**Exhibit 99.2**
| **Annual Report on**                |
|-------------------------------------|
| **Form 10-K**                  |
| **of**                              |
| **Enbridge  Energy Partners, L.P.** |

** **

 

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**UNITEDSTATES**

**SECURITIES AND EXCHANGECOMMISSION**

**Washington,D.C. 20549**

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**FORM 10-K**

**x**                               ANNUAL REPORT PURSUANT TO SECTION 13OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

**Forthe fiscal year ended DECEMBER 31, 2006**

**OR**

**o**                                  TRANSITION REPORT PURSUANT TO SECTION 13OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

**Forthe transition period from                    to                    **

**CommissionFile Number: 1-10934**

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

(Exact name of Registrantas 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 principalexecutive offices and zip code)

**(713)821-2000**

(Registrant’s telephone number, including area code)

Securities registeredpursuant to Section 12(b) of the 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 ifthe registrant is a well-known seasoned issuer, as defined in Rule 405 ofthe Securities Act. Yes x No o

Indicate by check mark ifthe registrant is not required to file reports pursuant to Section 13 or Section 15(d) ofthe Act. Yes o  No x

Indicate by check markwhether the Registrant (1) has filed all reports required to be filed by Section 13or 15(d) of the Securities Exchange Act of 1934 during the preceding12 months (or for such shorter period that the Registrant was required tofile such reports), and (2) has been subject to such filing requirementsfor the past 90 days. Yes x  No o

Indicate by check mark ifdisclosure of delinquent filers pursuant to Item 405 of Regulation S-K isnot contained herein, and will not be contained, to the best of the Registrant’sknowledge, in definitive proxy or information statements incorporated byreference in Part III of this Form 10-K or any amendment tothis Form 10-K. o

Indicateby check mark whether the registrant is a large accelerated filer, anaccelerated filer, or a non-accelerated filer. See definition of “acceleratedfiler and large accelerated filer” in Rule 12b-2 of the Exchange Act.
| Large Accelerated Filer x | Accelerated Filer o | Non-Accelerated  Filer o |
|---------------------------|---------------------|--------------------------|

 

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

The aggregate market valueof the Registrant’s Class A Common Units held by non-affiliates computedby reference to the price at which the common equity was last sold, or theaverage bid and asked price of such common equity, as of June 30, 2006,was $2,174,836,221.

As of February 22,2007 the Registrant has 49,938,834 Class A common units outstanding.

**DOCUMENTSINCORPORATED BY REFERENCE: NONE**

 

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**TABLEOF CONTENTS**

|                                                 | ** ** | ** **                                                                                  | ** ** | **Page** |
|-------------------------------------------------|------------|---------------------------------------------------------------------------------------------|------------|----------|
|                                            | ** ** | **PART I**                                                                             |       |     |
| **Item 1.**                                     |       | Business                                                                                    |       | 6        |
| **Item 1A.**                                    |       | Risk Factors                                                                                |       | 37       |
| **Item 1B.**                                    |       | Unresolved Staff Comments                                                                   |       | 49       |
| **Item 2.**                                     |       | Properties                                                                                  |       | 49       |
| **Item 3.**                                     |       | Legal Proceedings                                                                           |       | 49       |
| **Item 4.**                                     |       | Submission of Matters to a  Vote of Security Holders                                        |       | 49       |
|                                            | ** ** | **PART II**                                                                            |       |     |
| **Item 5.**                                     |       | Market for Registrant’s  Common Equity and Related Unitholder Matters                  |       | 50       |
| **Item 6.**                                     |       | Selected Financial Data                                                                     |       | 51       |
| **Item 7.**                                     |       | Management’s Discussion and  Analysis of Financial Condition and Results of Operations |       | 53       |
| **Item 7A.**                                    |       | Quantitative and Qualitative  Disclosures About Market Risk                                 |       | 92       |
| **Item 8.**                                     |       | Financial Statements and  Supplementary Data                                                |       | 99       |
| **Item 9.**                                     |       | Changes in and Disagreements  with Accountants on Accounting and Financial Disclosure       |       | 99       |
| **Item 9A.**                                    |       | Controls and Procedures                                                                     |       | 100      |
| **Item 9B.**                                    |       | Other Information                                                                           |       | 100      |
|                                            | ** ** | **PART III**                                                                           |       |     |
| **Item 10.**                                    |       | Directors and Executive  Officers of the Registrant                                         |       | 101      |
| **Item 11.**                                    |       | Executive Compensation                                                                      |       | 105      |
| **Item 12.**                                    |       | Security Ownership of  Certain Beneficial Owners and Management                             |       | 117      |
| **Item 13.**                                    |       | Certain  Relationships and Related Transactions, and Director Independence                  |       | 118      |
| **Item 14.**                                    |       | Principal Accountant Fees  and Services                                                     |       | 120      |
|                                            | ** ** | **PART IV**                                                                            |       |     |
| **Item 15.**                                    |       | Exhibits and Financial  Statement Schedules                                                 |       | 121      |
| **Signatures**                                  |       | 122                                                                                         |
| **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-Kare defined 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                                                                |
| AOCI                  |   | Accumulated  other comprehensive income                                                                                                                                                                        |
| 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 our 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  acquired October 17, 2002. |
| 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 and crude oil                                                                                                                                        |
| EP Act                |   | Energy  Policy Act of 1992                                                                                                                                                                                     |
| EPACT                 |   | Energy  Policy Act of 2005                                                                                                                                                                                     |
| EPA                   |   | Environmental  Protection Agency                                                                                                                                                                               |
| Exchange Act          |   | Securities  Exchange Act of 1934, as amended                                                                                                                                                                   |
| 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                                                                                                                                         |
| 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                                                                                   |
| M(3)                  |   | 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                                                                                                                                                                                    |

3

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| 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                                                                                                                                                                                                                             |
| NOPR                     |   | Notice  of Proposed Rulemaking issued by the FERC.                                                                                                                                                                                                  |
| 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 I                   |   | Consists of Connecticut,  Delaware, District of Columbia, Florida, Georgia, Maine, Maryland,  Massachusetts, New Hampshire, New Jersey, New York, North Carolina,  Pennsylvania, Rhode Island, South Carolina, Vermont, Virginia and West  Virginia |
| 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                                |
| Partnership   Agreement  |   | Fourth 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)                                                                                                                                                                              |
| PIPES of 2006            |   | Pipeline  Inspection, Protection, Enforcement, and Safety Act of 2006                                                                                                                                                                               |
| 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                                                                                                                                                                                                                 |

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| 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                                                                                                   |
| SFPP                   |   | Sante  Fe Pacific Pipelines, L.P., an unrelated pipeline company                                                                               |
| Suncor                 |   | Suncor  Energy Inc., an unrelated energy company                                                                                               |
| Syncrude               |   | Syncrude  Canada Ltd., an unrelated energy 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 oil andliquid petroleum transportation and storage assets, and natural gas gathering,treating, processing, transportation and marketing assets in the United Statesof America. Our Class A common units are traded on the NYSE under thesymbol “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 ofinterests and assets relating to the midstream energy sector. As ofDecember 31, 2006, our portfolio of assets include the following:

·       Approximately4,900 miles of crude oil gathering and transportation lines and24.5 million Bbl of crude oil storage and terminaling capacity.

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

·       Nineactive natural gas treating and 17 active natural gas processing facilitieswith an aggregate capacity of approximately 1,800 million cubic feet per day,or 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.Under a 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.”

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Ourownership at December 31, 2006 is comprised of the following:

| ** **                                              | ** ** | **2006** | ** ** |
|---------------------------------------------------------|------------|----------|------------|
| Class A common  units owned by the public               |       | 63.1     | %          |
| Class B  common units owned by our General Partner |       | 4.9      | %          |
| Class C  units owned by our General Partner        |       | 7.0      | %          |
| Class C  units owned by an institutional investor  |       | 7.0      | %          |
| i-units owned by  Enbridge Management                   |       | 16.0     | %          |
| General Partner  interest                               |       | 2.0      | %          |
|                                                    |       | 100.0    | %          |

 

**BUSINESS STRATEGY**

Our primary objective is to provide stable andsustainable cash distributions to our unitholders, while maintaining arelatively low investment risk profile. Our business strategies focus oncreating value for our customers, which we believe is the key to creating valuefor our investors. To accomplish our objective, we focus on the following keystrategies:

1.     Expand existing 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.     Develop new asset platforms

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

3.     Focus on 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 enhancethe value of services we provide 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 internal growthfor both our liquids and natural gas businesses will require a significantinvestment of expansion capital over the next few years. While these majorprojects are under construction, our ability to increase distributions, whilealso funding these projects, is likely to be limited. Our outlook is premisedon a number of major assumptions regarding the scope and timing of theprojects, financing alternatives available to us and excludes the potential ofsignificant acquisitions during the period. We expect our larger growthprojects will be accretive to distributable cash flow when placed into service.These projects are discussed below in the respective business section.

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***Liquids***

The following map presentsthe locations of our current Liquids systems assets:

This map depicts someassets owned by Enbridge to provide an understanding of how they interconnectwith our Liquids systems.

Western Canadian crude oil is an important source ofsupply for the United States. According to the latest available data for 2006from the U.S. Department of Energy’s Energy Information Administration, Canadasupplied approximately 1.6 million barrels per day, or Bpd, of crude oil to theU.S., the largest source of U.S. imports. Of the Canadian crude oil moving intothe U.S., about 69% was transported on the System, which is the primarypipeline from western Canada to the U.S. We are well positioned to developadditional infrastructure to deliver growing volumes of crude oil that areexpected from the Alberta oil sands. With an estimated $82 billion of active orplanned projects in the Alberta oil sands, new production is expected to growsteadily during the next 5 years, with an additional 2.4 million Bpd ofincremental supply available by 2015, according to the Canadian Association ofPetroleum Producers, or CAPP.

Our Southern Access project is the cornerstone of ourmainline expansion initiatives to address the expected increase in supply ofwestern Canadian crude oil. Our $1.3 billion project will provide anadditional 400,000 Bpd of heavy crude oil capacity to the Chicago market andbeyond by early 2009, with nearly half of this capacity available in early2008. The design will also permit a further 800,000 Bpd increase in capacityfor minimal additional cost, in conjunction with a corresponding expansionupstream of Superior. The Southern Access project involves new pipelineconstruction on our Lakehead system along with expansion on the Canadianportion of the pipeline by Enbridge.

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Additionally, we and Enbridge are developing theAlberta Clipper project, which will involve construction of a 990 mile, 36-inchdiameter, heavy crude oil pipeline from Hardisty, Alberta to Superior,Wisconsin with an initial capacity of 450,000 Bpd that is expandable to 800,000Bpd. Our share of the cost of this project as currently proposed will beapproximately $0.8 billion (excluding capitalized interest). Alberta Clipper isexpected to be in-service in late 2009 to mid 2010. Regulatory applications will be filed oncecommercial terms are finalized, which is expected to occur in the first quarterof 2007.

Along with Enbridge, weare actively working with our customers to develop options that will allow Canadiancrude oil to access new markets. The market strategy we are undertaking is toprovide timely, economical, integrated transportation solutions to connectgrowing supplies of production from the Alberta oil sands to key refinerymarkets in the United States. The strategy involves further penetration intoPADD II as well as entry into the vast refining center of the U.S. Gulf Coast.On April 28, 2005, the NEB approved two applications filed by EnbridgePipelines to recover the costs for the extension of service to other marketsvia Enbridge’s Spearhead pipeline and ExxonMobil’s Pegasus pipeline through itsCanadian tolls over the next 5 years. Through these initiatives, westernCanadian crude oil is being delivered into Cushing, Oklahoma and Beaumont,Texas, respectively, since the first quarter of 2006. We benefit from theseinitiatives, as western Canadian crude oil is carried on our Lakehead system asfar as Chicago and then transferred to these other pipelines to access thesemarkets.

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***Natural Gas***

Thefollowing map presents the locations of our Natural Gas systems assets:

This map depicts someassets owned by Enbridge to provide an understanding of how they relate to ourNatural Gas systems.

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 are experiencing consistent growth in natural gas land leases, drillingand production. These core basins are known as the East Texas basin, the FortWorth Basin and the Anadarko basin. Our focus has been on acquiring assets withstrong growth prospects located in these areas and then to continue to developthose prospects.

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 safe andreliable 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 greater 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 

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market hubs in Texas andLouisiana. From these market hubs, natural gas can be transported to consumersin the Midwest and Northeast United States. Our trucking operations are used toenhance the value of the NGLs produced at our processing plants by ensuringready access to strategic markets. Our marketing business also helps maximizethe value received for the natural gas we transport and purchase by identifyingcustomers with consistent demand for natural gas.

The growth prospects in our core areas are primarily aresult of strong commodity prices, rig utilization rates 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, new pipelinesand treating plant re-activations. During April 2006, we purchased $33million of additional natural gas gathering and processing assets in EastTexas, which we have integrated with our existing East 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 intrastatetransportation pipeline to carry increased volumes of natural gas to thepipeline hub at Carthage, Texas. Carthage access is important because it offersa number of connections to interstate pipelines, which tend to support morefavorable natural gas prices for our customers. In January 2006, weannounced a $610 million expansion and extension of our East Texas system. Thisproject is required to handle the strong growth occurring in East Texas naturalgas production, particularly from the Bossier Sands and other regionalproducing formations. We coordinated extensively with our customers to developand enhance access for growing Texas natural gas production to major markets insoutheast Texas. We have firm volume commitments and acreage dedications whichwe believe will approximate 550 MMcf/day, of the 700 MMcf/day of capacity, bythe end of 2007. The project is designed to be expandable and is positioned forpotential upstream and downstream extension.

**BUSINESSSEGMENTS**

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 financial statements.

***Liquids Segment***

***Lakehead system***

The Lakehead system consists primarily of a crude oiland liquid petroleum common carrier pipeline and terminal 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.

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Our Lakehead system is a FERC-regulated interstatecommon carrier pipeline system. The Lakehead system spans a distance ofapproximately 1,900 miles, and consists of approximately 3,500 miles of pipewith diameters ranging from 12 inches to 48 inches, 59 pump station locationswith a total of approximately 768,000 installed horsepower and 62 crude oilstorage tanks with an aggregate working capacity of approximately10.8 million barrels. The System operates in a segregation, or batch mode,allowing the transport of 59 crude oil commodities including light, medium andheavy crude oil (including bitumen, which is a naturally occurring tar-likemixture of hydrocarbons), condensate and NGLs.

*Customers.*   OurLakehead system operates under month-to-month transportation arrangements withour shippers. During 2006, approximately 30 shippers tendered crude oil andliquid petroleum for delivery through the Lakehead system. We consider multiplecompanies that are controlled by a common entity to be a single shipper forpurposes of determining the number of shippers delivering crude oil and liquidpetroleum on our Lakehead system. Our customers include integrated oilcompanies, major independent oil producers, refiners and marketers.

*Supplyand Demand.*   OurLakehead system is well positioned as the primary transporter of westernCanadian crude oil and continues to benefit from the growing production ofcrude oil from the Alberta oil sands. Similar to U.S. domestic conventionalcrude oil production, western Canada’s conventional crude oil production isdeclining. Over the last severalyears, development of the Alberta oil sands resource has more than offsetdeclining conventional production. The NEB estimated that total WCSB 2006production averaged approximately 2.3 million Bpd compared with 2.2million bpd in 2005. WCSB crude oil production is comparable with productionfrom key OPEC members Kuwait and Venezuela.

Remaining established conventional oil reserves inwestern Canada were estimated to be approximately 3.8 billion barrels at theend of 2005. During 2005, the latest period for which data is available,approximately 105 percent****of conventional production wasreplaced with reserve additions. Remaining established reserves from theAlberta oil sands as of the end of 2005, stand at approximately 174 billionbarrels. Combined conventional and oil sands established reserves ofapproximately 179 billion barrels compares with Saudi Arabia’s proved reservesof approximately 260 billion barrels.

According to CAPP, an estimated $46 billion has beenspent on oil sands development from 1996 through 2005. A survey of CAPP membersand oil sands developers estimate that oil producers may spend an additional$82 billion by 2016, including all announced and planned oil sandsprojects. Although it is unlikely that all projects will proceed as planned,the investment already in place and the number and size of companies involvedprovides strong evidence of ongoing oil sands industry expansion. CAPPestimates future production from the Alberta oil sands will increase by morethan 2.4 million barrels per day****by2015 based on a subset of currently approved applications and announcedexpansions.

The near-term growth in crude oil supply comes fromthe completion and consolidation of major expansion projects at existingsynthetic crude oil upgraders and growth of bitumen production from bothexisting and new SAGD facilities currently under construction. Over the nextyear, synthetic crude oil production capacity is expected to increase byapproximately 83,000 Bpd****at theexisting plants.

Syncrude completed a 100,000 Bpd Stage 3 expansionover the past year, increasing total production capacity to 350,000 Bpd.However, the new Stage 3 coker suffered from a number of start-up issues thatprevented Syncrude from attaining full utilization of its production capacity.Syncrude’s next expansion will de-bottleneck the current system to increasesynthetic production by approximately 40,000 Bpd to approximately 390,000 Bpdby 2011.

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Suncor completed its35,000 Bpd expansion in late 2005 resulting in total upgrading capacity of260,000 Bpd. Average synthetic production from the upgrader was 253,000 Bpd in2006. Suncor also received conditionalapproval from the AEUB for its proposed Voyageur expansion, which will increasesynthetic production capacity to 500,000 Bpd by 2012.

The Athabasca Oil Sands Project, or AOSP, owned byShell Canada Limited (60%), Chevron Canada Limited (20%) and Western Oil SandsL.P. (20%), is another oil sands project that reached full production capacityin 2004. The AOSP project moved forward with the AEUB’s conditional approval ofthe proposed AOSP Expansion 1 project. The AOSP Expansion 1 project aims toachieve an expansion from the current capacity of 165,000 Bpd to more than255,000 Bpd by 2010.

Over the next two years, unblended bitumen productionis expected to start, or increase, from more than ten individual****projects that are coming on line. Notableprojects include the expansions at Canadian Natural’s Wolf Lake/Primrose area,ConocoPhillips’ Surmont, Devon’s Jackfish, EnCana’s Foster Creek and ChristianaLake, Husky’s Sunrise, Suncor’s Firebag and Total’s Josyln project. Based onthe AEUB forecast, unblended bitumen production is expected to increase byroughly 60,000 Bpd by the end of 2007, more than offsetting the decline inconventional crude production.

Although the crudeoil and liquid petroleum delivered through the Lakehead system primarilyoriginates in oilfields in western Canada, the Lakehead system also receivesapproximately five percent****of its receipts from domesticsources including:

·       U.S.production at Clearbrook, Minnesota through a connection with the North Dakotasystem;

·       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 upgrader expansions and increased bitumenproduction, Lakehead system deliveries are expected to average 1.64 million Bpd in 2007 compared with1.52 million Bpd in 2006. The estimated deliveries for 2007 are part of aforecast representing forward-looking information and is subject to risks,uncertainties, and factors beyond our control.

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, 2006 demandfor crude oil in PADD II remained relatively unchanged from 2005 with anaverage of 3.3 million Bpd. At the same time, production of crude oil withinPADD II increased marginally by 13,000 Bpd to 456,000 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 theLakehead system to increase along with increases in WCSB supply. Based on ourindustry survey, we expect refineries in the PADD II market to competeaggressively with new markets for access to the growing supply from the WCSB.

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In conjunction with Enbridge, we announced the 400,000Bpd Southern Access expansion project in 2005. The first stage of the U.S.portion of the expansion on Lakehead will 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 completionexpected in early 2009. Completion of the total Southern Access expansionproject will create a new 454-mile pipeline with approximately 400,000Bpd of incremental capacity on our Lakehead system.

On March 16, 2006, the Federal Energy RegulatoryCommission (“FERC”) approved an Offer of Settlement with respect to rateprinciples for the Southern Access expansion, which were negotiated with CAPP. InJuly 2006, support from shippers and CAPP was obtained to increase thediameter of the new pipeline segment of the project from 36 inches to 42 inches.The incremental capital cost of the larger diameter pipe is currently estimatedat approximately $157 million, bringing our total estimated portion of thecosts to approximately $1.3 billion. The larger diameter will not provideincreased capacity in the near term but does increase the ultimate expansioncapacity of the line from 800,000 Bpd to 1,200,000 Bpd with additional pumpinghorsepower. This improves future expansion opportunities for our Lakeheadsystem. Return on the incremental capital for the larger diameter pipe will bedeferred until the additional capacity is required by shippers (see discussionof Alberta Clipper project below). In the interim, shippers will absorb all theincremental operating costs of the larger diameter pipe but will benefit fromreduced power costs at higher throughput levels. Delivery of line pipe to therights-of-way has commenced to ensure full completion in early 2009.

In July 2006, Enbridge announced that it had receivedsupport from shippers and CAPP for its 36-inch diameter, 400,000 BpdSouthern Access Extension pipeline from Flanagan, Illinois to Patoka, Illinois.The extension will broaden the reach of the Enbridge/Lakehead mainline systemto incremental markets accessible from the Patoka hub. The project will beundertaken by Enbridge; however, our Lakehead system will benefit fromincremental volumes moving through the system to connect with this extension. AFERC Offer of Settlement was filed on September 1, 2006. On December 8,2006, the FERC rejected the rolled in rate design contained in the Offer ofSettlement. However, supportfor the project remains very strong and Enbridge is preparing an alternativetolling structure to address the initial opposition from the interveningparties. It is expected that a second application will be filed with the FERCin the first quarter of 2007 to allow the project to continue on schedule, witha 2009 in-service date.

Based on forecasts of oil sands production growthprepared by Enbridge, as well as forecasts by CAPP, it is believed that therewill be a need for additional export pipeline capacity out of western Canadaover and above projects described above. Based on this analysis, as well asinterest expressed by shippers, we and Enbridge are developing the AlbertaClipper project. This project will involve construction of a 990-mile, 36-inchdiameter, heavy crude line from Hardisty, Alberta to Superior, Wisconsinwith an initial capacity of 450,000 Bpd that is expandable to 800,000 Bpd. Ourshare of the cost of this project as currently proposed will be approximately$0.8 billion (in 2006 dollars, excluding capitalized interest).

Based on discussions with our shippers the preferenceis for the Alberta Clipper Project to be a common carrier pipeline fullyintegrated with the System for rate-making purposes. Alberta Clipper isexpected to be in-service in late 2009 to mid 2010. Regulatory applications will be filed oncecommercial terms are finalized, which we expect to occur in the first quarterof 2007.

During the first quarter of 2006, Enbridge completedthe reversal of its Spearhead Pipeline that now flows from Chicago, Illinois toCushing, Oklahoma, with a capacity of 125,000 Bpd. In March 2006, thefirst western Canadian crude oil was delivered through this system into themajor oil hub at Cushing. Our Lakehead system benefits from the reversal of theSpearhead pipeline as western Canadian crude oil is 

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carried on our Lakeheadsystem as far as the Chicago region and then transferred to the Spearheadpipeline.

In April 2006, ExxonMobil announced it hadcompleted the reversal of two of its crude oil pipelines allowing up to 66,000Bpd of Canadian crude oil to flow from Patoka, Illinois to the U.S. Gulf Coast.The pipeline is linked to our Lakehead system at Chicago via the Mustang PipeLine LLC system to Patoka, Illinois. The Mustang system is 30% owned by anaffiliate of Enbridge. ExxonMobil has received firm commitments from Canadianshippers for an average of 50,000 Bpd of capacity on the lines from Patoka, toNederland, Texas for the next five years. The connection of our Lakehead systemwith this new market should also support increased throughput on our Lakeheadsystem; however, the reversed ExxonMobil system is also capable of transportingwestern Canadian crude oil moved via other competing pipelines into the Patokamarket.

*Competition.**  *Our Lakehead system, along with the Enbridge system, is the maincrude oil export route from the WCSB. WCSB production in excess of westernCanadian demand moves on existing pipelines into the Midwest area of the UnitedStates (PADD II), the Rocky Mountain states (PADD IV), the Anacortes area ofWashington State (PADD V), and the U.S. Gulf Coast (PADD III). In each of theseregions, WCSB crude oil competes with local and imported crude oil. As localcrude oil production declines and refineries demand more imported crude oil,imports from the WCSB should increase.

In 2005, PADD II imported approximately 1 million Bpdof Canadian crude. For 2006, the latest data available shows that PADD II totaldemand was 3.3 million Bpd while it produced only 456,000 Bpd, and thusimported 2.85 million Bpd. For the first ten months of 2006, PADD II importedapproximately 1.1 million Bpd of crude oil from Canada, and the remainder wasimported from PADD III and offshore sources through the U.S. Gulf Coast. Of thecrude oil imported from Canada, 2006 actual volumes transported on our Lakeheadsystem to PADD II averaged 1.1 million Bpd****including deliveries to destinationsin PADD II, and to other pipeline systems with PADD III destinations. Lakehead systemdeliveries of Canadian crude oil to PADD II increased by approximately 152,000Bpd in 2006, a 16% increase from 2005 volumes. Total deliveries on our Lakeheadsystem averaged 1.52 million Bpd in 2006, meeting approximately 71****percent of Minnesota refinery capacity; 62percent of the greater Chicago area; and 82 percent of Ontario’s refinerydemand.

Considering all of the pipeline systems that transportwestern Canadian crude oil out of Canada, the System transported approximately69 percent of the total western Canadian crude oil exports in 2006 to theUnited States. The remaining production was transported by systems serving theBritish Columbia, PADD IV and PADD V markets.

Given the expected increase in crude oil productionfrom the Alberta oil sands over the next 10 years, alternative transportationproposals have been presented to crude oil producers. These proposals rangefrom expansions of existing pipelines currently transporting western Canadiancrude oil to new pipelines and extensions of existing pipelines. These proposalsare in various stages of development, with some at the concept stage and othersthat are proceeding with regulatory approval. Some of these proposals could bein direct competition with our Lakehead system.

Enbridge has proposed construction of the GatewayPipeline in the 2012 to 2014 timeframe, which includes both a condensate importpipeline and a petroleum export pipeline. The condensate line would transportimported diluent from Kitimat, British Columbia to the Edmonton, Alberta area. Thepetroleum export line would transport crude oil from the Edmonton area toKitimat and would compete with our Lakehead system for production from theAlberta oil sands.

Shippers have indicated interest to Enbridge indevelopment of additional pipeline capacity to transport Canadian crude oil tothe U.S. Gulf Coast, including the potential for a direct line from Alberta tothe Gulf Coast. Enbridge is examining a number of alternatives to respond tothis interest, including 

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alternatives that wouldextend off our Lakehead system, utilizing either existing pipelines, whichcould be connected and reversed, or newly constructed extensions. Thesealternatives would complement our Lakehead system and support its expansion.Enbridge has indicated that a direct line would require a minimum of 400,000Bpd of throughput commitments to be economic, and could not be in servicebefore 2011. A direct line, if developed by Enbridge or any other party, wouldcompete with our Lakehead system.

The followingprovides an overview of other proposals put forth by competitor pipelinecompanies that are not affiliated with Enbridge:

·       The construction of a new 24-inchpipeline alongside an existing pipeline which begins in Clearbrook, Minnesotaand transports western Canadian crude oil to St. Paul, Minnesota. Thisexpansion will have 165,000 Bpd initial capacity and 350,000 Bpd ultimatecapacity. Construction is planned for summer 2007, with a completion date in2008. While throughput on our Lakehead system would benefit from thisexpansion, volumes moving on our Lakehead system would only be negativelyimpacted if the Wood River to St. Paul pipeline were to be reversed.

·       The expansion of anexisting pipeline that runs from Alberta to British Columbia and Washingtonstate. The first phase of this expansion to add 35,000 Bpd of capacity wasapproved by the NEB in 2005 and is expected to be in service in 2007. Thesecond phase received NEB approval in October 2006, and would furtherincrease capacity by another 40,000 Bpd by 2009. Additional phases have alsobeen proposed which would add substantial additional capacities.

·       Construction of a new435,000 Bpd crude oil pipeline from Hardisty, Alberta to Wood River and Patoka,with an expected in-service date of late 2009. This proposal has support oflong-term contracts for a total of 340,000 Bpd. The sponsor company filedapplications with the NEB in June 2006 to convert part of its mainline gastransmission facilities, and in December 2006, for approval to operate andconstruct facilities in Canada. Public hearings on the gas line transferapplication were held in mid-November 2006 and in early 2007 the NEBapproved transfer of the gas transmission facilities to crude oil service,although additional approvals will be required from United States and Canadianregulatory authorities before the project can proceed. The company is alsoproposing an expansion to 590,000 Bpd and an extension to Cushing, Oklahoma. Anopen season will be held in the early part of 2007 to determine shipperinterest and a variety of regulatory approvals will be required in the UnitedStates at state and local levels before the proposal can proceed.

·       Construction of a new crudeoil pipeline from northern Alberta directly to the U.S. Gulf Coast. Thisconceptual pipeline proposal is subject to shipper support and regulatoryapproval.

These competing alternatives for delivering westernCanadian crude oil into the United States and other markets could erode shippersupport for further expansion of our Lakehead system beyond the Southern AccessExpansion and the Alberta Clipper Project. They could also affect throughput onand utilization of the System. However, the Lakehead and Enbridge systems offersignificant cost savings and flexibility advantages, which are expected tocontinue to favor the systems as the preferred alternative for meeting shippertransportation requirements to the Midwest United States.

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Thefollowing table sets forth average deliveries per day and barrel miles of ourLakehead system for each of the periods presented.

| ** **                            | ** ** | **Deliveries**                   | ** ** |
|---------------------------------------|------------|----------------------------------|------------|
| ** **                            | ** ** | **2006**                         | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
| ** **                            | ** ** | **(thousands of Bpd)** | ** ** |
| **United States**                     |       |                             |       |   |   |   |   |   |   |   |   |
| Light crude oil                       |       | 327                              |       | 241 |   | 275 |   | 258 |   | 266 |   |
| Medium and heavy crude  oil           |       | 872                              |       | 791 |   | 785 |   | 741 |   | 665 |   |
| NGL                                   |       | 5                                |       | 4 |   | 4 |   | 4 |   | 6 |   |
| Total United States                   |       | 1,204                            |       | 1,036 |   | 1,064 |   | 1,003 |   | 937 |   |
| **Ontario**                           |       |                             |       |   |   |   |   |   |   |   |   |
| Light crude oil                       |       | 160                              |       | 146 |   | 174 |   | 174 |   | 171 |   |
| Medium and heavy crude  oil           |       | 63                               |       | 59 |   | 81 |   | 68 |   | 83 |   |
| NGL                                   |       | 90                               |       | 98 |   | 103 |   | 109 |   | 111 |   |
| Total Ontario                         |       | 313                              |       | 303 |   | 358 |   | 351 |   | 365 |   |
| **Total Deliveries**                  |       | 1,517                            |       | 1,339 |   | 1,422 |   | 1,354 |   | 1,302 |   |
| **Barrel  miles** (billions per year) |       | 400                              |       | 338 |   | 367 |   | 345 |   | 341 |   |

 

**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 12.8 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 11 newtanks during 2007 to our existing storage facilities in Cushing, which willincrease our crude oil storage capacity to 16.7 million barrels by the end of2007. A portion of the storage facilities are used for operational purposeswhile we contract the remainder of the facilities with various crude oil marketparticipants for their term storage requirements. Contract fees include fixedmonthly capacity fees as well as utilization fees, which we charge forinjecting crude 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 2006, approximately 30 shipperstendered crude oil for service by the Mid-Continent system. We considermultiple companies that are controlled by a common entity to be a singleshipper for purposes of determining the number of shippers delivering crude oiland liquid petroleum on our Mid-Continent system. These customers includeintegrated oil companies, independent oil producers, refiners and marketers. Averagedaily deliveries on the system were 236,000 Bpd for 2005 and 244,000 Bpd for2006.

*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 2006, PADD II imported 3.3 million barrels per day fromoutside of the PADD II region. The Lakehead system supplied roughly 1.1 millionbarrels per day of crude from Canada leaving 2.2 million barrels per dayimported from PADDs III and IV as well as offshore sources. We expect the gapbetween local supply and demand for crude oil in PADD II to continue to widen,encouraging imports 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, western Canadian crudeoil moving on Spearhead is increasing the importance of Cushing as a terminaland pipeline origination area.

The storage terminals relyon demand for storage service from numerous oil market participants. Producers,refiners, marketers and traders rely on storage capacity for a number ofdifferent reasons: batch scheduling, stream quality control, inventorymanagement, and speculative trading opportunities. Competitors to our storagefacilities at Cushing include large integrated oil companies and othermidstream 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 90,000 to 95,000 Bpd. This is a 10,000 to 15,000 Bpdincrease due to a recent successful hydrotest program and the addition of dragreducing agents at pumping stations along the pipeline. The North Dakota systemalso has 16 pump stations and 11 terminaling facilities with an aggregateworking storage capacity of approximately 685,000 barrels. We are in the middleof a $70 million expansion of this system that we began in 2006 and expect tocomplete in phases throughout 2007, with the majority of the project beginningservice in the second half of 2007. This expansion is necessary to meetincreased crude oil production from the Montana and 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.

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***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.

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, 2006, we haveapproximately 8,500 miles of gathering pipelines, nine treating plants and 17processing plants, excluding plants that are inactive. Our treating facilitieshave a combined capacity exceeding 850 MMcf/d while the combined capacity ofour processing facilities is over 950 MMcf/d.

Our natural gassegment consists of the following major systems:

·       EastTexas system: Includes approximately 2,900 miles of natural gas gathering andtransportation pipelines, seven natural gas treating plants and four naturalgas processing plants.

·       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 eight natural gas processing plants.

·       Ourtransportation operations include four FERC-regulated natural gas interstatepipeline systems. Our four major FERC regulated systems are the KPC pipeline,Midla pipeline, AlaTenn pipeline and UTOS pipeline. Each of these natural gaspipeline systems typically consists of a natural gas pipeline, compression, andvarious interconnects to other pipelines that serve wholesale customers.

·       Ourtransportation operations also include a number of smaller non-FERC regulatednatural gas pipelines as well as trucking operations which are discussed below.

*Customers.**  *Customers of our natural gaspipeline systems include both purchasers and producers of natural gas.Purchasers include marketers and large users of natural gas, such as powerplants, industrial facilities and local distribution companies. Producersserved by our systems consist of small, medium and large independent operatorsand large integrated energy companies. We sell NGLs resulting from ourprocessing activities to a variety of customers ranging from largepetrochemical and refining companies to small regional retail propanedistributors.

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.

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*Supplyand Demand.**  *Demandfor our gathering, treating and processing services primarily depends upon thesupply of natural gas reserves and the drilling rate of new wells. The level ofimpurities in the natural gas gathered also affects treating services. Demandfor these services also depends upon overall economic conditions and the pricesof natural gas and NGLs. Three of our larger systems are located in basins thatcontinue to experience growth in natural gas drilling 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 1,300 MMcf/d during the first half of2006. In the third quarter of 2006, we completed construction of our 120 MMcf/dHenderson natural gas processing facility on our East Texas system and acquiredan 80-mile pipeline in April 2006, that is complimentary to ourexisting East Texas system and provided approximately 75,500 MMBtu/d ofincremental volume. In addition the link between our North Texas and East Texassystems became fully operational during the third quarter of 2006. As expected,the completion of this connection has increased the utilization of our 500MMcf/d intrastate pipeline that we placed in service in June 2005 on ourEast Texas system by providing additional market access to customers of ourNorth Texas system. We also commenced a significant expansion of treating andprocessing capacity in the region, a significant portion of which is alreadyoperational with the remaining facilities expected to be complete in stagesthroughout 2007.

In an effort to address the strong growth in naturalgas production occurring in East Texas, we initiated a $610 million expansionand extension of our East Texas system in early 2006, which we refer to as theClarity project. The Clarity project is necessary to develop and enhance accessfor growing East Texas natural gas production to major markets in SoutheastTexas and to avoid shut in of natural gas production that could result frominsufficient natural gas pipeline transportation capacity. The extension andexpansion of our East Texas System is expected to be completed in stagesthrough 2007 and will provide increasing market options for customers. Inaddition, the Clarity project is designed to be expandable both upstream anddownstream to meet growing demand for natural gas transportation capacity. Wehave firm volume commitments and acreage dedications which we believe willapproximate 550 MMcf/day, of the 700 MMcf/d of capacity, by the end of 2007.The project is designed to be expandable and is positioned for potentialupstream and downstream extension.

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 developments in fracturing the shaleformation allows commercial production of these natural gas reserves. Since1999 Barnett Shale production has risen from approximately 110 MMcf/d to over1,800 MMcf/d in 2006, with the drilling of over 5,200 wells. We anticipate thatthroughput on the North Texas system will increase modestly in each of the nextseveral years as a result of Barnett Shale development. To accommodateanticipated growth in the region we have commenced construction of two new gasprocessing plants totaling approximately 75 MMcf/d of capacity and relatedupstream facilities. These facilities are expected to become operational in thesecond and fourth quarters of 2007.

Our Anadarko system is located within the Anadarkobasin and continues to experience considerable growth as a result of the rapiddevelopment of the Granite Wash play in Hemphill and Wheeler counties in Texas.We are continuing to make progress in increasing processing capacity in theregion from 230 MMcf/d at December 31, 2005 to approximately 440MMcf/d to accommodate the volume growth. In 2006 we expanded our existingZybach processing facility to a capacity of 150 MMcf/d of natural gas from theinitial capacity of approximately 105 MMcf/d when we placed the plant inservice in April 2005. During 

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2007, to meet thecontinuing demands resulting from rapid development in the Anadarko basin, weexpect to increase the processing capacity of our Anadarko system byapproximately 155 MMcf/d. We will also continue to add significant fieldcompression to accommodate the volume growth on this system.

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 insituations where we have natural advantages to create additional value for ourexisting assets.

Our natural gas pipelines generally serve different geographicalareas, with differing supply and demand characteristics in each market. Webelieve that demand and competition for natural gas in the areas served by ournatural gas assets will generally remain strong as a result of being located inareas where industrial, commercial or residential growth is occurring. Thegreatest demand for services in the markets served by our natural gas assetsoccurs in the winter months.

Thetable below indicates the capacity in MMcf/d of the transportation andwholesale customer pipelines with firm transportation contracts as of December 31,2006 and the amount of capacity that is reserved under those contracts as ofthat date.

| **Major System** | ** ** | ** ** | ** ** | **Capacity  MMcf/d** | ** ** | **Percentage   Reserved Under  Contract as of  December 31, 2006** | ** ** |
|-----------------------|------------|------------|------------|----------------------|------------|--------------------------------------------------------------------------------------------------|------------|
| UTOS system      |       |       | 1,200      |                 |       |                                                                                             | 0          | % |   |
| Midla system          |       |       | 200        |                 |       |                                                                                             | 74         | % |   |
| AlaTenn system        |       |       | 200        |                 |       |                                                                                             | 27         | % |   |
| 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 2006 was 181,000 MMBtu/d. The FERC approved ournegotiated settlement with UTOS shippers, keeping our current rates in effect underour 2003 FERC Order, through 2006. On December 7, 2006, we filed anapplication for an extension of that Order to keep the settlement rates ineffect for an additional 3-year term that was subsequently approved onFebruary 21, 2007.

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. We market the unused capacity on these systemsunder both short-term firm and interruptible transportation contracts andlong-term firm transportation contracts. These systems are located in areaswhere opportunities exist to serve new industrial facilities and to makedelivery interconnects to alleviate capacity constraints on other third-partypipeline systems. As of December 31, 2006, approximately 74% of contractedcapacity of the Midla system and approximately 16% of the AlaTenn system isunder contract to our marketing business.

The Bamagas system in northern Alabama is contiguouswith our AlaTenn system and serves two power plants that are indirectly ownedby Calpine Corporation (“Calpine”). In December 2005, Calpine declaredbankruptcy and is in reorganization however, Calpine has continued to performunder the terms of its agreement with Bamagas and we continue to monitor theproceedings. Refer to the discussion included in Item 7. Management’sDiscussion and Analysis of Financial Condition in our Natural Gas 

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segment included in theFuture Prospects section entitled Other Matters of this report for more informationabout Calpine’s bankruptcy filling.

Our KPC system has 84% 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 the availabilityof natural gas from the Mid-continent and Gulf Coast producing regions was todecline and if the cost of transporting natural gas from other producingregions through other pipelines into the areas we serve were to render thedelivered cost of natural gas uneconomical. We may be unable to find additionalcustomers to replace the lost demand or transportation fees.

*Competition.**  *Competition from other pipeline companies is significant in all themarkets we serve. Competitors of our gathering, treating and processingsystems include interstate and intrastate pipelines or their affiliates andother midstream businesses that gather, treat, process and market natural gasor NGLs. Some of these competitors are substantially larger than we are.Competition for the services we provide varies based upon the location ofgathering, treating and processing facilities. Most natural gas producers andowners have alternate gathering, treating and processing facilities availableto them. In addition, they have alternatives such as building their owngathering facilities or in some cases, selling their natural gas supplieswithout treating and processing. In addition to location, competition alsovaries based upon pricing arrangements and reputation. On the sour gas systems,such as our East Texas system, competition is more limited due to theinfrastructure 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 gas also competes on a price basis with alternative fuels such as crudeoil and coal, especially for customers that have the capability of using thesealternative fuels, and on the basis of local environmental considerations.Competition in the marketing of NGLs comes from other NGL marketing companies,producers, traders, chemical companies and other asset owners.

Because pipelines aregenerally the only practical mode of transportation for natural gas over land,the most significant competitors of our natural gas pipelines are otherpipelines. Pipelines typically compete with each other based on location,capacity, price and reliability. Many of the large wholesale customers we servehave multiple pipelines connected or adjacent to their facilities. Accordingly,many of these customers have the ability to purchase natural gas directly froma number of pipelines or third parties that may hold capacity on the variouspipelines. In addition, a number of new interstate natural gas pipelines arebeing constructed in areas currently served by some of our intrastate andinterstate pipelines. When completed, these new pipelines may compete forcustomers with our existing pipelines.

***Trucking and Liquids MarketingOperations***

We also include our trucking and liquids marketingoperations in our Natural Gas segment. Trucking and liquids marketingoperations include the transportation of NGLs, crude oil and carbon dioxide bytruck and railcar from wellheads and treating, processing and fractionationfacilities and to wholesale customers, such as distributors, refiners and chemicalfacilities. In addition, our trucking and liquids marketing operations resellthese products. A key component of our business is ensuring market access forthe liquids extracted at our processing facilities. On average this accountsfor approximately 35% of the volume transported by our trucking and liquidsmarketing business and is a major source of its growth in this area.

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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 and liquids marketing operations are wholesale customers, such asrefineries and propane distributors. Our trucking and liquids marketingoperations also market products to wholesale customers such as petrochemicalplants.

*Supplyand Demand.**  *Theareas served by our trucking and liquids marketing operations aregeographically diverse, and the forces that affect the supply of the productstransported vary by region. Crude oil and natural gas prices and productionlevels affect the supply of these products. The demand for services is affectedby the demand for NGLs and crude oil by large industrial refineries, andsimilar customers in the regions served by this business.

*Competition.**  *Our trucking and liquids marketingoperations have a number of competitors, including other trucking and railcaroperations, pipelines, and, to a lesser extent, marine transportation andalternative fuels. In addition, the marketing activities of our trucking andliquids marketing operations have numerous competitors, including marketers ofall types and sizes, affiliates of pipelines 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.

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 byour Marketing 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 monthlyprice index. Sales to end-use customers incorporate a pass-through charge forcosts of transportation and additional margin to compensate us for associatedservices.

*Supplyand 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 usesthird-party storage capacity to balance supply and demand factors within itsportfolio. Marketing pays third-party storage facilities andpipelines for the right to store gas for various periods of time. Thesecontracts may be denoted as firm storage, interruptible storage, or parking andlending services. These various contract structures are used to mitigate riskassociated with sales and purchase contracts, and to take advantage of pricedifferential opportunities. Due to the increased volumes from our gatheringassets, our Marketing business leases third-party pipeline capacity downstreamfrom 

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our Natural Gas assetsunder firm transportation contracts following specific, controlled guidelines.This capacity is leased for various lengths of time and rates that allows ourMarketing business to diversify its customer base by expanding its serviceterritory. Additionally, this transportation capacity provides assurance thatour gas will not be 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. Uponan appropriate showing, a shipper may obtain reparations for damages sustainedfor a period of up to two years prior to the filing of a complaint.

On October 24, 1992, Congress passed the EnergyPolicy Act of 1992, or EP Act, which deemed petroleum pipeline rates that werein effect for the 365-day period ending on the date of enactment, or thatwere in effect on the 365th day precedingenactment and had not been subject to complaint, protest or investigationduring the 365 day period, to be just and reasonable under the ICA (i.e., “grandfathered”).The EP Act also limited the circumstances under which a complaint can be madeagainst such grandfathered rates. In order to challenge grandfathered rates, aparty must show, 1) that it was contractually barred from challenging therates during the relevant 365 day period; 2) that there has been asubstantial change after the date of enactment of the EP Act in the economiccircumstances of the pipeline or in the nature of the services that were thebasis for the rate; or 3) that the rate is unduly discriminatory or undulypreferential.

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. Underthe regulations, which became 

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effective January 1,1995, petroleum pipelines are able to change their rates within prescribedceiling levels that are tied to an inflation index. Rate increases made withinthe ceiling levels may be protested, but such protests must show that the rateincrease resulting from application of the index is substantially in excess ofthe pipeline’s increase in costs. If the indexing methodology results in areduced ceiling level that is lower than a pipeline’s filed rate, Order No. 561requires the pipeline to reduce its rate to comply with the lower ceiling,although a pipeline is not required to reduce its rate below the levelgrandfathered under the EP Act. Under Order No. 561, a pipeline must, as ageneral rule, utilize the indexing methodology to change its rates. The FERC,however, uses cost-of-service ratemaking, market-based rates andsettlement rates as alternatives to the indexing approach in certain specifiedcircumstances.

Under Order No. 561,the original inflation index adopted by the FERC was equal to the annual changein the PPI-FG minus one percentage point. The index was subject to review everyfive years. Rates were then subject to an annual adjustment, based upon changesin the PPI-FG minus 1%, in order to accurately reflect the actual cost changesexperienced by the oil pipeline industry. In December 2000, as part of theFERC’s five-year review of the oil-pricing index (July 2001 through June 2006),the FERC concluded that the PPI-FG accurately reflected the actual cost changesexperienced by the industry. In February 2003 the FERC issued an Order onRemand concluding that for the current five-year period, the oil-pricing indexshould be the PPI-FG. In order to calculate the 2003 ceiling rate levels, oilpipelines were permitted to use the PPI-FG adjustment as though it had been ineffect since 2001. As of July 2006, the index increased to equal PPI-FGplus 1.3 percentage points, resulting in an index of 6.1485%. The FERCattributed the higher index formula to increases in industry costs from theimposition of new safety and environmental regulatory obligations, voluntarysecurity measures, and higher energy costs. The FERC will continue, over thenext five years, to review the oil pipeline index and monitor whether thecurrent rate in place still reflects the actual cost changes experienced by theoil pipeline industry.

**Allowance forIncome 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, or the D.C. CircuitCourt. On July 20, 2004, in *BP West Coast Products LLCv. FERC*(No. 99-1020), which we refer to as the *BP West Coast decision*, the D.C. Circuit Court issued adecision upholding certain aspects of the FERC’s orders regarding the SFPPcase, but vacating the FERC’s ruling regarding the proper tax allowance forSFPP. The D.C. Circuit Court 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 companies commentedon the proceeding. On May 4, 2005, the FERC issued a policy statement onincome tax allowances, in which it reinstated its earlier policy of providing afull tax allowance on all partnership and similar legal interests in regulatedcompanies if the owner of that interest has an actual or potential taxliability on the income earned through that interest. Whether a pipeline’sowners have such actual or potential income tax liability will be reviewed bythe FERC on a case-by-case basis. On December 16, 2005, FERC issued itsfirst case-specific oil pipeline review of the income tax allowance issuein the SFPP proceeding, reaffirming its new income tax allowance policy anddirecting SFPP to provide certain evidence necessary for the pipeline todetermine its income tax allowance. The new tax allowance policy and the December 16order have been appealed to the D.C. Circuit Court, and rehearing requests havebeen filed with respect to the 

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December 16 order. Aswell as the SFPP decision, which is currently on appeal, there are two othercases with regards to tax allowance pending in the D.C. Circuit Court includingExxon Mobil Oil Corporation v. FERC and CAPP v. FERC.

The D.C. Circuit Court heard oral arguments on thesecases on December 12, 2006. A decision is expected by April 2007. Atthis time, the ultimate outcome of these proceedings is not certain and couldresult in changes to the FERC’s treatment of income tax allowances in cost ofservice arrangements. Whether the income tax allowance policy is ultimatelyupheld or modified on judicial review, could affect the tariffs ofFERC-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.

At this time, the effect of the FERC’s policystatement on income tax allowances on us is uncertain. The tariff rates on ourcommon carrier interstate liquids pipelines have been established under avariety of different circumstances including settlements and tariff indexing. Itis anticipated that a change in the income tax allowance policy would onlyimpact those rates that were established after indexing. Even with the indexedrates, the income tax allowance is only one of many elements supporting ourpipeline rates for service. Accordingly, we cannot predict with certainty whatrates we will be allowed to charge in the future, or the potential impact on usof a change in FERC’s policy statement on income tax allowances.

We believe that the rateswe charge for transportation services on our interstate common carrier liquidspipelines are just and reasonable under the ICA. However, because the ratesthat we charge are subject to review upon an appropriately supported protest orcomplaint, we cannot predict what rates we will be allowed to charge in thefuture for service on our interstate common carrier liquids pipelines. Furthermore,because rates charged for transportation services must be competitive withthose charged by other transporters, the rates set forth in our tariffs will bedetermined based on competitive factors in addition to regulatoryconsiderations.

**Accounting forPipeline 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 took effect on January 1, 2006. Under the order, FERC-regulatedcompanies are generally required to recognize costs incurred in performingpipeline assessments that are part of a pipeline integrity management programas maintenance expense in the period in which the costs are incurred. Costs foritems such as rehabilitation projects designed to extend the useful life of thesystem can continue to be capitalized to the extent permitted under theexisting rules. The FERC denied rehearing of its accounting guidance order on September 19,2005.

We have historicallycapitalized first time in-line inspection programs, based on previous rulingsby the FERC. In January 2006, we began expensing all first-time internalinspection costs for all our pipeline systems, whether or not they are subjectto FERC regulation on a prospective basis. We will continue to expensesecondary internal inspection tests consistent with our previous practice. Referto Note 2: Summary of Significant Accounting Policies included in ourconsolidated financial statements beginning at page F-1 of thisannual report on Form 10-K. 

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***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 pipeline 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 is just and reasonable as required by theNGA, the FERC will accept the proposed change and the pipeline will implementsuch change in its tariff. However, if the FERC determines that a proposedchange may not be just and reasonable as required by the NGA, then the FERC maysuspend such change for up to five months and set the matter for anadministrative hearing. Subsequent to any suspension period ordered by theFERC, the proposed change may be placed into effect by the company, pendingfinal FERC approval. In most cases, a proposed rate increase is placed intoeffect before a final FERC determination on such rate increase, and theproposed increase is collected subject to refund (plus interest). Under thesecond 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 itorders generally will be effective prospectively from the date of the FERC orderrequiring this change.

In November 2003, the FERC issued Order 2004governing the Standards of Conduct for Transmission Providers (includingnatural gas interstate pipelines). These standards provide that interstatepipeline employees engaged in natural gas transmission system operations mustfunction independently from any employees of their energy affiliates andmarketing affiliates and that an interstate pipeline must treat alltransmission customers, affiliated and non-affiliated, on a non-discriminatorybasis, and cannot operate its transmission system to benefit preferentially, anenergy or marketing affiliate. In addition, Order 2004 restricts access tonatural gas transmission customer data by marketing and other energy affiliatesand provides 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. In November 2006, the D.C.Circuit Court vacated Order 2004 as that order applies to interstate naturalgas pipelines and remanded that proceeding to the FERC for further action.

On January 9, 2007, the FERC issued Order 690 inresponse to the D. C. Circuit Court’s decision. In its Order, the Commissionissued new interim standards of conduct pending the outcome of a new rulemakingproceeding. The interim standards will only govern the relationship between aninterstate 

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pipeline and its marketingaffiliates as opposed to its energy affiliates, the latter being a much broadercategory as originally set forth in Order 2004. As a result, the Commissioneffectively “repromulgated” on a temporary basis the Standards of Conduct firstissued in Order 497 in 1992, while it considers its course of action to addressthe court’s decision on a more permanent basis.

On January 18, 2007, the FERC issued a Notice ofProposed Rulemaking (“NOPR”) in Docket No. RM07-1 wherein itproposes to make permanent its interim standards of conduct issued in Order 690.The Commission is also seeking comment as to whether it should make comparablechanges to the electric industry standards of conduct that were not affected byeither the November 2006 decision by the D.C. Circuit Court, or by Order690, as well as comments regarding certain other electric-related exceptions toOrder 2004. We continue to closely monitor these proceedings and administer ourcompliance programs accordingly.

Additional proposals andproceedings that might affect the natural gas industry are pending beforeCongress, the FERC and the courts. The natural gas industry historically hasbeen heavily regulated; therefore, there is no assurance that a more stringentregulatory approach will not be pursued by the FERC and Congress, especially inlight of market power abuse by marketing affiliates of certain pipelinecompanies engaged in interstate commerce. In response to this issue, Congress,in the Energy Policy Act of 2005 (“EPACT”), and the FERC have implementedrequirements to ensure that energy prices are not impacted by the exercise ofmarket power or manipulative conduct. EPACT prohibits the use of any“manipulative or deceptive device or contrivance” in connection with thepurchase or sale of natural gas, electric energy or transportation subject tothe FERC’s jurisdiction. The FERC then adopted the Market ManipulationRules and the Market Behavior Rules to implement the authority grantedunder EPACT. These rules, which prohibit fraud and manipulation in wholesaleenergy markets, are very vague and are subject to broad interpretation.Although the FERC has not issued any order interpreting these rules, it islikely that the FERC will give itself broad latitude in determining whetherspecific behavior violates the rules. In addition, EPACT gave the FERCincreased penalty authority for these violations. The FERC may now issue civilpenalties of up to $1 million per day for each violation of FERC rules, andthere are possible criminal penalties of up to $1 million and 5 years inprison. Given the FERC’s broad mandate granted in EPACT, it is assumed that ifenergy prices are high, the FERC will investigate energy markets to determineif behavior unduly impacted or “manipulated” energy prices.

***Intrastate Pipeline Regulation***

Our intrastate liquids andnatural gas pipeline operations generally are not subject to rate regulation bythe FERC, but they are subject to regulation by various agencies of the states inwhich they are located. However, to the extent that our intrastate pipelinesystems deliver natural gas into interstate commerce, the rates, terms andconditions of such transportation service are subject to FERC jurisdictionunder Section 311 of the NGPA, which regulates, among other things, theprovision of transportation services by an intrastate natural gas pipelinemaking deliveries on behalf of a local distribution company or an interstatenatural gas pipeline. Most states have agencies that possess the authority toreview and authorize natural gas transportation transactions and theconstruction, acquisition, abandonment and interconnection of physicalfacilities. Some states also have state agencies that regulate transportationrates, service terms and conditions and contract pricing to ensure theirreasonableness and to ensure that the intrastate pipeline companies that theyregulate do not discriminate among similarly situated customers.

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***Natural Gas Gathering Pipeline Regulation***

Section 1(b) ofthe NGA exempts natural gas gathering facilities from the jurisdiction of theFERC under the NGA. We own certain natural gas pipelines that we believe meetthe traditional tests the FERC has used to establish a pipeline’s status as agatherer not subject to the FERC jurisdiction. State regulation of gatheringfacilities generally includes various safety, environmental and, in somecircumstances, nondiscriminatory take requirements, but historically has notentailed rate regulation. In 2005, the FERC initiated an inquiry regarding theextent to which gathering (both offshore and onshore) systems, particularlythose that have been previously transferred from a regulated entity should beregulated by the FERC. The inquiry is still open at this time. Further, somestates have, 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.

***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. TheFERC is continually proposing and implementing new 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. We cannot predict the ultimate impact of these regulatorychanges to 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 gas liquids currently are not regulated and are made atmarket prices. In a number of instances, however, the ability to transport andsell such products is dependent on pipelines whose rates, terms and conditionsof service are subject to the FERC’s jurisdiction under the ICA. Certainregulations implemented by the FERC in recent years could increase the cost oftransportation service on certain petroleum products pipelines. However, we donot believe that these regulations affect us any differently than othermarketers of these products.

***Other Regulation***

The governments of theUnited States and Canada have, by treaty, agreed to ensure nondiscriminatorytreatment for the passage of oil and natural gas through the pipelines of onecountry across the territory of the other. Individual border crossing pointsrequire U.S. government permits that may be terminated or amended at the willof the U.S. government. These permits provide that pipelines may be inspectedby or subject to orders issued by federal or state government agencies.

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***Tariffs and Rate Cases***

**Lakehead system**

Underpublished tariffs at December 31, 2006 (including the tariff surchargesrelated to Lakehead system expansions) for transportation on the Lakeheadsystem, the rates for transportation of heavy crude oil from Neche, NorthDakota, where the System enters the United States (unless otherwise stated), toprincipal delivery points are set forth below.

|                                                      | ** ** | **Published**                   | ** ** |
|------------------------------------------------------|------------|---------------------------------|------------|
| ** **                                           | ** ** | **Tariff Per Barrel** | ** ** |
| To Clearbrook, Minnesota                   |       |                            | $          | 0.218 |   |   |
| To Superior,  Wisconsin                              |       |                            | 0.437      |   |   |
| To Chicago,  Illinois area                           |       |                            | 0.919      |   |   |
| To Marysville,  Michigan area                        |       |                            | 1.102      |   |   |
| To Buffalo, New  York area                           |       |                            | 1.129      |   |   |
| Chicago to the  international border near Marysville |       |                            | 0.395      |   |   |

 

The rates at December 31,2006 for light and medium crude oils and NGL’s are lower than the rates setforth in the table to compensate 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.

*Base Rates**:***

The base portion of therates for the Lakehead system are subject to an annual escalation, which cannotexceed established ceiling rates as approved by the FERC, and determined incompliance with the FERC-approved indexing methodology.

*SEP II Surcharge**:***

Under the SettlementAgreement with CAPP that the FERC approved in 1996 and reconfirmed in 1998, weimplemented a tariff surcharge related to our SEP II project. This tariffsurcharge, which is added to the base rates, is a cost-of-service basedcalculation that is trued-up annually (usually in April) for actual costs andthroughputs from the previous calendar year, and is not subject to indexing. Theinitial term of the SEP II portion of the settlement agreement was for 15 yearsbeginning in 1999.

*Terrace Surcharge**:***

Under the Tariff Agreementapproved by the FERC in 1998, we also implemented a tariff surcharge for theTerrace expansion program of approximately $0.013 per barrel for light crudeoil from the Canadian border to Chicago. On April 1, 2001, pursuant to anagreement between us and Enbridge Pipelines, our share of the surcharge wasincreased to $0.026 per barrel. This surcharge was in effect until April 1,2004, when our share of the surcharge changed to $0.007 per barrel. Our sharewill remain at this level until 2010, after which time the surcharge willreturn to $0.013 per barrel through 2013, the term of the agreement. Inaddition to the Terrace surcharge, included in the 2005 tariff is the TerraceSchedule C adjustment. Under the tariff agreement, when Terrace Phase IIIfacilities are in service, and annual actual average pumping exiting Clearbrookare less than 225,000 M3 per day, an adjustment is made to the Terracesurcharge. In 2006, this adjustment is $0.041 per barrel, based on annualactual average pumpings exiting Clearbrook of 165,300 M3 perday in 2005.

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*FacilitiesSurcharge**:***

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 Lakeheadsystem to 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 tariff mechanismthat is trued-up each year for actual costs and throughput and, therefore, isnot subject to adjustment either upwards or downwards under indexing. In 2006,the Facilities Surcharge was $0.016 per barrel for light movements from theU.S./Canada border near Neche, North Dakota to Chicago. The FacilitiesSurcharge currently includes four projects that were agreed to with CAPP in2004. Additional projects to be included in the Facilities Surcharge will bedetermined as the result of a negotiating process between management of theLakehead system and CAPP.

On March 16, 2006, the FERC approved the Offer ofSettlement filed by Enbridge on December 21, 2005, seeking approval forthe Southern Access mainline expansion surcharge under the provisions of thepreviously approved Facilities Surcharge mechanism. The Southern Accessmainline expansion centers on the construction of a new 42-inch diameterpipeline between Superior, Wisconsin and Flanagan, Illinois, along withassociated upstream modifications to balance the expanded capacity created bythe new Superior-to-Flanagan line.

On September 1, 2006,Enbridge filed an Offer of Settlement with the FERC seeking prompt approval forthe Southern Access Extension surcharge. The proposed Extension is a new 36-inchpipeline which connects with the Southern Access Mainline Expansion pipeline atFlanagan to Patoka, Illinois, which allows Canadian producers and shippers toaccess the Patoka hub, where they can then access other refining centers. Underthe framework that established the Facilities Surcharge already approved by theCommission, the proposed tolling methodology in the Offer of Settlement askedthat the costs for the Extension be added to the existing base rates as asurcharge. A variety of benefits would accrue to shippers through theExtension, including a reduction in total tariff rates due to the higherutilization of upstream facilities and therefore reducing the net cost toshippers even if they do not ship on the Extension itself. The Offer ofSettlement was opposed by three shippers and was rejected by the Commission on December 8,2006, which stated that Enbridge did not submit adequate proof that theproposed pipeline would benefit all shippers. Enbridge still intends tocontinue with the development of the Extension and is exploring alternativetolling methodologies that would be supported by all shippers.

**Mid-Continent system**

The Mid-Continentsystem is comprised of pipeline, terminaling, and storage infrastructurelocated in the U.S. Mid-continent region. Specifically the system originates inCushing, Payne County, Oklahoma and offers transportation service to WoodRiver, Madison County, Illinois; West Tulsa, Oklahoma, other Mid-Continent systemfacilities, local area refineries, and other interconnected pipe non-affiliatedinfrastructure. The rates for the transportation of light crude oil fromCushing, Payne County, Oklahoma to principle delivery points are set forthbelow:

| ** **                    | ** ** | **Published**                   | ** ** |
|-------------------------------|------------|---------------------------------|------------|
| ** **                    | ** ** | **Tariff Per Barrel** | ** ** |
| To Wood  River, Illinois |       |                            | $          | 0.440 |   |   |
| To West Tulsa, Oklahoma       |       |                            | $          | 0.185 |   |   |

 

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The rates, at December 31, 2006 outlined above,apply to light crude only. Medium and heavy crude oil transportation rates onthese systems are higher to compensate us for differences in the costs ofshipping different types and grades of liquid hydrocarbons.

Where applicable, weperiodically adjust our tariff rates as allowed under the FERC’s indexingmethodology. Currently, this methodology allows for an adjustment of ratesequal to the PPI-FG +1.3%, which adjustment is made effective July 1 ofeach year.

**North Dakota  system**

OurNorth Dakota system consists of both gathering and trunkline assets. Allgathering rates from points in North Dakota, Montana and Wyoming are $0.608 perbarrel, and rates for transportation of light crude oil to principle deliverypoints via trunklines on our North Dakota System are set forth below: 

| ** **                                                                             | ** ** | **Published**                   | ** ** |
|----------------------------------------------------------------------------------------|------------|---------------------------------|------------|
| ** **                                                                             | ** ** | **Tariff Per Barrel** | ** ** |
| From Renville, Bottinaeu, Burke, Ward and Mountrail  Counties to Clearbrook, Minnesota |       |                            | $          | 0.740 |   |   |
| From Sheridan and  Williams County to Clearbrook, Minnesota                            |       |                            | $          | 0.847 |   |   |
| From Sheridan  County to Clearbrook, Minnesota                                         |       |                            | $          | 0.871 |   |   |
| From Sheridan  County to Clearbrook, Minnesota                                         |       |                            | $          | 0.906 |   |   |
| From Ramberg/Beaver Lodge Station, North Dakota to  Clearbrook, Minnesota              |       |                            | $          | 0.763 |   |   |
| From Williams  County to Clearbrook, Minnesota                                         |       |                            | $          | 0.967 |   |   |
| From McKenzie County to  Clearbrook, Minnesota                                         |       |                            | $          | 1.002 |   |   |

 

The rates at December 31,2006, outlined above, are subject to adjustment as allowed under the indexingmethodology established by the FERC. Currently this methodology allows for anadjustment of rates equal to the PPI-FG +1.3%, which is made effective July 1of each year.

*North DakotaExpansion*

Due to significant increases in crude oil productionin the Williston Basin area of North Dakota and Montana, our North Dakotasystem has been under significant capacity apportionment during the past year. Asa result, we submitted an Offer of Settlement to the FERC on August 14,2006 to facilitate a two-stage expansion of our North Dakota system. Our Offerof Settlement has received wide support from current shippers on our NorthDakota system. The settlement encompasses the expansion of our North Dakotasystem mainline between Minot, North Dakota and Clearbrook, Minnesota and thefeeder line between Alexander and Beaver Lodge, North Dakota. The recoverymechanism is the implementation of two agreed-upon surcharges to be added tothe existing base rates of our North Dakota system for a period of five years. Theproposed surcharges are transparent, cost of service based tariff mechanismsthat will be trued-up annually to reflect actual costs and throughput and willnot be subject to index adjustments.

The expansion of our North Dakota system is expectedto add approximately 30,000 Bpd of incremental capacity to the mainline,increasing the existing capacity to approximately 110,000 Bpd between Minot,North Dakota and Clearbrook, Minnesota. The expansion is also expected to addapproximately 30,000 Bpd of incremental capacity to the feeder segment of thesystem, increasing the existing capacity to approximately 90,000 barrels perday, between Alexander and Beaver Lodge. We expect the total cost of completingthe mainline and feeder expansions of the North Dakota systems to approximate$70 million.

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On October 31, 2006,the FERC approved the methodology of the proposed cost-based recovery mechanismoutlined in the North Dakota Offer of Settlement on the grounds that it appearsfair, reasonable and in the public interest.

**Natural Gas Systems**

Tariff rates on theFERC-regulated natural gas pipelines are approved by the FERC and vary bypipeline depending on a number of factors, including cost of providing service,throughput levels on the pipeline, and other factors. Competitive forces mayprompt us to charge tariff rates below the FERC-approved maximum rate onour interstate systems. The rates charged for transmission of natural gas onpipelines not regulated by the FERC, or a state agency, are established bycompetitive forces.

***Safety Regulation and Environmental***

**General**

Our transmission andgathering pipelines and storage and processing facilities are subject toextensive federal and state environmental, operational and safety regulation.The added costs imposed by regulations are generally no different than thoseimposed on our competitors. The failure to comply with such rules andregulations can result in substantial penalties and/or enforcement actions andadded operational costs.

**Pipeline Safety andTransportation Regulation**

Our transmission and non-rural gathering pipelines aresubject to regulation by the United States Department of Transportation, orDOT, Pipeline and Hazardous Materials Safety Administration (“PHMSA”) underTitle 49 United States Code (Pipeline Safety Act, or PSA) relating to thedesign, installation, testing, construction, operation, replacement andmanagement of transmission and non-rural gathering pipeline facilities. ThePHMSA is the agency charged with regulating the safe transportation ofhazardous materials under all modes of transportation, including intrastatepipelines. Periodically the PSA has been reauthorized and amended, imposing newmandates on the regulator to promulgate new regulations, imposing direct mandateson operators of pipelines.

On December 17, 2002 the PSI Act of 2002 wasenacted reauthorizing and amending the PSA. The most significant amendmentrequired natural gas pipelines to develop integrity management programs andconduct integrity assessment tests at a minimum of seven year intervals. Suchtests can include internal inspection, hydrostatic pressure tests or directassessments on pipelines in certain high consequence areas. The PHMSA has sincepromulgated rules for this and other mandates included in the PSI of 2002.

On December 29, 2006 the “Pipeline Inspection,Protection, Enforcement, and Safety Act of 2006” (PIPES of 2006) was signedinto legislation that further amended the Pipeline Safety Act. Many of theprovisions were welcome, including strengthening excavation damage preventionand enforcement. The most significant provisions of PIPES of 2006 that willaffect the Partnership, but not materially, include a mandate to PHMSA toremove most exemptions from federal regulations for liquid pipelines operatingat low stress and mandates PHMSA to undertake rulemaking requiring pipelineoperators to have a human factors management plan for pipeline control roompersonnel, including consideration for controlling hours of service.

We have incorporated the new requirements of the 2002and 2006 PSA amendments into procedures and budgets and, while we expect toincur higher regulatory compliance costs, the increase is not expected to bematerial.

In September 2006, PHMSA proposed extending itsregulatory oversight to include environmentally sensitive areas that are beyondthe scope of its current jurisdiction. PHMSA currently has jurisdiction over 

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rural gathering pipelines,low operating stress transmission pipelines that are located in highconsequence areas and pipelines in urban areas or across navigable waters. Weexpect this proposed rule to become final by mid-2007 and do notexpect the new mandates to have a material impact on our current systems. However,the PIPES of 2006 mandated that PHMSA go further and expand jurisdiction overall low stress pipelines, not just those in high consequence areas. We expectthe PHMSA, therefore, to immediately issue another proposed rule for lowstress pipelines, but until such rules are proposed, we are not certain ofthe effect or costs that the new requirements may have on our operations.

When hydrocarbons are released into the environment,the PHMSA can impose a return-to-service plan, which can include implementingcertain internal inspections, pipeline pressure reductions, and otherstrategies to verify the integrity of the pipeline in the affected area. We donot anticipate any return-to-service plans that will have a material impact onsystem throughput or compliance costs; however we have the potential of incurringadditional expenditures to remediate any condition in the event of a dischargeor failure on the system.

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 ourpipeline, trucking and railcar operations are in substantial compliance withapplicable operational and safety requirements. In instances of non-compliance,we have taken actions to remediate the situations. Nevertheless, significantexpenses could be incurred in the future if additional safety measures arerequired or if safety standards are raised and exceed the capabilities of ourcurrent pipeline control system or other safety equipment.

**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 substantial environmentalexpenses. However, we believe that through our due diligence process, weidentify and manage substantial issues.

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*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 measures in connection with maintainingexisting facilities and obtaining permits and approvals for any new or acquiredfacilities.

The Oil Pollution Act (OPA) was enacted in 1990 andamends parts of the CWA and other statutes as they pertain to the prevention ofand response to oil spills. Under the OPA, we could be subject to strict, jointand potentially unlimited liability for removal costs and other consequences ofan oil spill from our facilities into navigable waters, along shorelines or inan exclusive economic zone of the United States. The OPA also imposes certainspill prevention, control and countermeasure requirements for many of ournon-pipeline facilities, such as the preparation of detailed oil spillemergency response plans and the construction of dikes or other containmentstructures to prevent contamination of navigable or other waters in the eventof an oil overflow, rupture or leak. For our liquid pipeline facilities, theOPA imposes requirements for emergency plans to be prepared, submitted andapproved by the DOT. For our non-transportation facilities, such as storagetanks that are not integral to pipeline transportation system, the OPAregulations are promulgated by the EPA. We believe we are in material compliancewith these laws and regulations.

*Hazardous Substances and Waste Management.*   The federal CERCLA(also known as the “Superfund” law), and similar state laws, impose liabilitywithout regard to fault or the legality of the original conduct, on certainclasses of persons, including the owners or operators of waste disposal sitesand companies that disposed or arranged for disposal of hazardous substancesfound at such sites. We may generate some wastes that fall within thedefinition of a “hazardous substance.” We may, therefore, be jointly andseverally liable under CERCLA for all or part of any costs required to clean upand restore sites at which such wastes have been disposed. In addition, it isnot uncommon for neighboring landowners and other third parties to file claimsfor personal injury and property damage allegedly caused by hazardoussubstances or other pollutants released into the environment. Analogous statelaws may apply to a broader range of substances than CERCLA and, in someinstances, may offer fewer exemptions from liability. We have not received anynotification that we may be potentially responsible for material cleanup costsunder CERCLA or similar state laws.

*Employee Health and Safety.*   The workplaces associated with our operations are subject to therequirements of the federal OSHA and comparable state statutes that regulateworker health and safety. We have an ongoing safety, procedure and trainingprogram for our employees and believe that our operations are in compliancewith applicable occupational health and safety requirements, including industryconsensus standards, record keeping requirements, monitoring of occupationalexposure to regulated substances, and hazard communication standards.

*Site Remediation.*   We own and operate a number of pipelines, gathering systems, storagefacilities and processing facilities that have been used to transport,distribute, store and process crude oil, natural gas and other petroleumproducts. Many of our facilities were previously owned and operated by thirdparties whose handling, disposal and release of petroleum and waste materialswere not under our control. The age of the facilities, combined with the pastoperating and waste disposal practices, which were standard for the industryand regulatory regime at the time, have resulted in soil and groundwatercontamination at some facilities due to historical spills and releases. Suchcontamination is not unusual within the natural gas and petroleum industry.Historical contamination found on, under or originating from our properties maybe subject to CERCLA, RCRA and analogous state laws as described above.

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Under these laws, we couldincur 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 environmentalliabilities, exceed $20.0 million, and the General Partner’s aggregateliability, including environmental liabilities, may not exceed, with certainexceptions, $150.0 million. We will be liable for any environmentalconditions related to the acquired systems that were not known to the GeneralPartner or were disclosed under the contribution agreement between the GeneralPartner and us. In addition, we will be liable for all removal, remediation anddisposal of all asbestos containing materials and all naturally occurringradioactive materials associated with the Northeast Texas system and for whichthe General Partner is liable 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, have 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 generalpartner, however, retains certain functions and approval rights over ouroperations. To fulfill its management obligations, Enbridge Management hasentered into agreements with Enbridge and several of its affiliates to provideEnbridge Management with the necessary services and support personnel, who acton Enbridge Management’s behalf as its agents. We are ultimately responsiblefor reimbursing these service providers based on the costs that they incur inperforming these services.

**INSURANCE**

Our operations are subjectto many hazards inherent in the liquid petroleum and natural gas gathering,treating, processing and transportation industry. We maintain insurancecoverage for our operations and properties considered to be customary in theindustry. Our coverage limits for property and business interruption, generalliability, and polution liability insurance are expressed in Canadian dollars,or CAD, and vary from CAD $400 million to CAD $650 million, or US $343 to $558million, for property and business interruption, general liability, andpollution liability insurance. The exchange rate of $0.8581 United Statesdollars, or USD, for each CAD represents the effective exchange rate atDecember 31, 2006. Insurance policy deductibles vary with coverage and asexpressed in USD range from  approximately $9 million, $0.1 million, and$2.2 million for property, general liability, and pollution liability,respectively. We can make no assurance, however, that the insurance coverage wemaintain will be available or adequate for any particular risk or loss, or thatwe will be able to maintain adequate insurance in the future at rates weconsider reasonable. Although we believe that our assets are adequately coveredby insurance, a 

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substantialuninsured loss could have a material adverse effect on our financial position,results of operations and cash flows.

**TAXATION**

For U.S. federal incometax purposes, we are not a taxable entity. Generally, 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.

**AVAILABLE INFORMATION**

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 make 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.

**Item1A. Risk Factors**

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

**RISKS RELATED TO OUR BUSINESS**

***Our financialperformance could be adversely affected if our pipeline systems are used less.***

Our financial performancedepends to a large extent on the volumes transported on our pipeline systems.Decreases in the volumes transported by our systems, whether caused by supplyor demand factors in the markets these systems serve, competition or otherwise,can directly 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. Decreases inconventional crude oil exploration and production activities in western Canadaand other factors including supply disruption and competition can reduce theutilization of our Lakehead system. For example, in January 2005, deliverieson our Lakehead system were impacted by a fire at a Suncor facility. The volumeof crude oil that we transport on the Lakehead system also depends on thedemand for crude oil in the Great Lakes and Midwest regions of the UnitedStates and the delivery by others of crude oil and refined products into theseregions and the Province of Ontario. Pipeline capacity for the delivery ofcrude oil to the Great Lakes and Midwest regions of the United States currentlyexceeds refining capacity.

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 

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Terraceexpansion program, will largely depend on these anticipated increases in crudeoil production from oil sands projects.

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 ourtariff rates or challenges to our tariff rates could have a material adverseeffect on our financial condition and results of operations; a*** recent FERCPolicy Statement that limited allowances for income tax in an unrelatedpipeline’s cost of service, if applied to our FERC-regulated systems, couldadversely 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. Some producingstates, including Oklahoma and Texas, are considering legislation that wouldrequire rate and/or service regulation of gathering and intrastate transmissionnatural gas systems. Increased state regulation could adversely impact ournatural gas systems.

The question of whetherand to what extent an income tax allowance should be included in a regulatedutility’s cost of service for rate-making purposes was a matter of uncertaintyfor a number of years. In a 1995 decision involving our Lakehead system, whichwe 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*,which we refer to as the *BP West Coast decision*,the United States Court of Appeals for the District of Columbia Circuit issueda decision upholding certain aspects of the FERC’s orders regarding the SFPPcase, but vacating the FERC’s ruling regarding the proper tax allowance forSFPP. The United States Court of Appeals for the District of Columbia rejectedthe FERC’s rationale for its *Lakehead**ruling* and remanded the case to the FERC for furtherproceedings.

In the wake of the *BP West Coast* decision, the FERC initiated a notice andcomment process to address tax allowance issues across a range of industries. Weand many other companies commented on the proceeding. On May 4, 2005, theFERC issued a policy statement on income tax allowances, in which it reinstatedits earlier policy of providing a full tax allowance on all partnership andsimilar legal interests in regulated companies if the owner of that interesthas an actual or potential tax liability on the income earned through thatinterest. Whether a pipeline’s owners have such actual or potential income taxliability 

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will bereviewed by the FERC on a case-by-case basis. On December 16, 2005, FERCissued 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. The new tax allowancepolicy and the December 16 order have been appealed to the D.C. CircuitCourt, and rehearing requests have been filed with respect to the December 16order. As well as the SFPP decision, which is currently on appeal, there aretwo other cases with respect to tax allowance pending in the D.C. Circuit Courtincluding Exxon Mobil Oil Corporation v. FERC and CAPP v. FERC.

The D.C. Circuit Courtheard oral arguments on these cases on December 12, 2006. A decision isexpected by April 2007. At this time, the ultimate outcome of theseproceedings is not certain and could result in changes to the FERC’s treatmentof income tax allowances in cost of service. Whether the income tax allowancepolicy is ultimately upheld or modified on judicial review, could affect thetariffs of FERC-regulated pipelines.

A related issue is whetherthe FERC’s income tax allowance policy can be relied upon by shippers as asubstantial change in circumstances sufficient to remove the grandfatheringprotection under the EP Act from an oil pipeline’s rates. The FERC determinedin the SFPP case that its policy statement on income tax allowances does notrepresent a change from its pre-EP Act policy and therefore, cannot affectgrandfathering of rates, a position that is still potentially subject to furtherjudicial review.

At this time, the effectof the FERC’s policy statement on income tax allowances on us is uncertain. Thetariff rates on our common carrier interstate liquids pipelines have beenestablished under a variety of different circumstances including settlementsand tariff indexing. It is anticipated that a change in the income taxallowance policy would only impact those rates that were established afterindexing. Even with the indexed rates, the income tax allowance is only one ofmany elements supporting our pipeline rates for service. Accordingly, we cannotpredict with certainty what rates we will be allowed to charge in the future,or the potential impact on us of a change in the FERC’s policy statement onincome tax allowances.

We believe that the rateswe charge for transportation services on our interstate common carrier liquidspipelines are just and reasonable under the ICA. However, because the ratesthat we charge are subject to review upon an appropriately supported protest orcomplaint, we cannot predict what rates we will be allowed to charge in thefuture for service on our interstate common carrier liquids pipelines. Furthermore,because rates charged for transportation services must be competitive withthose charged by other transporters, the rates set forth in our tariffs will bedetermined based on competitive factors in addition to regulatoryconsiderations.

***Competition mayreduce our revenues.***

Our Lakehead system facescurrent, and potentially further competition for transporting western Canadiancrude oil from other pipelines, which may reduce our revenues. Our Lakeheadsystem competes with other crude oil and refined product pipelines and othermethods of delivering crude oil and refined products to the refining centers ofMinneapolis-St. Paul, Minnesota; Chicago, Illinois; Detroit, Michigan; Toledo,Ohio; Buffalo, New York; and Sarnia, Ontario and the refinery market andpipeline hub located in the Patoka/Wood River area of southern Illinois.Refineries in the markets served by our Lakehead system compete with refineriesin western Canada, the Province of Ontario and the Rocky Mountain region of theUnited States for supplies 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. A number of new interstate natural gas transmission pipelines beingconstructed could reduce 

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therevenue we derive from the interstate and intrastate transmission of naturalgas. Many of the large wholesale customers served by our systems’ transmissionand wholesale customer pipelines have multiple pipelines connected or adjacentto their facilities. Thus, many of these wholesale customers have the abilityto purchase natural gas directly from a number of pipelines and/or from thirdparties that may hold capacity on other pipelines. Likewise, most natural gasproducers and owners have alternate gathering and processing facilitiesavailable to them. In addition, they have other alternatives, such as buildingtheir own gathering facilities or, in some cases, selling their natural gassupplies without processing. Some of our natural gas marketing competitors havegreater financial resources and access to larger supplies of natural gas thanthose available to us, which could allow those competitors to price theirservices more aggressively than we do.

***Our gas marketingoperations involve market and certain 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, limitationsupon, or elimination of the regulatory authorization required for our wholesalesales of natural gas in interstate commerce.

***Our results may beadversely affected by commodity price volatility and risks associated with ourhedging 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 earningsvolatility due to turbulent commodity prices.

***Compliance withenvironmental and operational safety regulations, including any remediation ofsoil or water pollution or hydrostatic testing of our pipeline systems, may increaseour costs and/or reduce 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 environmental contamination, accidental releases or upsets,regulatory enforcement, litigation or safety and health incidents. As a result,we may incur costs or liabilities of this type, or experience a reduction in 

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revenues,in the future. We may also incur costs in the future due to changes inenvironmental and safety laws and regulations, enforcement policies or claimsfor personal, property or environmental damage. We may not be able to recoverthese costs from insurance or through higher tariffs.

***Failure of pipelineoperations due to unforeseen interruptions or catastrophic events may adverselyaffect our business and financial 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 acquisitionstrategy may be unsuccessful if we incorrectly predict operating results, areunable to identify and complete future acquisitions and integrate acquired assetsor businesses or are unable to raise financing on acceptable terms.***

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 actualconstruction and development costs could exceed our forecast and our cash flowfrom construction and development projects may not be immediate which may limitour ability to increase cash distributions.***

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 equity.

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

Our revenues and cashflows may 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 

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receiveany material increase in revenue or cash flow from that project until after itis placed in service and customers begin using the systems. If our revenues andcash flow do not increase at projected levels because of substantialunanticipated delays, or other factors, we may not meet our obligations as theybecome due and we may need to reduce or reprioritize our capital budget, sellnon-strategic assets, access the capital markets or reassess our level ofdistributions to unitholders to meet our capital requirements.

***Measurement losseson our pipeline system can be materially impacted by changes in estimation,commodity prices and other factors.***

Oilmeasurement losses occur as part of the normal operating conditions associatedwith our liquid petroleum pipelines. The three types of oil measurement lossesinclude:

·       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.

Quantifying oilmeasurement losses is inherently difficult because physical measurements ofvolumes are not practical due to the fact that products constantly move throughour pipelines and virtually all of our pipeline systems are locatedunderground. In our case, measuring and quantifying oil measurement losses isespecially difficult because of the size and scope of our pipeline systems andthe number of different grades of crude oil and types of crude oil products wecarry. Accordingly, we utilize engineering-based models and operationalassumptions to estimate product volumes in our system and associated oilmeasurement losses.

Natural gas measurementlosses occur as part of the normal operating conditions associated with ournatural gas pipelines. The quantification and resolution of measurement lossesis complicated by several factors including: 1) the significant quantities (i.e.,thousands) of measurement meters that we use throughout our natural gassystems, primarily around our gathering and processing assets; 2) varyingqualities of natural gas in the streams gathered and processed through oursystems; and 3) variances in measurement that are inherent in meteringtechnologies. Each of these factors may contribute to measurement losses thatcan occur on our natural gas systems.

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

Enbridge indirectly ownsall of the stock of our general partner and all of the voting stock of EnbridgeManagement, and elects all of the directors of both companies. Furthermore,some of the directors and officers of our general partners and EnbridgeManagement are also directors and officers of Enbridge. Consequently, conflictsof interest could arise between our unitholders and Enbridge.

Our partnership agreementlimits the fiduciary duties of our general partner to our unitholders. Theserestrictions allow our general partner to resolve conflicts of interest by consideringthe interests of all of the parties to the conflict, including EnbridgeManagement’s interests, our interests and those of our general partner. Inaddition, these limitations reduce the rights of our unitholders under ourpartnership agreement to sue our general partner or Enbridge Management, itsdelegee, should its directors or officers act in a way that, were it not forthese limitations of liability, would constitute breaches of their fiduciaryduties.

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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 affect us.

***We are exposed tocredit risks of our customers***

For example our Bamagassystem has agreements to provide transportation of up to 276,000 MMBtu/d ofnatural gas for a remaining period of 17 years to two utility plants that areindirectly owned by Calpine Corporation (“Calpine”). The Bamagas systemreceives a fixed demand charge of $0.07 per MMBtu of natural gas for 200,000MMBtu/d, regardless of whether the capacity is used. In December 2005,Calpine and many of its subsidiaries, including the subsidiary that owns thetwo utility plants served by our Bamagas system, filed voluntarily petitions torestructure under Chapter 11 of the United States Bankruptcy Code. Inconnection with the bankruptcy filing, Calpine has announced receipt ofcommitments for up to $2 billion of Debtor in Possession, or DIP financing toallow for the continued operation of its power plants. Our Bamagas system isthe sole supplier of natural gas to these two utility plants, and we expect thesubsidiary that owns these utility plants to continue performing under theterms of our agreement. Although we fully expect our customer to continue tomeet its obligations to us under the terms of the transportation agreements, weare exposed to a potential asset impairment of up to $53 million,representing the book value of the pipeline, if the customer is unable tofulfill its commitments. In April 2006, Calpine announced its intent tosell approximately 20 of its non-core and non-strategic power plants, althoughthe plants to be sold have not been announced. Calpine has continued to performunder the terms of its agreement with Bamagas and we remain confident that anylosses we may incur with respect to Calpine’s bankruptcy will be minimal. Wecontinue to monitor the Calpine bankruptcy proceedings and will recognize anylosses that may result when it becomes evident that a loss has been incurred.

***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. Revisionshave been proposed to the U.S. Energy Act that would, if passed, expand theregulation of certain greenhouse gas emissions requiring a cap and establishinga trade to facilitate compliance. Such provisions would make natural gaspipelines the segment of the gas industry regulated by an amendment. Whileproposed legislation has not yet passed and as other legislation is beingproposed the outcome is uncertain at this time. If and when these provisionspass the Partnership could be subject to additional costs to monitor andcontrol emissions above and beyond current practices and permits.

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**RISKS ARISING FROM OUR PARTNERSHIP STRUCTURE ANDRELATIONSHIPS WITH OUR GENERAL PARTNER AND ENBRIDGE MANAGEMENT**

***Our partnershipagreement and the delegation of control agreement limit the fiduciary dutiesthat Enbridge Management and our general partner owe to our unitholders andrestrict the remedies available to our unitholders for actions taken byEnbridge Management and our general partner that might otherwise constitute abreach of a fiduciary duty.***

Our partnership agreement contains provisions thatmodify the fiduciary duties that our general partner would otherwise owe to ourunitholders under state fiduciary duty law. Through the delegation of controlagreement, these modified fiduciary duties also apply to Enbridge Management asthe delegate of our general partner. For example, our partnership agreement:

·       permitsour general partner to make a number of decisions, including the determinationof which factors it will consider in resolving conflicts of interest, in its “solediscretion.” This entitles our general partner to consider only the interestsand factors that it desires, and it has no duty or obligation to giveconsideration to any interest of, or factors affecting, us, our affiliates orany unitholder;

·       providesthat any standard of care and duty imposed on our general partner will bemodified, waived or limited as required to permit our general partner to actunder our partnership agreement and to make any decision pursuant to theauthority prescribed in our partnership agreement, so long as such action isreasonably believed by the general partner to be in our best interests; and

·       providesthat our general partner and its directors and officers will not be liable formonetary damages to us or our unitholders for any acts or omissions if theyacted in good faith.

These and similarprovisions in our partnership agreement may restrict the remedies available toour unitholders for actions taken by Enbridge Management or our general partnerthat might otherwise constitute a breach of a fiduciary duty.

***Potential conflictsof interest may arise among Enbridge and its shareholders, on the one hand, andus and our unitholders and Enbridge Management and its shareholders, on theother hand. Because the fiduciary duties of the directors of our generalpartner and Enbridge Management have been modified, the directors may bepermitted to make decisions that benefit Enbridge and its shareholders orEnbridge Management and its shareholders more than us and our unitholders.***

Conflicts ofinterest may arise from time to time among Enbridge and its shareholders, onthe one hand, and us and our unitholders and Enbridge Management and itsshareholders, on the other hand. Conflicts of interest may also arise from timeto time between us and our unitholders, on the one hand, and EnbridgeManagement and its shareholders, on the other hand. In managing and controllingus as the delegate of our general partner, Enbridge Management may consider theinterests of all parties to a conflict and may resolve those conflicts bymaking decisions that benefit Enbridge and its shareholders or EnbridgeManagement and its shareholders more than us and our unitholders. The followingdecisions, among others, could involve conflicts of interest:

·       whetherwe or Enbridge will pursue certain acquisitions or other businessopportunities;

·       whetherwe will issue additional units or other equity securities or whether we willpurchase outstanding units;

·       whetherEnbridge Management will issue additional shares;

·       theamount of payments to Enbridge and its affiliates for any services rendered forour benefit;

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·       theamount of costs that are reimbursable to Enbridge Management or Enbridge andits affiliates by us;

·       theenforcement of obligations owed to us by Enbridge Management, our generalpartner or Enbridge, including obligations regarding competition betweenEnbridge and us; and

·       theretention of separate counsel, accountants or others to perform services for usand Enbridge Management.

In these and similar situations, any decision byEnbridge Management may benefit one group more than another, and in making suchdecisions, Enbridge Management may consider the interests of all groups, aswell as other factors, in deciding whether to take a particular course ofaction.

In othersituations, Enbridge may take certain actions, including engaging in businessesthat compete with us, that are adverse to us and our unitholders. For example,although Enbridge and its subsidiaries are generally restricted from engagingin any business that is in direct material competition with our businesses,that restriction is subject to the following significant 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 business thatmaterially and directly competes with us as part of a larger acquisition, solong as the majority of the value of the business or assets acquired, inEnbridge’s reasonable judgment, is not attributable to the competitivebusiness; and

·       Enbridgeand its subsidiaries are not prohibited from acquiring any business thatmaterially and directly competes with us if that business is first offered foracquisition to us and the board of directors of Enbridge Management and ourunitholders determine not to pursue the acquisition.

Since we were not engaged in any aspect of the naturalgas business at the time of our initial public offering, Enbridge and itssubsidiaries are not restricted from competing with us in any aspect of thenatural gas business. In addition, Enbridge and its subsidiaries would bepermitted to transport crude oil and liquid petroleum over routes that are notthe same as our Lakehead system, even if such transportation is in directmaterial competition with our business.

These exceptions 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.

***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 andthe issuance of additional Class C units, other than our quarterlydistributions 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.

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Additionally, the publicsale by our general partner of a significant portion of the Class B commonunits or Class C units that it currently owns could reduce the marketprice of the Class A common units. Our partnership agreement allows thegeneral partner to cause us to register for public sale any units held by thegeneral partner or its affiliates. A public or private sale of the Class Bcommon units or Class C units currently held by our general partner couldabsorb some of the trading market demand for the outstanding Class Acommon units.

***We are a holdingcompany and depend entirely on our operating subsidiaries’ distributions toservice 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 operating subsidiariesmay from time to time incur additional indebtedness under agreements thatcontain restrictions, which could further limit each operating subsidiary’sability 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

·       creditors holdingguarantees.

***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, and comply with applicable law or agreements to which weare a party or to provide funds for future distributions to partners. Thesecash reserves affect the amount of cash available for distribution to ourholders of common units.

**RISKS RELATED TOOUR 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 respective governingagreements. In addition, the agreements governing our credit facility and oursubsidiary’s First Mortgage Notes may prevent us from engaging in transactionsor capitalizing on 

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businessopportunities that we believe could be beneficial to us by requiring us tocomply with various covenants, including the maintenance of certain financialratios 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 incur liens to secure debt. A breach of anyrestriction under our credit facility or our indentures or our subsidiary’s FirstMortgage Notes could permit the holders of the related debt to declare allamounts outstanding under those agreements immediately due and payable and, inthe case of the credit facility, terminate all commitments to extend furthercredit. Any subsequent refinancing of our current debt or any new indebtednessincurred by us or our subsidiaries could have similar or greater restrictions.

**TAX RISKS TO COMMONUNITHOLDERS**

***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 be treated as a corporation for United Statesincome tax purposes. Our treatment as a corporation would substantially reducethe cash distributions on the common units that we distribute quarterly.Moreover, treatment of us as a corporation could materially and adverselyaffect our ability to make payments on our debt securities. The anticipatedbenefit of an investment in our common units depends largely on the treatmentof us as a partnership for federal income tax purposes. Under current law, weare treated as a partnership for federal income tax purposes and do not pay anyfederal income tax at the entity level. In order to qualify for this treatment,we must derive more than 90% of our annual gross income from specifiedinvestments and activities. While we believe that we currently do qualify andintend to meet this income requirement, we may not find it possible, regardlessof our efforts, to meet this income requirement or may inadvertently fail tomeet this income requirement. Current law may change so as to cause us to betreated as a corporation for federal income tax purposes without regard to oursources of income or otherwise subject us to entity-level taxation. If we wereto be treated as a corporation for federal income tax purposes, we would payfederal income tax on our income at the corporate tax rate, which is currentlya maximum of 35% and would pay state income taxes at varying rates. Undercurrent law, distributions to unitholders would generally be taxed as acorporate distribution. Because a tax would be imposed upon us as acorporation, the cash available for distribution to a unitholder would besubstantially reduced. Treatment of us as a corporation would cause asubstantial reduction in the value of our units.

In addition, severalstates are evaluating ways to subject partnerships to entity-level taxationthrough the imposition of state income, franchise, or other forms of taxation.State tax legislation resulting in the imposition of a partnership-level incometax on us would reduce the cash distributions on the common units and the valueof the i-units that we will distribute quarterly to Enbridge Management. Theenactment of significant legislation imposing partnership-level income taxescould cause a reduction in the value of our units.

***If the InternalRevenue Service does not respect our curative tax allocations, the after-taxreturn to our unitholders on their investment in our Class A common unitswould 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 

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RevenueService, which we refer to as the IRS, does not respect our curativeallocations, ratios of taxable income to cash distributions received by theholders of Class A common units will be materially higher than previouslyestimated

***The tax liability of our unitholders could exceedtheir distributions or proceeds from sales of Class A common units.***

Theholders of our Class A common units will be required to pay United Statesfederal income tax and, in some cases, state and local income taxes on theirallocable share of our income, even if they do not receive cash distributionsfrom us. They will not necessarily receive cash distributions equal to the taxon their allocable share of our taxable income. Further, if we have a largeamount of nonrecourse liabilities, they may incur a tax liability that isgreater than the money they receive when they sell their Class A commonunits.

***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, Arkansas, Florida, Georgia, Illinois,Indiana, Kansas, Kentucky, Louisiana, Michigan, Minnesota, Mississippi,Missouri, Montana, New York, South Carolina, North Carolina, North Dakota,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. Further, a unitholder who is a nonresidentalien, a foreign corporation or other foreign person will be required tofile a federal income tax return and pay tax on his share of our taxableincome because he will be regarded as being engaged in a trade or business inthe United 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 less thana 1% profit interest in us has very limited rights to participate in the incometax and audit process. Further, any adjustments in our tax returns will lead toadjustments 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.

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***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 to 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.

**Item 1B. UnresolvedStaff Comments**

None.

**Item 2. Properties**

A description of our properties and maps depicting thelocations of our liquids and natural gas systems are included in Item 1.Business, which is incorporated herein by reference.

In general, our systems are located on land owned byothers and are operated under perpetual easements and rights of way, licensesor permits that have been granted by private land owners, public authorities,railways or public utilities. The pumping stations, tanks, terminals andcertain other facilities of our systems are located on land that is owned byus, except for five pumping stations that are situated on land owned by othersand 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 theoperation of our business.

**Item 3. LegalProceedings**

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. Submissionof Matters to a Vote of Security Holders**

No matters were submitted to a vote of securityholders during the fourth quarter of 2006.

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**PART II**

**Item 5. Market forRegistrant’s Common Equity and Related Unitholder Matters**

OurClass A common units are listed and traded on the NYSE, the principalmarket for the Class A common units, under the symbol “EEP.” The quarterlyprice ranges per Class A common unit and cash distributions paid per unitfor 2006 and 2005 are summarized as follows:

| ** **               | ** ** | **First** | ** ** | **Second** | ** ** | **Third** | ** ** | **Fourth** | ** ** |
|--------------------------|------------|-----------|------------|------------|------------|-----------|------------|------------|------------|
| **2006 Quarters**        |       |      |       |       |       |      |       |       |       |
| High                     |       | $         | 47.80      |       | $          | 44.80     |       | $          | 49.51      |   | $ | 50.99 |   |
| Low                      |       | $         | 42.88      |       | $          | 42.00     |       | $          | 43.26      |   | $ | 46.10 |   |
| Cash distributions  paid |       | $         | 0.925      |       | $          | 0.925     |       | $          | 0.925      |   | $ | 0.925 |   |
| **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 |   |

 

On February 21, 2007the last reported sales price of our Class A common units on the NYSE was$52.58. At February 21, 2007, there were approximately 78,000 Class Acommon unitholders, of which there were approximately 2,000 registeredClass A common unitholders of record. There is no established publictrading market for our Class B common units, all of which are held by theGeneral Partner, our Class C units, 50 percent of which are held by theGeneral Partner and 50 percent of which are held by an institutional investor,or our 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,**                                       | ** ** |
|----------------------------------------------------------------------------------------------------|------------|----------------------------------------------------------------------------------|------------|
| ** **                                                                                         | ** ** | **2006**                                                                         | ** ** | **2005** | ** ** | **2004** | ** ** | **2003** | ** ** | **2002** | ** ** |
| ** **                                                                                         | ** ** | **(dollars in millions, except per unit amounts)** | ** ** |
| **Income Statement Data:****(2)(3)(4)**                                                            |       |                                                                             |       |   |   |   |   |   |   |   |   |   |   |
| Operating revenue                                                                                  |       | $                                                                                | 6,509.0    |   | $ | 6,476.9 |   | $ | 4,291.7 |   | $ | 3,172.3 |   |   | $ | 1,185.5 |   |   |
| Operating expenses                                                                                 |       | 6,122.1                                                                          |       | 6,285.0 |   | 4,054.5 |   | 2,978.0 |   |   | 1,047.5 |   |   |
| Operating income                                                                                   |       | 386.9                                                                            |       | 191.9 |   | 237.2 |   | 194.3 |   |   | 138.0 |   |   |
| Interest expense                                                                                   |       | (110.5                                                                           | )          | (107.7 | ) | (88.4 | ) | (85.0 | ) |   | (59.2 | ) |   |
| Rate refunds                                                                                       |       | —                                                                           |       | — |   | (13.6 | ) | — |   |   | — |   |   |
| Other income (expense)                                                                             |       | 8.5                                                                              |       | 5.0 |   | 3.0 |   | 2.4 |   |   | (0.2 | ) |   |
| Minority interest                                                                                  |       | —                                                                           |       | — |   | — |   | — |   |   | (0.5 | ) |   |
| Net income                                                                                         |       | $                                                                                | 284.9      |   | $ | 89.2 |   | $ | 138.2 |   | $ | 111.7 |   |   | $ | 78.1 |   |   |
| Net income per limited  partner unit (basic and diluted)(1)                              |       | $                                                                                | 3.62       |   | $ | 1.06 |   | $ | 2.06 |   | $ | 1.93 |   |   | $ | 1.76 |   |   |
| Cash distributions paid  per unit                                                                  |       | $                                                                                | 3.70       |   | $ | 3.70 |   | $ | 3.70 |   | $ | 3.70 |   |   | $ | 3.60 |   |   |
| **Financial Position Data (at year end):****(2)(3)(4)**                                            |       |                                                                             |       |   |   |   |   |   |   |   |   |   |   |
| Property, plant and  equipment, net                                                                |       | $                                                                                | 3,824.9    |   | $ | 3,080.0 |   | $ | 2,778.0 |   | $ | 2,465.6 |   |   | $ | 2,253.3 |   |   |
| Total assets                                                                                       |       | 5,223.8                                                                          |       | 4,428.4 |   | 3,770.7 |   | 3,231.8 |   |   | 2,834.9 |   |   |
| Long term debt,  excluding current  maturities                                                     |       | 2,066.1                                                                          |       | 1,682.9 |   | 1,559.4 |   | 1,155.8 |   |   | 1,011.4 |   |   |
| Loans from General  Partner and affiliates                                                         |       | —                                                                           |       | 151.8 |   | 142.1 |   | 133.1 |   |   | 444.1 |   |   |
| Partners’ capital:                                                                            |       |                                                                             |       |   |   |   |   |   |   |   |   |   |   |
| Class A common units                                                                               |       | 1,141.7                                                                          |       | 1,142.4 |   | 1,021.6 |   | 914.9 |   |   | 604.8 |   |   |
| Class B common units                                                                               |       | 67.6                                                                             |       | 67.2 |   | 66.7 |   | 64.2 |   |   | 48.7 |   |   |
| Class C units                                                                                      |       | 509.8                                                                            |       | — |   | — |   | — |   |   | — |   |   |
| i units                                                                                            |       | 466.3                                                                            |       | 421.7 |   | 399.4 |   | 370.7 |   |   | 335.6 |   |   |
| General Partner                                                                                    |       | 47.6                                                                             |       | 34.6 |   | 31.0 |   | 27.5 |   |   | 18.8 |   |   |
| Accumulated other  comprehensive (loss) income                                                |       | (189.6                                                                           | )          | (302.1 | ) | (120.8 | ) | (64.0 | ) |   | (16.3 | ) |   |
| Partners’ capital                                                                             |       | $                                                                                | 2,043.4    |   | $ | 1,363.8 |   | $ | 1,397.9 |   | $ | 1,313.3 |   |   | $ | 991.6 |   |   |
| **Cash Flow Data:****(2)(3)(4)**                                                                   |       |                                                                             |       |   |   |   |   |   |   |   |   |   |   |
| Cash flows provided by  operating activities                                                       |       | $                                                                                | 321.6      |   | $ | 267.1 |   | $ | 245.4 |   | $ | 148.2 |   |   | $ | 200.8 |   |   |
| Cash flows used in  investing activities                                                           |       | (867.0                                                                           | )          | (437.1 | ) | (419.1 | ) | (431.0 | ) |   | (557.2 | ) |   |
| Cash flows provided by  financing   activities                                                     |       | 640.2                                                                            |       | 181.5 |   | 187.6 |   | 286.9 |   |   | 376.5 |   |   |
| Acquisitions and capital expenditures included in  investing activities, net of cash acquired |       | (897.7                                                                           | )          | (531.2 | ) | (429.8 | ) | (423.5 | ) |   | (563.9 | ) |   |

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Notes to Selected Financial Data:

(1)                Theallocation of net income to the General Partner in the following amounts hasbeen deducted before calculating net income per unit: 2006, $30.9 million;2005, $23.5 million; 2004, $22.5 million; 2003, $19.6 million;and 2002, $13.1 million.

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(2)                Ourincome statement, financial position and cash flow data reflect the followingacquisitions and dispositions:

·       April 2006,acquisition of a natural gas pipeline in east Texas;

·       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;

(3)                Ourincome statement, financial position and cash flow data include the effect ofthe following debt issuances:

·       TheDecember 2006 issuance of $300 million of senior unsecured notes;

·       TheSeptember 2005 amendment of our credit facility to extend the letter ofcredit sublimit from $175 million to $300 million and increase the commitmentsavailable from $600 million to $800 million maturing in 2010, and thesubsequent extension of the commitments available to $1 billion inMarch 2006.

·       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

·       The 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 limited partner unit issuances:

·       TheAugust 2006 issuance of approximately 10.8 million Class C units inequal amounts to our general partner and an institutional investor andsubsequent Class C unit distribution of 0.2 million in lieu of cashdistributions;

·       TheDecember  2005 issuance of 0.13 million Class A common units; theNovember 2005 issuance of 3.0 million Class A common units; and theFebruary 2005 issuance of 2.5 million Class A common units;

·       TheSeptember 2004 issuance of 3.68 million Class A common units;and the January 2004 issuance of 0.45 million Class A commonunits;

·       TheDecember 2003 issuance of 5.0 million Class A common units; andthe May 2003 issuance of 3.9 million Class A common units;

·       TheMarch 2002 issuance of 2.3 million Class A common units; and

·       TheOctober 2002 issuance of 9.0 million i-units and subsequent quarterlyi-unit distributions during 2006, 2005, 2004, 2003 and 2002, respectively, of1.0 million, 0.8 million, 0.8 million, 0.8 million and0.2 million, in lieu of cash distributions.

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**Item 7. Management’sDiscussion and Analysis of Financial Condition and Results of Operations**

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 OFOPERATIONS—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 services, 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 achievement ofour long-term objectives, to aid in resource allocation decisions and to assessoperational performance.

Our Liquids segment includes the operations of ourLakehead, North Dakota and Mid-Continent systems. Each of these systems largelyconsists of FERC-regulated interstate crude oil and liquid petroleum pipelines.Our Mid-Continent system is also one of the largest above ground crude oilstorage facilities in North America, with the majority of the capacityavailable for contract storage not subject to regulation by the FERC. Each ofthese systems generates most of its revenues by charging shippers a per barreltariff rate to transport 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. 

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

| ** **                               | ** ** | **2006**               | ** ** | **2005** | ** ** | **2004** | ** ** |
|------------------------------------------|------------|------------------------|------------|----------|------------|----------|------------|
| ** **                               | ** ** | **(in millions)** | ** ** |
| **Operating Income**                     |       |                   |       |     |       |     |       |
| Liquids                                  |       | $                      | 199.8      |     | $          | 127.3    |       | $ | 139.1 |   |
| Natural Gas                              |       | 133.9                  |       | 110.5    |       | 98.1     |       |
| Marketing                                |       | 56.1                   |       | (42.4    | )          | 3.6      |       |
| Corporate, operating and  administrative |       | (2.9                   | )          | (3.5     | )          | (3.6     | )          |
| **Total Operating Income**               |       | 386.9                  |       | 191.9    |       | 237.2    |       |
| Interest expense                         |       | (110.5                 | )          | (107.7   | )          | (88.4    | )          |
| Rate refunds                             |       | —                 |       | —   |       | (13.6    | )          |
| Other income                             |       | 8.5                    |       | 5.0      |       | 3.0      |       |
| **Net Income**                           |       | $                      | 284.9      |     | $          | 89.2     |       | $ | 138.2 |   |

 

***Summary Analysis of Operating Results***

*Liquids*

Our Liquids segmentcontributed operating income of $199.8 million in 2006, or $72.5 million morethan the $127.3 million contributed in 2005. The operating income of ourLiquids segment in 2006 was affected by the following factors:

·       Highervolumes on our Lakehead system following completion of the repair and expansionof a major oil sands plant that was damaged by fire in early January 2005,partially offset by higher power costs associated with the increased volumes;

·       Theannual index rate increase effective July 1, 2006, which increased ouraverage tariffs;

·       Longertransportation hauls on our Lakehead system; and

·       Lower oil measurementlosses.

*Natural Gas*

Operating incomefrom our Natural Gas segment grew to $133.9 million in 2006 representing anincrease of $23.4 million over the $110.5 million generated in 2005. Theincreased contribution of our Natural Gas segment is attributable to thefollowing:

·       Averagedaily volume on our major natural gas systems was 13 percent greater in 2006than in 2005, due to continuing investments to expand the capacity of our threelargest natural gas systems. The volume and revenue growth is also the resultof additional wellhead supply contracts and robust drilling activity in theAnadarko basin, Bossier Trend and Barnett Shale. Also contributing to theincrease in volumes is an 80-mile pipeline we acquired in April 2006that is complimentary to our existing East Texas system and providedapproximately 75,500 million British thermal units per day, or MMBtu/d, ofincremental volume. 

·       Increasedprocessing capacity from the expansion of our existing Zybach processingfacility on our Anadarko system that we completed in the second quarter of 2006and the construction of our Henderson natural gas processing facility on ourEast Texas system completed in the third quarter of 2006. 

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·       Favorablecommodity prices where NGL and crude oil prices remained high relative tonatural gas prices, which have declined from the high prices reached in late2005, contributed to improved results from our processing activities.   

·       NGLpurchase, transportation and fractionation costs that are predominantlyassociated with prior years were corrected in 2006, partially offsetting theincreased contribution to operating income discussed above.

·       Also partially offsettingthe improvements to operating income noted above are increases in operating andadministrative costs that are mostly variable with the incremental volumesgathered, processed and transported on our systems and the workforce relatedcosts we are charged for the additional resources and related benefitsnecessary to operate and support our existing assets and the expansion of ournatural gas systems. Additionally, our repair and maintenance costs haveincreased due to additional pipeline integrity and other work we perform tomaintain the service capability of our systems. 

*Marketing*

Operating incomefrom our Marketing segment increased in 2006 from operating losses for thecomparable period in 2005. The change in operating income from 2005 to 2006resulted from the following:

·       Unrealized,non-cash mark-to-market net gains for 2006 of $64.5 million compared withnon-cash mark-to-market net losses of $50.3 million for 2005. The gainsresulted from the change in market value of our derivative financialinstruments that do not qualify for hedge accounting;

·       Partially offsetting theunrealized mark-to-market gains is a non-cash charge of $17.0 million for theyear ended December 31, 2006, resulting from a lower of cost or marketaccounting adjustment to the cost basis of our natural gas inventory. Themarket price for natural gas in various storage locations experienced declinesduring the year from the prices at which the inventory was purchased. We usederivative financial instruments to fix the price of our forecasted sales ofinventory and as a result we expect that a majority of this charge will beoffset by future financial and physical transactions that will settle at thetime we sell the inventory. 

***Derivative Transactions and Hedging Activities***

We record all financial instruments in theconsolidated financial statements at fair market value pursuant to therequirements of SFAS No. 133. For those derivative financial instrumentsthat do not qualify for hedge accounting, all changes in fair market value arerecorded through our Consolidated Statements of Income each period. The fairmarket value of these derivative financial instruments reflects the estimatedamounts that we would pay or receive to terminate or close the contracts at thereporting date, although that is not our intent.

Declining natural gas prices during our fiscal yearended December 31, 2006, produced non-cash mark-to-market gains of $64.4million and positively affected our operating results. Mark-to-market gains orlosses create volatility in our results. The derivative financial instrumentswe have in place do not affect our cash flow until they are settled. We expectthese non-cash gains or losses to reverse in future periods as we settle thederivative financial instruments against the underlying physical transactions.Because of the economic benefit we receive by minimizing the volatility in ourcash flows by using derivative financial instruments to hedge our portfolio ofnatural gas and NGLs, we intend to continue using them. Our continued use ofderivative financial instruments may result in additional unrealized, non-cashgains or losses in the future.

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Thefollowing table presents the unrealized gains and losses associated withchanges in the fair value of our derivatives, which are recorded as an elementof Cost of natural gas in our Consolidated Statements of Income and disclosedas a reconciling item on our Statements of Cash Flows:

| **Derivative fair value gains (losses)** | ** ** | ** **             | ** ** | **December 31,  2006** | ** ** | **December 31,  2005** | ** ** | **December 31,  2004** | ** ** |
|--------------------------------------------------------------|------------|------------------------|------------|-----------------------------|------------|-----------------------------|------------|-----------------------------|------------|
| ** **                                                   | ** ** | **(in millions)** | ** ** |
| Natural Gas segment                                          |       |                   |       |                        |       |                        |       |                        |       |   |   |   |   |
| Hedge ineffectiveness                                        |       |                   | $          | (1.9                        | )          |                        |       | $                           | (2.5       | ) |   |   | $ | (1.1 | ) |   |
| Non-qualified hedges                                         |       |                   | 1.8        |                        |       |                        | (5.6       | )                           |       |   | — |   |   |
| Marketing                                                    |       |                   |       |                        |       |                        |       |                        |       |   |   |   |   |
| Non-qualified hedges                                         |       |                   | 64.5       |                        |       |                        | (41.3      | )                           |       |   | (2.1 | ) |   |
| Discontinued hedges                                          |       |                   | —     |                        |       |                        | (9.0       | )                           |       |   | — |   |   |
| Derivative fair value  gains (losses)                        |       |                   | $          | 64.4                        |       |                        |       | $                           | (58.4      | ) |   |   | $ | (3.2 | ) |   |

 

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

In connection with thesale of assets in December 2005, as discussed in Note 3 to theConsolidated Financial Statements beginning on page F-1 of this report, wesettled for cash of approximately $16.3 million, natural gas collarsrepresenting derivative financial instruments on 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 qualified for and weredesignated 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 through 2007.

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**RESULTS OFOPERATIONS—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:

| ** **                                         | ** ** | **2006**                            | ** ** | **2005** | ** ** | **2004** | ** ** |
|----------------------------------------------------|------------|-------------------------------------|------------|----------|------------|----------|------------|
| ** **                                         | ** ** | **(dollars in millions)** | ** ** |
| **Operating Results**                              |       |                                |       |     |       |     |       |
| Operating  revenues                                |       | $                                   | 512.8      |     | $          | 418.0    |       | $ | 409.3 |   |
| Operating and  administrative                      |       | 141.3                               |       | 144.2    |       | 128.9    |       |
| Power                                              |       | 107.6                               |       | 74.8     |       | 72.8     |       |
| Depreciation and  amortization                     |       | 64.1                                |       | 71.7     |       | 68.5     |       |
| Operating  expenses                                |       | 313.0                               |       | 290.7    |       | 270.2    |       |
| **Operating  Income**                              |       | $                                   | 199.8      |     | $          | 127.3    |       | $ | 139.1 |   |
| **Operating  Statistics**                          |       |                                |       |     |       |     |       |
| **Lakehead system:**                               |       |                                |       |     |       |     |       |
| United States(1)                                   |       | 1,204                               |       | 1,036    |       | 1,064    |       |
| Province of Ontario(1)                             |       | 313                                 |       | 303      |       | 358      |       |
| **Total deliveries****(1)**                        |       | 1,517                               |       | 1,339    |       | 1,422    |       |
| **Barrel miles (billions)**                        |       | 400                                 |       | 338      |       | 367      |       |
| **Average haul (miles)**                           |       | 722                                 |       | 692      |       | 706      |       |
| **Mid-Continent  system deliveries****(1)(2)**     |       | 244                                 |       | 236      |       | 237      |       |
| **North  Dakota system deliveries****(1)**         |       | 92                                  |       | 87       |       | 85       |       |
| **Total Liquids Segment Delivery  Volumes****(1)** |       | 1,853                               |       | 1,662    |       | 1,744    |       |

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(1)                Average barrelsper day in thousands.

(2)                Tenmonths of deliveries in 2004.

*Year ended December 31,2006 compared with year ended December 31, 2005*

Our Liquids segment accounted for $199.8 million ofoperating income in 2006, representing an increase of $72.5 million over 2005. Thefavorable results of the Liquids segment assets reflect continuing growth inour transportation volumes while actively managing the costs of our services. Themajority of this increase related to significantly improved results on ourLakehead system.

Operating revenuein 2006 increased by $94.8 million to $512.8 million, compared with $418.0million in 2005. As indicated in the table above, total delivery volumes of ourLiquids segment averaged 1.853 million Bpd in 2006, representing a 0.191million Bpd increase from the 1.662 million Bpd delivered in 2005. Thisaccounted for an increase in operating revenues of approximately $48.0 million.The increases in deliveries on our Liquids systems are primarily derived fromincreased production of Western Canadian crude oil delivered on our Lakeheadsystem. The increases in deliveries are attributable to the following:

·       Suncor,an oil sands producer in Alberta, Canada, experienced a fire at its upgradesite in January 2005, which affected production for the majority of 2005. Inlate September 2005, Suncor completed repairs and an expansion to itsupgrader site. Suncor’s production levels have increased since that time.

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·       Conventionallight, heavy crude oil and bitumen production have increased as existing andnew facilities were commissioned during 2006.

·       Syncrude,another oil sands producer in Alberta completed its Stage 3 expansion andinitiated production on its Coker 8-3 unit in May 2006 enabling all Stage3 units to be brought on line. However, shortly following start up, an ammonialeak resulted in its closure until August 2006. Additionally, as a resultof a leak discovered in November, the Coker 8-2 unit was closed for turnaroundinto 2007. The Stage 3 expansion is designed to increase productive capacityfrom 250,000 Bpd to an average 350,000 Bpd of a light synthetic crude oil. Ourdeliveries in 2006 were marginally higher as a result of Syncrude’s completionand start up of its Stage 3 expansion.

Contributing to the revenue growth of our Liquidssegment are the increases in the average tariffs on all three of our Liquidssystems. These tariff increases were partly the result of the annual index rateincrease allowed by the FERC. On our Lakehead system, we increased our rates byan average of three percent. Also on our Lakehead system, new tariffs went intoeffect on April 1, 2006 for an adjustment on the Terrace expansion programsurcharge due to lower than expected volumes moving on the Lakehead system, andnew facilities in service, that were not operating during 2005. These tariffincreases, along with the four percent increase in average hauls from 692 milesin 2005 compared with 722 in 2006 resulted in a combined increase in operatingrevenue of approximately $35.4 million.

Continuing volume growth related to our Mid-Continentstorage terminal system in Cushing, Oklahoma, and El Dorado, Kansas, hasresulted in an increase in operating revenue of approximately $6.8 millioncompared with 2005. Net capacity additions in 2006 bring the total storagecapacity to 97 tanks and approximately 12.8 million barrels. This additionalstorage capacity is expected to provide ongoing fixed, variable, and spotstorage revenue.

Operating and administrative expenses for 2006 were$141.3 million, or $2.9 million less than in 2005, primarily as a result ofdecreased oil measurement losses which are partially offset by increasedworkforce related costs and materials, supplies, and other general costs.

Workforce related costs increased due to theadditional resources and related benefit costs we are charged for theoperational, administrative, regulatory and compliance support necessary forour growing systems. Our general partner charges us the costs associated with employees and related benefits for personnel thatare assigned to us or otherwise provide us with managerial and administrativeservices. The portion of compensation and related costs we are charged isdependent upon such items as estimated time spent, miles of pipe and headcount.We have experienced an increase in workforce related costs as a resultof the growth and expansion of our Liquids system operations. We expect thesecosts will continue to increase in future periods as we continue to expand ourLiquids system operations.

Materials, supplies and other, and Repair andmaintenance costs were both higher in 2006 compared with 2005 due to higherpipeline inspection costs associated with our pipeline integrity managementprograms, increased outside contractor services, field inventory adjustmentsand other general costs.

Inventoryadjustments include oil measurement losses, which occur as part of the normaloperating conditions associated with our Liquids pipelines, include thefollowing three elements:

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

·       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.

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During the fourth quarter of 2005, we identifiedcertain operating conditions on connected third-party systems that werecontributing to higher levels of physical losses on our Lakehead system. Improvementsto our oil measurement processes have resulted in fewer physical losses during2006 on our Lakehead and Mid-Continent systems. We expect these improvements tohave a continuing positive impact on our oil measurement losses going forward.

Power costs increased $32.8 million in 2006, comparedwith 2005, primarily due to the increase in volumes transported on our Lakeheadsystem and higher electricity rates we are charged by our power suppliers. Wehave experienced a trend of increasing electricity rates from our powersuppliers due to higher natural gas costs.

We completed adepreciation study of the Lakehead system in the first quarter of 2006 thatresulted in extending the composite remaining service life of the system assetsfrom 21.5 to 26 years. The impact of the depreciation study was an $11.0million reduction of depreciation expense for the full year of 2006.

*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 eight percentover 2004. Lower results on the Lakehead system were modestly offset bystronger 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 ortwo percent to $418.0 million, compared with $409.3 million for 2004. OurMid-Continent assets contributed higher operating revenue of approximately $6.6million for the additional two months of ownership in 2005 compared to 2004.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 percent, from 1.422 million Bpd during 2004 to1.339 million Bpd during 2005. This resulted in lower operating revenue for2005 of approximately $20.0 million. The decrease is the result of lower thanexpected crude oil supply in western Canada from three factors. First, Suncor,an oil sands 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.These tariff increases were partly the result of the annual index rate increaseof approximately 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.

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Operating andadministrative expenses for 2005 increased by $15.3 million to $144.2 million,compared with $128.9 million in 2004. The increase was attributable to thefollowing factors:

(1)         workforce related costsincreased by approximately $6.9 million due to the additional resources andrelated benefit costs we are charged for the operational, administrative,regulatory and compliance support necessary for our growing systems;

(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 projectrecoveries were lower by approximately $2.8 million due to a decrease inutilization of our workforce on capital projects and a reduction inconstruction activity on our Liquids systems;

(4)         oil measurement lossesincreased approximately $2.4 million.

Oil measurementlosses occur as part of the normal operating conditions associated with ourLiquids pipelines. During 2005, the increase in oil measurement losses was afunction of the following two factors:

·       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;

·       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 three percent,in 2005 compared with 2004, mostly due to higher electricity rates and a fulltwelve-month contribution from our Mid-Continent system compared to ten monthsin 2004, 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 five percent, in 2005 compared with2004. The increase is driven primarily by a full twelve-month contribution fromour Mid-Continent system and an increase in the depreciable asset base on ourLakehead system in 2005.

*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. Combined conventional and oil sands established reserves ofapproximately 179 billion barrels, compared with Saudi Arabia’s proved reservesof approximately 260 billion barrels. The National Energy Board, or NEB,estimates that total 2006 Western Canadian Sedimentary Basin, or WCSB,production averaged approximately 2.3 million Bpd compared with 2.2 million Bpdin 2005. According to production forecasts by CAPP, Western Canadian crude oilproduction is projected to grow progressively from approximately 2.2 millionBpd in 2005 to 4.7 million Bpd by 2020. Conventional crude oil production isexpected to decline from approximately 1.0 million Bpd to approximately 550,000Bpd over the same period. The net increased production is expected to resultfrom an estimated $82 billion of active or planned projects that are beingdeveloped in the oil sands. The projected growth in Western Canadiancrude production will require construction of new pipelines to ensure new oilsupplies can be transported to markets in the United States.

We and Enbridge are actively working with ourcustomers to develop transportation options that will allow Canadian crude oilgreater access to markets in the United States.

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Partnership Projects

***Southern Access***

In conjunction with Enbridge, we announced in 2005 theapproval of the 400,000 Bpd Southern Access expansion project, which receivedendorsement from CAPP, a trade association that represents a large majority ofthe Lakehead system’s customers. We are undertaking the U.S. portion of theexpansion on our Lakehead system and the first stage will add approximately44,000 Bpd of capacity in 2007 and up to an additional 146,000 Bpd by early2008. The project includes a new pipeline between Superior and Delavan,Wisconsin, along with pump station enhancements upstream and downstream of thissegment. The second stage of the expansion project will provide additionalupstream pumping capacity and a new pipeline from Delavan to Flanagan,Illinois, with completion expected in early 2009. Completion of the totalSouthern Access expansion project will create a 454-mile pipeline withapproximately 400,000 Bpd of incremental capacity on our Lakehead system.

On March 16, 2006,the FERC approved an Offer of Settlement with respect to tariff principles forthe Southern Access expansion, which were negotiated with CAPP. In July 2006,we obtained support from shippers and CAPP to increase the diameter of the newpipeline segments of the project from 36 inches, to which the previouslynegotiated tariff principles apply, up to 42 inches. The incremental capitalcost of the larger diameter pipe is currently estimated at approximately $157million, bringing our total estimated costs to approximately $1.3 billion. Thelarger diameter will not provide increased capacity in the near term but doesincrease the ultimate capacity of the line from 800,000 Bpd to 1,200,000 Bpdwith expenditures for additional pumping equipment. This places us in afavorable position to secure future expansion opportunities for our Lakeheadsystem. We will defer any return on the incremental capital until theadditional capacity is required by shippers (see discussion of Alberta Clipperproject below). In the interim, shippers will absorb all the incrementaloperating costs of the larger diameter line but will benefit from reduced powercosts at higher throughput levels. Delivery of line pipe to the right of wayhas commenced to ensure full completion in early 2009.

*Alberta Clipper*

Based on forecasts of oil sands production growthprepared by Enbridge, as well as forecasts by CAPP, we believe that there willbe a need for additional export pipeline capacity out of Western Canada overand above projects which have already received shipper support. Based on thisanalysis, as well as interest expressed by shippers, we and Enbridge areplanning to develop the Alberta Clipper project. This project will involveconstruction of a 36-inch diameter heavy crude line fromHardisty, Alberta to Superior, Wisconsin in conjunction with additionalpumping power applied to the Southern Access 42-inch pipe from Superiorto Flanagan. We anticipate that our share of the cost of this project, ascurrently proposed, will approximate $0.8 billion in 2006 dollars, excluding bothcapitalized interest and the approximate cost of $157 million to “prebuild”Southern Access to 42 inches as discussed above.

Alberta Clipper wasoriginally planned to be a contract carrier pipeline based on interestexpressed by selected shippers in providing throughput commitments in returnfor assured access to capacity. Based on discussions with a broader group ofshippers the preference is for Alberta Clipper to be a common carrier linefully integrated with the Enbridge/Lakehead mainline systems for tollingpurposes. Enbridge anticipates finalizing commercial terms of the AlbertaClipper project with CAPP during the first quarter of 2007. To maintain theproject construction schedule, CAPP has agreed to backstop initial capitalcosts of the Alberta Clipper project. Initial capital costs will includelong-lead time items such as pipe, pumping equipment and rights of way. In theunlikely event the Alberta Clipper project does not proceed, CAPP will supportthe collection of the initial capital costs through the Partnership’s normalFERC rate setting process. Alberta Clipper is expected to be in service betweenlate 2009 and mid-2010.

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*North Dakota*

Work is proceeding on ourpreviously announced North Dakota system expansion. Three critical hydrostaticpressure tests have been successfully completed and the North Dakota PublicService Commission approvals have been obtained for all phases of the project. Theexpansion will add approximately 30,000 Bpd of mainline throughput capacity andexpand the system’s feeder segment by approximately 30,000 Bpd at an estimatedcost of $70 million. The expansion is supported by increasing crude oilproduction from the Williston Basin in Montana and North Dakota and is expectedto be completed in phases throughout 2007, with the final completion datesscheduled in the fourth quarter of 2007.

*Superior and Griffith Storage*

Due to forecastedproduction increases of synthetic heavy crude oil that we anticipate will betransported on the Enbridge/Lakehead mainline systems from Western Canada toChicago, we are constructing additional crude oil storage tanks at Superior andGriffith to accommodate the anticipated volumes. We are building two tanks withan approximate capacity of 360,000 barrels each that are scheduled forcompletion in the first half of 2007, and two additional tanks each with anapproximate capacity of 250,000 barrels each to be completed in the first halfof 2008.

*Cushing Terminal Storage*

We continue to experiencestrong interest from customers in securing access to long-term contract storagecapacity at our Cushing, Oklahoma terminal. During 2006, we obtainedcommitments and initiated construction of an additional 5.0 million barrels ofstorage tanks, 1.1 million barrels of which were completed in late December 2006.The addition of the remaining 3.9 million barrels of capacity during 2007, atan expected cost of $72 million, will bring our total terminal capacity toapproximately 16.7 million barrels. This capacity will increase operationaltankage available to support our Mid-Continent liquids pipeline systems, andavailable contract storage.

Enbridge and Other Projects

*Spearhead Reversal*

In another effort toprovide shippers access to new markets, Enbridge acquired a pipeline that runsfrom Cushing to Chicago, Illinois. The pipeline, renamed Spearhead, begandelivering Canadian crude oil to the major oil hub at Cushing in March 2006and has ongoing capacity of approximately 125,000 Bpd. We have benefited fromreversal of the pipeline due to Western Canadian crude oil being carried on ourLakehead system as far as Chicago, and then transferred to the Spearheadpipeline.

*Pegasus Reversal*

In April 2006,ExxonMobil completed the reversal of two of its crude oil pipelines allowing upto 66,000 Bpd of Canadian crude oil to flow from the U.S. Midwest to the U.S.Gulf Coast. The combined reversed pipeline is linked to our Lakehead system atChicago via the Mustang Pipe Line Partners system to Patoka, Illinois. TheMustang Pipe Line Partners system is 30 percent owned by an affiliate ofEnbridge. ExxonMobil has firm commitments from Canadian shippers for an averageof 50,000 Bpd of capacity on the lines from Patoka, to Nederland, Texas for thenext five years. The connection of our Lakehead system with this new marketsupports increased throughput on our Lakehead system; however, the reversedExxonMobil system is also capable of transporting Western Canadian crude oilmoved via other competing pipelines into the Patoka market.

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*Southern Access Extension*

In July 2006,Enbridge announced that it received support from shippers and CAPP for its 36-inchdiameter Southern Access Extension pipeline from Flanagan, Illinois to Patoka,Illinois. The extension will broaden the reach of the Enbridge/Lakeheadmainline system to incremental markets accessible from the Patoka hub. Theproject is scheduled for completion in the first quarter of 2009 and will beundertaken by Enbridge; however, we will benefit through incremental volumes movingthrough our Lakehead system to reach this extension. The Offer of Settlementfiled in September 2006 was rejected by the FERC because of its rolled-intoll design. However, support for the project remains high and Enbridge isworking with shippers to prepare an alternative tolling structure to addressthe initial opposition. The second application is expected to be filed with theFERC in the first quarter of 2007 and will allow the project to proceed on schedule.

*Southern Lights*

During the third quarterof 2006, Enbridge completed a successful open season on its Southern Lightsdiluent pipeline from Chicago, Illinois to Edmonton, Alberta. The SouthernLights pipeline responds to interest from a number of western Canadianproducers to increase the availability of crude oil diluent in Alberta. Diluentis required to transport the heavy oil and bitumen being produced in increasingvolumes from the Alberta oil sands. The project involves the exchange of a 156-milesection of pipeline we own for a similar section of a new pipeline to beconstructed as part of the project. We expect to benefit from increased heavycrude shipments, which will be facilitated by the diluent line. In addition,this project involves a reconfiguration of our light crude mainline systemwhich will provide an additional 45,000 Bpd of effective capacity at no cost tous. This project is expected to be in service during 2010.

*U.S. Gulf Coast Access*

Shippers have indicatedinterest to Enbridge in the development of additional pipeline capacity totransport Canadian crude oil to the U.S. Gulf Coast, including the potentialfor a direct line from Alberta to the U.S. Gulf Coast. Enbridge is examining anumber of alternatives to respond to this interest, including alternatives thatwould extend off our Lakehead system, utilizing either existing pipelines whichcould be connected and reversed, or newly constructed extensions. Thesealternatives would complement our Lakehead system and support its expansion.Enbridge has indicated that a direct line would require a minimum of 400,000Bpd of throughput commitments to be economic, and could not be in servicebefore 2011. A direct line, if developed by Enbridge or any other party, wouldcompete with our Lakehead system.

*Eastern PADD II Access*

Enbridge has held discussions with several refiners inthe eastern United States to gauge interest in supporting the development of apipeline to provide incremental pipeline capacity to this market. The level ofinterest has increased significantly during the latter part of 2006. Enbridgeis currently in discussions with interested parties to develop a pipeline todeliver at least 200,000 Bpd of incremental Canadian supply from the Chicagoarea to the eastern region of PADD II. This project would be complementary tothe Partnership’s mainline system.

The Partnership andEnbridge believe that the Southern Access Expansion Program, the AlbertaClipper Project, and other initiatives to provide access to new markets in theMidwest, Mid-continent and Gulf Coast, offer flexible solutions to futuretransportation requirements of western Canadian crude oil producers, and thein-service timing of these solutions is in line with prospective shipper needs.

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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;

·       ninenatural gas treating plants;

·       seventeennatural 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,** | ** ** |
|--------------------------------|------------|--------------------------------------------|------------|
| ** **                     | ** ** | **2006**                                   | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                     | ** ** | **(dollars in millions)**        | ** ** |
| Operating revenues             |       | $                                          | 3,020.7    |   | $ | 2,352.1 |   | $ | 1,319.9 |   |
| Cost of natural gas            |       | 2,601.1                                    |       | 2,018.7 |   | 1,031.8 |   |
| Operating and administrative   |       | 215.4                                      |       | 175.0 |   | 138.3 |   |
| Depreciation and  amortization |       | 70.3                                       |       | 66.0 |   | 51.7 |   |
| Gain on sale of assets         |       | —                                     |       | (18.1 | ) | — |   |
| Expenses                       |       | 2,886.8                                    |       | 2,241.6 |   | 1,221.8 |   |
| **Operating  income**          |       | $                                          | 133.9      |   | $ | 110.5 |   | $ | 98.1 |   |

 

|                                                   | ** ** | **Year Ended December 31,** | ** ** |
|---------------------------------------------------|------------|--------------------------------------------|------------|
| **Average Daily Volume (MMBtu/d)** | ** ** | ** **                                 | ** ** | **2006** | ** ** | **2005** | ** ** | **2004** | ** ** |
| East Texas(1)                                     |       | 1,019,000                                  |       | 860,000 |   | 676,000 |   |
| Anadarko                                          |       | 582,000                                    |       | 488,000 |   | 357,000 |   |
| North Texas                                       |       | 294,000                                    |       | 265,000 |   | 192,000 |   |
| South Texas(1)                                    |       | —                                     |       | 33,000 |   | 40,000 |   |
| UTOS                                              |       | 181,000                                    |       | 158,000 |   | 219,000 |   |
| Midla                                             |       | 109,000                                    |       | 106,000 |   | 103,000 |   |
| AlaTenn                                           |       | 41,000                                     |       | 59,000 |   | 62,000 |   |
| KPC                                               |       | 29,000                                     |       | 31,000 |   | 48,000 |   |
| Bamagas                                           |       | 88,000                                     |       | 29,000 |   | 25,000 |   |
| Other Major  Intrastates                          |       | 158,000                                    |       | 186,000 |   | 176,000 |   |
| **Total**                                         |       | 2,501,000                                  |       | 2,215,000 |   | 1,898,000 |   |
|                                                   |            |                                            |            |  |  |  |  |  |  |

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(1)                In December 2005,we sold the South Texas assets and a sour gas system in East Texas which had acombined average daily volume of approximately 55,000 MMBtu/d.

We recognize revenue upondelivery of natural gas and NGLs to customers, when services are rendered,pricing is determinable and collectibility is reasonably assured. We deriverevenue in our Natural Gas segment from the following types of arrangements:

*Commodity-basedArrangements:*

We use several types of contractual arrangements toderive revenues for our Natural Gas segment. These arrangements expose us tocommodity price risk, which we substantially mitigate with offsetting physicalpurchases and sales and by the use of derivative financial instruments to hedgeopen positions. We 

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will continue to hedge asignificant amount of our commodity price risk to support the stability of ourcash flows. Refer to Item 7A. Quantitative and Qualitative Disclosuresabout Market Risk—Commodity Price Risk and Note 15 of our ConsolidatedFinancial Statements beginning on page F-1 of this report for moreinformation about our derivative activities.

Our commodity-basedarrangements are categorized as follows:

·       Percentage-of-IndexContracts—Under these contracts, we purchase raw natural gas at a negotiateddiscount to an agreed upon index price. We then resell the natural gas,generally for the index 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 types of contracts, we receive a negotiated percentage ofNGLs and condensate extracted from natural gas that requires processing, whichwe then sell at market prices and retain as our fee. This contract structure issimilar 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 atmarket prices, the resulting residue gas. In those instances when we gather andprocess raw natural gas for the account of the producer, we must return to theproducer residue gas with an energy content equivalent to the original rawnatural gas we received as measured in British thermal units, or Btu.

Under the terms of some ofthese contract structures, we retain a portion of the natural gas and NGLs asour fee in exchange for providing these producers with our services. In orderto protect our unitholders from volatility in our cash flows that can resultfrom fluctuations in commodity prices, we enter into derivative financialinstruments to effectively fix the sales price of the natural gas and NGLs weanticipate 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 processednatural gas and NGLs, although the market price of these commodities willcontinue to fluctuate during that time.

*Fee-BasedArrangements:*

We also use fee-basedcontract arrangements for services provided by our natural gas assets. Under afee-based contract, we receive a set fee for gathering, treating, processingand transporting 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 our FERC-regulated natural gas pipeline systemstypically pay a reservation fee each month to reserve capacity plus a nominalcommodity charge based on actual transmission volumes.

*Year ended December 31,2006 compared with year ended December 31, 2005*

Our Natural Gas segment contributed $133.9 million ofoperating income in 2006, an increase of $23.4 million from the $110.5 millionit contributed in 2005. The increase in operating income is primarily 

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attributable to favorablecommodity prices which contributed to higher revenue generated by ourprocessing assets in excess of the cost we incur for the natural gas used inprocessing. Additionally, operating income was higher due to volume increaseson each of our three largest systems resulting from additional wellhead supplycontracts and the expansion of our transportation and processing capacity. Partiallyoffsetting the benefit provided by favorable volumes and commodity prices areexpenses we recorded in 2006 of approximately $8.3 million for NGL purchasesand transportation and fractionation charges that relate to prior years we hadnot previously recorded. Our 2006 volumes and operating results are exclusiveof the volumes and operating results associated with our December 2005sale of the South Texas assets and a sour gas system located on our East Texassystem.

Average dailyvolumes on our major natural gas systems were up approximately 13 percent in2006, compared with 2005. Increases in our volumes for 2006 are attributable toour ongoing investments to expand the capacity of our systems and services. Ourinvestments in the following projects that were completed during 2006contributed to the increase in the average daily volumes and operating resultson our major natural gas systems:

·       Thelink between our North Texas and East Texas systems became fully operationalduring the third quarter of 2006, increasing the utilization of our 500 MMcf/dEast Texas intrastate pipeline that we placed in service in June 2005;

·       Constructionof our 120 MMcf/d Henderson natural gas processing facility on our East Texassystem was completed at the end of the third quarter of 2006 and processedvolumes of approximately 100 MMcf/d;

·       Theexpansion of our existing Zybach processing facility on our Anadarko system toa capacity of 150 MMcf/d of natural gas from an initial capacity of 105 MMcf/dto meet the continuing demands resulting from rapid development in the Anadarkobasin; and

·       Acquisitionof an 80-mile pipeline in April 2006 that is complimentary to ourexisting East Texas system that provided approximately 75,000 MMBtu/d ofincremental volume.

In addition to the investments we have made to expandour volumes in the areas served by our natural gas assets, the volume andrevenue growth is also the result of additional wellhead supply contracts androbust drilling activity in the Anadarko basin, Bossier Trend and Barnett Shale.We expect increasing volumes on our major natural gas systems to result fromour continuing investments to expand the capacity of our systems.

Throughout a majority of 2006, we have experienced afavorable pricing environment with regard to our processing assets and ourkeep-whole processing. During 2006, NGL and crude oil prices remained highrelative to natural gas prices which have declined from the high prices reachedin late 2005. As a result of this favorable pricing environment, the revenuegenerated by our processing assets less the cost of natural gas used forprocessing was approximately $40 million greater than the amounts we realizedin 2005. This increase includes the contribution to operating income derivedfrom our keep-whole processing of $60.3 million for the year ended December 31,2006, in excess of the $29.0 million generated in 2005 under this contractstructure. Due to the volatility associated with commodity prices, the revenueless cost of natural gas we derive from our processing activities in futureperiods could be adversely affected if the pricing environment becomesunfavorable, which can occur if the prices for NGLs substantially decline andthe price of natural gas significantly increases. We attempt to hedge amajority of our mandatory processing to minimize the effects volatility incommodity prices can have on our processing activities.

A portion of our Natural Gas segment is exposed tocommodity price risks associated with the percentage of proceeds, percentage ofliquids, and percentage of index contracts that we negotiate with producers.Under the terms of these contracts, we retain a portion of the natural gas and NGLswe process in exchange for providing these producers with our services. Inorder to protect our unitholders from the 

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volatility in cash flowsthat can result from fluctuations in commodity prices, we enter into derivativefinancial instruments to fix the sales price of the natural gas and NGLs weanticipate receiving under the terms of these contracts. We target to haveapproximately 70 to 80 percent of our anticipated near-term exposure tocommodity prices hedged using derivative financial instruments. As a result ofentering into these derivative financial instruments, we have largely fixed theamount of cash that we will pay for natural gas and receive in the future whenwe sell the processed natural gas and NGLs, although the market price of thesecommodities will continue to fluctuate during that time. Another significantportion of the revenue we receive is derived from fees charged for gatheringand treating of natural gas volumes and other related services which are notdirectly dependent on commodity prices.

Operating income of our Natural Gas segment for theyear ended December 31, 2006 includes unrealized non-cash, mark-to-marketnet losses of $0.1 million, including $1.9 million of losses resulting fromineffectiveness of our cash flow hedges and $1.8 million of gains derived fromour derivative financial instruments that do not qualify for hedge accountingtreatment under SFAS No. 133. In 2005, our operating income was reduced by$8.1 million of unrealized, non-cash, mark-to-market net losses that weincurred, primarily from derivative financial instruments that do not qualifyfor hedge accounting treatment under SFAS No. 133. The decline in ourunrealized derivative fair value losses in 2006 is largely due to a decline inthe current and forward prices of natural gas and NGLs during 2006 from thehigh levels reached in 2005 due to hurricanes Rita and Katrina that causedsupply disruptions in the Gulf of Mexico resulting in a volatile pricingenvironment. Additionally, our unrealized derivative fair value losses in 2006are lower due to our settlement in December 2005 for $16.3 million ofnatural gas collars on 2,000 MMBtu/d of natural gas through 2011 that did notqualify for hedge accounting treatment under SFAS No. 133. The settlementof these natural gas collars reduces the quantity of derivatives outstandingthat do not qualify for hedge accounting treatment in our Natural Gas segment,effectively reducing the unrealized mark-to-market adjustments resulting fromthese derivatives in periods following settlement (refer also to Item 7A.Quantitative and Qualitative Disclosures about Market Risk—Commodity Price Riskand Note 15 of our Consolidated Financial Statements beginning on page F-1of this report for more information about our derivative activities).

Operating and administrative costs of our Natural Gassegment were $215.4 million, or 23 percent, greater for 2006 than 2005,primarily as a result of increased workforce related costs, maintenanceactivities and other costs that are mostly variable with volumes. Workforcerelated costs have increased due to the additional resources and relatedbenefit costs we are charged for the operational, administrative, regulatoryand compliance support necessary for our existing assets and the expansion ofour natural gas operations. Our general partner charges us the costs associatedwith employees and related benefits forpersonnel that are assigned to us or otherwise provide us with managerial andadministrative services. The portion of compensation and related costs we arecharged is dependent upon such items as estimated time spent, miles of pipe andheadcount. In addition we have experienced an increase in outside contractlabor cost, given the high demand and competitive rates within our industry asa result of continuous pipeline expansions across the areas we serve. Weanticipate that our workforce related costs will continue to increase as weexpand our natural gas operations.

The increase in our Materials, supplies and othercosts along with our Repair and maintenance costs are predominantly related tothe increase in volumes and expansion of our natural gas systems. Materials,supplies and other costs include chemicals used in our processing activities,materials purchased for repair and maintenance purposes, utility costs to runour plants, pumps and other similar costs that are mostly variable with volumes.These costs were partially offset by the sale of our South Texas assets and asour gas system located on our East Texas system in December 2005, whichcontributed to the decrease in Materials, supplies and other costs comparedwith 2005. Repair and maintenance costs include compressor maintenance,downtime for routine and unscheduled maintenance, pipeline integrity costs andother similar items that have increased with the expansion of our existingnatural gas systems. During 2006, we 

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spent approximately $10.1million, the majority of which was in the fourth quarter of 2006, on pipelineintegrity work in connection with our ongoing pipeline integrity managementprogram in order to comply with regulatory guidance and maintain our existingpipeline integrity standards. We anticipate these costs will continue toincrease as we expand our systems and increase the volumes of natural gasservices we provide.

Our other operating and administrative costs includerents and leases which primarily relate to compressor rentals, property taxesand other costs. These additional operating and administrative costs tend tovary in relation to the natural gas volumes moving on our systems or inrelation to the expansion of our natural gas operations. We anticipate thesecosts will continue to increase as the volumes on our systems increase and weexpand our systems.

We expect our operating and administrative costs willcontinue to increase in future periods as greater volumes of natural gas flowthrough our systems and we continue to expand our natural gas operations.

Ourdepreciation and amortization expense for the year 2006 exceeded the amountreported for 2005 by approximately $4.3 million, primarily as a resultof capital projects completed and placed in-service during 2006 and projectscompleted in 2005 that were only depreciated for a partial year. The increasein depreciation expense was partially offset by modest extensions of thedepreciable lives of our major natural gas systems based on a third-party studycommissioned by management that was completed in the third quarter of 2005. Asa result of this study,  reviseddepreciation rates for the Anadarko, North Texas and East Texas systems wereimplemented effective August 1, 2005. The annual composite rate, whichrepresents the expected remaining service life of these natural gas systems,was reduced from 4.0% to 3.4%. As a result, our depreciation expense was approximately $3.5 million and $2.5million lower for the yearsended December 31, 2006 and 2005, respectively, than if these rates hadnot been reduced. Additionally, we revised our depreciation rates for a portionof our FERC-regulated natural gas assets effective July 1, 2006, toreflect a decrease in the remaining service life of these natural gas assets. Depreciationexpense was approximately $1.3 million higher for the year ended December 31,2006, as a result of this decrease in the expected remaining service life ofthese assets.

*Year ended December 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. Increased drilling by producers contributed toaverage daily volume increases of 17 percent in 2005 on our major natural gassystems compared with 2004. The increase in volumes is primarily the result ofadditional wellhead supply contracts on our East Texas and Anadarko systems, aswell as the additional volumes on the North Texas 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 inproduction volumes expected to result from the continuing increase in drillingactivities in 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 

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reduces the fair marketvalue of these derivative financial instruments because the fixed pricecomponent of these derivatives is significantly less than the market price ofnatural 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 in December 2005,when we divested non-strategic assets located within our East and South Texassystems. We sold for $105.4 million in cash, a processing plant and relatedfacilities, and other gathering and processing assets with a carrying value ofapproximately $86.9 million. We incurred selling costs of approximately $0.4million. In connection with this sale, we paid approximately $16.3 million tosettle natural gas hedges associated with the natural gas produced by theseassets. We had previously recorded unrealized losses associated with thenatural gas hedges that were realized upon settlement.

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 unusually low.During 2005, although natural gas prices were unusually high, they were morethan offset by favorable NGL prices. Operating revenue less cost of natural gasderived from keep-whole processing for the year 2005 was approximately $29.0million compared with $17.2 million in 2004.

Operating and administrative costs of our Natural Gassegment were $175.0 million, or 27 percent greater for 2005 than 2004,primarily as a result of increased workforce related costs and costs that arevariable with volumes. Workforce related costs increased $11.8 million dueto higher pension, medical and other benefits, as well as additionaladministrative, regulatory and compliance support. Costs that are incrementalwith volumes, such as chemicals, materials and supplies and direct workforceexpenses increased by $10.5 million. Additionally, the natural gasgathering and processing assets we acquired in January 2005 contributed tothe cost increases of approximately $7.2 million. As well, our maintenancecosts increased by approximately $4.9 million in 2005 due to severalprocessing plants that underwent major repairs, one of which was included withthe recently divested assets.

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 effective August 1, 2005.The annual composite rate, which represents the expected remaining service lifeof these natural gas systems, was reduced from 4.0% to 3.4%. Depreciationexpense for the year ended December 31, 2005 was approximately $2.5 millionlower as a result of the new depreciation rates.

*Future Prospectsfor Natural Gas*

Our natural gas assets are located in the Gulf Coastand Mid-continent regions of the United States, two of the premier natural gasproducing areas. As a result, there are many opportunities to connect newnatural gas supplies either by installing new facilities or acquiring adjacentthird-party gathering operations. Consolidation with neighboringfacilities will extract efficiencies by eliminating costs, for example, by combiningredundant facilities, increasing volume, and increasing processing margins.These opportunities tend to involve modest amounts of capital with attractiverates of return.

Although we continue to assess various acquisition andexpansion opportunities to pursue our strategy for growth, the market foracquiring energy transportation assets continues to remain active andsignificant competition persists among prospective acquirers of assets. Whilewe remain committed to making accretive acquisitions in or near areas where wealready operate or have a competitive advantage, we will 

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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 any non-strategic natural gasassets as conditions warrant.

Results of our natural gas gathering and processingbusiness depend upon the drilling activities of natural gas producers in theareas we serve. During 2006, increased drilling in the areas where ourgathering systems are located has generally contributed to our volume growth.We expect the growth trend in these areas to continue in the future asevidenced by third-party reserve studies and the increase in rig counts in theareas served by our systems. Continuing advances in seismic and drillingcompletion technology, along with robust energy prices, have been key driversfor the higher drilling activity levels in such areas as the tight gas and gas shalelocations of the Mid-Continent and East Texas. Other advances in drillingtechnology are enabling producers to more economically extract natural gas fromwells and increase well productivity.

One of the prominent areas in which this is occurringis the Barnett Shale play in North Texas. The Barnett Shale is a prominentnatural gas formation within the Fort Worth Basin, and it is being activelydeveloped. The formation production has risen from approximately 110 MMcf/d toover 1,800 MMcf/d since 1999, with the drilling of over 5,200 wells. Weanticipate that throughput on the North Texas system will increase modestly ineach of the next several years as a result of Barnett Shale development. Toaccommodate anticipated growth in the region we have commenced construction oftwo new gas processing plants totaling approximately 75 MMcf/d of capacity andrelated upstream facilities. These facilities are expected to becomeoperational in the second and fourth quarters of 2007.

Our Anadarko system continues to experienceconsiderable growth as a result of the rapid development of the Granite Washplay in Hemphill and Wheeler counties in Texas. We are continuing to makeprogress in increasing processing capacity and field compression in the regionfrom 230 MMcf/d at December 31, 2005 to approximately 440 MMcf/d toaccommodate the volume growth. We have added approximately 70 MMcf/d ofprocessing capacity during 2006 and expect to place 155 MMcf/d of additionalprocessing capacity as well as field compression in service during 2007.

Producer drillingplans in regional plays, in the areas served by our gas assets, are expected toresult in continued production growth. To accommodate this further growth weinitiated construction on several projects during 2006 to increase ourgathering and treating infrastructure and market access capability. Theseprojects continue to progress according to schedule and include:

·       Ourexpansion and extension of our East Texas natural gas system includesconstruction of a 36-inch diameter intrastate pipeline from Bethel, Texasto Orange County, Texas with capacity of approximately 700 MMcf/d. We expect tocomplete this project in stages throughout 2007. The new pipeline will provideservice to a number of major industrial companies in Southeast Texas and willcross a number of interstate pipelines. We continue to secure additionalcommitments for capacity on the pipeline. We currently anticipate the expansionproject will cost approximately $610 million.

·       Aspart of our East Texas expansion project we are adding a 200 MMcf/d treatingfacility to be built near Marquez, Texas which will be connected to the 36-inchdiameter intrastate pipeline via a new 24-inch diameter pipeline. Weexpect the plant to be completed and operating in the first quarter of 2007.

·       Expansionof our sour gas treating capacity on the East Texas system will increase thetotal sulfur capacity in the first half of 2007 from 72.5 tons per day (tpd) to125 tpd by early 2008, in order to handle additional sour gas supply and higherconcentration levels of hydrogen sulfide (H2S).

·       Installationof additional processing plants to enable the East Texas system to meet theincreasingly more stringent pipeline gas quality specifications by late 2007.

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·       Theinstallation of two processing plants to expand the processing capability ofour North Texas system, with processing capacities of 35 MMcf/d and 40 MMcf/d,to be fully operational in early 2007.

When fully operational inlate 2007, the new assets we are constructing will provide additional sourcesof stable cash flow for us. We continue toevaluate other projects that could further integrate our major Texas-centeredpipeline systems.

Anumber of new interstate natural gas transportation pipelines are beingconstructed that may alter the landscape for interstate transportation ofnatural gas. Although a majority of our Natural Gas segment revenues arederived from the gathering, processing and intrastate transportation of naturalgas, these newly constructed pipelines could affect the operating results ofour existing market-based interstate and intrastate natural gas pipelines.Conversely, our supply based gathering systems may benefit from enhancedcapacity out of our gathering areas.

*Other Matters*

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 Bamagassystem, 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 its powerplants. Our Bamagas system is the sole supplier of natural gas to these twoutility plants, and we expect the subsidiary that owns these utility plants tocontinue performing under the terms of our agreement. Due to the recent natureof the bankruptcy filing, we are unable to determine the extent of any lossesto which we may be subject as a result of the bankruptcy. In April 2006,Calpine announced its intent to sell approximately 20 of its non-core andnon-strategic power plants, although all of the plants to be sold have not beenannounced. Calpine has continued to perform under the terms of its agreementwith Bamagas and we remain confident that any losses we may incur with respectto Calpine’s bankruptcy will be minimal. We continue to monitor the Calpinebankruptcy proceedings and will recognize any losses that may result when itbecomes 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,** | ** ** |
|--------------------------------|------------|--------------------------------------------|------------|
| ** **                     | ** ** | **2006**                                   | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                     | ** ** | **(dollars in millions)**        | ** ** |
| Operating  revenues            |       | $                                          | 2,975.5    |   | $ | 3,706.8 |   | $ | 2,562.5 |   |
| Cost of natural  gas           |       | 2,913.5                                    |       | 3,744.6 |   | 2,555.3 |   |
| Operating and  administrative  |       | 5.4                                        |       | 4.1 |   | 3.4 |   |
| Depreciation and  amortization |       | 0.5                                        |       | 0.5 |   | 0.2 |   |
| Expenses                       |       | 2,919.4                                    |       | 3,749.2 |   | 2,558.9 |   |
| **Operating income (loss)**    |       | $                                          | 56.1       |   | $ | (42.4 | ) | $ | 3.6 |   |

 

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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-partystorage facilities and pipelines for the right to store and transport naturalgas for various periods of time. These contracts may be denoted as firmstorage, interruptible storage, or parking and lending services. These variouscontract structures are used to mitigate risk associated with sales andpurchase contracts, and to take advantage of price differential opportunities.

*Year ended December 31,2006 compared with year ended December 31, 2005*

A majority of the operating income of our Marketingsegment is derived from selling natural gas received from producers on ourNatural Gas segment pipeline assets to end users of the natural gas. A majorityof the natural gas we purchase is produced in Texas markets where we havelimited physical access to the primary interstate pipeline delivery points, orhubs such as Waha, Texas and the Houston Ship Channel. As a result, ourMarketing business must use third-party pipelines to transport the natural gasto these markets where it can be sold to our customers. However, physicalpipeline constraints often require our Marketing business to transport naturalgas to alternate market points. Under these circumstances, our Marketingsegment will sell the purchased gas at a pricing index that is different fromthe pricing index at which the gas was purchased. This creates a price exposurethat arises from the relative difference in natural gas prices between the contractedindex at which the natural gas is purchased and the index under which it issold, otherwise known as the “spread.” The spread can vary significantly due tolocal supply and demand factors. Wherever possible, this pricing exposure iseconomically hedged using derivative financial instruments. However, thestructure of these economic hedges often precludes our use of hedge accountingunder the requirements of SFAS No. 133, which can create volatility in theoperating 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. To offset the demand charges associatedwith these firm transportation contracts, we look for market conditions thatallow us to lock in the price differential or spread between the pipelinereceipt point and pipeline delivery point. This allows our Marketing businessto lock in a fixed sales margin inclusive of pipeline demand charges. Weaccomplish this by transacting basis swaps between the index where the naturalgas is purchased and the index where the natural gas is sold. By transacting abasis swap between those two indices, we can effectively lock in a margin onthe combined natural gas purchase and the natural gas sale, mitigating thedemand charges on firm transportation agreements and limiting the Partnership’sexposure 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 with balancing natural gas supply and end use marketsales. In order to mitigate the absolute price differential between the cost ofinjected natural gas and withdrawn natural gas, as well as storage fees, theinjection and withdrawal price differential, or “spread,” is hedged by buyingfixed price swaps for the forecasted injection periods and selling fixed priceswaps for the forecasted withdrawal periods. When the injection and withdrawalspread increases or decreases in value as a result of market price movements,we can earn additional profit through the optimization of those hedges in boththe forward and daily markets. Although all 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 

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accounted for on a mark-to-marketbasis, and the periodic change in their market value, although non-cash, willimpact the income statement.

For the year ended December 31, 2006, theoperating income of our Marketing segment increased $98.5 million to$56.1 million, from a loss of $42.4 million in 2005. The significantincrease in the operating income of our Marketing segment for 2006 is primarilydue to unrealized, non-cash, mark-to-market net gains of approximately $64.5million compared with unrealized mark-to-market net losses of $50.3 million for2005. These unrealized mark-to-market changes are associated with derivativefinancial instruments that do not qualify for hedge accounting treatment underSFAS No. 133. The unrealized, mark-to-market gains for 2006 are the resultof a decline in the forward and daily market price of natural gas from thehistorically high prices experienced in 2005. Additionally, the basis betweenthe index where the natural gas is purchased and the index where the naturalgas is sold has declined in correlation with the decline in the forward marketprice of natural gas contributing to the unrealized, mark-to-market net gains for2006.

The operating results ofour Marketing segment for the year ended December 31, 2006, also includenon-cash charges totaling $17.0 million attributable to reducing the cost basisof our natural gas inventory to fair market value. Natural gas prices aspublished by Platt’s *Gas Daily* forHenry Hub were approximately $10.08 per MMBtu at December 31, 2005, whichhad declined to $5.64 per MMBtu at December 31, 2006. As a result of thedecline in the price of natural gas from 2005 to 2006, we recorded chargestotaling $17.0 million during 2006 to reduce the cost basis of our inventory tofair market value. Partially offsetting this charge are gains of approximately$3 million that we realized upon settlement ofderivative financial instruments hedging our natural gas inventory for 2006. Dueto our hedging structures, we expect that a majority of the lower of cost ormarket inventory charges will be offset by future financial and physicaltransactions that will settle at the time the natural gas inventory is sold.

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

For the year ended December 31, 2005, ourMarketing segment incurred losses of $42.4 million, which include non-cashmark-to-market losses of $48.2 million, compared with earning $3.6 millionof operating income for 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” shift. We expect these net mark-to-market lossesto be predominantly offset when the related physical transactions are settled(refer also to the discussion included in Item 7A. Quantitative andQualitative Disclosures About Market Risk and Note 15 of our ConsolidatedFinancial Statements beginning on page F-1 of this report).

During the third andfourth quarters of 2005, disruptions of natural gas supplies from facilities inthe Gulf of Mexico region caused by hurricanes Katrina and Rita created greaterdemand for natural gas production from our onshore Natural Gas segment pipelineassets, increasing our ability to optimize natural gas supply to areas ofstrongest demand. As a result of the hurricanes, unusual volatility in theprices of natural gas created greater spreads on our natural gas volumes.

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**Corporate**

*Year ended December 31,2006 compared with year ended December 31, 2005*

Interest expense was $110.5 million in 2006 comparedwith $107.7 million in 2005. The increase is the result of higher debtbalances and weighted average interest rates, partially offset by approximately$10.7 million of interest capitalized on our construction projects for 2006compared with $4.0 million capitalized in 2005. Our weighted average interestrate was approximately 5.82% for the year ended December 31, 2006,compared with approximately 5.78% during 2005. Our debt balances are higher at December 31,2006 compared with December 31, 2005 as a result of the capitalexpenditures we have made to expand our existing systems to improve the servicecapabilities of our assets.

Included in other income for the year ended December 31,2006, is approximately $4.5 million that we received as settlement for aninsurance claim that we filed in connection with an interruption to the operationsof our Lakehead system resulting from a fire that occurred at Suncor’s upgradersite in January 2005.

The Partnership is not ataxable entity for U.S. federal income tax purposes and historically has notbeen a taxable entity for state income tax purposes. Federal and state incometaxes on partnership taxable income were both borne directly by the unitholderswith no entity level tax on the Partnership. In May 2006, the State ofTexas enacted substantial changes to its tax structure beginning in 2007 byimposing a new tax based upon modified gross revenue.   We determined that this tax is an income taxas defined under Statement of Financial Accounting Standards No. 109, *Accounting for Income Taxes*(“SFAS No. 109”). Ourinitial accounting for the enactment of this income tax did not materiallyaffect our results of operation, financial condition or cash flows. Although weanticipate Texas will make further changes to this tax in 2007 that may impactour income tax expense, our 2007 income tax expense will be approximately $5million.

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

Interestexpense was $107.7 million in 2005 compared with $88.4 million in2004. The increase is 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.

**LIQUIDITY ANDCAPITAL RESOURCES**

***General***

We believe that ourability to generate cash flow, in addition to our access to capital, issufficient to meet the demands of our current and future operating andinvestment needs. Our primary cash requirements consist of normal operatingexpenses, capital expenditures for our expansion projects, maintenance capital expenditures,debt service payments, distributions to our partners, acquisitions of newassets and businesses, and payments associated with our derivativetransactions. Short-term cash requirements, such as operating expenses,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 our commercial paper program, our Credit Facility,and the issuance of additional equity and debt securities. Our ability tocomplete future debt and equity offerings and the timing of any such offeringswill depend 

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onvarious factors, including prevailing market conditions, interest rates, ourfinancial condition and credit rating at the time.

Our current businessstrategy emphasizes developing and expanding our existing Liquids and NaturalGas businesses with less focus on acquisitions. The internal growth projects wehave planned for our Natural Gas business (see Natural Gas segment—FutureProspects), coupled with the Southern Access and Alberta Clipper projects onour 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. During our construction of these majorprojects, our ability to increase distributions while funding theseconstruction costs is likely to be limited.

***Capital Resources***

**Equity Capital**

Execution of our growthstrategy and completion of our planned construction projects contemplate ouraccessing the public and private equity markets to obtain the capital necessaryto fund these projects. During 2006, we raised net proceeds of approximately$500.0 million of equity in a private transaction for the sale of approximately10.8 million of our Class C units, representing a new class of our limitedpartner interests. We sold the Class C units in equal amounts ofapproximately 5.4 million units each to our general partner and aninstitutional investor. Additionally, our general partner contributedapproximately $10 million to maintain its two percent general partner interest.We used the proceeds from this issuance partially to reduce borrowingsoutstanding under our commercial paper program and to fund a portion of ourcapital expansion projects. We invested the remaining amount in short-termcommercial paper for use in future periods to further reduce our commercialpaper borrowings or fund additional expenditures under our capital expansionprojects.

Thefollowing table presents historical information about our public equityofferings since January 2004:

| **Issuance Date**                                       | ** ** | ** **                                                                 | ** ** | **Number of  Class A  common units  Issue** | ** ** | **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)** | ** ** |
| **2006**                                                     | ** ** |                                                                       | ** ** | ** **                                                 |       |                                                             | ** ** | ** **                                             |       |                                  | ** ** | ** **                                                       |       |   | ** ** | ** ** |   |   | ** ** | ** ** |   |
| We did not issue  any Class A common units during 2006. | ** ** |                                                                       |
| **2005**                                                     | ** ** |                                                                       | ** ** | ** **                                                 |       |                                                             | ** ** | ** **                                             |       |                                  | ** ** | ** **                                                       |       |   | ** ** | ** ** |   |   | ** ** | ** ** |   |
| December                                                     |       |                                                                       | 136,200    | ** **                                                 |       |                                                             | $          | 46.000                                                 | ** ** |                                  |       | $                                                                | 6.0        | ** ** |   |   | $ | 0.2 | ** ** |   |   | $ | 6.2 | ** ** |   |
| November                                                     |       |                                                                       | 3,000,000  | ** **                                                 |       |                                                             | $          | 46.000                                                 | ** ** |                                  |       | 132.1                                                            | ** ** |   |   | 2.8 | ** ** |   |   | 134.9 | ** ** |   |
| February                                                     |       |                                                                       | 2,506,500  | ** **                                                 |       |                                                             | $          | 49.875                                                 | ** ** |                                  |       | 124.8                                                            | ** ** |   |   | 2.7 | ** ** |   |   | 127.5 | ** ** |   |
| **2005  Totals**                                             |       |                                                                       | 5,642,700  | ** **                                                 |       |                                                             |       | ** **                                             |       |                                  | $          | 262.9                                                            | ** ** |   |   | $ | 5.7 | ** ** |   |   | $ | 268.6 | ** ** |   |
| **2004**                                                     | ** ** |                                                                       | ** ** | ** **                                                 |       |                                                             | ** ** | ** **                                             |       |                                  | ** ** | ** **                                                       |       |   | ** ** | ** ** |   |   | ** ** | ** ** |   |
| September                                                    |       |                                                                       | 3,680,000  | ** **                                                 |       |                                                             | $          | 47.900                                                 | ** ** |                                  |       | $                                                                | 168.6      | ** ** |   |   | $ | 3.6 | ** ** |   |   | $ | 172.2 | ** ** |   |
| January                                                      |       |                                                                       | 450,000    | ** **                                                 |       |                                                             | $          | 50.300                                                 | ** ** |                                  |       | 21.6                                                             | ** ** |   |   | 0.4 | ** ** |   |   | 22.0 | ** ** |   |
| **2004 Totals**                                              |       |                                                                       | 4,130,000  | ** **                                                 |       |                                                             |       | ** **                                             |       |                                  | $          | 190.2                                                            | ** ** |   |   | $ | 4.0 | ** ** |   |   | $ | 194.2 | ** ** |   |

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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.

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**Available Credit**

A significant source of our liquidity is provided bythe commercial paper market. We have a $600 million commercial paper programthat is supported by our long-term Credit Facility, which we access primarilyto provide temporary financing for our operating activities, capitalexpenditures and acquisitions, at rates that are generally lower than the ratesavailable under our Credit Facility. Under the terms of our commercial paperprogram, we may issue up to $600 million of commercial paper. At December 31,2006, we had $445 million in principal amount of commercial paper outstandingand could issue an additional $155 million in principal amount of commercial paper.

Our Credit Facility alsoprovides us with another significant source of liquidity. In March 2006,we obtained an increase from $800 million to $1 billion in the aggregatecommitment available to us under the terms of our Credit Facility. The amountswe may borrow under the terms of our Credit Facility are reduced by theprincipal amount of our commercial paper issuances and the balance of ourletters of credit outstanding. At December 31, 2006, we had no amountsoutstanding under our Credit Facility and letters of credit totaling $59.3million. We could borrow $495.7 million under the terms of our CreditFacility at December 31, 2006, after reducing the $1 billion commitmentamount by outstanding letters of credit and the principal balance of commercialpaper we have outstanding. We expect to extend the capacity of our CreditFacility to approximately $1.25 to $1.5 billion in the near term, subject tothe approval of the lenders that are party to our Credit Facility. At December 31,2006, our Credit Facility remains undrawn and available to support ourcommercial paper program and meet our short-term liquidity needs.

**Indebtedness andOther Payment Obligations**

Thefollowing table presents the components of our outstanding indebtedness:

| ** **                              | ** ** | **December 31,**  | ** ** |
|-----------------------------------------|------------|------------------------|------------|
| ** **                              | ** ** | **2006**               | ** ** | **2005** | ** ** |
| ** **                              | ** ** | **(in millions)** | ** ** |
| Current  maturities of long-term debt:  |       |                   |       |   |   |
| Current portion of First Mortgage Notes |       | $                      | 31.0       |   | $ | 31.0 |   |
| Loans from affiliates                   |       | $                      | 136.2      |   | $ | — |   |
| Long-term debt:                         |       |                   |       |   |   |
| Commercial Paper                        |       | $                      | 443.7      |   | $ | 329.3 |   |
| Credit Facility                         |       | —                 |       | — |   |
| First Mortgage Notes                    |       | 124.0                  |       | 155.0 |   |
| 4.000% senior notes due 2009            |       | 200.0                  |       | 200.0 |   |
| 7.900% senior notes due 2012(1)         |       | 100.0                  |       | 100.0 |   |
| 4.750% senior notes due 2013            |       | 200.0                  |       | 200.0 |   |
| 5.350% senior notes due 2014            |       | 200.0                  |       | 200.0 |   |
| 5.875% senior notes due 2016            |       | 300.0                  |       | — |   |
| 7.000% senior notes due 2018(1)         |       | 100.0                  |       | 100.0 |   |
| 7.125% senior notes due 2028(1)         |       | 100.0                  |       | 100.0 |   |
| 5.950% senior notes due 2033            |       | 200.0                  |       | 200.0 |   |
| 6.300% senior notes due 2034            |       | 100.0                  |       | 100.0 |   |
| Unamortized discount                    |       | (1.6                   | )          | (1.4 | ) |
| Total long-term  debt                   |       | $                      | 2,066.1    |   | $ | 1,682.9 |   |
| Loans from affiliates                   |       | $                      | —     |   | $ | 151.8 |   |

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(1)                Debtof Enbridge Energy, Limited Partnership, one of our operating subsidiaries.

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**Commercial PaperProgram**

At December 31, 2006,we had $445 million in principal amount of commercial paper outstanding, withunamortized discount of $1.3 million, at a weighted average interest rate of5.45%, before the effect of our interest rate hedging activities. We had netborrowings of approximately $111.4 million during 2006 under our commercial paperprogram which include gross issuances of $3,145.4 million and gross repaymentsof $3,034.0 million. At December 31, 2006, we could issue anadditional $155 million in principal amount of commercial paper.

**Credit Facility**

Our Credit Facility, as amended, is a revolving termfacility that matures in April 2010. In March 2006, we obtained anincrease from $800 million to $1 billion in the aggregate commitment availableto us. The amounts we can borrow under the terms of our Credit Facility arereduced by the principal amount of our commercial paper issuances and thebalance of our letters of credit outstanding. We pay interest on the amountsoutstanding at variable rates equal to a “Base Rate” or a “Eurodollar Rate” asdefined in the Credit Facility. In the case of Eurodollar Rate loans, anadditional margin is charged which varies depending on our credit rating andthe amounts drawn under the facility. We are also charged a facility fee on theentire amount of the Credit Facility, regardless of the amount drawn, whichalso varies depending on our credit rating. During 2006, we borrowedapproximately $90 million to provide short-term financing, which we repaid thefollowing business day.

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 31,2006, our interest coverage ratio was approximately 4.4 and our leverage ratiowas approximately 4.6. 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, 2006,we had no balances outstanding under our Credit Facility and could borrow$495.7 million. Additionally, we have outstanding letters of credit totaling$59.3 million at December 31, 2006.

**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, 2006. We believe these issuance tests will not negativelyaffect our ability to access the credit markets to finance future expansionprojects. Under the First Mortgage Note Agreements, we cannot make cashdistributions more frequently than quarterly in an amount not to exceedAvailable Cash for the immediately preceding calendar quarter. If we repay theNotes prior to their stated maturities, the First Mortgage Note Agreementsprovide for the payment of a redemption premium by us.

**Senior Notes**

In December 2006, we issued $300.0 millionin aggregate principal amount of our 5.875% Senior Notes due 2016 in a publicoffering, from which we received proceeds of $297.6 million, after paymentof underwriting discounts and commissions and estimated offering expenses. Weused the proceeds to repay a portion of our outstanding commercial paper and tofinance a portion of our capital expansion projects.

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We did not issueany Senior Notes during the year ended 2005; however, during 2004 we issued thefollowing senior notes:

·       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 the debt outstanding under our 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 ofthe debt outstanding under our bank Credit Facility.

Enbridge Energy, Limited Partnership, our operatingsubsidiary that owns the Lakehead system, has $300 million of senior notes, the(“the OLP Notes”) outstanding representing unsecured obligations that arestructurally senior to our Senior Notes. All of the OLP Notes pay interestsemi-annually and have varying maturities and terms as set forth in the tableabove. The OLP Notes do not contain any covenants restricting us from issuingadditional indebtedness. The OLP Notes are subject to make-whole redemptionrights and were issued under an indenture (“the OLP 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, except in accordance with the OLP Indenture. We were in compliance withthese covenants at December 31, 2006.

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 structurally subordinated to all existing and futureindebtedness and other liabilities, including trade payables of our subsidiariesand the $300 million of OLP Notes issued by Enbridge Energy, LimitedPartnership. The borrowings under our Senior Notes are non-recourse to our generalpartner and Enbridge Management. All of our Senior Notes pay interest semi-annuallyand have varying maturities and terms as presented in the table above. OurSenior Notes do not contain any covenants restricting us from issuingadditional indebtedness. Our Senior Notes are subject to make-whole redemptionrights and were issued under an indenture containing certain covenants thatrestrict our ability, with certain exceptions, to sell, convey, transfer, leaseor otherwise dispose of all or substantially all of our assets, except inaccordance with our indenture agreement. We were in compliance with thesecovenants at December 31, 2006.

**Loans from GeneralPartner and affiliates**

As of December 31,2006 and 2005, we had $136.2 million and $151.8 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 inDecember 2007 and has cross-default provisions that are triggered byevents of default under our First Mortgage Notes or defaults under our CreditFacility. The note is subordinate to our Credit Facility and other seniorindebtedness. For the years ended December 31, 2006 and 2005, we convertedinterest payable related to this note in the amount of $4.4 million and$9.7 million, respectively, into debt by increasing the principal balanceof this note. Additionally, in 2006 we repaid approximately $20.0 million inprincipal amount of this note.

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**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, 2006:
|                                                    | ** ** | **Standard &  Poor’s** | ** ** | **Moody’s** | ** ** | **Dominion Bond  Rating Service** | ** ** |
|----------------------------------------------------|------------|--------------------------------------|------------|------------------|------------|---------------------------------------------|------------|
| **Enbridge Energy Partners, L.P.**                 |       |                                 |       |             |       |                                        |       |   |   |   |   |
| Outlook                                            |       |                                 | Stable     |             |       | Negative                                    |       |   | Stable |   |   |
| Corporate                                          |       |                                 | BBB        |             |       | Baa2                                        |       |   | BBB |   |   |
| Commercial Paper                                   |       |                                 | A-2        |             |       | P-2                                         |       |   | R-2M |   |   |
| Medium Term  Notes & Unsecured Debentures |       |                                 | BBB        |             |       | Baa2                                        |       |   | BBB |   |   |
| **Enbridge Energy, Limited  Partnership**          |       |                                 |       |             |       |                                        |       |   |   |   |   |
| Outlook                                            |       |                                 | Stable     |             |       | Negative                                    |       |   | N/A |   |   |
| Senior secured                                     |       |                                 | BBB+       |             |       | Baa1                                        |       |   | NR |   |   |
| Senior unsecured                                   |       |                                 | BBB        |             |       | Baa1                                        |       |   | NR |   |   |

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NR—No   rating is available

Moody’s recently affirmedour Baa2 rating but revised its outlook to negative. This reflects Moody’s viewthat our financial profile is weaker than those of our similarly rated peers. However,Moody’s believes that this weaker financial profile is offset to a degree byour low business risk profile that stems from our highly regulated and/orcontracted liquids and natural gas systems and our strategy of hedging asignificant portion of our commodity exposure. While our substantial organicgrowth capital expenditure program will place our financial profile under nearterm pressure until these projects are commissioned and increase our relianceon the capital markets, Moody’s believes that completion of our organic growthprojects should contribute to a further reduction in our overall business riskprofile and that the cash flow generated by these projects as they arecommissioned will strengthen our financial profile. Following the successfulexecution of both the construction and financing of these growth projects overthe next 18 to 24 months, an improved rating outlook by Moody’s is possible.

**Summary ofObligations and Commitments**

Thefollowing table summarizes the principal amount of our obligations andcommitments at December 31, 2006:
| Future Minimum Commitments                          | ** ** | ** **             | ** ** | **2007** | ** ** | **2008** | ** ** | **2009** | ** ** | **2010** | ** ** | **2011** | ** ** | **Thereafter** | ** ** | **Total** | ** ** |
|---------------------------------------------------------------|------------|------------------------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------------|------------|-----------|------------|
| ** **                                                    | ** ** | **(in millions)** | ** ** |
| Long-term debt  and Loans from General Partner and affiliates |       | $                      | 167.2      |     | $          | 31.0     |       | $        | 231.0      |     | $          | 476.0    |       | $              | 31.0       |      |       | $ | 1,300.0 |   |   | $ | 2,236.2 |   |
| Purchase  commitments(1)                                      |       | 451.8                  |       | —   |       | —   |       | —   |       | —   |       |     | —     |           |       | 451.8     |       |
| Power commitments(2)                                          |       | 3.2                    |       | —   |       | —   |       | —   |       | —   |       |     | —     |           |       | 3.2       |       |
| Other operating  leases                                       |       | 10.8                   |       | 9.1      |       | 6.9      |       | 1.9      |       | 0.1      |       |     | —     |           |       | 28.8      |       |
| Right-of-way(3)                                               |       | 1.7                    |       | 1.7      |       | 1.7      |       | 1.7      |       | 1.7      |       |     | 42.4       |           |       | 50.9      |       |
| Product purchase   obligations(4)                             |       | 32.1                   |       | 34.0     |       | 31.5     |       | 27.6     |       | 24.6     |       |     | 83.4       |           |       | 233.2     |       |
| Service contract   obligations(5)                             |       | 16.4                   |       | 15.6     |       | 12.5     |       | 8.3      |       | 6.2      |       |     | 1.8        |           |       | 60.8      |       |
| Total                                                         |       | $                      | 683.2      |     | $          | 91.4     |       | $        | 283.6      |     | $          | 515.5    |       | $              | 63.6       |      |       | $ | 1,427.6 |   |   | $ | 3,064.9 |   |

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(1)                Representscommitments to purchase materials, primarily pipe from third-party suppliers inconnection with our expansion projects.

(2)                Representscommitments to purchase power in connection with our Liquids segment.

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(3)                Right-of-waypayments are estimated to be approximately $1.7 million per year for theremaining life of all pipeline systems, which has been assumed to be25 years for purposes of calculating the amount of future minimumcommitments beyond 2011.

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

(5)                Theservice contract obligations represent the minimum payment amounts for firmtransportation and storage capacity we have reserved on third-partypipelines and storage facilities.

***Cash Requirements for Future Growth***

**Capital Spending**

We expect to make significantexpenditures during the next three years for the construction of additionalnatural gas and crude oil transportation infrastructure. Extensive volumegrowth in the areas served by our East Texas system and the resultingconstraints in reaching primary market locations necessitates the constructionof additional pipeline capacity to transport these volumes to alternate naturalgas markets. Anticipated growth in Western Canadian oil sands production andthe need to reach newer markets has prompted the Southern Access, AlbertaClipper and related projects associated with our liquid systems. In 2007, weexpect to spend approximately $1.5 billion on these and other projects with theexpectation of realizing additional cash flows as projects are completed andplaced in service. At December 31, 2006, we had approximately $451.8million in outstanding purchase commitments attributable to capital projectsfor the construction of assets that will be recorded as property, plant andequipment during 2007.

*ForecastedExpenditures*

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 expendituresinclude our capital expansion projects and other projects that improve theservice capability of our existing assets, extend asset useful lives, increasecapacities from existing levels, reduce costs or enhance revenues, and enableus to respond to governmental regulations and developing industry standards.

Weestimate our forecasted expenditures based upon our strategic operating andgrowth plans, which are also dependent upon our ability to produce or otherwiseobtain the capital necessary to accomplish our growth objectives. The followingtable sets forth our estimates of capital required for system enhancement andcore maintenance expenditures through December 31, 2007. Although weanticipate making the expenditures in 2007, these estimates may change due tofactors beyond our control, including weather-related issues, constructiontiming, changes in supplier prices or poor economic conditions. Additionally,our estimates may also change as a result of decisions made at a later date torevise the scope of a project. We anticipate our capital expenditures toapproximate the following in millions:
|                                               | ** ** | **Total  Forecasted  Expenditures** | ** ** |
|-----------------------------------------------|------------|-------------------------------------|------------|
| Other system  enhancements                    |       |                                | $          | 540 |   |   |
| Core maintenance  activities                  |       |                                | 60         |   |   |
| Southern Access  expansion                    |       |                                | 735        |   |   |
| East Texas expansion and  extension (Clarity) |       |                                | 230        |   |   |
|                                          |       |                                | $          | 1,565 |   |   |

 

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*Major ConstructionProjects*

Thefollowing table includes our active major construction projects and additionalinformation regarding our projected cost, actual expenditures through December 31,2006, the incremental capacity that will become available upon completion ofthe project and the periods we expect to complete the construction. Theprojected amounts included in this table may change due to modifications of thescope of the project, increases in materials and construction costs and otherfactors that are outside of our direct control.
|                                             | ** ** | **Capital Expenditures**  | ** ** | **Estimated Incremental Capacity**      | ** ** | ** **                         | ** ** |
|---------------------------------------------|------------|--------------------------------|------------|---------------------------------------------------|------------|------------------------------------|------------|
| ** **                                  | ** ** | **Projected  Total Cost** | ** ** | **Actual  Expenditures   through 2006** | ** ** | **Storage**                        | ** ** | **Oil** | ** ** | **Natural  Gas** | ** ** | **Expected Completion** | ** ** |
| ** **                                  | ** ** | **(in billions)**         | ** ** | **(in millions)**                            | ** ** | **  (MBbl)  ** | ** ** | **(Mbpd)** | ** ** | **  (MMcf/d)  ** | ** ** | ** ** | ** ** |
| Southern Access  expansion   (Lakehead)     |       |                           | $          | 1.3                                               |       |                               |       | $ | 110 |   |   |   | — |   |   |   | 400 |   |   |   | — |   |   | In  phases to early 2009 |   |
| Clarity (East  Texas)                       |       |                           | 0.6        |                                              |       |                               | 325        |   |   |   | — |   |   |   | — |   |   |   | 700 |   |   | In  phases to late 2007 |   |
| Alberta Clipper                             |       |                           | 0.8        |                                              |       |                               | —     |   |   |   | — |   |   |   | 450 |   |   |   | — |   |   | Late  2009 to early 2010 |   |
| North Dakota  system expansion              |       |                           | 0.1        |                                              |       |                               | 11         |   |   |   | — |   |   |   | 30 |   |   |   | — |   |   | Late  2007 |   |
| Cushing terminal  storage tanks             |       |                           | 0.1        |                                              |       |                               | 39         |   |   |   | 4,970 |   |   |   | — |   |   |   | — |   |   | various |   |
| Griffith and  Superior storage tanks        |       |                           | 0.1        |                                              |       |                               | 10         |   |   |   | 1,220 |   |   |   | — |   |   |   | — |   |   | Mid-2007  and Mid-2008 |   |
| Natural gas connects  and   compression     |       |                           | 0.1        |                                              |       |                               | 62         |   |   |   | — |   |   |   | — |   |   |   | — |   |   | Various |   |
| Processing and  treating plant   expansions |       |                           | 0.3        |                                              |       |                               | 142        |   |   |   | — |   |   |   | — |   |   |   | 1,130 |   |   | Various |   |
| Total                                       |       |                           | $          | 3.4                                               |       |                               |       | $ | 699 |   |   |   | 6,190 |   |   |   | 880 |   |   |   | 1,830 |   |   |   |   |

 

Including major expansion projects and excluding acquisitions,ongoing capital expenditures are expected to be significant over the next threeyears due to our East Texas expansion and extension, Southern Access expansionand Alberta Clipper projects. Core maintenance capital is also anticipated toincrease over that period of time due to growth in our pipeline systems andaging of infrastructure.

We anticipate funding the system enhancement capitalexpenditures temporarily through the issuance of commercial paper and borrowingunder the terms of our Credit Facility, with permanent debt and equity fundingbeing obtained when appropriate. Core maintenance expenditures are expected tobe funded by operating cash flows.

We expect to incurcontinuing annual capital and operating expenditures for pipeline integrity measuresto ensure both regulatory compliance and to maintain the overall integrity ofour pipeline systems. Expenditure levels have continued to increase aspipelines age and require higher levels of inspection or maintenance; however,these are viewed to be consistent with industry trends.

*Acquisitions*

We will continue to assess various acquisition andexpansion opportunities to pursue our strategy for growth. However, the marketfor acquiring energy transportation assets is active and competition among prospectiveacquirers of assets has been significant. While we remain committed to makingaccretive acquisitions in or near areas where we already operate or have acompetitive advantage, we will continue to focus our efforts on development ofour existing pipeline systems. Additionally, we may pursue opportunities todivest of any non-strategic assets as conditions warrant.

We expect that the fundsneeded to achieve growth through acquisitions will be obtained throughissuances of commercial paper, borrowings under the terms of our CreditFacility, term debt and issuances of additional partnership interests.

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***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.

Thefollowing table provides summarized information about the timing and expectedsettlement amounts of our outstanding commodity derivative financialinstruments at December 31, 2006 for each of the indicated calendar years:
|                        | ** ** | **Notional**                  | ** ** | **2007**   | ** ** | **2008**   | ** ** | **2009**   | ** ** | **2010**     | ** ** | **2011**   | ** ** | **2012**   | ** ** |
|------------------------|------------|-------------------------------|------------|------------|------------|------------|------------|------------|------------|--------------|------------|------------|------------|------------|------------|
| ** **             | ** ** | **($ in millions)** | ** ** |
| **Swaps**              | ** ** | ** **                    | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** **   | ** ** | ** ** | ** ** | ** ** | ** ** |
| Natural gas(1)         |       | 301,986,269                   |       | $          | (32.4      | )          | $          | (34.0      | )          | $            | (29.2      | )          | $          | (23.0      | )          | $ | (19.5 | ) | $ | (3.9 | ) |
| NGL(2)                 |       | 8,434,778                     |       | (9.3       | )          | (5.2       | )          | —     |       | (1.5         | )          | (0.6       | )          | —     |       |
| Crude(2)               |       | 1,386,571                     |       | (8.6       | )          | (7.0       | )          | (1.9       | )          | (0.6         | )          | (0.2       | )          | —     |       |
| **Options—calls** | ** ** | ** **                    | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** **   | ** ** | ** ** | ** ** | ** ** | ** ** |
| Natural gas(1)         |       | 1,826,000                     |       | (1.0       | )          | (1.3       | )          | (1.2       | )          | (1.0         | )          | (0.9       | )          | —     |       |
| **Options—puts**  | ** ** | ** **                    | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** **   | ** ** | ** ** | ** ** | ** ** | ** ** |
| Natural gas(1)         |       | 2,890,000                     |       | 1.0        |       | —     |       | —     |       | —— |       | —     |       | —     |       |
| Totals                 |       |                          |       | $          | (50.3      | )          | $          | (47.5      | )          | $            | (32.3      | )          | $          | (26.1      | )          | $ | (21.2 | ) | $ | (3.9 | ) |

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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 by ouroperating activities was $321.6 million in 2006 compared with$267.1 million in 2005. Improved operating cash flow was primarily theresult of the operating income contributions of our processing assets and anincrease in the deliveries on our Lakehead system. The remaining changes incash from operating activities were due to changes in the operating assets andliabilities from declining natural gas prices in 2006, our payment of $10.2million to settle interest rate swaps we entered to hedge the interest on thesenior notes we issued in December 2006 and general timing differences inthe collection on and payment of our current accounts.

***Investing Activities***

We used approximately $430million more cash in our investing activities during 2006 than in 2005. Theapproximate $153 million decrease in expenditures for acquisitions from 2005was more than offset by the $520 million increase in our investments inproperty, plant and equipment during 2006. The increase in our capitalexpenditures during 2006 is directly attributable to our shift in strategy tomore organic growth projects to expand the service capability of our existingsystems. Also contributing to the increase in the cash used in our investingactivities in 2006 from 2005 are approximately $105 million of proceeds wereceived in 2005 in connection with the sale of gathering and processing assetslocated on our East and South Texas systems. The proceeds of this sale werepartially offset by our payment of $16.3 million to settle derivatives inconnection with the sale of these assets. We expect that cash flows used in ourinvesting activities will remain at high levels throughout the periods we areperforming extensive expansions to our Lakehead and East Texas systems.

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***Financing Activities***

Net cash provided by our financing activities was$640.2 million in 2006, compared with $181.5 million in 2005. In2006, we increased the level of our financing activities to obtain permanentcapital for financing our organic growth projects. In August 2006, weissued approximately 10.8 million of our Class C units to our generalpartner and an institutional investor at $46.00 per unit for proceeds of approximately$500 million. Additionally, our general partner contributed an additional $10million to maintain its two percent general partner interest. Also in December 2006,we issued $300 million in principal amount of our senior notes and receivedproceeds of approximately $297.6 million after payment of underwritingcommissions and issuance costs. Also contributing to our financing activitieswas approximately $111.4 million of net borrowings under our commercial paperprogram which include gross issuances of $3,145.4 million and gross repaymentsof $3,034.0 million. These increases in sources of cash flow fromfinancing activities are partially offset by a greater amount of distributionsto our partners resulting from more outstanding limited partner units andpayments we made on the First Mortgage Notes and on an affiliate loan.

During 2006, cashdistributions to partners increased to $227.4 million from $210.6 million in2005 due to:

·                    Anincrease in the number of units outstanding; and

·                    An increase inthe general partner incentive distributions, as a result of the increased cashdistributions to our common unitholders.

***Cash Distributions***

We make quarterly distributions to our General Partnerand the holders of our limited partner units in an amount equal to our “availablecash.” As defined in our partnership agreement, “available cash” represents forany calendar quarter, the sum of all of our cash receipts plus net reductionsto reserves less all of our cash disbursements and net changes to reserves. Weretain reserves to provide for the proper conduct of our business, to stabilizedistributions to our unitholders and the General Partner and, as necessary, tocomply with the terms of any of our agreements or obligations. EnbridgeManagement, as the delegate of the General Partner under a delegation ofcontrol agreement, computes the amount of our available cash.

Enbridge Management, as owner of our i-units, does notreceive distributions in cash. Instead, each time that we make a cashdistribution to the General Partner and the holders of our Class A and Class Bcommon 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 sum ofEnbridge Management’s shares that are then outstanding. The amount of thisincrease in i-units isdetermined by dividing the cash amount distributed per limited partner unit bythe average price of one of Enbridge Management’s listed shares on the NYSE forthe 10-trading day period immediately preceding the ex-dividend date forEnbridge Management’s shares multiplied by the number of shares outstanding onthe record date. The cash equivalent amount of the additional i-units istreated as if it had actually been distributed for purposes of determining thedistributions to be made to the General Partner.

Until August 15, 2009, in lieu of cashdistributions, the holders of our Class C units will receive quarterlydistributions of additional Class C units with a value equal to thequarterly cash distributions we pay to the holders of our Class A and Class Bcommon units, which we collectively refer to as common units. The number ofadditional Class C units we will issue is determined by dividing thequarterly cash distribution per unit we pay on our common units by the averagemarket price of a Class A common unit as listed on the New York StockExchange for the 10-trading day period immediately preceding theex-dividend date for our Class A common units multiplied by the number of Class Cunits outstanding on the 

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record date. As a result,the number of Class C units and the percentage of our total units owned byholders of the Class C units will increase automatically under theprovisions of our partnership agreement. The cash equivalent amount of theadditional Class C units is treated as if it had actually been distributedfor purposes of determining the distributions to be made to the GeneralPartner.

After August 15, 2009, the holders of our Class Cunits will receive quarterly cash distributions equal to those paid to theholders of our common units. Subject to the approval of holders of ouroutstanding units in accordance with the then-existing requirements of theprincipal national securities exchange on which the Class A common unitsare listed, the Class C units will convert into Class A common unitson a one-for-one basis. If our unitholders do not approve the conversion, theholders of our Class C units will receive quarterly cash distributionsequal to 115 percent of those paid to the holders of our common units. Prior toconversion, holders of our Class C units will not be entitled to receiveany quarterly cash distribution until the holders of our common units havereceived a minimum quarterly cash distribution of $0.59 per common unit.

For purposes of calculating the sum of alldistributions of available cash, the cash equivalent amount of the additionali-units and Class C 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 and holders ofour Class C units will not receive cash. We retain the cash for use in ouroperations to finance a portion of our capital expansion projects. During 2006,we distributed a total of 969,200 i-units through quarterly distributions toEnbridge Management, compared with 802,539 in 2005. Additionally, wedistributed a total of 200,587 Class C units to the holders of our Class Cunits. We retained $54.7 million in 2006 related to the i-unit and Class Cunit distributions, compared with $41.5 million in 2005.

We expect our annual cashdistribution rate for fiscal year 2007 to remain consistent with the declaredannual distribution per unit rate of $3.70 for the years ended December 31,2006 and 2005. 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 or issue additional commercialpaper for the purpose of paying cash distributions until the full impact ofassets being developed on operations is realized.

***Off-Balance Sheet Arrangements***

We have no significantoff-balance sheet arrangements.

***Subsequent Events***

*Distribution to Partners*

On January 26,2007, the board of directors of Enbridge Management declared a distributionpayable to our partners on February 14, 2007. The distribution was paid tounitholders of record as of February 6, 2007, of our available cashof $80.0 million at December 31, 2006,or $0.925 per limited partner unit. Of this distribution, $57.6 million was paid in cash, $11.7 million was distributed in i-unitsto our i-unitholder, $10.2 millionwas distributed in Class C units to the holders of our Class C units and $0.5 million was retained from theGeneral Partner in respect of the i-unit and Class C unitdistributions to maintain its two percent general partner interest.

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*Line 14 Leaks*

In January 2007, we detected a leak on line 14 ofour Lakehead system, near the Owen, Wisconsin pump station. We immediately shutthe pipeline down and dispatched emergency response crews to overseecontainment, cleanup and repair of the pipeline at an estimated cost of lessthan $1 million. We estimate the spill to approximate 1,500 barrels. Wecompleted excavation and repairs and returned the line to service within twodays. We have applied pressure restrictions to the line as we work with federaland state environmental and pipeline safety regulators to investigate the causeof the rupture. Such pressure restrictions are not anticipated to have amaterial impact on system throughput. We have the potential of incurringadditional expenditures to remediate any condition on the line that isdetermined to have caused the rupture.

In February 2007, acontractor undertaking work in Rusk County, Wisconsin on the Enbridge SouthernLights project punctured the adjacent Line 14 pipeline, resulting in a releaseof crude oil estimated at 3,000 barrels. As the spill was largely containedwithin the ditch used for construction, environmental impact was minimized. Impactto customers was minimized as the line was repaired and returned to service inless than two days. We are investigating this incident and will record costsassociated with the repair and cleanup as such amounts are determined.

**CRITICAL ACCOUNTINGPOLICIES AND ESTIMATES**

Our selection and application of accounting policiesis an important process that has developed as our business activities haveevolved and as new accounting pronouncements have been issued. Accountingdecisions generally involve an interpretation of existing accounting principlesand the use of judgment in applying those principles to the specificcircumstances existing in our business. We make every effort to comply with allapplicable accounting principles and believe the proper implementation andconsistent application of these principles is critical. However, not all situationswe encounter are specifically addressed in the accounting literature. In suchcases, we must use our best judgment to implement accounting policies thatclearly and accurately present the substance of these situations. We accomplishthis by analyzing similar situations and the accounting guidance governing themand consulting with experts about the appropriate interpretation andapplication of the accounting literature to these situations.

In addition to the above, certain amounts included inor affecting our consolidated financial statements and related disclosures mustbe estimated, requiring us to make certain assumptions with respect to valuesor conditions that cannot be known with certainty at the time the consolidatedfinancial statements are prepared. These estimates affect the reported amountsof assets, liabilities, revenues, expenses and related disclosures with respectto contingent assets and liabilities. The basis for our estimates is historicalexperience, consultation with experts and other sources we believe to bereliable. While we believe our estimates are appropriate, actual results canand often do differ from these estimates. Any effect on our business, financialposition, results of operations and cash flows resulting from revisions tothese estimates are recorded in the period in which the facts that give rise tothe revision become known.

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 of estimatesthat affect our consolidated financial statements. Our management has discussedthe development and selection of the critical accounting policies and estimatesrelated to the reported amounts of assets, liabilities, revenues and expensesand disclosure of contingent liabilities with the Audit, Finance &Risk Committee of Enbridge Management’s board of directors.

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***Revenue Recognition and the Estimation of Revenues andCost 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 gas andmarketing businesses, we must estimate our current month revenue and cost ofnatural gas to permit the timely preparation of our consolidated financialstatements. We generally cannot compile actual billing information nor obtainactual vendor invoices within a timeframe that would permit the recording ofthis actual data prior to preparation of the consolidated financial statements.As a result, we record an estimate each month for our operating revenues andcost of natural gas based on the best available volume and price data fornatural gas delivered and received, along with a true-up of the prior month’sestimate to equal the prior month’s actual data. As a result, there is onemonth of estimated data recorded in our operating revenues and cost of naturalgas for each period reported. We believe that the assumptions underlying theseestimates will not be significantly different from the actual amounts due tothe routine nature of these estimates and the stability of our processes.

***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 replaced, improved, or the useful lives have been extended; or (3) allland, regardless of cost. Acquisitions of new assets, additions, replacementsand improvements (other than land) costing less than the minimum rule inaddition to maintenance and 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 ofRegulation,* 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 governmental regulations anddeveloping industry standards. Examples of enhancement expenditures includecosts associated with installation of seals, liners and other equipment toreduce the risk of environmental contamination from crude oil storage tanks, costsof sleeving a major segment of the pipeline system following an integrity toolrun, natural gas or crude oil well-connects, natural gas plants and pipelineconstruction and expansion.

Regulatory guidance issued by the FERC requires us toexpense certain costs associated with implementing the pipeline integritymanagement requirements of the U.S. Department of Transportation’s Office ofPipeline Safety. Under this guidance, beginning in January 2006, costs to1) prepare a plan to implement the program, 2) identify high consequenceareas, 3) develop and maintain a record keeping system and 4) inspect, test andreport on the condition of affected pipeline segments to determine the need forrepairs or replacements, are required to be expensed. We adopted this guidanceprospectively in January 2006 for all our pipeline systems. 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 continue to becapitalized. We have historically capitalized initial in-line inspectionprograms, crackdetection tool runs and hydrostatic testing costs conducted for the purposes ofdetecting manufacturing or construction defects. Beginning January 2006,

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costs of this nature areexpensed as incurred which is consistent with industry practice and theregulatory guidance issued by the FERC. However, we continue to capitalize initial construction hydrostatictesting cost and subsequent hydrostatic testing programs conducted for thepurpose of increasing pipeline capacity in accordance with our capitalizationpolicies. Also capitalized are certain costs such as sleeving or recoatingexisting pipelines, unless the expenditures are incurred as a single event andnot part of a major program, in which case we expense these costs as incurred. Ouradoption of the regulatory guidance did not significantly affect our financialposition, results of operations or cash flows.

We record property, plant and equipment at itsoriginal cost, which we depreciate on a straight-line basis 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. Our determination ofthe useful lives of property, plant and equipment requires us to make variousassumptions, including the supply of and demand for hydrocarbons in the marketsserved by our assets, normal wear and tear of the facilities, and the extentand frequency of maintenance programs. We routinely utilize consultants andother experts 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 stand-alonepipeline system is sold, we will recognize a gain or loss in our ConsolidatedStatements of Income for the difference between the cash received and the netbook value of the assets sold. Changes in any of our assumptions may alter therate at which we recognize depreciation in our consolidated financialstatements. At regular intervals, we retain the services of independentconsultants to assist us with assessing the reasonableness of the useful liveswe have established for the property, plant and equipment of our major systems.Based on the results of these regular assessments we may make modifications tothe assumptions we use to determine our 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 impairment loss when the carrying amount of the asset exceedsits fair value as determined by quoted market prices in active markets orpresent value techniques if quotes are unavailable. The determination of thefair value 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.

***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 based on the carryingvalues as of the end of the second quarter, or more frequently if impairmentindicators arise that suggest the carrying value of goodwill may not berecovered. Impairment occurs when the carrying amount of a reporting unitexceeds its fair value. At the time we determine that impairment has occurred,the carrying value of the goodwill is written down to its fair value. Toestimate the fair value of the reporting units, we make estimates and judgmentsabout future cash flows, as well as revenue, cost of sales, operating 

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expenses, capitalexpenditures and net working capital based on assumptions that are consistentwith 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 judgment. Actual results can, and often do,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 customer contractsfor the purchase and sale of natural gas, 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 isexpected to 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***

We record a liability for the fair value of our assetretirement obligations, or ARO, on a discounted basis, in the period in whichthe liability is incurred. Typically we record an ARO at the time the assetsare installed or acquired, if a reasonable estimate of fair value can be made.In connection with establishing an ARO, we capitalize the costs as part of thecarrying value of the related assets. We recognize an ongoing expense for theinterest component of the liability as part of depreciation expense resultingfrom changes in the value of the ARO due to the passage of time. We depreciatethe initial capitalized costs over the useful lives of the related assets. Weextinguish the liabilities for asset retirement obligations when assets aretaken 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 conditional asset retirementobligations that we can reasonably estimate. FIN 47 also provides specificguidance regarding when an asset retirement obligation is reasonably estimableincluding when sufficient information is available to apply an expected presentvalue technique. Our implementation of FIN 47 did not have a material impacteffect 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 andthe ultimate consumption of those resources by end users. Variables can affectthe remaining lives of the assets which preclude us from making a 

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reasonableestimate of the ARO. Indeterminate ARO costs will be recognized in the periodin which sufficient information exists to reasonably estimate potentialsettlement 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 (the relative pricedifferential between NGL sales and the offsetting natural gas purchases). Toreduce the volatility of our cash flows, we use derivative financialinstruments (i.e., futures, forwards, swaps, options and other financialinstruments with similar characteristics) to manage the purchase and salesprices of the commodities and fix 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 reducing the risk that itis intended to hedge. 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 generally be divided into two categories:1) cash flow hedges, or 2) fair value hedges. We enter into cash flowhedges to reduce the variability in cash flows related to forecastedtransactions. We enter into fair value hedges to reduce the risk of changes inthe value of a recognized asset or liability. Cash flow and fair value hedgesare considered highly effective if they are able to substantially offset (i.e.,more than 80 percent) the changes in cash flow or fair value of the risk thatis being hedged. The extent to which a derivative financial instrumentdesignated as a hedge does not offset the changes in cash flow or fair value ofthe risk being hedged is considered ineffective. At inception and on an ongoingbasis we assess whether the derivative financial instruments we use in ourhedging transactions are highly effective in offsetting changes in cash flowsor fair values of the hedged items.

All of our derivative financial instruments arerecorded in our Consolidated Financial Statements at fair market value ascurrent and long-term assets or liabilities on a net basis by counterparty andare adjusted 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 thereporting date, taking into account the current unrealized losses or gains onopen contracts. We use external market quotes and indices to valuesubstantially all of the financial instruments we utilize.

Derivative financial instruments that we designate andqualify as cash flow or fair value hedges under the requirements of SFAS No. 133,receive hedge accounting treatment for the effective portion of the derivativefinancial instrument. Under hedge accounting, anyunrealized gain or loss in fair market value of the effective portion ofa derivative financial instrument designated as a cash flow hedge is recordedas an asset or liability with an offset deferredin Accumulated other comprehensive income (“AOCI”), a component of Partners’Capital, until the underlying hedged transaction occurs. Realized gains andlosses on derivative financial instruments that are designated as cash flowhedges of forecasted commodity purchases and sales are included in Cost ofnatural gas and cash flow hedges of forecasted interest payments are includedin Interest expense on our Consolidated Statements of Income in the period thehedged transaction occurs. Under hedge accounting, the realized andunrealized gain or loss in the fair market value of a derivative financialinstrument designated as a fair value hedge is recorded as an asset or aliability with the offset recorded in our Consolidated Statements of Income asa component of Cost of natural gas for fair value hedges of our commodities andas a component of interest expense for fair value hedges of our indebtednessboth of which are offset by the changes in the fair market value of theunderlying hedged item.

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Under the guidance of SFAS No. 133, the changesin fair market value, both realized and unrealized gains and losses, ofderivative financial instruments that 1) donot qualify for hedge accounting, 2) are not designated as hedges and 3)are ineffective, are recognized each period in our Consolidated Statements ofIncome. These changes in fair market value are recognized as a component ofCost of natural gas for our commodity derivative financial instruments and as acomponent of interest expense for derivative financial instruments of ourinterest rates. We refer to the accountingtreatment for derivative financial instruments that do not qualify for hedgeaccounting as mark-to-market accounting. Our preference, wheneverpossible, is for our derivative financial instruments to receive hedgeaccounting treatment to mitigate the non cash earnings volatility that arisesunder mark-to-market accounting 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 AOCI relatedto cash flow hedges for which hedge accounting has been discontinued, remain inAOCI until the underlying physical transaction occurs unless it is probablethat the 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.

***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 is reasonablyassured, we record and report an asset separately from the associated liabilityin our financial statements. New environmental developments, such asincreasingly strict environmental laws and regulations and new claims fordamages to property, employees, other persons and the environment resultingfrom our current or past operations, could result in substantial cost andfuture 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 

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amountof impairment or loss can be reasonably estimated. Both internal and externallegal counsel evaluate our potential exposure to adverse outcomes. When a rangeof probable loss can be estimated, we accrue the most likely amount, or atleast the minimum of the range of probable loss. To the extent that actualoutcomes differ from our estimates, or additional facts and circumstances causeus to review our estimates, income may be affected.

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

Crude oil over/shortbalance and crude oil measurement gains/losses are inherent in thetransportation of crude oil due to evaporation, measurement differences andblending of commodities in transit in addition to other factors. We estimateour crude oil measurement gains/losses and our crude oil over/short balancebased on mathematical calculations and physical measurements, which includeassumptions about the type of crude oil, its market value, normal physicallosses due to evaporation and capacity limitations of the system. A materialchange in these assumptions may result in a change to the carrying value of ourcrude oil over/short balance or revision of our crude oil measurement gain/lossestimates. We include the crude oil measurement gains/losses in our operatingand administrative expenses on our Consolidated Statements of Income and the crudeoil over/short balance in Accounts payable and other in the ConsolidatedStatements of Financial Position if the balance is a liability and in Inventoryif 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 to these estimates and assumptions, actualresults may differ.

**RECENT ACCOUNTINGPRONOUNCEMENTS NOT YET ADOPTED**

***Fair Value Measurements***

In September 2006,the Financial Accounting Standards Board (FASB) issued FASB Statement No. 157,*Fair Value Measurements.*This statementdefines fair value, establishes a framework for measuring fair value ingenerally accepted accounting principles (GAAP), and expands disclosures aboutfair value measurement. The statement is effective for fiscal years beginningafter November 15, 2007, and with limited exceptions is to be appliedprospectively as of the beginning of the fiscal year initially adopted. We donot expect our adoption of this pronouncement to materially affect ourfinancial statements. However, adoption of this pronouncement may affect ourdisclosures regarding derivative financial instruments and indebtedness.

***Accounting for Registration Payment Arrangements***

In December 2006, theFASB issued FASB Staff Position FSP EITF 00-19-2, *Accounting for Registration Payment Arrangements*. This FASBStaff Position, or FSP, specifies that the contingent obligation to make futurepayments or otherwise transfer consideration under a registration paymentarrangement, whether issued as a separate agreement or included as a provisionof a financial instrument or other agreement, should be separately recognizedand measured in accordance with FASB Statement No. 5, *Accountingfor Contingencies*. This FSP also requires certain disclosuresregarding registration payment arrangements and liabilities recorded for suchpurposes. This FSP is immediately effective for 

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registrationpayment arrangements entered into or modified after December 21, 2006. Theguidance of this FSP is effective for fiscal years beginning after December 15,2006, and interim periods within those fiscal years for registration paymentarrangements entered into prior to December 21, 2006. This FSP requiresadoption by reporting a change in accounting principle through a cumulative-effectadjustment to the opening balance of our partners’ capital accounts as of thefirst interim period of the year in which this FSP is initially applied. We donot expect our adoption of this FSP to materially affect our financialposition, results of operations or cash flows.

***Staff Accounting Bulletin No. 108***

In September 2006, theSecurities and Exchange Commission issued Staff Accounting Bulletin No. 108.This Bulletin requires a “dual approach” for quantifications of errors usingboth a method that focuses on the income statement impact, including thecumulative effect of prior years’ misstatements, and a method that focuses onthe period-end balance sheet. We adopted SAB No. 108 as of December 31,2006. The adoption of this Bulletin did not have a material impact on ourconsolidated financial statements.

**Item 7A. Quantitativeand Qualitative Disclosures About 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 thata material foreign exchange exposure arises, we intend to hedge such exposureusing derivative financial instruments.

Thefollowing table presents the principal cash flows and related weighted averageinterest rates by expected maturity dates along with the carrying values andfair values of our third-party debt obligations as of December 31, 2006and 2005.

| ** **             | ** ** | **December 31, 2006**     | ** ** | ** **                                                                                  | ** ** | ** **                      | ** ** |
|------------------------|------------|-------------------------------------|------------|---------------------------------------------------------------------------------------------|------------|---------------------------------|------------|
| ** **             | ** ** | **Average**                         | ** ** | **Expected Fiscal Year of Maturity of Carrying Amounts** | ** ** | **December 31, 2005** | ** ** |
| ** **             | ** ** | **Interest  Rate**                  | ** ** | **2007**                                                                                    | ** ** | **2008**                        | ** ** | **2009** | ** ** | **2010** | ** ** | **2011** | ** ** | **Thereafter** | ** ** | **Total** | ** ** | **Fair  Value** | ** ** | **Carrying  Amount** | ** ** | **Fair  Value** | ** ** |
| ** **             | ** ** | **(dollars in millions)** | ** ** |
| **Liabilities**        |       |                                |       |                                                                                        |       |                            |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| *Fixed Rate:*          |       |                                |       |                                                                                        |       |                            |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| First Mortgage  Notes  |       |                                | 9.150      | %                                                                                           |       | $                               | 31.0       |   | $ | 31.0 |   | $ | 31.0 |   | $ | 31.0 |   | $ | 31.0 |   |   | $ | — |   |   | $ | 155.0 |   | $ | 169.5 |   |   | $ | 186.0 |   |   | $ | 207.9 |   |
| Senior notes due  2009 |       |                                | 4.000      | %                                                                                           |       | —                          |       | — |   | 200.0 |   | — |   | — |   |   | — |   |   | 200.0 |   | 194.2 |   |   | 199.9 |   |   | 193.0 |   |
| Senior notes due  2012 |       |                                | 7.900      | %                                                                                           |       | —                          |       | — |   | — |   | — |   | — |   |   | 99.9 |   |   | 99.9 |   | 110.5 |   |   | 99.9 |   |   | 113.8 |   |
| Senior notes due  2013 |       |                                | 4.750      | %                                                                                           |       | —                          |       | — |   | — |   | — |   | — |   |   | 199.8 |   |   | 199.8 |   | 188.6 |   |   | 199.8 |   |   | 190.8 |   |
| Senior notes due  2014 |       |                                | 5.350      | %                                                                                           |       | —                          |       | — |   | — |   | — |   | — |   |   | 199.9 |   |   | 199.9 |   | 193.0 |   |   | 199.9 |   |   | 196.7 |   |
| Senior notes due  2016 |       |                                | 5.875      | %                                                                                           |       | —                          |       | — |   | — |   | — |   | — |   |   | 299.7 |   |   | 299.7 |   | 297.4 |   |   | — |   |   | — |   |
| Senior notes due  2018 |       |                                | 7.000      | %                                                                                           |       | —                          |       | — |   | — |   | — |   | — |   |   | 99.8 |   |   | 99.8 |   | 107.9 |   |   | 99.8 |   |   | 111.4 |   |
| Senior notes due  2028 |       |                                | 7.125      | %                                                                                           |       | —                          |       | — |   | — |   | — |   | — |   |   | 99.8 |   |   | 99.8 |   | 108.9 |   |   | 99.8 |   |   | 113.0 |   |
| Senior notes due  2033 |       |                                | 5.950      | %                                                                                           |       | —                          |       | — |   | — |   | — |   | — |   |   | 199.7 |   |   | 199.7 |   | 186.2 |   |   | 199.7 |   |   | 193.1 |   |
| Senior notes due  2034 |       |                                | 6.300      | %                                                                                           |       | —                          |       | — |   | — |   | — |   | — |   |   | 99.8 |   |   | 99.8 |   | 97.1 |   |   | 99.8 |   |   | 100.8 |   |
| *Variable  Rate:*      |       |                                |       |                                                                                        |       |                            |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Commercial paper       |       |                                | 5.450      | %                                                                                           |       | —                          |       | — |   | — |   | 443.7 |   | — |   |   | — |   |   | 443.7 |   | 443.7 |   |   | 329.3 |   |   | 329.3 |   |
| Credit Facility        |       |                                | n/a        |                                                                                        |       | —                          |       | — |   | — |   | — |   | — |   |   | — |   |   | — |   | — |   |   | — |   |   | — |   |
|                        |            |                                     |            |                                                                                             |            |                                 |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

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Our net income and cash flows are subject tovolatility stemming from changes in interest rates on our variable rate debtobligations. Our interest rate risk exposure does not exist within any of oursegments, but exists at the corporate level where our variable rate debtobligations are issued. To mitigate the volatility of our cash flows, we usederivative financial instruments (i.e., futures, forwards, swaps, options andother financial instruments with similar characteristics) to manage the risksassociated with market fluctuations in interest rates. Based on our riskmanagement policies, all of our derivative financial instruments are employedin connection with an underlying asset, liability and/or forecasted transactionand are not entered into with the objective of speculating on interest rates.

Thetable below provides information about our derivative financial instrumentsthat we use to hedge the interest payments on our variable rate debtobligations which are sensitive to changes in interest rates and to lock in theinterest rate on anticipated issuances of debt in the future. For interest rateswaps, the table presents notional amounts, the rates charged on the underlyingnotional and weighted average interest rates paid by expected maturity dates.Notional amounts are used to calculate the contractual payments to be exchangedunder the contract. Weighted average variable rates are based on impliedforward rates in the yield curve at December 31, 2006.

|                             | ** ** | **December 31, 2006**                                                             | ** ** | ** **                                                                                              | ** ** | ** **                                                                | ** ** | ** **                                                          | ** ** |
|-----------------------------|------------|---------------------------------------------------------------------------------------------|------------|---------------------------------------------------------------------------------------------------------|------------|---------------------------------------------------------------------------|------------|---------------------------------------------------------------------|------------|
| ** **                  | ** ** | **Expected Fiscal Year of Maturity of Notional Amounts** | ** ** | **December 31, 2005**                                                                         | ** ** |
| ** **                  | ** ** | **Notional  Amount**                                                                        | ** ** | **2007**                                                                                                | ** ** | **2008**                                                                  | ** ** | **2009**                                                            | ** ** | **2010** | ** ** | **2011** | ** ** | **Thereafter** | ** ** | **Fair Value** | ** ** | **Notional  Amount** | ** ** | **Fair Value** | ** ** |
| ** **                  | ** ** | ** **                                                                                  | ** ** | ** **                                                                                              | ** ** | ** **                                                                | ** ** | ** **                                                          | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | **Asset** | ** ** | **Liability** | ** ** | ** ** | ** ** | **Asset** | ** ** | **Liability** | ** ** |
| ** **                  | ** ** | **(dollars in millions)**                                                         | ** ** |
| *Interest Rate Derivatives* |       |                                                                                        |       |                                                                                                    |       |                                                                      |       |                                                                |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Interest Rate  Swaps:       |       |                                                                                        |       |                                                                                                    |       |                                                                      |       |                                                                |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Floating to Fixed           |       | $          525.0                          |       | $               1.5          |       | $         0.5                |       | $         0.4          |       | $         0.6 |   | $         0.6 |   |   | $         0.7 |   |   |   | $ 4.3 |   |   |   | $  — |   |   | $     275.0 |   |   | $ 3.1 |   |   |   | $ — |   |   |
| Average Pay Rate            |       | 4.41                                                                                        | %          | 4.81                                                                                                    | %          | 4.35                                                                      | %          | 4.35                                                                | %          | 4.35 | % | 4.35 | % |   | 4.35 | % |   |   | — |   |   |   | — |   |   | 3.72 | % |   | — |   |   |   | — |   |   |
| Average Receive  Rate       |       | LIBOR                                                                                       |       | LIBOR                                                                                                   |       | LIBOR                                                                     |       | LIBOR                                                               |       | LIBOR |   | LIBOR |   |   | LIBOR |   |   |   | — |   |   |   | — |   |   | LIBOR |   |   | — |   |   |   | — |   |   |
| Fixed to Floating           |       | $          125.0                          |       | $             (0.5                     | )          | $       (0.1                           | )          | $       (0.1                     | )          | $       (0.2 | ) | $       (0.2 | ) |   | $       (0.2 | ) |   |   | $ — |   |   |   | $ (1.3 | ) |   | $     125.0 |   |   | $ 0.6 |   |   |   | $ — |   |   |
| Average Pay Rate            |       | LIBOR-  0.21%                                                                          |       | LIBOR-  0.21%                                                                                           |       | LIBOR-  0.21%                                                             |       | LIBOR-  0.21%                                                       |       | LIBOR-  0.21% |   | LIBOR-  0.21% |   |   | LIBOR-  0.21% |   |   |   | — |   |   |   | — |   |   | LIBOR-  0.21% |   |   | — |   |   |   | — |   |   |
| Average Receive  Rate       |       | 4.75                                                                                        | %          | 4.75                                                                                                    | %          | 4.75                                                                      | %          | 4.75                                                                | %          | 4.75 | % | 4.75 | % |   | 4.75 | % |   |   | — |   |   |   | — |   |   | 4.75 | % |   | — |   |   |   | — |   |   |
| *Treasury Locks:*           |       |                                                                                        |       |                                                                                                    |       |                                                                      |       |                                                                |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Floating to Fixed           |       | $          200.0                          |       | $               2.8          |       | $          —       |       | $          — |       | $          — |   | $          — |   |   | $          — |   |   |   | $ 2.8 |   |   |   | $  — |   |   | $          — |   |   | $ — |   |   |   | $ — |   |   |
| Average Pay Rate            |       | 4.68                                                                                        | %          | 4.68                                                                                                    | %          | —                                                                    |       | —                                                              |       | — |   | — |   |   | — |   |   |   | — |   |   |   | — |   |   | — |   |   | — |   |   |   | — |   |   |
| Average Receive  Rate       |       | 30YR-UST                                                                                    |       | 30YR-UST                                                                                                |       | —                                                                    |       | —                                                              |       | — |   | — |   |   | — |   |   |   | — |   |   |   | — |   |   | — |   |   | — |   |   |   | — |   |   |
| *Interest Rate Collars:*    |       |                                                                                        |       |                                                                                                    |       |                                                                      |       |                                                                |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Calls                       |       | $          100.0                          |       | $               0.1          |       | $          –– |       | $          — |       | $          — |   | $          — |   |   | $          — |   |   |   | $ 0.1 |   |   |   | $  — |   |   | $          — |   |   | $ — |   |   |   | $ — |   |   |
| Average Pay Rate            |       | 5.50                                                                                        | %          | 5.50                                                                                                    | %          | 5.50                                                                      | %          | —                                                              |       | — |   | — |   |   | — |   |   |   | — |   |   |   | — |   |   | — |   |   | — |   |   |   | — |   |   |
| Average Receive  Rate       |       | LIBOR                                                                                       |       | LIBOR                                                                                                   |       | LIBOR                                                                     |       | —                                                              |       | — |   | — |   |   | — |   |   |   | — |   |   |   | — |   |   | — |   |   | — |   |   |   | — |   |   |
| Puts                        |       | $          100.0                          |       | $                — |       | $          —       |       | $          — |       | $          — |   | $          — |   |   | $          — |   |   |   | $ — |   |   |   | $  — |   |   | $          — |   |   | $ — |   |   |   | $ — |   |   |
| Average Pay Rate            |       | 4.17                                                                                        | %          | 4.17                                                                                                    | %          | 4.17                                                                      | %          | —                                                              |       | — |   | — |   |   | — |   |   |   | — |   |   |   | — |   |   | — |   |   | — |   |   |   | — |   |   |
| Average Receive  Rate       |       | LIBOR                                                                                       |       | LIBOR                                                                                                   |       | LIBOR                                                                     |       | —                                                              |       | — |   | — |   |   | — |   |   |   | — |   |   |   | — |   |   | — |   |   | — |   |   |   | — |   |   |

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(1)          LIBOR refers to thethree-month U.S. London Interbank Offered Rate.

(2)          UST refers to UnitedStates Treasury notes.

Our floating to fixed rate interest rate swapsmaturing in 2007 qualify for hedge accounting treatment as set forth in SFAS No. 133and have been designated cash flow hedges of interest payments on $400 million of our variable rateindebtedness. Similarly, our treasury locks maturing in 2007 qualify for hedgeaccounting treatment pursuant to the requirements of SFAS No. 133 and havebeen designated as cash flow hedges of future interest payments on the first $200 million of an anticipated debt issuance. Additionally,our interest rate collars qualify for hedge accounting treatment as per SFAS No. 133and have been designated as cash flow hedges of interest payments on $100 million of our variable rate indebtedness.As such, the fair value of these derivative financial instruments is recordedas assets or liabilities on our Consolidated Statements of Financial Positionwith the changes in fair value recorded as corresponding increases or decreasesin AOCI.

93

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The floating to fixed rateand fixed to floating rate interest rate swaps maturing in 2013 have not beendesignated as cash flow or fair value hedges under SFAS No. 133 and, as aresult, changes in the fair value of these derivative financialinstruments are recorded in earnings as an increase or decrease in interest expense.

**COMMODITY PRICERISK**

Our net income and cash flows are subject tovolatility stemming from changes in commodity prices of natural gas, NGLs,condensate and fractionation margins (the relative price differential betweenNGL sales and the offsetting natural gas purchases). Our exposure to commodityprice risk exists within our Natural Gas and Marketing segments. To mitigatethe volatility of our cash flows, we use derivative financial instruments(i.e., futures, forwards, swaps, options and other financial instruments withsimilar characteristics) to manage the risks associated with marketfluctuations in commodity prices. Based on our risk management policies, all ofour derivative financial instruments are employed in connection with anunderlying asset, liability and/or forecasted transaction and are not enteredinto with the objective of speculating on commodity prices.

Thefollowing tables provide information about our derivative financial instrumentsat December 31, 2006 and December 31, 2005, with respect to ourcommodity price risk management activities for natural gas and NGLs, includingcondensate:

| ** **                        | ** **   | **At December 31, 2006** | ** **   | **At December 31, 2005** | ** ** |
|-----------------------------------|--------------|-----------------------------------------|--------------|-----------------------------------------|------------|
| ** **                        | ** **   | ** **                              | ** **   | ** **                              | ** ** | **Wtd Avg Price**(2) | ** ** | **Fair Value**(3) | ** ** | **Fair Value**(3) | ** ** |
| ** **                        | ** **   | **Commodity**                           | ** **   | **Notional**(1)                         | ** ** | **Receive** | ** ** | **Pay** | ** ** | **Asset** | ** ** | **Liability** | ** ** | **   Asset   ** | ** ** | **Liability** | ** ** |
| ***Contracts maturing in 2007***  | *** *** |                                    | *** *** | *** ***                            |       | *** *** | *** *** |   | *** *** | *** *** |   | *** *** | *** *** |   | *** *** | *** *** |   |   | *** *** | *** *** |   |   | *** *** | *** *** |   |   | *** *** | *** *** |   |
| *Swaps*                           | * *     |                                    | * *     | *** ***                            |       | * * | * * |   | * * | *** *** |   | * * | * * |   | * * | *** *** |   |   | * * | * * |   |   | * * | *** *** |   |   | * * | * * |   |
| Receive variable/pay fixed        |         |                                    | Natural gas  | *** ***                            |       | 67,928,435 |   |   | $ 6.39 | *** *** |   | $ 7.56 |   |   | $ 8.1 | *** *** |   |   | $ (86.7 | ) |   |   | $ 112.0 | *** *** |   |   | $    (1.0 | ) |   |
|                              |         |                                    | NGL          | *** ***                            |       | 99,645 |   |   | 38.52 | *** *** |   | 43.65 |   |   | — | *** *** |   |   | (0.5 | ) |   |   | — | *** *** |   |   | — |   |   |
| Receive fixed/pay variable        |         |                                    | Natural gas  | *** ***                            |       | 67,584,962 |   |   | 7.32 | *** *** |   | 6.63 |   |   | 79.8 | *** *** |   |   | (33.0 | ) |   |   | 0.5 | *** *** |   |   | (170.0 | ) |   |
| * *                          |         |                                    | NGL          | *** ***                            |       | 4,296,415 |   |   | 38.18 | *** *** |   | 40.28 |   |   | 14.4 | *** *** |   |   | (23.2 | ) |   |   | — | *** *** |   |   | (22.5 | ) |   |
|                                   |         |                                    | Crude oil    | *** ***                            |       | 388,680 |   |   | 42.05 | *** *** |   | 64.96 |   |   | — | *** *** |   |   | (8.6 | ) |   |   | — | *** *** |   |   | (7.9 | ) |   |
| Receive  variable/pay variable    |         |                                    | Natural gas  | *** ***                            |       | 42,790,661 |   |   | 6.54 | *** *** |   | 6.55 |   |   | 3.1 | *** *** |   |   | (3.7 | ) |   |   | 0.7 | *** *** |   |   | (0.1 | ) |   |
| *Options*                         | * *     |                                    | * *     | *** ***                            |       | * * | * * |   | * * | *** *** |   | * * | * * |   | * * | *** *** |   |   | * * | * * |   |   | * * | *** *** |   |   | * * | * * |   |
| Calls (written)                   |         |                                    | Natural gas  | *** ***                            |       | 365,000 |   |   | 7.00 | *** *** |   | 4.31 |   |   | — | *** *** |   |   | (1.0 | ) |   |   | — | *** *** |   |   | (2.0 | ) |   |
| Puts                              |         |                                    | Natural gas  | *** ***                            |       | 1,429,000 |   |   | 6.79 | *** *** |   | 5.97 |   |   | 1.0 | *** *** |   |   | — |   |   |   | — | *** *** |   |   | — |   |   |
| ***Contracts  maturing in 2008*** |         |                                    |         | *** ***                            |       |   |   |   |   | *** *** |   |   |   |   |   | *** *** |   |   |   |   |   |   |   | *** *** |   |   |   |   |   |
| *Swaps*                           |         |                                    |         | *** ***                            |       |   |   |   |   | *** *** |   |   |   |   |   | *** *** |   |   |   |   |   |   |   | *** *** |   |   |   |   |   |
| Receive  variable/pay fixed       |         |                                    | Natural gas  | *** ***                            |       | 17,000,112 |   |   | 7.63 | *** *** |   | 7.36 |   |   | 9.5 | *** *** |   |   | (5.1 | ) |   |   | 18.5 | *** *** |   |   | — |   |   |
| Receive fixed/pay variable        |         |                                    | Natural gas  | *** ***                            |       | 24,537,303 |   |   | 6.30 | *** *** |   | 8.07 |   |   | 3.6 | *** *** |   |   | (44.1 | ) |   |   | — | *** *** |   |   | (66.3 | ) |   |
|                              |         |                                    | NGL          | *** ***                            |       | 1,680,453 |   |   | 37.28 | *** *** |   | 40.67 |   |   | 2.5 | *** *** |   |   | (7.7 | ) |   |   | — | *** *** |   |   | (7.2 | ) |   |
|                                   |         |                                    | Crude oil    | *** ***                            |       | 337,241 |   |   | 45.16 | *** *** |   | 67.49 |   |   | — | *** *** |   |   | (7.0 | ) |   |   | — | *** *** |   |   | (5.2 | ) |   |
| Receive  variable/pay variable    |         |                                    | Natural gas  | *** ***                            |       | 19,577,541 |   |   | 8.28 | *** *** |   | 8.16 |   |   | 2.5 | *** *** |   |   | (0.4 | ) |   |   | 1.0 | *** *** |   |   | — |   |   |
| *Options*                         | * *     |                                    | * *     | *** ***                            |       | * * | * * |   | * * | *** *** |   |   | * * |   | * * | *** *** |   |   | * * | * * |   |   | * * | *** *** |   |   | * * | * * |   |
| Calls (written)                   |         |                                    | Natural gas  | *** ***                            |       | 366,000 |   |   | 8.06 | *** *** |   | 4.31 |   |   | — | *** *** |   |   | (1.3 | ) |   |   | — | *** *** |   |   | (1.7 | ) |   |
| Puts                              |         |                                    | Natural  gas | *** ***                            |       | 366,000 |   |   | 8.06 | *** *** |   | 3.40 |   |   | — | *** *** |   |   | — |   |   |   | — | *** *** |   |   | — |   |   |

 

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| ** **                          | ** ** | **At December 31, 2006** | ** **  | **At December 31, 2005** | ** ** |
|-------------------------------------|------------|-----------------------------------------|-------------|-----------------------------------------|------------|
| ** **                          | ** ** | ** **                              | ** **  | ** **                              | ** ** | **Wtd Avg Price**(2) | ** ** | **Fair Value**(3) | ** ** | **Fair Value**(3) | ** ** |
| ** **                          | ** ** | **Commodity**                           | ** **  | **Notional**(1)                         | ** ** | **Receive** | ** ** | **Pay** | ** ** | **Asset** | ** ** | **Liability** | ** ** | **   Asset   ** | ** ** | **Liability** | ** ** |
| ***Contracts maturing in 2009***    |       |                                    |        |                                    |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| *Swaps*                             |       |                                    |        |                                    |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Receive variable/pay fixed          |       |                                    | Natural gas |                                    |       | 4,902,720 |   |   | 7.44 |   |   | 7.26 |   |   | 2.9 |   |   |   | (2.1 | ) |   |   | — |   |   |   | — |   |   |   |
| Receive fixed/pay variable          |       |                                    | Natural gas |                                    |       | 12,865,240 |   |   | 5.15 |   |   | 7.86 |   |   | 0.7 |   |   |   | (31.5 | ) |   |   | — |   |   |   | (34.5 | ) |   |   |
|                                |       |                                    | NGL         |                                    |       | 1,543,950 |   |   | 40.75 |   |   | 40.78 |   |   | 1.4 |   |   |   | (1.4 | ) |   |   | — |   |   |   | (0.6 | ) |   |   |
|                                     |       |                                    | Crude oil   |                                    |       | 264,625 |   |   | 59.09 |   |   | 67.13 |   |   | — |   |   |   | (1.9 | ) |   |   | — |   |   |   | (1.0 | ) |   |   |
| Receive  variable/pay variable      |       |                                    | Natural gas |                                    |       | 16,277,500 |   |   | 8.03 |   |   | 7.98 |   |   | 1.4 |   |   |   | (0.6 | ) |   |   | 1.1 |   |   |   | — |   |   |   |
| *Options*                           | * *   |                                    |        |                                    |       |   |   |   |   |   | * * | * * | * * |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Calls (written)                     |       |                                    | Natural gas |                                    |       | 365,000 |   |   | 7.83 |   |   | 4.31 |   |   | — |   |   |   | (1.2 | ) |   |   | — |   |   |   | (1.4 | ) |   |   |
| Puts                                |       |                                    | Natural gas |                                    |       | 365,000 |   |   | 7.83 |   |   | 3.40 |   |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   |
| ***Contracts maturing in 2010***    |       |                                    |        |                                    |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| *Swaps*                             |       |                                    |        |                                    |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Receive  variable/pay fixed         |       |                                    | Natural gas |                                    |       | 1,511,295 |   |   | 7.31 |   |   | 5.58 |   |   | 2.5 |   |   |   | (0.3 | ) |   |   | — |   |   |   | — |   |   |   |
| Receive fixed/pay variable          |       |                                    | Natural gas |                                    |       | 9,490,000 |   |   | 4.11 |   |   | 7.36 |   |   | 0.2 |   |   |   | (26.1 | ) |   |   | 0.1 |   |   |   | (25.9 | ) |   |   |
|                                |       |                                    | NGL         |                                    |       | 584,000 |   |   | 32.68 |   |   | 35.78 |   |   | — |   |   |   | (1.5 | ) |   |   | — |   |   |   | (0.4 | ) |   |   |
|                                     |       |                                    | Crude oil   |                                    |       | 213,525 |   |   | 63.00 |   |   | 66.46 |   |   | — |   |   |   | (0.6 | ) |   |   | — |   |   |   | (0.1 | ) |   |   |
| Receive  variable/pay variable      |       |                                    | Natural gas |                                    |       | 7,200,000 |   |   | 8.17 |   |   | 8.05 |   |   | 0.8 |   |   |   | (0.1 | ) |   |   | — |   |   |   | — |   |   |   |
| *Options*                           | * *   |                                    |        |                                    |       |   |   |   |   |   | * * | * * | * * |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Calls (written)                     |       |                                    | Natural gas |                                    |       | 365,000 |   |   | 7.42 |   |   | 4.31 |   |   | — |   |   |   | (1.0 | ) |   |   | — |   |   |   | (1.1 | ) |   |   |
| Puts                                |       |                                    | Natural gas |                                    |       | 365,000 |   |   | 7.42 |   |   | 3.40 |   |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   |
| ***Contracts maturing in 2011***    |       |                                    |        |                                    |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| *Swaps*                             |       |                                    |        |                                    |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Receive  variable/pay fixed         |       |                                    | Natural gas |                                    |       | 730,000 |   |   | 7.02 |   |   | 3.57 |   |   | 2.0 |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   |
| Receive fixed/pay variable          |       |                                    | Natural gas |                                    |       | 7,952,500 |   |   | 3.63 |   |   | 7.02 |   |   | — |   |   |   | (21.5 | ) |   |   | — |   |   |   | (21.3 | ) |   |   |
| * *                            |       |                                    | NGL         |                                    |       | 230,315 |   |   | 31.70 |   |   | 34.87 |   |   | — |   |   |   | (0.6 | ) |   |   | — |   |   |   | — |   |   |   |
|                                     |       |                                    | Crude oil   |                                    |       | 182,500 |   |   | 64.30 |   |   | 65.83 |   |   | — |   |   |   | (0.2 | ) |   |   | — |   |   |   | — |   |   |   |
| *Options*                           | * *   |                                    |        |                                    |       |   |   |   |   |   | * * | * * | * * |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Calls (written)                     |       |                                    | Natural gas |                                    |       | 365,000 |   |   | 7.02 |   |   | 4.31 |   |   | — |   |   |   | (0.9 | ) |   |   | — |   |   |   | (0.9 | ) |   |   |
| Puts                                |       |                                    | Natural gas |                                    |       | 365,000 |   |   | 7.02 |   |   | 3.40 |   |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   |
| ***Contracts maturing after 2012*** |       |                                    |        |                                    |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| *Swaps*                             |       |                                    |        |                                    |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Receive variable/pay fixed          |       |                                    | Natural gas |                                    |       | 182,000 |   |   | 7.56 |   |   | 3.57 |   |   | 0.6 |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   |
| Receive fixed/pay  variable         |       |                                    | Natural gas |                                    |       | 1,456,000 |   |   | 3.57 |   |   | 7.56 |   |   | — |   |   |   | (4.5 | ) |   |   | — |   |   |   | (4.8 | ) |   |   |

----

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

(2)          Weighted average pricesreceived and paid are in $/MMBtu for Natural gas and in $/Bbl for NGL andCrude.

(3)          Thefair value is determined based on quoted market prices at December 31,2006 and December 31, 2005, respectively, discounted using the swap ratefor the respective periods to consider the time value of money. Fair values arepresented in millions of dollars.

***Accounting Treatment***

All derivative financial instruments are recorded inthe 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, other than in a forced orliquidation sale, to terminate or close the contracts at the reporting date,taking into account the current unrealized losses or gains on open contracts.We use actively traded external market quotes and indices to valuesubstantially all of the financial instruments we utilize.

Under the guidance of SFAS No. 133, if aderivative financial instrument does not qualify as a hedge, or is notdesignated as a hedge, the derivative is adjusted to its fair market value, ormarked-to-market, each period with the increases and decreases infair value recorded in our Consolidated Statements of Income as increases anddecreases in Cost of natural gas for our commodity-based derivatives andInterest expense for our interest rate derivatives. Cash flow is only impactedto the extent the actual derivative contract is settled by making or receivinga payment to or from the counterparty or by making or receiving a payment forentering into a contract that exactly offsets the original derivative contract.Typically, we settle our derivative contracts when the physical transactionthat underlies the derivative financial instrument occurs.

95

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If a derivative financial instrument qualifies and isdesignated as a cash flow hedge, a hedge of a forecasted transaction or futurecash flows, any unrealized mark-to-market gain or loss is deferred inAccumulated other comprehensive income (“AOCI”), a component of Partners’Capital, until the underlying hedged transaction occurs. To the extent that thehedge instrument is effective in offsetting the transaction being hedged, thereis no impact to the income statement. At inception and on a quarterly basis, weformally assess whether the hedge contract is highly effective in offsettingchanges in cash flows of hedged items. 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 hedges and qualify for hedge accounting are included in Cost ofnatural gas for commodity hedges and Interest expense for interest rate hedgesin the period the hedged transaction occurs. Gains and losses deferred in AOCIrelated to cash flow hedges, for which hedge accounting has been discontinued,remain in AOCI until the underlying physical transaction occurs unless it isprobable that the forecasted transaction will not occur by the end of theoriginally specified time period, or within an additional two-month period oftime thereafter. Generally, our preference is for our derivative financialinstruments to receive hedge accounting treatment whenever possible, tomitigate the non-cash earnings volatility that arises under mark-to-marketaccounting treatment. To qualify for cash flow hedge accounting as set forth inSFAS No. 133, very specific requirements must be met in terms of hedgestructure, 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 or lossresulting from the change in fair market value of the derivative financialinstrument is recorded in earnings adjusted by the gain or 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 or loss onthe change in fair market value of the underlying asset or liability. Weinclude the gains and losses associated with derivative financial instrumentsdesignated and qualifying as fair value hedges of our debt obligations inInterest expense on our Consolidated Statements of Income. Similar toderivative financial instruments designated as cash flow hedges, very specificrequirements must be met in terms of hedge structure, hedge objective and hedgedocumentation.

***Non-Qualified Hedges***

Many of our derivative financial instruments qualifyfor hedge accounting treatment under the specific requirements of SFAS No. 133.However, we have four primary transaction types associated with our commodityderivative financial instruments where the hedge structure does not meet therequirements to apply hedge accounting. As a result, these derivative financialinstruments do not qualify for hedge accounting under SFAS No. 133 and arereferred to as “non-qualified.” Non-qualified derivative financial instrumentsare marked-to-market each period with the change in fair value,representing unrealized gains and losses, included in Cost of natural gas inour 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 when the associatedfinancial instrument contract settlement is made.

The four primarytransaction types that do not qualify for hedge accounting are as follows:

1.                **Transportation—**In our Marketing segment, when we transportnatural gas from one location to another the pricing index used for natural gassales is usually different from the pricing index used for natural gaspurchases, which exposes us to market price risk relative to changes in thosetwo indices. By entering into a basis swap, where we exchange one pricing indexfor another, we can effectively lock in the margin, representing the differencebetween the sales price and the purchase price, on the combined natural gaspurchase and natural gas sale, removing any market 

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price risk on the physicaltransactions. Although this represents a sound economic hedging strategy, thederivative financial instruments (i.e., the basis swaps) we use to manage thecommodity price risk associated with these transportation contracts do notqualify for hedge accounting under SFAS No. 133, since only the futuremargin has been fixed and not the future cash flow. As a result, thesederivative financial instruments are marked-to-market.

2.                **Storage—**In our Marketing segment, we use derivativefinancial instruments (i.e., natural gas swaps) to hedge the relativedifference between the injection price paid to purchase and store natural gasand the withdrawal price at which the natural gas is sold from storage. Theintent of these derivative financial instruments is to lock in the margin,representing the difference between the price paid for the natural gas injectedand the price received upon withdrawal of the gas from storage in a futureperiod. We do not pursue cash flow hedge accounting treatment for these storagetransactions since the underlying forecasted injection or withdrawal of naturalgas may not occur in the period as originally forecast. This can occur becausewe have the flexibility to make changes in the underlying injection orwithdrawal schedule, given changes in market conditions. In addition, since thephysical natural gas is recorded at the lower of cost or market, timingdifferences can result when the derivative financial instrument is settled in aperiod that is different from when the physical natural gas is sold fromstorage. As a result, derivative financial instruments associated with ournatural gas storage activities can create volatility in our earnings.

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 cash flow hedging relationship with the intent ofcontemporaneously re-designating the natural gas collars as hedges offorecasted physical natural gas sales with a NYMEX pricing index. However,because the fair value of these derivative instruments was a liability to us atre-designation, they are considered net written options under SFAS No. 133and do not qualify for hedge accounting. These derivatives are being marked-to-market,with the changes in fair value from the date of de-designation recordedto earnings each period. As a result, our operating income will be subject togreater volatility due to movements in the prices of natural gas until theunderlying long-term transactions are settled.

4.                **Optional Natural Gas Processing Volumes—**In our Natural Gassegment we use derivative financial instruments to hedge the volumes of NGLsproduced from our natural gas processing facilities. Our natural gas contractsallow us the option of processing natural gas when it is economical, and ceasingto do so when processing becomes uneconomic. We have entered into derivativefinancial instruments to fix the sales price of a portion of the NGLs that weproduce at our discretion and to fix the associated purchases of natural gasrequired for processing. We will designate derivative financial instrumentsassociated with NGLs we produce at our discretion as cash flow hedges when theprocessing of natural gas is probable of occurrence. However, we are precludedfrom designating the derivative financial instruments entered to manage therespective commodity price risk when we are unable to accurately forecast theNGLs to be processed at our discretion. As a result, our operating income willbe subject to increased volatility due to fluctuations in NGL prices until theunderlying transactions are settled or offset.

In each of the instancesdescribed above, the underlying physical purchase, storage and sale of naturalgas and NGLs are accounted for on a historical cost or market basis rather thanon the mark-to-market basis we utilize for the derivative financial instrumentsemployed to mitigate the commodity price risk associated with our storage andtransportation assets. This difference in accounting (i.e., the derivative financial instruments are recorded at fair marketvalue while the physical transactions are recorded at 

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historical cost) 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***

In 2005, we discontinued application of hedgeaccounting in connection with some of our derivative financial instrumentsdesignated as hedges of forecasted sales and purchases of natural gas. Wediscontinued application of hedge accounting when we determined it was nolonger probable that the originally forecasted purchases and sales of naturalgas would occur by the end of the originally specified time period, or withinan additional two-month period of time thereafter. As discussed above, this canoccur because we have the flexibility to make changes to the underlyingdelivery locations 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, in 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 AOCI. 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 in 2005.

Thefollowing table presents the unrealized gains and losses associated withchanges in the fair value of our derivatives, which are recorded as an elementof Cost of natural gas in our Consolidated Statements of Income and disclosedas a reconciling item on our Statements of Cash Flows:

| Derivative fair value gains (losses) | ** ** | ** **             | ** ** | **December 31,  2006** | ** ** | **December 31,  2005** | ** ** | **December 31,  2004** | ** ** |
|----------------------------------------------------------|------------|------------------------|------------|-----------------------------|------------|-----------------------------|------------|-----------------------------|------------|
| ** **                                               | ** ** | **(in millions)** | ** ** |
| Natural Gas segment                                      |       |                   |       |                        |       |                        |       |                        |       |   |   |   |   |
| Hedge ineffectiveness                                    |       |                   | $          | (1.9                        | )          |                        |       | $                           | (2.5       | ) |   |   | $ | (1.1 | ) |   |
| Non-qualified hedges                                     |       |                   | 1.8        |                        |       |                        | (5.6       | )                           |       |   | — |   |   |
| Marketing                                                |       |                   |       |                        |       |                        |       |                        |       |   |   |   |   |
| Non-qualified hedges                                     |       |                   | 64.5       |                        |       |                        | (41.3      | )                           |       |   | (2.1 | ) |   |
| Discontinued hedges                                      |       |                   | —     |                        |       |                        | (9.0       | )                           |       |   | — |   |   |
| Derivative fair value gains  (losses)                    |       |                   | $          | 64.4                        |       |                        |       | $                           | (58.4      | ) |   |   | $ | (3.2 | ) |   |

 

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

In connection with thesale of assets in December 2005, as discussed in Note 3 to theConsolidated Financial Statements beginning on page F-1 of thisreport, we settled for cash of approximately $16.3 million, natural gascollars representing derivative financial instruments on sales of 2,000 MMBtu/dof natural 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 qualified for and weredesignated 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 through 2007.

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***Derivative Positions***

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

|                              | ** ** | **December 31,  2006** | ** ** | **December 31,  2005** | ** ** |
|------------------------------|------------|-----------------------------|------------|-----------------------------|------------|
| ** **                   | ** ** | **(in millions)**      | ** ** |
| Receivables, trade and other |       |                        | $          | 7.2                         |       |   |   | $ | 5.8 |   |   |
| Other assets, net            |       |                        | 11.0       |                        |       |   | 4.2 |   |   |
| Accounts payable and other   |       |                        | (57.2      | )                           |       |   | (129.2 | ) |   |
| Other long-term  liabilities |       |                        | (136.4     | )                           |       |   | (243.0 | ) |   |
|                              |       |                        | $          | (175.4                      | )          |   |   | $ | (362.2 | ) |   |

 

The decrease in our obligation associated withderivative activities is primarily due to the decline in current and forwardnatural gas prices at December 31, 2006 in relation to current and forwardnatural gas prices at December 31, 2005. The Partnership’s portfolio ofderivative financial instruments is largely comprised of long-term fixedprice natural gas sales and purchase agreements.

We record the change in fair value of our highlyeffective cash flow hedges in AOCI until the derivative financial instrumentsare settled, at which time they are reclassified to earnings. We regularlyenter into treasury locks to hedge the interest on anticipated issuances ofindebtedness. The settlement of a treasury lock can result in the retention ofunrecognized gains or losses in AOCI that are amortized to interest expenseover the life of the related debt issuance. We paid $10.2 million in December 2006,to settle treasury locks in connection with the issuance of $300 million inprincipal amount of our senior notes. The $10.2 million will be amortized fromAOCI to interest expense over the 10-year life of the senior notes.

Also included in AOCI are unrecognized losses ofapproximately $4.8 million associated with derivative financial instrumentsthat qualified for and were classified as cash flow hedges of forecastedcommodity transactions that were subsequently de-designated. These unrealizedlosses are reclassified to earnings over the periods during which theoriginally hedged forecasted transactions affect earnings. For the years ended December 31,2006, 2005 and 2004, we reclassified unrealized losses of $78.3 million, $33.8 millionand $12.6 million, respectively, from AOCI to Cost of natural gas on ourConsolidated Statements of Income for the fair value of derivative financialinstruments that were settled. We estimate that approximately $57.6 million ofAOCI representing unrealized net losses on cash flow hedging activities at December 31,2006, will be reclassified 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.

**Item 8. FinancialStatements 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. Changesin and Disagreements with Accountants on Accounting and Financial Disclosure**

None.

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**Item9A. Controls and Procedures**

**DISCLOSURE CONTROLS AND PROCEDURES**

We and Enbridge maintainsystems of disclosure controls and procedures designed to provide reasonableassurance that we are able to record, process, summarize and report theinformation required in our annual and quarterly reports under the SecuritiesExchange Act of 1934. Our management has evaluated the effectiveness of ourdisclosure controls and procedures as of December 31, 2006. Based uponthat evaluation, our principal executive officer and principal financialofficer concluded that our disclosure controls and procedures are effective toaccomplish their purpose. In conducting this assessment, our management reliedon similar evaluations conducted by employees of Enbridge affiliates whoprovide certain treasury, accounting and other services on our behalf. Nochanges in our internal control over financial reporting were made during thethree months ended December 31, 2006, that would materially affect ourinternal control over financial reporting.

**INTERNAL CONTROL OVER FINANCIAL REPORTING**

***Management’s Reporton Internal Control Over Financial 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 financialofficers to 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.

ThePartnership’s internal control over financial reporting includes policies andprocedures that:

·       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, 2006, 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 31,2006.

Management’s assessment ofthe effectiveness of the Partnership’s internal control over financialreporting as of December 31, 2006 has been audited byPricewaterhouseCoopers LLP, an independent registered public accounting firm,as stated in their report beginning on page F-2.

**Item9B. Other Information**

None.

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**PART III**

**Item 10. Directorsand Executive Officers of the Registrant**

**DIRECTORS ANDEXECUTIVE 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  |       | 60         |       | Director                                                                         |
| E.C. Hambrook  |       | 69         |       | Director                                                                         |
| M.O. Hesse     |       | 64         |       | Director                                                                         |
| G.K. Petty     |       | 65         |       | Director                                                                         |
| S.J.J. Letwin  |       | 51         |       | Managing Director and  Director                                                  |
| T.L. McGill    |       | 52         |       | President and Director                                                           |
| J.R. Bird      |       | 57         |       | Executive Vice  President—Liquids Pipelines and Director                    |
| L.A. Zupan     |       | 51         |       | Vice President—Liquids  Pipelines Operations                                |
| M.A. Maki      |       | 42         |       | Vice President—Finance                                                      |
| R.L. Adams     |       | 42         |       | Vice  President—Operations and Technologies                                 |
| J.M. Gerez     |       | 50         |       | Vice President—Liquids  Pipelines Project Management & Engineering |
| J.A. Holder    |       | 49         |       | Vice President—Liquids  Pipelines Support Services                          |
| J.A. Loiacono  |       | 44         |       | Vice  President—Commercial Activities                                       |
| D.V. Krenz     |       | 55         |       | Vice President                                                                   |
| V.D. Yu        |       | 40         |       | Treasurer                                                                        |
| J.N. Rose      |       | 39         |       | Assistant Treasurer                                                              |
| S.J. Neyland   |       | 39         |       | Controller                                                                       |
| E.C. Kaitson   |       | 50         |       | Assistant Secretary                                                              |
| B.A. Stevenson |       | 51         |       | Corporate Secretary                                                              |

 

J.A. Connelly was elected a director of the GeneralPartner and Enbridge Management in January 2003 and serves as the Chairmanof the Audit, Finance & Risk Committee. Mr. Connelly served asExecutive Vice President, Senior Vice President and Vice President of theCoastal Corporation from 1988 to 2001. Mr. Connelly is a businessconsultant providing executive management consulting services.

E.C. Hambrook was elected a director of the GeneralPartner and Enbridge Management in January 1992 and serves on the Audit,Finance & Risk Committee. Mr. Hambrook serves as Chairman of theboard of directors of the General Partner and Enbridge Management. Mr. Hambrookhas served as President of Hambrook Resources, Inc. since its inception in1991. Hambrook Resources, Inc. is a real estate investment, marketing andsales company.

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M.O. Hesse was elected a director of the GeneralPartner and Enbridge Management in March 2003 and serves as a member ofthe Audit, Finance & Risk Committee. Ms. Hesse was President andCEO of Hesse Gas Company from 1990 through 2003. She served as Chairman of theU.S. Federal Energy Regulatory Commission from 1986 to 1989. Ms. Hessealso served as Senior Vice President, First Chicago Corporation and AssistantSecretary for Management and Administration, U.S. Department of Energy. Shecurrently serves as a director of Arizona Public Service Company, Pinnacle WestCapital Corporation, and Terra Industries, Inc.

G.K. Petty was elected a director of the GeneralPartner and Enbridge Management in February 2001 and serves on the Audit,Finance & Risk Committee. Mr. Petty has served as a director ofEnbridge since January 2001. Mr. Petty served as President and ChiefExecutive Officer of Telus Corporation, a Canadian telecommunications company,from November 1994 to November 1999. Mr. Petty is a businessconsultant providing executive management consulting services to thetelecommunications industry.

S.J.J. Letwin was elected Managing Director of theGeneral Partner and Enbridge Management in May 2006. Prior to his electionhe served Enbridge, the indirect parent of our General Partner, as Group VicePresident, Gas Strategy & Corporate Development since April 2003;prior thereto he served Enbridge as Group Vice President, Distribution &Services since September 2000.

T. L. McGill was elected President of the GeneralPartner and Enbridge Management in May 2006. Prior to that he served asVice President, Commercial Activity and Business Development of the GeneralPartner and Enbridge Management since April 2002 and Chief OperatingOfficer since July 2004. Prior to that time, Mr. McGill was Presidentof Columbia Gulf Transmission Company from January 1996 to March 2002.

J.R. Bird served as a director of the General Partnerand Enbridge Management from September 2000 to January 2003 and wasreelected as a Director in October 2003. He has also served as ExecutiveVice President, Liquids Pipelines of the General Partner and EnbridgeManagement since May 2006, and holds similar responsibilities withEnbridge. Prior to that Mr. Bird served as a Group Vice President, LiquidsTransportation from May 2001 and in other senior leadership positions withEnbridge from August 1997.

L.A. Zupan was elected Vice President, LiquidsPipelines Operations of the General Partner and Enbridge Management in July 2004,and holds similar responsibilities with Enbridge. Prior to that he has servedas Vice President, Development & Services for Enbridge Pipelines since2000 and prior to that as Director, Information Technology since November 1999.

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

R.L. Adams was elected Vice President, Operations andTechnologies of the General Partner and Enbridge Management in April 2003.Prior to his current position, he was Director of Technology &Operations for the General Partner and Enbridge Management since 2001, andDirector of Field Operations and Technical Services and Director of CommercialActivities for Ocensa/Enbridge in Bogota, Colombia from 1997 to 2001.

J.M. Gerez was elected Vice President, LiquidsPipelines Project Management and Engineering, of the General Partner andEnbridge Management in May 2006, and holds similar responsibilities withEnbridge. Prior to that he was Vice President Operations with OCENSA, anEnbridge affiliate in Colombia from 2000 to May 2006.

J. A. Holder was elected Vice President, LiquidsPipelines Support Services of the General Partner in April 2006, and holdssimilar responsibilities with Enbridge. Prior to that she served as VicePresident, 

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Market Services forEnbridge since December 2004 and prior to that as Vice President,Operations for Enbridge Gas Distribution since May 2001.

J.A. Loiacono was elected Vice President, CommercialActivities, of the General Partner and Enbridge Management in July 2006. Priorto that, he was Director of Commercial Activities for the General Partner andEnbridge Management from April 2003 and commenced employment with MidcoastEnergy Resources in February 2000 as an Asset Optimizer.

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

V. D. Yu was elected as Treasurer of the GeneralPartner and Enbridge Management in July 2005 and is also Vice President,Enterprise Risk of Enbridge. Since July 2002 he was Director FinancialManagement at Enbridge and previously Manager, Capital Markets and RiskManagement since October 2000.

J. N. Rose was appointed as Assistant Treasurer of theGeneral Partner and Enbridge Management in July 2005 and is also aManager, Corporate Finance of Enbridge, a position he has held since April 2004.Prior to that Mr. Rose was a Vice President with Citigroup GlobalCorporate and Investment Bank from 2001 to 2004.

S.J. Neyland, was elected Controller of the GeneralPartner and Enbridge Management effective September 2006. Prior to hiselection he served as Controller, Natural gas since January 2005,Assistant Controller from May 2004 to January 2005, and in othermanagerial roles in Finance and Accounting from December 2001 to May 2004.Prior to that Mr. Neyland was Controller of Koch Midstream Services from1999 to 2001.

E.C. Kaitson was elected Assistant Secretary of theGeneral Partner and Enbridge Management in July 2004. He served asCorporate Secretary of the General Partner and Enbridge Management from October 2001to July 2004. He also currently serves as Associate General Counsel ofEnbridge. He was previously Assistant Corporate Secretary and General Counselof Midcoast Energy Resources, Inc. from 1997 until Enbridge acquired it onMay 11, 2001.

B.A. Stevenson was electedCorporate Secretary of the General Partner and Enbridge Management in July 2004.Between 2000 and 2004 Mr. Stevenson held management positions with ReliantEnergy, Inc. and Arthur Andersen LLP. Prior to that Mr. Stevenson wasGeneral Counsel & Corporate Secretary of Alberta Natural GasCompany Ltd, a Canadian gas processing and transmission company, that wasacquired by TransCanada Pipelines.

**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. Toour knowledge, based solely on a review of the copies of reports furnished tous and written representations that no other reports were required, theofficers, directors, and greater than 10% beneficial owners complied with allapplicable filing requirements of Section 16(a) of the Exchange Actduring the year, except that Mr. G.K. Petty filed a late Form 4 on March 20,2006, for transactions that occurred on March 13, 2006.

**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 

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standards do not requirethat we or the General Partner have a majority of independent directors or anominating 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 March 17,2006.

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

We have adopted a Code of Ethics applicable to oursenior financial officers, including the principal executive officer, principalfinancial officer and principal accounting officer of Enbridge Management. Acopy of the Code of Ethics for Senior Financial Officers is available on ourwebsite 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.

**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 is relying upon any exemptions from theforegoing independence requirements. The members of the Audit Committee areJ.A. Connelly, E.C. Hambrook, M.O. Hesse, and G.K. Petty. 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.

Enbridge Management’s board of directors hasdetermined that J.A. Connelly, E.C. Hambrook and M.O. Hesse qualify as “AuditCommittee financial experts” as defined in Item 407(d)(ii) of 

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SEC Regulation S-K. Each of the members of theAudit, Finance and Risk Committee is independent as defined by Section 303Aof the listing standards of the NYSE.

Mr. Petty also serves on the Audit Committees of theGeneral Partner, Enbridge Management, Fuel Cell Energy, Inc. and ofEnbridge Inc. In compliance with the provisions of the Audit, Finance &Risk Committee Charter, the board of directors of the General Partner and ofEnbridge Management have determined that Mr. Petty’s simultaneous serviceon such audit committees would not impair his ability to effectively serve onthe Audit, Finance & Risk Committee.

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.

**EXECUTIVE SESSIONSOF NON-MANAGEMENT DIRECTORS**

The independent directorsof Enbridge Management meet at regularly scheduled executive sessions withoutmanagement. J.A. Connelly or E.C. Hambrook serve as the presiding director atthose executive sessions. Persons wishing to communicate with the Company’sindependent directors may do so by writing in care of Chairman, Board ofDirectors, Enbridge Energy Partners, L.P., 1100 Louisiana, Suite 3300,Houston, TX 77002.

**Item 11. ExecutiveCompensation**

**COMPENSATIONDISCUSSION AND ANALYSIS**

We are a master limited partnership and we do notdirectly employ any of the individuals responsible for managing or operatingour business nor do we have any directors. We obtain managerial, administrativeand operational services from our general partner and Enbridge pursuant toservice agreements among us, Enbridge Management, and affiliates of Enbridge.Pursuant to these service agreements, we have agreed to reimburse our generalpartner and affiliates of Enbridge for the cost of managerial, administrative,operational and director services they provide to us.

The compensation policies and philosophy of Enbridgegovern the types and amount of compensation granted each of the Named ExecutiveOfficers, or NEOs. Since these policies and philosophy are those of Enbridge,we refer you to a discussion of those items as set forth in the ExecutiveCompensation section of the Enbridge “Management Information Circular” on the Enbridgewebsite at www.enbridge.com. The Enbridge “Management Information Circular” isproduced by Enbridge pursuant to Canadian securities regulations and is notincorporated into this document by reference or deemed furnished or filed by usunder the Securities Exchange Act of 1934, as amended; rather the reference isto provide our investors with an understanding of the compensation policies andphilosophy of the ultimate parent of our general partner.

The boards of directors of Enbridge Management and ourGeneral Partner do not have separate compensation committees, nor do they haveresponsibility for approving the elements of compensation presented in thetables which follow this discussion. The boards of directors of EnbridgeManagement and our general partner do have responsibility for evaluating anddetermining the reasonableness of the total amount we are charged formanagerial, administrative and operational support, including compensation ofthe NEOs, provided by Enbridge and its affiliates, including our generalpartner.

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All U.S.-domiciled employees of Enbridge are directlyemployed by its subsidiary, Enbridge Employee Services, Inc., which werefer to as EES. In connection with our annual budget process, we calculate anaverage “Budgeted Allocation Rate,” which represents an estimated average ofthe percentage of time for each of our NEOs that will be spent on our businessduring the succeeding year. Those estimates are revised each year based onhistorical experience. The average Budgeted Allocation Rate was 87% for 2006and has been set at 84% for 2007. EES’s salary costs are allocated to us basedon the percentage of time spent by EES employees on our behalf compared withthe total time of all EES employees. We are allocated a portion of theequity-based compensation expense as determined in accordance with U.S. GAAP.Pension expenses of EES (other than expenses under Enbridge’s nonqualifiedsupplemental pension plan for U.S.-domiciled employees, which we refer to asthe SPP) are allocated to us based on the proportion that the total headcountof EES employees assigned to us bears to the total headcount of EES. For thispurpose, an employee of EES is deemed to be assigned to us if he or she workson assets owned by the Partnership. Pension expenses of EES attributable to theSPP are allocated to us based upon the average Budgeted Allocation Rate. EESallocates to us that portion of its compensation expense for Enbridge’s ShortTerm Incentive Plan, a non-equity performance-based incentive plan, equal tothe total salaries of employees who perform work for us multiplied by the averageBudgeted Allocation Rate divided by EES’ total salary expense.

As we are a partnershipand not a corporation for U.S. federal income tax purposes, we are not subjectto the executive compensation tax deductible limitations of Internal RevenueCode §162(m). Accordingly, none of the compensation paid to our NEOs is subjectto limitation. The compensation of our Named Executive Officers included in thetables below is established by a committee of the board of directors ofEnbridge. We have included in the following tables, the full amount ofcompensation and related benefits provided for the NEOs for 2006, together withthe approximate amount of compensation cost allocated to us for the year ended December 31,2006.

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**SUMMARYCOMPENSATION TABLE**

| Name and Principal  Position | ** ** | ** ** | ** ** | **Year** | ** ** | **Salary  ($)** | ** ** | **Bonus**

**($)** | ** ** | **Stock  Awards**(1)  ($) | ** ** | **Option  Awards**(2)  ($) | ** ** | **Non-Equity  Incentive  Plan  Compensation**(3)  ($) | ** ** | **Change in  Pension  Value and  Nonqualified  Deferred  Compensation  Earnings  ($)** | ** ** | **All  Other  Compensation**(4)  ($) | ** ** | **Total  ($)** | ** ** | **Approximate  Amount  Allocated to  Enbridge  Energy  Partners,  L.P.  ($)** | ** ** |
|----------------------------------------|------------|------------|------------|----------|------------|-----------------|------------|--------------------|------------|---------------------------|------------|----------------------------|------------|-------------------------------------------------------|------------|--------------------------------------------------------------------------------------------------|------------|--------------------------------------|------------|----------------|------------|------------------------------------------------------------------------------------|------------|

| S.J.J. Letwin(5)                                              |   |   | 2006   |   |   | $       | 457,257 |   |   | $      | — |   |   |   | $      | 108,600 |   |   |   | $      | 68,362  |   |   |   | $       | 450,000 |   |   |   | $      | 208,000 |      |   |   | $       | 156,165 |   |   | $ | 1,448,384 |   |   | $ | — |   |   |
|---------------------------------------------------------------|--------|--------|--------|--------|--------|---------|---------|--------|--------|--------|--------|--------|--------|--------|--------|---------|--------|--------|--------|--------|---------|--------|--------|--------|---------|---------|--------|--------|--------|--------|---------|-----------|--------|--------|---------|---------|--------|--------|---|-----------|--------|--------|---|--------|--------|--------|
| Managing Director*(Principal Executive  Officer)*             |   |   |   |   |   |    |    |   |   |   |   |   |   |   |   |    |   |   |   |   |    |   |   |   |    |    |   |   |   |   |    |      |   |   |    |    |   |
| D.C. Tutcher                                                  |   |   | 2006   |   |   | 145,441 |    |   | — |   |   |   | — |   |   |    | — |   |   |   | 90,000  |   |   |   | 200,000 |    |   |   | 39,971 |   |    | 475,412   |   |   | 400,000 |    |   |
| President—Retired*(Former Principal  Executive Officer)* |   |   |   |   |   |    |    |   |   |   |   |   |   |   |   |    |   |   |   |   |    |   |   |   |    |    |   |   |   |   |    |      |   |   |    |    |   |
| T.L. McGill                                                   |   |   | 2006   |   |   | 290,000 |    |   | — |   |   |   | 38,535 |   |   |    | 24,055 |   |   |   | 200,000 |   |   |   | 103,000 |    |   |   | 33,225 |   |    | 688,815   |   |   | 585,000 |    |   |
| President                                                     |   |   |   |   |   |    |    |   |   |   |   |   |   |   |   |    |   |   |   |   |    |   |   |   |    |    |   |   |   |   |    |      |   |   |    |    |   |
| J. R. Bird(6)                                                 |   |   | 2006   |   |   | 419,937 |    |   | — |   |   |   | 98,090 |   |   |    | 61,488 |   |   |   | 440,878 |   |   |   | 512,000 |    |   |   | 50,806 |   |    | 1,583,199 |   |   | 190,000 |    |   |
| Executive  Vice  President—Liquids  Pipelines            |   |   |   |   |   |    |    |   |   |   |   |   |   |   |   |    |   |   |   |   |    |   |   |   |    |    |   |   |   |   |    |      |   |   |    |    |   |
| M.A. Maki                                                     |   |   | 2006   |   |   | 212,500 |    |   | — |   |   |   | 22,187 |   |   |    | 14,131 |   |   |   | 140,000 |   |   |   | 71,000  |    |   |   | 30,842 |   |    | 490,660   |   |   | 420,000 |    |   |
| Vice President—  Finance*(Principal Financial Officer)*  |   |   |   |   |   |    |    |   |   |   |   |   |   |   |   |    |   |   |   |   |    |   |   |   |    |    |   |   |   |   |    |      |   |   |    |    |   |
| R.L. Adams                                                    |   |   | 2006   |   |   | 189,375 |    |   | — |   |   |   | 19,852 |   |   |    | 12,731 |   |   |   | 117,000 |   |   |   | 55,000  |    |   |   | 29,661 |   |    | 423,619   |   |   | 360,000 |    |   |
| Vice  President—  Operations and  Technology             |   |   |   |   |   |    |    |   |   |   |   |   |   |   |   |    |   |   |   |   |    |   |   |   |    |    |   |   |   |   |    |      |   |   |    |    |   |
| J.A. Loiacono                                                 |   |   | 2006   |   |   | 181,458 |    |   | — |   |   |   | — |   |   |    | 11,330 |   |   |   | 121,000 |   |   |   | 41,000  |    |   |   | 23,428 |   |    | 378,216   |   |   | 320,000 |    |   |
| Vice President—  Commercial Activities              |   |   |   |   |   |    |    |   |   |   |   |   |   |   |   |    |   |   |   |   |    |   |   |   |    |    |   |   |   |   |    |      |   |   |    |    |   |

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(1)                    The expense associated with Performance Stock Units(PSUs) is reflected in this column and is measured based on the number ofrespective units granted, the percentage vested (33%) and the current marketprice of the Company’s shares in Canadian dollars, or CAD, of $39.73. Theexpense has been converted to United States dollars, or USD, using the averageexchange rate during 2006 of $1.1341 CAD = $1 USD. The PSUs were granted on January 1,2006.

(2)                    The annual expense is determined by computing the fairvalue of the options under FAS 123(R) on the grant date using theBlack-Scholes option pricing model with the following assumptions:

·          8 years expected term;

·          19% expected volatility;

·          3.23% expected dividend yield; and

·          4.16% risk free interest rate

Thefair value of options granted as computed using these assumptions is expensedover the shorter of the vesting period for the options (generally 4 years) andthe period to early retirement eligibility. The exercise price was $36.47 CADfor all option grants in 2006, which have been converted to United Statesdollars using the exchange rate on the grant date of $1.1548 CAD =$1 USD. Thefair value of all grants on the grant date was $6.28 CAD and have beenconverted to USD using the average exchange rate during 2006 of $1.1341 CAD =$1 USD, representing the exchange rate for the period during which the expensewas recognized.

(3)                    Non-equity incentive plan compensationrepresents awards that are paid in February for amounts that are earned inthe immediately preceding fiscal year under the Enbridge Short Term IncentivePlan, or STIP. The Enbridge STIP is a performance-based plan where measurementmetrics are established at the beginning of each fiscal year that promote theachievement of financial, safety, corporate governance and individual goals.

(4)                    The table which follows labeled “All OtherCompensation” sets forth the elements comprising the amounts presented in thiscolumn.

(5)                    Mr. Letwin relocated to the UnitedStates on May 1, 2006, and became Managing Director of our general partnerand Enbridge Management concurrent with the retirement of Mr. Tutcher. Mr. Letwinis also an executive officer of Enbridge with responsibility for other Enbridgeoperations in addition to those of our general partner, Enbridge Management,and us, that he assumed in May 2006. We have included the full amount of Mr. Letwin’scompensation in the summary compensation table. However, we were not chargedthe cost of Mr. Letwin’s compensation for the period from January 1,2006 through December 31, 2006, since the allocation to us of compensationto Mr. Letwin was not contemplated in our budget. As a result, Mr. Letwin’scompensation was borne by other Enbridge affiliates. In the future, we will becharged for an allocable portion of the compensation paid to Mr. Letwinprimarily based on the time that he spends overseeing our operations. We used aweighted average exchange rate of $1.1519 CAD = $1.0 USD to convert thecompensation costs to USD for Mr. Letwin, which represents the weightedaverage exchange rate for the period from May 1, 2006 through December 31,2006. The costs associated with the PSU’s and options Mr. Letwin wasgranted in 2006 were borne by Enbridge and other affiliates where he is also anofficer because the grants occurred prior to his becoming managing director ofour general partner and Enbridge Management.

(6)                    Mr. Bird is also an executive officerof Enbridge with responsibility for other affiliates of Enbridge in addition tothose for our general partner and Enbridge Management. Mr. Bird iscompensated by affiliates of Enbridge in CAD which we have converted to USDusing the weighted average exchange rate from January 1, 2006 through December 31,2006 of $1.1341 CAD = $1.0 USD. The costs associated with the PSU’s and optionsMr. Bird was granted in 2006 were borne by Enbridge and other affiliateswhere he is also an officer. We are allocated a portion of the remainingelements of Mr. Bird’s compensation based on the approximate percentage oftime he devotes to us and Enbridge Management.

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**ALLOTHER COMPENSATION(year ended December 31, 2006)**

| Name          | ** ** | ** ** | ** ** | **Year** | ** ** | **Flexible  Benefits**(1) | ** ** | **401(k)  Matching  Contribution**(2) | ** ** | **Relocation  Allowance** | ** ** | **Mortgage  Interest  Payments** | ** ** | **Other  Benefits**(3) | ** ** | **Total** | ** ** |
|---------------|------------|------------|------------|----------|------------|---------------------------|------------|---------------------------------------|------------|---------------------------|------------|----------------------------------|------------|------------------------|------------|-----------|------------|
| S.J.J. Letwin |       | 2006       |       |     | 35,169     |                      |       |                                  | 11,000     |                      |       |                             | 77,500     |                   |       |      | 25,701     |   |   |   | 6,795 |   |   | 156,165 |   |
| D.C. Tutcher  |       | 2006       |       |     | 30,000     |                      |       |                                  | 7,137      |                      |       |                             | —     |                   |       |      | —     |   |   |   | 2,834 |   |   | 39,971 |   |
| T.L. McGill   |       | 2006       |       |     | 20,000     |                      |       |                                  | 11,000     |                      |       |                             | —     |                   |       |      | —     |   |   |   | 2,225 |   |   | 33,225 |   |
| J.R. Bird     |       | 2006       |       |     | 48,482     |                      |       |                                  | —     |                      |       |                             | —     |                   |       |      | —     |   |   |   | 2,324 |   |   | 50,806 |   |
| M.A. Maki     |       | 2006       |       |     | 20,000     |                      |       |                                  | 10,625     |                      |       |                             | —     |                   |       |      | —     |   |   |   | 217 |   |   | 30,842 |   |
| R.L. Adams    |       | 2006       |       |     | 20,000     |                      |       |                                  | 9,469      |                      |       |                             | —     |                   |       |      | —     |   |   |   | 192 |   |   | 29,661 |   |
| J.A. Loiacono |       | 2006       |       |     | 14,167     |                      |       |                                  | 9,073      |                      |       |                             | —     |                   |       |      | —     |   |   |   | 188 |   |   | 23,428 |   |

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(1)                Flexible benefitsare provided to our NEOs based on their family status and base salary. For ourNEOs that are domiciled in the United States, the flexible benefits can be (a) usedto purchase additional benefits such as extended health, dental, disability andlife insurance on the same terms as are available to all employees; or (b) paidas additional compensation. NEOs domiciled in Canada may also defer a portionof the flexible benefits to be applied as contributions to the Enbridge StockPurchase and Savings Plan.

(2)                Our NEOs that aredomiciled in the United States and participate in the Enbridge EmployeeServices, Inc. Savings Plan (the “401(k) Plan”) may contribute up to50 percent of their base salary which is matched up to 5 percent by Enbridge. Bothindividual and matching contributions are subject to limits established by theInternal Revenue Service. Enbridge contributions are used to purchase Enbridgeshares at market value and employee contributions may be used to purchaseEnbridge shares or 22 designated funds.

(3)                Other benefitsinclude professional financial services, term life insurance premiums, parking,and home security and internet services.

We do not maintain any compensation plans for thebenefit of the NEOs under which equity interests in Enbridge Management or thePartnership may be awarded. However, Enbridge allocates to us the compensationexpense it recognizes under FAS 123(R) in connection with recording thefair value of its restricted stock units and outstanding stock options grantedto certain of our officers, including the NEOs. The costs we are charged withrespect to option grants represents a portion of the costs determined inaccordance with U.S. GAAP.

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The restricted stock unitsare granted to the NEOs pursuant to the Enbridge Inc. Restricted Stock UnitPlan (2006) and stock options are granted pursuant to the Enbridge IncentiveStock Option Plan. Awards under these plans provide long-term incentive and areadministered by the Human Resources & Compensation Committee ofEnbridge. The restricted stock units and stock option grants are denominated inCanadian dollars. The following two tables set forth information concerningrestricted stock units and stock options outstanding at December 31, 2006,and the number of awards vested and exercised during the year ended December 31,2006, by each of the NEOs:

**GRANTSOF PLAN-BASED AWARDS**

|               | ** ** | ** ** | ** ** | ** **             | ** ** | ** **              | ** ** | **Estimated Future Payouts  Under non-Equity Incentive  Plan Awards**(4) | ** ** | **Estimated Future Payouts  Under Equity Incentive Plan  Awards**(2) | ** ** | **All  Other  Stock  Awards:  Number  of  Shares  of Stock** | ** ** | **All Other  Option  Awards:  Number  of  Securities  Underlying** | ** ** | **Exercise  or Base  Price of  Option** | ** ** | **Grant Date  Fair  Value of  Stock and  Option** | ** ** |
|---------------|------------|------------|------------|------------------------|------------|-------------------------|------------|---------------------------------------------------------------------------------------------------|------------|-----------------------------------------------------------------------------------------------|------------|-------------------------------------------------------------------|------------|-------------------------------------------------------------------------|------------|---------------------------------------------------|------------|------------------------------------------------------------------|------------|
| **Name  (a)** | ** ** | ** ** | ** ** | **Plan  Name**(1)  (b) | ** ** | **Approval  Date  (b)** | ** ** | **Grant  Date  (c)**                                                                              | ** ** | **Threshold  ($)  (d)**                                                                       | ** ** | **Target  ($)  (e)**                                              | ** ** | **Maximum  ($)  (f)**                                                   | ** ** | **Threshold  (#)  (g)**                           | ** ** | **Target  (#)  (h)**                                             | ** ** | **Maximum  (#)  (i)** | ** ** | **or Units  (#)  (j)** | ** ** | **Options**(3)  (#)  (k) | ** ** | **Awards**(3)  ($/Sh)  (l) | ** ** | **Awards**(2)(3)  ($)  (j) | ** ** |
|               |            |            |            |                        |            |                         |            |                                                                                                   |            |                                                                                               |            |                                                                   |            |                                                                         |            |                                                   |            |                                                                  |            |  |  |  |  |  |  |  |  |  |  |

| S.J.J. Letwin   |   |   | PSUP |   |   |   | 1-Feb-06 |   |   | 1-Jan-06  |   |   | — |   |   | —  |   |   | —  |   |   |   | 372    |   |   |   | 9,300  |   |   |   | 18,600 |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | 290,379 |   |   |
|-----------------|--------|--------|------|--------|--------|--------|----------|--------|--------|-----------|--------|--------|--------|--------|--------|---------|--------|--------|---------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|---------|--------|--------|
|                 |   |   | ISOP |   |   |   | 1-Feb-06 |   |   | 13-Feb-06 |   |   | — |   |   | —  |   |   | —  |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | 53,700 |   |   |   | 31.58  |   |   |   | 292,901 |   |   |
|                 |   |   | STIP |   |   |   | 1-Feb-06 |   |   | 28-Feb-06 |   |   | — |   |   | 232,500 |   |   | 465,000 |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | —  |   |   |
| D.C. Tutcher(5) |   |   | STIP |   |   |   | 1-Feb-06 |   |   | 28-Feb-06 |   |   | — |   |   | 58,333  |   |   | 116,667 |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | —  |   |   |
| T.L. McGill     |   |   | PSUP |   |   |   | 1-Feb-06 |   |   | 1-Jan-06  |   |   | — |   |   | —  |   |   | —  |   |   |   | 132    |   |   |   | 3,300  |   |   |   | 6,600  |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | 103,038 |   |   |
|                 |   |   | ISOP |   |   |   | 1-Feb-06 |   |   | 13-Feb-06 |   |   | — |   |   | —  |   |   | —  |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | 18,900 |   |   |   | 31.58  |   |   |   | 103,088 |   |   |
|                 |   |   | STIP |   |   |   | 1-Feb-06 |   |   | 28-Feb-06 |   |   | — |   |   | 120,000 |   |   | 240,000 |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | —  |   |   |
| J.R. Bird       |   |   | PSUP |   |   |   | 1-Feb-06 |   |   | 1-Jan-06  |   |   | — |   |   | —  |   |   | —  |   |   |   | 336    |   |   |   | 8,400  |   |   |   | 16,800 |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | 262,278 |   |   |
|            |   |   | ISOP |   |   |   | 1-Feb-06 |   |   | 13-Feb-06 |   |   | — |   |   | —  |   |   | —  |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | 48,300 |   |   |   | 31.58  |   |   |   | 263,447 |   |   |
|            |   |   | STIP |   |   |   | 1-Feb-06 |   |   | 28-Feb-06 |   |   | — |   |   | 213,826 |   |   | 427,652 |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | —  |   |   |
| M.A. Maki       |   |   | PSUP |   |   |   | 1-Feb-06 |   |   | 1-Jan-06  |   |   | — |   |   | —  |   |   | —  |   |   |   | 76     |   |   |   | 1,900  |   |   |   | 3,800  |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | 59,325  |   |   |
|                 |   |   | ISOP |   |   |   | 1-Feb-06 |   |   | 13-Feb-06 |   |   | — |   |   | —  |   |   | —  |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | 11,100 |   |   |   | 31.58  |   |   |   | 60,544  |   |   |
|                 |   |   | STIP |   |   |   | 1-Feb-06 |   |   | 28-Feb-06 |   |   | — |   |   | 84,000  |   |   | 168,000 |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | —  |   |   |
| R.L. Adams      |   |   | PSUP |   |   |   | 1-Feb-06 |   |   | 1-Jan-06  |   |   | — |   |   | —  |   |   | —  |   |   |   | 68     |   |   |   | 1,700  |   |   |   | 3,400  |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | 53,080  |   |   |
|            |   |   | ISOP |   |   |   | 1-Feb-06 |   |   | 13-Feb-06 |   |   | — |   |   | —  |   |   | —  |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | 10,000 |   |   |   | 31.58  |   |   |   | 54,544  |   |   |
|            |   |   | STIP |   |   |   | 1-Feb-06 |   |   | 28-Feb-06 |   |   | — |   |   | 67,375  |   |   | 134,750 |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | —  |   |   |
| J.A. Loiacono   |   |   | ISOP |   |   |   | 1-Feb-06 |   |   | 13-Feb-06 |   |   | — |   |   | —  |   |   | —  |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | 8,900  |   |   |   | 31.58  |   |   |   | 48,544  |   |   |
|                 |   |   | STIP |   |   |   | 1-Feb-06 |   |   | 28-Feb-06 |   |   | — |   |   | 67,375  |   |   | 134,750 |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | —  |   |   |

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(1)         The abbreviated plan names are defined as follows:

a.          PSUP refers to the Enbridge Performance Stock UnitPlan, an equity-based incentive plan.

b.          ISOP refers to the Enbridge Incentive Stock OptionPlan, a qualified stock option plan.

c.          STIP refers to the Enbridge Short Term Incentive Plan,a non-equity performance-based incentive plan.

(2)         Our NEOs are eligible to receive annual grants ofPerformance Stock Units, or PSUs, under the Performance Stock Unit Plan, orPSUP, an equity-based, long-term incentive plan, administered by a committee ofthe board of directors of Enbridge. The initial value of each of these PSUs isequivalent to the market value of one Enbridge share on the grant date. Theinitial PSUs granted are increased for quarterly dividends paid during thethree-year period on an Enbridge share. Awards under the PSUP are paid out incash at the end of a three-year performance cycle based on: (1) the marketvalue of an Enbridge share at the end of the three-year period; and (2) thetotal shareholder return for Enbridge over a three-year period in relation to apeer group of companies established in advance by a committee of the board ofdirectors of Enbridge. Payments under the PSUP may be increased up to 200percent of the original award when Enbridge outperforms its peer group. IfEnbridge fails to meet threshold performance levels, no payments are made underthe PSUP. Enbridge does not issue any shares in connection with the PSUP.

The threshold at which PSUsare issued represents 4 percent of the number of PSUs initially granted and isthe lowest level at which PSUs will be issued based on the performance criteriadiscussed above. The target level at which PSUs are issued represents 100percent of the number of PSUs initially granted and attainment of theestablished performance criteria. The maximum level at which PSUs may be issuedis 200 percent of the number of PSUs initially granted and may occur whenEnbridge exceeds the established performance criteria.

PSUs vest at the end of athree year performance period that begins on January 1 of the year grantedand during the term the PSUs are outstanding, a liability and expense arerecorded by Enbridge based on the number of PSUs outstanding and the currentmarket price of an Enbridge share. The grant date fair value for each PSUgranted to each of our NEOs was $36.13 CAD, representing the weighted averageclosing price of one Enbridge share as quoted on the Toronto Stock Exchange forthe 30 days immediately preceding the start of the performance period thatbegan on January 1, 2006. We have converted the grant date fair value foreach of the PSU grants made from CAD to USD using an exchange rate of $1.1571CAD per $1.00 USD, representing the noon buying rate in New York for transfersof CAD on January 3, 2006, the first business day of the performanceperiod that began on January 1, 2006.

(3)         The Enbridge Incentive Stock Option Plan (2002) isadministered by a committee of the Enbridge board of directors and if an optionis issued during a trading blackout period, the exercise price of an optiongrant is determined as the weighted average trading price of an Enbridge shareon the Toronto Stock Exchange for the three trading days immediately prior tothe effective date of the option. In the event an option grant is issued duringa period a trading blackout is not in effect, the exercise price of the optiongrant is equal to the last reported sales price on the Toronto Stock Exchangefor the day immediately preceding the grant date. During 2006, each of the NEOsreceived grants of Enbridge incentive stock options that upon exercise may beexchanged for an equivalent number of shares of Enbridge common stock. The 

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exercise price ofthe incentive stock options at the time of grant was $36.47 CAD which has beenconverted into USD using an exchange rate of $1.1548 CAD per $1 USD,representing the noon buying rate in New York for transfers of CAD on the grantdate of February 13, 2006.

Theamounts included as the grant date fair value for the 2006 incentive stockoption awards represent the amount determined by computing the fair value ofthe options under FAS 123(R) on the grant date using the Black-Scholesoption pricing model with the following assumptions:

·     8 years expected term;

·     19% expected volatility;

·     3.23% expected dividend yield; and

·     4.16% risk free interest rate

Thefair value of options granted as computed using these assumptions is $6.28 CADwhich has been converted to USD using an exchange rate of $1.1548 CAD = $1 USDwhich equates to a grant date fair value of $5.45 USD per option granted. Thegrant date fair value is expensed over the shorter of the vesting period forthe options (generally 4 years) and the period to early retirement eligibility.

(4)         The estimated future payouts under the Enbridge STIPare determined for the indicated fiscal year, based upon achievement ofperformance goals established at the beginning of the fiscal year for each ofthe NEOs. The payouts earned under the STIP for each fiscal year are generallypaid to the NEO on the last business day of February of the year followingthe fiscal year in which the payout is earned. The performance goals includepre-determined financial, safety, corporate governance and operational goalsthat are aligned with the business objectives for Enbridge and the businessunit(s) to which the NEOs are assigned, in addition to individualperformance objectives. Based upon the level achieved in meeting thepre-determined objectives, a multiple is determined that can vary from a low ofzero, if the level of achievement is significantly below the stated objectives,to a high of two, if the level of achievement significantly exceeds the statedobjective, with the mid-point or target representing achievement of 100 percentof the pre-established goals. The multiple is then applied to the bonus level,represented as a percentage of base salary, for each NEO. The STIP targets foreach NEO expressed as a percentage of salary for 2006 is as follows:

|               | ** ** | **Threshold** | ** ** | **Target** | ** ** | **Maximum** | ** ** |
|---------------|------------|---------------|------------|------------|------------|-------------|------------|
| S.J.J. Letwin |       |          | —     |       |       |        | 50         | % |   |   | 100 | % |   |
| D.C. Tutcher  |       |          | —     |       |       |        | 50         | % |   |   | 100 | % |   |
| T.L. McGill   |       |          | —     |       |       |        | 40         | % |   |   | 80 | % |   |
| J.R. Bird     |       |          | —     |       |       |        | 50         | % |   |   | 100 | % |   |
| M.A. Maki     |       |          | —     |       |       |        | 35         | % |   |   | 70 | % |   |
| R.L. Adams    |       |          | —     |       |       |        | 35         | % |   |   | 70 | % |   |
| J.A. Loiacono |       |          | —     |       |       |        | 35         | % |   |   | 70 | % |   |

 

(5)         Upon Mr. Tutcher’sretirement effective May 1, 2006, 67,500 of unvested incentive stockoptions were vested pursuant to the terms of the ISOP and became exercisableuntil June 2, 2006, and 56,667 performance stock options were cancelled. Inaddition, Mr. Tutcher’s PSUs granted in 2004 and 2005 continue to receivedividends and will be paid out on a pro rata basis within 60 day followingcompletion of the performance period.

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**OUTSTANDING EQUITY AWARDS AT FISCAL YEAR END**

|               | ** ** | **Option Awards**  | ** ** | **Stock Awards**   | ** ** |
|---------------|------------|--------------------|------------|--------------------|------------|
| ** **    | ** ** | ** **         | ** ** | ** **         | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | **Equity** | ** ** |
| ** **    | ** ** | ** **         | ** ** | ** **         | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | **Incentive** | ** ** |
| ** **    | ** ** | ** **         | ** ** | ** **         | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | **Equity** | ** ** | **Plan** | ** ** |
| ** **    | ** ** | ** **         | ** ** | ** **         | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | **Incentive** | ** ** | **Awards:** | ** ** |
| ** **    | ** ** | ** **         | ** ** | ** **         | ** ** | **Equity** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | **Plan** | ** ** | **Market or** | ** ** |
| ** **    | ** ** | ** **         | ** ** | ** **         | ** ** | **Incentive** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | **Market** | ** ** | **Awards:** | ** ** | **Payout** | ** ** |
| ** **    | ** ** | ** **         | ** ** | **Number of** | ** ** | **Plan Awards:** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | ** ** | **Value of** | ** ** | **Number of** | ** ** | **Value of** | ** ** |
| ** **    | ** ** | **Number of** | ** ** | **Securities**     | ** ** | **Number of** | ** ** | ** ** | ** ** | ** ** | ** ** | **Number** | ** ** | **Shares or** | ** ** | **Unearned** | ** ** | **Unearned** | ** ** |
| ** **    | ** ** | **Securities**     | ** ** | **Underlying**     | ** ** | **Securities** | ** ** | ** ** | ** ** | ** ** | ** ** | **of Shares** | ** ** | **Units of** | ** ** | **Shares,** | ** ** | **Shares,** | ** ** |
| ** **    | ** ** | **Underlying**     | ** ** | **Unexercised**    | ** ** | **Underlying** | ** ** | ** ** | ** ** | ** ** | ** ** | **or Units** | ** ** | **Stock** | ** ** | **Units or** | ** ** | **Units or** | ** ** |
| ** **    | ** ** | **Unexercised**    | ** ** | **Options**        | ** ** | **Unexercised** | ** ** | **Option** | ** ** | ** ** | ** ** | **of Stock** | ** ** | **That** | ** ** | **Other Rights** | ** ** | **Other Rights** | ** ** |
| ** **    | ** ** | **Options**        | ** ** | **(#)**            | ** ** | **Unearned** | ** ** | **Exercise** | ** ** | **Option** | ** ** | **That Have** | ** ** | **Have Not** | ** ** | **That Have** | ** ** | **That Have** | ** ** |
| ** **    | ** ** | **(#)**            | ** ** | **Unexercisable**  | ** ** | **Options** | ** ** | **Price** | ** ** | **Expiration** | ** ** | **Not Vested** | ** ** | **Vested** | ** ** | **Not Vested**(3) | ** ** | **Not Vested** | ** ** |
| **Name**      | ** ** | ** **         | ** ** | **Exercisable**    | ** ** | **(1)(2)** | ** ** | **(#)** | ** ** | **($)** | ** ** | **Date**(1) | ** ** | **(#)** | ** ** | **($)** | ** ** | **(#)** | ** ** | **($)** | ** ** |
| **(a)**       | ** ** | ** **         | ** ** | **(b)**            | ** ** | **(c)** | ** ** | **(d)** | ** ** | **(e)** | ** ** | **(f)** | ** ** | **(g)** | ** ** | **(h)** | ** ** | **(i)** | ** ** | **(j)** | ** ** |
| S.J.J. Letwin |       |               | —     |               |       |   | 40,000 | (2) |   |   | — |   |   |   | 14.63 |   |   |   | 16-Sep-10 |   |   |   | — |   |   |   | — |   |   |   | 9,759 |   |   |   | 337,228 |   |   |
|               |       |               | —     |               |       |   | 20,000 |   |   |   | — |   |   |   | 13.69 |   |   |   | 6-Feb-13 |   |   |   | — |   |   |   | — |   |   |   | 10,508 |   |   |   | 363,114 |   |   |
|               |       |               | —     |               |       |   | 22,000 |   |   |   | — |   |   |   | 19.30 |   |   |   | 4-Feb-14 |   |   |   | — |   |   |   | — |   |   |   | 9,597 |   |   |   | 331,622 |   |   |
|               |       |               | 13,100     |               |       |   | 39,300 |   |   |   | — |   |   |   | 25.49 |   |   |   | 3-Feb-15 |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
|               |       |               | —     |               |       |   | 53,700 |   |   |   | — |   |   |   | 31.58 |   |   |   | 13-Feb-16 |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| D.C. Tutcher  |       |               | 143,333    | (2)                |       |   | — |   |   |   | — |   |   |   | 14.63 |   |   |   | 2-May-09 |   |   |   | — |   |   |   | — |   |   |   | 7,740 |   |   |   | 267,444 |   |   |
|          |       |               |       |               |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   | — |   |   |   | — |   |   |   | 7,541 |   |   |   | 260,574 |   |   |
| T.L. McGill   |       |               | 34,800     |               |       |   | 11,600 |   |   |   | — |   |   |   | 13.69 |   |   |   | 6-Feb-13 |   |   |   | — |   |   |   | — |   |   |   | 3,063 |   |   |   | 105,847 |   |   |
|               |       |               | 20,000     |               |       |   | 20,000 |   |   |   | — |   |   |   | 19.30 |   |   |   | 4-Feb-14 |   |   |   | — |   |   |   | — |   |   |   | 3,405 |   |   |   | 117,672 |   |   |
|               |       |               | 5,100      |               |       |   | 15,300 |   |   |   | — |   |   |   | 25.49 |   |   |   | 3-Feb-15 |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
|               |       |               | —     |               |       |   | 18,900 |   |   |   | — |   |   |   | 31.58 |   |   |   | 13-Feb-16 |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| J.R. Bird     |       |               | 160,000    |               |       |   | 40,000 | (2) |   |   | — |   |   |   | 14.63 |   |   |   | 16-Sep-10 |   |   |   | — |   |   |   | — |   |   |   | 7,401 |   |   |   | 255,750 |   |   |
|          |       |               | 20,000     |               |       |   | 20,000 |   |   |   | — |   |   |   | 13.69 |   |   |   | 6-Feb-13 |   |   |   | — |   |   |   | — |   |   |   | 8,296 |   |   |   | 286,669 |   |   |
|          |       |               | 16,700     |               |       |   | 16,700 |   |   |   | — |   |   |   | 19.30 |   |   |   | 4-Feb-14 |   |   |   | — |   |   |   | — |   |   |   | 8,668 |   |   |   | 299,529 |   |   |
|          |       |               | 10,350     |               |       |   | 31,050 |   |   |   | — |   |   |   | 25.49 |   |   |   | 3-Feb-15 |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
|          |       |               | —     |               |       |   | 48,300 |   |   |   | — |   |   |   | 31.58 |   |   |   | 13-Feb-16 |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| M.A. Maki     |       |               | 7,500      |               |       |   | — |   |   |   | — |   |   |   | 12.43 |   |   |   | 21-Feb-11 |   |   |   | — |   |   |   | — |   |   |   | 2,276 |   |   |   | 78,650 |   |   |
|               |       |               | 16,000     |               |       |   | — |   |   |   | — |   |   |   | 13.68 |   |   |   | 5-Feb-12 |   |   |   | — |   |   |   | — |   |   |   | 1,961 |   |   |   | 67,751 |   |   |
|               |       |               | 25,050     |               |       |   | 8,350 |   |   |   | — |   |   |   | 13.69 |   |   |   | 6-Feb-13 |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
|               |       |               | 15,000     |               |       |   | 15,000 |   |   |   | — |   |   |   | 19.30 |   |   |   | 4-Feb-14 |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
|               |       |               | 2,850      |               |       |   | 8,550 |   |   |   | — |   |   |   | 25.49 |   |   |   | 3-Feb-15 |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
|               |       |               | —     |               |       |   | 11,100 |   |   |   | — |   |   |   | 31.58 |   |   |   | 13-Feb-16 |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| R.L. Adams    |       |               | 750        |               |       |   | 3,750 |   |   |   | — |   |   |   | 13.69 |   |   |   | 6-Feb-13 |   |   |   | — |   |   |   | — |   |   |   | 2,148 |   |   |   | 74,240 |   |   |
|          |       |               | 5,000      |               |       |   | 10,000 |   |   |   | — |   |   |   | 19.30 |   |   |   | 4-Feb-14 |   |   |   | — |   |   |   | — |   |   |   | 1,754 |   |   |   | 60,619 |   |   |
|          |       |               | 2,700      |               |       |   | 8,100 |   |   |   | — |   |   |   | 25.49 |   |   |   | 3-Feb-15 |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
|          |       |               | —     |               |       |   | 10,000 |   |   |   | — |   |   |   | 31.58 |   |   |   | 13-Feb-16 |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| J.A. Loiacono |       |               | 1,700      |               |       |   | — |   |   |   | — |   |   |   | 13.04 |   |   |   | 1-Jul-10 |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   |
|               |       |               | 5,000      |               |       |   | — |   |   |   | — |   |   |   | 13.68 |   |   |   | 5-Feb-12 |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
|               |       |               | 1,800      |               |       |   | 1,200 |   |   |   | — |   |   |   | 13.69 |   |   |   | 6-Feb-13 |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
|               |       |               | 4,000      |               |       |   | 4,000 |   |   |   | — |   |   |   | 19.30 |   |   |   | 4-Feb-14 |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
|               |       |               | 2,500      |               |       |   | 7,500 |   |   |   | — |   |   |   | 25.49 |   |   |   | 3-Feb-15 |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
|               |       |               | —     |               |       |   | 8,900 |   |   |   | — |   |   |   | 31.58 |   |   |   | 13-Feb-16 |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |

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(1)        Each incentive stock option award has a ten year termand vests pro rata as to one-fourth of the option award beginning on the firstanniversary of the grant date thus, the vesting dates for each of the optionawards in this table can be calculated accordingly. As an example, for Mr. Letwin’sgrant that expires on February 6, 2013, the grant date would be ten yearsprior or February 6, 2003 and as a result, the remaining unexercisableamounts become fully vested on February 6, 2007 representing four yearsfollowing the grant date.

(2)        Performance-based stock options, or PBSOs, which wereprovided to certain of our NEOs on September 16, 2002, that are similar tothe incentive stock options, except that the quantity that become exercisableare subject to both time and performance requirements. PBSOs are granted on aninfrequent basis and provide the eligible NEO the opportunity to acquire oneEnbridge Share for each option held when the specified time and performanceconditions are met. The PBSOs became exercisable, as to 50 percent of thegrant, when the price of an Enbridge Share exceeded $30.50 CAD for 20consecutive trading days during the period September 16, 2002 to September 16,2007, and became exercisable as to 100 percent when the price of an Enbridgeshare exceeded $35.50 CAD for 20 consecutive trading days during the sameperiod. As a result of achieving the established performance criteria, theinitial five year term of the options was extended to eight years expiring on September 16,2010. In addition to the performance hurdles, the PBSOs are also time vested20% annually over 5 years. As of December 31, 2006, 80 percent of the PBSOs had vested andwere exercisable and the remaining 20 percent will vest and become exercisableon September 16, 2007.

(3)        Theunearned shares, units or other rights that have not vested under stock awardsrepresent PSUs for which the performance criteria discussed in footnote number2 of the Grants of Plan-Based Awards table have not been achieved. The PSUsbecome vested upon achieving the established performance criteria as set forthin the aforementioned footnote.

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**OPTIONEXERCISES AND STOCK VESTED**

|               | ** ** | **Option Awards** | ** ** | **Stock Awards**                                       | ** ** |
|---------------|------------|------------------------|------------|-------------------------------------------------------------|------------|
| **Name**      | ** ** | ** **             | ** ** | **Number of  Shares  Acquired  on Exercise  (#)** | ** ** | **Value  Realized  on Exercise  ($)** | ** ** | **Number of  Shares  Acquired  on Vesting  (#)** | ** ** | **Value  Realized  on Vesting  ($)** | ** ** |
| S.J.J. Letwin |       |                   | 172,000    |                                                        |       | 2,058,154 |   |   | — |   |   |   | — |   |   |
| D.C. Tutcher  |       |                   | 589,694    |                                                        |       | 7,458,233 |   |   | — |   |   |   | — |   |   |
| T.L. McGill   |       |                   | 11,500     |                                                        |       | 165,319 |   |   | — |   |   |   | — |   |   |
| J.R. Bird     |       |                   | 200,000    |                                                        |       | 3,159,793 |   |   | — |   |   |   | — |   |   |
| M.A. Maki     |       |                   | 2,500      |                                                        |       | 35,911 |   |   | — |   |   |   | — |   |   |
| R.L. Adams    |       |                   | 6,300      |                                                        |       | 86,592 |   |   | — |   |   |   | — |   |   |
| J.A. Loiacono |       |                   | 7,300      |                                                        |       | 119,164 |   |   | — |   |   |   | — |   |   |
|               |            |                        |            |                                                             |            |  |  |  |  |  |  |  |  |  |  |  |  |

 

***Pension Plan***

Enbridge sponsors two basic pension plans, theRetirement Plan for Employees’ Annuity Plan (“EI RPP”) and the EnbridgeEmployee Services, Inc. Employees’ Annuity Plan (“QPP”), which providedefined pension benefits and cover employees in Canada and the United States,respectively. Both plans are non-contributory. The Company also sponsorssupplemental nonqualified retirement plans in both Canada (“EI SPP”) and theUnited States (“US SPP”), which provide pension benefits for the NEOs in excessof the tax-qualified plans’ limits. We collectively refer to the EI RPP, theQPP, the EI SPP and the US SPP as the “Pension Plans.”  Retirement benefits under the Pension Plansare based on the employees’ years of service and final average remunerationwith an offset for Social Security benefits. These benefits are partiallyindexed to inflation after a named executive officer’s retirement.

For service prior to January 1, 2000, the PensionPlans provide 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 PensionPlans provide for senior management employees, including the NEOs, a yearlypension payable after age 60 in the normal form (60 percent joint and lastsurvivor) equal to: (a) 2 percent of the sum of (i) the averageof the participant’s highest annual base salary during three consecutive yearsout of the last ten years of credited service and (ii) the average of theparticipant’s three highest annual performance bonus periods, represented ineach period by 50 percent of the actual bonus paid, in respect of the lastfive years of credited service, multiplied by (b) the number of creditedyears of service. An unreduced pension is payable if retirement is after age 55with 30 or more years of service, or after age 60. Early retirement reductionsapply if a participant retires and does not meet these requirements. Retirementbenefits paid from the Plan are indexed at 50 percent of the annualincrease in the consumer price index.

The table illustrates the total annual pensionentitlements assuming the eligibility requirements for an unreduced pensionhave been satisfied. Plan benefits that exceed maximum pension rules applicableto registered plan benefits are paid from the Enbridge supplemental pensionplans. Other trusteed pension plans, with varying contribution formulae andbenefits, cover the balance of employees.

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Mr. Bird accumulatedpension credits equal to 2.0% for each year of service from his date ofemployment until January 1, 2000 and 3.26% for each year of servicethereafter to his sixtieth birthday. Mr. Letwin was granted six additionalyears of credited service on his employment date based on the pension formulaapplicable for service prior to January 1, 2000. Mr. Tutcheraccumulated pension credits equal to 4.0% for each year of service to his tenthanniversary of employment with the Corporation.

**PENSIONBENEFITS**

| Name  (a)     | ** ** | ** ** | ** ** | **Plan  Name  (b)** | ** ** | **Number  Of Years  Credited  Service  (#)  (c)** | ** ** | **Present  Value of  Accumulated  Benefit  ($)  (d)** | ** ** | **Payments  During  Last Fiscal  Year  ($)  (e)** | ** ** |
|---------------|------------|------------|------------|---------------------|------------|--------------------------------------------------------|------------|------------------------------------------------------------|------------|--------------------------------------------------------|------------|
| S.J.J. Letwin |       | EI  RPP    |       |                | 7.08       |                                                   |       |                                                       | 169,000    |                                                   |       |   | — |   |   |
|               |       | EI  SPP    |       |                | 13.08      |                                                   |       |                                                       | 1,274,000  |                                                   |       |   | — |   |   |
|               |       | QPP        |       |                | 0.67       |                                                   |       |                                                       | 24,000     |                                                   |       |   | — |   |   |
|               |       | USSPP      |       |                | 0.67       |                                                   |       |                                                       | 62,000     |                                                   |       |   | — |   |   |
| D.C. Tutcher  |       | US QPP     |       |                | 4.76       |                                                   |       |                                                       | 208,000    |                                                   |       |   | 8,000 |   |   |
|          |       | US  SPP    |       |                | 4.92       |                                                   |       |                                                       | 1,200,000  |                                                   |       |   | 41,000 |   |   |
| T.L. McGill   |       | US QPP     |       |                | 4.83       |                                                   |       |                                                       | 72,000     |                                                   |       |   | — |   |   |
|               |       | US  SPP    |       |                | 4.83       |                                                   |       |                                                       | 280,000    |                                                   |       |   | — |   |   |
| J.R. Bird     |       | EI RPP     |       |                | 11.92      |                                                   |       |                                                       | 372,000    |                                                   |       |   | — |   |   |
|          |       | EI  SPP    |       |                | 11.92      |                                                   |       |                                                       | 2,191,000  |                                                   |       |   | — |   |   |
| M.A. Maki     |       | EI RPP     |       |                | 1.92       |                                                   |       |                                                       | 31,000     |                                                   |       |   | — |   |   |
|               |       | EI  SPP    |       |                | 1.92       |                                                   |       |                                                       | 29,000     |                                                   |       |   | — |   |   |
|               |       | US  QPP    |       |                | 18.40      |                                                   |       |                                                       | 392,000    |                                                   |       |   | — |   |   |
|               |       | US  SPP    |       |                | 5.50       |                                                   |       |                                                       | 74,000     |                                                   |       |   | — |   |   |
| R.L. Adams    |       | US QPP     |       |                | 20.20      |                                                   |       |                                                       | 395,000    |                                                   |       |   | — |   |   |
|          |       | US  SPP    |       |                | 5.50       |                                                   |       |                                                       | 63,000     |                                                   |       |   | — |   |   |
| J.A. Loiacono |       | US QPP     |       |                | 4.50       |                                                   |       |                                                       | 46,000     |                                                   |       |   | — |   |   |
|               |       | US SPP     |       |                | 3.75       |                                                   |       |                                                       | 80,000     |                                                   |       |   | — |   |   |

 

**Employment andSeverance Agreements**

Enbridge has employment and severance agreements inplace with each of Stephen J. J. Letwin, Managing Director and Chief ExecutiveOfficer of Enbridge Management and the General Partner, and J. RichardBird, Executive Vice President—Liquids Pipelines of Enbridge Management and theGeneral Partner. The agreements took effect on April 14, 2003 and wereamended effective June 24, 2004. The agreements continue in effect untilthe earlier of (i)  the applicable executive’s voluntary retirement inaccordance with the retirement policies established for senior employees ofEnbridge, (ii) such executive’s voluntary resignation, other than avoluntary resignation within 90 days after a “constructive dismissal” (asdefined in the agreements) or within one year following a change of control ofEnbridge, (iii) termination based on death or disability of suchexecutive, or (iv) termination of such executive’s employment by Enbridge.

The agreementsprovide that Enbridge will pay severance benefits to each of Mr. Letwinand Mr. Bird if (i) his employment is involuntarily terminatedwithout cause or because of his disability, (ii) he elects to terminatehis employment within 60 days of the first anniversary of the occurrence of achange of control of Enbridge, or (iii) he elects to terminate hisemployment within 60 days following constructive dismissal. 

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Ineach such instance, and subject to the terms of the agreements, Enbridge willpay to the applicable executive the following:

(a)           A lump sum paymentequal to two times the sum of: (i) twelve times the gross monthly salarypaid to him in the last full month of employment and (ii) the average ofthe last two years of the Enbridge Short Term Incentive Plan (STIP) awards paidto him;

(b)          A lump sum payment equalto two times the cash value of the last annual flex benefit credit allowanceprovided to him under Enbridge’s flexible benefit program, unless he continuesto be covered through Enbridge’s annuitant benefit program or the benefitsprogram of another employer;

(c)           A lump sum paymentequal to the value of his annual incentive bonus to be paid for the calendaryear in which termination occurs, pro rated based upon the number of days ofhis employment in such year;

(d)          A lump sum payment equalto the value of all of his accrued and unpaid annual vacation pay to the dateof his termination;

(e)           A lump sum paymentequal to two times the cash value of the last annual flexible perquisiteallowance provided to him under Enbridge’s flexible perquisites program, lessany amounts paid to him but unearned by virtue of such termination ofemployment; and

(f)             Payment for financialcounseling or career counseling assistance in an amount up to a maximum of$10,000.

The agreements also provide that each of Mr. Letwinand Mr. Bird are entitled to certain benefits, including two years ofadditional service added to the service already accrued at the date of histermination under the Enbridge defined benefit pension plan and supplementalbenefit pension plan and cash payment of certain non-vested options, if any,that are cancelled under the Incentive Stock Option Plan (ISOP) as aconsequence of termination of his employment. In the case of options grantedpursuant to the ISOP, the payment is calculated based on the in-the-money valueof the applicable executive’s non-vested option at the date of his termination.

According to theagreements, a “change of control” means:

·       thesale to a person or acquisition by a person not affiliated with Enbridge or itssubsidiaries of net assets of Enbridge or its subsidiaries having a valuegreater than 50% of the fair market value of the net assets of Enbridge and itssubsidiaries determined on a consolidated basis prior to such sale whether suchsale or acquisition occurs by way of reconstruction, reorganization,recapitalization, consolidation, amalgamation, arrangement, merger, transfer,sale or otherwise;

·       anychange in the holding, direct or indirect, of shares of Enbridge by a personnot affiliated with Enbridge as a result of which such person, or a group ofpersons, or persons acting in concert, or persons associated or affiliated withany such person or group within the meaning of the Securities Act (Alberta),are in a position to exercise effective control of Enbridge whether such changein the holding of such shares occurs by way of takeover bid, reconstruction,reorganization, recapitalization, consolidation, amalgamation, arrangement,merger, transfer, sale or otherwise; and for the purposes of this Agreement, aperson or group of persons holding shares or other securities in excess of thenumber which, directly or following conversion thereof, would entitle the holdersthereof to cast 20% or more of the votes attaching to all shares of Enbridgewhich, directly or following conversion of the convertible securities formingpart of the holdings of the person or group of persons noted above, may be castto elect directors of Enbridge shall be deemed, other than a person holdingsuch shares or other securities in the ordinary course of business as an 

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investment manager who isnot using such holding to exercise effective control, to be in a position toexercise effective control of Enbridge;

·       anyreconstruction, reorganization, recapitalization, consolidation, amalgamation,arrangement, merger, transfer, sale or other transaction involving Enbridgewhere shareholders of Enbridge immediately prior to such reconstruction, reorganization,recapitalization, consolidation, amalgamation, arrangement, merger, transfer,sale or other transaction hold less than 60% of the shares of Enbridge or ofthe continuing corporation following completion of such reconstruction,reorganization, recapitalization, consolidation, amalgamation, arrangement,transfer, sale or other transaction;

·       Enbridgeceases to be a distributing corporation as that term is defined in the CanadaBusiness Corporations Act;

·       anyevent or transaction which Enbridge board of directors, in its discretion,deems to be a change of control; or

·       Enbridgeboard of directors is no longer comprised of a majority of incumbent directors,who are defined as directors who were directors immediately prior to theoccurrence of the transaction, elections or appointments giving rise to achange of control and any successor to an incumbent director who wasrecommended for election at a meeting of Enbridge shareholders, or elected orappointed to succeed any incumbent director, by the affirmative vote of thedirectors, which affirmative vote includes a majority of the incumbentdirectors then on the board of directors.

Each of Mr. Letwin and Mr. Bird is subjectduring his employment (and for 2 years thereafter with regard to disclosure ofconfidential information) to restrictions on (i) any practice or businessin competition with Enbridge or its affiliates and (ii) disclosure of theconfidential information of Enbridge or its affiliates.

Inthe event of involuntary termination without cause or because of disability orvoluntary termination within 60 days of the first anniversary of theoccurrence of a change of control of Enbridge or within 60 days followingconstructive dismissal, Enbridge would owe approximately $6 million and $11million to Mr. Letwin and Mr. Bird, respectively. Such amounts assume that termination waseffective as of December 31, 2006, and as a result include amounts earnedthrough such time and are estimates of the amounts which would be paid out toeach of Mr. Letwin and Mr. Bird upon his termination under suchcircumstances. The actual amounts to be paid out can only be determined at thetime of such executive’s separation from Enbridge.

***Director Compensation***

As a partnership, we are managed by EnbridgeManagement, as the delegee of Enbridge Energy Company, Inc., our generalpartner. The boards of directors of Enbridge Management and our generalpartner, which are comprised of the same persons, perform for us the functionsof a board of directors of a business corporation. We are allocated 100 percentof the director compensation of these board members. Enbridge employees who aremembers of the boards of directors of the General Partner or EnbridgeManagement do not receive any additional compensation for serving in thosecapacities.

As ofJanuary 1, 2006, the Director Compensation Plan was amended to increase theannual retainer to $75,000 and additional meeting fees were eliminated. Theretainers paid to directors serving as the chairman of the boards and chairmanof the audit committees will remain at current levels. The out of state travelfee will be increased to $1,500 per meeting. As part of this change to theDirector Compensation Plan, the directors voted to amend the Corporate GovernanceGuidelines to incorporate an expectation that independent directors will hold apersonal investment in either or both of Enbridge Energy Partners, L.P. orEnbridge Management, of at least two times the annual board retainer (i.e., 

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2  ́ $75,000= $150,000). Directors would be expected to achieve the foregoing level ofshare ownership by the later of January 1, 2011 or five years from thedate they became a director.

**DIRECTORCOMPENSATION**
| Name                                       | ** ** | ** ** | ** ** | **Fees  Earned  or  Paid in  Cash  ($)** | ** ** | **Stock  Awards  ($)** | ** ** | **Option  Awards  ($)** | ** ** | **Non-Equity  Incentive Plan  Compensation  ($)** | ** ** | **Change in  Pension Value and  Nonqualified  Deferred  Compensation  Earnings  ($)** | ** ** | **All Other  Compensation  ($)** | ** ** | **Total  ($)** | ** ** |
|--------------------------------------------|------------|------------|------------|-----------------------------------------------|------------|------------------------|------------|-------------------------|------------|--------------------------------------------------------|------------|------------------------------------------------------------------------------------------------------|------------|---------------------------------------|------------|----------------|------------|
| J.A. Connelly*Audit Committee Chairman*    |       | 83,500     |       |                                          | —     |                   |       |                    | —     |                                                   |       |                                                                                                 | —     |                                  |       |           | —     |   |   |   | — |   |   | 83,500 |   |
| E.C. Hambrook*Chairman of the Boards* |       | 106,000    |       |                                          | —     |                   |       |                    | —     |                                                   |       |                                                                                                 | —     |                                  |       |           | —     |   |   |   | — |   |   | 106,000 |   |
| M.O. Hesse                                 |       | 82,000     |       |                                          | —     |                   |       |                    | —     |                                                   |       |                                                                                                 | —     |                                  |       |           | —     |   |   |   | — |   |   | 82,000 |   |
| G.K. Petty                                 |       | 81,000     |       |                                          | —     |                   |       |                    | —     |                                                   |       |                                                                                                 | —     |                                  |       |           | —     |   |   |   | — |   |   | 81,000 |   |

 

The General Partnerindemnifies each director for actions associated with being a director to thefull extent permitted under Delaware law and maintains errors and omissionsinsurance.

**COMPENSATION REPORTOF THE BOARD OF DIRECTORS**

The Boardof Directors of Enbridge Energy Management, L.L.C., as delegate of the generalpartner of Enbridge Energy Partners, L.P., has reviewed and discussed theCompensation Discussion and Analysis section of this report with management ofEnbridge Energy Partners, L.P. and, based on that review and discussions, hasrecommended that the Compensation Discussion and Analysis be included inreport.

| /s/ STEPHEN J.J. LETWIN                              |   | /s/ T.L. MCGILL                     |
|------------------------------------------------------|--------|-------------------------------------|
| Stephen J.J.  Letwin*Managing Director and Director* |   | T.L. McGill*President and Director* |
| /s/ J.R. BIRD                                        |   | /s/ J.A. CONNELLY                   |
| J.R. Bird*Director*                                  |   | J.A. Connelly*Director*             |
| /s/ E.C.  HAMBROOK                                   |   | /s/ M.O. HESSE                      |
| E.C. Hambrook*Director*                              |   | M.O. Hesse*Director*                |
| /s/ G.K. PETTY                                       |   |                                |
| G.K. Petty*Director*                                 |   |                                |

 

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**Item 12. SecurityOwnership of Certain Beneficial Owners and Management**

**SECURITY OWNERSHIPOF CERTAIN BENEFICIAL OWNERS**

Thefollowing table sets forth information as of February 22, 2007, withrespect to persons known to us to be the beneficial owners of more than 5% ofany class 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                   |       |                         | 12,902,676 |                                                       |       |                       | 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           |       | Class C units        |       |                         | 5,632,936  |                                                       |       |                       | 50.0       |   |   |
| CDP Infrastructures Fund G.P.                                 |       | Class C units        |       |                         | 5,632,936  |                                                       |       |                       | 50.0       |   |   |
| 1000 place Jean-Paul-Riopelle  Montreal, Québec H2Z 2B3  |       |                      |       |                         |       |                                                       |       |                       |       |   |   |

 

**SECURITY OWNERSHIP OF MANAGEMENT AND DIRECTORS**

Thefollowing table sets forth information as of February 15, 2007, withrespect to each class of our units and the Listed Shares of Enbridge Managementbeneficially owned by the NEOs, directors and nominees for director of theGeneral Partner and all executive officers, directors and nominees for directorof the Partnership as a group:

|                                                                     | ** ** | **Enbridge Energy Partners, L.P.** | ** ** | **Enbridge Energy Management, L.L.C.** | ** ** |
|---------------------------------------------------------------------|------------|---------------------------------------------------|------------|-------------------------------------------------------|------------|
| **Name**                                                            | ** ** | ** **                                        | ** ** | **Title of Class**                          | ** ** | **Amount and  Nature of  Beneficial  Ownership**(1) | ** ** | **Percent  Of Class** | ** ** | **Title of Class** | ** ** | **Number of  Shares**(1) | ** ** | **Percent  Of Class** | ** ** |
| J.A. Connelly                                                       |       | Class A common units                         |       |                                                  | 5,000      |   |   |   | * |   |   | Listed Shares |   |   | — |   |   |   | — |   |   |
| E.C. Hambrook                                                       |       | Class A common units                         |       |                                                  | 2,000      |   |   |   | * |   |   | Listed Shares |   |   | 1,282.30 |   |   |   | * |   |   |
| M.O. Hesse                                                          |       | Class A common units                         |       |                                                  | —     |   |   |   | — |   |   | Listed Shares |   |   | 7,152.60 |   |   |   | * |   |   |
| G.K. Petty                                                          |       | Class A common units                         |       |                                                  | 2,617      |   |   |   | * |   |   | Listed Shares |   |   | 967.70 |   |   |   | * |   |   |
| S.J.J. Letwin                                                       |       | Class A common units                         |       |                                                  | 15,000     |   |   |   | * |   |   | Listed Shares |   |   | — |   |   |   | — |   |   |
| T.L. McGill                                                         |       | Class A common units                         |       |                                                  | —     |   |   |   | — |   |   | Listed Shares |   |   | 1,364.70 |   |   |   | * |   |   |
| J.R. Bird(2)                                                        |       | Class A common units                         |       |                                                  | —     |   |   |   | — |   |   | Listed Shares |   |   | 10,752.20 |   |   |   | * |   |   |
| L.A. Zupan                                                          |       | Class A common units                         |       |                                                  | —     |   |   |   | — |   |   | Listed Shares |   |   | — |   |   |   | — |   |   |
| M.A. Maki                                                           |       | Class A common units                         |       |                                                  | —     |   |   |   | — |   |   | Listed Shares |   |   | — |   |   |   | — |   |   |
| R.L. Adams                                                          |       | Class A common units                         |       |                                                  | —     |   |   |   | — |   |   | Listed Shares |   |   | — |   |   |   | — |   |   |
| J.M. Gerez                                                          |       | Class A common units                         |       |                                                  | —     |   |   |   | — |   |   | Listed Shares |   |   | — |   |   |   | — |   |   |
| J.A. Holder                                                         |       | Class A common units                         |       |                                                  | —     |   |   |   | — |   |   | Listed Shares |   |   | — |   |   |   | — |   |   |
| J.A. Loiacono                                                       |       | Class A common units                         |       |                                                  | —     |   |   |   | — |   |   | Listed Shares |   |   | — |   |   |   | — |   |   |
| D.V. Krenz                                                          |       | Class A common units                         |       |                                                  | —     |   |   |   | — |   |   | Listed Shares |   |   | — |   |   |   | — |   |   |
| V.D. Yu                                                             |       | Class A common units                         |       |                                                  | —     |   |   |   | — |   |   | Listed Shares |   |   | — |   |   |   | — |   |   |
| J.N. Rose                                                           |       | Class A common units                         |       |                                                  | —     |   |   |   | — |   |   | Listed Shares |   |   | — |   |   |   | — |   |   |
| S.J. Neyland                                                        |       | Class A common units                         |       |                                                  | —     |   |   |   | — |   |   | Listed Shares |   |   | — |   |   |   | — |   |   |
| E.C. Kaitson                                                        |       | Class A common units                         |       |                                                  | —     |   |   |   | — |   |   | Listed Shares |   |   | — |   |   |   | — |   |   |
| B.A. Stevenson                                                      |       | Class A common units                         |       |                                                  | —     |   |   |   | — |   |   | Listed Shares |   |   | — |   |   |   | — |   |   |
| All Officers, directors  and  nominees as a group  17 persons) |       | Class A common units                         |       |                                                  | 24,617     |   |   |   | * |   |   | Listed Shares |   |   | 21,519.50 |   |   |   | * |   |   |
|                                                                     |            |                                                   |            |                                                       |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

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*        Less than 1%.

(1)      Each beneficial owner has sole voting and investmentpower with respect to all the units or shares attributed to him/her.

(2)      All of such shares held are pledged as security for a debt.

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**Item 13. CertainRelationships and Related Transactions, and Director Independence**

**INTEREST OF THEGENERAL PARTNER IN THE PARTNERSHIP**

In August 2006 we sold approximately 5.4 millionof our Class C units, representing a new class of limited partnerinterest, to our general partner and 5.4 million Class C units to aninstitutional investor for a purchase price of $46.00 per unit for a total ofapproximately $500 million. Additionally, our general partner contributedapproximately $10 million to maintain its two percent general partner interest.

AtDecember 31, 2006, our general partner had the following ownershipinterest in us:

| ** **                                                       | ** ** | **Quantity** | ** ** | **Effective  Ownership %** | ** ** |
|------------------------------------------------------------------|------------|--------------|------------|---------------------------------|------------|
| ***Direct  ownership***                                          |       |         |       |                            |       |   |   |
| Class B common units representing limited  partner interest |       | 3,912,750    |       |                            | 4.9        | % |   |
| Class C units representing limited partner  interest        |       | 5,535,076    |       |                            | 7.0        | % |   |
| General Partner interest                                         |       | —       |       |                            | 2.0        | % |   |
| ***Indirect  ownership***                                        |       |         |       |                            |       |   |   |
| Enbridge Management shares (Listed and Voting)                   |       | 2,182,771    |       |                            | 2.8        | % |   |
| Total effective  ownership                                       |       | 11,630,597   |       |                            | 16.7       | % |   |

 

**INTEREST OF ENBRIDGEMANAGEMENT IN THE PARTNERSHIP**

At December 31, 2006,Enbridge Management owned 12,674,148 i-units, representing a 16.0% 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 votingshares owned by the General Partner, at all times will equal the number ofi-units that it owns. Through the combined effect of the provisions in thePartnership Agreement and the provisions of Enbridge Management’s limitedliability company agreement, the number of outstanding Enbridge Managementshares and the number of 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. The holders of our i-units and Class C units receive in-kinddistributions under the Partnership Agreement. Our General Partner receivesincremental incentive cash distributions on the portion of cash distributionsthat exceed certain target thresholds on a per unit basis 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 2006, we paid cashand incentive distributions to our general partner for its general partner ownershipinterest of approximately $28.1 million and cash distributions of $14.5million in connection with its ownership of the Class B common units. Thecash distributions we make to our general partner for its general partnerownership interest exclude an amount equal to two percent of the i-unit andClass C unit distributions to maintain its two percent general partnerinterest.

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**IN-KINDDISTRIBUTIONS**

Enbridge Management, as owner of our i-units, does notreceive distributions in cash. Instead, each time that we make a cashdistribution to the General Partner and the holders of our Class A andClass B common units, we issue additional i-units to Enbridge Management in anamount determined by dividing the cash amount distributed per limited partnerunit by the average price of one of Enbridge Management’s listed shares on theNYSE for the 10-trading day period immediately preceding the ex-dividenddate for Enbridge Management’s shares multiplied by the number of sharesoutstanding on the record date. In 2006, we distributed a total of 969,200i-units to Enbridge Management and retained cash totaling approximately $44.6million in connection with these in-kind distributions.

Holders of ourClass C units receive quarterly distributions of additional Class Cunits with a value equal to the quarterly cash distribution we pay to theholders of our Class A and Class B common units. We determine theadditional Class C units we will issue by dividing the quarterly cashdistribution per unit we pay on our Class A and Class B common unitsby the average market price of a Class A common unit as listed on the NYSEfor the 10-trading day period immediately preceding the ex-dividend datefor our Class A common units multiplied by the number of Class Cunits outstanding on the record date. In 2006, we distributed a total of100,293 Class C units to our general partner in lieu of making cashdistributions and retained cash totaling approximately $10.1 million inconnection with these in-kind distributions.

**OTHER RELATED PARTYTRANSACTIONS**

We do not directly employ any of the individualsresponsible for managing or operating our business, nor do we have anydirectors. We obtain managerial, administrative and operational services fromour general partner and affiliates of Enbridge pursuant to service agreementsamong us, Enbridge Management, and affiliates of Enbridge. Pursuant to theseservice agreements, we have agreed to reimburse our general partner andaffiliates of Enbridge for the cost of managerial, administrative, operationaland director services they provide to us.

For further discussion ofthis and other related party transactions, refer to “Note 11—Related PartyTransactions” in the Notes to the Consolidated Financial Statements beginningon Page F-2 of this Annual Report on Form 10-K.

**REVIEW, APPROVAL ORRATIFICATION OF TRANSACTIONS WITH RELATED PERSONS**

If we contemplate entering into a transaction, otherthan a routine or in the ordinary course of business transaction, in which arelated person will have a direct or indirect material interest, the proposedtransaction is submitted for consideration to the board of directors of our generalpartner or Enbridge Management, as appropriate. The board of directors thendetermines whether it is advisable to constitute a special committee ofindependent directors to evaluate the proposed transaction. If a specialcommittee is appointed, the committee obtains information regarding theproposed transaction from management and determines whether it is advisable toengage independent legal counsel or an independent financial advisor to advisethe members of the committee regarding the transaction. If the specialcommittee retains such counsel or financial advisor, it considers the adviceand, in the case of a financial advisor, such advisor’s opinion as to whetherthe transaction is fair to us and all of our unitholders.

Potential transactions with related persons that arenot financially significant so as to require review by the board of directorsare disclosed to the President of Enbridge Management and our general partnerand reviewed for compliance with the Enbridge Statement on Business Conduct.The President may also consult with legal counsel in making such determination.If a related person transaction occurred and was later found not to comply withthe Statement on Business Conduct, the transaction would be reported to theboard of directors for further review and ratification or remedial action.

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During 2006, theboard of directors approved the following “related person” transactions (as theterm is defined in Item 404 of Regulation S-K) to be consummated in a futureperiod:

·       Alike-kind exchange with Enbridge Energy Company, Inc. (not in its capacityas General Partner of the Partnership) of Line 13 on the Lakehead system for anew diluent return line to be constructed in the future as part of the SouthernLights project being constructed by Enbridge Energy Company, Inc.

·       Thepurchase of a portion of the Spearhead pipeline system from an affiliate ofEnbridge Energy Company, Inc. (not in its capacity as General Partner ofthe Partnership). The transaction will occur in the future and is valued atapproximately $70 million.

During 2006, we entered into the following “relatedperson” transactions (as the term is defined in Item 404 of RegulationS-K):

·       Thepurchase by Enbridge Energy Company, Inc. (not in its capacity as GeneralPartner of the Partnership) of certain newly created Class C units as partof a private placement described in Notes 10 and 11 of our consolidated financialstatements beginning at page F-1 of this Annual Report onForm 10-K for a total value of $250 million.

·       An affiliate of Enbridgewhich provides employee services to the Partnership continued a previouslyexisting employment relationship with Jan Connelly, the sister of Jeffrey AConnelly, a member of the Board of Directors. Ms. Connelly is employed inour Michigan office as the Manager, Origination. During 2006, she receivedtotal cash compensation of $135,573.72 and benefits estimated at approximately35% of her cash compensation for a total of $183,024.52.

**Item 14. PrincipalAccountant 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,** | ** ** |
|---------------------|------------|-----------------------------------------------------------|------------|
| ** **          | ** ** | **2006**                                                  | ** ** | **2005** | ** ** |
| Audit fees(1)       |       | $ 2,405,200                                          |       | $ 2,276,166 |   |
| Audit related  fees |       | —                                                    |       | — |   |
| Tax fees(2)         |       | 625,000                                                   |       | 680,500 |   |
| All other fees      |       | —                                                    |       | — |   |
| Total               |       | $ 3,030,200                                          |       | $ 2,956,666 |   |

----

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

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 2006 and 2005 were approved by the Audit,Finance & Risk Committee.

120

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**PART IV**

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

The following documents are filed as a part of thisreport:

(1)   *Financial Statements, which are incorporated by reference in Item 8 areincluded beginning on page F-1*.

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

b.                 ConsolidatedStatements of Income for the years ended December 31, 2006, 2005, and2004.

c.                  ConsolidatedStatements of Comprehensive Income for the years ended December 31, 2006,2005, and 2004.

d.                 ConsolidatedStatements of Cash Flows for the years ended December 31, 2006, 2005,and 2004.

e.                  ConsolidatedStatements of Financial Position as of December 31, 2006 and 2005.

f.                    ConsolidatedStatements of Partners’ Capital for the years ended December 31, 2006,2005, and 2004.

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.*

Referenceis made to the “Index of Exhibits” following the signature page, which ishereby incorporated into this Item.

121

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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/ STEPHEN J.J. LETWIN |
|                          |                                          | Stephen J.J. Letwin |
| Date: February 22,  2007 |                                          | *(Managing  Director)* |

 

Pursuantto the requirements of the Securities Exchange Act of 1934, this Report hasbeen signed below on February 22, 2007 by the following persons on behalfof the Registrant and in the capacities indicated.
| /s/ STEPHEN J.J. LETWIN                                               |   | /s/ M.A. MAKI                                                         |
|-----------------------------------------------------------------------|--------|-----------------------------------------------------------------------|
| Stephen J.J. Letwin*Managing Director  (Principal Executive Officer)* |   | M.A. Maki*Vice President—Finance  (Principal Financial Officer)* |
| /s/ T.L. MCGILL                                                       |   | /s/ J.R. BIRD                                                         |
| T.L. McGill*President*                                                |   | J.R. Bird*Director*                                                   |
| /s/ J.A. CONNELLY                                                     |   | /s/ E.C. HAMBROOK                                                     |
| J.A. Connelly*Director*                                               |   | E.C. Hambrook*Director*                                               |
| /s/ M.O. HESSE                                                        |   | /s/ G.K. PETTY                                                        |
| M.O. Hesse*Director*                                                  |   | G.K. Petty*Director*                                                  |

 

122

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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 (incorporated by reference to  Exhibit 3.1 of the Partnership’s Registration Statement No. 33-43425).                                                                                                                                                                                   |
| 3.2              |       | Certificate  of Amendment to Certificate of Limited Partnership of the Partnership  (incorporated by reference to Exhibit 3.2 of the Partnership’s 2000  Form 10-K/A dated October 9, 2001).                                                                                                                                              |
| 3.3              |       | Fourth  Amended and Restated Agreement of Limited Partnership of the Partnership,  dated August 15, 2006 (incorporated by reference to Exhibit 3.1 of  our Current Report on Form 8-K dated August 16, 2006).                                                                                                                             |
| 4.1              |       | Form of  Certificate representing Class A Common Units (incorporated by reference  to Exhibit 4.1 of the Partnership’s 2000 Form 10-K/A dated  October 9, 2001).                                                                                                                                                                |
| 4.2              |       | Registration  Rights Agreement, dated August 15, 2006, between Enbridge Energy  Partners, L.P. and CDP Infrastructures Fund G.P. (incorporated by reference  to Exhibit 4.1 of our Current Report on Form 8-K dated  August 16, 2006).                                                                                                    |
| 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. (incorporated by reference  to Exhibit 10.10 of 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. (incorporated by reference to Exhibit 10.11 of the  Partnership’s 1991 Form 10-K). |
| 10.3             |       | Contribution  Agreement (incorporated by reference to Exhibit 10.1 of the  Partnership’s Registration Statement on Form S-3/A filed on  July 8, 2002).                                                                                                                                                                                    |
| 10.4             |       | First  Amendment to Contribution Agreement (incorporated by reference to  Exhibit 10.8 of the Partnership’s Registration Statement on Form S-3/A  filed on September 24, 2002).                                                                                                                                                           |
| 10.5             |       | Second  Amendment to Contribution Agreement (incorporated by reference to  Exhibit 99.3 of the Partnership’s Current Report on Form 8-K  filed on October 31, 2002).                                                                                                                                                                      |
| 10.6             |       | Delegation  of Control Agreement (incorporated by reference to Exhibit 10.2 of 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 (incorporated by reference to Exhibit 10.1 of the  Partnership’s Quarterly Report on Form 10-Q filed on May 5,  2005).                                                                                                               |
| 10.8             |       | Amended  and Restated Treasury Services Agreement (incorporated by reference to  Exhibit 10.3 of the Partnership’s Quarterly Report on Form 10-Q  filed on November 14, 2002).                                                                                                                                                            |
| 10.9             |       | Operational  Services Agreement (incorporated by reference to Exhibit 10.4 of the  Partnership’s Quarterly Report on Form 10-Q filed on  November 14, 2002).                                                                                                                                                                              |
| 10.10            |       | General  and Administrative Services Agreement (incorporated by reference to  Exhibit 10.5 of the Partnership’s Quarterly Report on Form 10-Q  filed on November 14, 2002).                                                                                                                                                               |
| 10.11            |       | Omnibus  Agreement (incorporated by reference to Exhibit 10.6 of the  Partnership’s Quarterly Report on Form 10-Q filed on  November 14, 2002).                                                                                                                                                                                           |

123

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| 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 (incorporated by reference of 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  (incorporated by reference to Exhibit 10.1 of the Partnership’s  Quarterly Report on Form 10-Q filed on May 4, 2004).                                                                                                                                                                |
| 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  (incorporated by reference to Exhibit 10.2 of 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 of 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 of 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 of 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 of 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 of 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 of 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 of 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 (incorporated by  reference to Exhibit 10.12 of 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 of the Partnership’s Annual  Report on Form 10-K filed on March 28, 2003).                                                                                                                                                                                                                                 |

124

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| 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 (incorporated by reference to Exhibit 10.14  of 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 (incorporated  by reference to Exhibit 10.15 of the Partnership’s Annual Report on  Form 10-K filed on March 28, 2003).                                             |
| 10.26  |   | Note  Agreement and Mortgage, dated December 12, 1991 (incorporated by  reference to Exhibit 10.1 of the Partnership’s 1991 Form 10-K).                                                                                                                                                                                         |
| 10.27  |   | Assumption  and Indemnity Agreement, dated December 18, 1992, between  Interprovincial Pipe Line Inc. and Interprovincial Pipe Line System Inc.  (incorporated by reference to Exhibit 10.4 of 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 (incorporated by reference to  Exhibit 10.17 of 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 (incorporated by  reference to Exhibit 10.21 of 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 (incorporated by reference to  Exhibit 10.19 of 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. (incorporated by reference to Exhibit 10.26 of 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 (incorporated by reference to  Exhibit 4.1 of 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 (incorporated  by reference to Exhibit 4.2 of 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 (incorporated  by reference to Exhibit 4.3 of 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 (incorporated  by reference to Exhibit 4.2 of 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 (incorporated by reference to  Exhibit 4.4 of the Lakehead Pipe Line Company, Limited Partnership’s  Current Report on Form 8-K dated October 20, 1998).                                        |
| 10.37+ |   | Executive  Employment Agreement, dated April 14, 2003, between Stephen J.J. Letwin,  as Executive, and Enbridge Inc., as Corporation (incorporated by reference to  Exhibit 10.1 of the Partnership’s Current Report on Form 8-K  filed on May 3, 2006).                                                                   |

125

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| 10.38*+ |   | Executive  Employment Agreement, dated April 14, 2003, between J. Richard Bird, as  Executive, and Enbridge Inc., as Corporation.                                                                                                                                                                      |
|---------|--------|-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 10.39+  |   | Executive  Employment Agreement, dated May 11, 2001, between E. Chris Kaitson, as  Executive, and Enbridge Inc., as Corporation (incorporated by reference to  Exhibit 10.27 of the Partnership’s Annual Report on Form 10-K  filed on March 28, 2003).                            |
| 10.40   |   | Indenture  dated May 27, 2003, between the Partnership, as Issuer, and SunTrust  Bank, as Trustee (incorporated by reference to Exhibit 4.5 of the  Partnership’s Registration Statement on Form S-4 filed on  June 30, 2003).                                                     |
| 10.41   |   | First  Supplemental Indenture dated May 27, 2003 between the Partnership and  SunTrust Bank (incorporated by reference to Exhibit 4.5 of the  Partnership’s Registration Statement on Form S-4 filed on  June 30, 2003).                                                           |
| 10.42   |   | Second  Supplemental Indenture dated May 27, 2003 between the Partnership and  SunTrust Bank (incorporated by reference to Exhibit 4.5 of the  Partnership’s Registration Statement on Form S-4 filed on  June 30, 2003).                                                          |
| 10.43   |   | Third  Supplemental Indenture dated January 9, 2004 between the Partnership and  SunTrust Bank (incorporated by reference to Exhibit 99.3 of the  Partnership’s Current Report on Form 8-K filed on January 9,  2004).                                                             |
| 10.44   |   | Fourth  Supplemental Indenture dated December 3, 2004 between the Partnership  and SunTrust Bank (incorporated by reference to Exhibit 4.2 of the  Partnership’s Current Report on Form 8-K filed on December 3,  2004).                                                           |
| 10.45   |   | Fifth  Supplemental Indenture dated December 3, 2004 between the Partnership  and SunTrust Bank (incorporated by reference to Exhibit 4.3 of the  Partnership’s Current Report on Form 8-K filed on December 3,  2004).                                                            |
| 10.46   |   | Sixth  Supplemental Indenture dated December 21, 2006 between the Partnership  and U.S. Bank National Association, successor to SunTrust Bank, as trustee  (incorporated by reference to Exhibit 4.2 of the Partnership’s Current  Report on Form 8-K filed on December 21, 2006). |
| 10.47   |   | Common  Unit Purchase Agreement (incorporated by reference to Exhibit 1.1 of the  Partnership’s Current Report on Form 8-K filed on  February 10, 2005).                                                                                                                                |
| 10.48   |   | Common  Unit Purchase Agreement (incorporated by reference to Exhibit 1.1 of the  Partnership’s Current Report on Form 8-K filed on November 17,  2005).                                                                                                                                     |
| 14.1    |   | Code  of Ethics for Senior Financial Officers (incorporated by reference to  Exhibit 14.1 of 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.  (incorporated by reference to Exhibit 99.1 of 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.

126

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**INDEXTO CONSOLIDATED FINANCIAL STATEMENTS,SUPPLEMENTARY INFORMATION ANDCONSOLIDATED FINANCIAL STATEMENT SCHEDULES**

**ENBRIDGEENERGY 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, 2006, 2005  and 2004                        |       | F-4      |
| Consolidated Statements of Comprehensive Income for  each of the years ended December 31, 2006, 2005 and 2004 |       | F-5      |
| Consolidated Statements of Cash Flows for each of the  years ended December 31, 2006, 2005 and 2004                |       | F-6      |
| Consolidated Statements of Financial Position as of  December 31, 2006 and 2005                                         |       | F-7      |
| Consolidated Statements of Partners’ Capital for each  of the years ended December 31, 2006, 2005 and 2004    |       | F-8      |
| Notes to the Consolidated Financial Statements                                                                               |       | F-9      |

 

**FINANCIAL STATEMENTSCHEDULES**

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

----

**Report ofIndependent Registered Public Accounting Firm**

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

We have completedintegrated audits of Enbridge Energy Partners, L.P.’s consolidated financialstatements and of its internal control over financial reporting as of December 31,2006, in accordance with the standards of the Public Company AccountingOversight Board (United States). Our opinions, based on our audits, arepresented below.

*Consolidatedfinancial statements*

In our opinion, theconsolidated statements of financial position and the related consolidatedstatements of income and comprehensive income, of partners capital and of cashflows present fairly, in all material respects, the financial position ofEnbridge Energy Partners, L.P. and its subsidiaries (the “Partnership”) at December 31,2006 and 2005, and the results of their operations and their cash flows foreach of the three years in the period ended December 31, 2006 inconformity with accounting principles generally accepted in the United Statesof America. These financial statements are the responsibility of thePartnership’s management. Our responsibility is to express an opinion on thesefinancial statements based on our audits. We conducted our audits of thesestatements 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 the financialstatements are free of material misstatement. An audit of financial statementsincludes examining, on a test basis, evidence supporting the amounts anddisclosures in the financial statements, assessing the accounting principlesused and significant estimates made by management, and evaluating the overallfinancial statement presentation. We believe that our audits provide areasonable basis for our opinion.

*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, 2006 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 material respects, effectiveinternal control over financial reporting as of December 31, 2006, basedon criteria established in *Internal Control—Integrated Framework*issued bythe COSO. The Partnership’s management is responsible for maintaining effectiveinternal control over financial reporting and for its assessment of theeffectiveness of internal control over financial reporting. Our responsibilityis to express opinions on management’s assessment and on the effectiveness ofthe Partnership’s internal control over financial reporting based on our audit.We conducted our audit of internal control over financial reporting inaccordance with the standards of the Public Company Accounting Oversight Board(United States). Those standards require that we plan and perform the audit toobtain reasonable assurance about whether effective internal control overfinancial reporting was maintained in all material respects. An audit ofinternal control over financial reporting includes obtaining an understandingof internal control over financial reporting, evaluating management’sassessment, testing and evaluating the design and operating effectiveness ofinternal control, and performing such other procedures as we consider necessaryin the circumstances. We believe that our audit provides a reasonable basis forour 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 

F-2

----

control over financialreporting includes those policies and procedures that (i) pertain to themaintenance of records that, in reasonable detail, accurately and fairlyreflect the transactions and dispositions of the assets of the company; (ii) providereasonable assurance that transactions are recorded as necessary to permitpreparation of financial statements in accordance with generally acceptedaccounting principles, and that receipts and expenditures of the company arebeing made only in accordance with authorizations of management and directorsof the company; and (iii) provide reasonable assurance regardingprevention or timely detection of unauthorized acquisition, use, or dispositionof the company’s assets that could have a material effect on the financialstatements.

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, TexasFebruary 22, 2007

F-3

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**ENBRIDGE ENERGY PARTNERS, L.P.CONSOLIDATED STATEMENTS OF INCOME**

|                                                                        | ** ** | **Year ended December 31,**                          | ** ** |
|------------------------------------------------------------------------|------------|---------------------------------------------------------------------|------------|
| ** **                                                             | ** ** | **2006**                                                            | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                                                             | ** ** | **(in millions, except per unit amounts)** | ** ** |
| Operating revenue                                                      |       | $                                                                   | 6,509.0    |   | $ | 6,476.9 |   | $ | 4,291.7 |   |
| Operating expenses                                                     |       |                                                                |       |   |   |   |   |
| Cost of natural gas (Note  15)                                         |       | 5,514.6                                                             |       | 5,763.3 |   | 3,587.1 |   |
| Operating and administrative                                           |       | 364.8                                                               |       | 326.8 |   | 274.1 |   |
| Power                                                                  |       | 107.6                                                               |       | 74.8 |   | 72.8 |   |
| Depreciation and amortization (Note 6)                                 |       | 135.1                                                               |       | 138.2 |   | 120.5 |   |
| Gain on sale of assets                                                 |       | —                                                              |       | (18.1 | ) | — |   |
|                                                                   |       | 6,122.1                                                             |       | 6,285.0 |   | 4,054.5 |   |
| Operating income                                                       |       | 386.9                                                               |       | 191.9 |   | 237.2 |   |
| Interest expense                                                       |       | (110.5                                                              | )          | (107.7 | ) | (88.4 | ) |
| Rate refunds (Note 13)                                                 |       | —                                                              |       | — |   | (13.6 | ) |
| Other income                                                           |       | 8.5                                                                 |       | 5.0 |   | 3.0 |   |
| Net income                                                             |       | $                                                                   | 284.9      |   | $ | 89.2 |   | $ | 138.2 |   |
| Net income  allocable to limited partner units                         |       | $                                                                   | 254.0      |   | $ | 65.7 |   | $ | 115.7 |   |
| Net income per limited  partner unit (basic and diluted) (Note 4) |       | $                                                                   | 3.62       |   | $ | 1.06 |   | $ | 2.06 |   |
| Weighted average  limited partner units outstanding                    |       | 70.2                                                                |       | 62.1 |   | 56.1 |   |
| Cash distributions paid per  limited partner unit                      |       | $                                                                   | 3.70       |   | $ | 3.70 |   | $ | 3.70 |   |

 

The accompanying notes are an integral part of these consolidated financial statements.

F-4

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**ENBRIDGE ENERGY PARTNERS, L.P.CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME**

| ** **                                                     | ** ** | **Year ended December 31,** | ** ** |
|----------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                     | ** ** | **2006**                                   | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                                                     | ** ** | **(in millions)**                     | ** ** |
| Net income                                                     |       | $                                     | 284.9      |   | $ | 89.2 |   | $ | 138.2 |   |
| Other  comprehensive income (loss) (Notes 14 and 15) |       | 112.5                                      |       | (181.3 | ) | (56.8 | ) |
| Comprehensive income  (loss)                                   |       | $                                          | 397.4      |   | $ | (92.1 | ) | $ | 81.4 |   |

 

The accompanying notes are an integral part of these consolidated financial statements.

F-5

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**ENBRIDGE ENERGY PARTNERS, L.P.CONSOLIDATED STATEMENTS OF CASH FLOWS**
|                                                                                    | ** ** | **Year ended December 31,** | ** ** |
|------------------------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                                         | ** ** | **2006**                                   | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                                                                         | ** ** | **(in millions)**                     | ** ** |
| Cash provided by operating activities                                              |       |                                       |       |   |   |   |   |
| Net income                                                                         |       | $                                          | 284.9      |   | $ | 89.2 |   | $ | 138.2 |   |
| Adjustments to reconcile net income to net cash  provided by operating activities: |       |                                       |       |   |   |   |   |
| Depreciation and  amortization (Note 6)                                       |       | 135.1                                      |       | 138.2 |   | 120.5 |   |
| Derivative fair value  (gains) losses (Notes 14 and 15)                       |       | (64.4                                      | )          | 58.4 |   | 3.2 |   |
| Environmental  liabilities (Note 12)                                          |       | (1.4                                       | )          | (0.5 | ) | (2.0 | ) |
| Gain on sale of assets  (Note 3)                                              |       | —                                     |       | (18.1 | ) | — |   |
| Inventory market price  adjustments (Note 5)                                       |       | 17.7                                       |       | — |   | — |   |
| Other                                                                              |       | 9.7                                        |       | (0.3 | ) | 0.4 |   |
| Changes in operating assets and liabilities, net of  cash acquired:                |       |                                       |       |   |   |   |   |
| Receivables, trade and other                                                       |       | (37.0                                      | )          | (38.0 | ) | (25.4 | ) |
| Due from General Partner  and affiliates                                           |       | (10.4                                      | )          | (12.4 | ) | (0.5 | ) |
| Accrued receivables                                                                |       | 98.8                                       |       | (237.1 | ) | (128.5 | ) |
| Inventory                                                                          |       | 1.1                                        |       | (57.5 | ) | (60.8 | ) |
| Current and long-term  other assets (Notes 14 and 15)                              |       | (2.7                                       | )          | (2.2 | ) | 15.3 |   |
| Due to General Partner  and affiliates (Note 11)                                   |       | 10.1                                       |       | 2.6 |   | 8.1 |   |
| Accounts payable and  other (Notes 2, 14 and 15)                                   |       | 4.3                                        |       | 42.2 |   | 36.8 |   |
| Accrued purchases                                                                  |       | (116.4                                     | )          | 295.3 |   | 120.8 |   |
| Interest payable                                                                   |       | 4.4                                        |       | 8.8 |   | 14.5 |   |
| Property and other taxes  payable                                                  |       | (2.0                                       | )          | (1.5 | ) | 4.8 |   |
| Settlement of interest  rate derivatives (Note 15)                                 |       | (10.2                                      | )          | — |   | — |   |
| Net cash provided by  operating activities                                         |       | 321.6                                      |       | 267.1 |   | 245.4 |   |
| Cash used in investing activities                                                  |       |                                       |       |   |   |   |   |
| Additions to property,  plant and equipment                                        |       | (864.4                                     | )          | (344.8 | ) | (288.8 | ) |
| Changes in construction  payables                                                  |       | 30.4                                       |       | 2.8 |   | 10.0 |   |
| Asset acquisitions, net  of cash acquired (Note 3)                            |       | (33.3                                      | )          | (186.4 | ) | (141.0 | ) |
| Proceeds from sale of  assets (Note 3)                                        |       | 0.2                                        |       | 105.4 |   | — |   |
| Settlement of natural  gas collars (Note 3 and 15)                                 |       | —                                     |       | (16.3 | ) | — |   |
| Other                                                                              |       | 0.1                                        |       | 2.2 |   | 0.7 |   |
| Net cash used in  investing activities                                             |       | (867.0                                     | )          | (437.1 | ) | (419.1 | ) |
| Cash provided by financing activities                                              |       |                                       |       |   |   |   |   |
| Proceeds from unit  issuances, net (Note 10)                                       |       | 509.6                                      |       | 268.6 |   | 194.2 |   |
| Distributions to  partners (Note 10)                                               |       | (227.4                                     | )          | (210.6 | ) | (191.0 | ) |
| Repayments of Credit  Facilities, net (Note 9)                                     |       | —                                     |       | (175.0 | ) | (280.0 | ) |
| Net issuances of  commercial paper (Note 9)                                        |       | 111.4                                      |       | 330.0 |   | — |   |
| Proceeds from issuance  of senior notes, net of issue costs (Note 9)               |       | 297.6                                      |       | — |   | 495.4 |   |
| Repayments on affiliate  loan (Note 11)                                            |       | (20.0                                      | )          | — |   | — |   |
| Repayments of First  Mortgage Notes (Note 9)                                       |       | (31.0                                      | )          | (31.0 | ) | (31.0 | ) |
| Other                                                                              |       | —                                     |       | (0.5 | ) | — |   |
| Net cash provided by  financing activities                                         |       | 640.2                                      |       | 181.5 |   | 187.6 |   |
| Net increase in cash and  cash equivalents                                         |       | 94.8                                       |       | 11.5 |   | 13.9 |   |
| Cash and cash  equivalents at beginning of year                                    |       | 89.8                                       |       | 78.3 |   | 64.4 |   |
| Cash and cash equivalents at end of year                                           |       | $                                          | 184.6      |   | $ | 89.8 |   | $ | 78.3 |   |

 

The accompanying notes are an integral part of these consolidated financial statements.

F-6

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**ENBRIDGE ENERGY PARTNERS, L.P.CONSOLIDATED STATEMENTS OF FINANCIAL POSITION**
|                                                                                                         | ** ** | **December 31,**               | ** ** |
|---------------------------------------------------------------------------------------------------------|------------|-------------------------------------|------------|
| ** **                                                                                              | ** ** | **2006**                            | ** ** | **2005** | ** ** |
| ** **                                                                                              | ** ** | **(dollars in millions)** | ** ** |
| **ASSETS**                                                                                              |       |                                |       |   |   |
| Current assets                                                                                          |       |                                |       |   |   |
| Cash and cash equivalents (Note 2)                                                                      |       | $                                   | 184.6      |   | $ | 89.8 |   |
| Receivables, trade and  other, net of allowance for doubtful accounts of $2.4  in 2006 and $4.5 in 2005 |       | 146.7                               |       | 109.7 |   |
| Due from General Partner and affiliates                                                                 |       | 30.5                                |       | 20.1 |   |
| Accrued receivables                                                                                     |       | 516.5                               |       | 615.3 |   |
| Inventory (Note 5)                                                                                      |       | 117.1                               |       | 138.9 |   |
| Other current assets (Notes 14 and 15)                                                                  |       | 13.9                                |       | 11.5 |   |
|                                                                                                    |       | 1,009.3                             |       | 985.3 |   |
| Property, plant and equipment, net (Note 6)                                                             |       | 3,824.9                             |       | 3,080.0 |   |
| Other assets, net  (Notes 14 and 15)                                                                    |       | 32.5                                |       | 22.2 |   |
| Goodwill (Note 7)                                                                                       |       | 265.7                               |       | 258.2 |   |
| Intangibles, net  (Note 8)                                                                              |       | 91.4                                |       | 82.7 |   |
|                                                                                                    |       | $                                   | 5,223.8    |   | $ | 4,428.4 |   |
| **LIABILITIES AND PARTNERS’ CAPITAL**                                                              |       |                                |       |   |   |
| Current liabilities                                                                                     |       |                                |       |   |   |
| Due to General Partner and affiliates (Note 11)                                                         |       | $                                   | 22.6       |   | $ | 12.5 |   |
| Accounts payable and other (Notes 14 and 15)                                                            |       | 211.5                               |       | 247.9 |   |
| Accrued purchases                                                                                       |       | 530.3                               |       | 646.7 |   |
| Interest payable                                                                                        |       | 11.4                                |       | 11.4 |   |
| Property and other taxes payable                                                                        |       | 18.6                                |       | 21.8 |   |
| Loans from General Partner and affiliates  (Note 11)                                               |       | 136.2                               |       | — |   |
| Current maturities of long-term debt  (Note 9)                                                     |       | 31.0                                |       | 31.0 |   |
|                                                                                                    |       | 961.6                               |       | 971.3 |   |
| Long-term debt (Note 9)                                                                                 |       | 2,066.1                             |       | 1,682.9 |   |
| Environmental  liabilities (Note 12)                                                               |       | 3.3                                 |       | 4.8 |   |
| Loans from  General Partner and affiliates (Note 11)                                               |       | —                              |       | 151.8 |   |
| Other long-term  liabilities (Notes 14 and 15)                                                          |       | 149.4                               |       | 253.8 |   |
|                                                                                                    |       | 3,180.4                             |       | 3,064.6 |   |
| Commitments and  contingencies (Note 13)                                                           |       |                                |       |   |   |
| Partners’ capital  (Note 10)                                                                       |       |                                |       |   |   |
| Class A common units (Units issued—49,938,834  in 2006 and 2005)                              |       | 1,141.7                             |       | 1,142.4 |   |
| Class B common units (Units issued—3,912,750 in  2006 and 2005)                               |       | 67.6                                |       | 67.2 |   |
| Class C units (Units issued—11,070,152 in 2006)                                               |       | 509.8                               |       | — |   |
| i-units (Units issued—12,674,148 in 2006 and  11,704,948 in 2005)                                  |       | 466.3                               |       | 421.7 |   |
| General Partner                                                                                         |       | 47.6                                |       | 34.6 |   |
| Accumulated other comprehensive loss (Notes  14 and 15)                                            |       | (189.6                              | )          | (302.1 | ) |
|                                                                                                    |       | 2,043.4                             |       | 1,363.8 |   |
|                                                                                                    |       | $                                   | 5,223.8    |   | $ | 4,428.4 |   |

 

The accompanying notes are an integral part of these consolidated financial statements.

F-7

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**ENBRIDGE ENERGY PARTNERS, L.P.CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL**
|                                                               | ** ** | **Year ended December 31,**                 | ** ** |
|---------------------------------------------------------------|------------|------------------------------------------------------------|------------|
| ** **                                                    | ** ** | **2006**                                                   | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                                                    | ** ** | **Units**                                                  | ** ** | **Amount** | ** ** | **Units** | ** ** | **Amount** | ** ** | **Units** | ** ** | **Amount** | ** ** |
| ** **                                                    | ** ** | **(in millions, except unit amounts)** | ** ** |
| **Class A common units:**                                |       |                                                       |       |   |   |   |   |   |   |   |   |   |   |
| Beginning balance                                             |       | 49,938,834                                                 |       | $ | 1,142.4 |   | 44,296,134 |   | $ | 1,021.6 |   | 40,166,134 |   | $ | 914.9 |   |
| Net income allocation                                         |       | —                                                     |       | 184.1 |   | — |   | 48.9 |   | — |   | 85.4 |   |
| Allocation of proceeds  and issuance costs from unit issuance |       | —                                                     |       | — |   | 5,642,700 |   | 242.7 |   | 4,130,000 |   | 175.0 |   |
| Distributions                                                 |       | —                                                     |       | (184.8 | ) | — |   | (170.8 | ) | — |   | (153.7 | ) |
| Ending balance                                                |       | 49,938,834                                                 |       | 1,141.7 |   | 49,938,834 |   | 1,142.4 |   | 44,296,134 |   | 1,021.6 |   |
| **Class B common units:**                                |       |                                                       |       |   |   |   |   |   |   |   |   |   |   |
| Beginning balance                                             |       | 3,912,750                                                  |       | 67.2 |   | 3,912,750 |   | 66.7 |   | 3,912,750 |   | 64.2 |   |
| Net income allocation                                         |       | —                                                     |       | 14.9 |   | — |   | 4.8 |   | — |   | 8.7 |   |
| Allocation of proceeds  and issuance costs from unit issuance |       | —                                                     |       | — |   | — |   | 10.2 |   | — |   | 8.2 |   |
| Distributions                                                 |       | —                                                     |       | (14.5 | ) | — |   | (14.5 | ) | — |   | (14.4 | ) |
| Ending balance                                                |       | 3,912,750                                                  |       | 67.6 |   | 3,912,750 |   | 67.2 |   | 3,912,750 |   | 66.7 |   |
| **Class C units:**                                       |       |                                                       |       |   |   |   |   |   |   |   |   |   |   |
| Beginning balance                                             |       | —                                                     |       | — |   | — |   | — |   | — |   | — |   |
| Net income allocation                                         |       | —                                                     |       | 10.4 |   | — |   | — |   | — |   | — |   |
| Allocation of proceeds  and issuance costs from unit issuance |       | 10,869,565                                                 |       | 499.4 |   | — |   | — |   | — |   | — |   |
| Distributions                                                 |       | 200,587                                                    |       | — |   | — |   | — |   | — |   | — |   |
| Ending balance                                                |       | 11,070,152                                                 |       | 509.8 |   | — |   | — |   | — |   | — |   |
| **i-units:**                                                  |       |                                                       |       |   |   |   |   |   |   |   |   |   |   |
| Beginning balance                                             |       | 11,704,948                                                 |       | 421.7 |   | 10,902,409 |   | 399.4 |   | 10,062,170 |   | 370.7 |   |
| Net income allocation                                         |       | —                                                     |       | 44.6 |   | — |   | 12.0 |   | — |   | 21.6 |   |
| Allocation of proceeds  and issuance costs from unit issuance |       | —                                                     |       | — |   | — |   | 10.3 |   | — |   | 7.1 |   |
| Distributions                                                 |       | 969,200                                                    |       | — |   | 802,539 |   | — |   | 840,239 |   | — |   |
| Ending balance                                                |       | 12,674,148                                                 |       | 466.3 |   | 11,704,948 |   | 421.7 |   | 10,902,409 |   | 399.4 |   |
| **General Partner:**                                          |       |                                                       |       |   |   |   |   |   |   |   |   |   |   |
| Beginning balance                                             |       |                                                       |       | 34.6 |   |   |   | 31.0 |   |   |   | 27.5 |   |
| Net income allocation                                         |       |                                                       |       | 30.9 |   |   |   | 23.5 |   |   |   | 22.5 |   |
| Allocation of proceeds  and issuance costs from unit issuance |       |                                                       |       | — |   |   |   | (0.3 | ) |   |   | (0.2 | ) |
| General Partner  contribution                                 |       |                                                       |       | 10.2 |   |   |   | 5.7 |   |   |   | 4.1 |   |
| Distributions                                                 |       |                                                       |       | (28.1 | ) |   |   | (25.3 | ) |   |   | (22.9 | ) |
| Ending balance                                                |       |                                                       |       | 47.6 |   |   |   | 34.6 |   |   |   | 31.0 |   |
| **Accumulated other comprehensive  loss:**                    |       |                                                       |       |   |   |   |   |   |   |   |   |   |   |
| Beginning balance                                             |       |                                                       |       | (302.1 | ) |   |   | (120.8 | ) |   |   | (64.0 | ) |
| Unrealized gain (loss) on  derivative financial instruments   |       |                                                       |       | 112.5 |   |   |   | (181.3 | ) |   |   | (56.8 | ) |
| Ending balance                                                |       |                                                       |       | (189.6 | ) |   |   | (302.1 | ) |   |   | (120.8 | ) |
| Partners’ capital at December 31,                   |       |                                                       |       | $ | 2,043.4 |   |   |   | $ | 1,363.8 |   |   |   | $ | 1,397.9 |   |

 

The accompanying notes are an integral part of these consolidated financial statements.

F-8

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**ENBRIDGE ENERGY PARTNERS, L.P.NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS**

**1. PARTNERSHIPORGANIZATION 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.(the “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 United States to eastern Canada.

We are a geographically and operationally diversifiedorganization, providing crude oil gathering, transportation and storageservices, and natural gas gathering, treating, processing, marketing andtransportation services in the Gulf Coast and Mid-continent regions of theUnited States. We hold our assets in a series of limited liability companiesand limited partnerships that we own directly or indirectly.

Ourownership includes general partner interests and limited partner interests. Ourlimited partner interests consist of Class A and Class B commonunits, Class C units and i-units, which we collectively refer to as thelimited partner units. At December 31, 2006 and 2005, our ownership isdistributed as follows:

|                                                         | ** ** | **2006** | ** ** | **2005** | ** ** |
|---------------------------------------------------------|------------|----------|------------|----------|------------|
| Class A common units  owned by the public          |       | 63.1     | %          | 74.7     | %          |
| Class B  common units owned by our General Partner |       | 4.9      | %          | 5.8      | %          |
| Class C units owned by  our General Partner        |       | 7.0      | %          | —   |       |
| Class C  units owned by an institutional investor  |       | 7.0      | %          | —   |       |
| i-units owned by Enbridge  Management                   |       | 16.0     | %          | 17.5     | %          |
| 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 

F-9

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limitedliability company agreement, Enbridge Management’s activities are restricted tobeing our limited partner and managing our business and affairs.

***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, 2006 and 2005, Enbridge and its consolidatedsubsidiaries owned an effective 16.7% and10.8% interest in us through its ownership in Enbridge Management and ourgeneral 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. OurMid-Continent system consists of over 480 miles of active crude oil pipelinesincluding the FERC-regulated Ozark pipeline and approximately 12.8 million barrels of storage capacity,which serves refineries in the U.S. Mid-continent region from Cushing,Oklahoma.

**Natural Gas**

Our Natural Gas segment consists of natural gasgathering and transmission pipelines, treating and processing plants andrelated facilities predominantly located in active producing basins in east andnorth Texas, as well as the Texas panhandle and western Oklahoma. Our NaturalGas segment includes nine natural gastreating plants and 17 natural gasprocessing plants at December 31, 2006, excluding plants that are inactiveor under construction. In addition, our Natural Gas segment includes approximately 11,000 miles of natural gasgathering and transmission pipelines, as well as trucks, trailers and rail carsused for transporting natural gas liquids (“NGL” or “NGLs”), crude oil andcarbon 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 other interconnectednatural gas pipeline systems. We primarily undertake marketing activities toincrease the 

F-10

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utilization of our naturalgas pipelines, realize incremental margin on gas purchased at the wellhead, andprovide value-added services to customers.

Our Marketing businesspurchases third-party pipeline transportation capacity which provides usand our customers 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 inject and storenatural gas over various periods of time for withdrawal as these productsbecome needed by end users of natural gas. These contracts may be denoted asfirm transportation, interruptible transportation, firm storage, interruptiblestorage, or parking and lending services. These various contract structures areused to mitigate risk associated with our natural gas purchase and salecontracts and to provide us with opportunities to competitively market thenatural gas and NGL products.

**2. SUMMARY OFSIGNIFICANT ACCOUNTING POLICIES**

***Basis of Presentation and Use of Estimates***

We prepare ourconsolidated financial statements in accordance with accounting principlesgenerally accepted in the United States of America (“GAAP”). Our preparation ofthese 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. We record the effectof any revisions to these estimates in our consolidated financial statements inthe period in which the facts that give rise to the revision become known.

***Principles of Consolidation***

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

***Accounting for Regulated Operations***

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 our natural gassystems are subject to the provisions of Statement of Financial AccountingStandards (“SFAS”) No. 71, *Accountingfor the Effects of Certain Types of Regulation.*Accordingly, werecord certain assets and liabilities that result from the regulated ratemakingprocess that would not be recorded for non-regulated entities under U.S. GAAP.

***Revenue Recognition and the Estimation of Revenues andCost 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 our crude oil storage assets. The tariffsestablished for our interstate pipelines specify the amounts to be paid byshippers for service between receipt and delivery locations and the generalterms and conditions of transportation services on the respective pipelinesystems. We recognize revenue upon delivery of products to our customers, whenpricing is determinable and collectibility is reasonably assured. We recognizecontract storage revenues based on contractual terms under which customers payfor the option to use available storage capacity and/or a fee based onthrough-put volumes. We recognize revenues as storage 

F-11

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servicesare rendered, pricing is determinable and collectibility is reasonably assured.In the Liquids segment, we generally do not own the crude oil and liquidpetroleum that we transport or store, and therefore, we do not assumesignificant direct commodity price risk.

**Natural Gas**

We recognize revenue upondelivery of natural gas and NGLs to customers, when services are rendered,pricing is determinable and collectibility is reasonably assured. We deriverevenue in our Natural Gas segment 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.

*Other Arrangements:*

We also use other types of arrangements to deriverevenues for our Natural Gas segment. These arrangements expose us to commodityprice risk, which we substantially mitigate with offsetting physical purchasesand sales and by the use of derivative financial instruments to hedge openpositions. We will continue to hedge a significant amount of our commodityprice risk to support the stability of our cash flows. Refer to Note 15for more information about the derivative activities we use to mitigate thiscommodity price risk.

These other typesof arrangements are categorized as follows:

·       Percentage-of-IndexContracts—Under these contracts, we purchase raw natural gas at a negotiateddiscount to an agreed upon index price. We then resell the natural gas,generally for the index 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 extracted from natural gas that requires processing, which we thensell at market prices and retain as our fee. This contract structure is similarto percentage-of-proceeds arrangements except that we only receive a percentageof 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 atmarket prices, the resulting residue gas. In those instances when we gather andprocess raw natural gas for the account of the producer, we must return to theproducer residue gas with an energy content equivalent to the original raw gaswe received as measured in British thermal units, or Btu.

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Under the terms of each ofthese contract structures, we retain a portion of the natural gas and NGLs asour fee in exchange for providing these producers with our services. In orderto protect our unitholders from volatility in our cash flows that can resultfrom fluctuations in commodity prices, we enter into derivative financialinstruments to effectively fix the sales price of the natural gas and NGLs weanticipate 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 processednatural gas and NGLs, although the market price of these commodities willcontinue to fluctuate during 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 revenueson natural gas purchased at the wellhead, and to provide other services valuedby our customers. In general, natural gas purchased and sold by our Marketingbusiness is priced at a published daily or monthly index price. Sales towholesale customers typically incorporate a premium for managing theirtransmission and balancing requirements. Higher premiums and associatedrevenues result from transactions that involve smaller volumes or that offergreater service flexibility for wholesale customers. At the request of somecustomers, we will enter into long-term fixed price purchase or sales contractswith our customers and usually will enter into offsetting positions under thesame or similar terms. We recognize revenues upon delivery of natural gas andNGLs to our customers, when services are rendered, pricing is determinable andcollectibility is reasonably assured.

**Estimation ofRevenue and Cost of Natural Gas**

For our natural gas andmarketing businesses, we must estimate our current month revenue and cost ofgas to permit 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, 2006, 2005 and 2004. 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 our obligation, which occurs when ourfinancial institution honors a check that the creditor has presented forpayment. As such, included in Accounts payable and other on our ConsolidatedStatements of Financial Position are obligations for which we have issued checkpayments that have not yet been presented to the financial institution ofapproximately $46.9 million and$46.5 million at December 31, 2006 and 2005, respectively.

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***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 specific identificationmethod.

***Inventory***

Inventory includes product inventory and materials andsupplies inventory. We record all product inventories at the lower of our costas determined on a weighted average basis, or market. The product inventoryconsists of liquids and natural gas. Upon disposition, product inventory isrecorded to Cost of natural gas at the weighted average cost of inventory,including any adjustments recorded to reduce inventory to market value.

Materials and suppliesinventory is either used during operations and charged to operating expense asincurred, or used for capital projects and new construction, and capitalized toproperty, plant and equipment.

***Oil Measurement Gains and Losses***

Oil measurementgains and losses occur as part of the normal operating conditions associatedwith our Liquids pipelines. The three types of oil measurement gains and lossesinclude:

·       physical,which occur through evaporation, shrinkage, differences in measurement betweenreceipt and delivery locations and other operational incidents;

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

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

Difficulties are inherentin quantifying oil measurement gains and losses because physical measurementsof volumes are not practical, as products continuously move through ourpipelines and virtually all of these pipelines are located underground. Quantifyingoil measurement gains and losses is especially difficult for us because of thelength of the pipeline systems and the number of different grades of crude oiland types of crude oil products we carry. We utilize engineering-basedmodels and operational assumptions to estimate product volumes in our systemsand associated oil measurement gains and losses. Material changes in ourassumptions may result in revisions to our oil measurement gain and lossestimates 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. Theimbalances are settled through periodic cash payments or repaid in kind throughthe receipt or delivery of natural gas in the future. Gas imbalances arerecorded as Accrued receivables and Accrued purchases on our Consolidated Statementsof Financial Position using the posted index prices, which approximate marketrates, or our weighted average cost of gas.

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***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 replaced, improved, or the useful lives have been extended; or (3) allland, regardless of cost. Acquisitions of new assets, additions, replacementsand improvements (other than land) costing less than the minimum rule inaddition to maintenance and 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 ofRegulation,* 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 governmental regulations anddeveloping industry standards. Examples of enhancement expenditures includecosts associated with installation of seals, liners and other equipment toreduce the risk of environmental contamination from crude oil storage tanks,costs of sleeving a major segment of a pipeline system following an integritytool run, natural gas or crude oil well-connects, natural gas plants andpipeline construction and expansion.

Regulatory guidance issued by the FERC requires us toexpense certain costs associated with implementing the pipeline integritymanagement requirements of the U.S. Department of Transportation’s Office ofPipeline Safety. Under this guidance, beginning in January 2006, costs to1) prepare a plan to implement the program, 2) identify high consequenceareas, 3) develop and maintain a record keeping system and 4) inspect, test andreport on the condition of affected pipeline segments to determine the need forrepairs or replacements, are required to be expensed. We adopted this guidanceprospectively in January 2006 for all our pipeline systems. 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 continue to becapitalized. We have historically capitalized initial in-line inspectionprograms, crackdetection tool runs and hydrostatic testing costs conducted for the purposes ofdetecting manufacturing or construction defects. Beginning January 2006,costs of this nature are expensed as incurred, which is consistent withindustry practice and the regulatory guidance issued by the FERC. However, we continue to capitalize initialconstruction hydrostatic testing cost and subsequent hydrostatic testingprograms conducted for the purpose of increasing pipeline capacity inaccordance with our capitalization policies. Also capitalized are certain costssuch as sleeving or recoating existing pipelines, unless the expenditures areincurred as a single event and not part of a major program, in which case weexpense these costs as incurred. Our adoption of the regulatory guidance didnot significantly affect our financial position, results of operations or cashflows.

We record property, plant and equipment at itsoriginal cost, which we depreciate on a straight-line basis 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. Our determination ofthe useful lives of property, plant and equipment requires us to make variousassumptions, including the supply of and demand for hydrocarbons in the marketsserved by our assets, normal wear and tear of the facilities, and the extentand frequency of maintenance programs. We routinely utilize consultants andother experts to assist us in assessing the remaining lives of the crude oil ornatural gas production in the basins we serve.

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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 typically chargedto accumulated depreciation and no gain or loss on disposal is recognized. However,when a separately identifiable group of assets, such as a stand-alone pipelinesystem is sold, we will recognize a gain or loss in our Consolidated Statementsof Income for the difference between the cash received and the net book valueof the assets sold. Changes in any of our assumptions may alter the rate atwhich we recognize depreciation in our consolidated financial statements. Atregular intervals, we retain the services of independent consultants to assistus with assessing the reasonableness of the useful lives we have establishedfor the property, plant and equipment of our major systems. Based on theresults of these regular assessments we may make modifications to theassumptions we use to determine our 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, the market and business environments toidentify indicators that could 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 the fair valueusing present value techniques requires us to make projections and assumptionsregarding the probability of a range of outcomes and the rates of interest usedin the present 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.

***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. We have notidentified or recognized any goodwill impairments during the years endedDecember 31, 2006, 2005 or 2004.

***Intangibles, Net***

Intangibles, net, consist of customer contracts forthe purchase and sale of natural gas and natural gas supply opportunities. Weamortize these assets on a straight-line basis over the weighted average usefullife of the underlying assets, representing the period over which the asset isexpected to contribute directly or indirectly to our future cash flows.

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We evaluate the carryingvalue of our 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. We did not identify nor recognize any impairment ofour intangible assets for the years ended December 31, 2006, 2005, or 2004.

***Other Assets***

Other assets primarilyinclude deferred financing costs, which we amortize on a straight-line basis,which approximates the effective interest method, over the life of the relateddebt to interest expense on our Consolidated Statements of Income.

***Income Taxes***

We are not a taxable entity for U.S. federal incometax purposes or for the majority of states that impose income tax. These taxeson our net income are borne by our unitholders through the allocation oftaxable income. In May 2006, the State of Texas enacted substantialchanges to its tax structure beginning in 2007 by imposing a new tax based uponmodified gross revenue. Under the provisions of Statement of FinancialAccounting Standards No. 109, *Accountingfor Income Taxes,*we have determined that this tax is an income tax.As a result, we have recognized deferred income tax assets and liabilities fortemporary differences between the relevant basis of our assets and liabilitiesfor financial reporting and tax purposes. The impact of changes in taxlegislation on deferred income tax liabilities and assets is recorded in theperiod of enactment. Our initial accounting for the enactment of this incometax did not materially affect our results of operation, financial condition orcash flows.

Net income for financialstatement purposes may differ significantly from taxable income of unitholdersas a result of differences between the tax basis and financial reporting basisof assets and liabilities and the taxable income allocation requirements underour partnership agreement. The aggregate difference in the basis of our netassets for financial and tax reporting purposes cannot be readily determinedbecause information regarding each partner’s tax attributes in us is notavailable.

***Derivative Financial Instruments***

Our net income and cash flows are subject tovolatility stemming from changes in interest rates and commodity prices of naturalgas, NGL, condensate and fraction margins (the relative price differentialbetween NGL sales and the offsetting natural gas purchases). In order to managethe risks to unitholders, we use a variety of derivative financial instrumentsincluding futures, forwards, swaps, options and other financial instrumentswith similar characteristics to create offsetting positions to specificcommodity or interest rate exposures. In accordance with SFAS No. 133, *Accounting for Derivative Instruments and Hedging Activities*(“SFAS No. 133”), we record all derivative financial instruments on ourConsolidated Statements of Financial Position at fair market value. We recordthe fair market value of our derivative financial instruments in theConsolidated Statements of Financial Position as current and long-term assetsor liabilities on a net basis by counterparty. For those instruments thatqualify for hedge accounting, the accounting treatment depends on the intendeduse and designation of each instrument. For our derivative financialinstruments related to commodities that do not qualify for hedge accounting,the change in market value is recorded as a component of Cost of natural gas inthe Consolidated Statements of Income. For our derivative financial instrumentsrelated to interest rates that do not qualify for hedge accounting, the changein fair market value is recorded as a component of Interest expense in theConsolidated Statements of Income.

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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 or anticipated transaction and we do notuse derivative financial instruments for speculative purposes.

Derivative financial instruments qualifying for hedgeaccounting treatment that we use can generally be divided into two categories:1) cash flow hedges, or 2) fair value hedges. We enter into cash flowhedges to reduce the variability in cash flows related to forecastedtransactions. We enter into fair value hedges to reduce the risk of changes inthe value of recognized assets or liabilities.

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 valuations 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 thecreditworthiness of our counterparties to manage against the risk of default. Ifwe determine that a derivative is no longer highly effective as a hedge, wediscontinue hedge accounting prospectively by including changes in the fairvalue of the derivative in current earnings.

For cash flow hedges, changes in the fair marketvalues of derivative financial instruments, to the extent that the hedges aredetermined to be highly effective, are recorded as a component of Accumulatedother comprehensive income until the hedged transactions occur and arerecognized in earnings. Any ineffective portion of a cash flow hedge’s changein fair market value is recognized immediately in earnings. For fair valuehedges, the change in fair market value of the financial instrument isdetermined each period and is taken into earnings. In addition, the change inthe fair market value of the hedged item is also calculated and taken intoearnings. To the extent that the two valuations offset, the hedge is effectiveand net earnings is not affected.

Our earnings are alsoaffected by use of the mark-to-market method of accounting as required underGAAP for derivative financial instruments that do not qualify for hedgeaccounting. We use short-term, highly liquid derivative financial instrumentssuch as basis swaps and other similar derivative financial instruments toeconomically hedge market price risks associated with inventories, firmcommitments and certain anticipated transactions, primarily within ourMarketing segment. However, these derivative financial instruments, do notqualify for hedge accounting treatment under SFAS No. 133, and thus thechanges in fair value of these instruments are recorded on the balance sheetand through earnings (i.e., using the “mark-to-market” method) rather thanbeing deferred until the firm commitment or anticipated transaction affectsearnings. The use of mark-to-market accounting for financial instruments cancause non-cash earnings volatility due to changes in the underlying indices,primarily commodity prices. The fair market value of these derivative financialinstruments is determined using price data from highly liquid markets such asthe New York Mercantile Exchange, or NYMEX, OTC market makers, or other similarsources.

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***Commitments,Contingencies and Environmental Liabilities***

We expense or capitalize,as appropriate, expenditures for ongoing compliance with environmentalregulations that relate to past or current operations. Amounts for remediationof existing environmental contamination caused by past operations, which do notbenefit future periods by preventing or eliminating future contamination, areexpensed. Liabilities are recorded when environmental assessments indicate thatremediation efforts are probable, and the costs can be reasonably estimated. Estimatesof the liabilities are based on currently available facts, existing technologyand presently 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 forother contingencies when, after fully analyzing the available information, wedetermine it is either probable that an asset has been impaired or that aliability has been incurred and the amount of impairment or loss can bereasonably estimated. When a range of probable loss can be estimated, we accruethe most likely amount, or if no amount is more likely than another, theminimum of the range of probable loss. We typically expense legal costsassociated with loss contingencies as such costs are incurred.

***Asset RetirementObligations***

We record a liability forthe fair value of asset retirement obligations, or ARO, on a discounted basis,in the period in which the liability is incurred. Typically we record an ARO atthe time the assets are installed or acquired, if a reasonable estimate of fairvalue can be made. In connection with establishing an ARO, we capitalize thecosts as part of the carrying value of the related assets. We recognize anongoing expense for the interest component of the liability as part ofdepreciation expense resulting from changes in the value of the ARO due to thepassage of time. We depreciate the initial capitalized costs over the usefullives of the related assets. We extinguish the liabilities for AROs when assetsare taken out of service or otherwise abandoned.

In December 2005, weadopted the provisions of Financial Accounting Standards Board (“FASB”)Interpretation No. 47, *Accounting forConditional Asset Retirement Obligations, 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 reasonably estimable including when sufficientinformation is available to apply an expected present value technique. Asindicated in the table below, our implementation of FIN 47 did not have amaterial 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 onshore right-of-way agreementsdue to requirements or landowner options to compel us to remove the pipe atfinal abandonment. Sufficient data exists with certain onshore pipeline systemsto reasonably estimate an abandonment retirement obligation cost. However, insome cases, there is insufficient information to reasonably determine thetiming and/or method of settlement for estimating the fair value of the assetretirement obligation. In these cases, the asset retirement obligation cost isconsidered indeterminate because there is no data or information that can bederived from past practice, industry practice, management’s intent, or theasset’s estimated economic life. Useful lives of most pipeline systems 

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areprimarily derived from available supply resources and ultimate consumption ofthose resources by end users. Variables can affect the remaining lives of theassets which preclude us from making a reasonable estimate of the assetretirement obligation. Indeterminate asset retirement obligation costs will berecognized in the period in which sufficient information exists to reasonablyestimate potential settlement dates and methods.

We did not record anyadditional AROs for the year ended December 31, 2006, and recorded anasset and liability of $2.1 million for AROs for the year ended December 31,2005. We recorded accretion expense of $0.2 million,$0.5 million and $0.1 million, respectively, in the Consolidated Statementsof Income for the years ended December 31, 2006, 2005 and 2004 forpreviously recorded asset retirement obligation liabilities.

Noassets are legally restricted for purposes of settling our ARO for each of theyears ended December 31, 2006 and 2005. Following is a reconciliation ofthe beginning and ending aggregate carrying amount of our ARO liabilities foreach of the years ended December 31, 2006 and 2005:

|                                          | ** ** | **2006**               | ** ** | **2005** | ** ** |
|------------------------------------------|------------|------------------------|------------|----------|------------|
| ** **                               | ** ** | **(in millions)** | ** ** |
| Balance at beginning of  period          |       | $                      | 3.6        |     | $          | 1.0 |   |
| Implementation of  FIN 47—Liability |       | —                 |       | 2.1      |       |
| Accretion expense                        |       | 0.2                    |       | 0.5      |       |
| Balance at end of period                 |       | $                      | 3.8        |     | $          | 3.6 |   |

 

***Comparative Amounts***

We have madereclassifications to the prior years’ reported amounts to conform to ourpresentation in the 2006 consolidated financial statements. Thesereclassifications were made within the Consolidated Statements of Cash Flowswithin net cash provided by operating activities and have no effect on netincome.

***Recent AccountingPronouncements Not Yet Adopted***

**Fair Value Measurements**

In September 2006,the Financial Accounting Standards Board (FASB) issued FASB Statement No. 157,*Fair Value Measurements.*This statementdefines fair value, establishes a framework for measuring fair value ingenerally accepted accounting principles (GAAP), and expands disclosures aboutfair value measurement. The statement is effective for fiscal years beginningafter November 15, 2007, and with limited exceptions is to be appliedprospectively as of the beginning of the fiscal year initially adopted. Weexpect to adopt the provisions of this statement prospectively beginning January 1,2008. We do not expect our adoption of this pronouncement to materially affectour consolidated financial statements. However, our adoption of thispronouncement may affect our disclosures regarding derivative financialinstruments and indebtedness.

**Accounting forRegistration Payment Arrangements**

In December 2006, theFASB issued FASB Staff Position FSP EITF 00-19-2, *Accounting for Registration Payment Arrangements*. This FASBStaff Position, or FSP, specifies that the contingent obligation to make futurepayments or otherwise transfer consideration under a registration paymentarrangement, whether issued as a separate agreement or included as a provisionof a financial instrument or other agreement, should be separately recognizedand measured in accordance with FASB Statement No. 5, *Accountingfor Contingencies*. This FSP also requires certain disclosures regardingregistration payment arrangements and liabilities recorded for such purposes. ThisFSP is immediately effective for registration payment arrangements entered intoor modified after December 21, 2006. The guidance of 

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this FSPis effective for fiscal years beginning after December 15, 2006, andinterim periods within those fiscal years for registration payment arrangementsentered into prior to December 21, 2006. This FSP requires adoption byreporting a change in accounting principle through a cumulative-effectadjustment to the opening balance of our partners’ capital accounts as of thefirst interim period of the year in which this FSP is initially applied. We donot expect our adoption of this FSP to materially affect our financialposition, results of operations or cash flows.

***StaffAccounting Bulletin No. 108***

In September 2006, theSecurities and Exchange Commission issued Staff Accounting BulletinNo. 108. This Bulletin requires a “dual approach” for quantifications oferrors using both a method that focuses on the income statement impact,including the cumulative effect of prior years’ misstatements, and a methodthat focuses on the period-end balance sheet. We adopted SAB No. 108 as of December 31,2006. The adoption of this Bulletin did not have a material impact on ourconsolidated financial statements.

**3. ACQUISITIONS AND DISPOSITIONS**

We accounted for each ofour completed acquisitions using the purchase method and recorded the assetsacquired and liabilities assumed at their estimated fair market values as ofthe date of purchase. We have included the results of operations from each ofthese acquisitions in our earnings from the acquisition date.

***2006 Acquisitionsand Dispositions***

**Oakhill Acquisition**

In April 2006, weacquired, for $33.3 million in cash, an 80-mile natural gas pipeline thatis complementary to our existing East Texas system. This pipeline providesapproximately 100 million cubic feet per day, or MMcf/d, of additional transportationcapacity and interconnects with approximately 65 central receipt points.

Thepurchase price and the allocation to assets acquired and liabilities assumedare as follows in millions of dollars:

| Purchase Price:                                                    |   |   |   |
|--------------------------------------------------------------------|--------|--------|--------|
| Cash paid, including transaction costs                             |   | $      | 33.3   |   |
| Allocation of purchase  price:                                     |   |   |   |
| Property, plant and equipment, including  construction in progress |   | $      | 13.0   |   |
| Intangibles                                                        |   | 12.8   |   |
| Goodwill                                                           |   | 7.5    |   |
| Total                                                              |   | $      | 33.3   |   |

 

***2005 Acquisitions and Dispositions***

**North Texas NaturalGas 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. Theassets we acquired serve the Fort Worth Basin, which is mature, butexperiencing minimal production decline rates and include:

·       2,200 miles of gasgathering pipelines; and

·       four processing plants withaggregate processing capacity of 121 MMcf/d of natural gas.

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The system provides cashflow primarily from purchasing raw natural gas from producers at the wellhead,processing the natural gas and then selling the natural gas liquids and residuenatural gas streams. We included the assets and results of operations in ourNatural Gas segment from the acquisition date.

Weallocated the purchase price of the assets acquired and liabilities assumed asfollows (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.

**Sale of 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 MillionBritish Thermal units per day, or MMBtu/d, associated with the natural gasproduced by these assets and entered into offsetting derivatives at market toclose out derivatives previously classified as hedges of 273 Barrels per day,or Bpd, of NGL produced by these assets. We had previously recorded unrealizedlosses associated with the natural gas collars that were realized uponsettlement. Refer to Note 15 for additional discussion regarding our derivativeactivities.

***2004 Acquisitions***

**Mid-Continent System**

In March 2004,we acquired crude oil pipeline and storage assets, which we refer to 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:

·       The 433-mile Ozarkpipeline from Cushing to Wood River, Illinois;

·       A 1.2 million barrelstorage terminal located in El Dorado, Kansas;

**·****     **The 47-mile WestTulsa pipeline in Oklahoma; and

·       A storage terminal atCushing, with 8.3 million barrels of storage capacity.

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These systems wereacquired to provide cash flows primarily from toll or fee-based revenues from acombination of regulated assets and contracted unregulated assets. We includedthe assets and results of operations in our Liquids segment from theacquisition date. The value allocated to the assets was determined by anindependent appraisal.

Weallocated the purchase price to assets acquired and liabilities assumed asfollows (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 completedfive separate acquisitions of natural gas assets for a total of$10.9 million. The purchase price for these acquisitions was applied toproperty, plant, and equipment with no associated goodwill recorded. Weincluded the results of operations for the acquisitions in our Natural Gassegment from the acquisition date.

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, andhave increased our 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. Weallocated the purchase price for this acquisition 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.

**4**. NET INCOME PER LIMITED PARTNER UNIT

Wecompute net income per limited partner unit by dividing net income, afterdeducting our allocation to the General Partner, by the weighted average numberof our limited partner units outstanding. The General Partner’s allocation isequal to an amount based upon its general partner interest, adjusted to reflectan amount equal to its incentive distributions and an amount required toreflect depreciation on the General Partner’s historical cost basis for assetscontributed on formation of the Partnership. We have no dilutive securities,therefore basic and diluted earnings perunit amounts are equal. Net income per limited partner unit wasdetermined as follows:

|                                                          | ** ** | **Year ended December 31,**                      | ** ** |
|----------------------------------------------------------|------------|-----------------------------------------------------------------|------------|
| ** **                                               | ** ** | **2006**                                                        | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                                               | ** ** | **(in millions,  except per unit amounts)** | ** ** |
| Net income                                               |       | $                                                               | 284.9      |   | $ | 89.2 |   | $ | 138.2 |   |
| Allocations to the  General Partner:                     |       |                                                            |       |   |   |   |   |
| Net income allocated to  General Partner                 |       | (5.7                                                            | )          | (1.8 | ) | (2.8 | ) |
| Incentive distributions  to General Partner              |       | (25.1                                                           | )          | (21.6 | ) | (19.6 | ) |
| Historical cost depreciation  adjustments                |       | (0.1                                                            | )          | (0.1 | ) | (0.1 | ) |
|                                                     |       | (30.9                                                           | )          | (23.5 | ) | (22.5 | ) |
| Net income allocable to  limited partner units           |       | $                                                               | 254.0      |   | $ | 65.7 |   | $ | 115.7 |   |
| Weighted average units  outstanding                      |       | 70.2                                                            |       | 62.1 |   | 56.1 |   |
| Net income per limited  partner unit (basic and diluted) |       | $                                                               | 3.62       |   | $ | 1.06 |   | $ | 2.06 |   |

 

F-23

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**5. INVENTORY**

Inventoryis comprised of the following:

|                                                | ** ** | **December 31,**  | ** ** |
|------------------------------------------------|------------|------------------------|------------|
| ** **                                     | ** ** | **2006**               | ** ** | **2005** | ** ** |
| ** **                                     | ** ** | **(in millions)** | ** ** |
| Material and supplies                          |       | $                      | 3.8        |   | $ | 8.3 |   |
| Liquids inventory                              |       | 9.9                    |       | 11.1 |   |
| Natural gas and natural gas  liquids inventory |       | 103.4                  |       | 119.5 |   |
|                                           |       | $                      | 117.1      |   | $ | 138.9 |   |

 

Our inventory at December 31,2006 is net of charges totaling $17.7 million we recorded in 2006 to reduce thecost basis of our natural gas inventory to reflect market value. The lower of costor market adjustments are included in the Cost of natural gas of our NaturalGas and Marketing segments on our Consolidated Statements of Income.

**6. PROPERTY, PLANTAND EQUIPMENT**

Property,Plant and Equipment is comprised of the following:

|                                                     | ** ** | **Depreciation** | ** ** | **December 31,**  | ** ** |
|-----------------------------------------------------|------------|------------------|------------|------------------------|------------|
| ** **                                          | ** ** | **Rates**        | ** ** | **2006**               | ** ** | **2005** | ** ** |
| ** **                                          | ** ** | ** **       | ** ** | **(in millions)** | ** ** |
| Land                                                |       | —           |       | $                      | 14.3       |   | $ | 13.8 |   |
| Rights-of-way                                       |       | 1.5%  - 6.4%     |       | 298.6                  |       | 280.2 |   |
| Pipeline                                            |       | 0.6%  - 12.0%    |       | 2,320.8                |       | 2,194.2 |   |
| Pumping equipment,  buildings and tanks             |       | 1.5%  - 14.3%    |       | 747.4                  |       | 673.0 |   |
| Compressors, meters, and  other operating equipment |       | 0.6%  - 20.0%    |       | 418.1                  |       | 310.0 |   |
| Vehicles, office  furniture and equipment           |       | 0.6%  - 33.3%    |       | 112.4                  |       | 102.7 |   |
| Processing and treating  plants                     |       | 2.7%  - 4.0%     |       | 86.4                   |       | 79.0 |   |
| Construction in  progress                           |       | —           |       | 733.6                  |       | 209.1 |   |
| Total property, plant and  equipment                |       |             |       | 4,731.6                |       | 3,862.0 |   |
| Accumulated  depreciation                           |       |             |       | (906.7                 | )          | (782.0 | ) |
| Net property, plant and  equipment                  |       |             |       | $                      | 3,824.9    |   | $ | 3,080.0 |   |

 

We have assets included in the above table that arehighly depreciated, which yield depreciation rates that suggest these assetshave significant remaining useful lives.

Based on third-partystudies commissioned by management, we implemented revised depreciation ratesfor the Lakehead system effective January 1, 2006, and the Anadarko, NorthTexas and East Texas systems effective August 1, 2005. We reduced theannual composite rate, representing the expected remaining service lives of thesystem assets, from 3.20% to 2.63% for our Lakehead system and from 4.0% to3.4% for our Anadarko, North Texas and East Texas systems. As a result, ourdepreciation expense for the years ended December 31, 2006 and 2005,respectively, was approximately $14.5 million and $2.5 million lower than ifthese rates had not been reduced. Additionally, effective July 1, 2006, weincreased the annual composite rates on three of our FERC-regulated pipelines,representing reductions to the expected remaining service lives of our AlaTenn,KPC and Midla systems. These increases resulted in approximately $1.3 millionof additional depreciation in 2006.

F-24

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**7. GOODWILL**

Thechanges in the carrying amount of goodwill for each of the years ended December 31,2006 and 2005 are as follows:

|                                       | ** ** | **Liquids**            | ** ** | **Natural Gas** | ** ** | **Marketing** | ** ** | **Corporate** | ** ** | **Total** | ** ** |
|---------------------------------------|------------|------------------------|------------|----------------------|------------|---------------|------------|---------------|------------|-----------|------------|
| ** **                            | ** ** | **(in millions)** | ** ** |
| Balance as of  December 31, 2004 |       |                   | $          | —               |       |          |       | $             | 236.8      |      |       |   | $ | 20.4 |   |   |   | $ | — |   |   | $ | 257.2 |   |
| Purchase price adjustments            |       |                   | —     |                 |       |          | 1.0        |          |       |      | —     |   |   |   | — |   |   | 1.0 |   |
| Balance as of  December 31, 2005 |       |                   | —     |                 |       |          | 237.8      |          |       |      | 20.4       |   |   |   | — |   |   | 258.2 |   |
| Acquisition                           |       |                   | —     |                 |       |          | 7.5        |          |       |      | —     |   |   |   | — |   |   | 7.5 |   |
| Balance as of  December 31, 2006 |       |                   | $          | —               |       |          |       | $             | 245.3      |      |       |   | $ | 20.4 |   |   |   | $ | — |   |   | $ | 265.7 |   |

 

We completed our annualgoodwill impairment test using data at June 30, 2006. To estimate the fairvalue of our reporting units we made estimates and judgments about future cashflows, as well as revenue, cost of sales, operating expenses, capital expenditures,and net working capital based on assumptions that are consistent with thelong-range plans we use to manage our businesses. Based on the results of ourimpairment analysis, we determined that the fair value of each reporting unitexceeded its respective carrying amount, including goodwill. As a result, nogoodwill impairment existed in any of our reporting units. We have not observedany events or circumstances subsequent to our analysis that would, more likelythan not, reduce the fair value of our reporting units below the carryingamounts as of December 31, 2006.

**8. INTANGIBLES**

Thefollowing table provides the gross carrying value, accumulated amortization andactivity affecting these balances for each of our major classes of intangibleassets.

|                                    | ** ** | **Gross Carrying Amount** | ** ** | **Accumulated Amortization**           | ** ** |
|------------------------------------|------------|-------------------------------------|------------|---------------------------------------------|------------|
| ** **                         | ** ** | **Customer  Contracts**             | ** ** | **Natural Gas  Supply  Opportunities** | ** ** | **Intangible  Assets  Gross** | ** ** | **Customer  Contracts** | ** ** | **Natural Gas  Supply  Opportunities** | ** ** | **Accumulated  Amortization  Gross** | ** ** | **Intangible  Assets, Net** | ** ** |
| ** **                         | ** ** | **(in millions)**              | ** ** |
| Balance at December 31,  2003 |       |                                | $          | 31.1                                        |       |   |   | $ | 48.1 |   |   |   | $ | 79.2 |   |   |   | $ | (2.0 | ) |   |   | $ | — |   |   |   | $ | (2.0 | ) |   |   | $ | 77.2 |   |   |
| Amortization                       |       |                                | —     |                                        |       |   | — |   |   |   | — |   |   |   | (1.3 | ) |   |   | (1.9 | ) |   |   | (3.2 | ) |   |   | (3.2 | ) |   |
| Balance at December 31,  2004 |       |                                | 31.1       |                                        |       |   | 48.1 |   |   |   | 79.2 |   |   |   | (3.3 | ) |   |   | (1.9 | ) |   |   | (5.2 | ) |   |   | 74.0 |   |   |
| Acquisitions                       |       |                                | 14.3       |                                        |       |   | — |   |   |   | 14.3 |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | 14.3 |   |   |
| Dispositions                       |       |                                | (2.2       | )                                           |       |   | — |   |   |   | (2.2 | ) |   |   | 0.3 |   |   |   | — |   |   |   | 0.3 |   |   |   | (1.9 | ) |   |
| Amortization                       |       |                                | —     |                                        |       |   | — |   |   |   | — |   |   |   | (1.7 | ) |   |   | (2.0 | ) |   |   | (3.7 | ) |   |   | (3.7 | ) |   |
| Balance at December 31,  2005 |       |                                | 43.2       |                                        |       |   | 48.1 |   |   |   | 91.3 |   |   |   | (4.7 | ) |   |   | (3.9 | ) |   |   | (8.6 | ) |   |   | 82.7 |   |   |
| Acquisitions                       |       |                                | 12.8       |                                        |       |   | — |   |   |   | 12.8 |   |   |   | — |   |   |   | — |   |   |   | — |   |   |   | 12.8 |   |   |
| Amortization                       |       |                                | —     |                                        |       |   | — |   |   |   | — |   |   |   | (2.2 | ) |   |   | (1.9 | ) |   |   | (4.1 | ) |   |   | (4.1 | ) |   |
| Balance  at December 31, 2006 |       |                                | $          | 56.0                                        |       |   |   | $ | 48.1 |   |   |   | $ | 104.1 |   |   |   | $ | (6.9 | ) |   |   | $ | (5.8 | ) |   |   | $ | (12.7 | ) |   |   | $ | 91.4 |   |   |

 

Our customer contracts are comprised entirely ofnatural gas purchase and sale agreements associated with our Natural Gas andMarketing segments. We amortize our customer contracts on a straight-line basisover the weighted average useful life of the underlying reserves at the time ofacquisition, which approximates 25 years.

F-25

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We obtained the natural gas supply opportunities inconjunction with the 2003 North Texas system acquisition and relate entirely toour Natural Gas segment. The value of the intangible asset was determined by athird party appraisal and it represents the fair value associated with growthopportunities present in the Barnett Shale producing zone. We are amortizingthe natural gas supply opportunities over the weighted average estimated usefullife of the underlying reserves at the time of the acquisition, whichapproximates 25 years.

We estimate theamortization expense associated with our intangibles for each year through December 31,2011 to approximate $4.2 million.

**9. DEBT**

Thefollowing table presents the primary components of our outstanding indebtednessand the weighted average interest rates associated with each component at theend of each period presented, before the effect of our interest rate hedgingactivities as discussed in Notes 14 and 15:

|                                         | ** ** | **December 31,**               | ** ** |
|-----------------------------------------|------------|-------------------------------------|------------|
| ** **                              | ** ** | ** **                          | ** ** | **2006** | ** ** | **2005** | ** ** |
| ** **                              | ** ** | **Maturity**                        | ** ** | **Rate** | ** ** | **Dollars** | ** ** | **Rate** | ** ** | **Dollars** | ** ** |
| ** **                              | ** ** | **(dollars in millions)** | ** ** |
| First Mortgage Notes                    |       | 2011                                |       | 9.15 | % | $ | 155.0 |   | 9.15 | % | $ | 186.0 |   |
| Senior Notes                            |       | 2009-2034                           |       | 5.74 | % | 1,498.4 |   | 5.70 | % | 1,198.6 |   |
| Credit Facility                         |       | 2010                                |       | — |   | — |   | — |   | — |   |
| Commercial Paper(1)                     |       | 2010                                |       | 5.45 | % | 443.7 |   | 4.36 | % | 329.3 |   |
|                                         |       |                                |       |   |   | $ | 2,097.1 |   |   |   | $ | 1,713.9 |   |
| Current  maturities and short-term debt |       |                                |       |   |   | (31.0 | ) |   |   | (31.0 | ) |
| Long-term debt                          |       |                                |       |   |   | $ | 2,066.1 |   |   |   | $ | 1,682.9 |   |

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(1)                Individualissuances of commercial paper generally mature in 90 days or less, but aresupported by our credit facility and are therefore considered long-term debt.

***First Mortgage Notes***

The First Mortgage Notes (“Notes”) are collateralizedby a first mortgage lien on substantially all of the property, plant and equipmentof the Lakehead Partnership and are due and payable in equal annualinstallments of $31.0 million until their maturity in 2011. Property,plant and equipment, net, associated with the Lakehead Partnership was $1,495.1 million and $1,384.2 millionat December 31, 2006 and 2005, respectively. The Notes contain variousrestrictive covenants applicable to us, and restrictions on the incurrence ofadditional indebtedness, including compliance with certain debt issuance tests.We believe these restrictions will not negatively impact our ability to financefuture expansion 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. We would be required to pay a redemption premium pursuant to the Noteagreements should we elect to repay the Notes prior to their stated maturity.

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, 2006 and 2005, there was norequired debt service reserve, as we have made all required interest andsinking fund payments.

F-26

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***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 unsecured and unsubordinated indebtedness. Theinterest rates set forth in this table represent the interest rates as setforth on the face of each note agreement without consideration to any discountor interest rate hedging activities.

|                                | ** ** | **Interest** | ** ** | **December 31,**  | ** ** |
|--------------------------------|------------|--------------|------------|------------------------|------------|
| **Senior Notes**          | ** ** | ** **   | ** ** | **Rate**               | ** ** | **2006** | ** ** | **2005** | ** ** |
| ** **                     | ** ** | ** **   | ** ** | **(in millions)** | ** ** |
| Senior Notes maturing in  2009 |       |         | 4.000      | %                      |       | $ | 200.0 |   | $ | 200.0 |   |
| Senior Notes  maturing in 2012 |       |         | 7.900      | %                      |       | 100.0 |   | 100.0 |   |
| Senior Notes maturing in  2013 |       |         | 4.750      | %                      |       | 200.0 |   | 200.0 |   |
| Senior Notes  maturing in 2014 |       |         | 5.350      | %                      |       | 200.0 |   | 200.0 |   |
| Senior Notes maturing in  2016 |       |         | 5.875      | %                      |       | 300.0 |   | — |   |
| Senior Notes  maturing in 2018 |       |         | 7.000      | %                      |       | 100.0 |   | 100.0 |   |
| Senior Notes maturing in  2028 |       |         | 7.125      | %                      |       | 100.0 |   | 100.0 |   |
| Senior Notes  maturing in 2033 |       |         | 5.950      | %                      |       | 200.0 |   | 200.0 |   |
| Senior Notes maturing in 2034  |       |         | 6.300      | %                      |       | 100.0 |   | 100.0 |   |
|                           |       |         |       |                   |       | 1,500.0 |   | 1,200.0 |   |
| Unamortized Discount           |       |         |       |                   |       | (1.6 | ) | (1.4 | ) |
|                           |       |         |       |                   |       | $ | 1,498.4 |   | $ | 1,198.6 |   |
|                                |            |              |            |                        |            |  |  |  |  |  |  |  |  |  |  |

 

***Credit Facility***

Our Credit Facility, as amended, is a five-year termfacility that matures in April 2010. In March 2006, we increased thecurrent borrowing capacity from $800 million to $1 billion. Additionally, ourCredit Facility has a letter of credit sublimit of $300 million. 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. A facility feeis payable on the entire amount of the Credit Facility whether or not drawn. Thefacility fee also varies depending on our credit rating. Our Credit Facilitycontains restrictive covenants that require us to maintain a minimum interestcoverage ratio of 2.75 and a maximum leverage ratio of 5.25 for twelve monthsthrough December 2006, at which time it decreases to 5.00, thereafter. At December 31,2006, our interest coverage ratio was approximately 4.4 and our leverage ratio was approximately 4.6. Our Credit Facility also placeslimitations on the debt that our subsidiaries may incur directly. Accordingly,it is expected that we will provide debt financing to our subsidiaries asnecessary. At December 31, 2006 and 2005, we had no amounts outstandingunder our Credit Facility and letters of credit totaling $59.3 million and $149.3, respectively. Theamounts we may borrow under the terms of our Credit Facility are reduced by theprincipal amount of our commercial paper issuances and the balance of ourletters of credit outstanding. At December 31, 2006, we could borrow $495.7 million under the terms of ourCredit 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 ended December 31,2005 and 2004, we net settled borrowings of approximately $565 million and$1,573 million, on a non-cash basis.

F-27

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***Commercial Paper Program***

We have a commercial paper program that provides forthe issuance of up to $600 million of commercial paper 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. At December 31, 2006, our Credit Facility remainsundrawn and available to support our commercial paper program. At December 31,2006 and 2005, respectively, we had $443.7and $329.3 million of commercial paper outstanding, net of unamortized discountof $1.3 million and $0.7 million, at aweighted average interest rate of 5.45%and 4.36% and outstanding letters of credit totaling $59.3 and $149.3 million. At December 31, 2006 and 2005,respectively, we could issue an additional $155million and $270 million in principal amount under our commercial paperprogram.

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 ConsolidatedStatement of Financial Position.

***Interest***

For the years ended December 31,2006, 2005, and 2004, interest expense is net of amounts capitalized of $10.7 million, $4.0 million, and$2.1 million. For each of the years ended December 31, 2006, 2005,and 2004, we made interest payments totaling $109.7million, $101.7 million, and $73.9 million.

***Maturities of Third Party Debt***

Thescheduled maturities of outstanding third party debt, excluding the marketvalue of interest rate swaps, at December 31, 2006, are summarized asfollows:

|            | ** ** | **(in millions)** | ** ** |
|------------|------------|------------------------|------------|
| 2007       |       |                   | $          | 31.0 |   |   |
| 2008       |       |                   | 31.0       |   |   |
| 2009       |       |                   | 231.0      |   |   |
| 2010       |       |                   | 476.0      |   |   |
| 2011       |       |                   | 31.0       |   |   |
| Thereafter |       |                   | 1,300.0    |   |   |
| **Total**  |       |                   | $          | 2,100.0 |   |   |

 

**10. PARTNERS’CAPITAL**

Our capital accounts are comprised of a two percentgeneral partner interest and 98 percent limited partner interests. The limitedpartner interests are comprised of Class A common units, Class Bcommon units, Class C units, and i-units. The limited partners havelimited rights of ownership as provided for under our partnership agreementand, as discussed below, the right to participate in our distributions. TheGeneral Partner manages our operations, subject to a delegation of controlagreement with Enbridge Management, and participates in the Partnership’sdistributions, including certain incentive income distributions.

F-28

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***Class A common units***

Thefollowing table presents the net proceeds from our Class A common unitissuances for each of the years ended December 31, 2006, 2005 and 2004. Theproceeds from each of our offerings were generally used to repay amountsoutstanding under our credit facilities or issuances of commercial paper, whichwe initially borrowed to finance our capital expansion projects andacquisitions, or to repay other outstanding obligations.

| Issuance Date                                                     | ** ** | **Number of  Class A  Common units  Issue**          | ** ** | **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)** | ** ** |
| **2006**                                                               |       |                                                                |       |                                                             |       |                                                   |       |                                  |       |                                                             |       |   |   |   |   |   |   |   |   |   |   |
| We did not issue  any Class A common units during 2006. |       |                                                                |
| **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 |   |   |

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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.

***Class B common units***

Our outstanding Class Bcommon units are held entirely by our general partner and have rights similarto our Class A common units except that they are not currently eligiblefor trading on the NYSE.

***Class C units***

In August 2006, weissued and sold 5.4 million Class C units, representing a new class oflimited partner interest, to our general partner and 5.4 million Class Cunits to an institutional investor for a purchase price of $46.00 per unit in aprivate transaction exempt from registration under Section 4(2) ofthe Securities Act of 1933. We received proceeds of approximately $500 million,net of expenses associated with the private placement. Additionally, ourgeneral partner contributed approximately $10 million to maintain its twopercent general partner interest.

***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.

EnbridgeManagement, as the owner of our i-units, votes together with the holders of thecommon units as a single class. However, the i-units vote separately as a classon the following matters:

·       Anyproposed action that would cause us to be treated as a corporation for U.S.federal income tax purposes;

F-29

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·       Amendmentsto our partnership agreement that would have a material adverse effect on theholder of our i-units, unless, under our partnership agreement, the amendmentcould be made by our general partner without a vote of holders of any class ofunits;

·       Theremoval of our general partner and the election of a successor general partner;and

·       Thetransfer by our general partner of its general partner interest to anon-affiliated person that requires a vote of holders of units under ourpartnership agreement and the admission of that person as a general partner.

In all cases, EnbridgeManagement will vote or refrain from voting its i-units in the same manner thatowners of Enbridge Management’s shares vote or refrain from voting their shares.Furthermore, under the terms of our partnership agreement, we agree that wewill not, except in liquidation, make a distribution on an i-unit other than inadditional i-units or a security that has in all material respects the samerights and privileges as the i-units.

***Distributions***

Our partnership agreement requires us to distribute100 percent of our “Available Cash”, which is generally defined in ourpartnership agreement as the sum of all cash receipts and net additions toreserves for future cash requirements less cash disbursements and amountsretained by us. Enbridge Management, as delegate of our general partner underthe delegation of control agreement, computes the amount of our “AvailableCash.” Typically, the General Partner and owners of our common units willreceive distributions in cash. However, we also retain reserves to provide forthe proper conduct of our business and as necessary to comply with the terms ofour agreements or obligations (including any reserves required under debtinstruments for future principal and interest payments and for future capitalexpenditures). We make distributions to our partners approximately 45 daysfollowing the end of each calendar quarter in accordance with their respectivepercentage 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 our 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 are generally made98.0 percent to holders of our limited partner units and 2.0 percent to ourgeneral partner. However, distributions are subject to the payment of incentivedistributions to the General Partner to the extent that certain target levelsof distributions to the unitholders are achieved. The incremental incentivedistributions payable to the General Partner are 15.0 percent, 25.0 percent and50.0 percent of all quarterly distributions of Available Cash that exceedtarget levels of $0.59, $0.70, and $0.99 per limited partner units. As setforth in our partnership agreement, we will not make cash distributions on ouri-units, but instead, will distribute additional i-units such that the cash isretained and used in our business. Similarly, until August 15, 2009, wewill distribute additional Class C units to the holders of our Class Cunits in lieu of cash distributions, which will be retained and used in ourbusiness. Further, we retain an additional amount equal to 2.0 percent of thei-unit and Class C unit distributions from the General Partner to maintainits 2 percent general partner interest in us.

Enbridge Management, as owner of the i-units, does notreceive distributions in cash. Instead, each time that the we make a cashdistribution to the General Partner and the holders of our common units, thenumber of i-units owned by Enbridge Management and the percentage of our totalunits owned by Enbridge Management will increase automatically under theprovisions of our partnership agreement with 

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the result that the numberof i-units owned by Enbridge Management will equal the number of EnbridgeManagement’s shares and voting shares that are then outstanding. The amount ofthis increase in i-units is determined by dividing the cash amount distributedper common unit by the average price of one of Enbridge Management’s listedshares on the NYSE for the 10-trading day period immediately precedingthe ex-dividend date for Enbridge Management’s shares multiplied by the numberof shares outstanding on the record date. The cash equivalent amount of theadditional i-units is treated as if it had actually been distributed forpurposes of determining the distributions to be made to the General Partner.

Until August 15, 2009, in lieu of cashdistributions, the holders of our Class C units will receive quarterlydistributions of additional Class C units with a value equal to thequarterly cash distributions we pay to the holders of our Class A and Class Bcommon units, which we collectively refer to as common units. The number ofadditional Class C units we will issue is determined by dividing thequarterly cash distribution per unit we pay on our common units by the averagemarket price of a Class A common unit as listed on the New York StockExchange for the 10-trading day period immediately preceding theex-dividend date for our Class A common units multiplied by the number of Class Cunits outstanding on the record date. As a result, the number of Class Cunits and the percentage of our total units owned by holders of the Class Cunits will increase automatically under the provisions of our partnershipagreement. The cash equivalent amount of the additional Class C units istreated as if it had actually been distributed for purposes of determining thedistributions to be made to the General Partner.

After August 15, 2009, the holders of our Class Cunits will receive quarterly cash distributions equal to those paid to theholders of our common units. Subject to the approval of holders of ouroutstanding units in accordance with the then-existing requirements of theprincipal national securities exchange on which the Class A common unitsare listed, the Class C units will convert into Class A common unitson a one-for-one basis. If our unitholders do not approve the conversion, theholders of our Class C units will receive quarterly cash distributionsequal to 115 percent of those paid to the holders of our common units. Prior toconversion, holders of our Class C units will not be entitled to receiveany quarterly cash distribution until the holders of our common units havereceived a quarterly cash distribution of $0.59 per common unit.

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Thefollowing table sets forth our distributions, as approved by the board ofdirectors for each period in the years ended December 31, 2006, 2005 and2004.

| 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) | ** ** | **Amount of  Distribution  of Class C  units  to Class C  unit  Holders**(2) | ** ** | **Retained  from  General  Partner**(3) | ** ** | **Distribution  of Cash** | ** ** |
|---------------------------------|------------|---------------------------------------------------------------------|------------------|------------------|------------|---------------------------------|------------|--------------------------------------------|------------|-------------------------------------------------------------------------------|------------|-------------------------------------------------------------------------------------------------------|------------|-----------------------------------------|------------|--------------------------------|------------|
| ** **                      | ** ** | **(in millions, except per unit amounts)** | ** **       |
| **2006**                        |       |                                                                |             |             |       |                            |       |                                       |       |                                                                          |       |                                                                                                  |       |                                    |       |                           |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| October 27                 |       |                                                                | November 14 |             |       | November 6                 |       |                                       | $          | 0.925                                                                         |       |                                                                                                  |       | $                                       | 79.6       |                           |       |   | $ | 11.5 |   |   |   | $ | 10.1 |   |   |   | $ | 0.4 |   |   |   | $ | 57.6 |   |   |
| July 28                    |       |                                                                | August 14   |             |       | August 4                   |       |                                       | 0.925      |                                                                          |       |                                                                                                  | 68.1       |                                    |       |                           | 11.3       |   |   |   | — |   |   |   | 0.2 |   |   |   | 56.6 |   |   |
| April 27                   |       |                                                                | May 15      |             |       | May 5                      |       |                                       | 0.925      |                                                                          |       |                                                                                                  | 67.8       |                                    |       |                           | 11.0       |   |   |   | — |   |   |   | 0.2 |   |   |   | 56.6 |   |   |
| January 30                 |       |                                                                | February 14 |             |       | February 7                 |       |                                       | 0.925      |                                                                          |       |                                                                                                  | 67.6       |                                    |       |                           | 10.8       |   |   |   | — |   |   |   | 0.2 |   |   |   | 56.6 |   |   |
|                            |       |                                                                |             |             |       |                            |       |                                       |       |                                                                          |       |                                                                                                  | $          | 283.1                                   |       |                           |       | $ | 44.6 |   |   |   | $ | 10.1 |   |   |   | $ | 1.0 |   |   |   | $ | 227.4 |   |   |
| **2005**                        | ** ** |                                                                |             |             | ** ** | ** **                      | ** ** |                                       |       |                                                                          |       |                                                                                                  |       |                                    |       |                           |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| October 26                 |       |                                                                | November 14 |             |       | November 3                 |       |                                       | $          | 0.925                                                                         |       |                                                                                                  |       | $                                       | 64.1       |                           |       |   | $ | 10.6 |   |   |   | $ | — |   |   |   | $ | 0.2 |   |   |   | $ | 53.3 |   |   |
| July 28                    |       |                                                                | August 12   |             |       | August 5                   |       |                                       | 0.925      |                                                                          |       |                                                                                                  | 64.0       |                                    |       |                           | 10.5       |   |   |   | — |   |   |   | 0.2 |   |   |   | 53.3 |   |   |
| April 25                   |       |                                                                | May 13      |             |       | May 4                      |       |                                       | 0.925      |                                                                          |       |                                                                                                  | 63.8       |                                    |       |                           | 10.3       |   |   |   | — |   |   |   | 0.2 |   |   |   | 53.3 |   |   |
| January 24                 |       |                                                                | February 14 |             |       | February 3                 |       |                                       | 0.925      |                                                                          |       |                                                                                                  | 61.0       |                                    |       |                           | 10.1       |   |   |   | — |   |   |   | 0.2 |   |   |   | 50.7 |   |   |
|                            |       |                                                                |             |             |       |                            |       |                                       |       |                                                                          |       |                                                                                                  | $          | 252.9                                   |       |                           |       | $ | 41.5 |   |   |   | $ | — |   |   |   | $ | 0.8 |   |   |   | $ | 210.6 |   |   |
| **2004**                        |       |                                                                |             |             |       |                            |       |                                       |       |                                                                          |       |                                                                                                  |       |                                    |       |                           |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| October 22                 |       |                                                                | November 12 |             |       | November 1                 |       |                                       | $          | 0.925                                                                         |       |                                                                                                  |       | $                                       | 60.7       |                           |       |   | $ | 9.9 |   |   |   | $ | — |   |   |   | $ | 0.2 |   |   |   | $ | 50.6 |   |   |
| July 22                    |       |                                                                | August 13   |             |       | August 2                   |       |                                       | 0.925      |                                                                          |       |                                                                                                  | 56.6       |                                    |       |                           | 9.6        |   |   |   | — |   |   |   | 0.2 |   |   |   | 46.8 |   |   |
| April 26                   |       |                                                                | May 14      |             |       | May 5                      |       |                                       | 0.925      |                                                                          |       |                                                                                                  | 56.5       |                                    |       |                           | 9.5        |   |   |   | — |   |   |   | 0.2 |   |   |   | 46.8 |   |   |
| January 22                 |       |                                                                | February 13 |             |       | February 2                 |       |                                       | 0.925      |                                                                          |       |                                                                                                  | 56.3       |                                    |       |                           | 9.3        |   |   |   | — |   |   |   | 0.2 |   |   |   | 46.8 |   |   |
|                            |       |                                                                |             |             |       |                            |       |                                       |       |                                                                          |       |                                                                                                  | $          | 230.1                                   |       |                           |       | $ | 38.3 |   |   |   | $ | — |   |   |   | $ | 0.8 |   |   |   | $ | 191.0 |   |   |

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(1)                    We issued 969,200,802,539 and 840,239 i-units to Enbridge Energy Management, L.L.C., the soleowner of our i-units, during 2006, 2005 and 2004, respectively, in lieu of cashdistributions.

(2)                    We issued 200,587 additional Class C units to our Class Cunitholders in lieu of cash distributions during 2006, including 100,293 to ourgeneral partner.

(3)                    We retained an amount equal to 2 percentof the i-unit and Class C unit distribution from the General Partner tomaintain its 2 percent general partner interest in us.

**11. RELATED PARTYTRANSACTIONS**

***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 us. Where directly attributable, the costs of allcompensation, benefits expenses and employer expenses for these employees arecharged directly by Enbridge to the appropriate affiliate. Enbridge does notrecord any profit or margin for the services charged to us.

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 to us by Enbridge and its affiliates.

Certain of the operating activities associated with ourLiquids 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.

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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, number of full-time equivalent employees and capitalemployed.

During2006, 2005 and 2004, we incurred the following costs related to these services,which are included in operating and administrative expenses. 

|                                                                     | ** ** | **Year ended December 31,** | ** ** |
|---------------------------------------------------------------------|------------|--------------------------------------------|------------|
| ** **                                                          | ** ** | **2006**                                   | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                                                          | ** ** | **(in millions)**                     | ** ** |
| Direct workforce costs                                              |       | $                                          | 163.9      |   | $ | 117.0 |   | $ | 101.7 |   |
| Liquids /Natural Gas operating costs                                |       | 17.3                                       |       | 15.3 |   | 14.0 |   |
| Allocated management and  administrative costs, including insurance |       | 27.4                                       |       | 20.1 |   | 17.2 |   |
|                                                                |       | $                                          | 208.6      |   | $ | 152.4 |   | $ | 132.9 |   |

 

***Affiliate Revenues 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. We also record operating revenues in our Liquids segment for storage,transportation and terminaling services we provide to affiliates. Included inour results for the twelve months ending December 31, 2006, 2005 and 2004,are operating revenues of $42.8 million, $43.6 million, and$23.6 million, respectively, related to these transactions.

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 31,2006, 2005 and 2004, are cost of natural gas expenses of $11.5 million,$4.5 million and $6.9 million, respectively, relating to thesepurchases.

***Affiliate Notes***

We have a loan payable to an affiliate of Enbridgethat totaled $136.2 million and $151.8 million at December 31, 2006and 2005, which matures in December 2007. The interest rate is 6.60% as ofDecember 31, 2006 and 2005.

We incurred interestexpense on the affiliate loan payable totaling $9.4 million, $9.7 million,and $9.0 million for the years ended December 31, 2006, 2005 and2004, respectively. We added the interest expense incurred on the affiliateloan payable to the principal amount of the loan for the specified amounts ineach of the respective periods. Additionally, in 2006 we repaid approximately$20.0 million in principal amount of this note.

***General Partner Distributions***

Our general partner owns an effective 2 percentgeneral partner ownership interest in us. Pursuant to our partnership agreementwe paid cash distributions to our general partner of $28.1 million,$25.3 million, and $22.9 million for the years endedDecember 31, 2006, 2005 and 2004, respectively. The cash distributions wemake to our general partner exclude an amount equal to 2 percent of the i-unitand Class C unit distributions, which we retain from the General Partnerto maintain its 2 percent ownership interest in us.

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As of December 31, 2006 and 2005, the GeneralPartner also owned 3,912,750 Class B common units, representing 4.9 and5.8 percent limited partner interest in us. We paid the General Partner cashdistributions of $14.5 million, $14.5 million and $14.4 millionrelated to its ownership of Class B common units for the years ended December 31,2006, 2005 and 2004, respectively.

In August 2006, ourgeneral partner purchased approximately 5.4 million of our Class C unitsfor $250 million, or $46.00 per unit. At December 31, 2006, theGeneral Partner owned 5,535,076 of our Class C units, including 100,293 Class Cunits that we distributed in lieu of making cash distributions. The Class Cunits owned by our general partner represent an approximate 7.0 percent limitedpartner interest in us. Refer to Note 10 for additional information regardingthe Class C units.

***Conflicts of Interest***

Enbridge Management makesall decisions relating to the management and control of our business through adelegation of control agreement with the General Partner and us. The GeneralPartner 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 directors and officers 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 all parties in addition tothose of our unitholders in resolving conflicts of interest, thereby limitingits fiduciary duties to our unitholders, as well as provisions that mayrestrict the remedies available to our unitholders for actions taken thatmight, without such 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 EnbridgeManagement on behalf of Enbridge Management.

**12. ENVIRONMENTALLIABILITIES**

We are subject to federal and state laws andregulations relating to the protection of the environment. Environmental riskis inherent to liquid hydrocarbon and natural gas pipeline operations and wecould, at times, be subject to environmental cleanup and enforcement actions. Wemanage this environmental risk through appropriate environmental policies andpractices to minimize any impact our operations may have on the environment. Tothe extent that we are unable to recover environmental liabilities associatedwith the Lakehead system assets through insurance, the General Partner hasagreed to indemnify us from and against any costs relating to environmentalliabilities associated with the Lakehead system assets prior to the transfer tous in 1991. This excludes any liabilities resulting from a change in laws aftersuch transfer. We continue to voluntarily investigate past leak sites on our systemsfor the purpose of assessing whether any remediation is required in light ofcurrent regulations, and to date, no material environmental risks have beenidentified.

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 

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indemnify us until theaggregate liabilities, including environmental liabilities, exceed$20.0 million, and the General Partner’s aggregate liability, includingenvironmental 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.

As of December 31, 2006 and 2005, we haverecorded $4.1 million and $4.0 million in current liabilities and $3.3million and $4.8 million, respectively, in long-term liabilities primarilyto address remediation of asbestos containing materials, management ofhazardous 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 approximately$2.0 million related to certain of our Natural Gas assets. Since October 2002,during the time that these assets have been owned by us, we completed a reviewof the affected sites and determined that suspected contamination is lesssignificant than originally estimated. Our assessment was based uponinformation gathered during the ownership period, existing technology,presently enacted laws and regulations and prior experience in remediatingcontaminated sites for similar assets.

**13. COMMITMENTS ANDCONTINGENCIES**

***Oil and Gas in Custody***

Our Liquids assets transport crude oil and NGLs ownedby our customers for a fee. The volume of liquid hydrocarbons in our pipelinesystems at any one time varies from approximately 24 to 28 millionbarrels, virtually all of which is owned by our customers. Under the terms ofour tariffs, losses of crude oil from identifiable incidents not resulting fromour direct negligence may be apportioned among our customers. In addition, wemaintain adequate property insurance coverage with respect to crude oil andNGLs 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 ourcustomers’ natural gas in the custody of our natural gas systems is notmaterial 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 to customerspending resolution of this contested rate case. In accordance with the FERC’sfindings, any difference between what was collected and the revised initial Section 7rates for the period of time between December 1997 and November 2002,plus interest compounded quarterly, is subject to refund.

Refunds to our customerswere made in January 2005 pursuant to a refund plan agreed upon withcustomers and approved by the FERC. Our Consolidated Statement 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 

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part ofProperty, plant and equipment. Right-of-way agreements that are leased from athird-party are expensed. We recorded expenses of $2.1 million,$1.9 million, and $1.8 million for the leased right-of-way agreementsfor the years ended December 31, 2006, 2005, and 2004, 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 31,2006, our future minimum commitments that have remaining non-cancelable termsin excess of one year are as follows:

| Future Minimum Commitments | ** ** | ** **             | ** ** | **2007** | ** ** | **2008** | ** ** | **2009** | ** ** | **2010** | ** ** | **2011** | ** ** | **Thereafter** | ** ** | **Total** | ** ** |
|--------------------------------------|------------|------------------------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------------|------------|-----------|------------|
| ** **                           | ** ** | **(in millions)** | ** ** |
| Purchase commitments(1)              |       | $                      | 451.8      |     | $          | —   |       | $        | —     |     | $          | —   |       | $              | —     |      |       | $ | — |   |   | $ | 451.8 |   |
| Power commitments(2)                 |       | 3.2                    |       | —   |       | —   |       | —   |       | —   |       |     | —     |           |       | 3.2       |       |
| Other operating leases               |       | 10.8                   |       | 9.1      |       | 6.9      |       | 1.9      |       | 0.1      |       |     | —     |           |       | 28.8      |       |
| Right-of-way(3)                      |       | 1.7                    |       | 1.7      |       | 1.7      |       | 1.7      |       | 1.7      |       |     | 42.4       |           |       | 50.9      |       |
| Product purchase obligations(4)      |       | 32.1                   |       | 34.0     |       | 31.5     |       | 27.6     |       | 24.6     |       |     | 83.4       |           |       | 233.2     |       |
| Service contract  obligations(5)     |       | 16.4                   |       | 15.6     |       | 12.5     |       | 8.3      |       | 6.2      |       |     | 1.8        |           |       | 60.8      |       |
| Total                                |       | $                      | 516.0      |     | $          | 60.4     |       | $        | 52.6       |     | $          | 39.5     |       | $              | 32.6       |      |       | $ | 127.6 |   |   | $ | 828.7 |   |

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(1)                Representscommitments to purchase materials, primarily pipe from third-party suppliers inconnection with our expansion projects.

(2)                Representscommitments to purchase power in connection with our Liquids segment.

(3)                Right-of-waypayments are estimated to be approximately $1.7 million per year for theremaining life of all pipeline systems, which has been assumed to be25 years for purposes of calculating the amount of future minimumcommitments beyond 2011.

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

(5)                Theservice contract obligations represent the minimum payment amounts for firmtransportation and storage capacity we have reserved on third-partypipelines and storage facilities.

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**14. FINANCIALINSTRUMENTS**

***Fair Value of Debt Obligations***

Thetable below presents the carrying amount and approximate fair values of ourdebt obligations. The carrying amounts of our commercial paper obligationsapproximate their fair values at December 31, 2006, due to the short-termnature of these obligations. 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, 2006** | ** ** | **December 31, 2005** | ** ** |
|-------------------------------|------------|---------------------------------|------------|---------------------------------|------------|
| ** **                    | ** ** | **Carrying  Amount**            | ** ** | **Fair Value**             | ** ** | **Carrying  Amount** | ** ** | **Fair Value** | ** ** |
| ** **                    | ** ** | **(in millions)**          | ** ** |
| Commercial paper              |       |                            | $          | 443.7                           |       |   |   | $ | 443.7 |   |   |   | $ | 329.3 |   |   |   | $ | 329.3 |   |   |
| Credit Facility               |       |                            | —     |                            |       |   | — |   |   |   | — |   |   |   | — |   |   |
| 9.150% First Mortgage Notes   |       |                            | 155.0      |                            |       |   | 169.5 |   |   |   | 186.0 |   |   |   | 207.9 |   |   |
| 4.000% Senior  notes due 2009 |       |                            | 200.0      |                            |       |   | 194.2 |   |   |   | 199.9 |   |   |   | 193.0 |   |   |
| 7.900% Senior notes due 2012  |       |                            | 99.9       |                            |       |   | 110.5 |   |   |   | 99.9 |   |   |   | 113.8 |   |   |
| 4.750% Senior  notes due 2013 |       |                            | 199.8      |                            |       |   | 188.6 |   |   |   | 199.8 |   |   |   | 190.8 |   |   |
| 5.350% Senior notes due 2014  |       |                            | 199.9      |                            |       |   | 193.0 |   |   |   | 199.9 |   |   |   | 196.7 |   |   |
| 5.875% Senior  notes due 2016 |       |                            | 299.7      |                            |       |   | 297.4 |   |   |   | — |   |   |   | — |   |   |
| 7.000% Senior notes due 2018  |       |                            | 99.8       |                            |       |   | 107.9 |   |   |   | 99.8 |   |   |   | 111.4 |   |   |
| 7.125% Senior  notes due 2028 |       |                            | 99.8       |                            |       |   | 108.9 |   |   |   | 99.8 |   |   |   | 113.0 |   |   |
| 5.950% Senior notes due 2033  |       |                            | 199.7      |                            |       |   | 186.2 |   |   |   | 199.7 |   |   |   | 193.1 |   |   |
| 6.300% Senior notes due  2034 |       |                            | 99.8       |                            |       |   | 97.1 |   |   |   | 99.8 |   |   |   | 100.8 |   |   |

 

***Fair Value of Derivative Financial Instruments***

The fair values of our derivative financialinstruments are determined based on available market information, valuation andmodeling techniques. These modeling techniques require us to make estimates offuture prices, price correlation, market volatility and liquidity. Theestimates also reflect factors for time value of money and the volatility ofprices underlying the contracts, the potential impact of liquidating positionsin an orderly manner over a reasonable period of time under present marketconditions, modeling risk, credit risk of counterparties and operational risk.

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**Interest RateDerivatives**

We enter into interestrate swaps, collars and derivative financial instruments with similarcharacteristics to manage the effect of future interest rate movements on ourinterest costs. The following table provides information about our currentinterest rate derivatives by transaction type for the specified periods.

| ** **              | ** ** | ** **    | ** ** | ** **      | ** ** | ** **   | ** **  | ** **             | ** ** | **Fair Value**                                      | ** **             |
|-------------------------|------------|---------------|------------|-----------------|------------|--------------|-------------|------------------------|------------|----------------------------------------------------------|------------------------|
| ** **              | ** ** | **Notional**  | ** ** | **Partnership** | ** ** | ** **   | ** **  | **December 31,**  | ** ** |
| ** **              | ** ** | **Principal** | ** ** | **Pays**        | ** ** | **Receives** | ** **  | **Maturity Date** | ** ** | **    2006    ** | ** **             | **    2005    ** | ** ** |
| ** **              | ** ** | ** **    | ** ** | ** **      | ** ** | ** **   | ** **  | ** **             | ** ** | **(dollars in millions)**                      | ** **             |
| Interest Rate  Swaps    |       |          |       |            |       |         |        |                   |       |                                                     |                   |   |   |   |   |   |   |   |   |
| Floating to Fixed:      |       |          |       |            |       |         |        |                   |       |                                                     |                   |   |   |   |   |   |   |   |   |
|                    |       |          | $          | 30.0            |       |         | 3.180%      |                   | LIBOR      | (2)                                                      | January 18, 2006  |   |   | $ | — |   |   |   | $ | 0.1 |   |   |
|                    |       |          | $          | 30.0            |       |         | 3.180%      |                   | LIBOR      |                                                     | January 20, 2006  |   |   | — |   |   |   | 0.1 |   |   |
|                    |       |          | $          | 30.0            |       |         | 3.200%      |                   | LIBOR      |                                                     | January 27, 2006  |   |   | — |   |   |   | 0.1 |   |   |
|                    |       |          | $          | 30.0            |       |         | 3.220%      |                   | LIBOR      |                                                     | January 30, 2006  |   |   | — |   |   |   | 0.1 |   |   |
|                    |       |          | $          | 30.0            |       |         | 3.210%      |                   | LIBOR      |                                                     | February 3, 2006  |   |   | — |   |   |   | 0.1 |   |   |
|                    |       |          | $          | 50.0            |       |         | 4.715%      |                   | LIBOR      |                                                     | January 22, 2007  |   |   | 0.1 |   |   |   | — |   |   |
|                    |       |          | $          | 50.0            |       |         | 4.738%      |                   | LIBOR      |                                                     | January 24, 2007  |   |   | 0.1 |   |   |   | — |   |   |
|                    |       |          | $          | 50.0            |       |         | 4.740%      |                   | LIBOR      |                                                     | February 3, 2007  |   |   | 0.1 |   |   |   | — |   |   |
|                    |       |          | $          | 50.0            |       |         | 4.750%      |                   | LIBOR      |                                                     | February 8, 2007  |   |   | 0.1 |   |   |   | — |   |   |
|                    |       |          | $          | 50.0            |       |         | 5.158%      |                   | LIBOR      |                                                     | April 3, 2007     |   |   | 0.1 |   |   |   | — |   |   |
|                    |       |          | $          | 50.0            |       |         | 5.163%      |                   | LIBOR      |                                                     | April 10, 2007    |   |   | — |   |   |   | — |   |   |
|                    |       |          | $          | 50.0            |       |         | 5.165%      |                   | LIBOR      |                                                     | April 17, 2007    |   |   | — |   |   |   | — |   |   |
|                    |       |          | $          | 50.0            |       |         | 5.175%      |                   | LIBOR      |                                                     | April 25, 2007    |   |   | — |   |   |   | — |   |   |
|                    |       |          | $          | 50.0            |       |         | 4.370%      |                   | LIBOR      |                                                     | June 1, 2013      |   |   | 1.5 |   |   |   | 1.0 |   |   |
|                    |       |          | $          | 50.0            |       |         | 4.343%      |                   | LIBOR      |                                                     | June 1, 2013      |   |   | 1.6 |   |   |   | 1.1 |   |   |
|                    |       |          | $          | 25.0            |       |         | 4.310%      |                   | LIBOR      |                                                     | June 1, 2013      |   |   | 0.7 |   |   |   | 0.5 |   |   |
| Fixed to  Floating:     |       |          |       |            |       |         |        |                   |       |                                                     |                   |   |   |   |   |   |   |   |   |
|                    |       |          | $          | 50.0            |       |         | LIBOR-21bps | (1)                    | 4.750%     |                                                     | June 1, 2013      |   |   | (0.5 | ) |   |   | 0.2 |   |   |
|                    |       |          | $          | 50.0            |       |         | LIBOR-21bps | (1)                    | 4.750%     |                                                     | June 1, 2013      |   |   | (0.5 | ) |   |   | 0.2 |   |   |
|                    |       |          | $          | 25.0            |       |         | LIBOR-25bps | (1)                    | 4.750%     |                                                     | June 1, 2013      |   |   | (0.3 | ) |   |   | 0.2 |   |   |
| Treasury Locks:         |       |          |       |            |       |         |        |                   |       |                                                     |                   |   |   |   |   |   |   |   |   |
|                    |       |          | $          | 100.0           |       |         | 4.697%      |                   | 30Yr UST   | (3)                                                      | December 17, 2007 |   |   | 1.2 |   |   |   | — |   |   |
|                    |       |          | $          | 100.0           |       |         | 4.668%      |                   | 30Yr UST   |                                                     | December 17, 2007 |   |   | 1.6 |   |   |   | — |   |   |
| Interest Rate  Collars: |       |          |       |            |       |         |        |                   |       |                                                     |                   |   |   |   |   |   |   |   |   |
| Calls                   |       |          | $          | 50.0            |       |         | 5.500%      |                   | LIBOR      |                                                     | June 13, 2008     |   |   | 0.1 |   |   |   | — |   |   |
| Puts                    |       |          | $          | 50.0            |       |         | 4.199%      |                   | LIBOR      |                                                     | June 13, 2008     |   |   | — |   |   |   | — |   |   |
| Calls                   |       |          | $          | 50.0            |       |         | 5.500%      |                   | LIBOR      |                                                     | June 25, 2008     |   |   | — |   |   |   | — |   |   |
| Puts                    |       |          | $          | 50.0            |       |         | 4.149%      |                   | LIBOR      |                                                     | June 25,  2008    |   |   | — |   |   |   | — |   |   |
|                         |            |               |            |                 |            |              |             |                        |            |                                                          |                        |  |  |  |  |  |  |  |  |  |  |  |

----

(1)                A bps refers to abasis point. One basis point is equivalent to 1/100th of1 percent.

(2)                LIBOR refers tothe three-month U.S. London Interbank Offered Rate.

(3)                UST refers toUnited States Treasury notes.

Our floating to fixed rate interest rate swapsmaturing in 2007 qualify for hedge accounting treatment as set forth in SFAS No. 133and have been designated cash flow hedges of interest payments on $400 million of our variable rate indebtedness.Similarly, our treasury locks maturing in 2007 qualify for hedge accountingtreatment pursuant to the requirements of SFAS No. 133 and have beendesignated as cash flow hedges of future interest payments on the first $200 million of an anticipated debt issuance. Additionally,our interest rate collars qualify for hedge accounting treatment as per SFAS No. 133and 

F-38

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have been designated ascash flow hedges of interest payments on $100million of our variable rate indebtedness. As such, the fair value ofthese derivative financial instruments are recorded as assets or liabilities onour Consolidated Statements of Financial Position with the changes in fairvalue recorded as corresponding increases or decreases in Accumulated othercomprehensive income.

The floating to fixed rateand fixed to floating rate interest rate swaps maturing in 2013 have not beendesignated as cash flow or fair value hedges under SFAS No. 133 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 PriceDerivatives**

Thefollowing table provides summarized information about the fair values of ouroutstanding commodity derivative financial instruments at December 31,2006 and 2005:

| ** **                     | ** ** | **December 31, 2006** | ** ** | **December 31, 2005** | ** ** |
|--------------------------------|------------|---------------------------------|------------|---------------------------------|------------|
| ** **                     | ** ** | ** **                      | ** ** | **Wtd Avg Price**     | ** ** | **Fair Value**(3) | ** ** | **Fair Value**(3) | ** ** |
| ** **                     | ** ** | **Notional**                    | ** ** | **Receive**                     | ** ** | **Pay** | ** ** | **Asset** | ** ** | **Liability** | ** ** | **Asset** | ** ** | **Liability** | ** ** |
| Swaps                          | * *   | * *                        | * *   | * *                        | * *   | * * | * * | * * | * * | * * | * * | * * | * * | * * | * * |
| *Natural  gas**(1)*            | * *   | * *                        | * *   | * *                        | * *   | * * | * * | * * | * * | * * | * * | * * | * * | * * | * * |
| Receive variable/ pay fixed    |       | 92,254,562                      |       | $                               | 6.70       |   | $ | 7.44 |   | $ | 25.6 |   | $ | (94.2 | ) | $ | 511.0 |   | $ | (12.7 | ) |
| Receive fixed/ pay variable    |       | 123,886,005                     |       | 6.37                            |       | 7.13 |   | 84.3 |   | (160.7 | ) | 15.1 |   | (790.4 | ) |
| Receive variable/ pay variable |       | 85,845,702                      |       | 7.36                            |       | 7.32 |   | 7.9 |   | (4.8 | ) | 8.0 |   | (5.3 | ) |
| *NGL**(2)*                     | * *   | * *                        | * *   | * *                        | * *   | * * | * * | * * | * * | * * | * * | * * | * * | * * | * * |
| Receive variable/ pay fixed    |       | 99,645                          |       | 38.52                           |       | 43.65 |   | — |   | (0.5 | ) | — |   | — |   |
| Receive fixed/ pay variable    |       | 8,335,133                       |       | 37.91                           |       | 39.98 |   | 18.3 |   | (34.4 | ) | — |   | (60.3 | ) |
| *Crude**(2)*                   | * *   | * *                        | * *   | * *                        | * *   | * * | * * | * * | * * | * * | * * | * * | * * | * * | * * |
| Receive fixed/ pay variable    |       | 1,386,571                       |       | 52.21                           |       | 66.34 |   | 0.2 |   | (18.5 | ) | 0.2 |   | (22.0 | ) |
| Options—calls             | * *   | * *                        | * *   | * *                        | * *   | * * | * * | * * | * * | * * | * * | * * | * * | * * | * * |
| *Natural gas**(1)*             |       | 1,826,000                       |       | 7.47                            |       | 4.31 |   | — |   | (5.4 | ) | — |   | (9.5 | ) |
| Options—puts              | * *   | * *                        | * *   | * *                        | * *   | * * | * * | * * | * * | * * | * * | * * | * * | * * | * * |
| *Natural gas**(1)*             |       | 2,890,000                       |       | 7.19                            |       | 4.67 |   | 1.0 |   | — |   | 0.1 |   | — |   |
| Totals(4)                      |       |                            |       |                            |       |   |   | $ | 137.3 |   | $ | (318.5 | ) | $ | 534.4 |   | $ | (900.2 | ) |
|                                |            |                                 |            |                                 |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

----

(1)                Notional amounts for natural gas arerecorded in millions of British thermal units (“MMBtu”).

(2)                Notional amounts for NGL and Crude arerecorded in Barrels (“Bbl”).

(3)                Fair values of derivatives arepresented in millions of dollars.

(4)                Werecord the fair value of our derivative financial instruments in the balancesheet as current and long-term assets or liabilities on a net basis bycounterparty.

**15. DERIVATIVEFINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES**

Our net income and cashflows are subject to volatility stemming from changes in interest rates on ourvariable rate debt obligations and fluctuations in commodity prices of naturalgas, NGLs, condensate and fractionation margins (the relative pricedifferential between NGL sales and the offsetting natural gas purchases). Ourinterest rate risk exposure does not exist within any of our segments, butexists at the corporate level where our variable rate debt obligations areissued. Our exposure to commodity price risk 

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existswithin our Natural Gas and Marketing segments. To mitigate the volatility ofour cash flows, we use derivative financial instruments (i.e., futures,forwards, swaps, options and other financial instruments with similarcharacteristics) to manage the risks associated with market fluctuations incommodity prices and interest rates. Based on our risk management policies, allof our derivative financial instruments are employed in connection with anunderlying asset, liability and/or forecasted transaction and are not enteredinto with the objective of speculating on interest rates or commodity prices.

***Accounting Treatment***

All derivative financial instruments are recorded inthe 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, other than in a forced orliquidation sale, to terminate or close the contracts at the reporting date,taking into account the current unrealized losses or gains on open contracts. Weuse actively traded external market quotes and indices to value substantiallyall of the financial instruments we utilize.

Under the guidance of SFAS No. 133, if aderivative financial instrument does not qualify as a hedge, or is notdesignated as a hedge, the derivative is adjusted to its fair market value, ormarked-to-market, each period with the increases and decreases infair value recorded in our Consolidated Statements of Income as increases anddecreases in Cost of natural gas for our commodity-based derivatives andInterest expense for our interest rate derivatives. Cash flow is only impactedto the extent the actual derivative contract is settled by making or receivinga payment to or from the counterparty or by making or receiving a payment forentering into a contract that exactly offsets the original derivative contract.Typically, we settle our derivative contracts when the physical transactionthat underlies the derivative financial instrument occurs.

If a derivative financial instrument qualifies and isdesignated as a cash flow hedge, a hedge of a forecasted transaction or futurecash flows, any unrealized mark-to-market gain or loss is deferred inAccumulated other comprehensive income (“AOCI”), a component of Partners’Capital, until the underlying hedged transaction occurs. To the extent that thehedge instrument is effective in offsetting the transaction being hedged, thereis no impact to the income statement. At inception and on a quarterly basis, weformally assess whether the hedge contract is highly effective in offsettingchanges in cash flows of hedged items. Any ineffective portion of a cash flowhedge’s change in fair market value is recognized each period in earnings. Realizedgains and losses on derivative financial instruments that are designated ashedges and qualify for hedge accounting are included in Cost of natural gas forcommodity hedges and Interest expense for interest rate hedges in the periodthe hedged transaction occurs. Gains and losses deferred in AOCI related tocash flow hedges, for which hedge accounting has been discontinued, remain inAOCI until the underlying physical transaction occurs unless it is probablethat the forecasted transaction will not occur by the end of the originallyspecified time period, or within an additional two-month period of timethereafter. Generally, our preference is for our derivative financialinstruments to receive hedge accounting treatment whenever possible, tomitigate the non-cash earnings volatility that arises under mark-to-marketaccounting treatment. To qualify for cash flow hedge accounting as set forth inSFAS No. 133, very specific requirements must be met in terms of hedgestructure, 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 or lossresulting from the change in fair market value of the derivative financialinstrument is recorded in earnings adjusted by the gain or loss resulting fromthe change in fair market value of the underlying asset or liability. Any ineffectiveportion of a fair value hedge’s change in fair market value will be recorded inearnings as the amount that is not offset by the gain or loss on the change infair market value of the underlying asset or liability. We include the gains 

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andlosses associated with derivative financial instruments designated andqualifying as fair value hedges of our debt obligations in Interest expense onour Consolidated Statements of Income. Similar to derivative financialinstruments designated as cash flow hedges, very specific requirements must bemet in terms of 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 four primary transaction types associated with our commodityderivative financial instruments where the hedge structure does not meet therequirements to apply hedge accounting. As a result, these derivative financialinstruments do not qualify for hedge accounting under SFAS No. 133 and arereferred to as “non-qualified.”  Thesenon-qualified derivative financial instruments are marked-to-marketeach period with the change in fair value, representing unrealized gains andlosses, included in Cost of natural gas in our Consolidated Statements ofIncome. 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 when the associated financial instrument contract settlement ismade.

The four primarytransaction types that do not qualify for hedge accounting are as follows:

1.                **Transportation—**In our Marketing segment, when we transportnatural gas from one location to another the pricing index used for natural gassales is usually different from the pricing index used for natural gaspurchases, which exposes us to market price risk relative to changes in thosetwo indices. By entering into a basis swap, where we exchange one pricing indexfor another, we can effectively lock in the margin, representing the differencebetween the sales price and the purchase price, on the combined natural gaspurchase and natural gas sale, removing any market price risk on the physicaltransactions. Although this represents a sound economic hedging strategy, thederivative financial instruments (i.e., the basis swaps) we use to manage thecommodity price risk associated with these transportation contracts do notqualify for hedge accounting under SFAS No. 133, since only the futuremargin has been fixed and not the future cash flow. As a result, thesederivative financial instruments are marked-to-market.

2.                **Storage—**In our Marketing segment, we use derivativefinancial instruments (i.e., natural gas swaps) to hedge the relativedifference between the injection price paid to purchase and store natural gasand the withdrawal price at which the natural gas is sold from storage. Theintent of these derivative financial instruments is to lock in the margin,representing the difference between the price paid for the natural gas injectedand the price received upon withdrawal of the gas from storage in a futureperiod. We do not pursue cash flow hedge accounting treatment for these storagetransactions since the underlying forecasted injection or withdrawal of naturalgas may not occur in the period as originally forecast. This can occur becausewe have the flexibility to make changes in the underlying injection orwithdrawal schedule, given changes in market conditions. In addition, since thephysical natural gas is recorded at the lower of cost or market, timingdifferences can result when the derivative financial instrument is settled in aperiod that is different from when the physical natural gas is sold fromstorage. As a result, derivative financial instruments associated with ournatural gas storage activities can create volatility in our earnings.

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 cash flow hedging relationship with the intent ofcontemporaneously re-designating the natural gas collars 

F-41

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as hedges of forecastedphysical natural gas sales with a NYMEX pricing index. However, because thefair value of these derivative instruments was a liability to us at re-designation,they are considered net written options under SFAS No. 133 and do notqualify for hedge accounting. These derivatives are being marked-to-market,with the changes in fair value from the date of de-designation recordedto earnings each period. As a result, our operating income will be subject togreater volatility due to movements in the prices of natural gas until theunderlying long-term transactions are settled.

4.                **Optional Natural Gas Processing Volumes—**In our Natural Gassegment we use derivative financial instruments to hedge the volumes of NGLsproduced from our natural gas processing facilities. Our natural gas contractsallow us the option of processing natural gas when it is economical, andceasing to do so when processing becomes uneconomic. We have entered intoderivative financial instruments to fix the sales price of a portion of theNGLs that we produce at our discretion and to fix the associated purchases ofnatural gas required for processing. We will designate derivative financialinstruments associated with NGLs we produce at our discretion as cash flowhedges when the processing of natural gas is probable of occurrence. However,we are precluded from designating the derivative financial instruments enteredto manage the respective commodity price risk when we are unable to accuratelyforecast the NGLs to be processed at our discretion. As a result, our operatingincome will be subject to increased volatility due to fluctuations in NGLprices until the underlying transactions are settled or offset.

In each of the instancesdescribed above, the underlying physical purchase, storage and sale of naturalgas and NGLs are accounted for on a historical cost or market basis rather thanon the mark-to-market basis we utilize for the derivative financial instrumentsemployed to mitigate the commodity price risk associated with our storage andtransportation assets. This difference in accounting (i.e., the derivative financial instruments are recorded at fair marketvalue while the physical transactions are recorded at historical cost) canand has resulted in volatility in our reported net income, even though theeconomic margin is essentially unchanged from the date the transactions wereconsummated.

***Discontinuance of Hedge Accounting***

In 2005, we discontinued application of hedgeaccounting in connection with some of our derivative financial instrumentsdesignated as hedges of forecasted sales and purchases of natural gas. Wediscontinued application of hedge accounting when we determined it was nolonger probable that the originally forecasted purchases and sales of naturalgas would occur by the end of the originally specified time period, or withinan additional two-month period of time thereafter. As discussed above, this canoccur because we have the flexibility to make changes to the underlyingdelivery locations 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 occurring asoriginally set forth in the hedge documentation. As a result, in 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 AOCI. 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 in 2005.

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Thefollowing table presents the unrealized gains and losses associated withchanges in the fair value of our derivatives, which are recorded as an elementof Cost of natural gas in our Consolidated Statements of Income and disclosedas a reconciling item on our Statements of Cash Flows:

| **Derivativefair value gains (losses)** | ** ** | ** **             | ** ** | **December 31,  2006** | ** ** | **December 31,  2005** | ** ** | **December 31,  2004** | ** ** |
|--------------------------------------------------------|------------|------------------------|------------|-----------------------------|------------|-----------------------------|------------|-----------------------------|------------|
| ** **                                             | ** ** | **(in millions)** | ** ** |
| Natural Gas segment                                    |       |                   |       |                        |       |                        |       |                        |       |   |   |   |   |
| Hedge  ineffectiveness                                 |       |                   | $          | (1.9                        | )          |                        |       | $                           | (2.5       | ) |   |   | $ | (1.1 | ) |   |
| Non-qualified hedges                                   |       |                   | 1.8        |                        |       |                        | (5.6       | )                           |       |   | — |   |   |
| Marketing                                              |       |                   |       |                        |       |                        |       |                        |       |   |   |   |   |
| Non-qualified  hedges                                  |       |                   | 64.5       |                        |       |                        | (41.3      | )                           |       |   | (2.1 | ) |   |
| Discontinued  hedges                                   |       |                   | —     |                        |       |                        | (9.0       | )                           |       |   | — |   |   |
| Derivative fair value  gains (losses)                  |       |                   | $          | 64.4                        |       |                        |       | $                           | (58.4      | ) |   |   | $ | (3.2 | ) |   |

 

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

In connection with thesale of assets in December 2005, as discussed in Note 3 to theseConsolidated Financial Statements, we settled for cash of approximately $16.3million, natural gas collars representing derivative financial instruments on salesof 2,000 MMBtu/d of natural gas through 2011. We had previously recordedunrealized losses associated with the natural gas collars that were realizedupon settlement. Additionally, we de-designated derivative financialinstruments that qualified for and were designated as cash flow hedges offorecasted sales of 273 Bpd of NGLs through 2007 and contemporaneously closedout the position by entering into an offsetting derivative financialinstrument, at market, on forecasted purchases of 273 Bpd of NGLs through 2007.

***Derivative Positions***

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

| ** **                    | ** ** | **December 31,  2006** | ** ** | **December 31,  2005** | ** ** |
|-------------------------------|------------|-----------------------------|------------|-----------------------------|------------|
| ** **                    | ** ** | **(in millions)**      | ** ** |
| Receivables,  trade and other |       |                        | $          | 7.2                         |       |   |   | $ | 5.8 |   |   |
| Other assets, net             |       |                        | 11.0       |                        |       |   | 4.2 |   |   |
| Accounts payable  and other   |       |                        | (57.2      | )                           |       |   | (129.2 | ) |   |
| Other long-term  liabilities  |       |                        | (136.4     | )                           |       |   | (243.0 | ) |   |
|                          |       |                        | $          | (175.4                      | )          |   |   | $ | (362.2 | ) |   |

 

The decrease in our obligation associated withderivative activities is primarily due to the decline in current and forwardnatural gas prices at December 31, 2006 in relation to current and forwardnatural gas prices at December 31, 2005. The Partnership’s portfolio ofderivative financial instruments is largely comprised of long-term fixedprice natural gas sales and purchase agreements.

We record the change in fair value of our highlyeffective cash flow hedges in AOCI until the derivative financial instrumentsare settled, at which time they are reclassified to earnings. We regularlyenter into treasury locks to hedge the interest on anticipated issuances ofindebtedness. The settlement of a treasury lock can result in the retention ofunrecognized gains or losses in AOCI that are amortized to interest expenseover the life of the related debt issuance. We paid $10.2 million in December 2006,to settle treasury locks in connection with the issuance of $300 million inprincipal amount of our senior notes. The $10.2 million will be amortized fromAOCI to interest expense over the 10-year life of the senior notes.

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Also included in AOCI areunrecognized losses of approximately $4.8 million associated with derivativefinancial instruments that qualified for and were classified as cash flowhedges of forecasted commodity transactions that were subsequentlyde-designated. These unrealized losses are reclassified to earnings over theperiods during which the originally hedged forecasted transactions affectearnings. For the years ended December 31, 2006, 2005 and 2004, we reclassifiedunrealized losses of $78.3 million, $33.8 million and $12.6 million,respectively, from AOCI to Cost of natural gas on our Consolidated Statementsof Income for the fair value of derivative financial instruments that weresettled. We estimate that approximately $57.6 million of AOCI representingunrealized net losses on cash flow hedging activities at December 31,2006, will be reclassified 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.

**16. SEGMENT INFORMATION**

Our business is dividedinto operating segments, defined as components of the enterprise, about whichfinancial information is available and evaluated regularly by our ChiefOperating Decision Maker in deciding how resources are allocated andperformance is assessed.

Eachof our reportable segments is a business unit that offers different servicesand products 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.

Thefollowing table presents certain financial information relating to our businesssegments as of and for the years ended December 31, 2006, 2005 and 2004.

| ** **                                     | ** ** | **As of and for the Year Ended December 31, 2006** | ** ** |
|------------------------------------------------|------------|-------------------------------------------------------------------------------------------------|------------|
| ** **                                     | ** ** | **Liquids**                                                                                     | ** ** | **Natural Gas** | ** ** | **Marketing** | ** ** | **Corporate**(1) | ** ** | **Total** | ** ** |
| ** **                                     | ** ** | **(in millions)**                                                                          | ** ** |
| Total revenue                                  |       | $                                                                                               | 512.8      |   |   | $ | 5,404.1 |   |   |   | $ | 3,182.3 |   |   |   | $ | — |   |   | $ | 9,099.2 |   |
| Less: Intersegment  revenue                    |       | —                                                                                          |       |   | 2,383.4 |   |   |   | 206.8 |   |   |   | — |   |   | 2,590.2 |   |
| Operating revenue                              |       | 512.8                                                                                           |       |   | 3,020.7 |   |   |   | 2,975.5 |   |   |   | — |   |   | 6,509.0 |   |
| Cost of natural gas                            |       | —                                                                                          |       |   | 2,601.1 |   |   |   | 2,913.5 |   |   |   | — |   |   | 5,514.6 |   |
| Operating and  administrative                  |       | 141.3                                                                                           |       |   | 215.4 |   |   |   | 5.4 |   |   |   | 2.7 |   |   | 364.8 |   |
| Power                                          |       | 107.6                                                                                           |       |   | — |   |   |   | — |   |   |   | — |   |   | 107.6 |   |
| Depreciation and  amortization                 |       | 64.1                                                                                            |       |   | 70.3 |   |   |   | 0.5 |   |   |   | 0.2 |   |   | 135.1 |   |
| Gain on sale of assets                         |       | —                                                                                          |       |   | — |   |   |   | — |   |   |   | — |   |   | — |   |
| Operating income                               |       | 199.8                                                                                           |       |   | 133.9 |   |   |   | 56.1 |   |   |   | (2.9 | ) |   | 386.9 |   |
| Interest expense                               |       | —                                                                                          |       |   | — |   |   |   | — |   |   |   | (110.5 | ) |   | (110.5 | ) |
| Rate Refunds                                   |       | —                                                                                          |       |   | — |   |   |   | — |   |   |   | — |   |   | — |   |
| Other income                                   |       | —                                                                                          |       |   | — |   |   |   | — |   |   |   | 8.5 |   |   | 8.5 |   |
| Net income                                     |       | $                                                                                               | 199.8      |   |   | $ | 133.9 |   |   |   | $ | 56.1 |   |   |   | $ | (104.9 | ) |   | $ | 284.9 |   |
| Total assets                                   |       | $                                                                                               | 1,816.4    |   |   | $ | 2,797.3 |   |   |   | $ | 366.9 |   |   |   | $ | 243.2 |   |   | $ | 5,223.8 |   |
| Capital  expenditures (excluding acquisitions) |       | $                                                                                               | 237.2      |   |   | $ | 614.8 |   |   |   | $ | 1.9 |   |   |   | $ | 10.5 |   |   | $ | 864.4 |   |

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(1)                Corporateconsists of interest expense, interest income and certain other costs such asfranchise taxes, which are not allocated to the other business segments.

F-44

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| ** **                                     | ** ** | **As of and for the Year Ended December 31, 2005** | ** ** |
|------------------------------------------------|------------|-------------------------------------------------------------------------------------------------|------------|
| ** **                                     | ** ** | **Liquids**                                                                                     | ** ** | **Natural Gas** | ** ** | **Marketing** | ** ** | **Corporate**(1) | ** ** | **Total** | ** ** |
| ** **                                     | ** ** | **(in millions)**                                                                          | ** ** |
| Total revenue                                  |       | $                                                                                               | 418.0      |   |   | $ | 4,945.1 |   |   |   | $ | 3,884.2 |   |   |   | $ | — |   |   | $ | 9,247.3 |   |
| Less: Intersegment  revenue                    |       | —                                                                                          |       |   | 2,593.0 |   |   |   | 177.4 |   |   |   | — |   |   | 2,770.4 |   |
| Operating revenue                              |       | 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 |   |
| 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)                Corporate consistsof interest expense, interest income and certain other costs such as franchisetaxes, which are not allocated to the other business segments.

| ** **                                     | ** ** | **As of and for the Year Ended December 31, 2004** | ** ** |
|------------------------------------------------|------------|-------------------------------------------------------------------------------------------------|------------|
| ** **                                     | ** ** | **Liquids**                                                                                     | ** ** | **Natural Gas** | ** ** | **Marketing** | ** ** | **Corporate**(1) | ** ** | **Total** | ** ** |
| ** **                                     | ** ** | **(in millions)**                                                                          | ** ** |
| Total revenue                                  |       | $                                                                                               | 409.3      |   |   | $ | 2,890.1 |   |   |   | $ | 2,686.9 |   |   |   | $ | — |   |   | $ | 5,986.3 |   |
| Less:  Intersegment revenue                    |       | —                                                                                          |       |   | 1,570.2 |   |   |   | 124.4 |   |   |   | — |   |   | 1,694.6 |   |
| Operating revenue                              |       | 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 |   |
| 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 |   |

----

(1)                Corporateconsists of interest expense, interest income and certain other costs such asfranchise taxes, which are not allocated to the other business segments.

**17. SUBSEQUENTEVENTS**

On January 26, 2007, the boardof directors of Enbridge Management declared a distribution payable to ourpartners on February 14, 2007. The distribution was paid to unitholders ofrecord as of February 6, 2007, of our available cash of $80.0 million at December 31, 2006,or $0.925per limited partner unit. Of 

F-45

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this distribution, $57.6 million was paid in cash, $11.7 million was distributed in i-unitsto our i-unitholder, $10.2 millionwas distributed in Class C units to the holders of our Class C units and $0.5 million was retained from theGeneral Partner in respect of the i-unit and Class C unitdistributions to maintain its two percent general partner interest.

In January 2007, we detected a leak on line 14 ofour Lakehead system, near the Owen, Wisconsin pump station. We immediately shutthe pipeline down and dispatched emergency response crews to overseecontainment, cleanup and repair of the pipeline at an estimated cost of lessthan $1 million. We estimate the spill to approximate 1,500 barrels. Wecompleted excavation and repairs and returned the line to service within twodays. We have applied pressure restrictions to the line as we work with federaland state environmental and pipeline safety regulators to investigate the causeof the rupture. Such pressure restrictions are not anticipated to have amaterial impact on system through-put. We have the potential of incurringadditional expenditures to remediate any condition on the line that isdetermined to have caused the rupture.

In February 2007, acontractor undertaking work in Rusk County, Wisconsin on the Enbridge SouthernLights project punctured the adjacent Line 14 pipeline, resulting in a releaseof crude oil estimated at 3,000 barrels. As the spill was largely containedwithin the ditch used for construction, environmental impact was minimized. Impactto customers was minimized as the line was repaired and returned to service inless than two days. We are investigating this incident and will record costsassociated with the repair and cleanup as such amounts are determined.

**18. QUARTERLY FINANCIAL DATA (Unaudited)**

| ** **                                       | ** ** | **First**                                                           | ** ** | **Second** | ** ** | **Third** | ** ** | **Fourth** | ** ** | **Total** | ** ** |
|--------------------------------------------------|------------|---------------------------------------------------------------------|------------|------------|------------|-----------|------------|------------|------------|-----------|------------|
| ** **                                       | ** ** | **(in millions, except per unit amounts)** | ** ** |
| **2006 Quarters**                                |       |                                                                |       |       |       |      |       |       |       |      |       |
| Operating revenue                                |       | $                                                                   | 1,888.6    |       | $          | 1,424.7   |       | $          | 1,532.3    |      | $          | 1,663.4 |   | $ | 6,509.0 |   |
| Operating income(2)                              |       | $                                                                   | 108.0      |       | $          | 93.6      |       | $          | 108.7      |      | $          | 76.6 |   | $ | 386.9 |   |
| Net income(2)                                    |       | $                                                                   | 81.1       |       | $          | 70.4      |       | $          | 82.2       |      | $          | 51.2 |   | $ | 284.9 |   |
| Net income per limited  partner unit(1) (2) |       | $                                                                   | 1.12       |       | $          | 0.96      |       | $          | 1.03       |      | $          | 0.56 |   | $ | 3.62 |   |
| **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 limited  partner unit(1)          |       | $                                                                   | 0.37       |       | $          | 0.32      |       | $          | (0.32      | )         | $          | 0.68 |   | $ | 1.06 |   |

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(1)                The GeneralPartner’s allocation of net income has been deducted before calculating netincome per limited partner unit.

(2)                The fourth quarterof 2006 includes approximately $8.3 million for raw natural gas purchases andtransportation and fractionation charges that relate to prior years that we hadnot previously recorded.

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