 27.5 |   | 18.8 |   | 6.5 |   |
| Accumulated other comprehensive (loss) income                                                   |       | (302.1                                                                           | )          | (120.8 | ) | (64.0 | ) | (16.3 | ) | 11.9 |   |
| Partners’ capital                                                                          |       | $                                                                                | 1,363.8    |   | $ | 1,397.9 |   | $ | 1,313.3 |   | $ | 991.6 |   | $ | 644.2 |   |
| **Cash  Flow Data:**                                                                            |       |                                                                             |       |   |   |   |   |   |   |   |   |
| Cash flows provided by operating activities                                                     |       | $                                                                                | 267.1      |   | $ | 245.4 |   | $ | 148.2 |   | $ | 200.8 |   | $ | 125.3 |   |
| Cash flows used in investing activities                                                         |       | (437.1                                                                           | )          | (419.1 | ) | (431.0 | ) | (557.2 | ) | (302.1 | ) |
| Cash flows provided by financing activities                                                     |       | 181.5                                                                            |       | 187.6 |   | 286.9 |   | 376.5 |   | 179.8 |   |
| Acquisitions and  capital expenditures included in investing activities, net of cash   acquired |       | (531.2                                                                           | )          | (429.8 | ) | (423.5 | ) | (563.9 | ) | (300.0 | ) |

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Notes to SelectedFinancial Data Table

(1)                The allocation ofnet income to the General Partner in the following amounts has been deductedbefore calculating net income per unit: 2005, $23.5 million; 2004,$22.5 million; 2003, $19.6 million; 2002, $13.1 million; and2001, $9.1 million.

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(2)                Ourincome statement and financial position data reflect the following acquisitionsand dispositions:

·       December 2005,disposition of assets on the East Texas and South Texas systems;

·       January 2005,acquisition of the natural gas gathering and processing asset in north Texas;

·       March 2004acquisition of the Mid-Continent system;

·       December 2003acquisition of the North Texas system;

·       October 2002acquisition of the Midcoast system including natural gas gathering andtransmission pipelines, and natural gas treating and processing assets in theMid-continent and Gulf Coast regions of the United States;

·       November 2001acquisition of the natural gas gathering, transportation, processing andmarketing assets in east Texas; and

·       May 2001 acquisitionof Enbridge Pipelines (North Dakota) L.L.C.

(3)                Ourincome statement, financial position and cash flow data include the effect of:

·       TheSeptember 2005 amendment of our credit facility to extend the letter ofcredit sub limit from $175 million to $300 million and increase the commitmentsavailable from $600 million to $800 million maturing in 2010;

·       TheApril 2005 establishment of a $600 million commercial paper program;

·       TheDecember 2004 issuance of $300 million of senior unsecured notes;

·       TheApril 2004 amendment of our credit facilities to terminate the 364-dayrevolving credit facility and increase the Three-year term credit facility to$600 million maturing in 2007;

·       TheJanuary 2004 issuance of $200 million of senior unsecured notes;

·       TheMay 2003 issuance of $400 million of senior unsecured notes; and

·       January 2002replacement of the $350 million Revolving Credit Facility with a$300 million Three-year term credit facility and a $300 million 364-dayFacility.

(4)                Ourincome statement, financial position and cash flow data include the effect ofthe following common unit issuances:

·       0.13million Class A common units in December 2005;3.0 million Class A common unitsin November 2005; 2.5 millon Class A common units in February 2005;

·       3.68 millionClass A common units in September 2004;0.45 million Class Acommon units in January 2004;

·       5.0 millionClass A common units in December 2003;3.9 million Class Acommon units in May 2003;

·       2.3 millionClass A common units in March 2002;

·       2.3 millionClass A common units in November 2001; and1.8 million Class Acommon units in May 2001.

(5)                Reflectsthe issuance of 9.0 million i-units in October 2002 and subsequentquarterly i-unit distributions of 0.8 million, 0.8 million,0.8 million and 0.2 million during 2005, 2004, 2003 and 2002,respectively, in lieu of cash distributions.

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**Item7. Management’s Discussion and Analysis of Financial Condition and Results ofOperations**

The following discussionand analysis of our financial condition and results of operations is based onand should be read in conjunction with our Consolidated Financial Statementsand the accompanying notes beginning on page F-1 of this AnnualReport on Form 10-K.

**RESULTS OF OPERATIONS—OVERVIEW**

We provide servicesto our customers and returns for our unitholders primarily through thefollowing activities:

·       Interstatepipeline transportation and storage of crude oil and liquid petroleum;

·       Gathering,treating, processing and transportation of natural gas and NGLs throughpipelines and related facilities; and

·       Providingsupply, transportation and sales service, including purchasing and selling ofnatural gas and NGLs.

We conduct our business through three businesssegments: Liquids, Natural Gas and Marketing. These segments are strategicbusiness units established by senior management to facilitate the achievementof our long-term objectives, to aid in resource allocation decisions and toassess operational performance.

Our Liquids segment includes the operations of ourLakehead, North Dakota and Mid-Continent systems. Each of these systems largelyconsist of FERC-regulated interstate crude oil and liquid petroleum pipelines. OurMid-Continent system is also one of the largest above ground crude oil storagefacilities in North America, with the majority of the capacity available formerchant storage not subject to regulation by the FERC. Each of these systemsgenerates most of its revenues by charging shippers a per barrel tariff rate totransport and store crude oil and liquid petroleum.

Our Natural Gas segment consists of natural gasgathering and transmission pipelines, including four FERC-regulated interstatenatural gas transmission pipelines, as well as natural gas treating andprocessing plants and related facilities. The revenues of our Natural Gassegment are derived from the fees we charge to gather and process natural gasand the rates we charge to transport natural gas on our pipelines.

Our Marketing segment provides supply, transmission,storage and sales services to producers and wholesale customers on ourgathering, transmission and customer pipelines, as well as other interconnectedpipeline systems. Our Marketing activities are primarily undertaken to realizeincremental revenue on gas purchased at the wellhead, increase pipelineutilization and provide other services that are valued by our customers.

Several types of arrangements in our Natural Gas andMarketing segments expose us to market risk associated with changes incommodity prices where we receive natural gas or NGLs in return for theservices we provide, or where we purchase natural gas or NGLs. We employderivative financial instruments to reduce our exposure to natural gas and NGLprices. Some of these derivative financial instruments do not qualify for hedgeaccounting under the provisions of SFAS No. 133, which can createvolatility in our earnings that can be significant. However, these fluctuationsin earnings do not affect our cash flow. Cash flow is only affected when wesettle the derivative financial instrument and the associated physicaltransaction.

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Thefollowing table reflects our operating income by business segment and corporatecharges for each of the years ended December 31:

| ** **                               | ** ** | **2005**               | ** ** | **2004** | ** ** | **2003** | ** ** |
|------------------------------------------|------------|------------------------|------------|----------|------------|----------|------------|
| ** **                               | ** ** | **(in millions)** | ** ** |
| **Operating Income**                     |       |                   |       |     |       |     |       |
| Liquids                                  |       | $                      | 127.3      |     | $          | 139.1    |       | $ | 124.5 |   |
| Natural Gas                              |       | 110.5                  |       | 98.1     |       | 63.6     |       |
| Marketing                                |       | (42.4                  | )          | 3.6      |       | 9.4      |       |
| Corporate, operating and  administrative |       | (3.5                   | )          | (3.6     | )          | (3.2     | )          |
| **Total Operating Income**               |       | 191.9                  |       | 237.2    |       | 194.3    |       |
| Interest expense                         |       | (107.7                 | )          | (88.4    | )          | (85.0    | )          |
| Rate refunds                             |       | —                 |       | (13.6    | )          | —   |       |
| Other income                             |       | 5.0                    |       | 3.0      |       | 2.4      |       |
| **Net Income (Loss)**                    |       | $                      | 89.2       |     | $          | 138.2    |       | $ | 111.7 |   |

 

***Summary Analysis of Operating Results***

*Liquids*

Our Liquids segmentcontributed operating income of $127.3 million in 2005, or $11.8 million lessthan the $139.1 million contributed in 2004. The operating income of ourLiquids segment in 2005 was affected by the following factors:

·       Deliverieson our Lakehead system declined by approximately 83,000 Bpd primarily due to afire in January 2005 at an upgrader site owned by Suncor, an oil sandsproducer in Alberta, Canada. A heavier crude oil mix and the annual indexadjustment to our tariff rates generated additional revenue as did the fullyear contribution from our Mid-Continent assets, more than offsetting the lossof revenue resulting from the lower transportation volumes on our Lakeheadsystem.

·       Higherworkforce-related costs resulting from increases in pension and healthcarecosts passed through to us and other general and administrative cost increases.

·       Increased costs for the additionaltwo months of ownership of our Mid-Continent system assets in 2005 comparedwith 2004.

*Natural Gas*

Operating incomefrom our Natural Gas segment grew to $110.5 million in 2005 representing anincrease of $12.4 million over the $98.1 million generated in 2004. Theincreased contribution of our Natural Gas segment is attributable to thefollowing:

·       Averagedaily volume on our major natural gas systems was 17 percent greater in 2005than in 2004, partially due to historically high natural gas prices, whichencourage producers to generate and ship greater volumes of natural gas andNGL. Also contributing to the volume growth were the gathering and processingassets in north Texas we acquired in January 2005, and the addition of 500MMcf/d of natural gas transportation capacity on our East Texas system from ourlate-June 2005 completion of the 107-mile natural gas pipeline tothe Carthage, Texas market hub.

·       Operatingincome of our natural gas segment was also positively affected by a gain of$18.1 million we realized on the sale of gathering and processing assetslocated in our East and South Texas systems. These gains were mostly offset by$16.3 million of losses we realized from the settlement of natural gasderivatives in connection with the sale. We had previously recorded unrealizedlosses associated with this natural gas derivative that were realized uponsettlement.

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·       Keep-wholeprocessing arrangements contributed to improved results. Two factorscontributed to this increase, first NGL prices increased in relation to thecost of our natural gas feedstocks. Second, additional processing capacity wascommissioned in 2005. In combination, these factors resulted in an increase of$11.8 million in revenue less cost of natural gas.

·       Theoperating results of our Natural gas segment were negatively affected byunrealized non-cash mark-to-market losses of $8.1 million associated withderivative financial instruments that do not qualify for hedge accounting underSFAS No. 133 and ineffectiveness charges associated with hedges thatqualify for cash flow hedge accounting under SFAS No. 133.

·       Operatingincome of our Natural gas segment in 2005 included an increase of $36.7 millionin operating and administrative costs from 2004. The increase is attributableto increases in workforce-related costs, costs that are variable with theincremental volumes gathered, processed and transported on our systems, theacquisition of gathering and processing assets in north Texas and repair andmaintenance and related costs resulting from maintenance and downtime at threeof our processing facilities.

*Marketing*

Our Marketingsegment incurred losses of $42.4 million in 2005, which include unrealized,non-cash mark-to-market losses of $50.3 million, compared with$3.6 million of operating income for the corresponding period in 2004. Theoperating income of our Marketing segment in 2005 was affected by the followingfactors:

·       Strong growth in natural gas production in the Texas markets we serve hascreated constraints in the available pipeline capacity used by our Marketingbusiness to transport and deliver natural gas into premium-priced downstreammarkets. These pipeline constraints have limited the ability of our Marketingbusiness to sell natural gas into these more attractive markets untiladditional pipeline capacity can be acquired and other alternatives becomeavailable.

·       During thelast four months of 2005, supply disruptions in the Gulf of Mexico regioncaused by hurricanes Katrina and Rita created greater demand for natural gasfrom the onshore production areas that our Marketing business serves,increasing our ability to optimize revenue from the sale of unhedged naturalgas volumes to areas of greater demand.

·       We were adversely affected by significantnon-cash volatility associated with our portfolio of derivative financialinstruments that do not qualify for hedge accounting treatment under SFASNo. 133. 

***DerivativeTransactions and Hedging Activities***

We record all financialinstruments in the consolidated financial statements at fair market valuepursuant to the requirements of SFAS No. 133. For those derivativefinancial instruments that do not qualify for hedge accounting, all changes infair market value are recorded through our Consolidated Statements of Incomeeach period. The fair market value of these derivative financial instrumentsreflects the estimated amounts that we would pay or receive to terminate or closethe contracts at the reporting date, although that is not our intent.

A volatile natural gas andNGL pricing environment during our fiscal year ended December 31, 2005,produced non-cash mark-to-market losses of $58.4 million and negatively affectedour operating results. While these mark-to-market losses create volatility inour results, the derivative financial instruments do not affect our cash flowuntil they are settled. We expect these non-cash losses to reverse in futureperiods as we settle the derivative financial instruments against theunderlying physical transactions. Because of the economic benefit we receive byminimizing the volatility in our cash flows by using derivative financialinstruments to hedge our portfolio of natural gas and NGL, we intend tocontinue using them. Our 

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continueduse of derivative financial instruments may result in additional unrealized,non-cash losses or gains in the future.

Thefollowing table presents the unrealized losses associated with changes in thefair value of our derivatives, which are recorded as an element of Cost ofnatural gas in our Consolidated Statements of Income and disclosed as areconciling item on our Statements of Cash Flows:

| **Derivative fair value losses** | ** ** | ** **             | ** ** | **December 31,  2005** | ** ** | **December 31,  2004** | ** ** | **December 31,  2003** | ** ** |
|-------------------------------------------------|------------|------------------------|------------|-----------------------------|------------|-----------------------------|------------|-----------------------------|------------|
| ** **                                      | ** ** | **(in millions)** | ** ** |
| Natural Gas segment                             |       |                   |       |                        |       |                        |       |                        |       |   |   |   |   |
| Ineffectiveness                                 |       |                   | $          | 2.5                         |       |                        |       | $                           | 1.1        |   |   |   | $ | — |   |   |
| Non-qualified hedges                            |       |                   | 5.6        |                        |       |                        | —     |                        |       |   | — |   |   |
| Marketing                                       |       |                   |       |                        |       |                        |       |                        |       |   |   |   |   |
| Non-qualified hedges                            |       |                   | 41.3       |                        |       |                        | 2.1        |                        |       |   | 0.3 |   |   |
| Discontinuance                                  |       |                   | 9.0        |                        |       |                        | —     |                        |       |   | — |   |   |
| Derivative fair value losses                    |       |                   | $          | 58.4                        |       |                        |       | $                           | 3.2        |   |   |   | $ | 0.3 |   |   |

 

In connection with thesale of a processing plant and related facilities and other gathering andprocessing assets located in our East and South Texas systems, we settled forcash of approximately $16.3 million, natural gas collars representingderivative financial instruments on forecasted sales of 2,000 MMBtu/d ofnatural gas through 2011. We had previously recorded unrealized lossesassociated with the natural gas collars that were realized upon settlement. Additionally,we de-designated derivative financial instruments that were qualified for anddesignated as cash flow hedges of forecasted sales of 273 Bpd of NGLs through2007 and contemporaneously closed out the position by entering into anoffsetting derivative financial instrument, at market, on forecasted purchasesof 273 Bpd of NGLs for the same term.

**RESULTSOF OPERATIONS—BY SEGMENT**

***Liquids***

OurLiquids segment includes the operations of our Lakehead, North Dakota, andMid-Continent systems. We provide a detailed description of each of thesesystems in Item 1.—Business. The following tables set forth the operatingresults and statistics of our Liquids segment for the periods presented:

| ** **                                 | ** ** | **Year Ended December 31,** | ** ** |
|--------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                 | ** ** | **2005**                                   | ** ** | **2004** | ** ** | **2003** | ** ** |
| ** **                                 | ** ** | **(dollars in millions)**        | ** ** |
| **Operating Results**                      |       |                                       |       |   |   |   |   |
| Operating revenues                         |       | $                                          | 418.0      |   | $ | 409.3 |   | $ | 344.2 |   |
| Operating and  administrative              |       | (144.2                                     | )          | (128.9 | ) | (104.1 | ) |
| Power                                      |       | (74.8                                      | )          | (72.8 | ) | (56.1 | ) |
| Depreciation and  amortization             |       | (71.7                                      | )          | (68.5 | ) | (59.5 | ) |
| Operating expenses                         |       | (290.7                                     | )          | (270.2 | ) | (219.7 | ) |
| **Operating Income**                       |       | $                                          | 127.3      |   | $ | 139.1 |   | $ | 124.5 |   |
| **Operating  Statistics**                  |       |                                       |       |   |   |   |   |
| **Lakehead system:**                       |       |                                       |       |   |   |   |   |
| United States(1)                           |       | 1,036                                      |       | 1,064 |   | 1,003 |   |
| Province of Ontario(1)                     |       | 303                                        |       | 358 |   | 351 |   |
| **Total  deliveries**(1)                   |       | 1,339                                      |       | 1,422 |   | 1,354 |   |
| **Barrel  miles (billions)**               |       | 363                                        |       | 367 |   | 345 |   |
| **Average  haul (miles)**                  |       | 692                                        |       | 706 |   | 698 |   |
| **Mid-Continent system  deliveries**(1)(2) |       | 236                                        |       | 237 |   | — |   |
| **North Dakota system deliveries**(1)      |       | 87                                         |       | 85 |   | 77 |   |

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(1)        Average barrels per day in thousands.

(2)        Ten months of deliveries in 2004.

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*Year ended December 31,2005 compared with year ended December 31, 2004*

Our Liquids segment accounted for $127.3 million ofoperating income in 2005, representing a decrease of $11.8 million or 8% overthe same period in 2004. Lower results on the Lakehead system were modestlyoffset by stronger results on our North Dakota system and a full twelve-monthcontribution from our Mid-Continent system compared with a ten-monthcontribution for the same period in 2004.

Operating revenue in 2005 increased by $8.7 million or2% to $418.0 million, compared with $409.3 million for the same period in 2004.Our Mid-Continent assets contributed higher operating revenue of approximately$6.6 million for the additional two months of ownership in 2005 compared to2004. Overall tariff increases and longer hauls on our North Dakota system weremostly offset by lower deliveries on the Lakehead system during 2005.

Average daily crude oil deliveries on the Lakeheadsystem decreased approximately 6%, from 1.422 million Bpd during 2004 to 1.339million Bpd during 2005. This resulted in lower operating revenue for 2005 ofapproximately $20.0 million. The decrease is the result of lower than expectedcrude oil supply in western Canada from three factors. First, Suncor, an oilsands producer in Alberta, Canada, had a fire at their upgrader site on January 4,2005. As a result of the incident, Suncor’s production was reduced by anaverage of 89,000 Bpd during the first nine months of 2005. In late September,Suncor announced that repairs to the upgrader site and an expansion werecompleted and production capacity has increased as a result. Second, westernCanadian crude oil supply available for delivery on our Lakehead system wasalso reduced during 2005 due to lower bitumen supplies. The nature of thecyclic steaming process used to extract bitumen from the ground can causeproduction timing differences during the year. Finally, during the secondquarter of 2005, Kinder Morgan, Inc., an unrelated company, completed anexpansion on its Express Pipeline system. The expansion increased capacity onthis pipeline by approximately 108,000 Bpd. Given the volume commitments on theExpress Pipeline expansion, coupled with the lower western Canadian crude oilsupply as noted above, deliveries on our Lakehead system were negativelyimpacted for 2005. Management believes that holders of firm capacity on theExpress Pipeline will first satisfy their commitments to that pipeline beforemoving incremental barrels on the Lakehead system.

Increases in average tariffs on all three Liquidssystems resulted in higher operating revenue by approximately $17.6 million. Thesetariff increases were mostly the result of the annual index rate increase ofapproximately 3.63% allowed by the FERC that became effective July 1,2005, on our base system tariffs. On the Lakehead system, new tariffs also wentinto effect on April 1, 2005 for an adjustment on the Terrace expansionprogram surcharge due to lower than expected volumes moving on the Lakeheadsystem. Longer hauls on our North Dakota system also contributed to higheraverage tariffs, as production in Montana continued to be strong during 2005.

Operating and administrative expenses for 2005increased by $15.3 million to $144.2 million, compared with $128.9 million in2004. The increase was attributable to the following factors:

(1)         workforce related costsincreased by approximately $6.9 million due to higher pension, medical andother benefits costs, along with increased administrative, regulatory andcompliance support;

(2)         operating andadministrative expenses on our Mid-Continent system increased approximately$2.9 million due to a full year’s ownership in 2005, compared with ten monthsin 2004;

(3)         capital project recoverieswere lower by approximately $2.8 million due to a decrease in utilization ofour workforce on capital projects and a reduction in construction activity onour Liquids systems;

(4)         oil measurement lossesincreased approximately $2.4 million. 

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Oil measurement losses occur as part of the normaloperating conditions associated with our Liquids pipelines. The three types ofoil measurement losses include:

·       physicallosses, which occur through evaporation, shrinkage, differences in measurementbetween receipt and delivery locations and other operational incidents;

·       degradationlosses, which result from mixing at the interface between higher quality lightcrude oil and lower quality heavy crude oil in pipelines; and

·       revaluationlosses, which are a function of crude oil prices, the level of the carrier’sinventory and the inventory positions of customers.

During2005, the increase in oil measurement losses was a function of two factors:

1.                Highervolumetric physical losses associated with changes in commodity properties andmeasurement, coupled with higher oil prices that made the monetary value ofnormal physical losses more expensive. During 2005, the average West TexasIntermediate crude oil price was approximately $56 per barrel compared withapproximately $41 per barrel during 2004;

2.                Widerlight/heavy crude price differentials made degradation losses more expensive.During 2005, light/heavy differentials were approximately $21 per barrelcompared with approximately $14 per barrel in 2004.

Power costs increased $2.0 million, or 3%, in2005 compared with 2004, mostly due to higher electricity rates and a fulltwelve-month contribution from our Mid-Continent system compared to ten-months in2004, partially offset by lower energy consumption related to lower Lakeheadvolumes. Power costs associated with the Mid-Continent system increasedapproximately $1.5 million in 2005.

Depreciation andamortization increased $3.2 million, or 5%, in 2005 compared to 2004. Theincrease is driven primarily by a full twelve-month contribution from ourMid-Continent system and an increase in the depreciable asset base on ourLakehead system in 2005.

*Year ended December 31,2004 compared with year ended December 31, 2003*

Our Liquids segment accounted for $139.1 millionof operating income, an increase of $14.6 million or 12% over 2003 Liquidsoperating income. The primary driver of the increase in 2004 was our newlyacquired Mid-Continent system, which contributed $13.7 million ofoperating income to the Liquids segment.

Segment operating revenues increased by$65.1 million or 19% in 2004 compared with 2003, largely due to a$36.7 million contribution from our Mid-Continent system. Operatingrevenues from our Lakehead system increased $22.9 or 7%, mostly due toincreased deliveries. Deliveries on our Lakehead system increased 5% during2004, primarily from increased production of western Canadian crude oiltransported on that system. Overall, production of western Canadian crude oilincreased in the last two years mainly due to the start up of new oil sandsprojects in the province of Alberta. These latest oil sands projects differfrom conventional oil production in two ways. First, oil sands deposits are amixture of bitumen, water, sand and clay. As a result, oil production takes theform of either mining the oil sands from subsurface deposits and separating outthe water, sand and clay components, or, if the deposits are deeper, heatingthe reservoir sufficiently to flow the pure bitumen to the well base and thento the surface. Second, the bitumen requires either upgrading or blending priorto being sent to market. The upgrading process partially refines the bitumeninto a crude stream, which can be readily refined by most conventionalrefineries. This product is known as synthetic crude oil. During 2004, crudeoil production increased in western Canada, primarily due to the start up ofthe Athabasca Oil Sands Project in June 2003. The AOSP is owned by ShellCanada Limited, Chevron Canada Limited and Western Oil Sands L.P., and consistsof oil sands mining and bitumen extraction operations with a current capacityof 

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155,000 Bpd. 2004deliveries on our Lakehead system reflect a full year’s impact from this newsource of supply. Operating revenues on our North Dakota system also increasedin 2004 by $5.5 million or 37%, primarily due to an increase intransportation of longer-haul, higher margin barrels resulting from improvedproduction in Montana.

Operating andadministrative expenses of our Liquids segment increased by $24.8 million,or 24%, in 2004 compared with 2003, mostly due to our new Mid-Continent system,which had operating and administrative expenses of $13.4 million.Operating and administrative expenses on our Lakehead system increased by$10.7 million, or 11%. This increase was attributable primarily to threefactors:

(1)         Workforce related costsincreased by $7.6 million due to higher pension and medical costs andother related general and administrative expenses.

(2)         Oil measurement lossesincreased by $7.6 million due to the impact of higher crude oil prices andincreased volumes on the system, which contributed to the physical losses. Wemade refinements in the oil measurement loss estimation process in valuingdifferent types of crude oil on station lines resulting in an increase ofapproximately $3.4 million to our oil measurement loss. The refinements werethe result of engineering studies completed in the fourth quarter of 2004.

(3)         Property taxes increased$2.6 million, or 15%. We have experienced a trend of increasing propertytaxes partially due to new facilities placed into service, and also due toincreases from the taxing authorities in counties and states where our pipelineassets are located.

These increases in operating and administrative expenseson our Lakehead system were partially offset by lower leak remediation andrepair costs of approximately $6.1 million, or 90%.

Power costs increased $16.7 million, or 30%, in2004 compared with 2003, mostly due to the growth in volumes on the Lakeheadsystem and higher generating rates attributable to higher demand and fuelcosts. Power costs associated with the Mid-Continent system were$5.2 million in 2004.

Depreciation andamortization increased $9.0 million, or 15%, over 2003. Depreciation onthe Mid-Continent system accounted for $4.4 million and the balancerelates to new facilities placed into service within our Liquids segment during2003 and 2004.

*Future Prospectsfor Liquids*

Historically, Western Canada has been a key source ofoil supply serving U.S. energy needs. Canada’s oil sands, one of the largestoil reserves in the world, are becoming an increasingly prominent source ofsupply. New production from the oil sands is expected to grow progressivelyduring the next five years, with an additional 890,000 to 930,000 Bpd availableby 2010. Conventional oil production is expected to decline by about 130,000Bpd during the same period. The net increased production will result from anestimated $55 billion of active or planned projects that are beingdeveloped in the oil sands.

Enbridge and the Partnership are actively working withour customers to develop transportation options that will allow Canadian crude oilaccess to new markets. After receiving strong shipper support during an Open Season,the Partnership and Enbridge announced approval of the 400,000 Bpd SouthernAccess expansion project, which has received endorsement from CAPP. A decisionfrom the FERC on tariff principles negotiated with shippers is expected beforemid-year 2006. Fieldwork has commenced to ensure completion in early 2009, withcapacity increases to start in 2007.

The U.S. portion of the expansion will be undertakenon our Lakehead System with the first stage to add approximately 44,000 Bpd ofcapacity in 2007 and up to an additional 146,000 Bpd by early 2008. The firststage includes a new pipeline between Superior and Delavan, Wisconsin, alongwith pump station enhancements upstream and downstream of this segment. Thesecond stage of the expansion project will provide additional upstream pumpingcapacity and a new pipeline from Delavan to Flanagan, Illinois, with 

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completion expected inearly 2009. Completion of the total Southern Access expansion project willcreate a 454-mile pipeline with approximately 400,000 Bpd of incrementalcapacity on our Lakehead system. The design will also permit a further 400,000Bpd increase in capacity for minimal additional cost, in conjunction with acorresponding expansion upstream of Superior, when required by shippers.

In another effort to provide shippers access to newmarkets, Enbridge acquired a pipeline that runs from Cushing, Oklahoma toChicago, and has reversed its flow. The pipeline has been renamed the SpearheadPipeline and will provide capacity to deliver 125,000 Bpd into the major oilhub at Cushing in early 2006. We expect to benefit following the reversal, aswestern Canadian crude oil will be carried on the Lakehead system as far asChicago, and then transferred to the Spearhead pipeline.

The Partnership and Enbridge believe that the SouthernAccess Program, the Spearhead pipeline reversal, and other initiatives toprovide access to new markets in the Midwest, Mid-continent and Gulf Coast,offer flexible solutions to future transportation requirements of westernCanadian crude oil producers, and the in-service timing of these solutions isin line with prospective shipper needs.

Average daily crude oil deliveries on the Lakeheadsystem are expected to increase by approximately 240,000 Bpd during 2006, from1.34 million Bpd in 2005 to approximately 1.58 million Bpd in 2006. Theincrease is mainly attributable to the re-start of Suncor’s upgrader in late September 2005after the January 2005 fire, along with commissioning of Suncor’s expansionin the last quarter of 2005. In addition to these volumes, we expect thecommissioning of Syncrude’s UE-1 expansion in mid-2006, resulting inultimate incremental production of 100,000 Bpd.

Our North Dakota system has benefitted over the pasttwo years from the six and 28 percent average annual production growth in NorthDakota and Montana, respectively. We expect deliveries on our North Dakotasystem to be approximately 92,000 Bpd in 2006.

Our Mid-Continent systemconsists of the Ozark and the West Tulsa pipelines. The West Tulsa pipelinemoves crude oil from Cushing to Tulsa. Throughput deliveries on this system areexpected to continue to remain stable, given the recent strength in refinerymargins experienced by the industry. The Ozark pipeline system transports crudeoil from Cushing to Wood River and provides access to the Wood River, east ofPatoka, and Minnesota refining areas through its connection to other systems. TheOzark system depends upon the demand of the Wood River and east of Patokarefineries for crude oil from west Texas, and imports from the Gulf Coast. Weexpect steady to declining throughputs as more growth in Canadian crude oildisplaces imports from the Gulf Coast and demand for domestic west Texas crudeoil. We expect deliveries on our two Mid-Continent pipelines to be approximately210,000 Bpd in 2006.

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***Natural Gas***

Our Natural Gassegment consists of natural gas gathering and transmission pipelines, as wellas treating and processing plants and related facilities. Collectively, thesesystems include:

·       approximately11,000 miles of natural gas gathering and transmission pipelines including fourFERC-regulated transmission pipeline systems;

·       eightnatural gas treating plants;

·       fifteennatural gas processing plants; and

·       trucks,trailers and railcars used for transporting NGLs, crude oil and carbon dioxide.

Thefollowing tables set forth the operating results of our Natural Gas segmentassets and average daily volumes of our major systems in MMBtu/d for theperiods presented:

| ** **                     | ** ** | **Year Ended December 31,** | ** ** |
|--------------------------------|------------|--------------------------------------------|------------|
| ** **                     | ** ** | **2005**                                   | ** ** | **2004** | ** ** | **2003** | ** ** |
| ** **                     | ** ** | **(dollars in millions)**        | ** ** |
| Operating  revenues            |       | $                                          | 2,352.1    |   | $ | 1,319.9 |   | $ | 958.5 |   |
| Cost of natural gas            |       | (2,018.7                                   | )          | (1,031.8 | ) | (754.9 | ) |
| Operating and  administrative  |       | (175.0                                     | )          | (138.3 | ) | (102.3 | ) |
| Depreciation and  amortization |       | (66.0                                      | )          | (51.7 | ) | (37.7 | ) |
| Gain on sale of  assets        |       | 18.1                                       |       | — |   | — |   |
| Expenses                       |       | (2,241.6                                   | )          | (1,221.8 | ) | $ | (894.9 | ) |
| **Operating  income**          |       | $                                          | 110.5      |   | $ | 98.1 |   | $ | 63.6 |   |

 

| ** **                                        | ** ** | **Year Ended December 31,** | ** ** |
|---------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                        | ** ** | **2005**                                   | ** ** | **2004** | ** ** | **2003** | ** ** |
| **Average Daily Volume (MMBtu/d)** | ** ** | ** **                                 | ** ** | ** ** | ** ** |
| East Texas                                        |       | 860,000                                    |       | 676,000 |   | 579,000 |   |
| Anadarko(1)                                       |       | 488,000                                    |       | 357,000 |   | 256,000 |   |
| North Texas                                       |       | 265,000                                    |       | 192,000 |   | — |   |
| South Texas(2)                                    |       | 33,000                                     |       | 40,000 |   | 38,000 |   |
| UTOS                                              |       | 158,000                                    |       | 219,000 |   | 213,000 |   |
| Midla                                             |       | 106,000                                    |       | 103,000 |   | 108,000 |   |
| AlaTenn                                           |       | 59,000                                     |       | 62,000 |   | 61,000 |   |
| KPC                                               |       | 31,000                                     |       | 48,000 |   | 53,000 |   |
| Bamagas                                           |       | 29,000                                     |       | 25,000 |   | 14,000 |   |
| Other Major  Intrastates(1)                       |       | 186,000                                    |       | 176,000 |   | 182,000 |   |
| **Total**                                         |       | 2,215,000                                  |       | 1,898,000 |   | 1,504,000 |   |
|                                                   |            |                                            |            |  |  |  |  |  |  |

 

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(1)        Anadarko includes the combined systemspreviously referred to separately as Anadarko and Palo Duro. The Palo Durovolumes were formerly included with Other major intrastates.

(2)                We sold the SouthTexas assets in December 2005.

We recognize revenue upon delivery of natural gas andNGLs to customers, and/or when services are rendered, pricing is determinableand collectibility is reasonably assured. We derive revenue in our Natural Gassegment from the following types of arrangements:

*Fee-BasedArrangements:*   Under a fee-based contract, wereceive a set fee for gathering, treating, processing and transporting rawnatural gas and providing other similar services. These revenues correspondwith the volumes and types of services provided and do not depend directly oncommodity 

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prices. Revenues of theNatural Gas segment that are derived from transmission services consist ofreservation fees charged for transmission of natural gas on the FERC-regulatedinterstate natural gas transmission pipeline systems, while revenues fromintrastate pipelines are generally derived from the bundled sales of naturalgas and transmission services. Customers of our FERC-regulated natural gaspipeline systems typically pay a reservation fee each month to reserve capacityplus a nominal commodity charge based on actual transmission volumes.

*OtherArrangements:*   We also use other types ofarrangements to derive revenues for our Natural Gas segment. These arrangementsexpose us to commodity price risk, which we substantially mitigate withoffsetting physical purchases and sales and by the use of derivative financialinstruments to hedge open positions. We will continue to hedge a significantamount of our commodity price risk to support the stability of our cash flows.Please refer to Item 7A. Quantitative and Qualitative Disclosures aboutMarket Risk—Commodity Price Risk and Note 15 of our Consolidated FinancialStatements beginning on page F-1 of this report for more informationabout our derivative activities.

These other typesof arrangements are categorized as follows:

·       Percentage-of-Index-Contracts—Underthese contracts, we purchase raw natural gas at a negotiated discount to anagreed upon index price. We then resell the natural gas, generally for theindex price, keeping the difference as our fee.

·       Percentage-of-ProceedsContracts—Under the terms of these contracts, we receive a negotiatedpercentage of the natural gas and NGLs we process in the form of residuenatural gas, NGLs, condensate and sulfur, which we then sell at market pricesand retain as our fee.

·       Percentage-of-LiquidsContracts—Under these contracts, we receive a negotiated percentage of NGLs andcondensate from natural gas that requires processing. This contract structureis similar to percentage-of-proceeds arrangements except that we only receive apercentage of the NGLs and condensate.

·       Keep-WholeContracts—Under these contracts, we gather or purchase raw natural gas from theproducer for processing. A portion of the gathered or purchased natural gas isconsumed during processing. We extract and retain the NGLs produced duringprocessing for our own account, which we sell at market prices. In instanceswhere we purchase raw gas at the wellhead, we also sell for our own account theresidue gas resulting from processing at market prices. In those instances whenwe gather and process raw natural gas for the account of the producer, we mustreturn to the producer residue gas with a British thermal unit contentequivalent to the original raw gas we received.

Under the terms of each of these contract structures,we retain a portion of the natural gas and NGLs as our fee in exchange forproviding these producers with our services. In order to protect ourunitholders from volatility in our cash flows that can result from fluctuationsin commodity prices, we enter into derivative financial instruments toeffectively fix the sales price of the natural gas and NGLs we anticipatereceiving under the terms of these contracts. As a result of entering intothese derivative financial instruments, we have largely fixed the amount ofcash that we will receive in the future when we sell the processed natural gasand NGLs, although the market price of these commodities will continue tofluctuate during that time.

*Year endedDecember 31, 2005 compared with year ended December 31, 2004*

Our Natural Gas segment contributed $110.5 million ofoperating income in 2005, representing an increase of $12.4 million, from the$98.1 million earned in 2004. Continuing favorable natural gas and NGL pricescontributed to average daily volume increases of 17 percent in 2005 on ourmajor natural gas systems compared with 2004. The increase in volumes isprimarily the result of additional wellhead supply contracts on our East Texasand Anadarko systems, as well as the additional volumes on the North Texas 

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system associated with thegathering and processing assets we acquired in January 2005. Drillingactivity continues to increase in the Anadarko Basin, Bossier Trend and BarnettShale areas as evidenced by increasing rig counts and production volumes overthe past several years. Additionally, completion of the East Texas expansionproject in late June 2005 contributed modestly to the growth in volumesfor the year 2005. With continued investment in our systems to expand capacity,we expect our major natural gas systems to benefit from the increase in productionvolumes expected to result from the continuing increase in drilling activitiesin the basins we serve.

Partially offsetting the positive operating resultsderived from the increases in gathering, processing and transportation volumeson our natural gas systems were non-cash, mark-to-market net losses of $8.1million associated with our derivative transactions and hedging activities.Included in Cost of natural gas are non-cash losses of $2.5 million resultingfrom ineffectiveness associated with our qualified cash flow hedges and $5.6million of non-cash mark-to-market losses from derivative financial instrumentsthat do not qualify for hedge accounting treatment under SFAS No. 133. Thenon-cash losses primarily result from the significant increases in forwardnatural gas and NGL prices during the year. The increase in prices reduces thefair market value of these derivative financial instruments because the fixedprice component of these derivatives is significantly less than the marketprice of natural gas at each of the forward settlement points.

Also included in our operating results for the yearended December 31, 2005 is a gain of $18.1 million we realized inDecember 2005, when we divested non-strategic assets located within ourEast and South Texas systems. We sold for $105.4 million in cash, a processingplant and related facilities, and other gathering and processing assets with acarrying value of approximately $86.9 million. We incurred selling costs ofapproximately $0.4 million. In connection with this sale, we paid approximately$16.3 million to settle natural gas hedges associated with the natural gas producedby these assets. We had previously recorded unrealized losses associated withthe natural gas hedges that were realized upon settlement. The reported amountsare subject to change pending the final settlement of the sale.

A variable element of the Natural Gas segment’soperating income is derived from keep-whole processing of natural gas primarilyon our Anadarko and East Texas systems. This contract structure requires us toprocess natural gas at times when it may not be economical to do so. This canhappen when natural gas prices are unusually high or NGL prices are unusuallylow. During 2005, although natural gas prices were unusually high, they weremore than offset by favorable NGL prices. Operating revenue less cost ofnatural gas derived from keep-whole processing for the year 2005 wasapproximately $29.0 million compared with $17.2 million in 2004.

Operating and administrative costs of our Natural Gassegment were $175.0 million, or 27% greater for 2005 than 2004, primarily as aresult of increased workforce related costs and costs that are variable withvolumes. Workforce related costs increased $11.8 million due to higherpension, medical and other benefits, as well as additional administrative,regulatory and compliance support. Costs that are incremental with volumes, suchas chemicals, materials and supplies and direct workforce expenses increased by$10.5 million. Additionally, the natural gas gathering and processingassets we acquired in January 2005 contributed to the cost increases ofapproximately $7.2 million. As well, our maintenance costs increased byapproximately $4.9 million in 2005 due to several processing plants thatunderwent major repairs, one of which was included with the recently divestedassets.

Our depreciation andamortization expense for the year 2005 exceeded the amount reported for 2004 byapproximately $14.3 million, primarily as a result of acquisitions andsignificant capital projects completed and placed in-service during 2005. Theincrease in depreciation expense was partially offset by modest extensions ofthe depreciable lives of our major pipeline systems as a result of adepreciation study completed during the third quarter of 2005. Based on a third-party studycommissioned by management, revised depreciation rates for the Anadarko, NorthTexas and East Texas systems were implemented 

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effective August 1, 2005. Theannual composite rate, which represents the expected remaining service life ofthese natural gas systems, was reduced from 4.0% to 3.4%. Depreciation expensefor the year ended December 31, 2005 was approximately $2.5 million loweras a result of the new depreciation rates.

*Year ended December 31,2004 compared with year ended December 31, 2003*

Our Natural Gas segment accounted for$98.1 million of operating income, an increase of $34.5 million, or54%, over 2003 Natural Gas operating income.

Compared with 2003, average daily volumes on our majorNatural Gas systems increased 26% in 2004, mostly due to the contribution ofour North Texas system from the acquisition date of December 31, 2003. OurNorth Texas system contributed $22.9 million to operating income in 2004,which was consistent with our expectations for the first year of ownership. Volumeson our East Texas system increased by 17% in 2004, compared with the sameperiod in 2003, as a result of increased drilling by producers of gas wells inthe areas served by the system. These volume increases resulted in higheroperating revenue less cost of natural gas of $7.9 million compared with2003. Volumes on our Anadarko system increased by approximately 32% in 2004,compared with the same period in 2003. The growth is a result of increaseddrilling activity in the Texas panhandle and western Oklahoma regions. Thehigher volumes contributed to an increase of $11.0 million in operatingrevenue less cost of natural gas.

High natural gas prices positively impacted volumes onour gathering and processing systems. This positive impact was compounded byfavorable processing economics in 2004. As described in our 2005 comparison,keep-whole processing is a variable element of the Natural Gas segment’soperating income. During 2004, operating income associated with keep-wholeprocessing was approximately $17.2 million compared with $1.9 millionin 2003. During 2004, natural gas prices were high but were more than offset byfavorable NGL prices.

On our East Texas system, we processed 191,420 MMtbu/dof natural gas in 2004, which was an increase of 28% compared with volumesprocessed in 2003. Due to more favorable NGL pricing conditions in 2004,processing activities contributed $10.0 million of operating income. Thiscompares with $1.7 million of operating income for processing activities in2003. The increase in business activity on our East Texas system has resultedin higher operating revenue and administrative expenses of $7.8 million, or17%, in 2004 compared with 2003. These costs are mostly variable in nature andrelate to higher workforce related costs associated with an increase in ouroperations staff, as well as higher overall benefit costs and an increase inrepairs and maintenance expenses. As a result, operating income on our EastTexas system increased $2.9 million, or 10%, in 2004 compared with 2003.

Similar to our East Texas system, processing resultsimproved on our Anadarko system during 2004 due to a more favorable natural gasand NGL pricing environment. On our Anadarko system, we processed 111,007MMBtu/d of natural gas in 2004, which was an increase of 35% compared withvolumes processed in 2003. Processing activities contributed to $7.2 million ofoperating income in 2004. This compares with $0.2 million of operating incomefor processing activities in 2003. These improvements to operating income werepartially offset by higher operating and administrative expenses mostly relatedto variable costs associated with the increased volumes on the system. As aresult, operating income on the Anadarko system increased by $16.0 million, or175%, in 2004 compared with 2003.

The increase in business activity on our Natural Gassystems has resulted in higher operating and administrative expenses of$36.0 million in 2004 compared with 2003. These costs are mostly variablein nature and relate to higher workforce related costs associated with anincrease in our operations staff, as well as higher overall benefit costs andan increase in repairs and maintenance expenses in relation to the highervolumes.

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The remainder of thechange in operating income in the Natural Gas segment was due to overalldecreased results on the balance of our natural gas systems.

*Future Prospects for Natural Gas*

Our natural gas assets arelocated in the Gulf Coast and Mid-continent regions of the United States, twoof the premier natural gas producing areas. As a result, there are manyopportunities to connect new natural gas supplies either by installing newfacilities or acquiring adjacent third-party gathering operations.Consolidation with neighboring facilities will extract efficiencies byeliminating costs, for example, by combining redundant facilities, increasingvolume, and increasing processing margins. These opportunities tend to involvemodest amounts of capital with attractive rates of return.

We continue to assessvarious acquisition and expansion opportunities to pursue our strategy forgrowth. The market for acquiring energy transportation assets is active andcompetition among prospective acquirers of assets has been significant. Whilewe remain committed to making accretive acquisitions in or near areas where wealready operate or have a competitive advantage, we will continue to focus ourefforts primarily on development of our existing pipeline systems. Although oneof our objectives is to grow our natural gas business through acquisitions, wemay and have pursued opportunities to divest of any non-strategic natural gasassets as conditions warrant.

Results of our natural gasgathering and processing business depend upon the drilling activities ofnatural gas producers in the areas we serve. During 2005, increased drilling inthe areas where our gathering systems are located has generally contributed toour volume growth. We expect the growth trend in these areas to continue in thefuture as evidenced by third-party reserve studies and the increase in rigcounts in the areas served by our systems. Continuing advances in seismic anddrilling completion technology, along with robust energy prices, have been keydrivers for the higher drilling activity levels in such areas as the tight gasand gas shale locations of the Mid-Continent and East Texas. Other advances indrilling technology are enabling producers to more economically extract naturalgas from wells and increase well productivity.

One of the prominent areasin which this is occurring is the Barnett Shale play in North Texas. TheBarnett Shale is a prominent natural gas formation within the Fort Worth Basin,and it is being actively developed.  Theformation produced approximately 110 MMcf/d in 1999 and had grown to over 1,200MMcf/d by July 2005. We anticipate that throughput on the North Texassystem will increase modestly in each of the next several years as a result ofBarnett Shale development.

Therate of growth on our Anadarko system continues to exceed projections as aresult of the rapid development of the Granite Wash play in Hemphill andWheeler counties. To accommodate this continuing volume growth, the Anadarko systemrequires additional processing capacity and field compression. We are set toexpand our system processing capacity in the region from 230MMcf/d to approximately400MMcf/d, which we expect to place in service in early 2007.

In theEast Texas region, our overall system receipts rose to over 800 MMbtu/d shortlyafter we brought our newly constructed 500 MMcf/d intrastate transmissionpipeline on line in mid-2005 to carry increased volumes of natural gas tothe Carthage hub.  Producer drillingplans in regional plays, including the Bossier trend and Deep Bossier, areexpected to result in continued production growth. To accommodate this furthergrowth, we will increase our gathering and treating infrastructure and marketaccess capability. To further this objective we have committed to a $530million expansion of our East Texas system. The key components of this projectinclude:

·       A36-inch diameter intrastate pipeline from Bethel, Texas to Orange County,Texas with capacity of approximately 700 MMcf/d, will be completed in stagesthroughout 2007. The new line will provide service to a number of majorindustrial and power companies in Southeast Texas and will cross a number ofinterstate pipelines.

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·       A200 MMcf/d treating facility to be built near Marquez, Texas will be connectedto the 36-inch pipe via a new 24-inch diameter pipeline, to becompleted in early 2007.

·       Anumber of upstream facilities, including gathering pipelines to tie existingfacilities into the new intrastate pipeline, will also be completed in early2007.

When fully operational inlate 2007, the new assets will be an additional source of stable cash flow forus. We are also evaluating other projectsthat further integrate all our major Texas-centered pipeline systems.

Weare also working with Enbridge on its proposed interstate extension from ourTexas natural gas midstream business. Enbridge announced an Open Season on aproposed 330 mile, 1 billion cubic feet per day pipeline from Texasthrough Louisiana, to interconnect with other interstate systems in WesternMississippi. This project, if supported by shippers, could draw, additionalvolumes through our East Texas system and its proposed expansion announced inJanuary 2006.

Our Bamagas system hasagreements to provide transportation of up to 276,000 MMbtu/d of natural gasfor a remaining period of 17 years to two utility plants that are indirectlyowned by Calpine Corporation (“Calpine”). Calpine is the sole customer servedby the Bamagas system. The Bamagas system receives a fixed demand charge of$0.07 per MMBtu of natural gas for 200,000 MMBtu/d, regardless of whether thecapacity is used. In December 2005, Calpine and many of its subsidiaries,including the subsidiary that owns the two utility plants served by our Bamagassytem, filed voluntarily petitions to restructure under Chapter 11 of theUnited States Bankruptcy Code. In connection with the bankruptcy filing,Calpine has announced receipt of commitments for up to $2 billion of Debtor inPossession, or DIP financing to allow for the continued operation of theirpower plants. Our Bamagas system is the sole supplier of natural gas to thesetwo utility plants, and we expect the subsidiary that owns these utility plantsto continue performing under the terms of our agreement. Due to the recentnature of the bankruptcy filing, we are unable to determine the extent of anylosses to which we may be subject as a result of the bankruptcy. We areactively monitoring the Calpine bankruptcy proceedings and will recognize anylosses that may result when it becomes evident that a loss has been incurred.

***Marketing***

Thefollowing table sets forth the operating results for the Marketing segmentassets for the periods presented:

| ** **                     | ** ** | **Year Ended December 31,** | ** ** |
|--------------------------------|------------|--------------------------------------------|------------|
| ** **                     | ** ** | **2005**                                   | ** ** | **2004** | ** ** | **2003** | ** ** |
| ** **                     | ** ** | **(dollars in millions)**        | ** ** |
| Operating  revenues            |       | $                                          | 3,706.8    |   | $ | 2,562.5 |   | $ | 1,869.6 |   |
| Cost of natural  gas           |       | (3,744.6                                   | )          | (2,555.3 | ) | (1,857.8 | ) |
| Operating and  administrative  |       | (4.1                                       | )          | (3.4 | ) | (2.2 | ) |
| Depreciation and  amortization |       | (0.5                                       | )          | (0.2 | ) | (0.2 | ) |
| Expenses                       |       | (3,749.2                                   | )          | (2,558.9 | ) | (1,860.2 | ) |
| **Operating income (loss)**    |       | $                                          | (42.4      | ) | $ | 3.6 |   | $ | 9.4 |   |

 

Natural gas purchased and sold by our Marketingsegment is priced at a published daily or monthly price index. Sales towholesale customers typically incorporate a premium for managing theirtransmission and balancing requirements. Higher premiums and associated marginsresult from transactions that involve smaller volumes or that offer greaterservice flexibility for wholesale customers. At their request, we will enterinto long-term fixed price purchase or sales contracts with our customers andgenerally will enter into offsetting hedged positions under the same or similarterms.

Marketing pays third-party storage facilitiesand pipelines for the right to store and transport natural gas for variousperiods of time. These contracts may be denoted as firm storage, interruptiblestorage, or 

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parking and lendingservices. These various contract structures are used to mitigate riskassociated with sales and purchase contracts, and to take advantage of pricedifferential opportunities.

As a result of thewidespread damage caused by hurricanes Katrina and Rita, the major creditrating agencies have issued negative credit implications for several of ourindustrial and utility customers. Although we do not anticipate any significantdeterioration in the credit standing of our other customers, we continue tomonitor their financial condition, and expect improvement in their creditstanding as system outages are restored and property damage repaired.

*Year ended December 31,2005 compared with year ended December 31, 2004*

A majority of the operating income of our Marketingsegment is derived from selling natural gas received from customers on ourNatural Gas segment pipeline assets to end users of natural gas. A majority ofthe natural gas is purchased in Texas markets where we have limited physicalaccess to the primary interstate pipeline delivery points, or hubs such asWaha, Texas and the Houston Ship Channel. As a result, our Marketing businessmust use third-party pipelines to transport the natural gas to these marketswhere it can be sold to customers. However, physical pipeline constraints oftenrequire our Marketing business to transport natural gas to alternate marketpoints. Under these circumstances, our Marketing segment will sell thepurchased gas at a pricing index that is different from the pricing index atwhich the gas was purchased. This creates a price exposure that arises from therelative difference in natural gas prices between the contracted index at whichthe natural gas is purchased and the index under which it is sold, otherwiseknown as the “spread.” The spread can vary significantly due to local supplyand demand factors. Wherever possible, this pricing exposure is economicallyhedged using derivative financial instruments. However, the structure of theseeconomic hedges often precludes our use of hedge accounting under therequirements of SFAS No. 133, which can create another element of volatilityin the operating results of our Marketing segment.

To ensure that we have access to primary pipelinedelivery points, we often enter into firm transportation agreements oninterstate and intrastate pipelines. In order to offset the demand chargesassociated with these firm transportation contracts, we look for marketconditions that allow us to lock in the price differential or spread betweenthe pipeline receipt point and pipeline delivery point. This allows ourMarketing business to lock in a fixed return, inclusive of pipeline demandcharges. We accomplish this by transacting basis swaps between the index wherethe natural gas is purchased and the index where the natural gas is sold. Bytransacting a basis swap between those two indices, we can effectively lock ina margin on the combined natural gas purchase and the natural gas sale,mitigating the demand charges on firm transportation agreements and limitingour exposure to cash flow volatility that could arise in markets where the firmtransportation becomes uneconomic. However, the structure of these transactionsprecludes our use of hedge accounting under the requirements of SFAS No. 133,which can create volatility in the operating results of our Marketing segment.

In addition to natural gas basis swaps, we contractfor storage to assist balancing natural gas supply and end use market sales. Inorder to mitigate the absolute price differential between the cost of injectednatural gas and withdrawn natural gas, as well as storage fees, the injectionand withdrawal price differential, or “spread” is hedged by buying fixed priceswaps for the forecasted injection periods and selling fixed price swaps forthe forecasted withdrawal periods. When the injection and withdrawal spreadincreases or decreases in value as a result of market price movements, we canearn additional profit through the optimization of those hedges in both theforward and daily markets. Although each of these hedge strategies are soundeconomic hedging techniques, these types of financial transactions do notqualify for hedge accounting under the SFAS No. 133 guidelines. As such,the non-qualified hedges are accounted for on a mark-to-marketbasis, and the periodic change in their market value, although non-cash, willimpact the income statement.

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During the third and fourth quarters, disruptions ofnatural gas supplies from facilities in the Gulf of Mexico region caused byhurricanes Katrina and Rita created greater demand for natural gas productionfrom our onshore Natural Gas segment pipeline assets, increasing our ability tooptimize natural gas supply to areas of strongest demand. As a result of thehurricanes, unusual volatility in the prices of natural gas created greaterspreads on our natural gas volumes.

Although our Marketing segment was not adverselyaffected from the temporary supply disruptions in the Gulf of Mexico, wegenerally continue to be affected by lower unit margins on natural gas volumespurchased due to physical pipeline constraints. The recent completion of ourEast Texas system expansion has partially alleviated these constraints;however, increasing production volumes will continue to create additional marketoutlet constraints. These additional pipeline constraints will requirecontinued use of third-party pipelines in East Texas. This situation is notlimited to the East Texas region. Pricing in our natural gas supply markets isexpected to continue to experience increasing pressure due to a greater supplyof natural gas from the Rocky Mountains, Mid-Continent and North Texas. Forthis reason we continue to increase our commitments on third-partypipelines to mitigate these constraints and provide more attractive marketoutlets for our natural gas supply. However, there continues to be timingdifferences between the acquisition of new third-party pipeline capacity andthe negotiation of applicable downstream sales agreements. Until new marketsare developed, our Marketing segment sells greater portions of its natural gassupply in less attractive short-term markets.

For the year endedDecember 31, 2005, our Marketing segment incurred losses of$42.4 million, which include non-cash mark-to-market losses of $48.2million, compared with earning $3.6 million of operating income for thecorresponding period in 2004. The non-cash, mark-to-market losses areassociated with derivative financial instruments that do not qualify for hedgeaccounting treatment under SFAS No. 133. During 2005, we revised ourbusiness strategy for the use of derivative financial instruments associatedwith the transportation and storage of natural gas to afford us the ability torespond to changing economic conditions. The flexibility provided by ourrevised strategy precludes us from continuing the use of hedge accounting withregard to these transactions. Under SFAS No. 133, if the forecastedtransaction is no longer probable of occurring as originally set forth in thehedge documentation, the financial instruments must be marked-to-market eachperiod with the change in fair market value recorded in earnings. However, SFASNo. 133 does not allow us to mark-to-market the change in value of therelated underlying physical transaction, and this difference creates earningsvolatility when the “spreads” move. We expect these net mark-to-market lossesto be predominantly offset when the related physical transactions are settled(refer also to the discussion  includedin Item 7A. Quantitative and Qualitative Disclosures About Market Risk andNote 15 of our Consolidated Financial Statements beginning on page F-1of this report).

*Year endedDecember 31, 2004 compared with year ended December 31, 2003*

Our Marketing segment accounted for $3.6 millionof operating income, a decrease of $5.8 million compared with $9.4 millioncontributed in 2003. Operating income in 2004 for our Marketing segmentincluded a loss of $2.1 million associated with financial natural gasbasis swap transactions that do not qualify for hedge accounting treatmentunder SFAS No. 133. The unqualified hedges are accounted for on amark-to-market basis, and the periodic change in their market value willcontinue to impact the income statement until the derivative financialinstruments are settled. In 2003, the loss associated with unqualifiedderivatives was $0.3 million.

Our Marketing segment was also impacted by lower unitmargins on natural gas volumes purchased due to physical pipeline constraints.Performance of the Marketing segment was also negatively impacted by demandcharges on new third-party pipeline capacity that is utilized totransport natural gas from markets that are over supplied with natural gas inour Natural Gas segment to new markets. Pricing in our natural gas supplymarkets is expected to come under increasing pressure due to higher natural gas

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supplies from the RockyMountains and North Texas. For this reason we have increased our commitments onthird-party pipelines to provide more attractive market outlets for ournatural gas supply.

**Corporate**

***Yearended December 31, 2005 compared with year ended December 31, 2004***

Interestexpense was $107.7 million in 2005 compared with $88.4 million in2004. The increases are the result of higher debt balances and higherweighted average interest rates of approximately 5.78% for the year ended December 31,2005, compared with approximately 5.56% during 2004. The increase in our debtbalances at December 31, 2005 is due to the gathering and processingassets in North Texas we acquired in January 2005, in addition to thecapital expenditures we have made to expand our existing systems to improve theservice capabilities of our assets.

***Yearended December 31, 2004 compared with year ended December 31, 2003***

Interest expense was $88.4 millionin 2004 compared with $85.0 million in 2003. The $3.4 million increasein 2004 compared with 2003 reflects higher average borrowings, partially offsetby a decrease in our average borrowing rates.

Included in our resultsfor the year ended December 31, 2004 was a charge related to rate refundspayable on KPC for $13.6 million associated with rates charged to customers ofKPC prior to our ownership. We extinguished this obligation in the firstquarter of 2005 and have not incurred any similar rate refunds during the yearended December 31, 2005.

**LIQUIDITY AND CAPITAL RESOURCES**

***General***

We believe that our ability to generate cash flow, inaddition to our access to capital is sufficient to meet the demands of ourcurrent and future operating growth and investment needs. Our primary cashrequirements consist of normal operating expenses, maintenance and expansioncapital expenditures, debt service payments, distributions to our partners andacquisitions of new assets and businesses, and payments associated with ourderivative transactions. Short-term cash requirements, such as operatingexpenses, maintenance capital expenditures, debt service payments and quarterlydistributions to our partners, are expected to be funded by operating cashflows. Margin requirements associated with our derivative transactions aregenerally supported by letters of credit issued under our Credit Facility. Weexpect to fund long-term cash requirements for expansion projects andacquisitions from several sources, including cash flows from operatingactivities, borrowings under the commercial paper program we established in April 2005,our Credit Facility, and the issuance of additional equity and debt securities.Our ability to complete future debt and equity offerings and the timing of anysuch offerings will depend on various factors, including prevailing marketconditions, interest rates, our financial condition and credit rating at thetime.

During 2005, we shiftedour business strategy to an emphasis on developing and expanding our existingLiquids and Natural Gas businesses with less focus on acquisitions. Theinternal growth projects we have planned for our Natural Gas business (seeNatural Gas segment—Future Prospects), coupled with the Southern Access Programon our Lakehead system (see Liquids segment—Future Prospects), will requiresignificant expenditures of capital over the next several years. We expect tofund these expenditures from a balanced combination of additional issuances ofpartnership capital and long-term debt. Our planned internal growth projectswill require us to bear the cost of constructing these new assets before wewill begin to realize a return on them. While these major projects are underconstruction, our ability to increase distributions, while funding theseprojects is likely to be limited.

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***Capital Resources***

*Equity Capital*

Our ability to execute our growth strategy andcomplete our planned construction projects is dependent upon our access to thecapital necessary to fund these projects. During 2005, we raised net proceedsof approximately $268.6 million from public offerings of our common units,including $5.7 million from our General Partner to maintain its 2-percentgeneral partner interest. We primarily used the proceeds from these offeringsto temporarily reduce amounts outstanding under our Credit Facility and ourcommercial paper program which were initially used to finance our capitalexpansion projects and acquisitions. The following table presents historicalinformation about our public equity offerings since January 2003:

| **Issuance Date** | ** ** | ** **                                                           | ** ** | **Number of  Class A  Common units  Issued** | ** ** | **Offering  Price per  Class A  Common  unit** | ** ** | **Net Proceeds to  Partnership**(1) | ** ** | **General Partner  Contribution**(2) | ** ** | **Net Proceeds  Including  General Partner  Contribution** | ** ** |
|------------------------|------------|----------------------------------------------------------------------|------------|-------------------------------------------------------------|------------|----------------------------------------------------------|------------|-----------------------------------------------|------------|-------------------------------------------|------------|----------------------------------------------------------------------|------------|
| ** **             | ** ** | **($in millions, except per unit amounts)** | ** ** |
| **2005:**              |       |                                                                 |       |                                                        |       |                                                     |       |                                          |       |                                      |       |                                                                 |       |   |   |   |   |   |   |
| December 2005     |       |                                                                 | 136,200    |                                                        |       | $                                                        | 46.000     |                                          |       | $                                         | 6.0        |                                                                 |       |   | $ | 0.2 |   |   |   | $ | 6.2 |   |   |
| November 2005     |       |                                                                 | 3,000,000  |                                                        |       | $                                                        | 46.000     |                                          |       | 132.1                                     |       |                                                                 |       | 2.8 |   |   |   | 134.9 |   |   |
| February 2005     |       |                                                                 | 2,506,500  |                                                        |       | $                                                        | 49.875     |                                          |       | 124.8                                     |       |                                                                 |       | 2.7 |   |   |   | 127.5 |   |   |
| **2005 Totals**        |       |                                                                 | 5,642,700  |                                                        |       |                                                     |       |                                          | $          | 262.9                                     |       |                                                                 |       | $ | 5.7 |   |   |   | $ | 268.6 |   |   |
| **2004:**              |       |                                                                 |       |                                                        |       |                                                     |       |                                          |       |                                      |       |                                                                 |       |   |   |   |   |   |   |
| September 2004    |       |                                                                 | 3,680,000  |                                                        |       | $                                                        | 47.900     |                                          |       | $                                         | 168.6      |                                                                 |       |   | $ | 3.6 |   |   |   | $ | 172.2 |   |   |
| January 2004      |       |                                                                 | 450,000    |                                                        |       | $                                                        | 50.300     |                                          |       | 21.6                                      |       |                                                                 |       | 0.4 |   |   |   | 22.0 |   |   |
| **2004 Totals**        |       |                                                                 | 4,130,000  |                                                        |       |                                                     |       |                                          | $          | 190.2                                     |       |                                                                 |       | $ | 4.0 |   |   |   | $ | 194.2 |   |   |
| **2003:**              |       |                                                                 |       |                                                        |       |                                                     |       |                                          |       |                                      |       |                                                                 |       |   |   |   |   |   |   |
| December 2003     |       |                                                                 | 5,000,000  |                                                        |       | $                                                        | 50.300     |                                          |       | $                                         | 240.4      |                                                                 |       |   | $ | 5.0 |   |   |   | $ | 245.4 |   |   |
| May 2003          |       |                                                                 | 3,850,000  |                                                        |       | $                                                        | 44.790     |                                          |       | 165.5                                     |       |                                                                 |       | 3.5 |   |   |   | 169.0 |   |   |
| **2003  Totals**       |       |                                                                 | 8,850,000  |                                                        |       |                                                     |       |                                          | $          | 405.9                                     |       |                                                                 |       | $ | 8.5 |   |   |   | $ | 414.4 |   |   |

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(1)                Net ofunderwriters’ fees and discounts, commissions and issuance expenses.

(2)                Contributionsmade by the General Partner to maintain its 2% general partner interest.

*Available Credit*

A significant source of our liquidity is provided bythe commercial paper market. In April 2005, we established a $600 millioncommercial paper program that is supported by our long-term Credit Facility. Weaccess the commercial paper market primarily to provide temporary financing forour operating activities, capital expenditures and acquisitions, at rates thatare generally lower than the rates available under our Credit Facility. Underthe terms of our commercial paper program, we may issue up to $600 million ofcommercial paper. However, the amount of commercial paper we may issue isreduced by any balance of outstanding letters of credit in excess of $200million. At December 31, 2005, we had $330.0 million in principal amountof commercial paper outstanding and could issue $270.0 million in principalamount of commercial paper.

Our Credit Facility alsoprovides us with another significant source of liquidity. We amended our CreditFacility twice during 2005, to among other things, extend the maturity to April 2010;increase the letter of credit sub limit to $300 million; increase the availablecommitments to $800 million with the right to request, subject to approval bythe Board of Directors of Enbridge Management, an increase in 

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commitmentsavailable up to an aggregate principal amount of $1 billion; decrease the “ApplicableRate” as set forth in the Credit facility; and extend to December 2006,the requirement to maintain a “Consolidated Leverage Ratio,” as defined in theCredit Facility, of not more than 5.25:1. The amounts we may borrow under theterms of our Credit Facility are reduced by the principal amount of ourcommercial paper issuances and the balance of our letters of creditoutstanding. At December 31, 2005, no amounts had been borrowed againstour Credit Facility and we had approximately $149.3 million of letters ofcredit outstanding. We could borrow $320.7 million under the terms of ourCredit Facility.

***Indebtedness and Other Payment Obligations***

Our Credit Facility and debt consist of the following:

| ** **                                    | ** ** | **December 31,**  | ** ** |
|-----------------------------------------------|------------|------------------------|------------|
| ** **                                    | ** ** | **2005**               | ** ** | **2004** | ** ** |
| ** **                                    | ** ** | **(in millions)** | ** ** |
| Current portion  of First Mortgage Notes      |       | $                      | 31.0       |   | $ | 31.0 |   |
| Long-term  debt:                              |       |                   |       |   |   |
| Commercial Paper                              |       | $                      | 329.3      |   | $ | — |   |
| Credit Facility                               |       | —                 |       | 175.0 |   |
| First Mortgage Notes                          |       | 155.0                  |       | 186.0 |   |
| 4.00% senior notes due 2009 or notes due 2009 |       | 200.0                  |       | 200.0 |   |
| 7.90% senior notes due 2012                   |       | 100.0                  |       | 100.0 |   |
| 4.75% senior notes due 2013                   |       | 200.0                  |       | 200.0 |   |
| 5.35% senior notes due 2014                   |       | 200.0                  |       | 200.0 |   |
| 7.00% senior notes due 2018                   |       | 100.0                  |       | 100.0 |   |
| 7.125% senior notes due 2028                  |       | 100.0                  |       | 100.0 |   |
| 5.95% senior notes due 2033                   |       | 200.0                  |       | 200.0 |   |
| 6.30% senior notes due 2034                   |       | 100.0                  |       | 100.0 |   |
| Unamortized discount                          |       | (1.4                   | )          | (1.6 | ) |
| Total long-term  debt                         |       | $                      | 1,682.9    |   | $ | 1,559.4 |   |
| Loans from General  Partner and affiliates    |       | $                      | 151.8      |   | $ | 142.1 |   |

 

*Commercial PaperProgram*

In April 2005, we established our $600 millioncommercial paper program that is supported by our Credit Facility. We accessthe commercial paper market primarily to provide temporary financing for ouroperating activities, capital expenditures and acquisitions, at rates that aregenerally lower than the rates available under our Credit Facility. We repaidthe entire amount previously outstanding under our Credit Facility withproceeds we obtained from issuing commercial paper under this program.  Our Credit Facility remains undrawn and availableto support our commercial paper program.

Under the terms of ourcommercial paper program, we can issue up to $600 million of commercial paper. However,the amount of commercial paper we may issue is reduced by any balance ofoutstanding letters of credit in excess of $200 million. At December 31,2005, we had $330.0 million in principal amount of commercial paperoutstanding, with unamortized discount of $0.7 million, at a weighted averageinterest rate of 4.36% and outstanding letters of credit totaling $149.3million. At December 31, 2005, we could issue an additional $270 millionin principal amount under our commercial paper program.

*Credit Facility*

Our Credit Facility, as amended, is a five-year termfacility that matures in April 2010 with a current borrowing capacity of$800 million and a letter of credit sub limit of $300 million. Subject to theapproval of Enbridge Management’s Board of Directors, we have the right torequest an increase in commitments 

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available under the CreditFacility up to an aggregate outstanding principal amount of $1 billion. We payinterest on the amounts outstanding at variable rates equal to the “Base Rate”or a “Eurodollar Rate” as defined in the Credit Facility. In the case ofEurodollar Rate loans, an additional margin is charged which varies dependingon our credit rating and the amounts drawn under the facility. We are alsocharged a facility fee on the entire amount of the Credit Facility, regardlessof the amount drawn, which also varies depending on our credit rating.

Our Credit Facility contains restrictive covenantsthat require us to maintain a minimum interest coverage ratio of 2.75 times anda maximum leverage ratio of 5.25 times for twelve months through December 2006,at which time it decreases to 5.00 times, thereafter. At December 31,2005, our interest coverage ratio was approximately 3.7 and our leverage ratiowas approximately 4.2. Our Credit facility also places limitations on the debtthat our subsidiaries may incur directly. Accordingly, it is expected that wewill provide debt financing to our subsidiaries as necessary.

At December 31, 2005,we had no balances outstanding under our Credit Facility and letters of credittotaling $149.3 million. The amounts we may borrow under the terms of ourCredit Facility are reduced by the principal amount of our commercial paperissuances and the balance of our letters of credit outstanding. At December 31,2005, we could borrow $320.7 million under the terms of our Credit Facility.

*First MortgageNotes*

The First Mortgage Notesare collateralized by a first mortgage on substantially all of the property,plant and equipment of the Lakehead Partnership and are due and payable inequal annual installments of $31.0 million until their maturity in 2011.The Notes contain various restrictive covenants applicable to us, andrestrictions on the incurrence of additional indebtedness, including compliancewith certain debt issuance tests. We were in compliance with these covenants atDecember 31, 2005. We believe these issuance tests will not negativelyaffect our ability to finance future expansion projects. Under the FirstMortgage Note Agreements, we cannot make cash distributions more frequentlythan quarterly in an amount not to exceed Available Cash for the immediatelypreceding calendar quarter. If we repay the Notes prior to their statedmaturities, the First Mortgage Note Agreements provide for the payment of aredemption premium by us.

*Senior Notes*

Our Senior Notes are structurally subordinated to allexisting and future indebtedness and other liabilities, including tradepayables of our subsidiaries. The borrowings under these Notes are non-recourseto our General Partner and Enbridge Management. These notes are subject tomake-whole redemption rights and were issued under an indenture containingcertain covenants that restrict our ability, with certain exceptions, to sell,convey, transfer, lease or otherwise dispose of all or substantially all of ourassets to any Person, except in accordance with our indenture agreement. Wewere in compliance with these covenants at December 31, 2005.

We did not issueany Senior Notes during the year ended December 31, 2005. However, for theyear ended December 31, 2004, we made the following senior note issuances:

·       InDecember 2004, we issued $200.0 million in aggregate principal amountof our 5.35% Senior Notes due 2014 and $100.0 million in aggregateprincipal amount of our 6.30% Senior Notes due 2034 in a public offering, fromwhich we received net proceeds of $297.1 million. We used the proceeds torepay a portion of our outstanding debt under bank Credit Facility.

·       InJanuary 2004, we issued $200.0 million in aggregate principal amountof our 4.0% Senior Notes due 2009 in a public offering, from which we receivednet proceeds of $198.3 million. We used the proceeds to repay a portion ofour outstanding debt under bank Credit Facility.

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All of our Senior Notesrepresent our unsecured obligations that rank equally in right of payment withall of our existing and future unsecured and unsubordinated indebtedness. OurSenior Notes are effectively junior in right of payment to any securedindebtedness that we may have and to all existing and future indebtedness andother liabilities of our subsidiaries, which own all of our operating assets. Additionally,all of our Senior Notes pay interest semi-annually and have varying maturitiesand terms as presented in the table above. Our Senior Notes do not contain anycovenants restricting us from issuing additional indebtedness.

*Loans from GeneralPartner and affiliates*

As of December 31,2005 and 2004, we had $151.8 million and $142.1 million,respectively, in debt outstanding under a note to an affiliate of our generalpartner. This note relates to debt we assumed in connection with ouracquisition of the Midcoast system in October 2002. The note matures in2007 and has cross-default provisions that are triggered by events ofdefault under our First Mortgage Notes or defaults under our Credit Facility.The note is subordinate to our Credit Facility and other senior indebtedness.For the years ended December 31, 2005 and 2004, we converted interestpayable related to this note in the amount of $9.7 million and$9.0 million, respectively, into long-term debt.

*Credit Ratings*

Thefollowing table reflects the ratings that have been assigned to our debt andthe debt of our wholly-owned subsidiary, Enbridge Energy, Limited Partnershipat December 31, 2005:

| ** **                                   | ** ** | **Standard  &  Poor’s** | ** ** | **Moody’s** | ** ** | **Dominion Bond  Rating Service** |
|----------------------------------------------|------------|----------------------------------|------------|------------------|------------|-----------------------------------|
| **Enbridge  Energy Partners, L.P.**          |       |                             |       |             |       |                              |
| Corporate                                    |       | BBB(stable)                      |       | NR               |       | BBB                               |
| Commercial Paper                             |       | A-2                              |       | P-1              |       | NR                                |
| Medium Term Notes & Unsecured Debentures |       | BBB                              |       | Baa2             |       | BBB                               |
| **Enbridge  Energy, Limited Partnership**    |       |                             |       |             |       |                              |
| Senior secured                               |       | BBB+                             |       | NR               |       | NR                                |
| Senior unsecured                             |       | BBB                              |       | Baa1             |       | NR                                |

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NR—No rating is available

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*Summaryof Obligations and Commitments*

Thefollowing table summarizes the principal amount of our obligations andcommitments at December 31, 2005:

| ** **                            | ** ** | **2006**                            | ** ** | **2007** | ** ** | **2008** | ** ** | **2009** | ** ** | **2010** | ** ** | **Thereafter** | ** ** | **Total** | ** ** |
|---------------------------------------|------------|-------------------------------------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------------|------------|-----------|------------|
| ** **                            | ** ** | **(dollars in millions)** | ** ** |
| Long-term  debt                       |       | $                                   | 31.0       |     | $          | 182.8    |       | $        | 31.0       |     | $          | 231.0          |       | $         | 360.3      |   |   | $ | 1,029.6 |   |   | $ | 1,865.7 |   |
| Power and other  purchase commitments |       | 70.4                                |       | —   |       | —   |       | —   |       | —   |       |           | —     |      |       | 70.4 |   |
| Other operating  leases               |       | 4.2                                 |       | 4.2      |       | 4.0      |       | 3.5      |       | 1.1      |       |           | —     |      |       | 17.0 |   |
| Right-of-way(1)                       |       | 1.8                                 |       | 1.7      |       | 1.7      |       | 1.8      |       | 1.8      |       |           | 44.7       |      |       | 53.5 |   |
| Product purchase  obligations(2)      |       | 62.8                                |       | 59.9     |       | 36.6     |       | 31.8     |       | 28.0     |       |           | 116.7      |      |       | 335.8 |   |
| Service contract  obligations(3)      |       | 12.4                                |       | 10.5     |       | 5.3      |       | 3.2      |       | —   |       |           | —     |      |       | 31.4 |   |
| Total                                 |       | $                                   | 182.6      |     | $          | 259.1    |       | $        | 78.6       |     | $          | 271.3          |       | $         | 391.2      |   |   | $ | 1,191.0 |   |   | $ | 2,373.8 |   |

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(1)                Right-of-waypayments are estimated to be approximately $1.8 million per year for theremaining life for all pipeline systems, which has been estimated to be25 years for purposes of calculating the amount of future minimumcommitments beyond 2010.

 

(2)                We have long-termproduct purchase obligations with several third-party suppliers toacquire natural gas and NGLs at prices approximating market at the time ofdelivery.

(3)                Thetransportation service obligations represent the minimum payment amounts forfirm transportation capacity we have reserved on third-party pipelines.

***Cash Requirements for Future Growth***

*Capital Spending*

We expect to make significant expenditures during thenext three years for the construction of additional natural gas and crude oiltransportation infrastructure. Extensive volume growth in the areas served by ourEast Texas system necessitates the construction of additional pipeline capacityto transport these volumes to alternate natural gas markets. Additionally,anticipated growth in western Canadian oil sands production and the need toreach newer markets has prompted the Southern Access project on our Lakeheadsystem. In 2006, we expect to spend approximately $530 million on theseprojects with the expectation of realizing additional cash flows as theseprojects are completed and placed in service. At December 31, 2005, we had$64.0 million in estimated outstanding purchase commitments attributable tocapital projects for the construction of assets that will be recorded asproperty, plant and equipment during 2006.

We categorize our capital expenditures as either coremaintenance or enhancement expenditures. Core maintenance expenditures arethose expenditures that are necessary to maintain the service capability of ourexisting assets and includes the replacement of system components and equipmentwhich is worn, obsolete or completing its useful life. Enhancement expendituresimprove the service capability of the existing assets, extend asset usefullives, increase capacities from existing levels, reduce costs or enhancerevenues, and enable us to respond to governmental regulations and developingindustry standards.

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In2006, we anticipate our capital expenditures to approximate the following inmillions:

| System  enhancements         |   | $   | 430    |   |
|------------------------------|--------|-----|--------|--------|
| Core maintenance  activities |   | 45  |   |
| Southern Access expansion    |   | 190 |   |
| East Texas  expansion        |   | 340 |   |
|                         |   | $   | 1,005  |   |

 

Including major expansion projects and excludingacquisitions, ongoing capital expenditures are expected to be significant overthe next three years due to the East Texas expansion and Southern Accessprojects. Core maintenance capital is also anticipated to increase over thatperiod of time due to growth in our pipeline systems and aging ofinfrastructure.

We anticipate funding the system enhancement capital expenditurestemporarily through the issuance of commercial paper, borrowing under the termsof our Credit Facility, with permanent debt and equity funding being obtainedwhen appropriate. Core maintenance expenditures are expected to be funded byoperating cash flows.

The Southern Access and East Texas expansion projectshave strong support from shippers, and upon completion each project will have stablecash flows. We have received indications that these projects can be readilyfinanced. We are currently in discussions with our commercial bankers tostructure and implement bridge credit facilities that will be required tofinance the construction. This incremental bridge credit capacity may also beused to support a temporary expansion of our commercial paper program. Thebridge credit facilities will be refinanced with permanent capital at keymilestone dates for each project.

We expect to incur continuing annual capital andoperating expenditures for pipeline integrity measures to ensure bothregulatory compliance and to maintain the overall integrity of our pipelinesystems. Expenditure levels have continued to increase as pipelines age andrequire higher levels of inspection or maintenance; however, these are viewedto be consistent with industry trends.

*Acquisitions*

We continue to assess various acquisition andexpansion opportunities to pursue our strategy for growth. However, the marketfor acquiring energy transportation assets is active and competition amongprospective acquirers of assets has been significant. While we remain committedto making accretive acquisitions in or near areas where we already operate orhave a competitive advantage, we will continue to focus our efforts ondevelopment of our existing pipeline systems. Additionally, we may pursueopportunities to divest of any non-strategic assets as conditions warrant.

We expect that the funds needed to achieve growththrough acquisitions will be obtained through issuances of commercial paper,term debt and additional partnership interests.

***Derivative Activities***

We use derivative financial instruments (i.e.,futures, forwards, swaps, options and other financial instruments with similarcharacteristics) to mitigate the volatility of our cash flows and manage thepurchase and sales prices of our commodities. Based on our risk managementpolicies, all of our derivative financial instruments are employed inconnection with an underlying asset, liability and/or anticipated transactionand are not entered into with the objective of speculating on commodity prices.

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Thefollowing table provides summarized information about the timing and expectedsettlement amounts of our outstanding commodity derivative financialinstruments at December 31, 2005 for each of the indicated calendar years:

| ** **             | ** **   | **Notional** | ** **   | **2006**                  | ** **   | **2007**     | ** **   | **2008**     | ** **   | **2009**     | ** **   | **2010**     | ** **   | **2011**     | ** **   | **2012**     | ** **   |
|------------------------|--------------|--------------|--------------|---------------------------|--------------|--------------|--------------|--------------|--------------|--------------|--------------|--------------|--------------|--------------|--------------|--------------|--------------|
| ** **             | ** **   | ** **   | ** **   | **(dollars in millions)** | ** **   |
| **Swaps**              | *** *** | *** *** | *** *** | *** ***              | *** *** | *** *** | *** *** | *** *** | *** *** | *** *** | *** *** | *** *** | *** *** | *** *** | *** *** | *** *** | *** *** |
| Natural gas(1)         |         | 498,796,627  |         | $                         | (84.3        | )            | $            | (58.0        | )            | $            | (46.8        | )            | $            | (33.4        | )            | $            | (25.8        | ) | $ | (21.2 | ) | $ | (4.8 | ) |
| NGL(2)                 |         | 6,942,833    |         | (29.7                     | )            | (22.5        | )            | (7.2         | )            | (0.6         | )            | (0.3         | )            | —       |         | —       |         |
| Crude(2)               |         | 1,376,479    |         | (7.6                      | )            | (7.9         | )            | (5.2         | )            | (1.0         | )            | (0.1         | )            | —       |         | —       |         |
| **Options—calls** |         |         |         |                      |         |         |         |         |         |         |         |         |         |         |         |         |         |
| Natural gas(1)         |         | 2,191,000    |         | (2.3                      | )            | (2.0         | )            | (1.7         | )            | (1.4         | )            | (1.1         | )            | (1.0         | )            | —       |         |
| **Options—puts**  |         |         |         |                      |         |         |         |         |         |         |         |         |         |         |         |         |         |
| Natural gas(1)         |         | 1,826,000    |         | —                    |         | —       |         | —       |         | —       |         | —       |         | 0.1          |         | —       |         |
| Totals                 |         |         |         | $                         | (123.9       | )            | $            | (90.4        | )            | $            | (60.9        | )            | $            | (36.4        | )            | $            | (27.3        | ) | $ | (22.1 | ) | $ | (4.8 | ) |

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(1)                Notional amountsfor natural gas are recorded in millions of British thermal units (“MMBtu”).

(2)                Notionalamounts for NGL and Crude are recorded in Barrels (“Bbl”).

***Operating Activities***

Net cash provided byoperating activities was $267.1 million in 2005 compared with$245.4 million in 2004. Improved operating cash flow was the result of operatingincome contributions from the gathering and processing assets we acquired innorth Texas, which was partially offset by lower deliveries on the Lakeheadsystem. The remaining changes in cash from operating activities were due tochanges in the operating assets and liabilities from increased natural gasprices in 2005 and general timing differences in the collection on and paymentof our current accounts.

***Investing Activities***

Net cash used inour investing activities was $437.1 million for the year ended December 31,2005, compared with $419.1 million for the prior year. The$18 million increase in funds utilized in investing activities wasprimarily attributable to the following items:

·       Thedollar value of our acquisitions in 2005 was higher compared with 2004,effectively increasing our cash outflows by $45.4 million. During 2005**,**we acquired natural gas gathering and processing assets inNorth Texas for $164.6 million, a natural gas pipeline with interconnects toour Anadarko system for $20.1 million, and other small assets for $1.7 million.In 2004 our asset acquisitions primarily consisted of our Mid-Continent andPalo Duro assets and several other smaller assets for $141.0 million.

·       Wealso had increased cash outflows associated with expansion and growthopportunities of existing assets during 2005 of $56.0 million, as comparedto 2004. ** **During2005, we spent $344.8 million for capital expenditures including coremaintenance and enhancement projects compared to $288.8 million in 2004. Ourcore maintenance capital expenditures increased to $33.0 million for 2005compared with $31.6 million for 2004, due to the expansion and growth ofour existing assets. Our enhancement capital spending increased to $311.8million in 2005 from $257.2 million in 2004. This increase is primarily due tothe 107-mile expansion of our East Texas System, which was completed in June 2005,and several smaller projects to expand our existing natural gas transmissionand processing capacity, and increase our crude oil storage facilities in themid-continent market.

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In December 2005, wesold for $105.4 million in cash a processing plant and related facilities andother gathering and processing assets located in our East and South Texassystems with a carrying value of approximately $86.9 million. We incurredselling costs of approximately $0.4 million and recognized a gain on the saleof approximately $18.1 million. The facilities we sold represent non-strategicassets within our Natural Gas segment. In connection with this sale, we paidapproximately $16.3 million to settle natural gas and NGL hedges associatedwith the natural gas and NGL produced by these assets. We had previouslyrecognized unrealized losses associated with the natural gas hedges that wererealized upon settlement.

***Financing Activities***

Net cash provided by financing activities was$181.5 million in 2005, compared with $187.6 million in 2004. Thedecrease in cash provided by financing activities of $6.1 million isattributable to a greater amount of distributions to our partners, no newissuances of senior notes during 2005, offset by a larger amount of proceedsreceived from unit issuances and increased net issuances of commercial paperand fewer net repayments on the Credit Facility.

During 2005, we had net commercial paper issuances of$330.0 million program which include gross issuances of $2,808.0 million andgross repayments of $2,478.0 million.   We began utilizing the commercial paperprogram in April 2005. We used proceeds from our issuances of commercialpaper to repay amounts outstanding under our Credit Facility. We made netrepayments of $175.0 million on our Credit Facility including borrowings andrepayments of $565.0 million representing net non-cash settlements with theparties to our Credit Facility. During 2004, we made net repayments of $280.0million on our Credit Facility including borrowings and repayments of $1,573.0 millionrepresenting net non-cash settlements with the parties to our Credit Facility. Additionallyduring 2004, we received proceeds of $495.4 million, excluding issuance costs anddiscounts totaling $4.6 million, from the issuance of $500 million in aggregateprinciple amount of our senior notes. We used a portion of the proceeds from oursenior note issuance to repay amounts outstanding under our credit facilitieswhich we initially borrowed to fund our capital expenditures for expansionprojects and acquisitions. We have historically borrowed on our Credit Facilityfor short-term operating activities and to fund capital expenditures forexpansion projects and acquisitions. However, in the second quarter of 2005 webegan issuing commercial paper as a more economical source of short-termcapital than our Credit Facility. During 2005 and 2004, we also repaid $31million on our First Mortgage Notes.

During2005, we also received approximately $268.6 million of net proceeds from theissuance of 5.6 million Class A common units, compared to net proceeds of$194.2 million from the issuance of 4.1 million Class A common units in2004. Cash distributions to partners increased to $210.6 million in 2005 from$191.0 million in 2004 due to:

·       Anincrease in the number of units outstanding; and

·       An increase in the generalpartner incentive distributions, as a result of the increased cashdistributions to our common unitholders.

***Cash Distributions***

We make quarterlydistributions to our General Partner and the holders of our common units, anamount equal to our “available cash,” which generally is defined to mean forany calendar quarter the sum of all of our cash receipts plus net reductions toreserves less all of our cash disbursements and net changes to reserves. Thesereserves are retained to provide for the proper conduct of our business, tostabilize distributions of cash to unitholders and the General Partner and, asnecessary, to comply with the terms of any of our agreements or obligations.Enbridge Management, as the delegate of the General Partner under a delegationof control agreement, computes the amount of our available cash.

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Enbridge Management, as ownerof our i-units, does not receive distributions in cash. Instead, each time thatwe make a cash distribution to the General Partner and the holders of ourcommon units, the number of i-units owned by Enbridge Management and thepercentage of total units in us owned by Enbridge Management increasesautomatically under the provisions of our partnership agreement with the resultthat the number of i-units owned by Enbridge Management will equal the numberof Enbridge Management’s shares and voting shares that are then outstanding.The amount of this increase in i-units is determined by dividing the cash amount distributed percommon unit by the average price of one of Enbridge Management’s listed shareson the NYSE for the 10-trading day period immediately preceding theex-dividend date for Enbridge Management’s shares multiplied by the number ofshares outstanding on the record date.

For purposes ofcalculating the sum of all distributions of available cash, the cash equivalentamount of the additional i-units that are issued when a distribution of cash ismade to the General Partner and owners of common units is treated asdistribution of available cash, even though the i-unit holder will not receivecash. We retain the cash for use in our operations. During 2005, we distributeda total of 802,539 i-units through quarterly distributions to EnbridgeManagement, compared with 840,239 in 2004. We retained $41.5 million in2005 related to the i-unit distributions compared with $38.3 million in2004.

We expect our annual cashdistribution rate for fiscal year 2006 to remain consistent with the declaredannual distribution per unit rate of $3.70 for the years ended December 31,2005 and 2004. We expect that all cash distributions will be paid out ofoperating cash flows over the long-term; however, from time to time, we maytemporarily borrow under our Credit Facility for the purpose of paying cashdistributions until the full impact of assets being developed on operations isrealized.

***Off-Balance SheetArrangements***

We have no off-balancesheet arrangements.

***Subsequent Events***

*Cash Distribution*

On January 30, 2006, Enbridge Management’s Boardof Directors declared a distribution payable to our partners on February 14,2006. The distribution was paid to unitholders of record as of February 6,2006, of our available cash of $67.6 million at December 31, 2005, or$0.925 per common unit. Of this distribution, $56.6 million was paid incash, $10.8 million was distributed in i-units to i-unit holders and$0.2 million was retained from the General Partner in respect of thisi-unit distribution.

**CRITICALACCOUNTING POLICIES AND ESTIMATES**

Our selection andapplication of accounting policies is an important process that has developedas our business activities have evolved and as new accounting pronouncementshave been issued. Accounting decisions generally involve an interpretation ofexisting accounting principles and the use of judgment in applying thoseprinciples to the specific circumstances existing in our business. We makeevery effort to comply with all applicable accounting principles and believethe proper implementation and consistent application of these principles iscritical. However, not all situations we encounter are specifically addressedin the accounting literature. In such cases, we must use our best judgment toimplement accounting policies that clearly and accurately present the substanceof these situations. We accomplish this by analyzing similar situations and theaccounting guidance governing them and consulting with experts about theappropriate interpretation and application of the accounting literature tothese situations.

In addition to the above,certain amounts included in or affecting our consolidated financial statementsand related disclosures must be estimated, requiring us to make certainassumptions with respect to values or conditions that cannot be known withcertainty at the time the consolidated financial 

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statementsare prepared. These estimates affect the reported amounts of assets, liabilities,revenues, expenses and related disclosures with respect to contingent assetsand liabilities. The basis for our estimates is historical experience,consultation with experts and other sources we believe to be reliable. While webelieve our estimates are appropriate, actual results can and often do differfrom these estimates. Any effect on our business, financial position, resultsof operations and cash flows resulting from revisions to these estimates arerecorded in the period in which the facts that give rise to the revision becomeknown.

We believe our criticalaccounting policies and estimates discussed in the following paragraphs addressthe more significant judgments and estimates we use in the preparation of ourconsolidated financial statements. Each of these areas involves complexsituations and a high degree of judgment either in the application andinterpretation of existing accounting literature or in the development ofestimates that affect our consolidated financial statements. Our management hasdiscussed the development and selection of the critical accounting policies andestimates related to the reported amounts of assets, liabilities, revenues andexpenses and disclosure of contingent liabilities with the Audit, Finance &Risk Committee of Enbridge Management’s Board of Directors.

***Revenue Recognitionand the Use of Estimates for Revenues and Cost of Natural Gas***

In general, we recognizerevenue when delivery has occurred or services have been rendered, pricing isdeterminable and collectibility is reasonably assured. For our natural gasbusiness, we must estimate our current month revenue and cost of natural gas topermit the timely preparation of our consolidated financial statements. Wegenerally cannot compile actual billing information nor obtain actual vendorinvoices within a timeframe that would permit the recording of this actual dataprior to preparation of the consolidated financial statements. As a result, werecord an estimate each month for our operating revenues and cost of naturalgas based on the best available volume and price data for natural gas deliveredand received, along with a true-up of the prior month’s estimate to equal theprior month’s actual data. As a result, there is one month of estimated datarecorded in our operating revenues and cost of natural gas for each of theyears ended December 31, 2005, 2004 and 2003. We believe that theassumptions underlying these estimates will not be significantly different fromactual amounts due to the routine nature of these estimates and the stabilityof our processes.

***CapitalizationPolicies, Depreciation Methods and Impairment of Property, Plant and Equipment***

We capitalize expendituresrelated to property, plant and equipment, subject to a minimum rule, that havea useful life greater than one year for (1) assets purchased orconstructed; (2) existing assets that are extended, replaced or improved;or (3) all land, regardless of cost. Acquisitions of new assets,additions, replacements and improvements (other than land) costing less thanthe minimum rule in addition to maintenance and repair costs are expensedas incurred.

During construction, wecapitalize direct costs, such as labor and materials, and other costs, such asdirect overhead and interest at our weighted average cost of debt, and, in ourregulated businesses that apply the provisions of Statement of FinancialAccounting Standards No. 71, *Accounting for the Effectsof Certain Types of Regulation,* or SFAS No. 71, an equityreturn component.

We categorize our capitalexpenditures as either core maintenance or enhancement expenditures. Coremaintenance expenditures are necessary to maintain the service capability ofour existing assets and include the replacement of system components andequipment that are worn, obsolete or near the end of their useful lives.Examples of core maintenance expenditures include valve automation programs,cathodic protection, zero-hour compression overhauls and electrical switchgearreplacement programs. Enhancement expenditures improve the service capabilityof our existing assets, extend asset useful lives, increase capacities fromexisting levels, reduce costs or enhance revenues, and enable us to respond togovernmental regulations and developing industry standards. Examples of enhancementexpenditures 

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include first-timehigh resolution integrity tool runs, the costs associated with installation ofseals, liners and other equipment to reduce the risk of environmentalcontamination from crude oil storage tanks, costs of sleeving a major segmentof the pipeline system following an integrity tool run, natural gas or crudeoil well-connects, natural gas plants and pipeline construction and expansion.

Recent regulatory guidanceissued by the FERC will require us to expense certain costs associated withimplementing the pipeline integrity management requirements of the U.S.Department of Transportation’s Office of Pipeline Safety. Under this guidance,beginning in January 2006, costs to 1) prepare a plan to implementthe program, 2) identify high consequence areas, 3) develop and maintain arecord keeping system and 4) inspect, test and report on the condition ofaffected pipeline segments to determine the need for repairs or replacements,are required to be expensed. We are adopting this guidance prospectively forour SFAS No. 71 companies only, namely, our UTOS, Midla, AlaTenn and KPCnatural gas transmission systems. Consistent with our prior practice, costs ofmodifying pipelines to permit in-line inspections, certain costs associatedwith developing or enhancing computer software and costs associated withremedial mitigation actions to correct an identified condition will continue tobe capitalized for our FERC-regulated and non-regulated pipeline systems. Additionally,for our non-regulated pipelines and our FERC-regulated crude oil pipelines thatare not eligible to apply the provisions of SFAS No. 71, we will continueto capitalize first-timecrack detection tool runs and hydrostatic testing costs conducted for thepurposes of detecting manufacturing or construction defects, consistent withour historical policy. Subsequent work of this nature is expensed as incurred. OurFERC-regulated crude oil pipelines will expense items 1-4 listed abovefor regulatory reporting purposes. We do not expect our implementation of thisregulation to significantly affect our financial position, results ofoperations or cash flows.

We record property, plantand equipment at its original cost and depreciate our assets over the lesser oftheir estimated useful lives or the estimated remaining lives of the crude oilor natural gas production in the basins the assets serve using the group method.Our determination of the useful lives of property, plant and equipment requiresus to make various assumptions, including the supply of and demand forhydrocarbons in the markets served by our assets, normal wear and tear of thefacilities, and the extent and frequency of maintenance programs. We routinelyutilize consultants and other experts to assist us in assessing the remaininglives of the crude oil or natural gas production in the basins we serve.

We record depreciation using the group method ofdepreciation which is commonly used by pipelines, utilities and similarentities. Under the group method, for all segments, upon the disposition ofproperty, plant and equipment, the cost less net proceeds is normally chargedto accumulated depreciation and no gain or loss on disposal is recognized.However, when a significant separately identifiable group of assets, such as aprocessing plant, treating facility or a pipeline system are sold, we willrecognize a gain or loss in our Consolidated Statements of Income for thedifference between the cash received and the net book value of the assets sold.Changes in any of our assumptions may alter the rate at which we recognizedepreciation in our consolidated financial statements. At regular intervals, weretain the services of independent consultants to assist us with assessing thereasonableness of the useful lives we have established for the property, plantand equipment of our major systems. Based on the results of these regularassessments we may make modifications to the assumptions we use to determineour depreciation rates.

We evaluate therecoverability of our property, plant and equipment when events orcircumstances such as economic obsolescence, the business climate, legal andother factors indicate we may not recover the carrying amount of the assets. Wecontinually monitor our businesses and the market and business environments toidentify indicators that may suggest an asset may not be recoverable. Weevaluate the asset for recoverability by estimating the undiscounted futurecash flows expected to be derived from operating the asset. These cash flowestimates require us to make projections and assumptions for many years intothe future for pricing, demand, competition, operating cost and other factors.We recognize an 

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impairmentloss when the carrying amount of the asset exceeds its fair value as determinedby quoted market prices in active markets or present value techniques if quotesare unavailable. The determination of the fair value using present valuetechniques requires us to make projections and assumptions regarding theprobability of a range of outcomes and the rates of interest used in thepresent value calculations. Any changes we make to these projections andassumptions could result in significant revisions to our evaluation ofrecoverability of our property, plant and equipment and the recognition of animpairment loss in our Consolidated Statements of Income.

***Assessment of Recoverability of Goodwill andIntangibles***

Goodwill represents the excess of the purchase priceover the fair value of net assets acquired in a business combination. Goodwillis not amortized, but is tested for impairment annually as of the end of thesecond quarter or more frequently if impairment indicators arise that suggestthe carrying value of goodwill may not be recovered. Impairment occurs when thecarrying amount of a reporting unit exceeds its fair value. At the time wedetermine that impairment has occurred, the carrying value of the goodwill iswritten down to its fair value. To estimate the fair value of the reporting units,we make estimates and judgments about future cash flows, as well as revenue,cost of sales, operating expenses, capital expenditures and net working capitalbased on assumptions that are consistent with our most recent five-year plan,which we use to manage the business.

Preparation of forecast information for use in ourfive-year plan involves significant judgments. Actual results can, and oftendo, differ from the projections and assumptions we make in preparing theseforecasts. These changes can have a negative impact on our estimates ofimpairment, which could result in charges to income. In addition, furtherchanges in the economic and business environment can affect our original andongoing assessments of potential impairment.

Other intangible assets consist of natural gaspurchase and sale customer contracts, and natural gas supply opportunities,which we amortize on a straight-line basis over the weighted average usefullife of the underlying assets, which is the period over which the asset is expectedto contribute directly or indirectly to our future cash flows.

We evaluate the carryingvalue of the intangible assets whenever certain events or changes incircumstances indicate that the carrying amount of these assets may not berecoverable. In assessing the recoverability of intangibles, we compare thecarrying value to the undiscounted future cash flows the intangibles areexpected to generate. If the total of the undiscounted future cash flows isless than the carrying amount of the intangibles, the intangibles are writtendown to their fair value. If there are changes to any of our estimates andassumptions, actual results may differ.

***Asset Retirement Obligations***

The provisions of SFAS No. 143, *Accountingfor Asset Retirement Obligations*, require us to record a liabilityfor the fair value of our asset retirement obligations, on a discounted basis,in the period in which the liability is incurred, which is typically at thetime the assets are installed or acquired, if a reasonable estimate of fairvalue can be made. The provisions also require that we capitalize the costsassociated with the asset retirement obligations as part of the carrying costof the related assets. We recognize an ongoing expense for the interestcomponent of the liability as part of depreciation expense resulting fromchanges in the value of the retirement obligation due to the passage of time.We depreciate the initial capitalized costs over the useful lives of therelated assets. We extinguish the liabilities for asset retirement obligationswhen assets are taken out of service or otherwise abandoned.

The provisions of Financial Accounting Standards Board(“FASB”) Interpretation No. 47, *Accounting for ConditionalAsset Retirement Obligations, an interpretation of FASB Statement No. 143*(“FIN 47”) require us to recognize a liability and related asset, consistentwith SFAS No. 143, for the fair value of 

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conditional assetretirement obligations that we can reasonably estimate. FIN 47 alsoprovides specific guidance regarding when an asset retirement obligation isreasonably estimable including when sufficient information is available toapply an expected present value technique. Our implementation of FIN 47 did nothave a material impact effect on our consolidated financial statements.

We have legal obligationsrequiring us to decommission our offshore pipeline systems at retirement. Incertain rate jurisdictions, we are permitted to include annual charges forremoval costs in the regulated cost of service rates we charge our customers.Additionally, legal obligations exist for a minority of our onshoreright-of-way agreements due to requirements or landowner options to compel usto remove the pipe at final abandonment. Sufficient data exists with certainonshore pipeline systems to reasonably estimate an abandonment retirementobligation cost. However, in some cases, there is insufficient information toreasonably determine the timing and/or method of settlement for estimating thefair value of the asset retirement obligation. In these cases, the assetretirement obligation cost is considered indeterminate because there is no dataor information that can be derived from past practice, industry practice,management’s intent, or the asset’s estimated economic life. Useful lives ofmost pipeline systems are primarily derived from available supply resources andultimate consumer/refinery consumption. Variables can affect the remaininglives of the assets which preclude us from making a reasonable estimate of theasset retirement obligation. Indeterminate asset retirement obligation costswill be recognized in the period in which sufficient information exists toreasonably estimate potential settlement dates and methods.

***Derivative Financial Instruments***

Our net income and cash flows are subject tovolatility stemming from changes in interest rates and commodity prices ofnatural gas, NGLs, condensate and fractionation margins. To mitigate thevolatility of our cash flows, we use derivative financial instruments (i.e.,futures, forwards, swaps, options and other financial instruments with similarcharacteristics) to manage the purchase and sales prices of the commodities andfix the interest rate on our variable rate debt.

The accounting treatment for our derivative financialinstruments is determined by the guidance of SFAS No. 133 and is dependenton each instrument’s intended use, how it is designated and the extent to whichthe derivative financial instrument is effective in hedging the risk that it isintended to mitigate. To qualify for hedge accounting, very specificrequirements must be met in terms of hedge structure, hedge objective and hedgedocumentation.

Derivative financial instruments qualifying for hedgeaccounting treatment that we use can be divided into two categories: 1) cashflow hedges, or 2) fair value hedges. Cash flow hedges are entered tohedge the variability in cash flows related to a forecasted transaction. Fairvalue hedges are entered to hedge the value of a recognized asset or liability.Cash flow and fair value hedges are considered highly effective if they areable to substantially offset (i.e., more than 80 percent) the changes in cashflow or fair value of the risk that is being hedged. The extent to which aderivative financial instrument designated as a hedge does not offset thechanges in cash flow or fair value of the risk being hedged is consideredineffective. At inception and on an ongoing basis we assess whether thederivative financial instruments we use in our hedging transactions are highlyeffective in offsetting changes in cash flows or fair values of the hedgeditems.

All of our derivative financial instruments arerecorded in our Consolidated Financial Statements at fair market value as currentand long-term assets or liabilities on a net basis by counterparty and areadjusted each period for changes in the fair market value. The fair marketvalue of these derivative financial instruments reflects the estimated amountsthat we would pay or receive to terminate or close the contracts at the reportingdate, taking into account the current unrealized losses or gains on open 

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contracts. We use externalmarket quotes and indices to value substantially all of the financialinstruments we utilize.

Derivative financial instruments that we designate andqualify as cash flow or fair value hedges under the requirements of SFASNo. 133, receive hedge accounting treatment for the effective portion ofthe derivative financial instrument. Under hedge accounting, any unrealized gain or loss in fair marketvalue of the effective portion of a derivative financial instrument designatedas a cash flow hedge is recorded as an asset or liability with an offset deferred in Accumulated other comprehensive income(“OCI”), a component of Partners’ Capital, until the underlying hedgedtransaction occurs. Realized gains and losses on derivative financialinstruments that are designated as cash flow hedges of forecasted commoditypurchases and sales are included in Cost of natural gas and cash flow hedges offorecasted interest payments are included in Interest on our ConsolidatedStatements of Income in the period the hedged transaction occurs. Underhedge accounting, the realized and unrealized gain or loss in the fair marketvalue of a derivative financial instrument designated as a fair value hedge isrecorded as an asset or a liability with the offset recorded in ourConsolidated Statements of Income as a component of Cost of natural gas forfair value hedges of our commodities and as a component of interest expense forfair value hedges of our indebtedness both of which are offset by the changesin the fair market value of the underlying hedged item.

Under the guidance of SFAS No. 133, the changesin fair market value, both realized and unrealized gains and losses, of derivativefinancial instruments that 1) do not qualifyfor hedge accounting, 2) are not designated as hedges and 3) are ineffective,are recognized each period in our Consolidated Statements of Income. Thesechanges in fair market value are recognized as a component of Cost of naturalgas for our commodity derivative financial instruments and as a component ofinterest expense for derivative financial instruments of our interest rates. We refer to the accounting treatment forderivative financial instruments that do not qualify for hedge accounting asmark-to-market accounting. Our preference, whenever possible, is for ourderivative financial instruments to receive hedge accounting treatment tomitigate the noncash earnings volatility that arises under mark-to-marketaccounting treatment.

Our cash flow is only affected to the extent theactual derivative contract is settled by 1) making or receiving a paymentto/from the counterparty; or 2) by making or receiving a payment for enteringinto a contract that exactly offsets the original derivative contract.Typically, a derivative contract is settled when the physical transaction thatunderlies the derivative financial instrument occurs.

Gains and losses that we have deferred in OCI relatedto cash flow hedges for which hedge accounting has been discontinued, remain inOCI until the underlying physical transaction occurs unless it is probable thatthe forecasted transaction will not occur by the end of the originallyspecified time period or within an additional two-month period of timethereafter.

One of the primary factorsthat can affect our operating results each period is the price assumptions weuse to value our derivative financial instruments. To the extent that thesederivative financial instruments are ineffective or do not qualify for hedgeaccounting treatment under the requirements of SFAS No. 133, they areaccounted for using the mark-to-market method of accounting and any change inthe fair market value is reflected in our Consolidated Statements of Income asa component of Cost of natural gas or Interest expense, depending on whetherthe derivative financial instrument relates to a commodity or interest rate. Weuse published market price information where available, or quotations from OTCmarket makers to find executable bids and offers. The valuations also reflectthe potential impact of liquidating our position in an orderly manner over areasonable period of time under present market conditions, modeling risk,credit risk of our counterparties and operational risk. The amounts we reportin our consolidated financial statements change quarterly as these estimatesare revised to reflect actual results, changes in market conditions or otherfactors, many of which are beyond our control.

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***Commitments, Contingencies and EnvironmentalLiabilities***

We accrue reserves for contingent liabilities,including environmental remediation and clean-up costs, when our assessmentsindicate that it is probable that a liability has been incurred and an amountcan be reasonably estimated. Estimates of the liabilities are based oncurrently available facts, existing technology and presently enacted laws andregulations taking into consideration the likely effects of inflation and otherfactors, and include estimates of associated legal costs. These estimates alsoconsider prior experience remediating contaminated sites, other companies’clean-up experience and data released by government organizations. Ourestimates are subject to revision in future periods based on actual costs ornew circumstances and any revisions are reflected in our earnings in the periodin which they are reasonably determinable. We evaluate recoveries frominsurance coverage separately from our liability and, when recovery isreasonably assured, we record and report an asset separately from theassociated liability in our financial statements. New environmentaldevelopments, such as increasingly strict environmental laws and regulationsand new claims for damages to property, employees, other persons and theenvironment resulting from our current or past operations, could result insubstantial cost and future liabilities.

We recognize liabilitiesfor other contingencies when we have an exposure that, when fully analyzed,indicates it is both probable that an asset has been impaired or that aliability has been incurred and the amount of impairment or loss can bereasonably estimated. Both internal and external legal counsel evaluate ourpotential exposure to adverse outcomes. When a range of probable loss can beestimated, we accrue the most likely amount, or at least the minimum of therange of probable loss. To the extent that actual outcomes differ from ourestimates, or additional facts and circumstances cause us to review ourestimates, income may be affected.

***Oil Over/Short Balance and Oil MeasurementGains/Losses***

Oil over/short balance andoil measurement gains/losses are inherent in the transportation of crude oildue to evaporation, measurement differences and blending of commodities intransit in addition to other factors. We estimate our oil measurementgains/losses and our oil over/short balance based on mathematical calculationsand physical measurements, which include assumptions about the type of crudeoil, its market value, normal physical losses due to evaporation and capacitylimitations of the system. A material change in these assumptions may result ina change to the carrying value of our oil over/short balance or revision of ouroil measurement gain/loss estimates. We include the oil measurementgains/losses in our operating and administrative expenses on our ConsolidatedStatements of Income and the oil over/short balance in Accounts payable andother in the Consolidated Statements of Financial Position if the balance is aliability and in Inventory if the balance is in an asset position.

***Operational Balancing Agreements and Natural GasImbalances***

We record payables andreceivables associated with our natural gas pipeline operational balancingagreements and natural gas imbalances monthly when a customer delivers more orless natural gas into our pipelines than they remove. These balances are eithersettled on a cash basis or are carried by the pipelines and shippers on anin-kind basis. We primarily estimate the value of the imbalances at month-endspot prices based on published third-party indices for the locations where theimbalances are derived using the best available third party and internal volumeinformation.  If there is a change tothese estimates and assumptions, actual results may differ.

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**RECENT ACCOUNTING DEVELOPMENTS**

***Accounting Changes and Error Corrections***

In May 2005, the FASBissued Statement of Financial Accounting Standards No. 154, *Accounting Changes and Error Corrections, a replacement of APB OpinionNo. 20 and FASB Statement No. 3*. Under this statement,voluntary changes in accounting principle are required to be applied retrospectivelyfor the direct effects of a change to prior periods’ financial statements,unless such application is impracticable. Retrospective application refers toreflecting a change in accounting principle in the financial statements ofprior periods as if the principle had always been used. When retrospectiveapplication is determined to be impracticable, this statement requires the newaccounting principle be applied to the balances of assets and liabilities as ofthe beginning of the earliest period for which retrospective treatment ispracticable with a corresponding adjustment to the opening balance of retainedearnings. This statement retains the guidance in APB Opinion No. 20 forreporting the corrections of errors and changes in accounting estimates. Thisstatement is effective for accounting changes and corrections of errors made infiscal years beginning after December 15, 2005, with early adoptionpermitted. Our adoption of this statement will affect our consolidatedfinancial statements for any changes in accounting principle we may make in thefuture, and new pronouncements we adopt that do not provide transitionprovisions.

***FERC Guidance on Accounting for Integrity ManagementCosts***

In June 2005, theFERC issued guidance describing how FERC-regulated companies should account forcosts associated with implementing the pipeline integrity managementrequirements of the U.S. Department of Transportation’s Office of PipelineSafety. Under the guidance, costs to 1) prepare a plan to implement the program,2) identify high consequence areas, 3) develop and maintain a recordkeeping system and 4) inspect, test and report on the condition of affectedpipeline segments to determine the need for repairs or replacements, arerequired to be expensed. Costs of modifying pipelines to permit in-lineinspections, certain costs associated with developing or enhancing computersoftware and costs associated with remedial and mitigation actions to correctan identified condition can be capitalized. The guidance is effectiveJanuary 1, 2006, and will be applied prospectively to our SFAS No. 71companies. We do not expect our implementation of this regulation tosignificantly affect our financial position, results of operations or cashflows.

**Item 7A. Quantitative and Qualitative DisclosuresAbout Market Risk**

**INTEREST RATE RISK**

We utilize both fixed and variable interest rate debt,and are exposed to market risk resulting from the variable interest rates onour Credit Facility and the frequent changes in interest rates when we re-issuematuring commercial paper. To the extent that we frequently issue and re-issuecommercial paper at short-term interest rates and have amounts drawn under ourcredit facilities at floating rates of interest, our earnings and cash flowsare exposed to changes in interest rates. This exposure is managed throughperiodically refinancing commercial paper and floating-rate bank debt withlong-term fixed rate debt and through the use of interest rate derivativefinancial instruments including futures, forwards, swaps, options and otherfinancial instruments with similar characteristics. We do not have any materialexposure to movements in foreign exchange rates as virtually all of ourrevenues and expenses are denominated in U.S. dollars. To the extent that amaterial foreign exchange exposure arises, we intend to hedge such exposureusing derivative financial instruments .

Thetable below summarizes the carrying value and fair value of our third-party debtobligations and interest rate derivative financial instruments as ofDecember 31, 2005 and 2004. For debt obligations, the table presentsprincipal cash flows and related weighted average interest rates by expectedmaturity dates. For interest rate swaps, the table presents notional amounts, therates charged on the underlying notional 

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and weighted average interest rates paid by expected maturitydates. Notional amounts are used to calculate the contractual payments to beexchanged under the contract. Within this table positive balances representliabilities and bracketed amounts represent assets.

| ** **            | ** ** | **December 31, 2005** | ** ** | ** **                                                                                  | ** ** | ** **                      | ** ** |
|-----------------------|------------|---------------------------------|------------|---------------------------------------------------------------------------------------------|------------|---------------------------------|------------|
| ** **            | ** ** | **Average**                     | ** ** | **Expected Fiscal Year of Maturity of Carrying Amounts** | ** ** | **December 31, 2004** | ** ** |
| ** **            | ** ** | **Interest  Rate**              | ** ** | **2006**                                                                                    | ** ** | **2007**                        | ** ** | **2008** | ** ** | **2009** | ** ** | **2010** | ** ** | **Thereafter** | ** ** | **Total** | ** ** | **Fair  Value** | ** ** | **Carrying  Amount** | ** ** | **Fair  Value** | ** ** |
| ** **            | ** ** | ** **                      | ** ** | **(dollars in millions)**                                                         | ** ** |
| **Liabilities**       |       |                            |       |                                                                                        |       |                            |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| *Fixed  Rate:*        |       |                            |       |                                                                                        |       |                            |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| First Mortgage Notes  |       | 9.15                            | %          | $                                                                                           | 31.0       |                            | $          | 31.0 |   | $ | 31.0 |   | $ | 31.0 |   | $ | 31.0 |   |   | $ | 31.0 |   |   | $ | 186.0 |   | $ | 207.9 |   | $ | 217.0 |   | $ | 256.8 |   |
| Senior notes due 2009 |       | 4.00                            | %          | —                                                                                      |       | —                          |       | — |   | 199.9 |   | — |   |   | — |   |   | 199.9 |   | 193.0 |   | 199.9 |   | 199.2 |   |
| Senior notes due 2012 |       | 7.90                            | %          | —                                                                                      |       | —                          |       | — |   | — |   | — |   |   | 99.9 |   |   | 99.9 |   | 113.8 |   | 99.9 |   | 120.1 |   |
| Senior notes due 2013 |       | 4.75                            | %          | —                                                                                      |       | —                          |       | — |   | — |   | — |   |   | 199.8 |   |   | 199.8 |   | 190.8 |   | 199.7 |   | 197.1 |   |
| Senior notes due 2014 |       | 5.35                            | %          | —                                                                                      |       | —                          |       | — |   | — |   | — |   |   | 199.9 |   |   | 199.9 |   | 196.7 |   | 199.9 |   | 203.2 |   |
| Senior notes due 2018 |       | 7.00                            | %          | —                                                                                      |       | —                          |       | — |   | — |   | — |   |   | 99.8 |   |   | 99.8 |   | 111.4 |   | 99.8 |   | 117.4 |   |
| Senior notes due 2028 |       | 7.125                           | %          | —                                                                                      |       | —                          |       | — |   | — |   | — |   |   | 99.8 |   |   | 99.8 |   | 113.0 |   | 99.8 |   | 119.3 |   |
| Senior notes due 2033 |       | 5.95                            | %          | —                                                                                      |       | —                          |       | — |   | — |   | — |   |   | 199.7 |   |   | 199.7 |   | 193.1 |   | 199.7 |   | 200.3 |   |
| Senior notes due 2034 |       | 6.30                            | %          | —                                                                                      |       | —                          |       | — |   | — |   | — |   |   | 99.8 |   |   | 99.8 |   | 100.8 |   | 99.7 |   | 104.1 |   |
| *Variable Rate:*      |       |                            |       |                                                                                        |       |                            |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Commercial paper      |       | 4.36                            | %          | —                                                                                      |       | —                          |       | — |   | — |   | 329.3 |   |   | — |   |   | 329.3 |   | 329.3 |   | — |   | — |   |
| Credit Facility       |       | n/a                             |       | —                                                                                      |       | —                          |       | — |   | — |   | — |   |   | — |   |   | — |   | — |   | 175.0 |   | 175.0 |   |
|                       |            |                                 |            |                                                                                             |            |                                 |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

| ** **                   | ** ** | **December 31, 2005** | ** ** | ** **                                                                                  | ** ** | ** ** | ** ** |
|------------------------------|------------|---------------------------------|------------|---------------------------------------------------------------------------------------------|------------|------------|------------|
| ** **                   | ** ** | ** **                      | ** ** | **Expected Fiscal Year of Maturity of Notional Amounts** | ** ** | ** ** | ** ** |
| ** **                   | ** ** | **Average**                     | ** ** | ** **                                                                                  | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | **Total** | ** ** | ** ** | ** ** | **December 31, 2004** | ** ** |
| ** **                   | ** ** | **Interest  Rate**              | ** ** | **2006**                                                                                    | ** ** | **2007**   | ** ** | **2008** | ** ** | **2009** | ** ** | **2010** | ** ** | **Thereafter** | ** ** | **Notional  Amount** | ** ** | **Fair  Value** | ** ** | **Notional  Amount** | ** ** | **Fair  Value** | ** ** |
| *Interest  Rate Derivatives* |       |                            |       |                                                                                        |       |       |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Interest Rate  Swaps:        |       |                            |       |                                                                                        |       |       |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Variable to Fixed            |       | LIBOR                           |       | 150.0                                                                                       |       | —     |       | — |   | — |   | — |   |   | 125.0 |   |   | 275.0 |   | (3.0 | ) | 125.0 |   | 0.9 |   |
| Average Pay Rate             |       | 3.72                            | %          | 3.20                                                                                        | %          | —     |       | — |   | — |   | — |   |   | 4.34 | % |   | 3.72 | % | — |   | 4.35 | % |   |   |
| Fixed to Variable            |       | 4.75                            | %          | —                                                                                      |       | —     |       | — |   | — |   | — |   |   | 125.0 |   |   | 125.0 |   | (0.6 | ) | 125.0 |   | (4.6 | ) |
| Average Pay Rate             |       | LIBOR-0.21                      | %          | —                                                                                      |       | —     |       | — |   | — |   | — |   |   | LIBOR-0.21 | % |   | LIBOR-0.21 | % | — |   | LIBOR-0.21 | % | — |   |

 

Our floating to fixed rateinterest rate swaps maturing in 2006 qualify for and have been designated cashflow hedges of interest payments on $150 million of our variable rateindebtedness and therefore, the changes in fair value of these derivatives arerecorded as an increase or decrease in Accumulated other comprehensive income.The floating to fixed rate and fixed to floating rate interest rate swapsmaturing in 2013 do not qualify as cash flow or fair value hedges and as aresult, changes in the fair value of these derivative financial instruments arerecorded in earnings as an increase or decrease in interest expense.

**COMMODITY PRICERISK**

Our net income and cash flows are also subject tovolatility stemming from changes in commodity prices of natural gas, NGLs,condensate and fractionation margins (the relative price differential betweenNGL sales and offsetting natural gas purchases). This market price exposureexists within our Natural Gas and Marketing segments. To mitigate thevolatility of our cash flows, we use derivative financial instruments (i.e.,futures, forwards, swaps, options and other financial instruments with similarcharacteristics) to manage the purchase and sales prices of the commodities.Based on our risk management policies, all of our derivative financialinstruments are employed in connection with an underlying asset, liabilityand/or anticipated transaction and are not entered into with the objective ofspeculating on commodity prices.

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Thefollowing tables provide information about our derivative financial instrumentsat December 31, 2005 and December 31, 2004, with respect to ourcommodity price risk management activities for natural gas and NGLs, includingcondensate:

| ** **                           | ** ** | **At December 31, 2005** | ** ** | **At December 31,   2004** | ** ** |
|--------------------------------------|------------|-----------------------------------------|------------|--------------------------------------|------------|
| ** **                           | ** ** | ** **                              | ** ** | ** **                           | ** ** | **Wtd Avg Price**(2) | ** ** | **Fair Value**(3) | ** ** | **Fair Value**(3) | ** ** |
| ** **                           | ** ** | **Commodity**                           | ** ** | **Volumes**(1)                       | ** ** | **Receive** | ** ** | **Pay** | ** ** | **Asset** | ** ** | **Liability** | ** ** | **Asset** | ** ** | **Liability** | ** ** |
| ***Contracts  maturing in 2006***    |       |                                    |       |                                 |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| *Swaps*                              |       |                                    |       |                                 |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Receive variable /pay fixed     |       | Natural  Gas                            |       | 145,258,496                          |       |   | $ | 9.78 |   |   | $ | 7.19 |   | $ | 380.6 |   |   | $ | (11.7 | ) |   |   | $ | 4.2 |   |   |   | $ | (7.8 | ) |   |
| Receive fixed /pay variable     |       | Natural  Gas                            |       | 152,649,441                          |       |   | 7.17 |   |   | 10.20 |   | 14.5 |   |   | (467.8 | ) |   |   | 7.8 |   |   |   | (23.3 | ) |   |
|                                 |       | NGL                                     |       | 2,702,460                            |       |   | 29.08 |   |   | 40.35 |   | — |   |   | (29.7 | ) |   |   | 0.5 |   |   |   | (4.1 | ) |   |
|                                 |       | Crude                                   |       | 417,725                              |       |   | 44.58 |   |   | 63.15 |   | 0.2 |   |   | (7.8 | ) |   |   | 0.4 |   |   |   | (1.4 | ) |   |
| Receive variable /pay variable       |       | Natural  Gas                            |       | 14,482,911                           |       |   | 9.70 |   |   | 9.70 |   | 5.2 |   |   | (5.2 | ) |   |   | — |   |   |   | (0.2 | ) |   |
| *Options*                            |       |                                    |       |                                 |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Calls (written)                      |       | Natural  Gas                            |       | 365,000                              |       |   | 10.78 |   |   | 4.31 |   | — |   |   | (2.0 | ) |   |   | — |   |   |   | (1.8 | ) |   |
| ***Contracts  maturing in 2007***    |       |                                    |       |                                 |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| *Swaps*                              |       |                                    |       |                                 |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Receive variable /pay fixed     |       | Natural  Gas                            |       | 53,882,446                           |       |   | 9.68 |   |   | 7.48 |   | 112.0 |   |   | (1.0 | ) |   |   | 0.6 |   |   |   | (8.2 | ) |   |
| Receive fixed /pay variable     |       | Natural  Gas                            |       | 60,540,090                           |       |   | 7.23 |   |   | 10.22 |   | 0.5 |   |   | (170.0 | ) |   |   | 8.5 |   |   |   | (15.8 | ) |   |
|                                 |       | NGL                                     |       | 2,698,810                            |       |   | 28.03 |   |   | 36.99 |   | — |   |   | (22.5 | ) |   |   | 0.4 |   |   |   | (4.0 | ) |   |
|                                 |       | Crude                                   |       | 388,680                              |       |   | 42.05 |   |   | 63.99 |   | — |   |   | (7.9 | ) |   |   | 0.2 |   |   |   | (1.3 | ) |   |
| Receive variable /pay variable       |       | Natural  Gas                            |       | 3,579,170                            |       |   | 9.97 |   |   | 9.79 |   | 0.7 |   |   | (0.1 | ) |   |   | — |   |   |   | — |   |   |
| *Options*                            |       |                                    |       |                                 |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Calls (written)                      |       | Natural  Gas                            |       | 365,000                              |       |   | 10.25 |   |   | 4.31 |   | — |   |   | (2.0 | ) |   |   | — |   |   |   | (1.5 | ) |   |
| Puts                                 |       | Natural  Gas                            |       | 365,000                              |       |   | 10.25 |   |   | 3.40 |   | — |   |   | — |   |   |   | — |   |   |   | — |   |   |
| ***Contracts  maturing in 2008***    |       |                                    |       |                                 |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| *Swaps*                              |       |                                    |       |                                 |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Receive variable /pay fixed     |       | Natural  Gas                            |       | 10,236,065                           |       |   | 9.23 |   |   | 7.23 |   | 18.5 |   |   | — |   |   |   | — |   |   |   | (1.9 | ) |   |
| Receive fixed /pay variable     |       | Natural  Gas                            |       | 21,922,508                           |       |   | 6.17 |   |   | 9.56 |   | — |   |   | (66.3 | ) |   |   | 2.3 |   |   |   | (12.2 | ) |   |
|                                 |       | NGL                                     |       | 729,438                              |       |   | 25.59 |   |   | 36.78 |   | — |   |   | (7.2 | ) |   |   | 0.7 |   |   |   | (0.2 | ) |   |
|                                 |       | Crude                                   |       | 323,699                              |       |   | 44.18 |   |   | 62.29 |   | — |   |   | (5.2 | ) |   |   | 0.5 |   |   |   | — |   |   |
| Receive variable /pay variable       |       | Natural  Gas                            |       | 3,294,000                            |       |   | 8.95 |   |   | 8.59 |   | 1.0 |   |   | — |   |   |   | — |   |   |   | — |   |   |
| *Options*                            |       |                                    |       |                                 |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Calls (written)                      |       | Natural  Gas                            |       | 366,000                              |       |   | 9.37 |   |   | 4.31 |   | — |   |   | (1.7 | ) |   |   | — |   |   |   | (1.2 | ) |   |
| Puts                                 |       | Natural  Gas                            |       | 366,000                              |       |   | 9.37 |   |   | 3.40 |   | — |   |   | — |   |   |   | 0.1 |   |   |   | — |   |   |
| ***Contracts  maturing in 2009***    |       |                                    |       |                                 |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| *Swaps*                              |       |                                    |       |                                 |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Receive fixed /pay variable     |       | Natural  Gas                            |       | 11,497,500                           |       |   | 5.02 |   |   | 8.55 |   | — |   |   | (34.5 | ) |   |   | — |   |   |   | (9.8 | ) |   |
|                                 |       | NGL                                     |       | 494,575                              |       |   | 32.83 |   |   | 34.24 |   | — |   |   | (0.6 | ) |   |   | — |   |   |   | — |   |   |
|                                 |       | Crude                                   |       | 155,125                              |       |   | 53.13 |   |   | 61.01 |   | — |   |   | (1.0 | ) |   |   | — |   |   |   | — |   |   |
| Receive variable /pay variable       |       | Natural  Gas                            |       | 4.197,500                            |       |   | 8.13 |   |   | 7.83 |   | 1.1 |   |   | — |   |   |   | — |   |   |   | — |   |   |
| *Options*                            |       |                                    |       |                                 |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Calls (written)                      |       | Natural  Gas                            |       | 365,000                              |       |   | 8.55 |   |   | 4.31 |   | — |   |   | (1.4 | ) |   |   | — |   |   |   | (1.1 | ) |   |
| Puts                                 |       | Natural  Gas                            |       | 365,000                              |       |   | 8.55 |   |   | 3.40 |   | — |   |   | — |   |   |   | 0.2 |   |   |   | — |   |   |
| ***Contracts  maturing in 2010***    |       |                                    |       |                                 |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| *Swaps*                              |       |                                    |       |                                 |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Receive fixed /pay variable     |       | Natural  Gas                            |       | 8,760,000                            |       |   | 4.15 |   |   | 7.80 |   | 0.1 |   |   | (25.9 | ) |   |   | — |   |   |   | (8.2 | ) |   |
|                                 |       | NGL                                     |       | 317,550                              |       |   | 30.60 |   |   | 31.96 |   | — |   |   | (0.4 | ) |   |   | — |   |   |   | — |   |   |
|                                 |       | Crude                                   |       | 91,250                               |       |   | 59.00 |   |   | 59.68 |   | — |   |   | (0.1 | ) |   |   | — |   |   |   | — |   |   |
| *Options*                            |       |                                    |       |                                 |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Calls (written)                      |       | Natural  Gas                            |       | 365,000                              |       |   | 7.91 |   |   | 4.31 |   | — |   |   | (1.1 | ) |   |   | — |   |   |   | (0.9 | ) |   |
| Puts                                 |       | Natural  Gas                            |       | 365,000                              |       |   | 7.91 |   |   | 3.40 |   | — |   |   | — |   |   |   | 0.2 |   |   |   | — |   |   |
| ***Contracts  maturing after 2010*** |       |                                    |       |                                 |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| *Swaps*                              |       |                                    |       |                                 |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Receive fixed /pay  variable    |       | Natural Gas                             |       | 8,496,500                            |       |   | 3.62 |   |   | 7.64 |   | — |   |   | (26.1 | ) |   |   | — |   |   |   | (10.1 | ) |   |
|                                      |            |                                         |            |                                      |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

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| *Options*       |   |        |   |    |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
|-----------------|--------|-------------|--------|---------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|
| Calls (written) |   | Natural Gas |   | 365,000 |   |   | 7.46   |   |   | 4.31   |   | — |   |   | (0.9   | )      |   |   | — |   |   |   | (0.9   | )      |   |
| Puts            |   | Natural Gas |   | 365,000 |   |   | 7.46   |   |   | 3.40   |   | — |   |   | — |   |   |   | $      | 0.2    |   |   |   | — |   |   |
|                 |        |             |        |         |        |        |        |        |        |        |        |        |        |        |        |        |        |        |        |        |        |        |        |        |        |  |

 

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(1)                 Volumes of Natural gas are measured inMMBtu, whereas volumes of NGL and Crude are measured in Bbl.

(2)                 Weighted average prices received and paidare in $/MMBtu for Natural gas and in $/Bbl for NGL and Crude.

(3)                 The fair value is determined based onquoted market prices at December 31, 2005 and December 31, 2004,respectively, discounted using the swap rate for the respective periods toconsider the time value of money. Fair values are presented in millions ofdollars.

***AccountingTreatment***

All derivative financial instruments are recorded inour consolidated financial statements at fair market value and are adjustedeach period for changes in the fair market value (“mark-to-market”).The fair market value of these derivative financial instruments reflects theestimated amounts that we would pay or receive to terminate or close thecontracts at the reporting date, taking into account the current unrealizedlosses or gains on open contracts. We use external market quotes and indices tovalue substantially all of the financial instruments we utilize.

Under the guidance of Statement of FinancialAccounting Standards No. 133, *Accountingfor Derivative Transactions and Hedging Activities* (“SFAS No. 133”),if a derivative financial instrument does not qualify as a hedge or is notdesignated as a hedge, a change in the fair market value, both realized andunrealized, is recognized currently in our income statement as a derivativefair value gain (loss) and is recorded in Cost of natural gas for commodityderivatives and interest expense for interest rate derivatives. Cash flow isonly impacted to the extent the actual derivative contract is settled by makingor receiving a payment to/from the counterparty or by making or receiving a paymentfor entering into a contract that exactly offsets the original derivativecontract. Typically, a derivative contract is settled when the future physicaltransaction that underlies the derivative financial instrument occurs (e.g.,purchase or sale of natural gas or interest payment).

If a derivative financial instrument is designated asa cash flow hedge and qualifies for hedge accounting, a change in the fairmarket value is deferred in Accumulated other comprehensive income (“OCI”), acomponent of Partners’ Capital, until the underlying hedged transaction occurs.Any ineffective portion of a cash flow hedge’s change in fair market value isrecognized each period in earnings. Realized gains and losses on derivativefinancial instruments that are designated as cash flow hedges and qualify forhedge accounting are included in Cost of natural gas in the period the hedgedtransaction occurs. Gains and losses deferred in OCI related to cash flowhedges for which hedge accounting has been discontinued, remain in OCI untilthe underlying physical transaction occurs unless it is probable that theforecasted transaction will not occur by the end of the originally specifiedtime period or within an additional two-month period of time thereafter. Ourpreference, whenever possible, is for our derivative financial instruments toreceive hedge accounting treatment to mitigate the noncash earnings volatilitythat arises under mark-to-market accounting treatment. To qualifyfor cash flow hedge accounting, very specific requirements must be met in termsof hedge structure, hedge objective and hedge documentation.

If a derivative financialinstrument is designated and qualifies as a fair value hedge of the change infair market value of an underlying asset or liability, the gain (loss)resulting from the change in fair market value of the derivative financialinstrument is recorded in earnings adjusted by the gain (loss) resulting fromthe change in fair market value of the underlying asset or liability. Anyineffective portion of a fair value hedge’s change in fair market value will berecorded in earnings as the amount that is not offset by 

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the gain(loss) on the change in fair market value of the underlying asset or liability.We include the gains and losses associated with derivative financialinstruments designated and qualifying as fair value hedges of our debtobligations in interest expense. Similar to derivative financial instrumentsdesignated as cash flow hedges, very specific requirements must be met in termsof hedge structure, hedge objective and hedge documentation.

***Non-Qualified Hedges***

Many of our derivative financial instruments qualifyfor hedge accounting treatment under the specific requirements of SFAS No. 133.However, we have three primary instances where the hedge structure does notmeet the requirements to apply hedge accounting and, therefore, these financialinstruments are considered ‘non-qualified’ under SFAS No. 133. Thesenon-qualified derivative financial instruments must be adjusted to their fairmarket value, or marked-to-market, each period, with the increasesand decreases in fair value recorded as increases and decreases in Cost ofnatural gas in our Consolidated Statements of Income. These mark-to-marketadjustments produce a degree of earnings volatility that can often besignificant from period to period, but have no cash flow impact relative tochanges in market prices. The cash flow impact occurs when the underlyingphysical transaction takes place in the future and an associated financialinstrument contract settlement is made.

The three instances of non-qualified hedges are asfollows:

1.                **Transportation**—In our Marketing segment, when the pricingindex used for gas sales is different from the pricing index used for gaspurchases, we are exposed to relative changes in those two indices. By enteringinto a basis swap between those two indices, we can effectively lock in themargin on the combined gas purchase and gas sale, removing any market pricerisk on the physical transactions. Although this represents a sound economichedging strategy, these types of derivative transactions do not qualify forhedge accounting under SFAS No. 133, as the ultimate cash flow has notbeen fixed, only the margin.

2.                **Storage**—In our Marketing segment, when we use derivativefinancial instruments to hedge market spreads around our owned or contractedassets, such as our gas storage portfolio, the underlying forecastedtransaction may or may not occur in the same period as originally forecast.This can occur because we have the flexibility to make these changes in theunderlying injection or withdrawal schedule, given changes in marketconditions. Therefore, these transactions do not qualify for hedge accountingtreatment under SFAS No. 133, as the forecasted transaction is no longerprobable of occurring as originally set forth in the hedge documentationestablished at the inception of the hedge.

3.                **Natural Gas Collars**—In our Natural Gas segment, we hadpreviously entered into natural gas collars to hedge the sales price of naturalgas. The natural gas collars were based on a NYMEX price, while the physicalgas sales were based on a different index. To better align the index of thenatural gas collars with the index of the underlying sales, we de-designatedthe original hedging relationship with the intent of contemporaneously re-designatingthe natural gas collars as hedges of physical natural gas sales with a NYMEXpricing index to better match the indices, which was a sound economic hedgingstrategy. However, because the fair value of these derivative instruments was aliability to us at re-designation, they are considered net writtenoptions under SFAS No. 133 and do not qualify for hedge accounting. Thesederivatives are now accounted for in the Consolidated Statements of Incomethrough mark-to-market accounting, with the changes in fair valuefrom the date of de-designation recorded to earnings each period. As aresult, our operating income will be subject to greater volatility due tomovements in the prices of natural gas until the underlying long-termtransactions are settled.

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In each of the instancesdescribed above, the underlying physical purchase, storage and sale of naturalgas and NGLs are accounted for on a historical cost basis rather than on themark-to-market basis we utilize for the derivatives used to mitigate thecommodity price risk associated with our storage and transportation assets. Thisdifference in accounting (i.e., thefinancial side of the transaction is recorded at fair market values while thephysical side of the transaction is not) can and has resulted involatility in our reported net income, even though the economic margin isessentially unchanged from the date the transactions were consummated.

***Discontinuance of Hedge Accounting***

During the second quarter of 2005, we discontinuedapplication of hedge accounting in connection with some of our derivativefinancial instruments designated as hedges of forecasted sales and purchases ofnatural gas. We discontinued application of hedge accounting when we determinedit was no longer probable that the originally forecasted purchases and sales ofnatural gas would occur by the end of the originally specified time period, orwithin an additional two-month period of time thereafter. As discussed above,this can occur because we have the flexibility to make changes to theunderlying delivery points for our transportation assets and to the underlyinginjection or withdrawal schedule for our storage assets, given changes inmarket conditions. One of the key criteria to achieve hedge accounting underSFAS No. 133 is that the forecasted transaction be probable of occurringas originally set forth in the hedge documentation. As a result, during thesecond quarter of 2005, we recognized previously deferred unrealized losses inour Marketing segment of approximately $9.0 million from the discontinuance ofhedge accounting. In doing so, we reclassified the $9.0 million to Cost ofnatural gas on our Consolidated Statements of Income from OCI. Going forward,the discontinued derivative financial instruments are considered to benon-qualified under SFAS No. 133, and must be marked-to-marketeach period, with the increases and decreases in fair value recorded asincreases and decreases in earnings. Also included in the loss fromdiscontinuance are approximately $2.1 million of net mark-to-market losses thatrelate to hedge positions that were closed out during the second quarter.

Thefollowing table presents the unrealized losses associated with changes in thefair value of our derivatives, which are recorded as an element of Cost ofnatural gas in our Consolidated Statements of Income and disclosed as areconciling item on our Statements of Cash Flows:

| **Derivative fair value losses** | ** ** | ** **             | ** ** | **December 31,  2005** | ** ** | **December 31,  2004** | ** ** | **December 31,  2003** | ** ** |
|-------------------------------------------------|------------|------------------------|------------|-----------------------------|------------|-----------------------------|------------|-----------------------------|------------|
| ** **                                      | ** ** | **(in millions)** | ** ** |
| Natural Gas  segment                            |       |                   |       |                        |       |                        |       |                        |       |   |   |   |   |
| Ineffectiveness                                 |       |                   | $          | 2.5                         |       |                        |       | $                           | 1.1        |   |   |   | $ | — |   |   |
| Non-qualified hedges                            |       |                   | 5.6        |                        |       |                        | —     |                        |       |   | — |   |   |
| Marketing                                       |       |                   |       |                        |       |                        |       |                        |       |   |   |   |   |
| Non-qualified hedges                            |       |                   | 41.3       |                        |       |                        | 2.1        |                        |       |   | 0.3 |   |   |
| Discontinuance                                  |       |                   | 9.0        |                        |       |                        | —     |                        |       |   | — |   |   |
| Derivative fair value losses                    |       |                   | $          | 58.4                        |       |                        |       | $                           | 3.2        |   |   |   | $ | 0.3 |   |   |

 

***De-designation and Settlement of Derivatives***

In connection with the sale of assets, as discussed inNote 3 to the Consolidated Financial Statements, we settled for cash ofapproximately $16.3 million, natural gas collars representing derivativefinancial instruments on sales of 2,000 MMBtu/d of natural gas through 2011. Wehad previously recorded unrealized losses associated with these natural gascollars that were realized upon settlement. Additionally, we de-designatedderivative financial instruments that were qualified for and designated as cashflow hedges of forecasted sales of 273 Bbl/d of NGLs through 2007 andcontemporaneously closed out the 

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position by entering intoan offsetting derivative financial instrument, at market, on forecastedpurchases of 273 Bbl/d of NGLs through 2007.

Ourderivative financial instruments are included at their fair values in theConsolidated Statements of Financial Position as follows:

| ** **                    | ** ** | **December 31,  2005** | ** ** | **December 31,  2004** | ** ** |
|-------------------------------|------------|-----------------------------|------------|-----------------------------|------------|
| ** **                    | ** ** | **(in millions)**      | ** ** |
| Receivables,  trade and other |       |                        | $          | 5.8                         |       |   |   | $ | 8.2 |   |   |
| Other assets, net             |       |                        | 4.2        |                        |       |   | 10.1 |   |   |
| Accounts payable  and other   |       |                        | (129.2     | )                           |       |   | (45.9 | ) |   |
| Other long-term  liabilities  |       |                        | (243.0     | )                           |       |   | (99.6 | ) |   |
|                          |       |                        | $          | (362.2                      | )          |   |   | $ | (127.2 | ) |   |

 

The increase in our obligation associated with ourderivative activities from December 31, 2004 to December 31, 2005 isprimarily due to the significant increases in forward natural gas and NGL prices.The Partnership’s portfolio of derivative financial instruments is largelycomprised of long-term fixed price sales and purchase agreements.

We record the change in fair value of our highlyeffective cash flow hedges in our OCI until the derivative financialinstruments are settled, at which time they are reclassified to earnings. Alsoincluded in OCI are unrecognized losses of approximately $8.0 millionassociated with derivative financial instruments that qualified for and wereclassified as cash flow hedges of forecasted transactions that weresubsequently de-designated. These unrealized losses are reclassified toearnings over the periods during which the originally hedged forecastedtransactions affect earnings. For the twelve months ended December 31,2005, and 2004 we reclassified unrealized losses of $33.8 million and $12.6million from OCI to Cost of natural gas on our Consolidated Statements ofIncome for the fair value of derivative financial instruments that were settled. We estimate that approximately $83.7million of OCI representing unrealized net losses on cash flow hedgingactivities at December 31, 2005, will be reclassified to earnings duringthe next twelve months.

We do not requirecollateral or other security from the counterparties to our derivativefinancial instruments, all of which were rated “BBB+” or better by the majorcredit rating agencies.

**Item 8. Financial Statements and Supplementary Data**

Our consolidated financialstatements, together with the notes thereto and the independent registeredpublic accounting firm’s report thereon, and unaudited supplementaryinformation, appear beginning on page F-2 of this report, and areincorporated by reference. Reference should be made to the “Index to FinancialStatements, Supplementary Information and Financial Statement Schedules” on page F-1of this report.

**Item 9. Changes in and Disagreements with Accountantson Accounting and Financial Disclosure**

None.

**Item9A. Controls and Procedures**

**DISCLOSURECONTROLS AND PROCEDURES**

The Partnership and Enbridge maintain systems ofdisclosure controls and procedures designed to provide reasonable assurancethat we are able to record, process, summarize and report the informationrequired in our annual and quarterly reports under the Securities Exchange Actof 1934. Management of 

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the Partnership hasevaluated the effectiveness of our disclosure controls and procedures as of December 31,2005. Based upon that evaluation, our principal executive officer and principalfinancial officer concluded that our disclosure controls and procedures areeffective to accomplish their purpose. In conducting this assessment,management of the Partnership relied on similar evaluations conducted byemployees of Enbridge affiliates who provide certain treasury, accounting andother services on our behalf. No changes in our internal control over financialreporting were made during the three months ended December 31, 2005, thatwould materially affect our internal control over financial reporting.

**INTERNALCONTROL OVER FINANCIAL REPORTING**

***Management’s Report on Internal Control OverFinancial Reporting***

Management of EnbridgeEnergy Partners, L.P. and its consolidated subsidiaries is responsible forestablishing and maintaining adequate internal control over financial reportingas such term is defined in Exchange Act Rule 13a-15(f).

The Partnership’s internalcontrol over financial reporting is a process designed under the supervisionand with the participation of our principal executive and principal financial officersto provide reasonable assurance regarding the reliability of financialreporting and the preparation of the Partnership’s financial statements forexternal reporting purposes in accordance with U.S. generally acceptedaccounting principles.

The Partnership’sinternal control over financial reporting includes policies and proceduresthat:

·       Pertainto the maintenance of records that, in reasonable detail, accurately and fairlyreflect transactions and dispositions of assets of the Partnership;

·       Providereasonable assurance that transactions are recorded as necessary to permitpreparation of financial statements in accordance with U.S. generally acceptedaccounting principles, and that receipts and expenditures are being made onlyin accordance with the authorization of the Partnership’s management anddirectors; and

·       Providereasonable assurance regarding prevention or timely detection of unauthorizedacquisition, use, or disposition of our assets that could have a materialeffect on our financial statements.

The Partnership’s internalcontrol over financial reporting may not prevent or detect all misstatementsbecause of its inherent limitations. Additionally, projections of anyevaluation of effectiveness to future periods are subject to the risk thatcontrols may become inadequate because of changes in conditions, ordeterioration in the degree of compliance with our policies and procedures.

Management assessed theeffectiveness of the Partnership’s internal control over financial reporting asof December 31, 2005, based on the framework established in *Internal Control—Integrated Framework*issued by the Committee of Sponsoring Organizations of the Treadway Commission(COSO). Based on this assessment, management concluded that the Partnershipmaintained effective internal control over financial reporting as of December 31,2005.

Management’s assessment of the effectiveness of thePartnership’s internal control over financial reporting as of December 31,2005 has been audited by PricewaterhouseCoopers LLP, an independent registeredpublic accounting firm, as stated in their report beginning on page F-2.

**Item 9B. OtherInformation**

None.

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**PART III**

**Item 10. Directors and Executive Officers of theRegistrant**

**(a)   DIRECTORSAND EXECUTIVE OFFICERS OF THE REGISTRANT**

ThePartnership is a limited partnership and has no officers or directors of itsown. Set forth below is certain information concerning the directors andexecutive officers of the General Partner and of Enbridge Management as thedelegate of the General Partner under a Delegation of Control Agreement amongthe Partnership, the General Partner and Enbridge Management. All directors ofthe General Partner are elected annually and may be removed by EnbridgePipelines, as the sole stockholder of the General Partner. All directors ofEnbridge Management were elected and may be removed by the General Partner, asthe sole holder of Enbridge Management’s voting shares. All officers of theGeneral Partner and Enbridge Management serve at the discretion of therespective boards of directors of the General Partner and Enbridge Management.All directors and officers of the General Partner hold identical positions inEnbridge Management.

| **Name**       | ** ** | ** ** | ** ** | **Age**                                                                                                     | ** ** | **Position** |
|----------------|------------|------------|------------|-------------------------------------------------------------------------------------------------------------|------------|--------------|
| J.A. Connelly  |       | 59         |       | Director                                                                                                    |
| P.D. Daniel    |       | 59         |       | Director                                                                                                    |
| E.C. Hambrook  |       | 68         |       | Director                                                                                                    |
| M.O. Hesse     |       | 63         |       | Director                                                                                                    |
| G.K. Petty     |       | 64         |       | Director                                                                                                    |
| D.C. Tutcher   |       | 56         |       | President and Director                                                                                      |
| J.R. Bird      |       | 56         |       | Group Vice President—Liquids Transportation and  Director                                              |
| L.A. Zupan     |       | 50         |       | Vice President—Liquids Transportation Operations                                                       |
| M.A. Maki      |       | 41         |       | Vice President—Finance                                                                                 |
| T.L. McGill    |       | 51         |       | Vice President—Commercial Activity &  Business Development & Chief Operating Officer |
| A.D. Meyer     |       | 49         |       | Vice President—Liquids Transportation Technology                                                       |
| R.L. Adams     |       | 41         |       | Vice President—Operations and Technologies                                                             |
| D.V. Krenz     |       | 54         |       | Vice President                                                                                              |
| V.D. Yu        |       | 39         |       | Treasurer                                                                                                   |
| J.L. Balko     |       | 40         |       | Controller                                                                                                  |
| E.C. Kaitson   |       | 49         |       | Assistant Secretary                                                                                         |
| B.A. Stevenson |       | 50         |       | Corporate  Secretary                                                                                        |

 

J.A. Connelly was elected a director of the GeneralPartner in January 2003 and serves as the Chairman of its Audit, Finance &Risk Committee. Mr. Connelly served as Executive Vice President, SeniorVice President and Vice President of the Coastal Corporation from 1988 to 2001.Mr. Connelly is a business consultant providing executive managementconsulting services.

P.D. Daniel was elected a director of the GeneralPartner in July 1996 and served as its President from July 1996through October 1997. Mr. Daniel has served as President of Enbridgesince September 2000 and as Chief Executive Officer of Enbridge since January 2001.Prior to that time Mr. Daniel also served as President & ChiefOperating Officer—Energy Delivery of Enbridge from June 1998 to December 2000.He currently serves as a director of EnCana Corporation.

E.C. Hambrook was elected a director of the GeneralPartner in January 1992 and serves on its Audit, Finance & RiskCommittee. Mr. Hambrook serves as Chairman of the board of directors ofthe General Partner. Mr. Hambrook has served as President of HambrookResources, Inc. since its inception in 1991. Hambrook Resources, Inc.is a real estate investment, marketing and sales company.

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M.O. Hesse was elected a director of the GeneralPartner in March 2003 and serves as a member of its Audit, Finance &Risk Committee. Ms. Hesse was President and CEO of Hesse Gas Company from1990 through 2003. She served as Chairman of the U.S. Federal Energy RegulatoryCommission from 1986 to 1989. Ms. Hesse also served as Senior VicePresident, First Chicago Corporation and Assistant Secretary for Management andAdministration, U.S. Department of Energy. She currently serves as a directorof Arizona Public Service Company, Pinnacle West Capital Corporation, and TerraIndustries, Inc.

G.K. Petty was elected a director of the GeneralPartner in February 2001 and serves on its Audit, Finance & RiskCommittee. Mr. Petty has served as a director of Enbridge since January 2001.Mr. Petty served as President and Chief Executive Officer of TelusCorporation, a Canadian telecommunications company, from November 1994 to November 1999.Mr. Petty is a business consultant providing executive managementconsulting services to the telecommunications industry.

D.C. Tutcher was elected a director and President ofthe General Partner in June 2001. He also currently serves as Group VicePresident, Transportation South of Enbridge. He was previously Chairman of theBoard, President and Chief Executive Officer of Midcoast Energy Resources, Inc.from its formation in 1992 until it was acquired by Enbridge on May 11,2001.

J.R. Bird served as a director of the General Partnerfrom September 2000 to January 2003 and was reelected as a Directorin October 2003. He was elected Group Vice President, LiquidsTransportation of the General Partner in May 2005 and Vice President, LiquidsTransportation in January 2003. He served as President from September 2000until June 2001. He has also served as Group Vice President, LiquidsPipelines since May 2005 prior to which he was Group Vice President,Transportation North of Enbridge since May 2001 and President of EnbridgePipelines since September 2000. Prior to that time he served as Group VicePresident, Transportation from September 2000 through April 2001 andas Senior Vice President, Corporate Planning and Development of Enbridge from August 1997through August 2000.

L.A. Zupan was elected Vice President, LiquidsTransportation Operations of the General Partner in July 2004. Prior tothat he has served as Vice President, Development & Services forEnbridge Pipelines since 2000 and prior to that as Director, InformationTechnology.

M.A. Maki was elected Vice President, Finance of theGeneral Partner in July 2002. Prior to that time, he served as Controllerof the General Partner since June 2001, and prior to that, as Controllerof Enbridge Pipelines since September 1999.

T.L. McGill was elected Vice President, CommercialActivity and Business Development of the General Partner in April 2002 andChief Operating Officer in July 2004. Prior to that time, Mr. McGillwas President of Columbia Gulf Transmission Company from January 1996 to March 2002.

A.D. Meyer was elected Vice President, LiquidsTransportation Technology, of the General Partner in July 2003. He alsocontinues to serve as Vice President, Technology, Enbridge Pipelines since hisappointment in July 1999 and as President, Gateway Pipeline Inc. since hisappointment in June 2005. Prior to that time he served as President,Enbridge Pipelines (Athabasca) Inc. from October 1997 to July 1999and as Vice President, Liquids Marketing with Enbridge for the same period.

R.L. Adams was elected Vice President, Operations andTechnologies of the General Partner in April 2003. Prior to his currentposition, he was Director of Technology & Operations for the GeneralPartner since 2001, and Director of Field Operations and Technical Services andDirector of Commercial Activities for Ocensa/Enbridge in Bogota, Columbia from1997 to 2001.

D.V. Krenz was elected Vice President of the GeneralPartner in January 2005. Prior to that, he was President of Shell GasTransmission, LLC (previously Shell Gas Pipelines Co.) from March 1996 to December 2004.

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V. D. Yu was appointed as Treasurer of the GeneralPartner in July 2005 and is also an Assistant Treasurer of Enbridge. SinceJuly 2002 he was Director Financial Management at Enbridge and previouslyManager, Capital Markets and Risk Management.

J.L. Balko was elected Controller of the GeneralPartner in April 2003. Prior to that time, she served as Chief Accountantof the General Partner from October 1999 to April 2003.

E.C. Kaitson was elected Assistant Secretary of theGeneral Partner in July 2004. He served as Corporate Secretary of the GeneralPartner from October 2001 to July 2004. He also currently serves asAssociate General Counsel, of Enbridge. He was previously Assistant CorporateSecretary and General Counsel of Midcoast Energy Resources, Inc. from 1997until Enbridge acquired it on May 11, 2001.

B.A. Stevenson was electedCorporate Secretary of the General Partner in July 2004. Between 2000 and2004 Mr. Stevenson held management positions with Reliant Energy, Inc.and Arthur Andersen LLP. Prior to that Mr. Stevenson was General Counsel &Corporate Secretary of Alberta Natural Gas Company Ltd, a Canadian gasprocessing and transmission company, that was acquired by TransCanada Pipelines.

**(b)   SECTION 16(a) BENEFICIALOWNERSHIP REPORTING COMPLIANCE**

Section 16(a) ofthe Exchange Act requires our directors, executive officers and 10% beneficialowners to file with the SEC, reports of ownership and changes in ownership ofour equity securities and to furnish us with copies of all reports filed. Basedsolely on the review of the reports furnished to us, we believe that, duringfiscal year 2005, all Section 16(a) filing requirements applicable toEnbridge Management’s directors, officers, and greater than 10% beneficialowners were met.

**(c)   GOVERNANCE MATTERS**

We are a “controlled company,” as that term is used inNYSE Rule 303A, because all of our voting shares are owned by the GeneralPartner. Because we are a controlled company, the NYSE listing standards do notrequire that we or the General Partner have a majority of independent directorsor a nominating or compensation committee of the General Partner’s board ofdirectors.

The NYSE listing standardsrequire our CEO to annually certify that he is not aware of any violation bythe Partnership of the NYSE corporate governance listing standards.Accordingly, this certification was provided as required to the NYSE on October 14,2005.

**AUDIT, FINANCE & RISK COMMITTEE**

Enbridge Management has an Audit, Finance &Risk Committee (the “Audit Committee”) comprised of four board members who areindependent as the term is used in Section 10A of the Exchange Act of1934, as amended. None of these members are relying upon any exemptions fromthe foregoing independence requirements. The members of the Audit Committee areM.O. Hesse, E.C. Hambrook, G.K. Petty and J.A. Connelly. The Audit Committeeprovides independent oversight with respect to our internal controls,accounting policies, financial reporting, internal audit function and thereport of the independent registered public accounting firm. The AuditCommittee also reviews the scope and quality, including the independence andobjectivity of the independent and internal auditors and the fees paid for bothaudit and non-audit work and makes recommendations concerning audit matters,including the engagement of the independent auditors, to the Board ofDirectors.

The charter of the Audit Committee is available on ourwebsite at *www.enbridgepartners.com*.The Charter of the Audit Committee complies with the listing standards of theNYSE currently applicable to us.

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Enbridge Management’s Board of Directors hasdetermined that M.O. Hesse, E.C. Hambrook and J.A. Connelly qualify as “AuditCommittee financial experts” as defined in Item 401(h) of SEC Regulation S-K and are independent as thatterm is used in Item 7(d)(3)(iv) of Schedule 14A under the ExchangeAct.

Enbridge Management’sAudit Committee has established procedures for the receipt, retention andtreatment of complaints we receive regarding accounting, internal accountingcontrols or auditing matters and the confidential, anonymous submission by ouremployees of concerns regarding questionable accounting or auditing matters.Persons wishing to communicate with our Audit Committee may do so by writing incare of Chairman, Audit Committee, c/o Enbridge Energy Management, L.L.C., 1100Louisiana, Suite 3300, Houston TX 77002.

**CODEOF ETHICS, STATEMENT OF BUSINESS CONDUCT AND CORPORATE GOVERNANCE GUIDELINES**

The Partnership has adopted a Code of Ethicsapplicable to our senior financial officers, including the principal executiveofficer, principal financial officer and principal accounting officer ofEnbridge Management. A copy of the Code of Ethics for Senior Financial Officersis available on our website at *www.enbridgepartners.com*and is included herein as Exhibit 14.1. We intend to post on our websiteany amendments to or waivers of our Code of Ethics for Senior FinancialOfficers. Additionally, this material is available in print, free of charge, toany person who requests the information. Persons wishing to obtain this printedmaterial should submit a request to Corporate Secretary, c/o Enbridge EnergyPartners, L.P., 1100 Louisiana, Suite 3300, Houston, TX 77002.

We also have a Statement of Business Conductapplicable to all of our employees, officers and directors. A copy of theStatement of Business Conduct is available on our website at *www.enbridgepartners.com*. We intend topost on our website any amendments to or waivers of our Statement of BusinessConduct. Additionally, this material is available in print, free of charge, toany person who requests the information. Persons wishing to obtain this printedmaterial should submit a request to Corporate Secretary, c/o Enbridge EnergyPartners, L.P., 1100 Louisiana, Suite 3300, Houston TX 77002.

We also have a statementof Corporate Governance Guidelines that sets forth the expectation of how theBoard should function and the Board’s position with respect to key corporategovernance issues. A copy of the Corporate Governance Guidelines is availableon our website at *www.enbridgepartners.com*.We intend to post on our website any amendments to our Corporate GovernanceGuidelines. Additionally, this material is available in print, free of charge,to any person who requests the information. Persons wishing to obtain thisprinted material should submit a request to Corporate Secretary, c/o EnbridgeEnergy Partners, L.P., 1100 Louisiana, Suite 3300, Houston TX 77002.

**EXECUTIVESESSIONS OF NON-MANAGEMENT DIRECTORS**

The independent directors of Enbridge Management meetat regularly scheduled executive sessions without management. J.A. Connelly orE.C. Hambrook serve as the presiding director at those executive sessions.Persons wishing to communicate with the Company’s independent directors may doso by writing in care of Chairman, Board of Directors, Enbridge EnergyPartners, L.P., 1100 Louisiana, Suite 3300, Houston, TX 77002.

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**Item 11. Executive Compensation**

The following table setsforth the annual, long-term and other compensation for all services provided inall capacities to Enbridge Management and the Partnership for the fiscal yearsended December 31, 2005, 2004 and 2003 of the Chief Executive Officer andfour of our other executive officers with the highest salary and bonuscompensation charged to Enbridge Management and Partnership in the 2005 fiscalyear (the “Named Executive Officers”). The Partnership bears an allocableportion of these officers’ total compensation that is based on the approximatepercentage of time each of these officers devote to Enbridge Management and thePartnership. The other affiliates of Enbridge, to whom these officers alsorender services, bear the remainder of the compensation expenses of theseofficers.

***SummaryCompensation Table***

| Name & Principal  Position  | ** ** | ** ** | ** ** | **Year** | ** ** | **Salary  ($)** | ** ** | **Bonus  ($)** | ** ** | **Other Annual  Compensation**(1)(2)($) | ** ** | **Restricted  Stock  Award(s)  ($)** | ** ** | **Securities  Underlying  Options/  SARs**(4)(#) | ** ** | **LTIP  Payouts  ($)** | ** ** | **All Other  Compensation**(3)($) | ** ** | **Approximate  Percentage of  Time Devoted  to Enbridge  Management  and the  Partnership** | ** ** |
|-------------------------------------------|------------|------------|------------|----------|------------|-----------------|------------|----------------|------------|----------------------------------------------|------------|--------------------------------------|------------|--------------------------------------------------|------------|------------------------|------------|----------------------------------------|------------|-----------------------------------------------------------------------------------------------------------------|------------|
| D.C. Tutcher                              |       |       | 2005       |     |       | 343,750         |       | 235,000        |       |                                         | 30,000     |                                 |       |                                             | —     |                   |       |                                   | 34,000     |                                                                                                            |       |   | — |   |   |   | 17,897 |   |   |   | 90 |   |   |
| President                                 |       |       | 2004       |     |       | 322,000         |       | 270,000        |       |                                         | 30,000     |                                 |       |                                             | —     |                   |       |                                   | 17,000     |                                                                                                            |       |   | — |   |   |   | 12,350 |   |   |   |   |   |   |
|                                           |       |       | 2003       |     |       | 309,750         |       | 235,000        |       |                                         | 35,000     |                                 |       |                                             | —     |                   |       |                                   | 50,000     |                                                                                                            |       |   | — |   |   |   | 10,000 |   |   |   |   |   |   |
| T.L. McGill                               |       |       | 2005       |     |       | 267,750         |       | 143,894        |       |                                         | 20,000     |                                 |       |                                             | —     |                   |       |                                   | 20,400     |                                                                                                            |       |   |   |   |   |   | 12,886 |   |   |   | 90 |   |   |
| Vice President—                      |       |       | 2004       |     |       | 231,385         |       | 126,500        |       |                                         | 20,000     |                                 |       |                                             | —     |                   |       |                                   | 20,000     |                                                                                                            |       |   | — |   |   |   | 11,044 |   |   |   |   |   |   |
| Commercial                                |       |       | 2003       |     |       | 221,000         |       | 89,800         |       |                                         | 20,000     |                                 |       |                                             | —     |                   |       |                                   | 23,200     |                                                                                                            |       |   | — |   |   |   | 6,361 |   |   |   |   |   |   |
| Activity &  Business Development |       |       |       |     |       |            |       |           |       |                                         |       |                                 |       |                                             |       |                   |       |                                   |       |                                                                                                            |       |   |   |   |   |   |   |   |   |   |   |   |   |
| E.C. Kaitson                              |       |       | 2005       |     |       | 182,685         |       | 54,839         |       |                                         | 10,000     |                                 |       |                                             | —     |                   |       |                                   | 11,600     |                                                                                                            |       |   | — |   |   |   | 11,384 |   |   |   | 90 |   |   |
| Assistant Secretary                       |       |       | 2004       |     |       | 174,055         |       | 59,900         |       |                                         | 10,000     |                                 |       |                                             | —     |                   |       |                                   | 6,500      |                                                                                                            |       |   | — |   |   |   | 10,643 |   |   |   |   |   |   |
| and Associate General                     |       |       | 2003       |     |       | 168,000         |       | 35,400         |       |                                         | 10,000     |                                 |       |                                             | —     |                   |       |                                   | 5,900      |                                                                                                            |       |   | — |   |   |   | 8,375 |   |   |   |   |   |   |
| Counsel                                   |       |       |       |     |       |            |       |           |       |                                         |       |                                 |       |                                             |       |                   |       |                                   |       |                                                                                                            |       |   |   |   |   |   |   |   |   |   |   |   |   |
| M.A. Maki                                 |       |       | 2005       |     |       | 197,500         |       | 84,840         |       |                                         | 20,000     |                                 |       |                                             | —     |                   |       |                                   | 11,400     |                                                                                                            |       |   | — |   |   |   | 10,288 |   |   |   | 90 |   |   |
| Vice President—                      |       |       | 2004       |     |       | 171,365         |       | 87,300         |       |                                         | 20,000     |                                 |       |                                             | —     |                   |       |                                   | 15,000     |                                                                                                            |       |   | — |   |   |   | 9,444 |   |   |   |   |   |   |
| Finance                                   |       |       | 2003       |     |       | 161,750         |       | 71,400         |       |                                         | 20,000     |                                 |       |                                             | —     |                   |       |                                   | 16,700     |                                                                                                            |       |   | — |   |   |   | 7,100 |   |   |   |   |   |   |
| R.L. Adams                                |       |       | 2005       |     |       | 176,070         |       | 75,600         |       |                                         | 20,000     |                                 |       |                                             | —     |                   |       |                                   | 10,800     |                                                                                                            |       |   |   |   |   |   | 8,950 |   |   |   | 90 |   |   |
| Vice President—                      |       |       | 2004       |     |       | 161,960         |       | 81,600         |       |                                         | 20,000     |                                 |       |                                             | —     |                   |       |                                   | 10,000     |                                                                                                            |       |   | — |   |   |   | 8,339 |   |   |   |   |   |   |
| Operations and                            |       |       | 2003       |     |       | 151,000         |       | 54,100         |       |                                         | 26,229     |                                 |       |                                             | —     |                   |       |                                   | 7,500      |                                                                                                            |       |   | — |   |   |   | 7,568 |   |   |   |   |   |   |
| Technology                                |       |       |       |     |       |            |       |           |       |                                         |       |                                 |       |                                             |       |                   |       |                                   |       |                                                                                                            |       |   |   |   |   |   |   |   |   |   |   |   |   |

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(1)                Amounts in thiscolumn include: the flexible perquisites allowance (as described in Note 2below), flexible credits paid as additional compensation (as described inNote 2 below), one-time payments for termination benefits, and the taxablebenefit from loans by Enbridge, which were granted for relocation or hiringincentive purposes (and amounts reimbursed for the payment of taxes relating tosuch benefit).

(2)                Effective July 1,2001, Enbridge adopted a flexible benefit program pursuant to which employeesreceive an amount of flex credits based on their family status and base salary.Beginning in fiscal 2003, the Named Executive Officers were given a FlexiblePerquisites Allowance to cover perquisites that may have been previously paidon behalf of each executive. Flex credits can be (a) used to purchasevarious benefits (such as extended health or dental coverage, disabilityinsurance and life insurance) on the same terms as are available to allemployees; (b) applied as contributions to the Stock Purchase and SavingsPlan (as described in Note 3 below); or (c) paid to the employee asadditional compensation. In 2005, Mr. Tutcher received perquisites andother personal benefits totaling $30,000, all of which related to his FlexiblePerquisites Allowance; Mr. McGill received perquisites and other personalbenefits totaling $20,000, all of which related to his Flexible PerquisitesAllowance; Mr. Maki 

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received perquisites andother personal benefits totaling $20,000, all of which related to his FlexiblePerquisites Allowance; Mr. Kaitson received perquisites and other personalbenefits totaling $10,000, all of which related to his Flexible PerquisitesAllowance, and Mr. Adams received perquisites and other personal benefitstotaling $20,000 all of which related to his Flexible Perquisites Allowance.

(3)                Employees in theUnited States participate in the Enbridge Employee Services, Inc. SavingsPlan (the “401(k) Plan”) under which employees may contribute up to 50% oftheir base salary, with employee contributions up to 5% matched by Enbridge(all subject to the contribution limits specified in the Internal RevenueCode). Enbridge’s contributions are used to purchase Enbridge shares at marketvalue and the employees’ contributions may be used to purchase Enbridge sharesor nine designated funds. During 2005, Enbridge made contributions of $10,500,$10,500, $9,134.34, $9,875.06, and $8,571.53, respectively, to the 401(k) Planfor the benefit of Mr. Tutcher, Mr. McGill, Mr. Kaitson, Mr. Maki,and Mr. Adams. Mr. Tutcher also received $5,000 as reimbursement forprofessional financial services. Additionally, during 2005 Enbridge EmployeeServices, Inc. paid term life insurance premiums of $540, $529, $393,$413, and $378 for the benefit of Mr. Tutcher, Mr. McGill, Mr. Kaitson,Mr. Maki, and Mr. Adams, respectively. In 2005, Enbridge EmployeeServices, Inc. also furnished Messrs. Tutcher, McGill and Kaitsonwith parking benefits, at an annual cost of $1,857.

(4)                Eachoption entitles the holder to acquire the indicated number of shares ofEnbridge common stock. The costs associated with recognizing the fair value ofthe options as compensation expense are borne by the Partnership. Additionalinformation is provided in the following section labeled “Stock Options”.

***Stock Options***

We do not maintain any compensationplans for the benefit of the Named Executive Officers under which equityinterests in Enbridge Management or the Partnership may be awarded. In 2004,Enbridge began allocating to us the compensation expense it recognized inconnection with recording the fair value of its outstanding stock optionsgranted to certain of our officers, including the Named Executive Officers.Prior to 2004, we were not allocated any expense associated with stock optiongrants. The stock options are granted to the Named Executive Officers pursuantto the Enbridge Incentive Stock Option Plan, which is a long-term incentiveplan administered by the Human Resources & Compensation Committee ofEnbridge. The stock option grants are denominated in Canadian dollars. Thefollowing two tables set forth information concerning options granted andexercised during 2005 by the Named Executive Officers under the Enbridge stockoption plans:

***Options/SAR Grantsin Last Fiscal Year***

| ** **   | ** ** | **Individual Grants**                                        | ** ** | **Potential Realizable**                                                    | ** ** |
|--------------|------------|-------------------------------------------------------------------|------------|----------------------------------------------------------------------------------|------------|
| ** **   | ** ** | **Number of  Securities  Underlying  Options/SARs  Granted** | ** ** | **Percent of Total  Options/SARs  Granted to  Employees in** | ** ** | **Exercise or  Base Price** | ** ** | ** ** | ** ** | **Value at Assumed  Annual Rates of  Stock Price  Appreciation for   Options Term** | ** ** |
| **Name**     | ** ** | ** **                                                        | ** ** | **(#)**                                                                          | ** ** | **Fiscal Year** | ** ** | **($CAD/Sh)** | ** ** | **Expiration Date** | ** ** | **5% $CAD** | ** ** | **10% $CAD** | ** ** |
| D.C. Tutcher |       |                                                              | 34,000     |                                                                             |       |   | 2.22% |   |   |   | 31.68 |   |   | February 3, 2015 |   | 677,395 |   | 1,716,651 |   |
| T.L. McGill  |       |                                                              | 20,400     |                                                                             |       |   | 1.33% |   |   |   | 31.68 |   |   | February 3, 2015 |   | 406,437 |   | 1,029,991 |   |
| E.C. Kaitson |       |                                                              | 11,600     |                                                                             |       |   | 0.76% |   |   |   | 31.68 |   |   | February 3, 2015 |   | 231,111 |   | 585,681 |   |
| M.A. Maki    |       |                                                              | 11,400     |                                                                             |       |   | 0.74% |   |   |   | 31.68 |   |   | February 3, 2015 |   | 227,127 |   | 575,583 |   |
| R.L. Adams   |       |                                                              | 10,800     |                                                                             |       |   | 0.70% |   |   |   | 31.68 |   |   | February 3, 2015 |   | 215,173 |   | 545,289 |   |
|              |            |                                                                   |            |                                                                                  |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

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***AggregatedOption/SAR Exercises in Last Fiscal Year and Fiscal Year End Option/SAR Values***

| ** **   | ** ** | ** ** | ** ** | ** **                                      | ** ** | **Number of Securities  Underlying Unexercised   Options/SARs At Fiscal  Year-End**(1) | ** ** | **Value of Unexercised In-  The-Money Options/SARS   At Fiscal Year-End** | ** ** |
|--------------|------------|------------|------------|-------------------------------------------------|------------|----------------------------------------------------------------------------------------------------------------------|------------|--------------------------------------------------------------------------------------------------------------|------------|
| **Name**     | ** ** | ** ** | ** ** | **Shares Acquired  on Exercise  (#)** | ** ** | **Value Realized  ($CAD)**                                                                                      | ** ** | **Exercisable  (#)**                                                                                         | ** ** | **Unexercisable  (#)** | ** ** | **Exercisable  ($CAD)** | ** ** | **Unexercisable  ($CAD)** | ** ** |
| D.C. Tutcher |       |       | —     |                                            |       |                                                                                                                 | —     |                                                                                                         |       |   | 575,194 |   |   |   | 214,500 |   |   | 9,826,198 |   |   | 2,622,450 |   |   |
| T.L. McGill  |       |       | 34,500     |                                            |       |                                                                                                                 | 365,788    |                                                                                                         |       |   | 33,200 |   |   |   | 85,100 |   |   | 466,148 |   |   | 938,522 |   |   |
| E.C. Kaitson |       |       | —     |                                            |       |                                                                                                                 | —     |                                                                                                         |       |   | 121,420 |   |   |   | 31,400 |   |   | 2,577,113 |   |   | 309,273 |   |   |
| M.A. Maki    |       |       | —     |                                            |       |                                                                                                                 | —     |                                                                                                         |       |   | 46,200 |   |   |   | 54,600 |   |   | 685,031 |   |   | 609,135 |   |   |
| R.L. Adams   |       |       | 24,900     |                                            |       |                                                                                                                 | 237,299    |                                                                                                         |       |   | — |   |   |   | 36,600 |   |   | — |   |   | 373,808 |   |   |
|              |            |            |            |                                                 |            |                                                                                                                      |            |                                                                                                              |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

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(1)                The number ofsecurities underlying unexercised options/SARs at May 20, 2005, wereadjusted for a 2-for-1 stock split declared by Enbridge on itsshares.

Enbridge also maintains along-term, performance-based stock unit plan (the “PSU Plan”). Under thePSU Plan, participating executives receive annual grants of PSUs. The initialvalue of each of these PSUs is equivalent to the market value of one Enbridge share.Each award may be paid out at the end of a three-year performance cycle basedon: 1) the market value of the Enbridge share at the end of the three-yearperiod; 2) additional PSUs representing dividends paid during thethree-year period; and 3) Enbridge’s total shareholder return over athree-year period relative to a peer group of companies established in advanceby Enbridge’s Human Resources & Compensation Committee. Payments under thePSU Plan may be increased up to 200% of the original award when Enbridgeoutperforms its peer group. If performance fails to meet threshold performancelevels, no payments are made. Enbridge does not issue any shares in connectionwith the PSU Plan. The compensation expense associated with recognizing thefair value of the outstanding stock units attributable to our executiveofficers that participate in the PSU Plan are allocated to us and expensed inour consolidated statements of income. The following table sets forth thegrants made to the Named Executive Officers during 2005 pursuant to the PSUPlan:

***Long-Term IncentivePlan Awards Table***

| ** **   | ** ** | **Securities, Units or** | ** ** | **Performance or Other** | ** ** | **Estimated Future Payouts Under Non-  Securities-Price-Based Plans** | ** ** |
|--------------|------------|------------------------------------|------------|------------------------------------|------------|------------------------------------------------------------------------------------------------|------------|
| **Name**     | ** ** | ** **                         | ** ** | **Other Rights  (#)**         | ** ** | **Period Until Maturation or  Payout**                                          | ** ** | **Threshold**(1)  (#) | ** ** | **Target**(2)  (#) | ** ** | **Maximum**(3)  (#) | ** ** |
| D.C. Tutcher |       |                               | 7,090      |                               |       | January 1, 2005-December 31,  2007                                                   |       |   | 284 |   |   |   | 7,090 |   |   |   | 14,180 |   |   |
| T.L. McGill  |       |                               | 2,880      |                               |       | January 1, 2005-December 31,  2007                                                   |       |   | 115 |   |   |   | 2,880 |   |   |   | 5,760 |   |   |
| E.C. Kaitson |       |                               | —     |                               |       | January 1, 2005-December 31,  2007                                                   |       |   | — |   |   |   | — |   |   |   | — |   |   |
| M.A. Maki    |       |                               | 2,140      |                               |       | January 1, 2005-December 31,  2007                                                   |       |   | 86 |   |   |   | 2,140 |   |   |   | 4,280 |   |   |
| R.L. Adams   |       |                               | 2,020      |                               |       | January 1, 2005-December 31, 2007                                                    |       |   | 81 |   |   |   | 2,020 |   |   |   | 4,040 |   |   |
|              |            |                                    |            |                                    |            |                                                                                                |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

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(1)                “Threshold” refersto the minimum amount payable for a certain level of performance under the PSUPlan.

(2)                “Target” refers tothe amount payable if the specified performance target is reached.

(3)                “Maximum”refers to the maximum payout possible as specified under the PSU Plan.

***Pension Plan***

The following tables illustrate the benefits payableunder the defined benefit component of Enbridge’s trusteed non-contributorypension plans (the “Plan”), which apply to the Named Executive Officers of the 

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Partnership. The tablesillustrate the total annual pension entitlements assuming the eligibilityrequirements for an unreduced pension have been satisfied. Plan benefits thatexceed maximum pension rules applicable to registered plan benefits arepaid from the Enbridge supplemental pension plan. Other trusteed pension plans,with varying contribution formulae and benefits, cover the balance ofemployees.

For service prior to January 1, 2000, the Planprovides a yearly pension payable after age 60 in the normal form(60 percent joint and last survivor) equal to: (a) 1.6 percentof the average of the participant’s highest annual salary during threeconsecutive years out of the last ten years of credited service multiplied by (b) thenumber of credited years of service. The pension is offset, after age 65, by50 percent of the participant’s Social Security benefit, prorated by yearsin which the participant has both credited service and Social Securitycoverage. An unreduced pension is payable if retirement is after age 55 with 30or more years of service, or after age 60. Early retirement reductions apply ifa participant retires and does not meet these requirements. Retirement benefitspaid from the Plan are indexed at 50 percent of the annual increase in theconsumer price index.

For service after December 31,1999, the Plan provides for senior management employees, including the NamedExecutive Officers, a yearly pension payable after age 60 in the normal form(60 percent joint and last survivor) equal to: (a) 2 percent ofthe sum of (i) the average of the participant’s highest annual base salaryduring three consecutive years out of the last ten years of credited serviceand (ii) the average of the participant’s three highest annual performancebonus periods, represented in each period by 50 percent of the actualbonus paid, in respect of the last five years of credited services, multipliedby (b) the number of credited years of service. An unreduced pension ispayable if retirement is after age 55 with 30 or more years of service, orafter age 60. Early retirement reductions apply if a participant retires anddoes not meet these requirements. Retirement benefits paid from the Plan areindexed at 50 percent of the annual increase in the consumer price index.

***Pension Plan Tables***

**ServicePrior to January 1, 2000, before Social Security Offset**

| ** **          | ** ** | **Years of Credited Service** | ** ** |
|---------------------|------------|----------------------------------------------|------------|
| **Remuneration**(1) | ** ** | ** **                                   | ** ** | **10** | ** ** | **15** | ** ** | **20** | ** ** | **25** | ** ** | **30** | ** ** | **35** | ** ** |
| $200,000            |       | $                                            | 32,000     |   | $ | 48,000 |   | $ | 64,000 |   | $ | 80,000 |   | $ | 96,000 |   | $ | 112,000 |   |
|   250,000 |       | 40,000                                       |       | 60,000 |   | 80,000 |   | 100,000 |   | 120,000 |   | 140,000 |   |
|   300,000 |       | 48,000                                       |       | 72,000 |   | 96,000 |   | 120,000 |   | 144,000 |   | 168,000 |   |
|   350,000 |       | 56,000                                       |       | 84,000 |   | 112,000 |   | 140,000 |   | 168,000 |   | 196,000 |   |
|   400,000 |       | 64,000                                       |       | 96,000 |   | 128,000 |   | 160,000 |   | 192,000 |   | 224,000 |   |
|   450,000 |       | 72,000                                       |       | 108,000 |   | 144,000 |   | 180,000 |   | 216,000 |   | 252,000 |   |
|   500,000 |       | 80,000                                       |       | 120,000 |   | 160,000 |   | 200,000 |   | 240,000 |   | 280,000 |   |
|   550,000 |       | 88,000                                       |       | 132,000 |   | 176,000 |   | 220,000 |   | 264,000 |   | 308,000 |   |
|   600,000 |       | 96,000                                       |       | 144,000 |   | 192,000 |   | 240,000 |   | 288,000 |   | 336,000 |   |
|   650,000 |       | 104,000                                      |       | 156,000 |   | 208,000 |   | 260,000 |   | 312,000 |   | 364,000 |   |
|   700,000 |       | 112,000                                      |       | 168,000 |   | 224,000 |   | 280,000 |   | 336,000 |   | 392,000 |   |
|   750,000 |       | 120,000                                      |       | 180,000 |   | 240,000 |   | 300,000 |   | 360,000 |   | 420,000 |   |
|   800,000 |       | 128,000                                      |       | 192,000 |   | 256,000 |   | 320,000 |   | 384,000 |   | 448,000 |   |
|                     |            |                                              |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

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**ServiceAfter December 31, 1999**

| **Remuneration**(1) | ** ** | ** ** | ** ** | **10**  | ** ** | **15**  | ** ** | **20**  | ** ** | **25**  | ** ** | **30**  | ** ** | **35** | ** ** |
|---------------------|------------|------------|------------|---------|------------|---------|------------|---------|------------|---------|------------|---------|------------|--------|------------|
| $200,000            |       | $          | 40,000     |    | $          | 60,000  |       | $       | 80,000     |    | $          | 100,000 |       | $      | 120,000    |   | $ | 140,000 |   |
|   250,000 |       | 50,000     |       | 75,000  |       | 100,000 |       | 125,000 |       | 150,000 |       | 175,000 |       |
|   300,000 |       | 60,000     |       | 90,000  |       | 120,000 |       | 150,000 |       | 180,000 |       | 210,000 |       |
|   350,000 |       | 70,000     |       | 105,000 |       | 140,000 |       | 175,000 |       | 210,000 |       | 245,000 |       |
|   400,000 |       | 80,000     |       | 120,000 |       | 160,000 |       | 200,000 |       | 240,000 |       | 280,000 |       |
|   450,000 |       | 90,000     |       | 135,000 |       | 180,000 |       | 225,000 |       | 270,000 |       | 315,000 |       |
|   500,000 |       | 100,000    |       | 150,000 |       | 200,000 |       | 250,000 |       | 300,000 |       | 350,000 |       |
|   550,000 |       | 110,000    |       | 165,000 |       | 220,000 |       | 275,000 |       | 330,000 |       | 385,000 |       |
|   600,000 |       | 120,000    |       | 180,000 |       | 240,000 |       | 300,000 |       | 360,000 |       | 420,000 |       |
|   650,000 |       | 130,000    |       | 195,000 |       | 260,000 |       | 325,000 |       | 390,000 |       | 455,000 |       |
|   700,000 |       | 140,000    |       | 210,000 |       | 280,000 |       | 350,000 |       | 420,000 |       | 490,000 |       |
|   750,000 |       | 150,000    |       | 225,000 |       | 300,000 |       | 375,000 |       | 450,000 |       | 525,000 |       |
|   800,000 |       | 160,000    |       | 240,000 |       | 320,000 |       | 400,000 |       | 480,000 |       | 560,000 |       |
|                     |            |            |            |         |            |         |            |         |            |         |            |         |            |        |            |  |  |  |  |  |  |

 

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(1)                “Remuneration”refers to annual salary and that portion of the annual bonus eligible forinclusion in final average earnings.

Mr. Tutcher accumulates pension credits equal to4.0 percent for each year of service to his tenth anniversary ofemployment with Enbridge.

Forpurposes of computing the total retirement benefit of the Named ExecutiveOfficers, the following table sets forth the service accrued prior to January 1,2000, (“Pre 2000 Service”) and service accrued after December 31, 1999 (“Post1999 Service”) by the Named Executive Officers at December 31, 2004. Thesefigures include the additional service mentioned in the previous paragraph.

| **Name**     | ** ** | ** ** | ** ** | **Age** | ** ** | **Pre 2000 Service** | ** ** | **Post 1999 Service** | ** ** |
|--------------|------------|------------|------------|---------|------------|--------------------------------|------------|---------------------------------|------------|
| D.C. Tutcher |       |       | 56         |    |       |                           | —     |                            |       |   | 4.58 |   |   |
| T.L. McGill  |       |       | 51         |    |       |                           | —     |                            |       |   | 3.83 |   |   |
| E.C. Kaitson |       |       | 49         |    |       |                           | —     |                            |       |   | 4.58 |   |   |
| M.A. Maki    |       |       | 41         |    |       |                           | 13.32      |                            |       |   | 6.00 |   |   |
| R.L. Adams   |       |       | 41         |    |       |                           | 14.70      |                            |       |   | 4.50 |   |   |

 

***Employment Agreements***

Messrs. Tutcher andKaitson have executive employment agreements with Enbridge. The agreementscommenced on May 11, 2001, and continue until the earlier of (i) thedate of voluntary retirement in accordance with the retirement policiesestablished for senior employees of Enbridge (ii) the voluntaryresignation which is not a constructive dismissal, or (iii) terminationbased on disability, death, cause or by either party. The agreements providethat in the event of termination of employment, the executive agrees to keepconfidential all information of a confidential or proprietary nature andfurther agrees not to use such information for personal advantage. Theagreements also provide for a base salary, annual reviews, discretionaryraises, participation in short and long-term incentive plans of Enbridge, andseverance payments in the amount of two years compensation in the event oftermination by Enbridge.

***Director Compensation***

Enbridge employees who are members of the board ofdirectors of the General Partner or Enbridge Management do not receive anyadditional compensation for serving in those capacities.

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During 2005, independent members of the board ofdirectors of the General Partner and Enbridge Management received an aggregateannual fee of $30,000, paid quarterly, plus $1,000 per day for each meetingattended of the board of directors or committees of the board. In addition,each independent director is reimbursed for out-of-pocket expenses inconnection with attending meetings of the board of directors or committees andan additional $500 for meetings requiring out of state travel. The director whoserves as chairman of the audit committees is paid an additional $7,500 peryear and the director who serves as chairman of the boards is paid anadditional $10,000 per year, paid quarterly.

As of January, 1, 2006, theDirector Compensation Plan was amended to increase the annual retainerto $75,000 and additional meeting fees were eliminated. The retainers paid to directorsserving as the chairman of the boards and chairman of the audit committees willremain at current levels. The out of state travel fee will be increased to $1,500.As part of this change to the Director Compensation Plan, the directors votedto amend the Corporate Governance Guidelines to incorporate an expectation thatindependent directors will hold a personal investment in either or both ofEnbridge Energy Partners, L.P. or Enbridge Management, of at least two timesthe annual board retainer (i.e., 2 X $75,000 = $150,000). Directors would beexpected to achieve the foregoing level of share ownership by the later of January 1,2011 or five years from the date they became a director.

The General Partner indemnifies each director foractions associated with being a director to the full extent permitted underDelaware law and maintains errors and omissions insurance.

Messrs. Hambrook and Connelly served on a pricingcommittee in 2005 in connection with public offerings to sell limitedpartnership interest in the Partnership. As compensation for serving on thepricing committee, they each received a fee of $1,000 per meeting.

Messrs. Hambrook andConnelly and Ms. Hesse also served on a special committee during 2005 inconnection with an evaluation of a proposed transaction with an Enbridgeaffiliate. As compensation for serving on the special committee, they eachreceived a fee of $1,000 per meeting and Mr. Hambrook received $3,000 forserving as the chairman of that committee.

**Item 12. Security Ownership of Certain BeneficialOwners and Management**

*(a)   SecurityOwnership of Certain Beneficial Owners*

Thefollowing table sets forth information as of February 15, 2006, with respectto persons known to us to be the beneficial owners of more than 5% of eitherclass of the Partnership’s Units:

| Name and Address of Beneficial Owner | ** ** | ** **                 | ** ** | **Title of Class** | ** ** | **Amount and  Nature of  Beneficial  Ownership** | ** ** | **Percent  Of Class** | ** ** |
|---------------------------------------------------------------|------------|----------------------------|------------|------------------------------|------------|------------------------------------------------------------|------------|----------------------------|------------|
| Enbridge Energy Management,  L.L.C.                           |       | i-units                    |       | 11,933,019                   |       |                                                       | 100.0      |                       |       |
| 1100 Louisiana,  Suite 3300

Houston, TX 77002           |       |                       |       |                         |       |                                                       |       |                       |       |
| Enbridge Energy  Company, Inc.                           |       | Class B  Common Units |       | 3,912,750                    |       |                                                       | 100.0      |                       |       |
| 1100 Louisiana, Suite 3300

Houston, TX 77002            |       |                       |       |                         |       |                                                       |       |                       |       |

 

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*(b)   Security Ownership of Management andDirectors*

Thefollowing table sets forth information as of February 15, 2005, withrespect to each class of our units beneficially owned by the Named ExecutiveOfficers, directors and nominees for director of the General Partner and allexecutive officers, directors and nominees for director of the Partnership as agroup:

| **Name**                                                          | ** ** | ** **                 | ** ** | **Title of Class** | ** ** | **Amount and  Nature of  Beneficial  Ownership**(1) | ** ** | **Percent  Of Class** | ** ** |
|-------------------------------------------------------------------|------------|----------------------------|------------|------------------------------|------------|---------------------------------------------------------------|------------|----------------------------|------------|
| J.A. Connelly                                                     |       | Class A Common  Units |       |                         | 5,000      |                                                          |       |                       | *          |   |   |
| P.D. Daniel                                                       |       | Class A Common  Units |       |                         | —     |                                                          |       |                       | —     |   |   |
| E.C. Hambrook                                                     |       | Class A Common  Units |       |                         | 2,000      |                                                          |       |                       | *          |   |   |
| M.O. Hesse                                                        |       | Class A Common  Units |       |                         | —     |                                                          |       |                       | —     |   |   |
| G.K. Petty                                                        |       | Class A Common  Units |       |                         | 1,000      |                                                          |       |                       | *          |   |   |
| D.C.Tutcher                                                       |       | Class A Common  Units |       |                         | 20,200     |                                                          |       |                       | *          |   |   |
| J.R. Bird                                                         |       | Class A Common  Units |       |                         | —     |                                                          |       |                       | —     |   |   |
| L.A. Zupan                                                        |       | Class A Common  Units |       |                         | —     |                                                          |       |                       | —     |   |   |
| M.A. Maki                                                         |       | Class A Common  Units |       |                         | —     |                                                          |       |                       | —     |   |   |
| T.L. McGill                                                       |       | Class A Common  Units |       |                         | —     |                                                          |       |                       | —     |   |   |
| A.D. Meyer                                                        |       | Class A Common  Units |       |                         | —     |                                                          |       |                       | —     |   |   |
| R.L. Adams                                                        |       | Class A Common  Units |       |                         | —     |                                                          |       |                       | —     |   |   |
| D.V. Krenz                                                        |       | Class A Common  Units |       |                         | —     |                                                          |       |                       | —     |   |   |
| V.D. Yu                                                           |       | Class A Common  Units |       |                         | —     |                                                          |       |                       | —     |   |   |
| J.L. Balko                                                        |       | Class A Common  Units |       |                         | —     |                                                          |       |                       | —     |   |   |
| E.C. Kaitson                                                      |       | Class A Common  Units |       |                         | —     |                                                          |       |                       | —     |   |   |
| B.A. Stevenson                                                    |       | Class A Common  Units |       |                         | —     |                                                          |       |                       | —     |   |   |
| All Officers, directors  and nominees as a group 17 persons) |       | Class A Common Units  |       |                         | 28,200     |                                                          |       |                       | *          |   |   |

 

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*                    Less than 1%

(1)        Eachbeneficial owner has sole voting and investment power with respect to all theunits attributed to him/her.

**Item 13. Certain Relationships and RelatedTransactions**

***Interest of the General Partner in the Partnership***

At December 31, 2005,the General Partner owned 3,912,750 Class B Common Units representing a 5.8%limited partner interest in the Partnership. In addition, the General Partneralso owns 2,015,853 Listed shares or 17.2% of Enbridge Management’s outstandingListed shares, constituting an effective 3.0% limited partner interest in thePartnership. Together with the 2% general partner interest, the General Partnereffectively owns a total of 10.8% of the Partnership and received $39.8 millionin cash and incentive distributions.

***Interest of Enbridge Management in the Partnership***

At December 31, 2005,Enbridge Management owned 11,704,948 i-units, representing an 17.5% limitedpartner interest in us. The i-units are a separate class of our limited partnerinterests. All of our i-units are owned by Enbridge Management and are notpublicly traded. Enbridge Management’s limited liability company agreementprovides that the number of all of its outstanding shares, including the voting

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sharesowned by the General Partner, at all times will equal the number of i-unitsthat it owns. Through the combined effect of the provisions in the PartnershipAgreement and the provisions of Enbridge Management’s limited liability companyagreement, the number of outstanding Enbridge Management shares and the numberof our i-units will at all times be equal.

***Cash Distributions***

Asdiscussed in “Part II, Item 7”, we make quarterly cash distributions ofall of our available cash to our General Partner and the holders of our commonunits. Under the Partnership Agreement, our General Partner receivesincremental incentive cash distributions on the portion of cash distributions ona per unit basis that exceed certain target thresholds as follows:

| ** **                                                              | ** ** | **Unitholders** | ** ** | **General Partner** | ** ** |
|-------------------------------------------------------------------------|------------|-----------------|------------|--------------------------|------------|
| 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 | % |   |

 

During 2005, incentivedistributions paid to the General Partner were approximately $25.3 million.

***Other Related Party Transactions***

The Partnership, which has no employees, uses theservices of Enbridge and its affiliates (the “Group”) for management, operatingand administrative services of our business.

For further discussion ofthis and other related party transactions, refer to “Note 10—Related PartyTransactions” in the Notes to the Consolidated Financial Statements beginningon Page F-2 of this Annual Report on Form 10-K.

**Item 14. Principal Accountant Fees and Services**

Thefollowing table sets forth the aggregate fees billed for professional servicesrendered by PricewaterhouseCoopers LLP, our principal independent auditors, foreach of our last two fiscal years.

| ** **             | ** ** | **For the years ended  December 31,** | ** ** |
|------------------------|------------|-----------------------------------------------------------|------------|
| ** **             | ** ** | **2005**                                                  | ** ** | **2004** | ** ** |
| Audit fees(1)          |       | $                                                         | 2,276,166  |   | $ | 2,143,655 |   |
| Audit related  fees(2) |       | —                                                    |       | — |   |
| Tax fees(3)            |       | 680,500                                                   |       | 756,868 |   |
| All other fees         |       | —                                                    |       | — |   |
| Total                  |       | $                                                         | 2,956,666  |   | $ | 2,900,523 |   |

 

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(1)                Audit fees consistof fees billed for professional services rendered for the audit of ourconsolidated financial statements, reviews of our interim consolidatedfinancial statements, audits of various subsidiaries for statutory andregulatory filing requirements and our debt and equity offerings.

(2)                Audit related feesconsist of fees billed for professional services rendered for Sarbanes-OxleySection 404 consultation.

(3)                Tax fees consistof fees billed for professional services rendered for federal and state taxcompliance for Partnership tax filings and unitholder K-1’s.

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Engagements for servicesprovided by PricewaterhouseCoopers LLP are subject to pre-approval by theAudit, Finance & Risk Committee of Enbridge Management’s Board ofDirectors, or services up to $50,000 may be approved by the Chairman of theAudit, Finance & Risk Committee, under Board of Directors delegatedauthority. All services in 2005 and 2004 were approved by the Audit, Finance &Risk Committee.

**PART IV**

**Item 15. Exhibits, Financial Statement Schedules**

The followingdocuments are filed as a part of this report:

(1)         *FinancialStatements, which are incorporated by reference in Item 8 are includedbeginning on page F-1.*

a.                  Report ofPricewaterhouseCoopers LLP, Independent Registered Public Accounting Firm.

b.                 ConsolidatedStatements of Income for the years ended December 31, 2005, 2004, and2003.

c.                  ConsolidatedStatements of Comprehensive Income for the years ended December 31, 2005,2004, and 2003.

d.                 ConsolidatedStatements of Cash Flows for the years ended December 31, 2005, 2004, and2003.

e.                  ConsolidatedStatements of Financial Position as of December 31, 2005 and 2004.

f.                    ConsolidatedStatements of Partners’ Capital for the years ended December 31, 2005,2004, and 2003.

g.                  Notesto the Consolidated Financial Statements.

(2)         *Financial Statement Schedules.*

All schedules have beenomitted because they are not applicable, the required information is shown inthe Consolidated Financial Statements or Notes thereto, or the requiredinformation is immaterial.

(3)         *Exhibits.*

Reference is made to the “Index of Exhibits” followingthe signature page, which is hereby incorporated into this Item.

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**SIGNATURES**

Pursuantto the requirements of Section 13 or 15(d) of the Securities ExchangeAct of 1934, the Registrant has duly caused this Report to be signed on itsbehalf by the undersigned, thereunto duly authorized.

|                              | ENBRIDGE ENERGY PARTNERS,  L.P.  (Registrant) |
|------------------------------|-----------------------------------------------|
|                         | By:                                           | Enbridge Energy  Management, L.L.C.,  as delegate of the General Partner |
|                         | By:                                           | /s/  DAN C. TUTCHER |
|                         |                                          | Dan C. Tutcher |
| Date: February 22, 2006 |                                          | *(President)* |

 

Pursuantto the requirements of the Securities Exchange Act of 1934, this Report hasbeen signed below on February 22, 2006 by the following persons on behalfof the Registrant and in the capacities indicated.

| /s/ DAN  C. TUTCHER                                                   |   | /s/ M.A. MAKI                                                         |
|-----------------------------------------------------------------------|--------|-----------------------------------------------------------------------|
| Dan C. Tutcher  President and Director  (Principal Executive Officer) |   | M.A. Maki  Vice President—Finance  (Principal Financial Officer) |
| /s/ J.A.  CONNELLY                                                    |   | /s/ E.C.  HAMBROOK                                                    |
| J.A. Connelly  Director                                               |   | E.C. Hambrook  Director                                               |
| /s/ G.K.  PETTY                                                       |   | /s/ P.D.  DANIEL                                                      |
| G.K. Petty  Director                                                  |   | P.D. Daniel  Director                                                 |
| /s/ M.O.  HESSE                                                       |   | /s/ J.R.  BIRD                                                        |
| M.O. Hesse  Director                                                  |   | J.R. Bird  Director                                                   |

 

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**Index to Exhibits**

Eachexhibit identified below is filed as a part of this Annual report. Exhibitsincluded in this filing are designated by an asterisk; all exhibits not sodesignated are incorporated by reference to a prior filing as indicated.Exhibits designated with a “+” constitute a management contract or compensatoryplan arrangement required to be filed as an exhibit to this report pursuant toItem 15(c) of Form 10-K.
| Exhibit   Number | ** ** | **Description**                                                                                                                                                                                                                                                                                                                                          |
|------------------|------------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
|   3.1  |       | Certificate of Limited Partnership of the  Partnership (Exhibit 3.1 to the Partnership’s Registration Statement  No. 33-43425).                                                                                                                                                                                                           |
|   3.2  |       | Certificate of Amendment to Certificate of Limited  Partnership of the Partnership (Exhibit 3.2 to the Partnership’s 2000  Form 10-K/A dated October 9, 2001).                                                                                                                                                                       |
|   3.3  |       | Third Amended and Restated Agreement of Limited  Partnership of the Partnership (Exhibit 3.1 to the Partnership’s  Quarterly Report on Form 10-Q filed on November 14, 2002).                                                                                                                                                        |
|   4.1  |       | Form of Certificate representing Class A  Common Units (Exhibit 4.1 to the Partnership’s 2000 Form 10-K/A  dated October 9, 2001).                                                                                                                                                                                         |
| 10.1             |       | Contribution, Conveyance and Assumption Agreement,  dated December 27, 1991, among Lakehead Pipe Line Company, Inc.,  Lakehead Pipe Line Partners, L.P. and Lakehead Pipe Line Company, Limited  Partnership. (Exhibit 10.10 to the Partnership’s 1991 Form 10-K).                                                              |
| 10.2             |       | LPL Contribution and Assumption Agreement, dated  December 27, 1991, among Lakehead Pipe Line Company, Inc., Lakehead  Pipe Line Partners, L.P. and Lakehead Pipe Line Company, Limited Partnership  and Lakehead Services, Limited Partnership. (Exhibit 10.11 to the  Partnership’s 1991 Form 10-K).                          |
| 10.3             |       | Contribution Agreement (Exhibit 10.1 to the  Partnership’s Registration Statement on Form S-3/A filed on  July 8, 2002).                                                                                                                                                                                                             |
| 10.4             |       | First Amendment to Contribution Agreement  (Exhibit 10.8 to the Partnership’s Registration Statement on Form S-3/A  filed on September 24, 2002).                                                                                                                                                                                    |
| 10.5             |       | Second Amendment to Contribution Agreement  (Exhibit 99.3 to the Partnership’s Current Report on Form 8-K  filed on October 31, 2002).                                                                                                                                                                                               |
| 10.6             |       | Delegation of Control Agreement (Exhibit 10.2  to the Partnership’s Quarterly Report on Form 10-Q filed on  November 14, 2002).                                                                                                                                                                                                      |
| 10.7             |       | First Amending Agreement to the Delegation of  Control Agreement dated as of February 21, 2005 (Exhibit 10.1 to the  Partnership’s Quarterly Report on Form 10-Q filed on May 5, 2005).                                                                                                                                                        |
| 10.8             |       | Amended and Restated Treasury Services Agreement  (Exhibit 10.3 to the Partnership’s Quarterly Report on Form 10-Q  filed on November 14, 2002).                                                                                                                                                                                     |
| 10.9             |       | Operational Services Agreement (Exhibit 10.4 to  the Partnership’s Quarterly Report on Form 10-Q filed on  November 14, 2002).                                                                                                                                                                                                       |
| 10.10            |       | General and Administrative Services Agreement  (Exhibit 10.5 to the Partnership’s Quarterly Report on Form 10-Q  filed on November 14, 2002).                                                                                                                                                                                        |
| 10.11            |       | Omnibus Agreement (Exhibit 10.6 to the  Partnership’s Quarterly Report on Form 10-Q filed on  November 14, 2002).                                                                                                                                                                                                                    |
| 10.12            |       | Amended and Restated Credit Agreement, dated  January 24, 2003, among Enbridge Energy Partners, L.P., Bank of America,  N.A., as administrative agent, and the lenders party thereto  (Exhibit 10.11 to the Partnership’s Annual Report on Form 10-K  filed on March 28, 2003).                                                 |
| 10.13            |       | First Amendment, dated January 12, 2004, to  Amended and Restated Credit Agreement, dated January 24, 2003, among  Enbridge Energy Partners, L.P., Bank of America, N.A., as administrative  agent, and the lenders party thereto (Exhibit 10.1 to the Partnership’s  Quarterly Report on Form 10-Q filed on May 4, 2004). |

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| 10.14 |   | Second Amendment, dated April 26, 2004, to  Amended and Restated Credit Agreement, dated January 24, 2003, among  Enbridge Energy Partners, L.P., Bank of America, N.A., as administrative  agent, and the lenders party thereto (Exhibit 10.2 to the Partnership’s  Quarterly Report on Form 10-Q filed on May 4, 2004).                                                                                                                                                                                              |
|-------|--------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 10.15 |   | Third Amendment to the Amended and Restated Credit  Agreement, dated as of January 24, 2003 (as amended by the First  Amendment, dated January 12, 2004 and the Second Amendment, dated as of  April 26, 2004), by and the Partnership, the lenders from time to time  parties thereto, and Bank of America, N.A., as administrative agent  (incorporated by reference to Exhibit 10.1 to the Partnership’s Current  Report on Form 8-K filed on April 19, 2005).                                                 |
| 10.16 |   | Fourth Amendment to the Amended and Restated Credit  Agreement, dated January 24, 2003 (as amended by the First Amendment,  dated January 12, 2004, the Second Amendment, dated April 26, 2004,  and the Third Amendment dated April 14, 2005), by and among the  Partnership, the lenders from time to time parties thereto, and Bank of  America, N.A., as administrative agent (incorporated by reference to  Exhibit 10.1 to the Partnership’s Current Report on Form 8-K  filed on September 21, 2005). |
| 10.17 |   | Commercial Paper Dealer Agreement between the  Company, as Issuer, and Banc of America Securities LLC, as Dealer, dated  as of April 21, 2005 (incorporated by reference to exhibit 10.1 to  the Partnership’s Current Report on Form 8-K filed May 3,  2005).                                                                                                                                                                                                                                                         |
| 10.18 |   | Commercial Paper Dealer Agreement between the  Company, as Issuer, and Deutsche Bank Securities Inc., as Dealer, dated  as of April 21, 2005 (incorporated by reference to exhibit 10.2 to  the Partnership’s Current Report on Form 8-K filed May 3,  2005).                                                                                                                                                                                                                                                          |
| 10.19 |   | Commercial Paper Dealer Agreement between the  Company, as Issuer, and Goldman, Sachs & Co., as Dealer, dated  as of April 21, 2005 (incorporated by reference to exhibit 10.3 to  the Partnership’s Current Report on Form 8-K filed May 3,  2005).                                                                                                                                                                                                                                                          |
| 10.20 |   | Commercial Paper Dealer Agreement between the  Company, as Issuer, and Merrill Lynch Money Markets Inc., as Dealer,  dated as of April 21, 2005 (incorporated by reference to  exhibit 10.4 to the Partnership’s Current Report on Form 8-K  filed May 3, 2005).                                                                                                                                                                                                                                                       |
| 10.21 |   | Issuing and Paying Agency Agreement between the  Company and Deutsche Bank Trust Company Americas, dated as of April 21,  2005 (incorporated by reference to exhibit 10.5 to the Partnership’s  Current Report on Form 8-K filed May 3, 2005).                                                                                                                                                                                                                                                                              |
| 10.22 |   | Amended and Restated 364-Day Credit Agreement,  dated January 24, 2003, among Enbridge Energy Partners, L.P., Bank of  America, N.A., as administrative agent, and the lenders party thereto  (Exhibit 10.12 to the Partnership’s Annual Report on Form 10-K  filed on March 28, 2003).                                                                                                                                                                                                                                     |
| 10.23 |   | Subordinated Promissory Note, dated as of  January 24, 2003, given by Enbridge Energy Partners, L.P., as borrower,  to Enbridge Hungary Liquidity Management Limited Liability Company, as lender  (Exhibit 10.13 to the Partnership’s Annual Report on Form 10-K  filed on March 28, 2003).                                                                                                                                                                                                                                |
| 10.24 |   | Subordinated Promissory Note, dated as of  January 24, 2003, given by Enbridge Energy Partners, L.P., as borrower,  to Enbridge Hungary Liquidity Management Limited Liability Company, as lender  (Exhibit 10.14 to the Partnership’s Annual Report on Form 10-K  filed on March 28, 2003).                                                                                                                                                                                                                                |
| 10.25 |   | Subordinated Promissory Note, dated as of  January 24, 2003, given by Enbridge Energy Partners, L.P., as borrower,  to Enbridge (U.S.) Inc., as lender (Exhibit 10.15 to the Partnership’s Annual  Report on Form 10-K filed on March 28, 2003).                                                                                                                                                                                                                                                                            |
| 10.26 |   | Note Agreement and Mortgage, dated December 12,  1991 (Exhibit 10.1 to the Partnership’s 1991 Form 10-K).                                                                                                                                                                                                                                                                                                                                                                                                                        |

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| 10.27  |   | Assumption and Indemnity Agreement, dated  December 18, 1992, between Interprovincial Pipe Line Inc. and  Interprovincial Pipe Line System Inc. (Exhibit 10.4 to the Partnership’s  1992 Form 10-K).                                                                            |
|--------|--------|-----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 10.28  |   | Settlement Agreement, dated August 28, 1996,  between Lakehead Pipe Line Company, Limited Partnership and the Canadian  Association of Petroleum Producers and the Alberta Department of Energy  (Exhibit 10.17 to the Partnership’s 1996 Form 10-K).                           |
| 10.29  |   | Tariff Agreement as filed with the Federal Energy  Regulatory Commission for the System Expansion Program II and Terrace  Expansion Project (Exhibit 10.21 to the Partnership’s 1998 Form 10-K).                                                                                     |
| 10.30  |   | Promissory Note, dated as of September 30,  1998, given by Lakehead Pipe Line Company, Limited Partnership, as borrower,  to Lakehead Pipe Line Company, Inc., as lender (Exhibit 10.19 to  the Partnership’s 1998 Form 10-K).                                             |
| 10.31  |   | Promissory Note, dated as of March 31, 1999,  given by Lakehead Pipe Line Company, Limited Partnership, as borrower, to  Lakehead Pipe Line Company, Inc., as lender. (Exhibit 10.26 to the  Partnership’s 1999 Form 10-K).                                                |
| 10.32  |   | Indenture dated September 15, 1998, between  Lakehead Pipe Line Company, Limited Partnership and the Chase Manhattan Bank  (Exhibit 4.1 to the Lakehead Pipe Line Company, Limited Partnership’s  Current Report on Form 8-K dated October 20, 1998).                      |
| 10.33  |   | First Supplemental Indenture dated  September 15, 1998, between Lakehead Pipe Line Company, Limited  Partnership and the Chase Manhattan Bank (Exhibit 4.2 to the Lakehead  Pipe Line Company, Limited Partnership’s Current Report on Form 8-K  dated October 20, 1998).  |
| 10.34  |   | Second Supplemental Indenture dated  September 15, 1998, between Lakehead Pipe Line Company, Limited  Partnership and the Chase Manhattan Bank (Exhibit 4.3 to the Lakehead  Pipe Line Company, Limited Partnership’s Current Report on Form 8-K  dated October 20, 1998). |
| 10.35  |   | Third Supplemental Indenture dated November 21,  2000, between Lakehead Pipe Line Company, Limited Partnership and the Chase  Manhattan Bank (Exhibit 4.2 to the Lakehead Pipe Line Company, Limited  Partnership’s Current Report on Form 8-K dated November 16,  2000).  |
| 10.36  |   | Indenture dated September 15, 1998, between  Lakehead Pipe Line Company, Limited Partnership and the Chase Manhattan Bank  (Exhibit 4.4 to the Lakehead Pipe Line Company, Limited Partnership’s  Current Report on Form 8-K dated October 20, 1998).                      |
| 10.37+ |   | Executive Employment Agreement, dated May 11,  2001, between Dan C. Tutcher, as Executive, and Enbridge Inc., as Corporation  (Exhibit 10.26 to the Partnership’s Annual Report on Form 10-K  filed on March 28, 2003).                                                    |
| 10.38+ |   | Executive Employment Agreement, dated May 11,  2001, between E. Chris Kaitson, as Executive, and Enbridge Inc., as  Corporation (Exhibit 10.27 to the Partnership’s Annual Report on  Form 10-K filed on March 28, 2003).                                                  |
| 10.39  |   | Indenture dated May 27, 2003, between the  Partnership, as Issuer, and SunTrust Bank, as Trustee (Exhibit 4.5 to  the Partnership’s Registration Statement on Form S-4 filed on  June 30, 2003).                                                                           |
| 10.40  |   | First Supplemental Indenture dated May 27, 2003  between the Partnership and SunTrust Bank (Exhibit 4.5 to the  Partnership’s Registration Statement on Form S-4 filed on  June 30, 2003).                                                                                 |
| 10.41  |   | Second Supplemental Indenture dated May 27,  2003 between the Partnership and SunTrust Bank (Exhibit 4.5 to the  Partnership’s Registration Statement on Form S-4 filed on  June 30, 2003).                                                                                |

100

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| 10.42 |   | Third Supplemental Indenture dated January 9,  2004 between the Partnership and SunTrust Bank (Exhibit 99.3 to the  Partnership’s Current Report on Form 8-K filed on January 9,  2004).   |
|-------|--------|---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 10.43 |   | Fourth Supplemental Indenture dated December 3,  2004 between the Partnership and SunTrust Bank (Exhibit 4.2 to the  Partnership’s Current Report on Form 8-K filed on December 3,  2004). |
| 10.44 |   | Fifth Supplemental Indenture dated December 3,  2004 between the Partnership and SunTrust Bank (Exhibit 4.3 to the  Partnership’s Current Report on Form 8-K filed on December 3,  2004).  |
| 10.45 |   | Common Unit Purchase Agreement (Exhibit 1.1 to  the Partnership’s Current Report on Form 8-K filed on  February 10, 2004.                                                                       |
| 10.46 |   | Common Unit Purchase Agreement (Exhibit 1.1 to  the Partnership’s Current Report on Form 8-K filed on  February 10, 2005.                                                                       |
| 10.47 |   | Common Unit Purchase Agreement (Exhibit 1.1 to  the Partnership’s Current Report on Form 8-K filed on  November  17, 2005.                                                                      |
| 14.1  |   | Code of Ethics for Senior Financial Officers  (Exhibit 14.1 to the Partnership’s Annual Report on Form 10-K  filed on March 12, 2004).                                                          |
| 21.1* |   | Subsidiaries of the Registrant.                                                                                                                                                                                     |
| 23.1* |   | Consent of PricewaterhouseCoopers LLP.                                                                                                                                                                              |
| 31.1* |   | Certification of Chief Executive Officer Pursuant to  Section 302 of the Sarbanes-Oxley Act of 2002.                                                                                                           |
| 31.2* |   | Certification of Chief Financial Officer Pursuant to  Section 302 of the Sarbanes-Oxley Act of 2002.                                                                                                           |
| 32.1* |   | Certification of Chief Executive Officer Pursuant to  Section 906 of the Sarbanes-Oxley Act of 2002.                                                                                                           |
| 32.2* |   | Certification of Chief Financial Officer Pursuant to  Section 906 of the Sarbanes-Oxley Act of 2002.                                                                                                           |
| 99.1  |   | Charter of the Audit, Finance & Risk  Committee of Enbridge Energy Management, L.L.C. (Exhibit 99.1 to the  Partnership’s Annual Report on Form 10-K filed February 25, 2005).                        |

 

Copies of Exhibits may be obtained upon writtenrequest of any Unitholder to Investor Relations, Enbridge Energy Partners,L.P., 1100 Louisiana, Suite 3300, Houston, Texas 77002.

101

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**INDEXTO CONSOLIDATED FINANCIAL STATEMENTS,SUPPLEMENTARY INFORMATION ANDCONSOLIDATED FINANCIAL STATEMENT SCHEDULESENBRIDGE ENERGY PARTNERS, L.P.**

| ** **                                                                                                           | ** ** | **Page** |
|----------------------------------------------------------------------------------------------------------------------|------------|----------|
| **Financial Statements**                                                                                             |       |     |
| Report of Independent Registered Public Accounting  Firm                                                             |       | F-2      |
| Consolidated Statements of Income for each of the years  ended December 31, 2005, 2004 and 2003                 |       | F-4      |
| Consolidated Statements of Comprehensive Income for  each of the years ended December 31, 2005, 2004 and 2003   |       | F-5      |
| Consolidated Statements of Cash Flows for each of the  years ended December 31, 2005, 2004 and 2003             |       | F-6      |
| Consolidated Statements of Financial Position as of  December 31, 2005 and 2004                                 |       | F-7      |
| Consolidated Statements of Partners’ Capital for each  of the years ended December 31, 2005, 2004 and 2003 |       | F-8      |
| Notes to the Consolidated Financial Statements                                                                       |       | F-9      |

 

**FINANCIAL STATEMENT SCHEDULES**

Financial statement schedules not included in thisReport have been omitted because they are not applicable or the requiredinformation is either immaterial or shown in the consolidated financialstatements or notes thereto.

F-1

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**Report of Independent Registered Public AccountingFirm**

To the Partners ofEnbridge Energy Partners, L.P.:

We have completed integratedaudits of Enbridge Energy Partners, L.P.’s 2005 and 2004 consolidated financialstatements and of its internal control over financial reporting as of December 31,2005 and an audit of its 2003 consolidated financial statements in accordancewith the standards of the Public Company Accounting Oversight Board (UnitedStates). Our opinions, based on our audits, are presented below.

*Consolidatedfinancial statements*

In our opinion, the consolidatedfinancial statements listed in the accompanying index present fairly, in allmaterial respects, the financial position of Enbridge Energy Partners, L.P. andits subsidiaries (the “Partnership”) at December 31, 2005 and 2004, andthe results of their operations and their cash flows for each of the threeyears in the period ended December 31, 2005 in conformity with accountingprinciples generally accepted in the United States of America. These financialstatements are the responsibility of the Partnership’s management. Ourresponsibility is to express an opinion on these financial statements based onour audits. We conducted our audits of these statements in accordance with thestandards of the Public Company Accounting Oversight Board (United States). Thosestandards require that we plan and perform the audit to obtain reasonableassurance about whether the financial statements are free of materialmisstatement. An audit of financial statements includes examining, on a testbasis, evidence supporting the amounts and disclosures in the financialstatements, assessing the accounting principles used and significant estimatesmade by management, and evaluating the overall financial statementpresentation. We believe that our audits provide a reasonable basis for ouropinion.

*Internal controlover financial reporting*

Also, in our opinion, management’s assessment,included in Management’s Report on Internal Control Over Financial Reportingappearing under Item 9A, that the Partnership maintained effective internalcontrol over financial reporting as of December 31, 2005 based on criteriaestablished in *Internal Control—Integrated Framework*issued bythe Committee of Sponsoring Organizations of the Treadway Commission (“COSO”),is fairly stated, in all material respects, based on those criteria.Furthermore, in our opinion, the Partnership maintained, in all materialrespects, effective internal control over financial reporting as of December 31,2005, based on criteria established in *Internal Control—Integrated Framework*issuedby the COSO. The Partnership’s management is responsible for maintainingeffective internal control over financial reporting and for its assessment ofthe effectiveness of internal control over financial reporting. Ourresponsibility is to express opinions on management’s assessment and on theeffectiveness of the Partnership’s internal control over financial reportingbased on our audit. We conducted our audit of internal control over financialreporting in accordance with the standards of the Public Company AccountingOversight Board (United States). Those standards require that we plan andperform the audit to obtain reasonable assurance about whether effectiveinternal control over financial reporting was maintained in all materialrespects. An audit of internal control over financial reporting includesobtaining an understanding of internal control over financial reporting,evaluating management’s assessment, testing and evaluating the design andoperating effectiveness of internal control, and performing such otherprocedures as we consider necessary in the circumstances. We believe that ouraudit provides a reasonable basis for our opinions.

A company’s internal control over financial reportingis a process designed to provide reasonable assurance regarding the reliabilityof financial reporting and the preparation of financial statements for externalpurposes in accordance with generally accepted accounting principles. A company’sinternal control over financial reporting includes those policies andprocedures that (i) pertain to the maintenance 

F-2

----

of records that, inreasonable detail, accurately and fairly reflect the transactions anddispositions of the assets of the company; (ii) provide reasonableassurance that transactions are recorded as necessary to permit preparation offinancial statements in accordance with generally accepted accounting principles,and that receipts and expenditures of the company are being made only inaccordance with authorizations of management and directors of the company; and (iii) providereasonable assurance regarding prevention or timely detection of unauthorizedacquisition, use, or disposition of the company’s assets that could have amaterial effect on the financial statements.

Because of its inherentlimitations, internal control over financial reporting may not prevent ordetect misstatements. Also, projections of any evaluation of effectiveness tofuture periods are subject to the risk that controls may become inadequatebecause of changes in conditions, or that the degree of compliance with thepolicies or procedures may deteriorate.

** **

** **

**PricewaterhouseCoopers LLP**

**Houston, Texas**

**February 22, 2006**

F-3

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** **

**ENBRIDGE ENERGY PARTNERS, L.P.CONSOLIDATED STATEMENTS OFINCOME**

| ** **                                                          | ** ** | **Year ended December 31,**                                                       | ** ** |
|---------------------------------------------------------------------|------------|--------------------------------------------------------------------------------------------------|------------|
| ** **                                                          | ** ** | **2005**                                                                                         | ** ** | **2004** | ** ** | **2003** | ** ** |
| ** **                                                          | ** ** | **(dollars and units in millions,  except per unit amounts)** | ** ** |
| Operating revenue                                                   |       | $                                                                                                | 6,476.9    |   | $ | 4,291.7 |   | $ | 3,172.3 |   |
| Operating  expenses                                                 |       |                                                                                             |       |   |   |   |   |
| Cost of natural gas (Note 15)                                       |       | 5,763.3                                                                                          |       | 3,587.1 |   | 2,612.7 |   |
| Operating and administrative                                        |       | 326.8                                                                                            |       | 274.1 |   | 211.8 |   |
| Power                                                               |       | 74.8                                                                                             |       | 72.8 |   | 56.1 |   |
| Depreciation and amortization (Note 6)                              |       | 138.2                                                                                            |       | 120.5 |   | 97.4 |   |
| Gain on sale of  assets                                             |       | (18.1                                                                                            | )          | — |   | — |   |
|                                                                |       | 6,285.0                                                                                          |       | 4,054.5 |   | 2,978.0 |   |
| Operating income                                                    |       | 191.9                                                                                            |       | 237.2 |   | 194.3 |   |
| Interest expense                                                    |       | (107.7                                                                                           | )          | (88.4 | ) | (85.0 | ) |
| Rate refunds  (Note 13)                                             |       | —                                                                                           |       | (13.6 | ) | — |   |
| Other income                                                        |       | 5.0                                                                                              |       | 3.0 |   | 2.4 |   |
| Net income                                                          |       | $                                                                                                | 89.2       |   | $ | 138.2 |   | $ | 111.7 |   |
| Net income  allocable to common and i-units                         |       | $                                                                                                | 65.7       |   | $ | 115.7 |   | $ | 92.1 |   |
| Net income per  common and i-unit (basic and diluted) (Note 4) |       | $                                                                                                | 1.06       |   | $ | 2.06 |   | $ | 1.93 |   |
| Weighted average  units outstanding                                 |       | 62.1                                                                                             |       | 56.1 |   | 47.7 |   |
| Cash distributions paid  per unit                                   |       | $                                                                                                | 3.70       |   | $ | 3.70 |   | $ | 3.70 |   |

 

The accompanying notes are an integral part of these consolidatedfinancial statements.

F-4

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**ENBRIDGE ENERGYPARTNERS, L.P.CONSOLIDATED STATEMENTSOF COMPREHENSIVE INCOME**

| ** **                                              | ** ** | **Year ended December 31,** | ** ** |
|---------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                              | ** ** | **2005**                                   | ** ** | **2004** | ** ** | **2003** | ** ** |
| ** **                                              | ** ** | **(dollars in millions)**        | ** ** |
| Net income                                              |       | $                                          | 89.2       |   | $ | 138.2 |   | $ | 111.7 |   |
| Other  comprehensive loss (Notes 14 & 15) |       | (181.3                                     | )          | (56.8 | ) | (47.7 | ) |
| Comprehensive (loss)  income                            |       | $                                          | (92.1      | ) | $ | 81.4 |   | $ | 64.0 |   |

 

The accompanying notes are an integral part of these consolidatedfinancial statements.

F-5

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**ENBRIDGE ENERGY PARTNERS, L.P.CONSOLIDATED STATEMENTSOF CASH FLOWS**

| ** **                                                                         | ** ** | **Year ended December 31,** | ** ** |
|------------------------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                                         | ** ** | **2005**                                   | ** ** | **2004** | ** ** | **2003** | ** ** |
| ** **                                                                         | ** ** | **(dollars in millions)**        | ** ** |
| Cash provided by operating activities                                              |       |                                       |       |   |   |   |   |
| Net income                                                                         |       | $                                          | 89.2       |   | $ | 138.2 |   | $ | 111.7 |   |
| Adjustments to reconcile net income to net cash  provided by operating activities: |       |                                       |       |   |   |   |   |
| Depreciation and  amortization (Note 6)                                       |       | 138.2                                      |       | 120.5 |   | 97.4 |   |
| Derivative fair value  loss (Note 15)                                         |       | 58.4                                       |       | 3.2 |   | 0.3 |   |
| Environmental  liabilities (Note 12)                                          |       | —                                     |       | (2.0 | ) | — |   |
| Gain on sale of asset (Note 3)                                                |       | (18.1                                      | )          | — |   | — |   |
| Other                                                                              |       | (0.3                                       | )          | 0.4 |   | (0.7 | ) |
| Changes in operating assets and liabilities, net of  cash acquired:                |       |                                       |       |   |   |   |   |
| Receivables, trade and  other                                                      |       | (38.0                                      | )          | (25.4 | ) | (21.0 | ) |
| Due from General Partner  and affiliates                                           |       | (12.4                                      | )          | (0.5 | ) | (7.2 | ) |
| Accrued receivables                                                                |       | (237.1                                     | )          | (128.5 | ) | (59.2 | ) |
| Inventory                                                                          |       | (57.5                                      | )          | (60.8 | ) | (10.2 | ) |
| Current and long-term  other assets                                                |       | (2.2                                       | )          | 15.3 |   | (14.6 | ) |
| Due to General Partner  and affiliates                                             |       | 2.6                                        |       | 8.1 |   | (8.7 | ) |
| Accounts payable and  other                                                        |       | 41.7                                       |       | 36.8 |   | (34.1 | ) |
| Accrued purchases                                                                  |       | 295.3                                      |       | 120.8 |   | 76.6 |   |
| Interest payable                                                                   |       | 8.8                                        |       | 14.5 |   | 15.9 |   |
| Property and other taxes  payable                                                  |       | (1.5                                       | )          | 4.8 |   | 2.0 |   |
| Net cash provided by  operating activities                                         |       | 267.1                                      |       | 245.4 |   | 148.2 |   |
| Cash used in investing activities                                                  |       |                                       |       |   |   |   |   |
| Additions to property,  plant and equipment                                        |       | (344.8                                     | )          | (288.8 | ) | (129.3 | ) |
| Changes in construction  payables                                                  |       | 2.8                                        |       | 10.0 |   | (7.5 | ) |
| Asset acquisitions, net  of cash acquired (Note 3)                            |       | (186.4                                     | )          | (141.0 | ) | (294.2 | ) |
| Proceeds from sale of  assets (Note 3)                                        |       | 105.4                                      |       | — |   | — |   |
| Settlement of natural  gas collars (Note 3 and 15)                                 |       | (16.3                                      | )          | — |   | — |   |
| Other                                                                              |       | 2.2                                        |       | 0.7 |   | — |   |
| Net cash used in  investing activities                                             |       | (437.1                                     | )          | (419.1 | ) | (431.0 | ) |
| Cash provided by financing activities                                              |       |                                       |       |   |   |   |   |
| Proceeds from unit  issuances, net (Note 10)                                       |       | 268.6                                      |       | 194.2 |   | 414.4 |   |
| Distributions to  partners (Note 10)                                               |       | (210.6                                     | )          | (191.0 | ) | (156.7 | ) |
| Repayments of credit  facilities, net                                              |       | (175.0                                     | )          | (280.0 | ) | (9.0 | ) |
| Net issuances of  commercial paper                                                 |       | 330.0                                      |       | — |   | — |   |
| Proceeds from issuance  of senior notes, net of issue costs                        |       | —                                     |       | 495.4 |   | 396.3 |   |
| Repayments to the  General Partner and affiliates                                  |       | —                                     |       | — |   | (327.1 | ) |
| Repayments of First  Mortgage Notes                                                |       | (31.0                                      | )          | (31.0 | ) | (31.0 | ) |
| Other                                                                              |       | (0.5                                       | )          | — |   | — |   |
| Net cash provided by  financing activities                                         |       | 181.5                                      |       | 187.6 |   | 286.9 |   |
| Net increase in cash and  cash equivalents                                         |       | 11.5                                       |       | 13.9 |   | 4.1 |   |
| Cash and cash  equivalents at beginning of year                                    |       | 78.3                                       |       | 64.4 |   | 60.3 |   |
| Cash and cash equivalents at end of year                                           |       | $                                          | 89.8       |   | $ | 78.3 |   | $ | 64.4 |   |

 

The accompanying notes are an integral part ofthese consolidated financial statements.

F-6

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**ENBRIDGE ENERGY PARTNERS, L.P.CONSOLIDATED STATEMENTSOF FINANCIAL POSITION**

| ** **                                                                                             | ** ** | **December 31,**               | ** ** |
|--------------------------------------------------------------------------------------------------------|------------|-------------------------------------|------------|
| ** **                                                                                             | ** ** | **2005**                            | ** ** | **2004** | ** ** |
| ** **                                                                                             | ** ** | **(dollars in millions)** | ** ** |
| **ASSETS**                                                                                             |       |                                |       |   |   |
| Current assets                                                                                         |       |                                |       |   |   |
| Cash and cash equivalents (Note 2)                                                                     |       | $                                   | 89.8       |   | $ | 78.3 |   |
| Receivables, trade and other, net of allowance for  doubtful accounts of $4.5 in 2005 and $4.0 in 2004 |       | 109.7                               |       | 71.7 |   |
| Due from General Partner and affiliates                                                                |       | 20.1                                |       | 7.7 |   |
| Accrued receivables                                                                                    |       | 615.3                               |       | 378.2 |   |
| Inventory (Note 5)                                                                                     |       | 138.9                               |       | 84.5 |   |
| Other current assets                                                                                   |       | 11.5                                |       | 13.4 |   |
|                                                                                                   |       | 985.3                               |       | 633.8 |   |
| Property, plant  and equipment, net (Note 6)                                                           |       | 3,080.0                             |       | 2,778.0 |   |
| Other assets, net  (Note 15)                                                                           |       | 22.2                                |       | 27.7 |   |
| Goodwill (Note 7)                                                                                      |       | 258.2                               |       | 257.2 |   |
| Intangibles, net  (Note 8)                                                                             |       | 82.7                                |       | 74.0 |   |
|                                                                                                   |       | $                                   | 4,428.4    |   | $ | 3,770.7 |   |
| **LIABILITIES AND PARTNERS’ CAPITAL**                                                             |       |                                |       |   |   |
| Current  liabilities                                                                                   |       |                                |       |   |   |
| Due to General Partner and affiliates                                                                  |       | $                                   | 12.5       |   | $ | 9.9 |   |
| Accounts payable and other (Note 15)                                                                   |       | 247.9                               |       | 136.4 |   |
| Accrued purchases                                                                                      |       | 646.7                               |       | 351.4 |   |
| Interest payable                                                                                       |       | 11.4                                |       | 12.3 |   |
| Property and other taxes payable                                                                       |       | 21.8                                |       | 23.3 |   |
| Current maturities of long-term debt  (Note 9)                                                    |       | 31.0                                |       | 31.0 |   |
|                                                                                                   |       | 971.3                               |       | 564.3 |   |
| Long-term  debt (Note 9)                                                                               |       | 1,682.9                             |       | 1,559.4 |   |
| Loans from  General Partner and affiliates (Note 11)                                              |       | 151.8                               |       | 142.1 |   |
| Environmental  liabilities (Note 12)                                                              |       | 4.8                                 |       | 5.3 |   |
| Other long-term  liabilities (Note 15)                                                                 |       | 253.8                               |       | 101.7 |   |
|                                                                                                   |       | 3,064.6                             |       | 2,372.8 |   |
| Commitments and  contingencies (Note 13)                                                          |       |                                |       |   |   |
| Partners’ capital  (Note 10)                                                                      |       |                                |       |   |   |
| Class A common units (Units issued—49,938,834  in 2005 and 44,296,134 in 2004)               |       | 1,142.4                             |       | 1,021.6 |   |
| Class B common units (Units issued—3,912,750 in  2005 and 2004)                              |       | 67.2                                |       | 66.7 |   |
| i-units (Units issued—11,704,948 in 2005 and  10,902,409 in 2004)                                 |       | 421.7                               |       | 399.4 |   |
| General Partner                                                                                        |       | 34.6                                |       | 31.0 |   |
| Accumulated other comprehensive loss (Note  14 & 15)                                          |       | (302.1                              | )          | (120.8 | ) |
|                                                                                                   |       | 1,363.8                             |       | 1,397.9 |   |
|                                                                                                   |       | $                                   | 4,428.4    |   | $ | 3,770.7 |   |

 

The accompanying notes are an integral part ofthese consolidated financial statements.

F-7

----

**ENBRIDGE ENERGY PARTNERS, L.P.CONSOLIDATED STATEMENTSOF PARTNERS’ CAPITAL**

| ** **                                                    | ** ** | **Year ended December 31,** | ** ** |
|---------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                    | ** ** | **2005**                                   | ** ** | **2004** | ** ** | **2003** | ** ** |
| ** **                                                    | ** ** | **Units**                                  | ** ** | **Amount** | ** ** | **Units** | ** ** | **Amount** | ** ** | **Units** | ** ** | **Amount** | ** ** |
| ** **                                                    | ** ** | **(dollars in millions)**        | ** ** |
| **Class A common units:**                                |       |                                       |       |   |   |   |   |   |   |   |   |   |   |
| Beginning balance                                             |       | 44,296,134                                 |       | $ | 1,021.6 |   | 40,166,134 |   | $ | 914.9 |   | 31,313,634 |   | $ | 604.8 |   |
| Net income allocation                                         |       | —                                     |       | 48.9 |   | — |   | 85.4 |   | — |   | 64.9 |   |
| Allocation of proceeds  and issuance costs from unit issuance |       | 5,642,700                                  |       | 242.7 |   | 4,130,000 |   | 175.0 |   | 8,852,500 |   | 368.2 |   |
| Distributions                                                 |       | —                                     |       | (170.8 | ) | — |   | (153.7 | ) | — |   | (123.0 | ) |
| Ending balance                                                |       | 49,938,834                                 |       | 1,142.4 |   | 44,296,134 |   | 1,021.6 |   | 40,166,134 |   | 914.9 |   |
| **Class B common units:**                                |       |                                       |       |   |   |   |   |   |   |   |   |   |   |
| Beginning balance                                             |       | 3,912,750                                  |       | 66.7 |   | 3,912,750 |   | 64.2 |   | 3,912,750 |   | 48.7 |   |
| Net income allocation                                         |       | —                                     |       | 4.8 |   | — |   | 8.7 |   | — |   | 8.3 |   |
| Allocation of proceeds  and issuance costs from unit issuance |       | —                                     |       | 10.2 |   | — |   | 8.2 |   | — |   | 21.7 |   |
| Distributions                                                 |       | —                                     |       | (14.5 | ) | — |   | (14.4 | ) | — |   | (14.5 | ) |
| Ending balance                                                |       | 3,912,750                                  |       | 67.2 |   | 3,912,750 |   | 66.7 |   | 3,912,750 |   | 64.2 |   |
| **i-units:**                                                  |       |                                       |       |   |   |   |   |   |   |   |   |   |   |
| Beginning balance                                             |       | 10,902,409                                 |       | 399.4 |   | 10,062,170 |   | 370.7 |   | 9,228,655 |   | 335.6 |   |
| Net income allocation                                         |       | —                                     |       | 12.0 |   | — |   | 21.6 |   | — |   | 18.9 |   |
| Allocation of proceeds  and issuance costs from unit issuance |       | —                                     |       | 10.3 |   | — |   | 7.1 |   | — |   | 16.2 |   |
| Distributions                                                 |       | 802,539                                    |       | — |   | 840,239 |   | — |   | 833,515 |   | — |   |
| Ending balance                                                |       | 11,704,948                                 |       | 421.7 |   | 10,902,409 |   | 399.4 |   | 10,062,170 |   | 370.7 |   |
| **General Partner:**                                          |       |                                       |       |   |   |   |   |   |   |   |   |   |   |
| Beginning balance                                             |       |                                       |       | 31.0 |   |   |   | 27.5 |   |   |   | 18.8 |   |
| Net income allocation                                         |       |                                       |       | 23.5 |   |   |   | 22.5 |   |   |   | 19.6 |   |
| Allocation of proceeds  and issuance costs from unit issuance |       |                                       |       | (0.3 | ) |   |   | (0.2 | ) |   |   | (0.3 | ) |
| General Partner  contribution                                 |       |                                       |       | 5.7 |   |   |   | 4.1 |   |   |   | 8.6 |   |
| Distributions                                                 |       |                                       |       | (25.3 | ) |   |   | (22.9 | ) |   |   | (19.2 | ) |
| Ending balance                                                |       |                                       |       | 34.6 |   |   |   | 31.0 |   |   |   | 27.5 |   |
| **Accumulated other comprehensive loss:**                     |       |                                       |       |   |   |   |   |   |   |   |   |   |   |
| Beginning balance                                             |       |                                       |       | (120.8 | ) |   |   | (64.0 | ) |   |   | (16.3 | ) |
| Unrealized loss on  derivative financial instruments          |       |                                       |       | (181.3 | ) |   |   | (56.8 | ) |   |   | (47.7 | ) |
| Ending balance                                                |       |                                       |       | (302.1 | ) |   |   | (120.8 | ) |   |   | (64.0 | ) |
| Partners’ capital at December 31,                   |       |                                       |       | $ | 1,363.8 |   |   |   | $ | 1,397.9 |   |   |   | $ | 1,313.3 |   |

 

Theaccompanying notes are an integral part of these consolidated financialstatements.

F-8

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**ENBRIDGEENERGY PARTNERS, L.P.NOTES TO THECONSOLIDATED FINANCIAL STATEMENTS**

**1.PARTNERSHIP ORGANIZATION AND NATURE OF OPERATIONS**

***General***

Enbridge Energy Partners, L.P. and its consolidatedsubsidiaries, referred to herein as “we,” “us,” “our,” and the “Partnership,”is a publicly-traded Delaware limited partnership that owns and operatescrude oil and liquid petroleum transportation and storage assets, and naturalgas gathering, treating, processing, transmission and marketing assets in theUnited States of America. Our Class A Common Units are traded on the NewYork Stock Exchange (“NYSE”) under the symbol “EEP.”

We were formed in 1991 by Enbridge Energy Company, Inc.(our “General Partner”), which is an indirect, wholly-owned subsidiary ofEnbridge Inc. (“Enbridge”) of Calgary, Alberta. We were formed to acquire,own and operate the crude oil and liquid petroleum transportation assets ofEnbridge Energy, Limited Partnership (the “Lakehead Partnership”) which ownsthe United States portion of a crude oil and liquid petroleum pipeline systemextending from western Canada through the upper and lower Great Lakes region ofthe Unites States to eastern Canada.

For several years, we have been diversifyinggeographically and operationally through acquisitions of crude oil gathering,transportation and storage assets, and of natural gas gathering, treating,processing, marketing and transportation systems in the Gulf Coast andmid-continent regions of the United States. We hold our assets in a series oflimited liability companies and limited partnerships that we own directly orindirectly.

Ourownership at December 31, 2005 and 2004 is comprised of the following:

| ** **                                              | ** ** | **2005** | ** ** | **2004** | ** ** |
|---------------------------------------------------------|------------|----------|------------|----------|------------|
| Class A  common units owned by the public          |       | 74.7     | %          | 73.4     | %          |
| Class B  common units owned by our General Partner |       | 5.8      | %          | 6.5      | %          |
| i-units owned by  Enbridge Management                   |       | 17.5     | %          | 18.1     | %          |
| General Partner  interest                               |       | 2.0      | %          | 2.0      | %          |
|                                                    |       | 100.0    | %          | 100.0    | %          |

 

***Enbridge Energy Management, L.L.C.***

Enbridge Energy Management, L.L.C. and its subsidiary,which we refer to as Enbridge Management, is a Delaware limited liabilitycompany, formed in May 2002. Our General Partner, through its directownership of the voting shares of Enbridge Management, elects all of thedirectors of Enbridge Management. Enbridge Management’s Listed Shares aretraded on the NYSE under the symbol “EEQ.” Enbridge Management owns all of aspecial class of our limited partner interests, referred to as “i-units” andreceives its earnings from this investment.

Enbridge Management’sprincipal activity is managing and controlling our business and affairspursuant to a delegation of control agreement with our general partner. TheDelegation of Control Agreement provides that Enbridge Management will notamend or propose to amend our partnership agreement, allow a merger orconsolidation involving us, allow a sale or exchange of all or substantiallyall of our assets or dissolve or liquidate us without the approval of ourgeneral partner. In accordance with its limited liability company agreement,Enbridge Management’s activities are restricted to being our limited partnerand managing our business and affairs.

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***Enbridge Inc.***

Enbridge is the indirectparent of our general partner and is publicly traded on the NYSE and TorontoStock Exchange under the symbol “ENB.” Enbridge is a leader in thetransportation and distribution of energy, with a focus on crude oil andliquids pipelines, natural gas pipelines and natural gas distribution in NorthAmerica. Enbridge also has international interests located in Western Europeand Latin America. At December 31, 2005 and 2004, Enbridge and itsconsolidated subsidiaries owned an effective 10.8% and 11.6% interest in usthrough its ownership in Enbridge Management and our general partner.

***Business Segments***

We conduct our businessthrough three segments: Liquids, Natural Gas, and Marketing.

**Liquids**

Our Liquids segmentincludes the Lakehead, North Dakota, and the Mid-Continent systems. OurLakehead system consists of an interstate common carrier crude oil and liquidpetroleum pipeline that is regulated by the Federal Energy RegulatoryCommission, or FERC, and storage assets, all of which are located in the GreatLakes and Midwest regions of the United States. Our Lakehead system, togetherwith the Enbridge system in Canada owned by Enbridge, forms the longest liquidpetroleum pipeline in the world. The Lakehead system, which spans approximately3,300 miles, has been in operation for over 50 years and is the primarytransporter of crude oil and liquid petroleum from western Canada to the UnitedStates. The Lakehead system serves all the major refining centers in the GreatLakes and Midwest regions of the United States and the province of Ontario,Canada. Our North Dakota system includes approximately 330 miles of crude oilgathering lines connected to an interstate transportation line that isapproximately 620 miles long and is regulated by the FERC. The North Dakotasystem connects directly into the Lakehead system in the state of Minnesota.Our Mid-Continent system consists of over 480 miles of crude oil pipelinesincluding the FERC-regulated Ozark pipeline and approximately 11.9 millionbarrels of storage capacity, which serves refineries in the U.S. Mid-Continentregion from Cushing, Oklahoma.

**Natural Gas**

Our Natural Gas segment consists of natural gasgathering and transmission pipelines, treating and processing plants andrelated facilities. Our Natural Gas segment includes eight natural gas treatingplants and 15 natural gas processing plants at December 31, 2005,excluding plants that are inactive. In addition, our Natural Gas segmentincludes approximately 11,000 miles of natural gas gathering and transmissionpipelines, as well as trucks, trailers and rail cars used for transportingnatural gas liquids (“NGL” or “NGLs”), crude oil and carbon dioxide.

Our Natural Gas segmentalso includes four FERC regulated natural gas transmission pipeline systemslocated in the mid-continent and Gulf Coast regions of the United States.

**Marketing**

Our Marketing segment primarily provides natural gassupply, transportation, balancing, storage and sales services for producers andwholesale customers on our natural gas pipelines as well as otherinterconnected natural gas pipeline systems. We primarily undertake marketingactivities to increase the utilization of our natural gas pipelines, realizeincremental margin on gas purchased at the wellhead, and provide value-addedservices to customers.

Our Marketing businesspurchases third-party pipeline transportation capacity which provides ourcustomers with access to natural gas markets that might not be directlyaccessible from our existing natural gas pipelines. Our Marketing business alsopurchases third-party storage capacity which permits us to 

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injectand store natural gas over various periods of time for withdrawal as theseproducts become needed by end users of natural gas. These contracts may bedenoted as firm transportation, interruptible transportation, firm storage,interruptible storage, or parking and lending services. These various contractstructures are used to mitigate risk associated with our natural gas purchaseand sale contracts and to provide us with opportunities to competitively marketthe natural gas and NGL products.

**2.SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES**

We prepare ourconsolidated financial statements in accordance with accounting principlesgenerally accepted in the United States of America (“GAAP”). The preparation ofour consolidated financial statements requires us to make estimates andassumptions that affect the reported amounts of assets, liabilities, revenues,expenses and the disclosure of contingent assets and liabilities. We regularlyevaluate these estimates, utilizing historical experience, consultation withexperts and other methods we consider reasonable in the circumstances.Nevertheless, actual results may differ significantly from these estimates. Werecord the effect of any revisions to these estimates in our consolidatedfinancial statements in the period in which the facts that give rise to therevision become known.

***Basis of Presentation and Principles of Consolidation***

The consolidated financialstatements include the accounts of the Partnership and its wholly-ownedsubsidiaries on a consolidated basis. All significant intercompany items havebeen eliminated in consolidation.

***Regulation***

Certain of our liquids and natural gas activities aresubject to regulation by the FERC and various state authorities. Regulatorybodies exercise statutory authority over matters such as construction, ratesand underlying accounting practices, and ratemaking agreements with customers.

Certain of the natural gassystems are subject to the provisions of Statement of Financial AccountingStandards (“SFAS”) No. 71, *Accountingfor the Effects of Certain Types of Regulation.* Accordingly, certainassets and liabilities that result from the regulated ratemaking process arerecorded that would not be recorded for non-regulated entities under US GAAP.

***Revenue Recognition and the Use of Estimates forRevenues and Cost of Natural Gas***

**Liquids**

Revenues of our Liquidssegment are primarily derived from two sources, interstate transportation ofcrude oil and liquid petroleum under tariffs regulated by the FERC and contractstorage revenues related to the Partnership’s tankage assets. The tariffsspecify the amounts to be paid by shippers for service between receipt anddelivery locations and the general terms and conditions of transportationservices on the respective pipeline systems. Revenues are recognized upondelivery to customers of products, as pricing is determinable andcollectibility is reasonably assured. The contract storage revenues arerecognized based on contractual terms under which customers pay for the optionof availability of storage capacity and /or a fee based on through-put volumes.Revenues are recognized as storage services are rendered, pricing isdeterminable and collectibility is reasonably assured. In the Liquids segment,we generally do not own the crude oil and liquid petroleum that we transportsor store, and therefore, we do not assume significant direct commodity risk.

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**Natural Gas**

We recognize revenue upon delivery of natural gas andNGLs to customers, and/or when services are rendered, pricing is determinableand collectibility is reasonably assured. We derive revenue in our Natural Gassegment from the following types of arrangements:

*Fee-BasedArrangements:*

Under a fee-basedcontract, we receive a set fee for gathering, treating, processing andtransporting raw natural gas and providing other similar services. Theserevenues correspond with the volumes and types of services provided and do notdepend directly on commodity prices. Revenues of the Natural Gas segment thatare derived from transmission services consist of reservation fees charged fortransmission of natural gas on the FERC-regulated interstate natural gastransmission pipeline systems, while revenues from intrastate pipelines aregenerally derived from the bundled sales of natural gas and transmissionservices. Customers of the FERC-regulated natural gas pipeline systemstypically pay a reservation fee each month to reserve capacity plus a nominalcommodity charge based on actual transmission volumes. Revenues are recognizedas natural gas is delivered to customers or as transportation services arerendered, pricing is determinable and collectibility is reasonably assured.

*Other Arrangements:*

We also use othertypes of arrangements to derive revenues for our Natural Gas segment. Thesearrangements expose us to commodity price risk, which we substantially mitigatewith offsetting physical purchases and sales and by the use of derivativefinancial instruments to hedge open positions. We will continue to hedge asignificant amount of our commodity price risk to support the stability of ourcash flows. Please refer to Note 15 for more information about ourderivative activities.

These other typesof arrangements are categorized as follows:

·       Percentage-of-Index-Contracts—Underthese contracts, we purchase raw natural gas at a negotiated discount to anagreed upon index price. We then resell the natural gas, generally for theindex price, keeping the difference as our fee.

·       Percentage-of-ProceedsContracts—Under the terms of these contracts, we receive a negotiatedpercentage of the natural gas and NGLs we process in the form of residuenatural gas, NGLs, condensate and sulfur, which we then sell at market pricesand retain as our fee.

·       Percentage-of-LiquidsContracts—Under these contracts, we receive a negotiated percentage of NGLs andcondensate from natural gas that requires processing. This contract structureis similar to percentage-of-proceeds arrangements except that we only receive apercentage of the NGL and condensate.

·       Keep-WholeContracts—Under these contracts, we gather or purchase raw natural gas from theproducer for processing. A portion of the gathered or purchased natural gas isconsumed during processing. We extract and retain the NGLs produced duringprocessing for our own account, which we sell at market prices. In instanceswhere we purchase raw gas at the wellhead, we also sell for our own account theresidue gas resulting from processing at market prices. In those instances whenwe gather and process raw natural gas for the account of the producer, we mustreturn to the producer residue gas with a British thermal unit contentequivalent to the original raw gas we received.

Under the terms ofeach of these contract structures, we retain a portion of the natural gas andNGLs as our fee in exchange for providing these producers with our services. Inorder to protect our unitholders from volatility in our cash flows that canresult from fluctuations in commodity prices, we enter into derivativefinancial instruments to effectively fix the sales price of the natural gas andNGLs we anticipate receiving under the terms of these contracts. As a result ofentering into these derivative financial instruments, we have largely fixed theamount of cash that we will receive in the future when we sell the 

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processed natural gas andNGLs, although the market price of these commodities will continue to fluctuateduring that time.

**Marketing**

Revenues of our Marketingsegment are derived from providing supply, transportation, balancing, storageand sales services for producers and wholesale customers on our natural gaspipelines, as well as other interconnected pipeline systems. Natural gasmarketing activities are primarily undertaken to realize incremental margins ongas purchased at the wellhead, and provide value-added services tocustomers. In general, natural gas purchased and sold by our Marketing businessis priced at a published daily or monthly index price. Sales to wholesalecustomers typically incorporate a premium for managing their transmission andbalancing requirements. Higher premiums and associated margins result fromtransactions that involve smaller volumes or that offer greater serviceflexibility for wholesale customers. At the request of some customers, we willenter into long-term fixed price purchase or sales contracts with our customersand usually will enter into offsetting positions under the same or similarterms. Revenues are recognized upon delivery of natural gas and NGLs tocustomers and/or when services are rendered, pricing is determinable andcollectibility is reasonably assured.

***Use of Estimates***

For our natural gasbusinesses, we must estimate our current month revenue and cost of gas topermit the timely preparation of our consolidated financial statements. Wegenerally cannot compile actual billing information nor obtain actual vendorinvoices within a timeframe that would permit the recording of this actual dataprior to preparation of the consolidated financial statements. As a result, werecord an estimate each month for our operating revenues and cost of naturalgas based on the best available volume and price data for natural gas deliveredand received, along with a true-up of the prior month’s estimate to equal theprior month’s actual data. As a result, there is one month of estimated datarecorded in our operating revenues and cost of natural gas for each of theyears ended December 31, 2005, 2004 and 2003. We believe that theassumptions underlying these estimates will not be significantly different fromactual amounts due to the routine nature of these estimates and the stabilityof our processes.

***Cash and Cash Equivalents***

Cash equivalents are defined as all highly marketablesecurities with maturities of three months or less when purchased. The carryingvalue of cash and cash equivalents approximates fair value because of the shortterm to maturity of these investments.

We extinguish liabilitieswhen a creditor has relieved us of the obligation, which occurs when ourfinancial institution honors a check that the creditor has presented forpayment. As such, included in Accounts Payable and Other are obligations forwhich we have issued check payments that have not yet been presented to thefinancial institution of approximately $46.5 million and $25.3 millionat December 31, 2005 and 2004, respectively.

***Allowance for Doubtful Accounts***

We establish provisionsfor losses on accounts receivable if we determine that we will not collect allor part of the outstanding balance. Collectibility is reviewed regularly and anallowance is established or adjusted, as necessary, using the specificidentification method.

***Inventory***

Inventory includes product inventory and materials andsupplies inventory. All inventories are valued at the lower of cost or market.The product inventory consists of liquids and natural gas. Upon disposition,product inventory is recorded to Cost of natural gas at the weighted averagecost of inventory.

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Materials and suppliesinventory is either used during operations and expensed to operating expenses,or used on capital projects and/or new construction, and capitalized toproperty, plant and equipment.

***Oil Measurement Losses***

Oil measurementlosses occur as part of the normal operating conditions associated with ourLiquids pipelines. The three types of oil measurement losses include:

·       physicallosses, which occur through evaporation, shrinkage, differences in measurementbetween receipt and delivery locations and other operational incidents;

·       degradationlosses, which result from mixing at the interface between higher quality lightcrude oil and lower quality heavy crude oil in pipelines; and

·       revaluationlosses, which are a function of crude oil prices and the level of the carrier’sinventory.

There are inherentdifficulties in quantifying oil measurement losses because physicalmeasurements of volumes are not practical, as products continuously movethrough our pipelines and virtually all of these pipelines are locatedunderground. Quantifying oil measurement losses is especially difficult for usbecause of the length of the pipeline systems and the number of differentgrades of crude oil and types of crude oil products we carry. We utilizeengineering-based models and operational assumptions to estimate productvolumes in our system and associated oil measurement losses. If there is amaterial change in these assumptions, it may result in a revision of oilmeasurement loss estimates in the period determined.

***Operational Balancing Agreements and Natural GasImbalances***

To facilitate deliveriesof natural gas and provide for operational flexibility, we have operationalbalancing agreements in place with other interconnecting pipelines. Theseagreements ensure that the volume of gas a shipper schedules for transportationbetween two interconnecting pipelines equals the volume actually delivered. Ifnatural gas moves between pipelines in volumes that are more or less than thevolumes the shipper previously scheduled, a gas imbalance is created. The imbalancesare settled through periodic cash payments or repaid in kind through thereceipt or delivery of natural gas in the future. Gas imbalances are recordedas current assets or current liabilities on the balance sheet using the postedindex prices, which approximate market rates, or our weighted average cost ofgas.

***Capitalization Policies, Depreciation Methods andImpairment of Property, Plant and Equipment***

We capitalize expenditures related to property, plantand equipment, subject to a minimum rule, that have a useful life greater thanone year for (1) assets purchased or constructed; (2) existing assetsthat are extended, replaced or improved; or (3) all land, regardless ofcost. Acquisitions of new assets, additions, replacements and improvements (otherthan land) costing less than the minimum rule in addition to maintenanceand repair costs are expensed as incurred.

During construction, we capitalize direct costs, suchas labor and materials, and other costs, such as direct overhead and interestat our weighted average cost of debt, and, in our regulated businesses thatapply the provisions of Statement of Financial Accounting Standards No. 71,  *Accounting for the Effects of Certain Types of Regulation,*or SFAS No. 71, an equity return component.

We categorize our capital expenditures as either coremaintenance or enhancement expenditures. Core maintenance expenditures arenecessary to maintain the service capability of our existing assets and includethe replacement of system components and equipment that are worn, obsolete ornear the end of their useful lives. Examples of core maintenance expendituresinclude valve automation programs, cathodic protection, zero-hour compressionoverhauls and electrical switchgear replacement programs. Enhancementexpenditures improve the service capability of our existing assets, extendasset useful lives, increase capacities from existing levels, reduce costs orenhance revenues, and enable us to respond to 

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governmental regulationsand developing industry standards. Examples of enhancement expenditures includefirst-time high resolution integrity tool runs, the costs associated withinstallation of seals, liners and other equipment to reduce the risk ofenvironmental contamination from crude oil storage tanks, costs of sleeving amajor segment of the pipeline system following an integrity tool run andnatural gas or crude oil well-connects, and mainline systems expansions.

Recent regulatory guidance issued by the FERC willrequire us to expense certain costs associated with implementing the pipelineintegrity management requirements of the U.S. Department of Transportation’sOffice of Pipeline Safety. Under this guidance, beginning in January 2006,costs to 1) prepare a plan to implement the program, 2) identify highconsequence areas, 3) develop and maintain a record keeping system and 4)inspect, test and report on the condition of affected pipeline segments todetermine the need for repairs or replacements, are required to be expensed. Weare adopting this guidance prospectively for our SFAS No. 71 companiesonly, namely, our UTOS, Midla, AlaTenn and KPC natural gas transmission systems.Consistent with our prior practice, costs of modifying pipelines to permitin-line inspections, certain costs associated with developing or enhancingcomputer software and costs associated with remedial mitigation actions tocorrect an identified condition will continue to be capitalized for our FERC-regulatedand non-regulated pipeline systems. Additionally, for our non-regulatedpipelines and our FERC-regulated crude oil pipelines that are not eligible toapply the provisions of SFAS No. 71, we will continue to capitalize first-time in-line inspection tool runs andhydrostatic testing costs conducted for the purposes of detecting manufacturingor construction defects, consistent with our historical policy. For regulatoryreporting, our FERC-regulated crude oil pipelines will expense items 1-4listed above. We do not expect our implementation of this regulation tosignificantly affect our financial position, results of operations or cashflows.

We record property, plant and equipment at itsoriginal cost and depreciate our assets over the lesser of their estimateduseful lives or the estimated remaining lives of the crude oil or natural gasproduction in the basins the assets serve. Our determination of the usefullives of property, plant and equipment requires us to make various assumptions,including the supply of and demand for hydrocarbons in the markets served byour assets, normal wear and tear of the facilities, and the extent andfrequency of maintenance programs. We routinely utilize consultants and otherexperts to assist us in assessing the remaining lives of the crude oil ornatural gas production in the basins we serve.

We record depreciation using the group method ofdepreciation which is commonly used by pipelines, utilities and similarentities. Under the group method, for all segments, upon the disposition ofproperty, plant and equipment, the cost less net proceeds is normally chargedto accumulated depreciation and no gain or loss on disposal is recognized. However,when a separately identifiable group of assets, such as a processing plant,treating facility or a pipeline system are sold, we will recognize a gain orloss in our Consolidated Statements of Income for the difference between thecash received and the net book value of the assets sold. Changes in any of ourassumptions may alter the rate at which we recognize depreciation in ourconsolidated financial statements. At regular intervals, we retain the servicesof independent consultants to assist us with assessing the reasonableness ofthe useful lives we have established for the property, plant and equipment ofour major systems. Based on the results of these regular assessments we maymake modifications to the assumptions we use to determine our depreciationrates.

We evaluate therecoverability of our property, plant and equipment when events orcircumstances such as economic obsolescence, the business climate, legal andother factors indicate we may not recover the carrying amount of the assets. Wecontinually monitor our businesses and the market and business environments toidentify indicators that may suggest an asset may not be recoverable. Weevaluate the asset for recoverability by estimating the undiscounted futurecash flows expected to be derived from operating the asset. These cash flowestimates require us to make projections and assumptions for many years intothe future for pricing, demand, competition, operating cost and other factors. Werecognize an impairment loss when the carrying amount of the asset exceeds itsfair value as determined by quoted market prices in active markets or presentvalue techniques if quotes are unavailable. The determination of 

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the fairvalue using present value techniques requires us to make projections andassumptions regarding the probability of a range of outcomes and the rates ofinterest used in the present value calculations. Any changes we make to theseprojections and assumptions could result in significant revisions to ourevaluation of recoverability of our property, plant and equipment and therecognition of an impairment loss in our Consolidated Statements of Income.

***Goodwill***

Goodwill represents the excess of the purchase priceover the fair value of net assets acquired in a business combination. Goodwillis allocated to two of our segments, Natural Gas and Marketing.

Goodwill is not amortized,but is tested for impairment annually based on carrying values as of the end ofthe second quarter, or more frequently if impairment indicators arise thatsuggest the carrying value of goodwill may not be recovered. Impairment occurswhen the carrying amount of a reporting unit exceeds its fair value. At thetime we determine that impairment has occurred, the carrying value of thegoodwill is written down to its fair value. To estimate the fair value of thereporting units, we make estimates and judgments about future cash flows, aswell as revenue, cost of sales, operating expenses, capital expenditures andnet working capital based on assumptions that are consistent with our mostrecent five-year plan, which we use to manage the business. There have been noimpairments recorded in 2005, 2004 or 2003.

***Intangibles, Net***

Intangibles, net, consist of natural gas purchase andsale customer contracts and natural gas supply opportunities, which we amortizeon a straight-line basis over the weighted average useful life of theunderlying assets, which is the period over which the asset is expected tocontribute directly or indirectly to our future cash flows.

We evaluate the carryingvalue of the intangible assets whenever certain events or changes in circumstancesindicate that the carrying amount of these assets may not be recoverable. Inassessing the recoverability of intangibles, we compare the carrying value tothe undiscounted future cash flows the intangibles are expected to generate. Ifthe total of the undiscounted future cash flows is less than the carryingamount of the intangibles, the intangibles are written down to their fairvalue. We did not record any impairments in 2005, 2004, or 2003.

***Other Assets***

Other assets primarilyinclude deferred financing charges, which are amortized on a straight-linebasis, over the life of the related debt and classified as interest expense onthe Consolidated Statements of Income.

***Income Taxes***

We are not a taxableentity for federal and state income tax purposes. Accordingly, no recognitionis given to income taxes for financial reporting purposes. The tax on our netincome is borne by the individual partners through the allocation of taxableincome. Net income for financial statement purposes may differ significantlyfrom taxable income of unitholders as a result of differences between the taxbasis and financial reporting basis of assets and liabilities and the taxableincome allocation requirements under our partnership agreement. The aggregatedifference in the basis of our net assets for financial and tax reportingpurposes cannot be readily determined because information regarding eachpartner’s tax attributes in us is not available.

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***Derivative Financial Instruments***

Our net income and cash flows are subject to volatilitystemming from changes in market prices such as interest rates, natural gasprices, natural gas liquids prices and processing spreads. In order to managethe risks to unitholders, we use a variety of derivative financial instrumentsto create offsetting positions to specific commodity or interest rateexposures. Under SFAS No. 133, *Accountingfor Derivative Instruments and Hedging Activities* (“SFAS No. 133”)all derivative financial instruments are recorded in the balance sheet at theirfair value. We record the fair value of our derivative financial instruments inthe balance sheet as current and long-term assets or liabilities on a net basisby counterparty. For those instruments that qualify for hedge accounting, theaccounting treatment depends on each instrument’s intended use and how it isdesignated. For our derivative financial instruments related to commoditiesthat do not qualify for hedge accounting, the change in market value isrecorded as a component of Cost of natural gas in the Consolidated Statementsof Income. For our derivative financial instruments related to interest ratesthat do not qualify for hedge accounting, the change in market value isrecorded as a component of interest expense in the Consolidated Statements ofIncome.

In implementing our hedging programs, we haveestablished a formal analysis, execution and reporting framework that requiresthe approval of the Board of Directors of Enbridge Management or a committee ofour senior management. We employ derivative financial instruments in connectionwith an underlying asset, liability and/or anticipated transaction and we donot use derivative financial instruments for speculative purposes.

Derivative financial instruments qualifying for hedgeaccounting treatment and in use by the Partnership can generally be dividedinto two categories: 1) cash flow hedges, or 2) fair value hedges. Weenter into cash flow hedges to hedge the variability in cash flows related to aforecasted transaction. We enter into fair value hedges to hedge the value of arecognized asset or liability.

Price assumptions we use to value the cash flow andfair value hedges can affect net income for each period. We use publishedmarket price information where available, or quotations from over-the-counter (“OTC”)market makers to find executable bids and offers. The valuations also reflectthe potential impact of liquidating our position in an orderly manner over areasonable period of time under present market conditions, modeling risk,credit risk of our counterparties and operational risk. The amounts reported inour consolidated financial statements change quarterly as these estimates arerevised to reflect actual results, changes in market conditions or otherfactors, many of which are beyond our control.

At inception, we formally document the relationshipbetween the hedging instrument and the hedged item, the risk managementobjectives, and the methods used for assessing and testing correlation andhedge effectiveness. We also assess, both at the inception of the hedge and onan on-going basis, whether the derivatives that are used in our hedgingtransactions are highly effective in offsetting changes in cash flows or thefair value of the hedged item. Furthermore, we regularly assess the creditworthinessof our counterparties to manage against the risk of default. If we determinethat a derivative is no longer highly effective as a hedge, we discontinuehedge accounting prospectively by including changes in the fair value of thederivative in current earnings.

For cash flow hedges, changes in the derivative fairvalues, to the extent that the hedges are determined to be highly effective,are recorded as a component of accumulated other comprehensive income until thehedged transactions occur and are recognized in earnings. Any ineffectiveportion of a cash flow hedge’s change in value is recognized immediately inearnings. For fair value hedges, the change in value of the financialinstrument is determined each period and is taken into earnings. In conjunctionwith this, the change in the value of the hedged item is also calculated andtaken into earnings. To the extent that the two valuations offset, the hedge iseffective and net earnings is not affected.

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Our earnings are alsoaffected by the use of the mark-to-market method of accounting required underGAAP for certain basis swap financial instruments. Short-term, highly liquidfinancial instruments such as basis swaps and other contracts are used to economicallyhedge market price risks associated with inventories, firm commitments andcertain anticipated transactions, primarily within the Marketing segment. As ofDecember 31, 2005, these basis swap financial instruments, however, didnot qualify for hedge accounting treatment under SFAS No. 133, and thusthe changes in fair value of these instruments are recorded on the balancesheet and through earnings (i.e., using the “mark-to-market” method) ratherthan being deferred until the firm commitment or anticipated transactionaffects earnings. The use of mark-to-market accounting for financialinstruments may cause non-cash earnings to fluctuate based upon changes in theunderlying indices, primarily commodity prices. The fair value of thesefinancial instruments is determined using price data from highly liquid marketssuch as the New York Mercantile Exchange or NYMEX or OTC market makers or othersimilar sources.

***Commitments, Contingencies and EnvironmentalLiabilities***

We expense or capitalize, as appropriate, expendituresfor ongoing compliance with environmental regulations that relate to past orcurrent operations. Amounts for remediation of existing environmentalcontamination caused by past operations, which do not benefit future periods bypreventing or eliminating future contamination, are expensed. Liabilities arerecorded when environmental assessments indicate that remediation efforts areprobable, and the costs can be reasonably estimated. Estimates of theliabilities are based on currently available facts, existing technology andpresently enacted laws and regulations taking into consideration the likelyeffects of inflation and other factors. These amounts also consider priorexperience in remediating contaminated sites, other companies’ clean-up experienceand data released by government organizations. These estimates are subject torevision in future periods based on actual costs or new information and areincluded on the balance sheet in other current and long-term liabilities attheir undiscounted amounts. We evaluate recoveries from insurance coverageseparately from the liability and, when recovery is probable, we record andreport an asset separately from the associated liability in our consolidatedfinancial statements.

We recognize liabilities for other contingencies when,after fully analyzing the available information, we determine it is eitherprobable that an asset has been impaired or that a liability has been incurredand the amount of impairment or loss can be reasonably estimated. When a rangeof probable loss can be estimated, we accrue the most likely amount, or if noamount is more likely than another, the minimum of the range of probable loss.

***Asset Retirement Obligations***

We adopted the provisions of SFAS No. 143, *Accounting for Asset Retirement Obligations*(“SFAS No. 143”) in January 2003. The provisions of SFAS No. 143require us to record a liability for the fair value of asset retirementobligations, on a discounted basis, in the period in which the liability isincurred, which is typically at the time the assets are installed or acquired,if a reasonable estimate of fair value can be made. The provisions also requirethat we capitalize the costs associated with the asset retirement obligationsas part of the carrying cost of the related assets. We recognize an ongoingexpense for the interest component of the liability as part of depreciationexpense resulting from changes in the value of the retirement obligation due tothe passage of time. We depreciate the initial capitalized costs over theuseful lives of the related assets. We extinguish the liabilities for assetretirement obligations when assets are taken out of service or otherwiseabandoned.

In December 2005, we adopted the provisions ofFinancial Accounting Standards Board (“FASB”) Interpretation No. 47, *Accounting for Conditional Asset RetirementObligations, an interpretation of FASB Statement No. 143* (“FIN 47”). FIN 47 requires us torecognize a liability and related asset, consistent with SFAS No. 143, forthe fair value of conditional asset retirement obligations that we canreasonably estimate. FIN 47 also provides specific guidance regarding when anasset retirement obligation is 

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reasonably estimableincluding when sufficient information is available to apply an expected presentvalue technique. As indicated in the table below, our implementation of FIN 47did not have a material effect on our consolidated financial statements.

We have legal obligations requiring us to decommissionour offshore pipeline systems at retirement. In certain rate jurisdictions, weare permitted to include annual charges for removal costs in the regulated costof service rates we charge our customers. Additionally, legal obligations existfor a minority of our onshore right-of-way agreements due to requirements orlandowner options to compel us to remove the pipe at final abandonment. Sufficientdata exists with certain onshore pipeline systems to reasonably estimate anabandonment retirement obligation cost. However, in some cases, there isinsufficient information to reasonably determine the timing and/or method ofsettlement for estimating the fair value of the asset retirement obligation. Inthese cases, the asset retirement obligation cost is considered indeterminatebecause there is no data or information that can be derived from past practice,industry practice, management’s intent, or the asset’s estimated economic life.Useful lives of most pipeline systems are primarily derived from availablesupply resources and ultimate consumer/refinery consumption. Variables canaffect the remaining lives of the assets which preclude us from making areasonable estimate of the asset retirement obligation. Indeterminate assetretirement obligation costs will be recognized in the period in whichsufficient information exists to reasonably estimate potential settlement datesand methods.

We recorded an asset and liability of $2.1 million forasset retirement obligations for the year ended December 31, 2005 in theConsolidated Statement of Financial Position. We recorded accretion expense of$0.5 million, $0.1 million and $0.1 million, respectively, in theConsolidated Statements of Income for the years ended December 31, 2005,2004 and 2003 for previously recorded asset retirement obligation liabilities.

Noassets are legally restricted for purposes of settling our asset retirementobligations for each of the years ended December 31, 2005 and 2004. Followingis a reconciliation of the beginning and ending aggregate carrying amount ofour asset retirement obligation liabilities for each of the years ended December 31,2005 and 2004:

| ** **                               | ** ** | **2005**               | ** ** | **2004** | ** ** |
|------------------------------------------|------------|------------------------|------------|----------|------------|
| ** **                               | ** ** | **(in millions)** | ** ** |
| Balance at  beginning of period          |       | $                      | 1.0        |     | $          | 0.9 |   |
| Implementation of  FIN 47—Liability |       | 2.1                    |       | —   |       |
| Accretion expense                        |       | 0.5                    |       | 0.1      |       |
| Balance at end of period                 |       | $                      | 3.6        |     | $          | 1.0 |   |

 

***Comparative Amounts***

We have madereclassifications to the prior years’ reported amounts to conform to ourpresentation in the 2005 consolidated financial statements. Thesereclassifications were made within the Consolidated Statements of FinancialPosition, Consolidated Statements of Cash Flows, and Segment Information (note16), and have no effect on net income.

***New Accounting Pronouncements***

**AccountingChanges and Error Corrections**

In May 2005, the FASBissued Statement of Financial Accounting Standards No. 154, *Accounting Changes and Error Corrections, a replacement of APB Opinion No. 20and FASB Statement No. 3*. Under this statement, voluntarychanges in accounting principle are required to be applied retrospectively forthe direct effects of a change to prior periods’ financial statements, unlesssuch application is impracticable. Retrospective application refers toreflecting a change in accounting principle in the financial statements 

F-19

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of priorperiods as if the principle had always been used. When retrospectiveapplication is determined to be impracticable, this statement requires the newaccounting principle be applied to the balances of assets and liabilities as ofthe beginning of the earliest period for which retrospective treatment ispracticable with a corresponding adjustment to the opening balance of retainedearnings. This statement retains the guidance in APB Opinion No. 20 forreporting the corrections of errors and changes in accounting estimates. Thisstatement is effective for accounting changes and corrections of errors made infiscal years beginning after December 15, 2005, with early adoptionpermitted. Our adoption of this statement will affect our consolidatedfinancial statements for any changes in accounting principle we may make in thefuture, and new pronouncements we adopt that do not provide transitionprovisions.

**FERCGuidance on Accounting for Integrity Management Costs**

In June 2005, theFERC issued guidance describing how FERC-regulated companies should account forcosts associated with implementing the pipeline integrity managementrequirements of the U.S. Department of Transportation’s Office of PipelineSafety. Under the guidance, costs to 1) prepare a plan to implement theprogram, 2) identify high consequence areas, 3) develop and maintain arecord keeping system and 4) inspect, test and report on the condition ofaffected pipeline segments to determine the need for repairs or replacements,are required to be expensed. Costs of modifying pipelines to permit in-lineinspections, certain costs associated with developing or enhancing computersoftware and costs associated with remedial and mitigation actions to correctan identified condition can be capitalized. The guidance is effective January 1,2006, and will be applied prospectively to our SFAS No. 71 entities.

**3. ACQUISITIONS AND DISPOSITIONS**

We accounted for each ofour completed acquisitions using the purchase method and record the assetsacquired and liabilities assumed at their estimated fair market values as ofthe date of purchase. The results of operations from each of these acquisitionsare included in earnings from the date of the acquisition.

***2005Acquisitions and Dispositions***

**North Texas Natural Gas System**

In January 2005,we acquired natural gas gathering and processing assets in north Texas for$164.6 million in cash, including transaction costs of $0.5 million. The assetswe acquired serve the Fort Worth Basin, which is mature, but experiencingminimal production decline rates and include:

·                    2,200miles of gas gathering pipelines; and

·                    fourprocessing plants with aggregate processing capacity of 121 million cubic feetof natural gas per day (“MMcf/d”).

The system provides cash flow primarily frompurchasing raw natural gas from producers at the wellhead, processing thenatural gas and then selling the natural gas liquids and residue natural gasstreams. The assets and results of operations are included in our Natural Gassegment from the date of acquisition.

F-20

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Thepurchase price and the allocation to assets acquired and liabilities assumedwas as follows (in millions):

| Purchase Price:                                                    |   |   |   |
|--------------------------------------------------------------------|--------|--------|--------|
| Cash paid, including transaction costs                             |   | $      | 164.6  |   |
| Allocation of  purchase price:                                     |   |   |   |
| Property, plant and equipment, including  construction in progress |   | 151.6  |   |
| Intangibles, including contracts                                   |   | 14.3   |   |
| Current liabilities                                                |   | (0.9   | )      |
| Contingent liabilities                                             |   | (0.4   | )      |
| Total                                                              |   | $      | 164.6  |   |

 

**Other 2005 Acquisitions**

In June 2005, weacquired for $20.1 million in cash, a natural gas pipeline and relatedfacilities consisting of 92 miles of 20-inch diameter pipeline thatextends from Pampa, Texas into western Oklahoma and has interconnects with ourAnadarko system. We integrated this pipeline into our existing Anadarko systemand have included the assets and operating results in our Natural Gas segmentfrom the date of acquisition. The purchase price for this acquisition wasallocated to property, plant and equipment for $19.1 million and goodwill for$1.0 million. We also acquired other gathering and processing assets during2005 that are complementary to our existing natural gas systems for cashtotaling approximately $1.7 million.

**Saleof Gathering and Processing Assets**

In December 2005, wesold for $105.4 million in cash, a processing plant and related facilities andother gathering and processing assets located in our East and South Texassystems with a carrying value of approximately $86.9 million. We incurredselling costs of approximately $0.4 million and recognized a gain on the saleof approximately $18.1 million. The facilities we sold represent non-strategicassets within our Natural Gas segment. In connection with this sale, we paidapproximately $16.3 million to settle natural gas collars on 2,000 MMBtu/dassociated with the natural gas produced by these assets and entered intooffsetting derivatives at market to close out derivatives previously classifiedas hedges of 273 Bbl/d of NGL produced by these assets. We had previouslyrecorded unrealized losses associated with the natural gas collars that wererealized upon settlement. Refer to Note 15 for additional discussion regardingderivative transactions. The reported amounts are subject to change pendingfinal settlement of the sale.

***2004Acquisitions***

**Mid-ContinentSystem**

In March 2004,we acquired crude oil pipeline and storage assets, known as the Mid-Continentsystem, for $117.0 million, including transaction costs of$2.0 million. The assets acquired serve refineries in the U.S.Mid-Continent from Cushing, Oklahoma and include:

·       The433-mile Ozark pipeline from Cushing to Wood River, Illinois;

·       A1.2 million barrel storage terminal located in El Dorado, Kansas;

**·****     **The47-mile West Tulsa pipeline in Oklahoma; and

·       Astorage terminal at Cushing, with 8.3 million barrels of storage capacity.

These systems wereacquired to provide cash flows primarily from toll or fee-based revenues from acombination of regulated assets and contracted unregulated assets. The assetsand results of operations are included in our Liquids segment from the date ofacquisition. The value allocated to the assets was determined by an independentappraisal.

F-21

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Thepurchase price and the allocation to assets acquired and liabilities assumedwas as follows:

| ** **                              | ** ** | **(dollars  in millions)** | ** ** |
|-----------------------------------------|------------|---------------------------------|------------|
| Purchase Price:                         |       |                            |       |   |   |
| Cash paid,  including transaction costs |       |                            | $          | 117.0 |   |   |
| Allocation of  purchase price:          |       |                            |       |   |   |
| Property, plant and equipment           |       |                            | $          | 117.5 |   |   |
| Current assets                          |       |                            | 0.2        |   |   |
| Current liabilities                     |       |                            | (0.2       | ) |   |
| Environmental liabilities               |       |                            | (0.5       | ) |   |
| Total                                   |       |                            | $          | 117.0 |   |   |

 

**Other 2004 Acquisitions**

During 2004, we completed five separate acquisitionsof natural gas assets for a total of $10.9 million. The purchase price forthese acquisitions was applied to property, plant, and equipment and there wasno goodwill recorded. The results of operations for the acquisitions areincluded in our Natural Gas segment from the date of acquisition.

In March 2004, wealso purchased natural gas transmission and gathering pipeline assets for$13.1 million. The assets, referred to as the “Palo Duro” system, arelocated in Texas between our existing Anadarko and North Texas systems, and areexpected to increase natural gas delivery flexibility to our customers. Theassets purchased include approximately 400 miles of natural gas transmissionand gathering pipelines, together with 5,200 horsepower of compression. Thepurchase price for this acquisition was applied to property, plant andequipment and no goodwill was recorded. The Palo Duro system’s results ofoperations are included in our Natural Gas segment from the date ofacquisition.

***2003 Acquisitions***

**North Texas System**

On December 31, 2003, we acquired natural gasgathering and processing assets in north Texas. The gathering system, referredto as the North Texas system, primarily serves the Fort Worth Basin, includingthe Barnett Shale producing zone, and is complementary to our existing naturalgas systems in the area. The assets were purchased for cash of$249.6 million, which includes the buyout of a capital lease of$1.9 million and transaction costs of $1.7 million. The purchase wasfunded with borrowings under our credit facilities. The value allocated to theassets was determined by an independent appraisal. Goodwill associated with theacquisition was $23.8 million, and is allocated entirely to our NaturalGas segment. Intangible assets acquired of $48.1 million represent thefair value associated with the natural gas supply opportunities present in theBarnett Shale producing zone that will be shipped through the North Texassystem and is recorded in our Natural Gas segment. Of the $2.7 million ofenvironmental liabilities assumed, $0.5 million are included in Accountspayable and other and $2.2 million are included in environmentalliabilities on our Consolidated Statement of Financial Position as of December 31,2003.

F-22

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Thepurchase price and the allocation to assets acquired and liabilities assumedwas as follows:

| ** **                                                         | ** ** | **(dollars  in millions)** | ** ** |
|--------------------------------------------------------------------|------------|---------------------------------|------------|
| Purchase Price:                                                    |       |                            |       |   |   |
| Cash paid, including transaction costs                             |       |                            | $          | 249.6 |   |   |
| Allocation of  purchase price:                                     |       |                            |       |   |   |
| Current assets                                                     |       |                            | $          | 0.4 |   |   |
| Property, plant and equipment, including  construction in progress |       |                            | 181.0      |   |   |
| Intangibles                                                        |       |                            | 48.1       |   |   |
| Goodwill                                                           |       |                            | 23.8       |   |   |
| Current liabilities                                                |       |                            | (1.0       | ) |   |
| Environmental liabilities                                          |       |                            | (2.7       | ) |   |
| Total                                                              |       |                            | $          | 249.6 |   |   |

 

**Other2003 Acquisition Transactions**

In December 2003, we paid $43.8 million,which includes $2.0 million of interest, in full settlement ofpost-closing adjustments from the acquisition of acquired assets in 2002. Thepurchase price was therefore reduced by $8.8 million, which is reflectedas a decrease to Goodwill in 2003.

**4. NET INCOME PER COMMON AND i-UNIT**

Netincome per common and i-unit is computed by dividing net income, afterdeducting the General Partner’s allocation, by the weighted average number of Class Aand B common units and i-units outstanding. The General Partner’s allocation isequal to an amount based upon its 2% general partner interest, adjusted toreflect an amount equal to incentive distributions earned and an amountrequired to reflect depreciation on the General Partner’s historical cost basisfor assets contributed on formation of the Partnership. As there are nodilutive securities outstanding, basic and diluted earnings per unit amountsare equal. Net income per common and i-unit was determined as follows:

| ** **                                            | ** ** | **Year ended December 31,**                                                       | ** ** |
|-------------------------------------------------------|------------|--------------------------------------------------------------------------------------------------|------------|
| ** **                                            | ** ** | **2005**                                                                                         | ** ** | **2004** | ** ** | **2003** | ** ** |
| ** **                                            | ** ** | **(dollars and units in millions,  except per unit amounts)** | ** ** |
| Net income                                            |       | $                                                                                                | 89.2       |   | $ | 138.2 |   | $ | 111.7 |   |
| Allocations to the  General Partner:                  |       |                                                                                             |       |   |   |   |   |
| Net income  allocated to General Partner              |       | (1.8                                                                                             | )          | (2.8 | ) | (2.2 | ) |
| Incentive distributions  earned                       |       | (21.6                                                                                            | )          | (19.6 | ) | (17.2 | ) |
| Historical cost  depreciation adjustments             |       | (0.1                                                                                             | )          | (0.1 | ) | (0.2 | ) |
|                                                  |       | (23.5                                                                                            | )          | (22.5 | ) | (19.6 | ) |
| Net income  allocable to common units and i-units     |       | $                                                                                                | 65.7       |   | $ | 115.7 |   | $ | 92.1 |   |
| Weighted average  units outstanding                   |       | 62.1                                                                                             |       | 56.1 |   | 47.7 |   |
| Net income per common  and i-unit (basic and diluted) |       | $                                                                                                | 1.06       |   | $ | 2.06 |   | $ | 1.93 |   |

 

F-23

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**5. INVENTORY**

Inventoryis comprised of the following:

| ** **             | ** ** | **December 31,**           | ** ** |
|------------------------|------------|---------------------------------|------------|
| ** **             | ** ** | **2005**                        | ** ** | **2004** | ** ** |
| ** **             | ** ** | **(dollars in  millions)** | ** ** |
| Material and  supplies |       | $                               | 8.3        |   | $ | 7.1 |   |
| Liquids inventory      |       | 11.1                            |       | 5.7 |   |
| Natural gas  inventory |       | 119.5                           |       | 71.7 |   |
|                   |       | $                               | 138.9      |   | $ | 84.5 |   |

 

**6.PROPERTY, PLANT AND EQUIPMENT**

Property,Plant and Equipment is comprised of the following:

| ** **                                          | ** ** | ** **                          | ** ** | **December 31,** | ** ** |
|-----------------------------------------------------|------------|-------------------------------------|------------|-----------------------|------------|
| ** **                                          | ** ** | **Depreciation  Rates**             | ** ** | **2005**              | ** ** | **2004** | ** ** |
| ** **                                          | ** ** | **(dollars in millions)** | ** ** |
| Land                                                |       | —                              |       | $                     | 13.8       |   | $ | 14.4 |   |
| Rights-of-way                                       |       | 0.6%-6.4                            | %          | 280.2                 |       | 238.2 |   |
| Pipeline                                            |       | 0.6%-6.7                            | %          | 2,194.2               |       | 1,919.8 |   |
| Pumping  equipment, buildings and tanks             |       | 1.6%-14.3                           | %          | 673.0                 |       | 613.0 |   |
| Compressors,  meters, and other operating equipment |       | 1.6%-20.0                           | %          | 310.0                 |       | 227.8 |   |
| Vehicles, office  furniture and equipment           |       | 0.8%-33.3                           | %          | 102.7                 |       | 80.0 |   |
| Processing and  treating plants                     |       | 2.7%-4.0                            | %          | 79.0                  |       | 95.6 |   |
| Construction in  progress                           |       | —                              |       | 209.1                 |       | 253.0 |   |
|                                                |       |                                |       | 3,862.0               |       | 3,441.8 |   |
| Accumulated  depreciation                           |       |                                |       | (782.0                | )          | (663.8 | ) |
|                                                |       |                                |       | $                     | 3,080.0    |   | $ | 2,778.0 |   |

 

Based on a third-partystudy commissioned by management, revised depreciation rates for the Anadarko,North Texas and East Texas systems were implemented effective August 1,2005. The annual composite rate, which represents the expected remainingservice life of these natural gas systems, was reduced from 4.0% to 3.4%.Depreciation expense for the year ended December 31, 2005 wasapproximately $2.5 million lower as a result of the new depreciationrates.

**7. GOODWILL**

Thechanges in the carrying amount of goodwill for each of the years ended December 31,2005 and 2004 are as follows:

| ** **                            | ** ** | **Liquids**            | ** ** | **Natural Gas** | ** ** | **Marketing** | ** ** | **Corporate** | ** ** | **Total** | ** ** |
|---------------------------------------|------------|------------------------|------------|----------------------|------------|---------------|------------|---------------|------------|-----------|------------|
| ** **                            | ** ** | **(in millions)** | ** ** |
| Balance as of  December 31, 2003 |       |                   | $          | —               |       |          |       | $             | 236.9      |      |       |   | $ | 20.4 |   |   |   | $ | — |   |   | $ | 257.3 |   |
| Purchase price  adjustments           |       |                   | —     |                 |       |          | (0.1       | )             |       |      | —     |   |   |   | — |   |   | (0.1 | ) |
| Balance as of  December 31, 2004 |       |                   | —     |                 |       |          | 236.8      |          |       |      | 20.4       |   |   |   | — |   |   | 257.2 |   |
| Acquisition                           |       |                   | —     |                 |       |          | 1.0        |          |       |      | —     |   |   |   | — |   |   | 1.0 |   |
| Balance as of  December 31, 2005 |       |                   | $          | —               |       |          |       | $             | 237.8      |      |       |   | $ | 20.4 |   |   |   | $ | — |   |   | $ | 258.2 |   |

 

F-24

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In accordance with SFAS No. 142, *Goodwill and Other Intangible Assets,*we completed ourannual goodwill impairment test using data at June 30, 2005. To estimatethe fair value of our reporting units we made estimates and judgments aboutfuture cash flows, as well as revenue, cost of sales, operating expenses,capital expenditures, and net working capital based on assumptions that areconsistent with the long-range plans used to manage the business. Based on theresults of the impairment analysis, the fair value of each reporting unit wasdetermined to exceed the respective carrying amount, including goodwill. As aresult, no goodwill impairment existed in any of our reporting units at June 30,2005 and no events have occurred or circumstances changed that would, morelikely than not, reduce the fair value of our reporting units below thecarrying amounts as of December 31, 2005.

**8. INTANGIBLES**

| ** **                        | ** ** | **December 31,**       | ** ** |
|-----------------------------------|------------|-----------------------------|------------|
| ** **                        | ** ** | **2005**                    | ** ** | **2004** | ** ** |
| ** **                        | ** ** | **Gross  Carrying  Amount** | ** ** | **Accumulated  Amortization** | ** ** | **Net  Carrying  Amount** | ** ** | **Gross  Carrying  Amount** | ** ** | **Accumulated  Amortization** | ** ** | **Net  Carrying  Amount** | ** ** |
| ** **                        | ** ** | **(in millions)**      | ** ** |
| Customer  contracts               |       |                        | $          | 43.2 |   |   |   | $ | (4.7 | ) |   |   | $ | 38.5 |   |   |   | $ | 31.1 |   |   |   | $ | (3.3 | ) |   |   | $ | 27.8 |   |   |
| Natural gas  supply opportunities |       |                        | 48.1       |   |   |   | (3.9 | ) |   |   | 44.2 |   |   |   | 48.1 |   |   |   | (1.9 | ) |   |   | 46.2 |   |   |
|                              |       |                        | $          | 91.3 |   |   |   | $ | (8.6 | ) |   |   | $ | 82.7 |   |   |   | $ | 79.2 |   |   |   | $ | (5.2 | ) |   |   | $ | 74.0 |   |   |

 

Customer contracts arecomprised entirely of natural gas purchase and sale contracts and are recordedin our Natural Gas and Marketing segments. Customer contracts are amortized ona straight-line basis over the weighted average useful life of the underlyingreserves at the time of the acquisitions, which is approximately 25 years.

The natural gas supplyopportunities were acquired in conjunction with the 2003 North Texas system acquisition(see Note 3) and are recorded entirely in our Natural Gas segment. Thevalue of the intangible asset was determined by a third party appraisal and itrepresents the fair value associated with growth opportunities present in theBarnett Shale producing zone. The natural gas supply opportunities are beingamortized over the weighted average estimated useful life of the underlyingreserves at the time of the acquisition, which is approximately 25 years.

The aggregate amortizationexpense for the years ended December 31, 2005, 2004 and 2003, were$3.7 million, $3.2 million, and $1.3 million, respectively. Theestimated amortization expense for each year through December 31, 2010 is$3.6 million.

**9. DEBT**

The Partnership’sdebt consisted of the following:

| ** **                              | ** ** | **December 31,**               | ** ** |
|-----------------------------------------|------------|-------------------------------------|------------|
| ** **                              | ** ** | ** **                          | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                              | ** ** | **Maturity**                        | ** ** | **Rate** | ** ** | **Dollars** | ** ** | **Rate** | ** ** | **Dollars** | ** ** |
| ** **                              | ** ** | **(dollars in millions)** | ** ** |
| First Mortgage  Notes                   |       | 2011                                |       | 9.15 | % | $ | 186.0 |   | 9.15 | % | $ | 217.0 |   |
| Senior Notes                            |       | 2009-2034                           |       | 5.70 | % | 1,198.6 |   | 5.66 | % | 1,198.4 |   |
| Credit Facility                         |       | 2010                                |       | — |   | — |   | 2.05 | % | 175.0 |   |
| Commercial Paper(1)                     |       | 2010                                |       | 4.36 | % | 329.3 |   | — |   | — |   |
|                                    |       |                                |       |   |   | $ | 1,713.9 |   |   |   | $ | 1,590.4 |   |
| Current  maturities and short-term debt |       |                                |       |   |   | (31.0 | ) |   |   | (31.0 | ) |
| Long-term debt                          |       |                                |       |   |   | $ | 1,682.9 |   |   |   | $ | 1,559.4 |   |

----

(1)                Individual issuesof commercial paper generally mature in 90 days or less, but are supported byour credit facility and are therefore considered long-term debt.

F-25

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***First Mortgage Notes***

The First Mortgage Notes (“Notes”) are collateralizedby a first mortgage lien on substantially all of the property, plant andequipment of the Lakehead Partnership and are due and payable in equal annualinstallments of $31.0 million until their maturity in 2011. Property,plant and equipment attributable to the Lakehead Partnership are$1,384.2 million and $1,408.9 million as of December 31, 2005and 2004, respectively. The Notes contain various restrictive covenantsapplicable to us, and restrictions on the incurrence of additionalindebtedness, including compliance with certain debt issuance tests. We believethese restrictions will not negatively impact our ability to finance futureexpansion projects. Under the Notes agreements, we cannot make cashdistributions more frequently than quarterly in an amount not to exceedAvailable Cash (see Note 10) for the immediately preceding calendarquarter. If the Notes were to be paid prior to their stated maturities, theNote agreements provide for the payment of a redemption premium by thePartnership.

Under the terms of theNotes, we are required to establish, at the end of each quarter, a debt servicereserve. This reserve includes an amount equal to 50% of the prospective Notesinterest payments for the immediately following quarter and an amount for Notesinking fund repayments. At December 31, 2005 and 2004, there was norequired debt service reserve, as all required interest and sinking fundpayments had been made.

***Senior Notes***

All ofthe Senior Notes pay interest semi-annually and have varying maturities andterms as outlined below. The Senior Notes do not contain any covenantsrestricting the issuance of additional indebtedness and rank equally with allof our other existing and future unsubordinated indebtedness.

| ** **                    | ** ** | ** **                          | ** ** | **December 31,** | ** ** |
|-------------------------------|------------|-------------------------------------|------------|-----------------------|------------|
| ** **                    | ** ** | **Interest**                        | ** ** | ** **            | ** ** | ** ** | ** ** |
| **Senior Notes**         | ** ** | ** **                          | ** ** | **Rate**              | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                    | ** ** | **(dollars in millions)** | ** ** |
| Senior Notes maturing in 2009 |       |                                | 4.00       | %                     |       | $ | 200.0 |   | $ | 200.0 |   |
| Senior Notes maturing in 2012 |       |                                | 7.90       | %                     |       | 100.0 |   | 100.0 |   |
| Senior Notes maturing in 2013 |       |                                | 4.75       | %                     |       | 200.0 |   | 200.0 |   |
| Senior Notes maturing in 2014 |       |                                | 5.35       | %                     |       | 200.0 |   | 200.0 |   |
| Senior Notes maturing in 2018 |       |                                | 7.00       | %                     |       | 100.0 |   | 100.0 |   |
| Senior Notes maturing in 2028 |       |                                | 7.125      | %                     |       | 100.0 |   | 100.0 |   |
| Senior Notes maturing in 2033 |       |                                | 5.95       | %                     |       | 200.0 |   | 200.0 |   |
| Senior Notes maturing in 2034 |       |                                | 6.30       | %                     |       | 100.0 |   | 100.0 |   |
|                          |       |                                |       |                  |       | $ | 1,200.0 |   | $ | 1,200.0 |   |
| Unamortized Discount          |       |                                |       |                  |       | (1.4 | ) | (1.6 | ) |
|                          |       |                                |       |                  |       | $ | 1,198.6 |   | $ | 1,198.4 |   |
|                               |            |                                     |            |                       |            |  |  |  |  |  |  |  |  |

 

***Credit Facility***

Our Credit Facility, as amended, is a five-year termfacility that matures in April 2010 with a current borrowing capacity of$800 million and a letter of credit sub limit of $300 million. Additionally, subjectto the approval of Enbridge Management’s Board of Directors, we have the rightto request an increase in commitments available under the Credit Facility up toan aggregate outstanding principal amount of $1 billion. We pay interest on theamounts outstanding at variable rates equal to the “Base Rate” or a “EurodollarRate” as defined in the Credit Facility. In the case of Eurodollar Rate loans,an additional margin is charged which varies depending on our credit rating andthe amounts drawn under the facility. A facility fee is payable on the entireamount of the Credit Facility whether or not drawn. The facility fee alsovaries depending on our credit rating. Our Credit Facility contains restrictivecovenants that require us to 

F-26

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maintain a minimum interestcoverage ratio of 2.75 times and a maximum leverage ratio of 5.25 times fortwelve months through December 2006, at which time it decreases to 5.00times, thereafter. At December 31, 2005, our interest coverage ratio wasapproximately 3.7 and our leverage ratio was approximately 4.2. Our Creditfacility also places limitations on the debt that our subsidiaries may incurdirectly. Accordingly, it is expected that we will provide debt financing toour subsidiaries as necessary. At December 31, 2005, we had no amountsoutstanding under our Credit Facility and letters of credit totaling $149.3million. The amounts we may borrow under the terms of our Credit Facility arereduced by the principal amount of our commercial paper issuances and the balanceof our letters of credit outstanding. At December 31, 2005, we couldborrow $320.7 million under the terms of our Credit Facility.

Individual borrowingsunder the terms of our Credit Facility generally become due and payable at theend of each contract period, typically a period of three months or less. Wehave the option to repay these amounts on a non-cash basis by net settling withthe parties to our credit facility by contemporaneously borrowing at the thencurrent rate of interest and repaying the amounts due. During the years endedDecember 31, 2005, 2004 and 2003, we net settled borrowings of approximately$565 million, $1,573 million and $1,094 million, on a non-cash basis.

***Commercial Paper Program***

In April 2005, weestablished our $600 million commercial paper program that is supported by ourCredit Facility. We access the commercial paper market primarily to providetemporary financing for our operating activities, capital expenditures andacquisitions, at rates that are generally lower than the rates available underour Credit Facility. We repaid the entire amount previously outstanding underour Credit Facility with proceeds we obtained from issuing commercial paperunder this program. Our Credit Facility remains undrawn and available tosupport our commercial paper program. Under the terms of our commercial paperprogram, we can issue up to $600 million of commercial paper. However, theamount of commercial paper we may issue is reduced by any balance ofoutstanding letters of credit in excess of $200 million. At December 31,2005, we had outstanding $329.3 million of commercial paper, net of unamortizeddiscount of $0.7 million, at a weighted average interest rate of 4.36% andoutstanding letters of credit totaling $149.3 million. At December 31,2005, we could issue an additional $270.0 million in principal amountunder our commercial paper program.

We have the ability andintent to refinance all of our commercial paper obligations on a long-termbasis under our unsecured long-term Credit Facility. Accordingly, such amountshave been classified as long-term debt in our accompanying consolidated Statementof Financial Position.

***Interest***

For the years ended December 31,2005, 2004, and 2003, interest expense is net of amounts capitalized of$4.0 million, $2.1 million, and $2.2 million, respectively. Foreach of the years ended December 31, 2005, 2004, and 2003, we madeinterest payments totaling $101.7 million, $73.9 million, and$69.1 million, respectively.

F-27

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***Maturities of ThirdParty Debt***

Thescheduled maturities of outstanding third party debt, excluding the marketvalue of interest rate swaps, at December 31, 2005, are summarized asfollows:

| ** ** | ** ** | **(dollars  in millions)** | ** ** |
|------------|------------|---------------------------------|------------|
| 2006       |       |                            | $          | 31.0 |   |   |
| 2007       |       |                            | 31.0       |   |   |
| 2008       |       |                            | 31.0       |   |   |
| 2009       |       |                            | 231.0      |   |   |
| 2010       |       |                            | 360.3      |   |   |
| Thereafter |       |                            | 1,029.6    |   |   |
| **Total**  |       |                            | $          | 1,713.9 |   |   |

 

**10. PARTNERS’CAPITAL**

Our capital accounts arecomprised of a 2% general partner interest and 98% limited partner interests.The limited partner interests are comprised of Class A common units, Class Bcommon units and i-units. The limited partners have limited rights of ownershipas provided for under our partnership agreement and, as discussed below, theright to participate in our distributions. The General Partner manages ouroperations, subject to a delegation of control agreement with EnbridgeManagement, and participates in the Partnership’s distributions, includingcertain incentive income distributions.

***Class A common units***

Thefollowing table presents the net proceeds from our Class A common unitissuances for each of the years ended December 31, 2005, 2004 and 2003. Theproceeds from each of the offerings were generally used to repay amountsoutstanding under our credit facilities or commercial paper issued, which wereinitially issued to finance our capital expansion projects and acquisitions, orrepayment of other outstanding obligations.

| **Issuance Date**   | ** ** | **Number of  Class A  Common units  Issued**                | ** ** | **Offering Price  per Class A  Common unit** | ** ** | **Net Proceeds to**

**the Partnership**(1) | ** ** | **General**

**Partner**

**Contribution**(2) | ** ** | **Net Proceeds  Including  General  Partner  Contribution** | ** ** |
|---------------------|------------|----------------------------------------------------------------------------|------------|------------------------------------------------------------------|------------|---------------------------------------------|------------|-----------------------------------------------|------------|------------------------------------------------------------------|------------|
| ** **          | ** ** | **($ in millions, except per unit amounts)** | ** ** |
| **2005:**           |       |                                                                       |       |                                                             |       |                                        |       |                                          |       |                                                             |       |   |   |   |   |   |   |   |   |   |   |
| December 2005  |       |                                                                       | 136,200    |                                                             |       |                                        | $          | 46.000                                        |       |                                                             |       | $ | 6.0 |   |   |   | $ | 0.2 |   |   |   | $ | 6.2 |   |   |
| November 2005  |       |                                                                       | 3,000,000  |                                                             |       |                                        | $          | 46.000                                        |       |                                                             |       | 132.1 |   |   |   | 2.8 |   |   |   | 134.9 |   |   |
| February 2005  |       |                                                                       | 2,506,500  |                                                             |       |                                        | $          | 49.875                                        |       |                                                             |       | 124.8 |   |   |   | 2.7 |   |   |   | 127.5 |   |   |
| **2005  Totals**    |       |                                                                       | 5,642,700  |                                                             |       |                                        |       |                                          |       |                                                             | $          | 262.9 |   |   |   | $ | 5.7 |   |   |   | $ | 268.6 |   |   |
| **2004:**           |       |                                                                       |       |                                                             |       |                                        |       |                                          |       |                                                             |       |   |   |   |   |   |   |   |   |   |   |
| September 2004 |       |                                                                       | 3,680,000  |                                                             |       |                                        | $          | 47.900                                        |       |                                                             |       | $ | 168.6 |   |   |   | $ | 3.6 |   |   |   | $ | 172.2 |   |   |
| January 2004   |       |                                                                       | 450,000    |                                                             |       |                                        | $          | 50.300                                        |       |                                                             |       | 21.6 |   |   |   | 0.4 |   |   |   | 22.0 |   |   |
| **2004  Totals**    |       |                                                                       | 4,130,000  |                                                             |       |                                        |       |                                          |       |                                                             | $          | 190.2 |   |   |   | $ | 4.0 |   |   |   | $ | 194.2 |   |   |
| **2003:**           |       |                                                                       |       |                                                             |       |                                        |       |                                          |       |                                                             |       |   |   |   |   |   |   |   |   |   |   |
| December 2003  |       |                                                                       | 5,000,000  |                                                             |       |                                        | $          | 50.300                                        |       |                                                             |       | $ | 240.4 |   |   |   | $ | 5.0 |   |   |   | $ | 245.4 |   |   |
| May 2003       |       |                                                                       | 3,850,000  |                                                             |       |                                        | $          | 44.790                                        |       |                                                             |       | 165.5 |   |   |   | 3.5 |   |   |   | 169.0 |   |   |
| **2003 Totals**     |       |                                                                       | 8,850,000  |                                                             |       |                                        |       |                                          |       |                                                             | $          | 405.9 |   |   |   | $ | 8.5 |   |   |   | $ | 414.4 |   |   |

----

(1)        Net of underwriters’ fees and discounts,commissions and issuance expenses.

(2)        Contributions made by the General Partner tomaintain its 2% general partner interest.

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***Class B common units***

At December 31,2005 and 2004, we had 3,912,750 Class B common units outstanding, whichare held entirely by our general partner. Our Class B common units haverights similar to our Class A common units except that they are notcurrently eligible for trading on the NYSE.

***i-units***

The i-units are a separate class of our limitedpartner interests, all of which are owned by Enbridge Management and are notpublicly traded.

Enbridge Management, asthe owner of our i-units, votes together with the holders of the common unitsas a single class. However, the i-units vote separately as a class on thefollowing matters:

·       Any proposed action thatwould cause us to be treated as a corporation for U.S. federal income taxpurposes;

·       Amendments to ourpartnership agreement that would have a material adverse effect on the holderof our i-units, unless, under our partnership agreement, the amendment could bemade by our general partner without a vote of holders of any class of units;

·       The removal of our generalpartner and the election of a successor general partner; and

·       The transfer by our generalpartner of its general partner interest to a non-affiliated person thatrequires a vote of holders of units under our partnership agreement and theadmission of that person as a general partner.

Inall cases, Enbridge Management will vote or refrain from voting its i-units inthe same manner that owners of Enbridge Management’s shares vote or refrainfrom voting their shares. Furthermore, under the terms of our partnershipagreement, we agree that we will not, except in liquidation, make adistribution on an i-unit other than in additional i-units or a security thathas in all material respects the same rights and privileges as the i-units.

***Distributions Paid***

Our partnership agreement requires us to distribute100% of our “Available Cash”, which is generally defined in our partnershipagreement as the sum of all cash receipts and net additions to reserves for futurerequirements less cash disbursements and amounts retained by us. The reservesare retained to provide for the proper conduct of our business and as necessaryto comply with the terms of our agreements or obligations (including anyreserves required under debt instruments for future principal and interestpayments and for future capital expenditures). The distributions are made toour partners approximately 45 days following the end of each calendarquarter in accordance with their respective percentage interests.

Our General Partner is granted discretion by ourpartnership agreement, which discretion has been delegated to EnbridgeManagement, subject to the approval of the General Partner in certain cases, toestablish, maintain and adjust reserves for future operating expenses, debtservice, maintenance capital expenditures, and distributions for the next fourquarters. These reserves are not restricted by magnitude, but only by type offuture cash requirements with which they can be associated. When EnbridgeManagement determines the quarterly distributions, it considers current andexpected reserve needs along with current and expected cash flows to identifythe appropriate sustainable distribution level.

Distributions of our Available Cash generally are made98.0% to our Class A and B common unitholders and our i-unitholder and2.0% to the General Partner. We will not distribute the cash related to thei-units, but instead, will distribute additional i-units such that the cash isretained and used in our business. Further, we retain an additional amountequal to 2.0% of the i-unit distribution from the General Partner to maintainits 2% general partner interest in us. Distributions are subject to the paymentof incentive distributions to the General Partner to the extent that certaintarget levels of cash distributions to the unitholders are achieved. Theincremental incentive distributions payable to the General Partner are 

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15.0%, 25.0% and 50.0% ofall quarterly distributions of Available Cash that exceed target levels of$0.59, $0.70, and $0.99 per Class A and B common units and i-units,respectively.

Typically, the General Partner and owners of ourcommon units will receive distributions in cash. Enbridge Management, as thedelegate of our general partner under the delegation of control agreement,computes the amount of our available cash. Enbridge Management, as owner of thei-units, however, does not receive distributions in cash. Instead, each timethat the we make a cash distribution to the General Partner and the holders ofour common units, the number of i-units owned by Enbridge Management and thepercentage of our total units owned by Enbridge Management will increaseautomatically under the provisions of our partnership agreement with the resultthat the number of i-units owned by Enbridge Management will equal the numberof Enbridge Management’s shares and voting shares that are then outstanding.The amount of this increase in i-units is determined by dividing the cashamount distributed per common unit by the average price of one of EnbridgeManagement’s listed shares on the NYSE for the 10-trading day periodimmediately preceding the ex-dividend date for Enbridge Management’s sharesmultiplied by the number of shares outstanding on the record date. The cashequivalent amount of the additional i-units is treated as if it had actuallybeen distributed for purposes of determining the distributions to be made tothe General Partner.

The following table setsforth our distributions, as approved by the Board of Directors for each periodin the years ended December 31, 2005, 2004 and 2003.

| **Distribution  Declaration Date** | ** ** | **Distribution  Payment Date** | ** ** | **Record Date**       | ** ** | **Distribution  per Unit**                                                  | ** ** | **Cash  available for  distribution** | ** ** | **Amount of**

**Distribution**

**of i units**

**to i unit**

**holders**(1) | ** ** | **Retained**

**from**

**General**

**Partner**(2) | ** ** | **Distribution  of Cash** | ** ** |
|-----------------------------------------|------------|-------------------------------------|------------|----------------------------|------------|----------------------------------------------------------------------------------|------------|--------------------------------------------|------------|---------------------------------------------------------------------------------------------------------|------------|-----------------------------------------------------|------------|--------------------------------|------------|
| ** **                              | ** ** | ** **                          | ** ** | ** **                 | ** ** | **(dollars in millions, except per unit amounts)** | ** ** |
| **2005**                                |       |                                |       |                       |       |                                                                             |       |                                       |       |                                                                                                    |       |                                                |       |                           |       |   |   |   |   |   |   |   |   |   |   |
| October 26, 2005                   |       | November 14, 2005         |       | November 3, 2005 |       |                                                                             | $          | 0.925                                      |       |                                                                                                    |       | $                                                   | 64.1       |                           |       |   | $ | 10.6 |   |   |   | $ | 0.2 |   |   |   | $ | 53.3 |   |   |
| July 28, 2005                      |       | August 12, 2005           |       | August 5, 2005   |       |                                                                             | 0.925      |                                       |       |                                                                                                    | 64.0       |                                                |       |                           | 10.5       |   |   |   | 0.2 |   |   |   | 53.3 |   |   |
| April 25, 2005                     |       | May 13, 2005              |       | May 4, 2005      |       |                                                                             | 0.925      |                                       |       |                                                                                                    | 63.8       |                                                |       |                           | 10.3       |   |   |   | 0.2 |   |   |   | 53.3 |   |   |
| January 24, 2005                   |       | February 14, 2005         |       | February 3, 2005 |       |                                                                             | 0.925      |                                       |       |                                                                                                    | 61.0       |                                                |       |                           | 10.1       |   |   |   | 0.2 |   |   |   | 50.7 |   |   |
|                                    |       |                                |       |                       |       |                                                                             |       |                                       |       |                                                                                                    | $          | 252.9                                               |       |                           |       | $ | 41.5 |   |   |   | $ | 0.8 |   |   |   | $ | 210.6 |   |   |
| **2004**                                |       |                                |       |                       |       |                                                                             |       |                                       |       |                                                                                                    |       |                                                |       |                           |       |   |   |   |   |   |   |   |   |   |   |
| October 22, 2004                   |       | November 12, 2004         |       | November 1, 2004 |       |                                                                             | $          | 0.925                                      |       |                                                                                                    |       | $                                                   | 60.7       |                           |       |   | $ | 9.9 |   |   |   | $ | 0.2 |   |   |   | $ | 50.6 |   |   |
| July 22, 2004                      |       | August 13, 2004           |       | August 2, 2004   |       |                                                                             | 0.925      |                                       |       |                                                                                                    | 56.6       |                                                |       |                           | 9.6        |   |   |   | 0.2 |   |   |   | 46.8 |   |   |
| April 26, 2004                     |       | May 14, 2004              |       | May 5, 2004      |       |                                                                             | 0.925      |                                       |       |                                                                                                    | 56.5       |                                                |       |                           | 9.5        |   |   |   | 0.2 |   |   |   | 46.8 |   |   |
| January 22, 2004                   |       | February 13, 2004         |       | February 2, 2004 |       |                                                                             | 0.925      |                                       |       |                                                                                                    | 56.3       |                                                |       |                           | 9.3        |   |   |   | 0.2 |   |   |   | 46.8 |   |   |
|                                    |       |                                |       |                       |       |                                                                             |       |                                       |       |                                                                                                    | $          | 230.1                                               |       |                           |       | $ | 38.3 |   |   |   | $ | 0.8 |   |   |   | $ | 191.0 |   |   |
| **2003**                                |       |                                |       |                       |       |                                                                             |       |                                       |       |                                                                                                    |       |                                                |       |                           |       |   |   |   |   |   |   |   |   |   |   |
| October 22, 2003                   |       | November 14, 2003         |       | November 4, 2003 |       |                                                                             | $          | 0.925                                      |       |                                                                                                    |       | $                                                   | 50.5       |                           |       |   | $ | 9.2 |   |   |   | $ | 0.2 |   |   |   | $ | 41.1 |   |   |
| July 23, 2003                      |       | August 14, 2003           |       | August 4, 2003   |       |                                                                             | 0.925      |                                       |       |                                                                                                    | 50.3       |                                                |       |                           | 8.9        |   |   |   | 0.2 |   |   |   | 41.2 |   |   |
| April 24, 2003                     |       | May 15, 2003                   |       | May 2, 2003           |       |                                                                             | 0.925      |                                       |       |                                                                                                    | 46.1       |                                                |       |                           | 8.7        |   |   |   | 0.2 |   |   |   | 37.2 |   |   |
| January 23, 2003                   |       | February 14, 2003         |       | February 4, 2003 |       |                                                                             | 0.925      |                                       |       |                                                                                                    | 46.0       |                                                |       |                           | 8.6        |   |   |   | 0.2 |   |   |   | 37.2 |   |   |
|                                    |       |                                |       |                       |       |                                                                             |       |                                       |       |                                                                                                    | $          | 192.9                                               |       |                           |       | $ | 35.4 |   |   |   | $ | 0.8 |   |   |   | $ | 156.7 |   |   |

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(1)                We issued 802,539,840,239 and 833,515 i-units to Enbridge Energy Management, L.L.C., the soleowner of our i-units, during 2005, 2004 and 2003, respectively, in lieu of cashdistributions.

(2)                Weretained an amount equal to 2% of the i-unit distribution from the GeneralPartner to maintain its 2% general partner interest in us.

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**11. RELATED PARTY TRANSACTIONS**

***Administrative and Workforce Related Services***

Enbridge and its affiliates provide management andadministrative, operations and workforce related services to us. Employees ofEnbridge and its affiliates are assigned to work for one or more affiliates ofEnbridge, including the Partnership. Where directly attributable, the costs ofall compensation, benefits expenses and employer expenses for these employeesare charged directly by Enbridge to the appropriate affiliate. There is noprofit or margin for these services charged by Enbridge to its affiliates.

The portion of direct workforce costs associated withthe management and administrative services provided at our Houston office andthe operating and administrative services provided to support our facilitiesacross the United States, are charged from Enbridge and its affiliates to us.

Certain of our operating activities associated withour Liquids segment are provided by Enbridge Pipelines Inc. (“EnbridgePipelines”), a subsidiary of Enbridge, as the majority of these pipelinesystems form one contiguous system with the Enbridge system in Canada. Theseservices include control center operations, facilities management, shipperservices, pipeline integrity management and other related activities. The coststo provide these services are allocated to us from Enbridge Pipelines, based onan appropriate allocation methodology consistent with Enbridge’s corporate costallocation policy, including estimated time spent and miles of pipe. We alsoreceive costs associated with control center services for some of the naturalgas assets from another affiliate of Enbridge.

Enbridge also allocates management and administrativecosts to us pursuant to our partnership agreement and related servicesagreements. These costs are allocated to us based on an allocation methodologyconsistent with Enbridge’s corporate cost allocation policy, includingestimated time spent and headcount.

During2005, 2004 and 2003, we incurred the following costs related to these services,which are included in operating and administrative expenses.

| ** **                                                          | ** ** | **Year ended December 31,** | ** ** |
|---------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                          | ** ** | **2005**                                   | ** ** | **2004** | ** ** | **2003** | ** ** |
| ** **                                                          | ** ** | **(dollars in millions)**        | ** ** |
| Direct workforce  costs                                             |       | $                                          | 117.0      |   | $ | 101.7 |   | $ | 75.4 |   |
| Liquids /Natural  Gas operating costs                               |       | 15.3                                       |       | 14.0 |   | 9.6 |   |
| Allocated  management and administrative costs, including insurance |       | 20.1                                       |       | 17.2 |   | 14.2 |   |
|                                                                |       | $                                          | 152.4      |   | $ | 132.9 |   | $ | 99.2 |   |

 

***Natural Gas Sales and Purchases***

We purchase natural gas from third-parties, whichsubsequently generates operating revenues from sales to Enbridge and itsaffiliates. These transactions are entered into at the market price on the dateof sale. Included in our results for the twelve months ending December 31,2005, 2004 and 2003, are operating revenues of $43.6 million, $23.6 million,and $30.6 million, respectively, related to these sales.

We also purchase naturalgas from Enbridge and its affiliates for sale to third-parties at market priceson the date of purchase. Included in our results for the twelve months ending December 31,2005, 2004 and 2003, are cost of natural gas expenses of $4.5 million,$6.9 million and $1.2 million, respectively, relating to thesepurchases.

F-31

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***Affiliate Notes***

The Partnership has a note payable with an affiliateof Enbridge that totaled $151.8 million and $142.1 million at December 31,2005 and 2004, which matures in 2007. The interest rate is 6.60% as of December 31,2005 and 2004.

We incurred interest expense on affiliate notestotaling $9.7 million, $9.0 million, and $16.1 million for theyears ended December 31, 2005, 2004, and 2003, respectively.

For the years ended December 31,2005 and 2004, we converted interest payable related to loans from the GeneralPartner and affiliates in the amount of $9.7 million and$9.0 million, respectively, into long-term loans from the General Partnerand affiliates.

***Incentive and Partnership Distributions***

Pursuant to our partnership agreement, the GeneralPartner owns an effective 2% general partner ownership interest in us. TheGeneral Partner received incentive distributions for the years ended December 31,2005, 2004 and 2003 of $25.3 million, $22.9 million, and$19.2 million, respectively.

As of December 31,2005 and 2004, the General Partner also owned 3,912,750 Class B commonunits, representing 5.8% and 6.5% ownership, respectively in us. The GeneralPartner received cash distributions related to its ownership of Class Bcommon units for the years ended December 31, 2005, 2004 and 2003 of$14.5 million, $14.4 million and $14.5 million, respectively.

***Conflicts of Interest***

Through a delegation ofcontrol agreement with the General Partner and us, Enbridge Management makesall decisions relating to the management and control of our business. TheGeneral Partner owns the voting shares of Enbridge Management and elects all ofEnbridge Management’s directors. Enbridge, through its wholly-ownedsubsidiary, Enbridge Pipelines, owns all the common stock of the GeneralPartner. Some of the General Partner’s officers and directors are alsodirectors and officers of Enbridge and Enbridge Management and have fiduciaryduties to manage the business of Enbridge and Enbridge Management in a mannerthat may not be in the best interests of our unitholders. Certain conflicts ofinterest could arise as a result of the relationships among EnbridgeManagement, the General Partner, Enbridge and us. Our partnership agreement andthe delegation of control agreement contain provisions that allow EnbridgeManagement to take into account the interest of parties in addition to those ofour unitholders in resolving conflicts of interest, thereby limiting itsfiduciary duties to our unitholders, as well as provisions that may restrictthe remedies available to unitholders for actions taken that might, withoutsuch limitations, constitute breaches of fiduciary duty.

***Enbridge Management***

Pursuant to the delegationof control agreement between Enbridge Management, our General Partner and us,and our partnership agreement, we pay all expenses relating to EnbridgeManagement. This includes Texas franchise taxes and any other similarcapital-based foreign, state and local taxes not otherwise paid or reimbursedpursuant to a tax indemnification agreement between Enbridge and Enbridge Managementon behalf of Enbridge Management.

**12. ENVIRONMENTAL LIABILITIES**

We are subject to federal and state laws andregulations relating to the protection of the environment. Environmental riskis inherent to liquid and gas pipeline operations and we could, at times, besubject to environmental cleanup and enforcement actions. We manage thisenvironmental risk through appropriate environmental policies and practices tominimize any impact. To the extent that we are unable to recover 

F-32

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environmental liabilitiesassociated with the Lakehead system assets through insurance, the GeneralPartner has agreed to indemnify us from and against any costs relating toenvironmental liabilities associated with the Lakehead system assets prior tothe transfer to us in 1991. This excludes any liabilities resulting from achange in laws after such transfer. We continue to voluntarily investigate pastleak sites on our systems for the purpose of assessing whether any remediationis required in light of current regulations, and to date, no materialenvironmental risks have been identified.

In connection with our acquisition of the Midcoastsystems in October 2002, the General Partner has agreed to indemnify usand other related persons for certain environmental liabilities of which theGeneral Partner has knowledge and which it did not disclose. The GeneralPartner will not be required to indemnify us until the aggregate liabilities,including environmental liabilities, exceed $20.0 million, and the GeneralPartner’s aggregate liability, including environmental liabilities, may notexceed, with certain exceptions, $150.0 million. We will be liable for anyenvironmental conditions related to the acquired systems that were not known tothe General Partner or were disclosed.

As of December 31, 2005 and 2004, we haverecorded $4.0 million and $3.6 million in current liabilities and$4.8 million and $5.3 million, respectively, in long-term liabilitiesprimarily to address remediation of asbestos containing materials, managementof hazardous waste material disposal, and outstanding air quality measures forcertain of our liquids and natural gas assets.

In March 2004, wereduced our long-term environmental liabilities by $2.0 million related tocertain of our Natural Gas assets. Since October 2002, during the timethat these assets have been owned by us, we completed a review of the affectedsites and determined that suspected contamination is less significant thanoriginally estimated. Our assessment was based upon information gathered duringthe ownership period, existing technology, presently enacted laws andregulations and prior experience in remediating contaminated sites for similarassets.

**13. COMMITMENTS AND CONTINGENCIES**

***Oil and Gas in Custody***

Our Liquids assets transport crude oil and natural gasliquids owned by our customers for a fee. The volume of liquid hydrocarbons inour pipeline system at any one time approximates 25 million barrels,virtually all of which is owned by the Partnership’s customers. Under terms ofour tariffs, losses of crude oil from indentifiable incidents not resultingfrom our direct negligence may be apportioned among our customers. In addition,we maintain adequate property insurance coverage with respect to crude oil andnatural gas liquids in our custody.

Approximately 50% of thenatural gas volumes on our natural gas assets are transported for customers ona contractual basis. We purchase the remaining 50% and sell to third-partiesdownstream of the purchase point. At any point in time, the value of customers’natural gas in the custody of our natural gas systems is not material to us.

***Rate Refunds***

On October 8, 2004, the FERC issued an Order onRemand (“Remand Order”) relating to initial rates on our Kansas Pipeline System(“KPC”) for the period of time between December 1997 and November 2002.We acquired KPC on October 17, 2002. The Remand Order was issued inresponse to a United States Court of Appeals ruling in August 2003requiring the FERC to address the issue of appropriate rate refunds, if any,with respect to KPC’s initial rates. In the Remand Order, the FERC found thatthe proper initial rates are lower than the rates previously charged tocustomers pending resolution of this contested rate case. In accordance withthe FERC’s findings, any difference between what was 

F-33

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collected and the revisedinitial Section 7 rates for the period of time between December 1997and November 2002, plus interest compounded quarterly, is subject torefund.

Refunds to our customerswere made in January 2005 pursuant to a refund plan agreed upon withcustomers and approved by the FERC. Our Consolidated Statements of Income forthe year ended December 31, 2004, includes a charge of approximately$13.6 million for the rate refunds and interest. The rate refunds relatealmost entirely to a time period prior to our ownership of KPC.

***Right-of-Way***

As part of our pipelineconstruction process, we must obtain certain right-of-way agreements fromlandowners whose property the pipeline will cross. Right-of-way agreements thatwe buy are capitalized as part of Property, Plant and Equipment. Right-of-wayagreements that are leased from a third-party are expensed. We recordedexpenses for the leased right-of-way agreements of $1.9 million,$1.8 million, and $1.4 million for the years ended December 31,2005, 2004, and 2003, respectively.

***Legal Proceedings***

We are a participant invarious legal proceedings arising in the ordinary course of business. Some ofthese proceedings are covered, in whole or in part, by insurance. We believethat the outcome of all these proceedings will not, individually or in theaggregate, have a material adverse effect on our financial condition.

***Future Minimum Commitments***

As of December 31,2005, the future minimum commitments having remaining non-cancelable terms inexcess of one year are as follows:

| **Future Minimum Commitments** | ** ** | ** **                          | ** ** | **2006** | ** ** | **2007** | ** ** | **2008** | ** ** | **2009** | ** ** | **2010** | ** ** | **Thereafter** | ** ** | **Total** | ** ** |
|------------------------------------------|------------|-------------------------------------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------------|------------|-----------|------------|
| ** **                               | ** ** | **(dollars in millions)** | ** ** |
| Power and other  purchase commitments    |       | $                                   | 70.4       |     | $          | —   |       | $        | —     |     | $          | —   |       | $              | —     |      |       | $ | — |   |   | $ | 70.4 |   |
| Other operating  leases                  |       | 4.2                                 |       | 4.2      |       | 4.0      |       | 3.5      |       | 1.1      |       |     | —     |           |       | 17.0      |       |
| Right-of-way(1)                          |       | 1.8                                 |       | 1.7      |       | 1.7      |       | 1.8      |       | 1.8      |       |     | 44.7       |           |       | 53.5      |       |
| Product purchase  obligations(2)         |       | 62.8                                |       | 59.9     |       | 36.6     |       | 31.8     |       | 28.0     |       |     | 116.7      |           |       | 335.8     |       |
| Service contract  obligations(3)         |       | 12.4                                |       | 10.5     |       | 5.3      |       | 3.2      |       | —   |       |     | —     |           |       | 31.4      |       |
| Total                                    |       | $                                   | 151.6      |     | $          | 76.3     |       | $        | 47.6       |     | $          | 40.3     |       | $              | 30.9       |      |       | $ | 161.4 |   |   | $ | 508.1 |   |

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(1)                Right-of-waypayments are estimated to be approximately $1.8 million per year for theremaining life for all pipeline systems, which has been assumed to be25 years for purposes of calculating the amount of future minimumcommitments beyond 2010.

(2)                We have long-termproduct purchase obligations with several third-party suppliers toacquire natural gas and NGLs at prices approximating market at the time ofdelivery.

(3)                The transportationservice obligations represent the minimum payment amounts for firmtransportation capacity reserved by the Partnership on third-partypipelines.

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**14. FINANCIAL INSTRUMENTS**

***Fair Value of DebtObligations***

Thetable below presents the carrying amount and approximate fair values of ourdebt obligations. The carrying amounts of our commercial paper approximatetheir fair values at December 31, 2005, due to the short-term nature ofthese obligations. The carrying amounts of our Credit Facility at December 31,2004, approximate the fair values of this instrument because the variableinterest rates on the amounts outstanding reprice frequently to reflect currentlyavailable interest rates. The fair values of the First Mortgage Notes andSenior notes have been determined based on quoted market prices for the same orsimilar issues.

| ** **                    | ** ** | **December 31, 2005** | ** ** | **December 31, 2004** | ** ** |
|-------------------------------|------------|---------------------------------|------------|---------------------------------|------------|
| ** **                    | ** ** | **Carrying Amount**        | ** ** | **Fair Value**             | ** ** | **Carrying Amount** | ** ** | **Fair Value** | ** ** |
| ** **                    | ** ** | **(in millions)**          | ** ** |
| Commercial paper              |       |                            | $          | 329.3                           |       |   |   | $ | 329.3 |   |   |   | $ | — |   |   |   | $ | — |   |   |
| Credit Facility               |       |                            | —     |                            |       |   | — |   |   |   | 175.0 |   |   |   | 175.0 |   |   |
| 9.15% First Mortgage  Notes   |       |                            | 186.0      |                            |       |   | 207.9 |   |   |   | 217.0 |   |   |   | 256.8 |   |   |
| 4.00% Senior notes due  2009  |       |                            | 199.9      |                            |       |   | 193.0 |   |   |   | 199.9 |   |   |   | 199.2 |   |   |
| 7.90% Senior notes due  2012  |       |                            | 99.9       |                            |       |   | 113.8 |   |   |   | 99.9 |   |   |   | 120.1 |   |   |
| 4.75% Senior notes due  2013  |       |                            | 199.8      |                            |       |   | 190.8 |   |   |   | 199.7 |   |   |   | 197.1 |   |   |
| 5.35% Senior notes due  2014  |       |                            | 199.9      |                            |       |   | 196.7 |   |   |   | 199.9 |   |   |   | 203.2 |   |   |
| 7.00% Senior notes due  2018  |       |                            | 99.8       |                            |       |   | 111.4 |   |   |   | 99.8 |   |   |   | 117.4 |   |   |
| 7.125% Senior notes due  2028 |       |                            | 99.8       |                            |       |   | 113.0 |   |   |   | 99.8 |   |   |   | 119.3 |   |   |
| 5.95% Senior notes due  2033  |       |                            | 199.7      |                            |       |   | 193.1 |   |   |   | 199.7 |   |   |   | 200.3 |   |   |
| 6.30% Senior notes due 2034   |       |                            | 99.8       |                            |       |   | 100.8 |   |   |   | 99.7 |   |   |   | 104.1 |   |   |

 

***Fair Value ofDerivative Financial Instruments***

The fair values of ourderivative financial instruments are determined based on available marketinformation, valuation and modeling techniques. These modeling techniquesrequire us to make estimates of future prices, price correlation, marketvolatility and liquidity. The estimates also reflect factors for time value ofmoney and the volatility of prices underlying the contracts, the potentialimpact of liquidating positions in an orderly manner over a reasonable periodof time under present market conditions, modeling risk, credit risk of counterparties and operational risk.

F-35

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**Interest Rate Derivatives**

Weenter into floating to fixed interest rate swaps to manage the effect of futureinterest rate movements on our interest costs. We also enter fixed to floatingrate interest rate swaps to manage the fair value of debt issuances. Thefollowing table summarizes our interest rate derivatives outstanding at December 31:

| ** **                                   | ** ** | **Partnership**                 | ** ** | ** ** | ** ** | **Fair Value** | ** ** |
|----------------------------------------------|------------|---------------------------------|------------|------------|------------|---------------------|------------|
| ** **                                   | ** ** | **Notional  Principal**         | ** ** | **Pays**   | ** ** | **Receives**        | ** ** | **Maturity  Date** | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                                   | ** ** | **(dollars in  millions)** | ** ** | ** ** | ** ** | ** **          | ** ** | ** ** | ** ** | **(dollars in  millions)** | ** ** |
| Floating to Fixed rate  interest rate swaps: |       |                            | 30.0       |       |       | 3.18%               |       | LIBOR |   | January 18, 2006 |   |   | 0.1 |   |   | — |   |
|                                         |       |                            | 30.0       |       |       | 3.18%               |       | LIBOR |   | January 20, 2006 |   |   | 0.1 |   |   | — |   |
|                                         |       |                            | 30.0       |       |       | 3.20%               |       | LIBOR |   | January 27, 2006 |   |   | 0.1 |   |   | — |   |
|                                         |       |                            | 30.0       |       |       | 3.22%               |       | LIBOR |   | January 30, 2006 |   |   | 0.1 |   |   | — |   |
|                                         |       |                            | 30.0       |       |       | 3.21%               |       | LIBOR |   | February 3, 2006 |   |   | 0.1 |   |   | — |   |
|                                         |       |                            | 50.0       |       |       | 4.37%               |       | LIBOR |   | June 1, 2013 |   |   | 1.0 |   |   | (0.4 | ) |
|                                         |       |                            | 50.0       |       |       | 4.34%               |       | LIBOR |   | June 1, 2013 |   |   | 1.1 |   |   | (0.3 | ) |
|                                         |       |                            | 25.0       |       |       | 4.31%               |       | LIBOR |   | June 1, 2013 |   |   | 0.5 |   |   | (0.2 | ) |
| Fixed to Floating rate  interest rate swaps: |       |                            | 50.0       |       |       | LIBOR-21bps         |       | 4.75% |   | June 1, 2013 |   |   | 0.2 |   |   | 1.8 |   |
|                                         |       |                            | 50.0       |       |       | LIBOR-21bps         |       | 4.75% |   | June 1, 2013 |   |   | 0.2 |   |   | 1.8 |   |
|                                         |       |                            | 25.0       |       |       | LIBOR-25bps         |       | 4.75% |   | June 1, 2013 |   |   | 0.2 |   |   | 1.0 |   |

----

(1)        A bps refersto a basis point. One basis point is equivalent to 1/100th of1%.

Our floating to fixed rateinterest rate swaps maturing in 2006 qualify for and have been designated cashflow hedges of interest payments on $150 million of our variable rateindebtedness and therefore, the changes in fair value of these derivatives arerecorded as an increase or decrease in Accumulated other comprehensive income. Thefloating to fixed rate and fixed to floating rate interest rate swaps maturingin 2013 do not qualify as cash flow or fair value hedges and as a result, changesin the fair value of these derivative financial instruments are recorded inearnings as an increase or decrease in interest expense.

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**CommodityPrice Derivatives**

Thefollowing table provides summarized information about the fair values of ouroutstanding commodity derivative financial instruments at December 31,2005 and 2004: 

| ** **                     | ** ** | ** **   | ** ** | **Wtd Avg Price** | ** ** | **December 31, 2005  fair Value** | ** ** | **December 31, 2004  Fair Value** | ** ** |
|--------------------------------|------------|--------------|------------|-----------------------------|------------|--------------------------------------------------|------------|--------------------------------------------------|------------|
| ** **                     | ** ** | **Notional** | ** ** | **Receive**                 | ** ** | **Pay**                                          | ** ** | **Asset**                                        | ** ** | **Liability** | ** ** | **Asset** | ** ** | **Liability** | ** ** |
| **Swaps**                      |       |         |       |                        |       |                                             |       |                                             |       |   |   |   |   |   |   |
| *Natural gas*(1**)**           |       |         |       |                        |       |                                             |       |                                             |       |   |   |   |   |   |   |
| Receive variable/ pay fixed    |       | 209,377,007  |       | $                           | 9.73       |                                             | $          | 7.27                                             |       | $ | 511.0 |   | $ | (12.7 | ) | $ | 12.9 |   | $ | (72.4 | ) |
| Receive fixed/ pay variable    |       | 263,866,039  |       | 6.79                        |       | 9.92                                             |       | 15.1                                             |       | (790.4 | ) | 66.9 |   | (105.3 | ) |
| Receive variable/ pay variable |       | 25,553,581   |       | 9.38                        |       | 9.26                                             |       | 8.0                                              |       | (5.3 | ) | 0.7 |   | (2.6 | ) |
| *NGL*(2)                       |       |         |       |                        |       |                                             | ** ** | ** **                                       | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Receive fixed/ pay variable    |       | 6,942,833    |       | 28.64                       |       | 37.85                                            |       | —                                           |       | (60.3 | ) | 2.6 |   | (16.3 | ) |
| *Crude*(2)                     |       |         |       |                        |       |                                             | ** ** | ** **                                       | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| Receive fixed/ pay variable    |       | 1,376,479    |       | 45.69                       |       | 62.72                                            |       | 0.2                                              |       | (22.0 | ) | 1.1 |   | (5.9 | ) |
| **Options—calls**         |       |         |       |                        |       |                                             | ** ** | ** **                                       | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| *Natural gas*(1)               |       | 2,191,000    |       | 9.05                        |       | 4.31                                             |       | —                                           |       | (9.5 | ) | — |   | (9.3 | ) |
| **Options—puts**          |       |         |       |                        |       |                                             | ** ** | ** **                                       | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** |
| *Natural gas*(1)               |       | 1,826,000    |       | 8.71                        |       | 3.40                                             |       | 0.1                                              |       | — |   | 0.9 |   | — |   |
| **Totals****(3)**              |       |         |       |                        |       |                                             |       | $                                                | 534.4      |   | $ | (900.2 | ) | $ | 85.1 | ** ** | $ | (211.8 | **)** |
|                                |            |              |            |                             |            |                                                  |            |                                                  |            |  |  |  |  |  |  |  |  |  |  |  |  |

----

(1)                Notionalamounts for natural gas are recorded in millions of British thermal units (“MMBtu”).

(2)                Notionalamounts for NGL and Crude are recorded in Barrels (“Bbl”).

(3)                We record the fairvalue of our derivative financial instruments in the balance sheet as currentand long-term assets or liabilities on a net basis by counterparty.

**15. DERIVATIVEFINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES**

Our net income and cash flows are subject tovolatility stemming from changes in interest rates on our variable rate debtobligations and fluctuations in commodity prices of natural gas, NGLs,condensate and fractionation margins (the relative price differential betweenNGL sales and offsetting natural gas purchases). Our interest rate riskexposure does not exist within any of our segments, but exists at the corporatelevel where our variable rate debt obligations are issued. Our exposure tocommodity price risk exists within our Natural Gas and Marketing segments. Weuse derivative financial instruments (i.e., futures, forwards, swaps, optionsand other financial instruments with similar characteristics) to mitigate thevolatility of our cash flows resulting from fluctuations in commodity pricesand interest rates. Based on our risk management policies, all of ourderivative financial instruments are employed in connection with an underlyingasset, liability and/or anticipated transaction and are not entered into withthe objective of speculating on interest rates or commodity prices.

***AccountingTreatment***

Allderivative financial instruments are recorded in our consolidated financialstatements at fair market value and are adjusted each period for changes in thefair market value (“mark-to-market”). The fair market value ofthese derivative financial instruments reflects the estimated amounts that wewould pay or receive to terminate or close the contracts at the reporting date,taking into account the current unrealized losses or gains on open contracts. Weuse external market quotes and indices to value substantially all of thefinancial instruments we utilize.

Underthe guidance of Statement of Financial Accounting Standards No. 133, *Accounting for Derivative Transactions and HedgingActivities* (“SFAS No. 133”), if a derivative financialinstrument does not qualify as a hedge or is not designated as a hedge, achange in the fair market value, both realized and unrealized, is recognizedcurrently in our income statement as a derivative fair value gain (loss) and isrecorded in Cost of natural gas for commodity derivatives and interest expensefor interest rate derivatives. 

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Cashflow is only impacted to the extent the actual derivative contract is settledby making or receiving a payment to/from the counterparty or by making orreceiving a payment for entering into a contract that exactly offsets theoriginal derivative contract. Typically, a derivative contract is settled whenthe future physical transaction that underlies the derivative financialinstrument occurs (e.g., purchase or sale of natural gas or interest payment).

If a derivative financialinstrument is designated as a cash flow hedge and qualifies for hedgeaccounting, a change in the fair market value is deferred in Accumulated othercomprehensive income (“OCI”), a component of Partners’ Capital, until theunderlying hedged transaction occurs. Any ineffective portion of a cash flowhedge’s change in fair market value is recognized each period in earnings.Realized gains and losses on derivative financial instruments that aredesignated as cash flow hedges and qualify for hedge accounting are included inCost of natural gas in the period the hedged transaction occurs. Gains andlosses deferred in OCI related to cash flow hedges for which hedge accountinghas been discontinued, remain in OCI until the underlying physical transactionoccurs unless it is probable that the forecasted transaction will not occur bythe end of the originally specified time period or within an additionaltwo-month period of time thereafter. Our preference, whenever possible, is forour derivative financial instruments to receive hedge accounting treatment tomitigate the noncash earnings volatility that arises under mark-to-marketaccounting treatment. To qualify for cash flow hedge accounting, very specificrequirements must be met in terms of hedge structure, hedge objective and hedgedocumentation.

If a derivative financialinstrument is designated and qualifies as a fair value hedge of the change infair market value of an underlying asset or liability, the gain (loss)resulting from the change in fair market value of the derivative financialinstrument is recorded in earnings adjusted by the gain (loss) resulting fromthe change in fair market value of the underlying asset or liability. Anyineffective portion of a fair value hedge’s change in fair market value will berecorded in earnings as the amount that is not offset by the gain (loss) on thechange in fair market value of the underlying asset or liability. We includethe gains and losses associated with derivative financial instrumentsdesignated and qualifying as fair value hedges of our debt obligations ininterest expense. Similar to derivative financial instruments designated ascash flow hedges, very specific requirements must be met in terms of hedgestructure, hedge objective and hedge documentation.

***Non-QualifiedHedges***

Many of our derivativefinancial instruments qualify for hedge accounting treatment under the specificrequirements of SFAS No. 133. However, we have three primary instanceswhere the hedge structure does not meet the requirements to apply hedgeaccounting and, therefore, these financial instruments are considered ‘non-qualified’under SFAS No. 133. These non-qualified derivative financial instrumentsmust be adjusted to their fair market value, or marked-to-market,each period, with the increases and decreases in fair value recorded asincreases and decreases in Cost of natural gas in our Consolidated Statementsof Income. These mark-to-market adjustments produce a degree ofearnings volatility that can often be significant from period to period, buthave no cash flow impact relative to changes in market prices. The cash flowimpact occurs when the underlying physical transaction takes place in thefuture and an associated financial instrument contract settlement is made.

The three instances ofnon-qualified hedges are as follows:

1.                **Transportation**—In our Marketing segment, when the pricingindex used for gas sales is different from the pricing index used for gaspurchases, we are exposed to relative changes in those two indices. By enteringinto a basis swap between those two indices, we can effectively lock in themargin on the combined gas purchase and gas sale, removing any market pricerisk on the physical transactions. Although this represents a sound economichedging strategy, these types of derivative transactions do not qualify forhedge accounting under SFAS No. 133, as the ultimate cash flow has notbeen fixed, only the margin.

F-38

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2.                **Storage**—In our Marketing segment, when we use derivativefinancial instruments to hedge market spreads around our owned or contractedassets, such as our gas storage portfolio, the underlying forecastedtransaction may or may not occur in the same period as originally forecast.This can occur because we have the flexibility to make these changes in theunderlying injection or withdrawal schedule, given changes in marketconditions. Therefore, these transactions do not qualify for hedge accountingtreatment under SFAS No. 133, as the forecasted transaction is no longerprobable of occurring as originally set forth in the hedge documentationestablished at the inception of the hedge.

3.                **Natural Gas Collars**—In our Natural Gas segment, we hadpreviously entered into natural gas collars to hedge the sales price of naturalgas. The natural gas collars were based on a NYMEX price, while the physicalgas sales were based on a different index. To better align the index of thenatural gas collars with the index of the underlying sales, we de-designatedthe original hedging relationship with the intent of contemporaneously re-designatingthe natural gas collars as hedges of physical natural gas sales with a NYMEXpricing index to better match the indices, which was a sound economic hedgingstrategy. However, because the fair value of these derivative instruments was aliability to us at re-designation, they are considered net writtenoptions under SFAS No. 133 and do not qualify for hedge accounting. Thesederivatives are now accounted for in the Consolidated Statements of Incomethrough mark-to-market accounting, with the changes in fair valuefrom the date of de-designation recorded to earnings each period. As aresult, our operating income will be subject to greater volatility due tomovements in the prices of natural gas until the underlying long-termtransactions are settled.

In each of the instancesdescribed above, the underlying physical purchase, storage and sale of naturalgas and NGLs are accounted for on a historical cost basis rather than on themark-to-market basis we utilize for the derivatives used to mitigate thecommodity price risk associated with our storage and transportation assets. Thisdifference in accounting (i.e., thefinancial side of the transaction is recorded at fair market values while thephysical side of the transaction is not) can and has resulted involatility in our reported net income, even though the economic margin isessentially unchanged from the date the transactions were consummated.

***Discontinuance ofHedge Accounting***

During the second quarterof 2005, we discontinued application of hedge accounting in connection withsome of our derivative financial instruments designated as hedges of forecastedsales and purchases of natural gas. We discontinued application of hedgeaccounting when we determined it was no longer probable that the originallyforecasted purchases and sales of natural gas would occur by the end of theoriginally specified time period, or within an additional two-month period oftime thereafter. As discussed above, this can occur because we have theflexibility to make changes to the underlying delivery points for ourtransportation assets and to the underlying injection or withdrawal schedulefor our storage assets, given changes in market conditions. One of the keycriteria to achieve hedge accounting under SFAS No. 133 is that theforecasted transaction be probable of occurring as originally set forth in thehedge documentation. As a result, during the second quarter of 2005, werecognized previously deferred unrealized losses in our Marketing segment ofapproximately $9.0 million from the discontinuance of hedge accounting. Indoing so, we reclassified the $9.0 million to Cost of natural gas on ourConsolidated Statements of Income from OCI. Going forward, the derivativefinancial instruments for which hedge accounting has been discontinued areconsidered to be non-qualified under SFAS No. 133, and must be marked-to-marketeach period, with the increases and decreases in fair value recorded asincreases and decreases in earnings. Also included in the loss fromdiscontinuance are approximately $2.1 million of net mark-to-market losses thatrelate to hedge positions that were closed out during the second quarter.

F-39

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The following table presents the unrealized lossesassociated with changes in the fair value of our derivatives, which arerecorded as an element of Cost of natural gas in our Consolidated Statements ofIncome and disclosed as a reconciling item on our Statements of Cash Flows:

| **Derivative fair value losses** | ** ** | ** **             | ** ** | **December 31,  2005** | ** ** | **December 31,  2004** | ** ** | **December 31,  2003** | ** ** |
|-------------------------------------------------|------------|------------------------|------------|-----------------------------|------------|-----------------------------|------------|-----------------------------|------------|
| ** **                                      | ** ** | **(in millions)** | ** ** |
| Natural Gas segment                             |       |                   |       |                        |       |                        |       |                        |       |   |   |   |   |
| Ineffectiveness                                 |       |                   | $          | 2.5                         |       |                        |       | $                           | 1.1        |   |   |   | $ | — |   |   |
| Non-qualified hedges                            |       |                   | 5.6        |                        |       |                        | —     |                        |       |   | — |   |   |
| Marketing                                       |       |                   |       |                        |       |                        |       |                        |       |   |   |   |   |
| Non-qualified hedges                            |       |                   | 41.3       |                        |       |                        | 2.1        |                        |       |   | 0.3 |   |   |
| Discontinuance                                  |       |                   | 9.0        |                        |       |                        | —     |                        |       |   | — |   |   |
| Derivative fair value losses                    |       |                   | $          | 58.4                        |       |                        |       | $                           | 3.2        |   |   |   | $ | 0.3 |   |   |

 

***De-designation andSettlement of Derivatives***

In connection with the sale of assets, as discussed inNote 3 to these Consolidated Financial Statements, we settled for cash ofapproximately $16.3 million, natural gas collars representing derivativefinancial instruments on sales of 2,000 MMBtu/d of natural gas through 2011. Wehad previously recorded unrealized losses associated with the natural gascollars that were realized upon settlement. Additionally, we de-designatedderivative financial instruments that were qualified for and designated as cashflow hedges of forecasted sales of 273 Bbl/d of NGLs through 2007 andcontemporaneously closed out the position by entering into an offsettingderivative financial instrument, at market, on forecasted purchases of 273Bbl/d of NGLs through 2007.

Ourderivative financial instruments are included at their fair values in theConsolidated Statements of Financial Position as follows:

| ** **                    | ** ** | **December 31,  2005** | ** ** | **December 31,  2004** | ** ** |
|-------------------------------|------------|-----------------------------|------------|-----------------------------|------------|
| ** **                    | ** ** | **(in millions)**      | ** ** |
| Receivables, trade and  other |       |                        | $          | 5.8                         |       |   |   | $ | 8.2 |   |   |
| Other assets, net             |       |                        | 4.2        |                        |       |   | 10.1 |   |   |
| Accounts payable and  other   |       |                        | (129.2     | )                           |       |   | (45.9 | ) |   |
| Other long-term liabilities   |       |                        | (243.0     | )                           |       |   | (99.6 | ) |   |
|                          |       |                        | $          | (362.2                      | )          |   |   | $ | (127.2 | ) |   |

 

The increase in ourobligation associated with our derivative activities from December 31,2004 to December 31, 2005 is primarily due to the significant increases inforward natural gas and NGL prices. The Partnership’s portfolio of derivativefinancial instruments is largely comprised of long-term fixed price salesand purchase agreements.

We record the change infair value of our highly effective cash flow hedges in our OCI until thederivative financial instruments are settled, at which time they arereclassified to earnings. Also included in OCI are unrecognized losses ofapproximately $8.0 million associated with derivative financial instrumentsthat qualified for and were classified as cash flow hedges of forecastedtransactions that were subsequently de-designated. These unrealized losses arereclassified to earnings over the periods during which the originally hedgedforecasted transactions affect earnings. For the twelve months ended December 31,2005, and 2004 we reclassified unrealized losses of $33.8 million and $12.6million from OCI to Cost of natural gas on our Consolidated Statements ofIncome for the fair value of derivative financial instruments that were settled.We estimate that approximately $83.7 million of OCI representing unrealized netlosses on cash flow hedging activities at December 31, 2005, will bereclassified to earnings during the next twelve months.

We do not requirecollateral or other security from the counterparties to our derivativefinancial instruments, all of which were rated “BBB+” or better by the majorcredit rating agencies.

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**16. SEGMENT INFORMATION**

Our business is divided into operating segments,defined as components of the enterprise, about which financial information isavailable and evaluated regularly by our Chief Operating Decision Maker indeciding how resources are allocated and performance is assessed.

Each of ourreportable segments is a business unit that offers different services andproducts that is managed separately, since each business segment requiresdifferent operating strategies. We have segregated our business activities intothree distinct operating segments:

·                    Liquids;

·                    NaturalGas; and

·                    Marketing.

The following tablepresents certain financial information relating to our business segments as ofand for the years ended December 31, 2005, 2004 and 2003.

| ** **                                     | ** ** | **As of and for the Year Ended December 31, 2005** | ** ** |
|------------------------------------------------|------------|-------------------------------------------------------------------------------------------------|------------|
| ** **                                     | ** ** | **Liquids**                                                                                     | ** ** | **Natural Gas** | ** ** | **Marketing** | ** ** | **Corporate**(1) | ** ** | **Total** | ** ** |
| ** **                                     | ** ** | **(in millions)**                                                                          | ** ** |
| Total revenues                                 |       | $                                                                                               | 418.0      |   |   | $ | 4,945.1 |   |   |   | $ | 3,884.2 |   |   |   | $ | — |   |   | $ | 9,247.3 |   |
| Less:  Intersegment revenue                    |       | —                                                                                          |       |   | 2,593.0 |   |   |   | 177.4 |   |   |   | — |   |   | 2,770.4 |   |
| Operating  revenues                            |       | 418.0                                                                                           |       |   | 2,352.1 |   |   |   | 3,706.8 |   |   |   | — |   |   | 6,476.9 |   |
| Cost of natural  gas                           |       |                                                                                            |       |   | 2,018.7 |   |   |   | 3,744.6 |   |   |   | — |   |   | 5,763.3 |   |
| Operating and  administrative                  |       | 144.2                                                                                           |       |   | 175.0 |   |   |   | 4.1 |   |   |   | 3.5 |   |   | 326.8 |   |
| Power                                          |       | 74.8                                                                                            |       |   | — |   |   |   |   |   |   |   | — |   |   | 74.8 |   |
| Depreciation and  amortization                 |       | 71.7                                                                                            |       |   | 66.0 |   |   |   | 0.5 |   |   |   | — |   |   | 138.2 |   |
| Gain on sale of  assets                        |       | —                                                                                          |       |   | (18.1 | ) |   |   | — |   |   |   | — |   |   | (18.1 | ) |
| Operating income                               |       | 127.3                                                                                           |       |   | 110.5 |   |   |   | (42.4 | ) |   |   | (3.5 | ) |   | 191.9 |   |
| Interest expense                               |       |                                                                                            |       |   | — |   |   |   | — |   |   |   | (107.7 | ) |   | (107.7 | ) |
| Rate refunds                                   |       | —                                                                                          |       |   | — |   |   |   | — |   |   |   | — |   |   | — |   |
| Other income                                   |       | —                                                                                          |       |   | — |   |   |   | — |   |   |   | 5.0 |   |   | 5.0 |   |
| Minority interest                              |       | —                                                                                          |       |   | — |   |   |   | — |   |   |   | — |   |   | — |   |
| Net income                                     |       | $                                                                                               | 127.3      |   |   | $ | 110.5 |   |   |   | $ | (42.4 | ) |   |   | $ | (106.2 | ) |   | $ | 89.2 |   |
| Total assets                                   |       | $                                                                                               | 1,664.0    |   |   | $ | 2,145.9 |   |   |   | $ | 512.3 |   |   |   | $ | 106.2 |   |   | $ | 4,428.4 |   |
| Capital expenditures  (excluding acquisitions) |       | $                                                                                               | 77.0       |   |   | $ | 263.8 |   |   |   | $ | 0.2 |   |   |   | $ | 3.8 |   |   | $ | 344.8 |   |

----

(1)                Corporateconsists of interest expense, interest income, minority interest and certainother costs such as franchise taxes, which are not allocated to the otherbusiness segments.

F-41

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| ** **                                     | ** ** | **As of and for the Year Ended December 31, 2004** | ** ** |
|------------------------------------------------|------------|-------------------------------------------------------------------------------------------------|------------|
| ** **                                     | ** ** | **Liquids**                                                                                     | ** ** | **Natural Gas** | ** ** | **Marketing** | ** ** | **Corporate**(1) | ** ** | **Total** | ** ** |
| ** **                                     | ** ** | **(in millions)**                                                                          | ** ** |
| Total revenues                                 |       | $                                                                                               | 409.3      |   |   | $ | 2,890.1 |   |   |   | $ | 2,686.9 |   |   |   | $ | — |   |   | $ | 5,986.3 |   |
| Less:  Intersegment revenue                    |       | —                                                                                          |       |   | 1,570.2 |   |   |   | 124.4 |   |   |   | — |   |   | 1,694.6 |   |
| Operating  revenues                            |       | 409.3                                                                                           |       |   | 1,319.9 |   |   |   | 2,562.5 |   |   |   | — |   |   | 4,291.7 |   |
| Cost of natural  gas                           |       | —                                                                                          |       |   | 1,031.8 |   |   |   | 2,555.3 |   |   |   | — |   |   | 3,587.1 |   |
| Operating and  administrative                  |       | 128.9                                                                                           |       |   | 138.3 |   |   |   | 3.4 |   |   |   | 3.5 |   |   | 274.1 |   |
| Power                                          |       | 72.8                                                                                            |       |   | — |   |   |   | — |   |   |   | — |   |   | 72.8 |   |
| Depreciation and  amortization                 |       | 68.5                                                                                            |       |   | 51.7 |   |   |   | 0.2 |   |   |   | 0.1 |   |   | 120.5 |   |
| Gain on sale of  assets                        |       | —                                                                                          |       |   | — |   |   |   | — |   |   |   | — |   |   | — |   |
| Operating income                               |       | 139.1                                                                                           |       |   | 98.1 |   |   |   | 3.6 |   |   |   | (3.6 | ) |   | 237.2 |   |
| Interest expense                               |       | —                                                                                          |       |   | — |   |   |   | — |   |   |   | (88.4 | ) |   | (88.4 | ) |
| Rate refunds                                   |       | —                                                                                          |       |   | — |   |   |   | — |   |   |   | (13.6 | ) |   | (13.6 | ) |
| Other income                                   |       | —                                                                                          |       |   | — |   |   |   | — |   |   |   | 3.0 |   |   | 3.0 |   |
| Minority interest                              |       | —                                                                                          |       |   | — |   |   |   | — |   |   |   | — |   |   | — |   |
| Net income                                     |       | $                                                                                               | 139.1      |   |   | $ | 98.1 |   |   |   | $ | 3.6 |   |   |   | $ | (102.6 | ) |   | $ | 138.2 |   |
| Total assets                                   |       | $                                                                                               | 1,639.8    |   |   | $ | 1,717.2 |   |   |   | $ | 313.7 |   |   |   | $ | 100.0 |   |   | $ | 3,770.7 |   |
| Capital expenditures  (excluding acquisitions) |       | $                                                                                               | 81.9       |   |   | $ | 197.4 |   |   |   | $ | 0.3 |   |   |   | $ | 9.2 |   |   | $ | 288.8 |   |

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(1)                Corporateconsists of interest expense, interest income, minority interest and certainother costs such as franchise taxes, which are not allocated to the otherbusiness segments.

| ** **                                     | ** ** | **As of and for the Year Ended December 31, 2003** | ** ** |
|------------------------------------------------|------------|-------------------------------------------------------------------------------------------------|------------|
| ** **                                     | ** ** | **Liquids**                                                                                     | ** ** | **Natural Gas** | ** ** | **Marketing** | ** ** | **Corporate**(1) | ** ** | **Total** | ** ** |
| ** **                                     | ** ** | **(in millions)**                                                                          | ** ** |
| Total revenues                                 |       | $                                                                                               | 344.2      |   |   | $ | 2,079.8 |   |   |   | $ | 1,984.9 |   |   |   | $ | — |   |   | $ | 4,408.9 |   |
| Less: Intersegment  revenue                    |       | —                                                                                          |       |   | 1,121.3 |   |   |   | 115.3 |   |   |   | — |   |   | 1,236.6 |   |
| Operating  revenues                            |       | 344.2                                                                                           |       |   | 958.5 |   |   |   | 1,869.6 |   |   |   | — |   |   | 3,172.3 |   |
| Cost of natural  gas                           |       | —                                                                                          |       |   | 754.9 |   |   |   | 1,857.8 |   |   |   | — |   |   | 2,612.7 |   |
| Operating and  administrative                  |       | 104.1                                                                                           |       |   | 102.3 |   |   |   | 2.2 |   |   |   | 3.2 |   |   | 211.8 |   |
| Power                                          |       | 56.1                                                                                            |       |   | — |   |   |   | — |   |   |   | — |   |   | 56.1 |   |
| Depreciation and  amortization                 |       | 59.5                                                                                            |       |   | 37.7 |   |   |   | 0.2 |   |   |   | — |   |   | 97.4 |   |
| Gain on sale of  assets                        |       | —                                                                                          |       |   | — |   |   |   | — |   |   |   | — |   |   | — |   |
| Operating income                               |       | 124.5                                                                                           |       |   | 63.6 |   |   |   | 9.4 |   |   |   | (3.2 | ) |   | 194.3 |   |
| Interest expense                               |       | —                                                                                          |       |   | — |   |   |   | — |   |   |   | (85.0 | ) |   | (85.0 | ) |
| Rate refunds                                   |       | —                                                                                          |       |   | — |   |   |   | — |   |   |   | — |   |   | — |   |
| Other income                                   |       | —                                                                                          |       |   | — |   |   |   | — |   |   |   | 2.4 |   |   | 2.4 |   |
| Minority interest                              |       | —                                                                                          |       |   | — |   |   |   | — |   |   |   | — |   |   | — |   |
| Net income                                     |       | $                                                                                               | 124.5      |   |   | $ | 63.6 |   |   |   | $ | 9.4 |   |   |   | $ | (85.8 | ) |   | $ | 111.7 |   |
| Total assets                                   |       | $                                                                                               | 1,511.2    |   |   | $ | 1,490.5 |   |   |   | $ | 189.6 |   |   |   | $ | 40.5 |   |   | $ | 3,231.8 |   |
| Capital expenditures  (excluding acquisitions) |       | $                                                                                               | 69.3       |   |   | $ | 55.4 |   |   |   | $ | 0.1 |   |   |   | $ | 4.5 |   |   | $ | 129.3 |   |

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(1)                Corporateconsists of interest expense, interest income, minority interest and certainother costs such as franchise taxes, which are not allocated to the otherbusiness segments.

F-42

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**17. SUBSEQUENT EVENTS**

***Cash Distribution***

On January 30, 2006,Enbridge Management’s Board of Directors declared a distribution payable to ourpartners on February 14, 2006. The distribution was paid to unitholders ofrecord as of February 7, 2006, of our available cash of $67.6 millionat December 31, 2005, or $0.925 per common unit. Of this distribution,$56.6 million was paid in cash, $10.8 million was distributed ini-units to i-unit holders and $0.2 million was retained from the GeneralPartner in respect of this i-unit distribution.

**18.QUARTERLY FINANCIAL DATA (Unaudited)**

| ** **                           | ** ** | **First**                                                                        | ** ** | **Second** | ** ** | **Third** | ** ** | **Fourth** | ** ** | **Total** | ** ** |
|--------------------------------------|------------|----------------------------------------------------------------------------------|------------|------------|------------|-----------|------------|------------|------------|-----------|------------|
| ** **                           | ** ** | **(dollars in millions, except per unit amounts)** | ** ** |
| **2005  Quarters**                   |       |                                                                             |       |       |       |      |       |       |       |      |       |
| Operating revenue                    |       | $                                                                                | 1,250.1    |       | $          | 1,332.7   |       | $          | 1,809.6    |      | $          | 2,084.5 |   | $ | 6,476.9 |   |
| Operating income                     |       | $                                                                                | 53.2       |       | $          | 50.6      |       | $          | 11.9       |      | $          | 76.2 |   | $ | 191.9 |   |
| Net income                           |       | $                                                                                | 28.2       |       | $          | 25.7      |       | $          | (14.4      | )         | $          | 49.7 |   | $ | 89.2 |   |
| Net income per  common and i-unit(1) |       | $                                                                                | 0.37       |       | $          | 0.32      |       | $          | (0.32      | )         | $          | 0.69 |   | $ | 1.06 |   |
| **2004  Quarters**                   |       |                                                                             |       |       |       |      |       |       |       |      |       |
| Operating revenue                    |       | $                                                                                | 982.5      |       | $          | 969.7     |       | $          | 1,004.8    |      | $          | 1,334.7 |   | $ | 4,291.7 |   |
| Operating income                     |       | $                                                                                | 52.6       |       | $          | 58.0      |       | $          | 61.6       |      | $          | 65.0 |   | $ | 237.2 |   |
| Net income                           |       | $                                                                                | 33.1       |       | $          | 35.9      |       | $          | 27.6       |      | $          | 41.6 |   | $ | 138.2 |   |
| Net income per common  and i-unit(1) |       | $                                                                                | 0.50       |       | $          | 0.56      |       | $          | 0.39       |      | $          | 0.61 |   | $ | 2.06 |   |

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(1)                The GeneralPartner’s allocation of net income has been deducted before calculating netincome per common and i-unit.

F-43

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