**UNITED STATESSECURITIES AND EXCHANGE COMMISSION**

**Washington,D.C. 20549**

**FORM 10-Q**

**x**                              QUARTERLYREPORT PURSUANT TO SECTION 13 OR 15(d) OF THESECURITIES EXCHANGE ACT OF 1934

**Forthe quarterly period ended March 31, 2007**

**OR**

**o**                                 TRANSITIONREPORT PURSUANT TO SECTION 13 OR 15(d) OF THESECURITIES EXCHANGE ACT OF 1934

**Forthe transition period from                  to                   **

**Commissionfile number 1-10934**

**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, TX 77002

(Address of principalexecutive offices and zip code)

**(713) 821-2000**

(Registrant’s telephonenumber, including area code)

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 preceding 12 months(or for such shorter period that the registrant was required to file suchreports), and (2) has been subject to such filing requirements for thepast 90 days. Yes  x  No o

Indicate by check markwhether the registrant is a large accelerated filer, accelerated filer, or anon-accelerated filer (as defined in Rule 12b-2 of theExchange Act). Large Accelerated Filer xAccelerated Filer o Non-AcceleratedFiler 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 Registrant had49,938,834 Class A common units outstanding as of April 30, 2007.

 

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**ENBRIDGE ENERGYPARTNERS, L.P.**

**TABLEOF CONTENTS**
|                | ** ** | **PART I.  FINANCIAL INFORMATION**                                                                         | ** ** | ** ** |
|----------------|------------|-----------------------------------------------------------------------------------------------------------------|------------|------------|
| Item  1.       |       | Financial  Statements                                                                                           |       |       |
|           |       | Consolidated Statements of Income for the three month  periods ended March 31, 2007 and 2006               |       | 3          |   |
|           |       | Consolidated Statements of Comprehensive Income for  the three month periods ended March 31, 2007 and 2006 |       | 4          |   |
|           |       | Consolidated Statements of Cash Flows for the three  month periods ended March 31, 2007 and 2006           |       | 5          |   |
|           |       | Consolidated Statements of Financial Position as of  March 31, 2007 and December 31, 2006             |       | 6          |   |
|           |       | Notes to Consolidated Financial Statements                                                                      |       | 7          |   |
| Item 2.        |       | Management’s Discussion and Analysis of Financial  Condition and Results of Operations                     |       | 17         |   |
| Item 3.        |       | Quantitative and Qualitative Disclosures About Market  Risk                                                     |       | 35         |   |
| Item 4.        |       | Controls and Procedures                                                                                         |       | 40         |   |
| ** **     |       | **PART II.  OTHER INFORMATION**                                                                            |       |       |   |
| Item  1.       |       | Legal  Proceedings                                                                                              |       | 41         |   |
| Item  1A.      |       | Risk Factors                                                                                                    |       | 41         |   |
| Item 6.        |       | Exhibits                                                                                                        |       | 41         |   |
| **Signatures** |       | 42                                                                                                              |       |
| **Exhibits**   |       |                                                                                                            |       |       |   |

 

*In this report,unless the context requires otherwise, references to “we”, “us”, “our”, or the “Partnership”are intended to mean Enbridge Energy Partners, L.P. and its consolidatedsubsidiaries. This Quarterly Report on Form 10-Q contains forward-lookingstatements. These forward-looking statements are identified as anystatement that does not relate strictly to historical or current facts. Theyuse words such as “anticipate,” “believe,” “continue,” “estimate,” “expect,” “forecast,”“intend,” “may,” “plan,” “position,” “projection,” “strategy,” “could,” “would,”or “will” or the negative of those terms or other variations of them or bycomparable terminology. In particular, statements, expressed or implied,concerning future actions, conditions or events or future operating results orthe ability to generate sales, income or cash flow or to make distributions areforward-looking statements. Forward-looking statements are notguarantees of performance. They involve risks, uncertainties and assumptions.Future actions, conditions or events and future results of operations maydiffer 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 “Risk Factors” included in Part I,Item 1A of our Annual Report on Form 10-K for the fiscal yearended December 31, 2006 and in Part II, Item 1A of ourquarterly reports on Form 10-Q.*

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**PART I—FINANCIALINFORMATION**

**Item 1.**                        Financial Statements

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

| ** **                                                             | ** ** | **Three months ended  March 31,**                                      | ** ** |
|------------------------------------------------------------------------|------------|---------------------------------------------------------------------------------------|------------|
| ** **                                                             | ** ** | **2007**                                                                              | ** ** | **2006** | ** ** |
| ** **                                                             | ** ** | **(unaudited; in millions, except   per unit amounts)** | ** ** |
| Operating revenue                                                      |       | $                                                                                     | 1,712.7    |   | $ | 1,888.6 |   |
| Operating expenses                                                     |       |                                                                                  |       |   |   |
| Cost of natural gas (Note 10)                                          |       | 1,484.3                                                                               |       | 1,647.7 |   |
| Operating and administrative                                           |       | 97.7                                                                                  |       | 73.9 |   |
| Power                                                                  |       | 30.1                                                                                  |       | 26.3 |   |
| Depreciation and amortization                                          |       | 36.5                                                                                  |       | 32.7 |   |
|                                                                   |       | 1,648.6                                                                               |       | 1,780.6 |   |
| Operating income                                                       |       | 64.1                                                                                  |       | 108.0 |   |
| Interest expense                                                       |       | 25.3                                                                                  |       | 27.9 |   |
| Other income                                                           |       | 1.4                                                                                   |       | 1.0 |   |
| Income before income tax expense                                       |       | 40.2                                                                                  |       | 81.1 |   |
| Income tax expense (Note 6)                                            |       | 1.1                                                                                   |       | — |   |
| Net income                                                             |       | $                                                                                     | 39.1       |   | $ | 81.1 |   |
| Net income allocable to limited partner units (Note  2)                |       | $                                                                                     | 31.4       |   | $ | 73.9 |   |
| Net income per limited partner unit (basic and  diluted) (Note 2) |       | $                                                                                     | 0.40       |   | $ | 1.12 |   |
| Weighted average  units outstanding                                    |       | 77.8                                                                                  |       | 65.7 |   |

 

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

3

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

|                                             | ** ** | **Three months ended  March 31,** | ** ** |
|---------------------------------------------|------------|--------------------------------------------------|------------|
| ** **                                  | ** ** | **2007**                                         | ** ** | **2006** | ** ** |
| ** **                                  | ** ** | **(unaudited; in millions)**           | ** ** |
| Net income                                  |       | $                                                | 39.1       |   | $ | 81.1 |   |
| Other comprehensive income (loss) (Note 10) |       | (40.3                                            | )          | 34.1 |   |
| Comprehensive income (loss)                 |       | $                                                | (1.2       | ) | $ | 115.2 |   |

 

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

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**ENBRIDGE ENERGY PARTNERS, L.P.CONSOLIDATED STATEMENTS OF CASH FLOWS**

| ** **                                                                         | ** ** | **Three months ended  March 31,** | ** ** |
|------------------------------------------------------------------------------------|------------|--------------------------------------------------|------------|
| ** **                                                                         | ** ** | **2007**                                         | ** ** | **2006** | ** ** |
| ** **                                                                         | ** ** | **(unaudited; in millions)**           | ** ** |
| Cash provided by  operating activities                                             |       |                                             |       |   |   |
| Net income                                                                         |       | $                                                | 39.1       |   | $ | 81.1 |   |
| Adjustments to  reconcile net income to net cash provided by operating activities: |       |                                             |       |   |   |
| Depreciation and amortization                                                      |       | 36.5                                             |       | 32.7 |   |
| Derivative fair value (gains) losses (Note 10)                                     |       | 16.3                                             |       | (27.7 | ) |
| Inventory market price adjustments (Note 4)                                        |       | —                                           |       | 8.0 |   |
| Environmental liabilities (Note 9)                                                 |       | (0.6                                             | )          | (0.2 | ) |
| Other                                                                              |       | (0.8                                             | )          | (1.1 | ) |
| Changes in  operating assets and liabilities, net of cash acquired:                |       |                                             |       |   |   |
| Receivables, trade and other                                                       |       | 45.5                                             |       | (15.7 | ) |
| Due from General Partner and affiliates                                            |       | (13.2                                            | )          | (1.3 | ) |
| Accrued receivables                                                                |       | 28.2                                             |       | 105.5 |   |
| Inventory (Note 4)                                                                 |       | 61.1                                             |       | 26.7 |   |
| Current and long-term other assets (Note 10)                                       |       | (0.2                                             | )          | (0.5 | ) |
| Due to General Partner and affiliates                                              |       | (3.3                                             | )          | 1.9 |   |
| Accounts payable and other (Notes 3 and 10)                                        |       | (28.9                                            | )          | (36.6 | ) |
| Accrued purchases                                                                  |       | (53.1                                            | )          | (101.7 | ) |
| Interest payable                                                                   |       | 23.5                                             |       | 19.9 |   |
| Current income tax payable (Note 6)                                                |       | 1.1                                              |       | — |   |
| Property and other taxes payable                                                   |       | 1.6                                              |       | 5.4 |   |
| Net cash provided  by operating activities                                         |       | 152.8                                            |       | 96.4 |   |
| Cash used in  investing activities                                                 |       |                                             |       |   |   |
| Additions to property, plant and equipment                                         |       | (399.3                                           | )          | (98.7 | ) |
| Changes in construction payables                                                   |       | 63.9                                             |       | (6.8 | ) |
| Other                                                                              |       | 0.4                                              |       | (0.3 | ) |
| Net cash used in  investing activities                                             |       | (335.0                                           | )          | (105.8 | ) |
| Cash provided by  financing activities                                             |       |                                             |       |   |   |
| Distributions to partners (Note 8)                                                 |       | (57.6                                            | )          | (56.6 | ) |
| Net issuances of commercial paper (Note 7)                                         |       | 139.4                                            |       | 110.0 |   |
| Net cash provided  by financing activities                                         |       | 81.8                                             |       | 53.4 |   |
| Net increase (decrease) in cash and cash equivalents                               |       | (100.4                                           | )          | 44.0 |   |
| Cash and cash equivalents at beginning of year                                     |       | 184.6                                            |       | 89.8 |   |
| Cash and cash  equivalents at end of period                                        |       | $                                                | 84.2       |   | $ | 133.8 |   |

 

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

5

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**ENBRIDGE ENERGY PARTNERS, L.P.CONSOLIDATED STATEMENTS OF FINANCIAL POSITION**

| ** **                                                                                                  | ** ** | **March 31,  2007**               | ** ** | **December 31,  2006** | ** ** |
|-------------------------------------------------------------------------------------------------------------|------------|----------------------------------------|------------|-----------------------------|------------|
| ** **                                                                                                  | ** ** | **(unaudited; in millions)** | ** ** |
| **ASSETS**                                                                                                  |       |                                   |       |                        |       |   |   |   |   |
| Current assets                                                                                              |       |                                   |       |                        |       |   |   |   |   |
| Cash and cash equivalents (Note 3)                                                                          |       |                                   | $          | 84.2                        |       |   |   | $ | 184.6 |   |   |
| Receivables, trade and other, net of allowance for  doubtful accounts of $1.7 in 2007 and $2.4 in 2006 |       |                                   | 101.8      |                        |       |   | 146.7 |   |   |
| Due from General Partner and affiliates                                                                     |       |                                   | 43.7       |                        |       |   | 30.5 |   |   |
| Accrued receivables                                                                                         |       |                                   | 488.3      |                        |       |   | 516.5 |   |   |
| Inventory (Note 4)                                                                                          |       |                                   | 56.0       |                        |       |   | 117.1 |   |   |
| Other current assets (Note 10)                                                                              |       |                                   | 8.2        |                        |       |   | 13.9 |   |   |
|                                                                                                        |       |                                   | 782.2      |                        |       |   | 1,009.3 |   |   |
| Property, plant and equipment, net (Note 5)                                                                 |       |                                   | 4,188.5    |                        |       |   | 3,824.9 |   |   |
| Other assets, net  (Notes 6 and 10)                                                                         |       |                                   | 32.2       |                        |       |   | 32.5 |   |   |
| Goodwill                                                                                                    |       |                                   | 265.7      |                        |       |   | 265.7 |   |   |
| Intangibles, net                                                                                            |       |                                   | 90.3       |                        |       |   | 91.4 |   |   |
|                                                                                                        |       |                                   | $          | 5,358.9                     |       |   |   | $ | 5,223.8 |   |   |
| **LIABILITIES AND PARTNERS’ CAPITAL**                                                                  |       |                                   |       |                        |       |   |   |   |   |
| Current liabilities                                                                                         |       |                                   |       |                        |       |   |   |   |   |
| Due to General Partner and affiliates                                                                       |       |                                   | $          | 19.3                        |       |   |   | $ | 22.6 |   |   |
| Accounts payable and other (Notes 3 and 10)                                                                 |       |                                   | 276.3      |                        |       |   | 211.5 |   |   |
| Accrued purchases                                                                                           |       |                                   | 477.2      |                        |       |   | 530.3 |   |   |
| Interest payable                                                                                            |       |                                   | 32.6       |                        |       |   | 11.4 |   |   |
| Property and other taxes payable (Note 6)                                                                   |       |                                   | 20.9       |                        |       |   | 18.6 |   |   |
| Loans from General Partner and affiliates                                                                   |       |                                   | 138.5      |                        |       |   | 136.2 |   |   |
| Current maturities of long-term debt                                                                        |       |                                   | 31.0       |                        |       |   | 31.0 |   |   |
|                                                                                                        |       |                                   | 995.8      |                        |       |   | 961.6 |   |   |
| Long-term debt (Note 7)                                                                                     |       |                                   | 2,203.8    |                        |       |   | 2,066.1 |   |   |
| Environmental  liabilities (Note 9)                                                                    |       |                                   | 4.1        |                        |       |   | 3.3 |   |   |
| Other long-term  liabilities (Note 10)                                                                      |       |                                   | 170.6      |                        |       |   | 149.4 |   |   |
|                                                                                                        |       |                                   | 3,374.3    |                        |       |   | 3,180.4 |   |   |
| Commitments and  contingencies (Note 9)                                                                |       |                                   |       |                        |       |   |   |   |   |
| Partners’ capital  (Note 8)                                                                            |       |                                   |       |                        |       |   |   |   |   |
| Class A common units (Units issued—49,938,834  in 2007 and 2006)                                  |       |                                   | 1,115.5    |                        |       |   | 1,141.7 |   |   |
| Class B common units (Units issued—3,912,750 in  2007 and 2006)                                   |       |                                   | 65.7       |                        |       |   | 67.6 |   |   |
| Class C units (Units issued—11,265,872 in 2007  and 11,070,152 in 2006)                           |       |                                   | 514.3      |                        |       |   | 509.8 |   |   |
| i-units (Units issued—12,902,676 in 2007 and  12,674,148 in 2006)                                      |       |                                   | 471.5      |                        |       |   | 466.3 |   |   |
| General Partner                                                                                             |       |                                   | 47.5       |                        |       |   | 47.6 |   |   |
| Accumulated other comprehensive loss (Note 10)                                                              |       |                                   | (229.9     | )                           |       |   | (189.6 | ) |   |
|                                                                                                        |       |                                   | 1,984.6    |                        |       |   | 2,043.4 |   |   |
|                                                                                                        |       |                                   | $          | 5,358.9                     |       |   |   | $ | 5,223.8 |   |   |

 

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

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**ENBRIDGEENERGY PARTNERS, L.P.NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)**

**1.**                 BASISOF PRESENTATION

The accompanying unauditedinterim consolidated financial statements have been prepared in accordance withaccounting principles generally accepted in the United States of America forinterim consolidated financial information and with the instructions toForm 10-Q and Rule 10-01 of Regulation S-X.Accordingly, they do not include all the information and footnotes required byaccounting principles generally accepted in the United States of America forcomplete consolidated financial statements. In the opinion of management, theycontain all adjustments, consisting only of normal recurring adjustments, whichmanagement considers necessary to present fairly the financial position as ofMarch 31, 2007 and December 31, 2006, the results of operations,comprehensive income and cash flows for the three month periods endedMarch 31, 2007 and 2006. We derived the consolidated statement offinancial position as of December 31, 2006, from the audited financialstatements included in our 2006 Annual Report on Form 10-K. The results ofoperations for the three month period ended March 31, 2007, should not betaken as indicative of the results to be expected for the full year due toseasonality of portions of the natural gas business, timing and completion ofour construction projects, maintenance activities and the impact of forwardnatural gas prices and differentials on certain derivative financial instrumentsthat are accounted for using mark-to-market accounting. Inaddition, our consolidated statements of cash flows for the period ended March31, 2006 include reclassifications that were made to present changes inenvironmental liabilities separately from changes in Accounts payable andother, consistent with our current period presentation. These reclassificationshave no effect on previously reported results of operations, comprehensiveincome or partners’ capital. The interim consolidated financial statementsshould be read in conjunction with our consolidated financial statements andnotes presented in our Annual Report on Form 10-K for the fiscalyear ended December 31, 2006.

**2.**                 NETINCOME PER LIMITED PARTNER UNIT

Netincome per limited partner unit is computed by dividing net income, afterdeduction of Enbridge Energy Company, Inc.’s (the “General Partner”)allocation, by the weighted average number of our limited partner unitsoutstanding. The General Partner’s allocation is equal to an amount based uponits general partner interest, adjusted to reflect an amount equal to itsincentive distributions and an amount required to reflect depreciation on theGeneral Partner’s historical cost basis for assets contributed on formation ofthe Partnership. We have no dilutive securities. Net income per limited partnerunit was determined as follows:

|                                                          | ** ** | **Three months ended  March 31,**                | ** ** |
|----------------------------------------------------------|------------|-----------------------------------------------------------------|------------|
| ** **                                               | ** ** | **2007**                                                        | ** ** | **2006** | ** ** |
| ** **                                               | ** ** | **(in millions, except  per unit amounts)** | ** ** |
| Net income                                               |       |                                                            | $          | 39.1 |   |   |   | $ | 81.1 |   |   |
| Allocations to  the General Partner:                     |       |                                                            |       |   |   |   |   |   |   |
| Net income allocated to the  General Partner             |       |                                                            | (0.8       | ) |   |   | (1.6 | ) |   |
| Incentive income allocated to the General Partner        |       |                                                            | (6.8       | ) |   |   | (5.6 | ) |   |
| Historical cost depreciation  adjustments                |       |                                                            | (0.1       | ) |   |   | — |   |   |
|                                                     |       |                                                            | (7.7       | ) |   |   | (7.2 | ) |   |
| Net income allocable to  limited partner units           |       |                                                            | $          | 31.4 |   |   |   | $ | 73.9 |   |   |
| Weighted average units outstanding                       |       |                                                            | 77.8       |   |   |   | 65.7 |   |   |
| Net income per limited  partner unit (basic and diluted) |       |                                                            | $          | 0.40 |   |   |   | $ | 1.12 |   |   |

 

7

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**3.**                 CASHAND CASH EQUIVALENTS

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. Accordingly, obligations for which we have issued check payments thathave not yet been presented to the financial institution of approximately $28.5 millionat March 31, 2007 and $46.9 million at December 31, 2006, areincluded in Accounts payable and other on the Consolidated Statements ofFinancial Position.

**4.**                 INVENTORY

Inventoryis comprised of the following:

|                                                | ** ** | **March 31,  2007** | ** ** | **December 31,  2006** | ** ** |
|------------------------------------------------|------------|--------------------------|------------|-----------------------------|------------|
| ** **                                     | ** ** | **(in millions)**   | ** ** |
| Material and supplies                          |       |                     | $          | 3.9                         |       |   |   | $ | 3.8 |   |   |
| Liquids inventory                              |       |                     | 4.9        |                        |       |   | 9.9 |   |   |
| Natural gas and natural gas  liquids inventory |       |                     | 47.2       |                        |       |   | 103.4 |   |   |
|                                           |       |                     | $          | 56.0                        |       |   |   | $ | 117.1 |   |   |

 

**5.**                 PROPERTY,PLANT AND EQUIPMENT

Property,Plant and Equipment is comprised of the following: 

| ** **                                          | ** ** | **March 31,  2007** | ** ** | **December 31,  2006** | ** ** |
|-----------------------------------------------------|------------|--------------------------|------------|-----------------------------|------------|
| ** **                                          | ** ** | **(in millions)**   | ** ** |
| Land                                                |       |                     | $          | 14.8                        |       |   |   | $ | 14.3 |   |   |
| Rights-of-way                                       |       |                     | 306.2      |                        |       |   | 298.6 |   |   |
| Pipelines                                           |       |                     | 2,367.8    |                        |       |   | 2,320.8 |   |   |
| Pumping  equipment, buildings and tanks             |       |                     | 765.5      |                        |       |   | 747.4 |   |   |
| Compressors,  meters, and other operating equipment |       |                     | 436.9      |                        |       |   | 418.1 |   |   |
| Vehicles, office  furniture and equipment           |       |                     | 116.8      |                        |       |   | 112.4 |   |   |
| Processing and  treating plants                     |       |                     | 87.2       |                        |       |   | 86.4 |   |   |
| Construction in  progress                           |       |                     | 1,036.0    |                        |       |   | 733.6 |   |   |
| Total property, plant and equipment                 |       |                     | 5,131.2    |                        |       |   | 4,731.6 |   |   |
| Accumulated  depreciation                           |       |                     | (942.7     | )                           |       |   | (906.7 | ) |   |
| Net property,  plant and equipment                  |       |                     | $          | 4,188.5                     |       |   |   | $ | 3,824.9 |   |   |

 

**6.**                 INCOME TAXES

We are not a taxableentity for U.S. federal income tax purposes, or for the majority of states thatimpose income tax. The taxes on our net income are generally borne by ourunitholders through the allocation of taxable income. In May 2006, the State ofTexas enacted substantial changes to its tax structure to impose a new taxbased on modified gross margin, which began in 2007. Under the provisions ofStatement of Financial Accounting Standards (“SFAS”) No. 109, *Accounting for Income Taxes*, we have determined that thistax is an income tax. Our income tax expense is $1.1 million for the threemonths ended March 31, 2007, which we computed by applying a 0.56% apportioned stateincome tax rate to taxable margin, as defined in State of Texas statutes. Ourincome tax expense represents a 2.7% effective rate as applied to pretax bookincome. At March 31, 2007, we have included a current income tax payable of$1.1 million in Property and other taxes payable and a deferred income taxasset of $0.5 million in Other assets, net on our Consolidated Statement ofFinancial Position.

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**7.**                 DEBT

***Credit Facility***

At March 31, 2007 and December 31, 2006, wehad no amounts outstanding under our Credit Facility and had letters of credit totaling$73.0 million and $59.3 million, respectively. The amounts we may borrowunder the terms of our Credit Facility are reduced by the principal amount ofour commercial paper issuances and the balance of our letters of creditoutstanding. At March 31, 2007, we could borrow $345.0 million underthe terms of our Credit Facility without consideration to additional borrowingsunder our commercial paper program.

On April 4, 2007 weentered into the Second Amended and Restated Credit Agreement (Credit Facility)which among other things: (i) increases the maximum principal amount of creditavailable to us at any one time from $1 billion to $1.25 billion; (ii) gives usthe right to request increases in the maximum principal amount of creditavailable at any one time from $1.25 billion to $1.5 billion; (iii) eliminatesthe sublimit on letters of credit; (iv) provides for a five-year facility thatmatures April 4, 2012 and grants us the option to request annual extensions ofmaturity and a one-year term out period upon maturity; (v) modifies ourleverage ratio to include in the calculations of EBITDA (as defined in theSecond Amended and Restated Credit Agreement) pro forma adjustments formaterial projects and to exclude from the calculation of Consolidated FundedDebt (as defined in the Second Amended and Restated Credit Agreement) certainamounts of preferred securities and subordinated debt that we or our designatedsubsidiaries may issue in the future; and (vi) eliminates our coverage ratiofinancial covenant. Our Credit Facility continues to support our commercialpaper program.

***Commercial Paper Program***

Under the terms of ourcommercial paper program, we can issue up to $600 million of commercial paper. AtMarch 31, 2007, we had outstanding $581.4 million of commercial paper, netof unamortized discount of $0.6 million, bearing interest at a weighted averagerate of 5.45%. At December 31, 2006, we had $443.7 million ofcommercial paper outstanding, net of $1.3 million of unamortized discount,at a weighted average interest rate of 5.45%. At March 31, 2007, we couldissue an additional $18 million in principal amount under the terms of ourcommercial paper program.

**8.      PARTNERS’ CAPITAL**

Thefollowing table sets forth the distributions, as approved by the Board ofDirectors of Enbridge Energy Management, L.L.C. (“Enbridge Management”) duringthe three months ended March 31, 2007:

| 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** | ** ** |
|---------------------------------|------------|-------------------------------------|------------|------------------|------------|---------------------------------|------------|--------------------------------------------|------------|-------------------------------------------------------------------------------|------------|-------------------------------------------------------------------------------------------------------|------------|-----------------------------------------|------------|--------------------------------|------------|
| January 26, 2007                |       | February 14, 2007                   |       | February 6, 2007 |       |                            | $          | 0.925                                      |       |                                                                          |       | $                                                                                                     | 80.0       |                                    |       |                           | $          | 11.7 |   |   |   | $ | 10.2 |   |   |   | $ | 0.5 |   |   |   | $ | 57.6 |   |   |
|                                 |            |                                     |            |                  |            |                                 |            |                                            |            |                                                                               |            |                                                                                                       |            |                                         |            |                                |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

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(1)                    During 2007, in lieu of cashdistributions, the Partnership issued 228,528 i-units to EnbridgeManagement.

(2)                    During 2007, in lieu of cashdistributions, the Partnership issued 195,720 Class C units to our Class Cunitholders.

(3)                    The Partnership retains an amount equal to2% of the i-unit and Class C unit distribution from the General Partnerin respect of its 2 percent general partner interest.

***Private Placement of Class C Units***

During April 2007, weissued and sold 4.7 million Class C units at a price of $53.11 per Class C unitto CDP Infrastructure Fund G.P. (“CDP”), 0.9 million Class C units to TortoiseInfrastructure Corporation and 0.3 million Class C units to Tortoise EnergyCapital Corporation. We sold the Class C units in a 

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privatetransaction exempt from registration under Section 4(2) of the Securities Act.We received net proceeds, including expenses associated with the privateplacement, of approximately $315 million. In addition, our general partnercontributed approximately $6.4 million to us to maintain its 2.0 percentgeneral partner interest. We intend to use the net proceeds from the sale tofinance a portion of our capital expansion program, including the East Texasand Southern Access expansion projects.

**9.**                 COMMITMENTS,CONTINGENCIES AND ENVIRONMENTAL LIABILITIES

***Environmental Liabilities***

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.We manage this environmental risk through appropriate environmental policiesand practices to minimize any impact on the environment of our operations.

As of March 31, 2007 and December 31, 2006,we have recorded $2.7 million and $4.1 million, respectively, incurrent liabilities and $4.1 million and $3.3 million, respectively,in long-term liabilities, primarily to address remediation ofcontaminated sites, asbestos containing materials, management of hazardouswaste material disposal, and outstanding air quality measures for certain ofour liquids and natural gas assets.

In January 2007, we detected a leak on Line 14 of ourLakehead system, near the Owen, Wisconsin pump station. We immediately shut thepipeline down and dispatched emergency response crews to oversee containment,cleanup and repair of the pipeline at an estimated cost of $1 million, which wehave recorded as a liability on our Consolidated Statements of FinancialPosition. We estimate the spill to approximate 1,500 barrels. We completedexcavation and repairs and returned the line to service within two days. Wehave applied pressure restrictions to the line as we work with federal andstate environmental and pipeline safety regulators to investigate the cause ofthe rupture. Such pressure restrictions are not anticipated to have a materialimpact on system through-put. We have the potential of incurring additionalexpenditures to remediate any condition on the line that is determined to havecaused 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 also minimized as the line was repaired and returned toservice in less than two days. We continue investigating this incident and haveestimated costs to approximate $2.6 million associated with the repair andcleanup, which we have recorded as a liability and a receivable, since we willrecover these cost from the parties responsible for the damage. Any furtherexposure or impact related to this incident is not believed to be material.

***Legal Proceedings***

We are a participant in variouslegal proceedings arising in the ordinary course of business. Some of theseproceedings are covered, in whole or in part, by insurance. We believe that theoutcome of all these proceedings will not, individually or in the aggregate,have a material adverse effect on our financial condition.

**10.**          DERIVATIVEFINANCIAL INSTRUMENTS—COMMODITY PRICE RISK

Our net income and cashflows are subject to volatility stemming from changes in commodity prices ofnatural gas, NGLs, condensate and fractionation margins (the relative pricedifferential between NGL sales and the offsetting natural gas purchases). Ourexposure to commodity price risk exists within 

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ourNatural Gas and Marketing segments. To mitigate the volatility of our cashflows, we use derivative financial instruments (i.e., futures, forwards, swaps,options and other financial instruments with similar characteristics) to managethe risks associated with market fluctuations in commodity prices. Based on ourrisk management policies, all of our derivative financial instruments areemployed in connection with an underlying asset, liability and/or forecastedtransaction and are not entered into with the objective of speculating oninterest 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 the estimatedamounts that we would pay or receive, other than in a forced or liquidationsale, to terminate or close the contracts at the reporting date, taking intoaccount the current unrealized losses or gains on open contracts. We useactively traded external market quotes and indices to value substantially allof the derivative 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. Cash flowis only impacted to the extent the actual derivative contract is settled bymaking or receiving a payment to or from the counterparty or by making orreceiving a payment for entering into a contract that exactly offsets theoriginal derivative contract. Typically, we settle our derivative contractswhen the physical transaction that underlies the derivative financialinstrument occurs.

If a derivative financial instrumentqualifies and is designated as a cash flow hedge, a hedge of a forecastedtransaction or future cash flows, any unrealized mark-to-market gain or loss isdeferred in Accumulated other comprehensive income (“AOCI”), a component ofPartners’ Capital, until the underlying hedged transaction occurs. To theextent that the hedge instrument is effective in offsetting the transactionbeing hedged, there is no impact to the income statement. At inception and on aquarterly basis, we formally assess whether the hedge contract is highlyeffective in offsetting changes in cash flows of hedged items. Any ineffectiveportion of a cash flow hedge’s change in fair market value is recognized eachperiod in earnings. Realized gains and losses on derivative financial instrumentsthat are designated as hedges and qualify for hedge accounting are included inCost of natural gas in the period the hedged transaction occurs. Gains andlosses deferred in AOCI related to cash flow hedges, for which hedge accountinghas been discontinued, remain in AOCI until the underlying physical transactionoccurs unless it is probable that the forecasted transaction will not occur bythe end of the originally specified time period, or within an additionaltwo-month period of time thereafter. Generally, our preference is for ourderivative financial instruments to receive hedge accounting treatment wheneverpossible, to mitigate 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.

***Non-Qualified Hedges***

Many of our derivative financial instruments qualifyfor hedge accounting treatment under the specific requirements of SFASNo. 133. However, we have four primary transaction types associated withour commodity derivative financial instruments where the hedge structure doesnot meet the requirements to apply hedge accounting. As a result, thesefinancial instruments do not qualify for hedge accounting under SFAS No. 133and are referred 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, 

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included in Cost ofnatural gas in our Consolidated Statements of Income. These mark-to-marketadjustments produce a degree of earnings volatility that can often besignificant from period to period, but have no cash flow impact relative tochanges in market prices. The cash flow impact occurs when the underlyingphysical transaction takes place in the future and when the associatedfinancial instrument contract settlement is made.

The four primary transaction types that do not qualifyfor 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 derivative financialinstruments (i.e., natural gas swaps) to hedge the relative difference betweenthe injection price paid to purchase and store natural gas and the withdrawalprice at which the natural gas is sold from storage. The intent of thesederivative financial instruments is to lock in the margin, representing thedifference between the price paid for the natural gas injected and the pricereceived upon withdrawal of the gas from storage in a future period. We do notpursue cash flow hedge accounting treatment for these storage transactionssince the underlying forecasted injection or withdrawal of natural gas may notoccur in the period as originally forecast. This can occur because we have theflexibility to make changes in the underlying injection or withdrawal schedule,given changes in market conditions. In addition, since the physical natural gasis recorded at the lower of cost or market, timing differences can result whenthe derivative financial instrument is settled in a period that is differentfrom when the physical natural gas is sold from storage. As a result,derivative financial instruments associated with our natural gas storageactivities can create volatility in our earnings.

3**.****                 NaturalGas Collars—**In our Natural Gas segment, we had previously entered intonatural gas collars to hedge the sales price of natural gas. The natural gascollars were based on a NYMEX price, while the physical gas sales were based ona different index. To better align the index of the natural gas collars withthe index of the underlying sales, we de-designated the original cashflow hedging relationship with the intent of contemporaneously re-designatingthe natural gas collars as hedges of forecasted physical natural gas sales witha NYMEX pricing index. However, because the fair value of these derivative financialinstruments was a liability to us at re-designation, they are considerednet written options under SFAS No. 133 and do not qualify for hedgeaccounting. These derivatives are being marked-to-market, with thechanges in fair value from the date of de-designation recorded toearnings 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 NGLs producedfrom our natural gas 

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processing facilities. Ournatural gas contracts allow us the option of processing natural gas when it iseconomical, and ceasing to do so when processing becomes uneconomic. We haveentered into derivative financial instruments to fix the sales price of aportion of the NGLs that we produce at our discretion and to fix the associatedpurchases of natural gas required for processing. We will designate derivativefinancial instruments associated with NGLs we produce at our discretion as cashflow hedges when the processing of natural gas is probable of occurrence.However, we are precluded from designating the derivative financial instrumentsentered to 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 instances described above, theunderlying physical purchase, storage and sale of natural gas and NGLs are accountedfor on a historical cost or market basis rather than on the mark-to-marketbasis we utilize for the derivative financial instruments employed to mitigatethe commodity price risk associated with our storage and transportation assets.This difference in accounting (i.e.,the derivative financial instruments are recorded at fair market value whilethe physical transactions are recorded at historical cost) can and hasresulted in volatility in our reported net income, even though the economicmargin is essentially unchanged from the date the transactions wereconsummated.

Thefollowing table presents the mark-to-market gains and losses associated withchanges in the fair value of our commodity price derivative financialinstruments, which are recorded as an element of Cost of natural gas in ourConsolidated Statements of Income and disclosed as a reconciling item on ourStatements of Cash Flows:

| ** **                                                   | ** ** | **Three months ended  March 31,** | ** ** |
|--------------------------------------------------------------|------------|--------------------------------------------------|------------|
| **Derivative fair value gains (losses)** | ** ** | ** **                                       | ** ** | **    2007    ** | ** ** | **    2006    ** | ** ** |
| ** **                                                   | ** ** | **(in millions)**                           | ** ** |
| Natural Gas segment                                          |       |                                             |       |   |   |   |   |   |   |
| Hedge ineffectiveness                                        |       |                                             | $          | 0.1 |   |   |   | $ | — |   |   |
| Non-qualified hedges                                         |       |                                             | (3.2       | ) |   |   | 1.8 |   |   |
| Marketing                                                    |       |                                             |       |   |   |   |   |   |   |
| Non-qualified hedges                                         |       |                                             | (13.2      | ) |   |   | 25.9 |   |   |
| Derivative fair value  gains (losses)                        |       |                                             | $          | (16.3 | ) |   |   | $ | 27.7 |   |   |
|                                                              |            |                                                  |            |  |  |  |  |  |  |  |  |  |  |

 

We record the change in fair value of our cash flowhedges in AOCI until the derivative financial instruments are settled, at whichtime they are reclassified from AOCI to earnings. Also included in AOCI areunrecognized losses of approximately $4.1 million associated with cashflow hedges that were subsequently de-designated. These losses are reclassifiedto earnings over the periods during which the originally hedged forecastedtransactions affect earnings. For the three months ended March 31, 2007, wereclassified losses of $16.2 million, respectively from AOCI to Cost of naturalgas on our Consolidated Statements of Income for the fair value of derivativefinancial instruments that were settled.

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***Derivative Positions***

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

|                              | ** ** | **March 31,  2007** | ** ** | **December 31,  2006** | ** ** |
|------------------------------|------------|--------------------------|------------|-----------------------------|------------|
| ** **                   | ** ** | **(in millions)**   | ** ** |
| Other current assets         |       |                     | $          | 1.7                         |       |   |   | $ | 7.2 |   |   |
| Other assets, net            |       |                     | 10.6       |                        |       |   | 11.0 |   |   |
| Accounts payable and other   |       |                     | (88.1      | )                           |       |   | (57.2 | ) |   |
| Other long-term  liabilities |       |                     | (160.3     | )                           |       |   | (136.4 | ) |   |
|                              |       |                     | $          | (236.1                      | )          |   |   | $ | (175.4 | ) |   |

 

The increase in our obligation associated withderivative activities is primarily due to the increase in forward natural gasprices from December 31, 2006 to March 31, 2007. The Partnership’sportfolio of derivative financial instruments is largely comprised of long-termfixed price natural gas sales and purchase agreements.

We do not requirecollateral or other security from the counterparties to our derivative financialinstruments, all of which were rated “BBB+” or better by the major credit ratingagencies.

**11.**          SEGMENTINFORMATION

Our business is divided into operating segments,defined as components of the enterprise, about which financial information isavailable and evaluated regularly by our Chief Operating Decision Maker indeciding how resources are allocated and performance is assessed.

Each of ourreportable segments is a business unit that offers different services andproducts that is managed separately, since each business segment requiresdifferent operating strategies. We have segregated our business activities intothree distinct operating segments:

·       Liquids;

·       NaturalGas; and

·       Marketing.

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Thefollowing tables present certain financial information about our businesssegments:

|                                                | ** ** | **As of and for the three months ended March 31, 2007** | ** ** |
|------------------------------------------------|------------|-----------------------------------------------------------------------------------------------------------|------------|
| ** **                                     | ** ** | **Liquids**                                                                                               | ** ** | **Natural Gas** | ** ** | **Marketing** | ** ** | **Corporate**(1) | ** ** | **Total** | ** ** |
| ** **                                     | ** ** | **(in millions)**                                                                                    | ** ** |
| Total revenue                                  |       | $                                                                                                         | 132.8      |   |   | $ | 1,324.3 |   |   |   | $ | 889.4 |   |   |   | $ | — |   |   | $ | 2,346.5 |   |
| Less:  Intersegment revenue                    |       | —                                                                                                    |       |   | 568.8 |   |   |   | 65.0 |   |   |   | — |   |   | 633.8 |   |
| Operating revenue                              |       | 132.8                                                                                                     |       |   | 755.5 |   |   |   | 824.4 |   |   |   | — |   |   | 1,712.7 |   |
| Cost of natural  gas                           |       | —                                                                                                    |       |   | 663.2 |   |   |   | 821.1 |   |   |   | — |   |   | 1,484.3 |   |
| Operating and administrative                   |       | 33.7                                                                                                      |       |   | 61.3 |   |   |   | 1.6 |   |   |   | 1.1 |   |   | 97.7 |   |
| Power                                          |       | 30.1                                                                                                      |       |   | — |   |   |   | — |   |   |   | — |   |   | 30.1 |   |
| Depreciation and  amortization                 |       | 16.4                                                                                                      |       |   | 20.0 |   |   |   | 0.1 |   |   |   | — |   |   | 36.5 |   |
| Operating income                               |       | 52.6                                                                                                      |       |   | 11.0 |   |   |   | 1.6 |   |   |   | (1.1 | ) |   | 64.1 |   |
| Interest expense                               |       | —                                                                                                    |       |   | — |   |   |   | — |   |   |   | 25.3 |   |   | 25.3 |   |
| Other income                                   |       | —                                                                                                    |       |   | — |   |   |   | — |   |   |   | 1.4 |   |   | 1.4 |   |
| Income before income tax  expense              |       | 52.6                                                                                                      |       |   | 11.0 |   |   |   | 1.6 |   |   |   | (25.0 | ) |   | 40.2 |   |
| Income tax  expense                            |       | —                                                                                                    |       |   | — |   |   |   | — |   |   |   | 1.1 |   |   | 1.1 |   |
| Net income                                     |       | $                                                                                                         | 52.6       |   |   | $ | 11.0 |   |   |   | $ | 1.6 |   |   |   | $ | (26.1 | ) |   | $ | 39.1 |   |
| Total assets                                   |       | $                                                                                                         | 2,016.7    |   |   | $ | 2,845.6 |   |   |   | $ | 334.5 |   |   |   | $ | 162.1 |   |   | $ | 5,358.9 |   |
| Capital expenditures  (excluding acquisitions) |       | $                                                                                                         | 223.2      |   |   | $ | 166.7 |   |   |   | $ | 1.2 |   |   |   | $ | 8.2 |   |   | $ | 399.3 |   |

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(1)      Corporateconsists of interest expense, interest income and certain other costs such asfranchise and income taxes, which are not allocated to our business segments.

|                                                | ** ** | **As of and for the three months ended March 31, 2006** | ** ** |
|------------------------------------------------|------------|-----------------------------------------------------------------------------------------------------------|------------|
| ** **                                     | ** ** | **Liquids**                                                                                               | ** ** | **Natural Gas** | ** ** | **Marketing** | ** ** | **Corporate**(1) | ** ** | **Total** | ** ** |
| ** **                                     | ** ** | **(in millions)**                                                                                    | ** ** |
| Total revenue                                  |       | $                                                                                                         | 122.6      |   |   | $ | 1,601.9 |   |   |   | $ | 966.4 |   |   |   | $ | — |   |   | $ | 2,690.9 |   |
| Less:  Intersegment revenue                    |       | —                                                                                                    |       |   | 730.9 |   |   |   | 71.4 |   |   |   | — |   |   | 802.3 |   |
| Operating revenue                              |       | 122.6                                                                                                     |       |   | 871.0 |   |   |   | 895.0 |   |   |   | — |   |   | 1,888.6 |   |
| Cost of natural  gas                           |       | —                                                                                                    |       |   | 773.5 |   |   |   | 874.2 |   |   |   | — |   |   | 1,647.7 |   |
| Operating and administrative                   |       | 28.6                                                                                                      |       |   | 43.7 |   |   |   | 1.1 |   |   |   | 0.5 |   |   | 73.9 |   |
| Power                                          |       | 26.3                                                                                                      |       |   | — |   |   |   | — |   |   |   | — |   |   | 26.3 |   |
| Depreciation and  amortization                 |       | 15.9                                                                                                      |       |   | 16.6 |   |   |   | 0.1 |   |   |   | 0.1 |   |   | 32.7 |   |
| Operating income                               |       | 51.8                                                                                                      |       |   | 37.2 |   |   |   | 19.6 |   |   |   | (0.6 | ) |   | 108.0 |   |
| Interest expense                               |       | —                                                                                                    |       |   | — |   |   |   | — |   |   |   | 27.9 |   |   | 27.9 |   |
| Other income                                   |       | —                                                                                                    |       |   | — |   |   |   | — |   |   |   | 1.0 |   |   | 1.0 |   |
| Net income (loss)                              |       | $                                                                                                         | 51.8       |   |   | $ | 37.2 |   |   |   | $ | 19.6 |   |   |   | $ | (27.5 | ) |   | $ | 81.1 |   |
| Total assets                                   |       | $                                                                                                         | 1,669.5    |   |   | $ | 2,227.0 |   |   |   | $ | 390.9 |   |   |   | $ | 125.4 |   |   | $ | 4,412.8 |   |
| Capital expenditures  (excluding acquisitions) |       | $                                                                                                         | 16.4       |   |   | $ | 81.1 |   |   |   | $ | 0.4 |   |   |   | $ | 0.8 |   |   | $ | 98.7 |   |

 

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(1)      Corporate consists ofinterest expense, interest income and certain other costs such as franchisetaxes, which are not allocated to our business segments.

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**12.**          SUBSEQUENTEVENT

***Distribution to Partners***

On April 26, 2007,the Board of Directors of Enbridge Management declared a distribution payableto our partners on May 15, 2007. The distribution will be paid to unitholdersof record as of May 7, 2007, of our available cash of $86.6 million atMarch 31, 2007, or $0.925 per common unit. Of this distribution, $58.2 millionwill be paid in cash, $11.9 million will be distributed in i-units to ouri-unitholder, $15.9 million will be distributed in Class C units tothe holders of our Class C units and $0.6 million will be retained fromthe General Partner in respect of the i-unit and Class C unitdistributions.

**13.**          RECENTACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED

In February 2007, the Financial Accounting StandardsBoard (FASB) issued Statement No. 159, *The Fair Value Option forFinancial Assets and Liabilities.*This statement provides companieswith an option to report certain financial assets and liabilities at fairvalue. The objective of SFAS No. 159 is to reduce complexity in accounting forfinancial instruments and the volatility in earnings caused by measuringrelated financial assets and liabilities. SFAS No. 159 also establishespresentation and disclosure requirements designed to facilitate comparisonsbetween companies that choose different measurement attributes for similartypes of assets and liabilities. The provisions of SFAS No. 159 are effectiveat the beginning of our first fiscal year that begins after November 15, 2007.We have elected not to early adopt the provisions of SFAS No. 159, althoughearly adoption is permitted as of the beginning of a fiscal year that begins onor before November 15, 2007, provided the entity also elects to apply theprovisions of SFAS No. 157. We do not expect our adoption of SFAS No. 159to have a material affect on our Consolidated Financial Statements.

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**Item 2.**                        Management’sDiscussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financialcondition and results of operations should be read together with our ConsolidatedFinancial Statements and the accompanying notes included in “Item 1.Financial Statements” of this report.

Additionally, this quarterlyreport on Form 10-Q should be read in conjunction with our Annual Reporton Form 10-K for the year ended December 31, 2006.

**RESULTS OFOPERATIONS—OVERVIEW**

We provide services to our customers and returns forour unitholders primarily through the following activities:

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

·       Gathering,treating, processing and transportation of natural gas and natural gas liquids,or NGLs, through pipelines and related facilities; and

·       Providingsupply, transportation and sales services, including purchasing and sellingnatural gas and NGLs.

We conduct our business through three business segments:Liquids, Natural Gas and Marketing. These segments are strategic business unitsestablished by senior management to facilitate the achievement of our long-termobjectives, to aid in resource allocation decisions and to assess operationalperformance.

We primarily provide fee-based services to ourcustomers to minimize our exposure to commodity price risks. However, in ournatural gas and marketing businesses, a portion of our earnings and cash flowsare exposed to movements in the prices of natural gas and NGLs. Tosubstantially mitigate this exposure and to provide stability to our cash flow,we enter into derivative financial instrument transactions. Certain of thesetransactions qualify for hedge accounting under Statement of FinancialAccounting Standards No. 133, *Accountingfor Derivative Transactions and Hedging Activities*(“SFAS No. 133”); some, however, must be accounted for using the mark-to-marketmethod of accounting and this can expose our earnings to significantvolatility.

Thefollowing table reflects our operating income by business segment and corporatecharges for the three month periods ended March 31:

| ** **                              | ** ** | **Three months ended  March 31,**         | ** ** |
|-----------------------------------------|------------|----------------------------------------------------------|------------|
| ** **                              | ** ** | **    2007    ** | ** ** | **    2006    ** | ** ** |
| ** **                              | ** ** | **(in millions)**                                   | ** ** |
| **Operating Income**               | ** ** |                                                     | ** ** | ** ** |   |   | ** ** | ** ** |   |
| Liquids                                 |       |                                                     | $          | 52.6 |   |   |   | $ | 51.8 |   |   |
| Natural Gas                             |       |                                                     | 11.0       |   |   |   | 37.2 |   |   |
| Marketing                               |       |                                                     | 1.6        |   |   |   | 19.6 |   |   |
| Corporate, operating and administrative |       |                                                     | (1.1       | ) |   |   | (0.6 | ) |   |
| **Total  Operating Income**             |       |                                                     | 64.1       |   |   |   | 108.0 |   |   |
| Interest expense                        |       |                                                     | 25.3       |   |   |   | 27.9 |   |   |
| Other income                            |       |                                                     | 1.4        |   |   |   | 1.0 |   |   |
| Income tax expense                      |       |                                                     | 1.1        |   |   |   | — |   |   |
| **Net Income**                          |       |                                                     | $          | 39.1 |   |   |   | $ | 81.1 |   |   |

 

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***Summary Analysis ofOperating Results***

*Liquids*

Our Liquids segmentproduced operating income of $52.6 million for the three months endedMarch 31, 2007, a slight increase over the $51.8 million earned in thesame period of 2006. The increase in operating income of our Liquids segment isprimarily due to improved operating results on our Mid-Continent system,complemented by consistent operating results on our Lakehead system.

*Natural Gas*

Operating income from ourNatural Gas segment decreased by $26.2 million to $11.0 million for the threemonths ended March 31, 2007, from $37.2 million for the same period in2006. The decrease in contribution from our Natural Gas segment is primarilyattributable to the following:

·       Anunexpected increase in natural gas measurement losses on two of our majorgathering systems, partly resulting from increased water production within somenatural gas streams.

·       Operationalinefficiencies at our Zybach plant, in part caused by fouling of the plant bycontaminated water in the natural gas stream, which reduced NGL production andthe associated revenue.

·       Increased operating and administrative costs associated with theincrease in volumes and expansion of our natural gas systems as well aschanging pipeline integrity regulation.

*Marketing*

Operating income from ourMarketing segment decreased by $18.0 million to $1.6 million for the threemonths ended March 31, 2007 from $19.6 million for the same period in 2006.The decrease in operating income of our Marketing segment is predominantly theresult of three factors:

·       Unrealized,non-cash mark-to-market net losses for the three months ended March 31, 2007 of$13.2 million compared with non-cash mark-to-market net gains of $25.9 million forthe same period in 2006, that resulted from the change in market value of our derivativefinancial instruments that do not qualify for hedge accounting.

·       Partiallyoffsetting our unrealized, non-cash, mark-to-market losses in the first quarterof 2007 is income of approximately $12 million that we realized upon the saleof approximately 3.9 billion cubic feet, or bcf of natural gas inventory thatincluded approximately $6 million in gains from the settlement of derivative financialinstruments hedging our natural gas inventory.

·       During the three monthsended March 31, 2006, we recorded a non-cash charge of $8.0 million, resultingfrom a lower of cost or market accounting adjustment to the cost basis of ournatural gas inventory that we did not incur during the first quarter of 2007.The market price for natural gas in various storage locations may experiencedeclines during the year from the prices at which the inventory was purchased. 

***DerivativeTransactions and Hedging Activities***

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

The unrealized,mark-to-market losses for the three months ended March 31, 2007, are the resultof increases in the forward and daily market prices of natural gas and NGLs,compared to the first quarter of 

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2006. However,NGL prices, which tend to move in relation to crude oil prices, have continuedto trend higher due to supply instability in the crude oil market. While thenatural gas and NGL pricing environment continues to remain volatile, themark-to-market gains and losses created by this volatility do not affect ourcash flow. We expect these non-cash gains and losses to be offset in futurequarters as we settle the derivative financial instruments and the underlyingphysical transactions.

Thefollowing table presents the unrealized, non-cash, mark-to-market gains andlosses by segment, associated with our derivative financial instruments for thethree month periods ended March 31, 2007 and 2006:

| ** **                                                   | ** ** | **Three months ended  March 31,** | ** ** |
|--------------------------------------------------------------|------------|--------------------------------------------------|------------|
| **Derivative fair value gains (losses)** | ** ** | ** **                                       | ** ** | **   2007   ** | ** ** | **   2006   ** | ** ** |
| ** **                                                   | ** ** | **(in millions)**                           | ** ** |
| Natural Gas  segment                                         |       |                                             |       |   |   |   |   |   |   |
| Hedge ineffectiveness                                        |       |                                             | $          | 0.1 |   |   |   | $ | — |   |   |
| Non-qualified hedges                                         |       |                                             | (3.2       | ) |   |   | 1.8 |   |   |
| Marketing                                                    |       |                                             |       |   |   |   |   |   |   |
| Non-qualified hedges                                         |       |                                             | (13.2      | ) |   |   | 25.9 |   |   |
| Derivative fair value  gains (losses)                        |       |                                             | $          | (16.3 | ) |   |   | $ | 27.7 |   |   |
|                                                              |            |                                                  |            |  |  |  |  |  |  |  |  |  |  |

 

**RESULTS OF OPERATIONS—BY SEGMENT**

***Liquids***

Thefollowing tables set forth the operating results and statistics of our Liquidssegment assets for the periods presented:

| ** **                                     | ** ** | **Three months ended  March 31,**         | ** ** |
|------------------------------------------------|------------|----------------------------------------------------------|------------|
| ** **                                     | ** ** | **    2007    ** | ** ** | **    2006    ** | ** ** |
| ** **                                     | ** ** | **(in millions)**                                   | ** ** |
| **Operating Results**                          | ** ** |                                                     | ** ** | ** ** |   |   | ** ** | ** ** |   |
| Operating revenues                             |       |                                                     | $          | 132.8 | ** ** |   |   | $ | 122.6 | ** ** |   |
| Operating and administrative                   |       |                                                     | 33.7       | ** ** |   |   | 28.6 | ** ** |   |
| Power                                          |       |                                                     | 30.1       | ** ** |   |   | 26.3 | ** ** |   |
| Depreciation and amortization                  |       |                                                     | 16.4       | ** ** |   |   | 15.9 | ** ** |   |
| Operating expenses                             |       |                                                     | 80.2       | ** ** |   |   | 70.8 | ** ** |   |
| **Operating  Income**                          |       |                                                     | $          | 52.6 | ** ** |   |   | $ | 51.8 | ** ** |   |
| **Operating  Statistics**                      | ** ** |                                                     | ** ** | ** ** |   |   | ** ** | ** ** |   |
| **Lakehead system:**                           | ** ** |                                                     | ** ** | ** ** |   |   | ** ** | ** ** |   |
| United States(1)                               |       |                                                     | 1,248      | ** ** |   |   | 1,161 | ** ** |   |
| Province of Ontario(1)                         |       |                                                     | 335        | ** ** |   |   | 348 | ** ** |   |
| **Total deliveries**(1)                        |       |                                                     | 1,583      | ** ** |   |   | 1,509 | ** ** |   |
| **Barrel miles (billions)**                    |       |                                                     | 103        | ** ** |   |   | 100 | ** ** |   |
| **Average haul (miles)**                       |       |                                                     | 722        | ** ** |   |   | 738 | ** ** |   |
| **Mid-Continent  system deliveries**(1)        |       |                                                     | 238        | ** ** |   |   | 237 | ** ** |   |
| **North Dakota  system deliveries**(1)  (2)    |       |                                                     | 87         | ** ** |   |   | 82 | ** ** |   |
| **Total Liquids Segment Delivery  Volumes**(1) |       |                                                     | 1,908      | ** ** |   |   | 1,828 | ** ** |   |

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(1)                 Average barrels per day (“Bpd”) inthousands.

(2)                 Included in these volumes for the threemonths ended March 31, 2007 and 2006, respectively are approximately 6,000 Bpdand 8,000 Bpd of deliveries for which we receive both gathering andtransportation tolls.

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***Three months ended March 31, 2007 compared withthree months ended March 31, 2006***

Our Liquids segment accounted for $52.6 million of operatingincome during the three months ended March 31, 2007, representing a $0.8million increase over the same period in 2006. The increase is primarily relatedto improved operating results on our Mid-Continent system coupled withconsistent results on our Lakehead system.

Operating revenue for the first quarter of 2007increased by approximately $10.2 million to $132.8 million from $122.6million for the same period in 2006. Volumes on our Lakehead system increasedapproximately 5 percent, from 1.509 million Bpd during the first quarter of2006 to 1.583 million Bpd during the same period in 2007, which resulted inhigher operating revenue of approximately $4.9 million. In addition,increases in average tariffs on all three Liquids systems resulted in higheroperating revenue by approximately $4.3 million. These tariff increases werethe result of the annual index rate increases allowed by the Federal EnergyRegulatory Commission (“FERC”). New tariff rates went into effect on April 1,2006 for an adjustment on the Terrace expansion program surcharge and newfacilities in service, which were not in effect during the first quarter of2006. Further tariff revisions came about as a result of the annual index rateincrease allowed by the FERC effective July 1, 2006.

Operating and administrative expenses for the Liquidssegment increased $5.1 million for the first quarter of 2007, compared with thesame period in 2006. The increase is driven primarily by (i) higher workforcerelated costs due to the additional costs we are charged for operational,administrative, regulatory and compliance support necessary for our existingassets, (ii) the expansion of our liquids operations and (iii) repairs andcleanup costs associated with the leak on line 14 that occurred in January 2007.

Power costs increased $3.8million in the first quarter of 2007, compared with the same period in 2006,primarily due to the increased throughput on our Lakehead system, along withhigher utility rates we are charged by our power suppliers. 

*Future ProspectsUpdate for Liquids*

We and Enbridge areactively working with our customers to develop transportation options that willallow Canadian crude oil greater access to markets throughout the UnitedStates.

Partnership Projects

*Southern Access*

In conjunction withEnbridge, we announced in 2005 the approval of the 400,000 Bpd Southern Accessexpansion project, which received endorsement from the Canadian Association ofPetroleum Producers, or CAPP, a trade association that represents a largemajority of the Lakehead system’s customers. We are undertaking the U.S.portion of the expansion on our Lakehead system. The first stage will addapproximately 44,000 Bpd of capacity in 2007 and up to an additional 146,000Bpd by early 2008. The project includes a new pipeline between Superior andDelavan, Wisconsin, along with pump station enhancements upstream anddownstream of this segment. The second stage of the expansion project willprovide additional upstream pumping capacity and a new pipeline from Delavan toFlanagan, Illinois, with completion expected in early 2009. Completion of thetotal Southern Access expansion project will create a 454-mile pipelinewith approximately 400,000 Bpd of incremental capacity on our Lakehead system.In April 2007, the Illinois Commerce Commission approved and allowed theproject to exercise the right of eminent domain if necessary. We continue toprogress on schedule with this project; however, we are experiencing costpressures for labor, materials and rights-of-way which may affect the ultimatecost of completing this project. The risk to our unitholders resulting fromthese cost pressures is largely mitigated by the cost of service tollingarrangement used for this project.

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*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, Wisconsin. We anticipate that our share of the cost of thisproject, as currently proposed, will approximate $0.8 billion in 2006 dollars.

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 is continuing tofinalize commercial terms of the Alberta Clipper project with CAPP. To maintainthe project 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 our normal FERC ratesetting process.AlbertaClipper is expected to be in service between late 2009 and mid-2010. Theproject progressed through the first quarter of 2007 as anticipated. 

*North Dakota*

Work continues on ourpreviously announced North Dakota system expansion. North Dakota Public ServiceCommission approvals were obtained for all phases of the project during 2006.The expansion will add approximately 30,000 Bpd of mainline throughput capacityand expand the system’s feeder segment by approximately 30,000 Bpd at anestimated cost $0.1 billion. 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 scheduledfor the fourth quarter of 2007. As shippers continue to express interest infurther expansion of pipeline capacity, we initiated an open season to enlistshipper commitments for further expansion of the North Dakota system.

*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 for completionin the first half of 2007 and two additional tanks each with an approximatecapacity of 250,000 barrels each to be completed in the first half of 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 December2006. The remaining 3.9 million barrels of capacity will be completed during2007 at an expected cost of $72 million. Once complete our total terminal capacitywill be approximately 16.7 million barrels, which includes 1.4 million barrelsof operational storage. This capacity will increase 

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operationaltankage available to support our Mid-Continent liquids pipeline systems, and availablecontract storage. Progress continues to be made in adding additional capacityto the terminal.

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 2006 andhas operated at its capacity of 125,000 Bpd. We have benefited from reversal ofthe pipeline due to Western Canadian crude oil being carried on our Lakeheadsystem as far as Chicago, and then transferred to the Spearhead pipeline. On March2, 2007, Enbridge initiated a binding open season for expansion of the pipelineto 190,000 Bpd, which was successfully concluded in late April with receipt ofbinding commitments for capacity in excess of 30,000 Bpd. This project will becomplementary to our Lakehead system and Enbridge is targeting completion inearly 2009.

*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 volumesmoving through our Lakehead system to reach this extension. The Offer ofSettlement filed in September 2006 was rejected by the FERC because of itsrolled-in toll design. However, support for the project remains high andEnbridge is working with shippers to prepare an alternative tolling structureto address the initial opposition. The second application is expected to befiled with the FERC in the near future and should allow the project to proceedon 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 the need to increase the availability of crude oil diluentin Alberta. Diluent is required to transport the heavy oil and bitumen beingproduced in increasing volumes from the Alberta oil sands. The project involvesthe exchange of a 156-mile section of pipeline we own for a similarsection of a new pipeline to be constructed as part of the project. We expectto benefit from increased heavy crude shipments, which will be facilitated bythe diluent line. In addition, this project involves a reconfiguration of our lightcrude mainline system which will provide an additional 45,000 Bpd of effectivecapacity at no cost to us. This project is expected to be in service during2010. During the first quarter of 2007 Enbridge filed applications withCanada’s National Energy Board (NEB) for approval of all facets of the Canadianportion of the project and continues to progress on the necessary applicationsfor the U.S. portion of the project with U.S. federal and state regulatoryagencies. In conjunction with the Southern Access project, the Southern Lightsproject has been allowed the right to exercise eminent domain for right of wayin Illinois.

*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 

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ourLakehead system and support its expansion. Enbridge has indicated that a directline would require a minimum of 400,000 Bpd of throughput commitments to beeconomic, and could not be in service before 2011. A direct line, if developedby Enbridge or any other party, would compete 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. A project ofthis nature would be complementary to our Lakehead system.

We and Enbridge believethat the Southern Access Expansion Program, the Alberta Clipper Project, andother initiatives to provide access to new markets in the Midwest,Mid-continent and Gulf Coast, offer flexible solutions to future transportationrequirements of western Canadian crude oil producers, and the in-service timingof these solutions is in line with prospective shipper needs.

***Natural Gas***

Thefollowing tables set forth the operating results of our Natural Gas segmentassets and approximate average daily volumes of our major systems in MMBtu/dfor the periods presented:

| ** **                          | ** ** | **Three months ended  March 31,** | ** ** |
|-------------------------------------|------------|--------------------------------------------------|------------|
| ** **                          | ** ** | **2007**                                         | ** ** | **2006** | ** ** |
| ** **                          | ** ** | **(in millions)**                           | ** ** |
| **Operating Results**               |       |                                             |       |   |   |
| Operating  revenues                 |       | $                                                | 755.5      |   | $ | 871.0 |   |
| Cost of natural  gas                |       | 663.2                                            |       | 773.5 |   |
| Operating and  administrative       |       | 61.3                                             |       | 43.7 |   |
| Depreciation and  amortization      |       | 20.0                                             |       | 16.6 |   |
| Operating  expenses                 |       | 744.5                                            |       | 833.8 |   |
| **Operating  Income**               |       | $                                                | 11.0       |   | $ | 37.2 |   |
| **Operating  Statistics (MMBtu/d)** | ** ** | ** **                                       | ** ** | ** ** | ** ** |
| East Texas                          |       | 1,135,000                                        |       | 921,000 |   |
| Anadarko                            |       | 583,000                                          |       | 563,000 |   |
| North Texas                         |       | 320,000                                          |       | 279,000 |   |
| UTOS                                |       | 125,000                                          |       | 199,000 |   |
| MidLa                               |       | 110,000                                          |       | 83,000 |   |
| AlaTenn                             |       | 59,000                                           |       | 54,000 |   |
| KPC                                 |       | 37,000                                           |       | 47,000 |   |
| Bamagas                             |       | 115,000                                          |       | 37,000 |   |
| Other major  intrastates(1)         |       | 267,000                                          |       | 220,000 |   |
| Total                               |       | 2,751,000                                        |       | 2,403,000 |   |

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(1)                 We have included in Other majorintrastates the volumes of our Gloria system for the three months ended March31, 2007 and 2006 in the amounts of 66,000 MMBtu/d and 62,000 MMBtu/d,respectively.

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***Three months ended March 31, 2007 compared withthree months ended March 31, 2006***

Our Natural Gas segment contributed $11.0 million ofoperating income in the first quarter of 2007, a decrease of $26.2 million fromthe $37.2 million contributed in the corresponding period of 2006. Although theoverall volumes for the first quarter of 2007 on our three largest systems weregreater than the comparable period of 2006, operational inefficiencies at ourZybach plant and an unexpected increase in measurement losses, primarily on ourEast Texas and Anadarko systems, reduced the operating income of our NaturalGas segment. Natural gas measurement losses occur as part of the normaloperating conditions associated with our natural gas pipelines. Thequantification and resolution of measurement losses is complicated by severalfactors including varying qualities of natural gas in the streams gathered andprocessed through our systems, changes in weather temperatures and variances inmeasurement that are inherent in metering technologies. We are taking steps toaddress these operational issues through plant maintenance and discussions withproducers that use our natural gas systems.

We have identified operating conditions on our gatheringsystems which we believe have contributed to our increased measurement losses.We are taking several actions to address increased measurement losses. Thesesteps include the installation of separator equipment to identify free-water inthe natural gas streams and shut in such streams until producers are able toeliminate the free-water. During the first quarter of 2007 we estimate thatmeasurement losses resulted in approximately $8 million of additional economiccost to our natural gas systems relative to the first quarter of 2006.

Average daily volumes on our major natural gas systemswere up approximately 14 percent in the first quarter of 2007, compared withthe corresponding period in 2006. Increases in our volumes for 2007 areattributable to our ongoing investments to expand the capacity of our systemsand services. Our investments in the following projects that were completedduring 2006 and 2007 contributed to the increase in the average daily volumesand operating results on 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; and

·                  Acquisitionof an 80-mile pipeline in April 2006 that is complementary 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 BarnettShale. We expect increasing volumes on our major natural gas systems to resultfrom our continuing investments to expand the capacity of our systems.

A variable element of our Natural Gas segment’soperating income is derived from keep-whole processing of natural gas.Operating income derived from our keep-whole processing for the threemonths ended March 31, 2007, was approximately $5*** ***million,compared with approximately $10 million for the same period in 2006. As aresult of operational issues associated with our Zybach processing plant therevenue generated by our processing assets less the cost of natural gaspurchased for processing was approximately $8 million lower than theamounts we realized in the comparable period of 2006.

During the first quarter of 2007, we determined thatour Zybach processing plant needed to be repaired and modified. We areundertaking a project to increase the plant’s NGL recoveries, which havedecreased in the first quarter of 2007 compared to its level of production whenwe initially commissioned 

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the plant in 2006. Theoperating inefficiencies created by this condition negatively affected ourprocessing results in the first quarter of 2007. As a result of this condition,we are completing modifications to enhance recoveries of NGLs at our Zybachplant.

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 andNGLs we process in exchange for providing these producers with our services. Inorder to protect our unitholders from the volatility in cash flows that canresult 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 thefirst quarter of 2007 includes unrealized non-cash, mark-to-market netlosses of $3.1 million, including $0.1 million of gains resulting fromineffectiveness of our cash flow hedges and $3.2 million of losses derived fromour derivative financial instruments that do not qualify for hedge accountingtreatment under SFAS No. 133. In the first quarter of 2006, our operatingincome was increased by $1.8 million of unrealized, non-cash, mark-to-marketnet gains that we incurred, primarily from derivative financial instrumentsthat do not qualify for hedge accounting treatment under SFAS No. 133. Weexpect the net mark-to-market gains and losses to be offset when the relatedphysical transactions are settled (refer also to the discussions included inNote 10 of Item 1. Financial Statements and following under DerivativeActivities, and Item 3. Quantitative and Qualitative Disclosures About MarketRisk).

Operating and administrative costs of our Natural Gassegment were $17.6 million greater for the three months ended March 31,2007 than the three months ended March 31, 2006, primarily as a result ofincreased workforce related costs associated with the expansion of our systems,maintenance activities and other costs that are mostly variable with volumes.However, the operating costs in the first quarter of 2007 approximate our operatingcosts for the fourth quarter of 2006. This is consistent with the expansion ofour natural gas systems and the related costs that continue to increase as weexpand our systems and increase the volumes of natural gas services we provide.Workforce related costs have increased due to the additional resources andrelated benefit costs we are charged for the operational, administrative,regulatory and compliance support necessary for our existing assets and theexpansion of our natural gas operations. Our general partner charges us thecosts associated with employees and relatedbenefits for personnel that are assigned to us or otherwise provide us withmanagerial and administrative services. The portion of compensation and relatedcosts we are charged is dependent upon such items as estimated time spent,miles of pipe and headcount. In addition we have experienced an increase inoutside contract labor cost, given the high demand and competitive rates withinour industry as a result of continuous pipeline expansions across the areas weserve.

Materials, supplies and other costs along with repairand maintenance costs were higher predominantly related to the increase involumes and expansion of our natural gas systems. Repair and maintenance costsinclude compressor maintenance, downtime for routine and unscheduledmaintenance, pipeline integrity costs and other similar items that haveincreased with the expansion of our existing natural gas systems. During thefirst quarter of 2007, we spent more on pipeline integrity work in connectionwith our ongoing pipeline integrity management program compared with the sameperiod of 

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2006. We expect workforcerelated costs in addition to materials, supplies and other cost to continueincreasing as we expand our systems and increase the volumes of natural gasservices we provide.

Depreciation expense forour Natural Gas segment was higher in the first quarter of 2007 as compared tothe first quarter of 2006, primarily as a result of capital projects completedand placed in-service during 2006. Additionally, we revised thedepreciation rates for a portion of our FERC-regulated natural gas assetseffective July 1, 2006, to reflect a decrease in the remaining servicelife of these natural gas assets. We expect deprecation expense to increasethroughout 2007 as we complete our construction projects and place the assetsinto service.

*Future ProspectsUpdate for Natural Gas*

We continue to assess various expansion opportunitiesto pursue our strategy for growth. 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 primarily ondevelopment of our existing pipeline systems. We may, and have, pursuedopportunities to divest any non-strategic natural gas assets as conditionswarrant.

Results of our natural gas gathering and processingbusiness depend upon the drilling activities of natural gas producers in theareas we serve. During the first quarter of 2007, increased drilling in theareas where our gathering systems are located has contributed to our volumegrowth. We expect the growth trend in these areas to continue in the future asevidenced by external production forecast and the strong rig counts andpermitting in the areas served by our systems.

Producer drilling plans in regional plays, in theareas served by our natural gas assets, are expected to result in continuedproduction growth. To accommodate this further growth, we initiatedconstruction on several projects to increase our gathering and treatinginfrastructure and market access capability. These projects continue toprogress according to schedule and include:

*East Texas SystemExpansion and Extension (Project Clarity):*

·                  Theexpansion and extension of our East Texas natural gas system, referred to asthe Clarity project, includes construction of a 36-inch diameterintrastate pipeline from Bethel, Texas to Orange County, Texas with capacity ofapproximately 700 MMcf/d. The new pipeline will provide service to a number ofmajor industrial companies in Southeast Texas and will cross a number ofinterstate pipelines. We continue to secure additional commitments for capacityon the pipeline. We currently anticipate the expansion project will costapproximately $610 million; however, we are experiencing cost pressures forlabor, materials and rights-of-way, which may affect the ultimate cost ofcompleting the construction of this project. Additionally, the project’sschedule could be affected by severe weather conditions.

·                  Thefirst phase of our Clarity project was completed late in March 2007 andincludes the construction of a 24-inch diameter intrastate pipeline thatextends approximately 60 miles from Marquez, Texas to Crockett, Texas and a 36-inchdiameter pipeline that extends approximately 53 miles from Crockett toGoodrich, Texas. We expect the completion of this phase to begin to contributemodest operating revenue to our natural gas segment in the second quarter of2007 following completion of upstream gathering facilities late in the secondquarter.

·                  Theremainder of our Clarity project is expected to be completed in stagesthroughout 2007. These phases include the construction of a 36-inchdiameter intrastate pipeline that extends approximately 63 miles from Bethel toCrockett and approximately 42 miles from Goodrich to Kountze, Texas andapproximately 41 miles from Kountze to Orange County.

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·                  Aspart of our East Texas expansion project we added a 200 MMcf/d treatingfacility near Marquez which is connected to the 36-inch diameterintrastate pipeline via a new 24-inch diameter pipeline. This project wascompleted in conjunction with the first phase of our Clarity project in lateMarch 2007, and is expected to contribute additional volume growth on ourEast Texas natural gas system through increased CO2 and sour gastreating capacity commensurate with thecompletion of several ongoing construction projects in the area.

*Other East TexasProjects:*

·                  Theexpansion of our sour gas treating capacity on the East Texas system willincrease the total sulfur capacity in the first half of 2007 from 72.5 tons perday (tpd) to 125 tpd by early 2008, in order to handle additional sour gassupply and higher concentration levels of hydrogen sulfide (H2S).

·                  The installationof additional processing plants will enable our East Texas system to meet theincreasingly more stringent pipeline gas quality specifications by late 2007.

*North Texas SystemProjects:*

·                  Inorder to accommodate the active development and anticipated growth occurring inthe Barnett Shale play in North Texas we have commenced construction of two newgas processing plants totaling approximately 75 MMcf/d of capacity and relatedupstream facilities. These facilities with processing capacities of 35 MMcf/dand 40 MMcf/d are expected to become operational in the second and fourthquarters of 2007, respectively.

*Anadarko SystemProjects:*

·                  OurAnadarko system continues to experience considerable growth as a result of therapid development of the Granite Wash play in Hemphill and Wheeler counties inTexas. We are continuing to make progress in increasing processing capacity andfield compression in the region and expect to place 155 MMcf/d of additionalprocessing capacity as well as field compression in service duringMay 2007.

·                  Duringthe second quarter of 2007, we refurbished our Zybach processing plant toaddress the operational inefficiencies being experienced by the plant. As aresult of the downtime and associated restart we expect processing volumes andoperating revenues from our Anadarko system to continue to be depressed in thesecond quarter.

When fully operational in late 2007, we expect thatthe new assets we are constructing will provide additional sources of cash flowfor us. We continue to evaluate otherprojects that could further integrate our major Texas-centered naturalgas pipeline systems.

A number of new interstatenatural gas transportation pipelines are being constructed that may alter thelandscape for interstate transportation of natural gas. Although a majority ofour Natural Gas segment revenues are derived from the gathering, processing andintrastate transportation of natural gas, these newly contracted pipelinescould affect the operating results of our existing market-based interstate andintrastate natural gas pipelines. Conversely, our supply based gatheringsystems may benefit from enhanced capacity out of our gathering areas.

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*Other Matters*

In December 2005,Calpine Corporation (“Calpine”) and many of its subsidiaries, including thesubsidiary that owns the two utility plants served by our Bamagas system, filedvoluntarily petitions to restructure under Chapter 11 of the United StatesBankruptcy Code. Calpine has continued to perform under the terms of itsagreement with Bamagas and we remain confident that any losses we may incurwith respect to Calpine’s bankruptcy will be minimal. We continue to monitorthe Calpine bankruptcy proceedings and will recognize any losses that may resultwhen it becomes evident that a loss has been incurred.

***Marketing***

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

|                                | ** ** | **Three months ended  March 31,**         | ** ** |
|--------------------------------|------------|----------------------------------------------------------|------------|
| ** **                     | ** ** | **    2007    ** | ** ** | **    2006    ** | ** ** |
| ** **                     | ** ** | **(in millions)**                                   | ** ** |
| Operating revenues             |       |                                                     | $          | 824.4 |   |   |   | $ | 895.0 |   |   |
| Cost of natural  gas           |       |                                                     | 821.1      |   |   |   | 874.2 |   |   |
| Operating and administrative   |       |                                                     | 1.6        |   |   |   | 1.1 |   |   |
| Depreciation and  amortization |       |                                                     | 0.1        |   |   |   | 0.1 |   |   |
| Operating Expenses             |       |                                                     | 822.8      |   |   |   | 875.4 |   |   |
| **Operating  Income**          |       |                                                     | $          | 1.6 |   |   |   | $ | 19.6 |   |   |

 

***Three months ended March 31, 2007 compared withthree months ended March 31, 2006***

In the first quarter of 2007, the operating income ofour Marketing segment decreased $18.0 million to $1.6 million, from$19.6 million for the corresponding period in 2006. Included in operatingincome for the first quarter of 2007 are unrealized, non-cash, mark-to-marketlosses of approximately $13.2 million compared with unrealized mark-to-marketgains of $25.9 million for the comparable period in 2006, associated withderivative financial instruments that do not qualify for hedge accountingtreatment under SFAS No. 133. The unrealized, mark-to-market losses forthe three months ended March 31, 2007, are the result of increases in theforward and daily market prices of natural gas and NGLs from December 31,2006. We expect these net mark-to-market losses to be offset when the relatedphysical transactions are settled (refer also to the discussion included inNote 10 of Item 1. Financial Statements, following under DerivativeActivities and Item 3. Quantitative and Qualitative Disclosures AboutMarket Risk).

The operating results of our Marketing business forthe three months ended March 31, 2007, do not include adjustments to thecost basis of our natural gas inventory to reduce it to fair market value.Natural gas prices as published by Platt’s *Gas Daily* forHenry Hub were approximately $7.34 per MMBtu at March 31, 2007, which hadincreased from $5.64 per MMBtu at December 31, 2006. Partially offsettingour unrealized, non-cash, mark-to-market losses in the first quarter of 2007are gains of approximately $12 million that we realized upon the sale of approximately 3.9 Bcf of natural gas inventorythat included approximately $6 million in gains from the settlement ofderivative financial instruments hedging our natural gas inventory.

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 customers who need natural gas. Amajority of the natural gas we purchase is produced in Texas markets where wehave limited physical access to the primary interstate pipeline deliverypoints, or hubs such as Waha, Texas and the Houston Ship Channel. As a result,our Marketing business must use third-party pipelines to transport the natural 

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gas to these markets whereit can be sold to our customers. However, physical pipeline constraints oftenrequire our Marketing business to transport natural gas to alternate marketpoints. Under these circumstances, our Marketing segment will sell thepurchased gas at a pricing index that is different from the pricing index atwhich the gas was purchased. This creates a price exposure that arises from therelative difference in natural gas prices between the contracted index at whichthe natural gas is purchased and the index under which it is sold, otherwiseknown as the “spread.” The spread can vary significantly due to local supplyand demand factors. Wherever possible, this pricing exposure is economicallyhedged using derivative financial instruments. However, the structure of theseeconomic hedges often precludes our use of hedge accounting under the requirementsof SFAS No. 133, which can create volatility in the operating results ofour 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 our exposure tocash flow volatility that could arise in markets where the firm transportationbecomes uneconomic. However, the structure of these transactions precludes ouruse of hedge accounting under the requirements of SFAS No. 133, which cancreate volatility in the operating results of our Marketing segment.

In addition to natural gasbasis swaps, we contract for storage to assist with balancing natural gassupply and end use market sales. In order to mitigate the absolute pricedifferential between the cost of injected natural gas and withdrawn naturalgas, as well as storage fees, the injection and withdrawal price differential,or “spread,” is hedged by buying fixed price swaps for the forecasted injectionperiods and selling fixed price swaps for the forecasted withdrawal periods.When the injection and withdrawal spread increases or decreases in value as aresult of market price movements, we can earn additional profit through theoptimization of those hedges in both the forward and daily markets. Althougheach of these hedge strategies are sound economic hedging techniques, thesetypes of financial transactions do not qualify for hedge accounting under theSFAS No. 133 guidelines. As such, the non-qualified hedges areaccounted for on a mark-to-market basis, and the periodic change intheir market value, although non-cash, will impact the income statement.

***Corporate***

Interest expense was $25.3 million for the threemonths ended March 31, 2007, compared with $27.9 million for thecorresponding period in 2006. The decrease is primarily the result of $8.5million of interest capitalized on our construction projects for the threemonths ended March 31, 2007, compared with the $0.5 million capitalizedduring the same period of 2006. Partially offsetting the increase incapitalized interest is the additional interest expense generated by higherweighted average debt balances. Our weighted average interest rate of 5.9% isconsistent with our weighted average interest rate of 5.9% for the same periodin 2006.

We are not a taxableentity for U.S. federal income tax purposes or for the majority of states thatimpose an income tax. Our income tax expense of $1.1 million for the threemonths ended March 31, 2007 results from the enactment, by the State ofTexas, of a new state tax computed on our 2007 modified gross margin. Wedetermined this tax to be an income tax under the provisions of SFASNo. 109, *Accounting for Income Taxes*. Wecomputed our income tax expense for the quarter ended March 31, 2007 byapplying a 

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0.56%apportioned state income tax rate to taxable margin, as defined in State ofTexas statutes. Our income tax expense represents a 2.7% effective rate asapplied to pretax book income.

**LIQUIDITY AND CAPITAL 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 capitalexpenditures, debt service payments, distributions to our partners,acquisitions of new assets and businesses, and payments associated with ourderivative transactions. Short-term cash requirements, such as operatingexpenses, maintenance capital expenditures debt service payments and quarterlydistributions to our partners, are expected to be funded by our 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 on various factors, including prevailing market conditions,interest rates, our financial 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 April 2007, we issued and sold 4.7 millionClass C units at a price of $53.11 per Class C unit to CDP InfrastructureFund G.P. (“CDP”), 0.9 million Class C units to Tortoise Infrastructure Corporationand 0.3 million Class C units to Tortoise Energy Capital Corporation. Wesold the Class C units in a private transaction exempt from registrationunder Section 4(2) of the Securities Act. We received net proceeds,including expenses associated with the private placement, of approximately $315million. In addition, our general partner contributed approximately $6.4million to us to maintain its 2.0 percent general partner interest. We intendto use the net proceeds from the sale to finance a portion of our capitalexpansion program, including the East Texas and Southern Access expansionprojects.

**Available Credit**

A significant source ofour liquidity is provided by the commercial paper market and our CreditFacility. We have a $600 million commercial paper program that is supported byour long-term Credit Facility, which we access primarily to provide temporaryfinancing for our operating activities, capital expenditures and acquisitions,at rates that are generally lower than the rates available under our CreditFacility.

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*Credit Facility*

The amounts we may borrowunder the terms of our Credit Facility are reduced by the principal amount ofour commercial paper issuances and the balance of our letters of creditoutstanding. At March 31, 2007, no amounts had been borrowed against ourCredit Facility and we had approximately $73.0 million of letters of creditoutstanding. At March 31, 2007, we could borrow $345 million underthe terms of our Credit Facility without consideration to additionalborrowings under our commercial paper program.

On April 4, 2007 weentered into the Second Amended and Restated Credit Agreement (Credit Facility)which among other things: (i) increases the maximum principal amount ofcredit available at any one time to us from $1 billion to $1.25 billion;(ii) gives us the right to request increases in the maximum principalamount of credit available at any one time to us up to $1.5 billion;(iii) eliminates the sublimit on letters of credit; (iv) provides fora five-year facility that matures April 4, 2012 and grants us the optionto request annual extensions of maturity and a one-year term out period uponmaturity; (v) modifies the our leverage ratio to include in thecalculations of EBITDA (as defined in the Second Amended and Restated CreditAgreement) pro forma adjustments for material projects and to exclude from thecalculation of Consolidated Funded Debt (as defined in the Second Amended andRestated Credit Agreement) certain amounts of preferred securities andsubordinated debt that we or our designated subsidiaries may issue in thefuture; and (vi) eliminates our coverage ratio financial covenant. OurCredit Facility continues to support our commercial paper program.

*Commercial Paper*

Under the terms of ourcommercial paper program, we may issue up to $600 million of commercial paper. AtMarch 31, 2007, we had outstanding $581.4 million of commercial paper, netof unamortized discount of $0.6 million, bearing interest at a weighted averagerate of 5.45%. At December 31, 2006, we had $443.7 million ofcommercial paper outstanding, net of $1.3 million of unamortized discount,at a weighted average interest rate of 5.45%. At March 31, 2007, we couldissue an additional $18 million in principal amount under our commercial paperprogram.

***Cash Requirementsfor Future Growth***

**Capital Spending**

We expect to makesignificant expenditures during the next three years for the construction ofadditional natural gas and crude oil transportation infrastructure. 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. As of March 31, 2007, we have approximately $825 millionin outstanding purchase commitments for materials and services associated withour capital projects for the construction of assets that we expect to settleduring the remainder of 2007. However, we will incur additional commitments asour capital projects continue to progress.

*Forecasted Expenditures*

We categorize our capitalexpenditures as either core maintenance or enhancement expenditures. Coremaintenance expenditures are those expenditures that are necessary to maintainthe service capability of our existing assets and include the replacement ofsystem components and equipment which is worn, obsolete or completing itsuseful life. Enhancement expenditures improve the service capability of ourexisting assets, extend asset useful lives, increase capacities from existinglevels, reduce costs or enhance revenues, and enable us to respond togovernmental regulations and developing industry standards.

We estimate our capitalexpenditures based upon our strategic operating and growth plans, which arealso dependent upon our ability to produce or otherwise obtain the capitalnecessary to accomplish our 

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growthobjectives. The following table sets forth our estimates of capital requiredfor system enhancement and core maintenance expenditures throughDecember 31, 2007. Although we anticipate making the indicatedexpenditures, these estimates may change due to factors beyond our control,including weather-related issues, construction timing, changes insupplier prices or poor economic conditions. Additionally, estimates may changeas a result of decisions made at a later date to revise the scope of a project.We made capital expenditures of approximately $399.3 million, including$9.2 million on core maintenance activities, during the three months endedMarch 31, 2007.

Forthe full year of 2007, we anticipate our capital expenditures to approximatethe following in millions:

| System enhancements          |   | $   | 440    |   |
|------------------------------|--------|-----|--------|--------|
| Core maintenance  activities |   | 60  |   |
| Southern Access expansion    |   | 810 |   |
| East Texas  expansion        |   | 270 |   |
|                              |   | $   | 1,580  |   |

 

*Major ConstructionProjects*

The following tableincludes our active major construction projects and additional informationregarding our estimated construction cost, actual expenditures throughMarch 31, 2007, the incremental capacity that will become available uponcompletion of the project and the periods during which we expect to completethe construction. From December 31, 2006, through the first three monthsof 2007, we incurred approximately $348 million of capital expendituresassociated with the projects listed below. The estimated amounts included inthis table may change due to modifications of the scope of the project,increases in materials and construction costs and other factors that areoutside of our direct control.

|                                          | ** ** | **Capital Expenditures**        | ** ** | **Estimated Incremental Capacity**                            | ** ** | ** **  | ** ** |
|------------------------------------------|------------|--------------------------------------|------------|-------------------------------------------------------------------------|------------|-------------|------------|
| ** **                               | ** ** | **Estimated   Total Cost** | ** ** | **Actual   Expenditures   through  March 31, 2007** | ** ** | **Storage** | ** ** | **Oil** | ** ** | **Natural   Gas** | ** ** | **Expected   Completion** | ** ** |
| ** **                               | ** ** | **(in billions)**               | ** ** | **(KBbl)**                                                              | ** ** | **(Kbpd)**  | ** ** | **(MMcf/d)** | ** ** | ** ** | ** ** |
| Southern Access expansion (Lakehead)     |       |                                 | $          | 1.3                                                                     |       |        |       | $ | 0.297 |   |   |   | — |   |   |   | 400 |   |   |   | — |   |   | 2009 |   |
| Clarity (East Texas)                     |       |                                 | 0.6        |                                                                    |       |        | 0.404      |   |   |   | — |   |   |   | — |   |   |   | 700 |   |   | In  phases to late 2007 |   |
| Alberta Clipper                          |       |                                 | 0.8        |                                                                    |       |        | —     |   |   |   | — |   |   |   | 450 |   |   |   | — |   |   | Late  2009 to mid-2010 |   |
| North Dakota system   expansion          |       |                                 | 0.1        |                                                                    |       |        | 0.020      |   |   |   | — |   |   |   | 30 |   |   |   | — |   |   | Late  2007 |   |
| Cushing terminal storage   tanks         |       |                                 | 0.1        |                                                                    |       |        | 0.050      |   |   |   | 4,970 |   |   |   | — |   |   |   | — |   |   | Throughout  2007 |   |
| Griffith and Superior storage tanks      |       |                                 | 0.1        |                                                                    |       |        | 0.014      |   |   |   | 1,220 |   |   |   | — |   |   |   | — |   |   | Mid-2007  and mid-2008 |   |
| Natural gas connects and compression     |       |                                 | 0.1        |                                                                    |       |        | 0.092      |   |   |   | — |   |   |   | — |   |   |   | — |   |   | Various |   |
| Processing and treating plant expansions |       |                                 | 0.3        |                                                                    |       |        | 0.170      |   |   |   | — |   |   |   | — |   |   |   | 1,130 |   |   | Various |   |
| Total                                    |       |                                 | $          | 3.4                                                                     |       |        |       | $ | 1.047 |   |   |   | 6,190 |   |   |   | 880 |   |   |   | 1,830 |   |   |   |   |

 

 

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Including major expansion projects and excludingacquisitions, ongoing capital expenditures are expected to be significant overthe next three years due to our East Texas expansion and extension, SouthernAccess expansion and Alberta Clipper projects. Core maintenance capital is alsoanticipated to increase over that period of time due to growth in our pipelinesystems and aging 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 integritymeasures to ensure both regulatory compliance and to maintain the overallintegrity of our pipeline systems. Expenditure levels have continued toincrease as pipelines age and require higher levels of inspection ormaintenance; however, these are viewed to be consistent with industry trends.

***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 therisks associated with market fluctuations in commodity prices. Based on ourrisk management policies, all of our derivative financial instruments areemployed in connection with an underlying asset, liability or anticipatedtransaction and are not entered into with the objective of speculating oncommodity prices.

Thefollowing table provides summarized information about the timing and expectedsettlement amounts of our outstanding commodity derivative financialinstruments at March 31, 2007 for each of the indicated calendar years: 

|                        | ** ** | **Notional**                  | ** ** | **2007** | ** ** | **2008** | ** ** | **2009** | ** ** | **2010** | ** ** | **2011** | ** ** | **2012** | ** ** |
|------------------------|------------|-------------------------------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------|------------|
| ** **             | ** ** | **($ in millions)** | ** ** |
| **Swaps**              |       |                          |       |     |       |     |       |     |       |     |       |     |       |     |       |
| Natural gas(1)         |       | 274,738,530                   |       | $        | (30.7      | )        | $          | (39.8    | )          | $        | (33.2      | )        | $          | (27.2    | )          | $ | (23.9 | ) | $ | (4.8 | ) |
| NGL(2)                 |       | 8,337,949                     |       | (27.4    | )          | (15.7    | )          | (7.5     | )          | (3.5     | )          | (1.1     | )          | —   |       |
| Crude(2)               |       | 1,284,691                     |       | (7.5     | )          | (7.8     | )          | (2.3     | )          | (0.8     | )          | (0.3     | )          | —   |       |
| **Options—calls** |       |                          |       |     |       |     |       |     |       |     |       |     |       |     |       |
| Natural gas(1)         |       | 1,736,000                     |       | (1.1     | )          | (1.5     | )          | (1.3     | )          | (1.2     | )          | (1.1     | )          | —   |       |
| **Options—puts**  |       |                          |       |     |       |     |       |     |       |     |       |     |       |     |       |
| Natural gas(1)         |       | 2,470,000                     |       | 0.2      |       | —   |       | —   |       | —   |       | —   |       | —   |       |
| Totals                 |       |                          |       | $        | (66.5      | )        | $          | (64.8    | )          | $        | (44.3      | )        | $          | (32.7    | )          | $ | (26.4 | ) | $ | (4.8 | ) |

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(1)                Notional amounts for natural gas arerecorded in MMBtu.

(2)                Notional amounts for NGL and Crude arerecorded in Bbl.

***Operating Activities***

Net cash provided byoperating activities for the three months ended March 31, 2007 was $152.8million, an increase of $56.4 million from the $96.4 million generatedduring the same period in 2006. The improved operating cash flow is primarilyattributable to sales of inventory in the first quarter 2007 that we did notmake in the first quarter of 2006, and other changes in working capitalaccounts. Additionally, net cash provided by operating activities increased dueto the general timing differences in the collection on and payment of ourcurrent and related party accounts.

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***Investing Activities***

We used $229.2 millionmore in our investing activities during the three months ended March 31,2007 in relation to the same period in 2006. The increase is primarilyattributable to the $300.6 million increase in our investments in property,plant and equipment during the first quarter of 2007 over the amount spentduring the same period of 2006 offset by a $70.7 million increase in ourconstruction payables. The increase in our capital expenditures in the firstquarter of 2007 is directly attributable to our previously announced expansionprojects.

***Financing Activities***

Net cash provided byfinancing activities during the three months ended March 31, 2007 was$81.8 million, compared with $53.4 million for the correspondingperiod in 2006. The increase in financing activities is primarily attributableto net issuances of commercial paper. During the first quarter of 2007 we had$139.4 million of net commercial paper issuances, which include gross issuancesof $1,136.3 million and gross repayments of $996.9 million. Additionally, wemade $57.6 million in cash distributions to our partners during the threemonths ended March 31, 2007. On January 26, 2007, the board ofdirectors of Enbridge Management declared a distribution payable to ourpartners on February 14, 2007. Our cash distributions to our partners wereapproximately $1 million more for the first quarter of 2007 compared to thefirst quarter of 2006 due to higher incentive distribution payments to ourgeneral partner as a result of a greater number of units outstanding.

**OFF-BALANCESHEET ARRANGEMENTS**

We have no significant off-balancesheet arrangements.

**SUBSEQUENT EVENTS**

*Distribution toPartners*

On April 26, 2007,the Board of Directors of Enbridge Management declared a distribution payableto our partners on May 15, 2007. The distribution will be paid tounitholders of record as of May 7, 2007, of our available cash of $86.6million at March 31, 2007, or $0.925 per common unit. Of thisdistribution, $58.2 million will be paid in cash, $11.9 million will bedistributed in i-units to our i-unitholder, $15.9 million will bedistributed in Class C units to the holders of our Class C units and$0.6 million will be retained from the General Partner in respect of the i-unitand Class C unit distributions.

**REGULATORY MATTERS**

***FERC Transportation Tariffs-***Liquids

Effective April 1,2007, we filed our annual tariff with the FERC for our Lakehead system SEP IIexpansion. This tariff reflected the annual calculation of the SEP II andother surcharges based on true-ups of prior year amounts and estimates for2007, and an adjustment for the Terrace surcharge as a result of lower thanexpected volumes moving on the Lakehead system in 2006. This filing increasedthe tariff for heavy crude oil movements from the Canadian border to Chicago, Illinois,by approximately $0.007 per barrel, to approximately $0.926 per barrel.

**RECENT ACCOUNTINGPRONOUNCEMENTS NOT YET ADOPTED**

In February 2007, theFinancial Accounting Standards Board (FASB) issued Statement No. 159, *The Fair Value Option for Financial Assets and Liabilities.*Thisstatement provides companies with an option to report certain financialassets  and liabilities at fair value. Theobjective of SFAS No. 159 is to reduce complexity in accounting forfinancial instruments and the volatility in earnings caused by measuring 

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relatedfinancial assets and liabilities. SFAS No. 159 also establishespresentation and disclosure requirements designed to facilitate comparisonsbetween companies that choose different measurement attributes for similar typesof assets and liabilities. The provisions of SFAS No. 159 are effective atthe beginning of our first fiscal year that begins after November 15, 2007.We have elected not to early adopt the provisions of SFAS No. 159,although early adoption is permitted as of the beginning of a fiscal year thatbegins on or before November 15, 2007, provided the entity also elects toapply the provisions of SFAS No. 157. We do not expect our adoption ofSFAS No. 159 to have a material affect on our Consolidated Statements ofFinancial Position.

**Item 3.**                        Quantitativeand Qualitative Disclosures About Market Risk

This information updates, and you should read it inconjunction with, our quantitative and qualitative disclosures about marketrisks reported in our Annual Report on Form 10-K for the year ended December 31,2006, in addition to information presented in Items 1 and 2 of this QuarterlyReport on Form 10-Q.

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 or forecasted transaction and are not entered intowith the objective of speculating on commodity prices.

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Thefollowing tables provide information about our derivative financial instrumentsat March 31, 2007 and December 31, 2006, with respect to ourcommodity price risk management activities for natural gas and NGLs, includingcondensate:

|                                     | ** **   | **At March 31, 2007** | ** **   | **At December 31,   2006** | ** ** |
|-------------------------------------|--------------|--------------------------------------|--------------|-------------------------------------------|------------|
| ** **                          | ** **   | ** **                           | ** **   | ** **                                | ** ** | **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 |                                      |       |   | 44,761,845 |   |   |   | $ | 7.62 |   |   | $ | 7.40 |   |   | $ | 25.0 |   |   |   | $ | (15.6 | ) |   |   | $ | 8.1 |   |   |   | $ | (86.7 | ) |   |
|                                |         |                                 | NGL          |                                      |       |   | 106,725 |   |   |   | 46.70 |   |   | 43.26 |   |   | 0.5 |   |   |   | (0.1 | ) |   |   | — |   |   |   | (0.5 | ) |   |
| Receive fixed/pay variable          |         |                                 | Natural  gas |                                      |       |   | 44,322,680 |   |   |   | 7.00 |   |   | 7.93 |   |   | 8.6 |   |   |   | (48.7 | ) |   |   | 79.8 |   |   |   | (33.0 | ) |   |
|                                |         |                                 | NGL          |                                      |       |   | 3,278,275 |   |   |   | 38.16 |   |   | 46.83 |   |   | 1.6 |   |   |   | (29.4 | ) |   |   | 14.4 |   |   |   | (23.2 | ) |   |
|                                     |         |                                 | Crude  oil   |                                      |       |   | 286,800 |   |   |   | 41.82 |   |   | 68.76 |   |   | — |   |   |   | (7.5 | ) |   |   | — |   |   |   | (8.6 | ) |   |
| Receive  variable/pay variable      |         |                                 | Natural  gas |                                      |       |   | 54,220,154 |   |   |   | 7.78 |   |   | 7.78 |   |   | 3.4 |   |   |   | (3.4 | ) |   |   | 3.1 |   |   |   | (3.7 | ) |   |
| *Options*                           | * *     |                                 | * *     | * *                                  |       |   | * * | * * |   |   | * * | * * |   | * * | * * |   | * * | * * |   |   | * * | * * |   |   | * * | * * |   |   | * * | * * |   |
| Calls (written)                     |         |                                 | Natural  gas |                                      |       |   | 275,000 |   |   |   | 8.23 |   |   | 4.31 |   |   | — |   |   |   | (1.1 | ) |   |   | — |   |   |   | (1.0 | ) |   |
| Puts                                |         |                                 | Natural  gas |                                      |       |   | 1,009,000 |   |   |   | 8.01 |   |   | 6.15 |   |   | 0.2 |   |   |   | — |   |   |   | 1.0 |   |   |   | — |   |   |
| ***Contracts maturing in 2008***    |         |                                 |         |                                      |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| *Swaps*                             |         |                                 |         |                                      |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Receive  variable/pay fixed         |         |                                 | Natural  gas |                                      |       |   | 18,633,796 |   |   |   | 8.33 |   |   | 7.41 |   |   | 18.4 |   |   |   | (2.1 | ) |   |   | 9.5 |   |   |   | (5.1 | ) |   |
| Receive fixed/pay variable          |         |                                 | Natural  gas |                                      |       |   | 24,958,326 |   |   |   | 6.33 |   |   | 8.79 |   |   | 1.1 |   |   |   | (58.9 | ) |   |   | 3.6 |   |   |   | (44.1 | ) |   |
|                                |         |                                 | NGL          |                                      |       |   | 2,046,819 |   |   |   | 39.69 |   |   | 47.87 |   |   | — |   |   |   | (15.7 | ) |   |   | 2.5 |   |   |   | (7.7 | ) |   |
|                                     |         |                                 | Crude  oil   |                                      |       |   | 337,241 |   |   |   | 45.16 |   |   | 69.96 |   |   | — |   |   |   | (7.8 | ) |   |   | — |   |   |   | (7.0 | ) |   |
| Receive  variable/pay variable      |         |                                 | Natural  gas |                                      |       |   | 21,618,803 |   |   |   | 9.04 |   |   | 8.96 |   |   | 2.5 |   |   |   | (0.8 | ) |   |   | 2.5 |   |   |   | (0.4 | ) |   |
| *Options*                           | * *     |                                 | * *     | * *                                  |       |   | * * | * * |   |   | * * |   |   |   | * * |   | * * | * * |   |   | * * | * * |   |   | * * | * * |   |   | * * | * * |   |
| Calls (written)                     |         |                                 | Natural  gas |                                      |       |   | 366,000 |   |   |   | 8.70 |   |   | 4.31 |   |   | — |   |   |   | (1.5 | ) |   |   | — |   |   |   | (1.3 | ) |   |
| Puts                                |         |                                 | Natural  gas |                                      |       |   | 366,000 |   |   |   | 8.70 |   |   | 3.40 |   |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   |
| ***Contracts maturing in 2009***    |         |                                 |         |                                      |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| *Swaps*                             |         |                                 |         |                                      |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Receive  variable/pay fixed         |         |                                 | Natural  gas |                                      |       |   | 6,524,450 |   |   |   | 7.96 |   |   | 7.39 |   |   | 4.6 |   |   |   | (1.2 | ) |   |   | 2.9 |   |   |   | (2.1 | ) |   |
| Receive fixed/pay variable          |         |                                 | Natural  gas |                                      |       |   | 12,865,240 |   |   |   | 5.15 |   |   | 8.36 |   |   | 0.2 |   |   |   | (37.3 | ) |   |   | 0.7 |   |   |   | (31.5 | ) |   |
|                                |         |                                 | NGL          |                                      |       |   | 1,909,315 |   |   |   | 42.46 |   |   | 46.85 |   |   | — |   |   |   | (7.5 | ) |   |   | 1.4 |   |   |   | (1.4 | ) |   |
|                                     |         |                                 | Crude  oil   |                                      |       |   | 264,625 |   |   |   | 59.09 |   |   | 68.87 |   |   | — |   |   |   | (2.3 | ) |   |   | — |   |   |   | (1.9 | ) |   |
| Receive  variable/pay variable      |         |                                 | Natural  gas |                                      |       |   | 17,602,611 |   |   |   | 8.61 |   |   | 8.58 |   |   | 1.4 |   |   |   | (0.9 | ) |   |   | 1.4 |   |   |   | (0.6 | ) |   |
| *Options*                           | * *     |                                 | * *     | * *                                  |       |   | * * | * * |   |   | * * | * * |   | * * | * * |   | * * | * * |   |   | * * | * * |   |   | * * | * * |   |   | * * | * * |   |
| Calls (written)                     |         |                                 | Natural  gas |                                      |       |   | 365,000 |   |   |   | 8.33 |   |   | 4.31 |   |   | — |   |   |   | (1.3 | ) |   |   | — |   |   |   | (1.2 | ) |   |
| Puts                                |         |                                 | Natural  gas |                                      |       |   | 365,000 |   |   |   | 8.33 |   |   | 3.40 |   |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   |
| ***Contracts maturing in 2010***    |         |                                 |         |                                      |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| *Swaps*                             |         |                                 |         |                                      |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Receive  variable/pay fixed         |         |                                 | Natural  gas |                                      |       |   | 2,220,125 |   |   |   | 7.76 |   |   | 6.09 |   |   | 3.3 |   |   |   | (0.1 | ) |   |   | 2.5 |   |   |   | (0.3 | ) |   |
| Receive fixed/pay variable          |         |                                 | Natural  gas |                                      |       |   | 9,490,000 |   |   |   | 4.11 |   |   | 7.93 |   |   | — |   |   |   | (31.0 | ) |   |   | 0.2 |   |   |   | (26.1 | ) |   |
|                                |         |                                 | NGL          |                                      |       |   | 766,500 |   |   |   | 33.83 |   |   | 39.28 |   |   | — |   |   |   | (3.5 | ) |   |   | — |   |   |   | (1.5 | ) |   |
|                                     |         |                                 | Crude  oil   |                                      |       |   | 213,525 |   |   |   | 63.00 |   |   | 67.35 |   |   | — |   |   |   | (0.8 | ) |   |   | — |   |   |   | (0.6 | ) |   |
| Receive variable/pay  variable      |         |                                 | Natural  gas |                                      |       |   | 7,200,000 |   |   |   | 8.77 |   |   | 8.68 |   |   | 0.9 |   |   |   | (0.3 | ) |   |   | 0.8 |   |   |   | (0.1 | ) |   |
| *Options*                           | * *     |                                 | * *     | * *                                  |       |   | * * | * * |   |   | * * | * * |   | * * | * * |   | * * | * * |   |   | * * | * * |   |   | * * | * * |   |   | * * | * * |   |
| Calls (written)                     |         |                                 | Natural  gas |                                      |       |   | 365,000 |   |   |   | 7.98 |   |   | 4.31 |   |   | — |   |   |   | (1.2 | ) |   |   | — |   |   |   | (1.0 | ) |   |
| Puts                                |         |                                 | Natural  gas |                                      |       |   | 365,000 |   |   |   | 7.98 |   |   | 3.40 |   |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   |
| ***Contracts maturing in 2011***    |         |                                 |         |                                      |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| *Swaps*                             |         |                                 |         |                                      |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Receive  variable/pay fixed         |         |                                 | Natural  gas |                                      |       |   | 730,000 |   |   |   | 7.71 |   |   | 3.57 |   |   | 2.5 |   |   |   | — |   |   |   | 2.0 |   |   |   | — |   |   |
| Receive fixed/pay variable          |         |                                 | Natural  gas |                                      |       |   | 7,952,500 |   |   |   | 3.63 |   |   | 7.71 |   |   | — |   |   |   | (26.4 | ) |   |   | — |   |   |   | (21.5 | ) |   |
|                                |         |                                 | NGL          |                                      |       |   | 230,315 |   |   |   | 31.70 |   |   | 37.51 |   |   | — |   |   |   | (1.1 | ) |   |   | — |   |   |   | (0.6 | ) |   |
|                                     |         |                                 | Crude  oil   |                                      |       |   | 182,500 |   |   |   | 64.30 |   |   | 66.45 |   |   | — |   |   |   | (0.3 | ) |   |   | — |   |   |   | (0.2 | ) |   |
| *Options*                           | * *     |                                 | * *     | * *                                  |       |   | * * | * * |   |   | * * | * * |   | * * | * * |   | * * | * * |   |   | * * | * * |   |   | * * | * * |   |   | * * | * * |   |
| Calls (written)                     |         |                                 | Natural  gas |                                      |       |   | 365,000 |   |   |   | 7.71 |   |   | 4.31 |   |   | — |   |   |   | (1.1 | ) |   |   | — |   |   |   | (0.9 | ) |   |
| Puts                                |         |                                 | Natural  gas |                                      |       |   | 365,000 |   |   |   | 7.71 |   |   | 3.40 |   |   | — |   |   |   | — |   |   |   | — |   |   |   | — |   |   |
| ***Contracts maturing after 2011*** |         |                                 |         |                                      |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| *Swaps*                             |         |                                 |         |                                      |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Receive variable/pay fixed          |         |                                 | Natural  gas |                                      |       |   | 182,000 |   |   |   | 8.40 |   |   | 3.57 |   |   | 0.7 |   |   |   | — |   |   |   | 0.6 |   |   |   | — |   |   |
| Receive fixed/pay  variable         |         |                                 | Natural gas  |                                      |       |   | 1,456,000 |   |   |   | 3.57 |   |   | 8.40 |   |   | — |   |   |   | (5.5 | ) |   |   | — |   |   |   | (4.5 | ) |   |
|                                     |              |                                      |              |                                           |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

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

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

(3)                 The fair value is determined based onquoted market prices at March 31, 2007 and December 31, 2006,respectively, discounted using the swap rate for the respective periods toconsider the time value of money. Fair values are presented in millions ofdollars.

***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 period inwhich the hedged transaction occurs. Gains and losses deferred in AOCI relatedto cash flow hedges, for which hedge accounting has been discontinued, remainin AOCI 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. 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 

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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.” Non-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 derivative financial instrument contractsettlement 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 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 had previouslyentered into natural gas collars to hedge the sales price of natural gas. Thenatural gas collars were based on a NYMEX price, while the physical gas saleswere based on a different index. To better align the index of the natural gascollars with the index of the underlying sales, we de-designated theoriginal cash flow hedging relationship with the intent of contemporaneously re-designatingthe natural gas collars as hedges of forecasted physical natural gas sales witha NYMEX pricing index. However, because the fair value of these derivativefinancial instruments was a liability to us at 

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re-designation, theyare considered net written options under SFAS No. 133 and do not qualifyfor 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 instances described above, theunderlying physical purchase, storage and sale of natural gas and NGLs areaccounted for on a historical cost or market basis rather than on themark-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.

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:

|                                                              | ** ** | **Three months ended  March 31,** | ** ** |
|--------------------------------------------------------------|------------|--------------------------------------------------|------------|
| **Derivative fair value gains (losses)** | ** ** | ** **                                       | ** ** | **2007** | ** ** | **2006** | ** ** |
| ** **                                                   | ** ** | **(in millions)**                           | ** ** |
| Natural Gas segment                                          |       |                                             |       |   |   |
| Hedge  ineffectiveness                                       |       | $                                                | 0.1        |   | $ | — |   |
| Non-qualified hedges                                         |       | (3.2                                             | )          | 1.8 |   |
| Marketing                                                    |       |                                             |       |   |   |
| Non-qualified hedges                                         |       | (13.2                                            | )          | 25.9 |   |
| Derivative fair value gains (losses)                         |       | $                                                | (16.3      | ) | $ | 27.7 |   |
|                                                              |            |                                                  |            |  |  |  |  |  |  |

 

***Derivative Positions***

Our derivative financialinstruments are included at their fair values in the Consolidated Statements ofFinancial Position as follows:

|                             | ** ** | **March 31,  2007** | ** ** | **December 31,  2006** | ** ** |
|-----------------------------|------------|--------------------------|------------|-----------------------------|------------|
| ** **                  | ** ** | **(in millions)**   | ** ** |
| Other current assets        |       |                     | $          | 1.7                         |       |   |   | $ | 7.2 |   |   |
| Other assets, net           |       |                     | 10.6       |                        |       |   | 11.0 |   |   |
| Accounts payable and other  |       |                     | (88.1      | )                           |       |   | (57.2 | ) |   |
| Other long-term liabilities |       |                     | (160.3     | )                           |       |   | (136.4 | ) |   |
|                             |       |                     | $          | (236.1                      | )          |   |   | $ | (175.4 | ) |   |

 

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The increase in our obligation associated withderivative activities is primarily due to the increase in forward natural gasprices from December 31, 2006 to March 31, 2007. The Partnership’sportfolio of derivative financial instruments is largely comprised of long-termfixed price 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. Also included inAOCI are unrecognized losses of approximately $4.1 million associated withcash flow hedges that were subsequently de-designated. These unrealized lossesare reclassified to earnings over the periods during which the originallyhedged forecasted transactions affect earnings. For the three months endedMarch 31, 2007, we reclassified losses of $16.2 million from AOCI to Costof natural gas on our Consolidated Statements of Income for the fair value ofderivative financial instruments that were settled.

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 4.**                        Controlsand Procedures

The Partnership and Enbridge maintain systems ofdisclosure controls and procedures designed to provide reasonable assurancethat we are able to record, process, summarize and report the informationrequired in our annual and quarterly reports under the Securities Exchange Actof 1934. Our management has evaluated the effectiveness of our disclosurecontrols and procedures as of March 31, 2007. Based upon that evaluation,our principal executive officer and principal financial officer concluded thatour disclosure controls and procedures are effective to accomplish theirpurpose. In conducting this assessment, our management relied on similarevaluations conducted by employees of Enbridge affiliates who provide certaintreasury, accounting and other services on our behalf. No changes in ourinternal control over financial reporting were made during the three monthsended March 31, 2007, that would materially affect our internal controlover financial reporting, nor were any corrective actions with respect tosignificant deficiencies or material weaknesses necessary subsequent to thatdate.

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**PART II—OTHERINFORMATION**

**Item 1.**                        LegalProceedings

Refer to Part I,Item 1. Financial statements, Note 9, which is incorporated herein byreference.

**Item 1A.**                RiskFactors

There have been nomaterial changes to our risk factors as previously disclosed in Part I,Item 1A of our Annual Report on Form 10-K for the fiscal year ended December 31,2006.

**Item 6.**                        Exhibits

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

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**SIGNATURES**

Pursuantto the requirements of the Securities Exchange Act of 1934, the Registrant hasduly caused this report to be signed on its behalf by the undersigned thereuntoduly authorized.
|                            | ** ** | ** ** |     | **ENBRIDGE ENERGY PARTNERS,  L.P.**                                                                         |
|----------------------------|------------|------------|----------|-------------------------------------------------------------------------------------------------------------|
| ** **                 |       |       |     | (Registrant)                                                                                                |
|                       |       | By:        |     | Enbridge Energy  Management, L.L.C.  as delegate of  Enbridge Energy Company, Inc.  as General Partner |
| Date: April 30,  2007 |       | By:        |     | /s/ Stephen J.J. Letwin                                                                                     |
|                       |       |       |     | Stephen J. J. Letwin                                                                                        |
| * *                   | * *   | * *   | * * | *Managing Director*                                                                                         |
| * *                   | * *   | * *   | * * | *(Principal Executive Officer)*                                                                             |
| Date: April 30,  2007 |       | By:        |     | /s/ MARK A. MAKI                                                                                            |
| * *                   |       |       |     | Mark A. Maki                                                                                                |
| * *                   | * *   | * *   |     | *Vice President, Finance*                                                                                   |
| * *                   | * *   | * *   |     | *(Principal Financial Officer)*                                                                             |

 

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**Index of Exhibits**

Eachexhibit identified below is filed as part of this document. Exhibits notincorporated by reference to a prior filing are designated by an “*”; allexhibits not so designated are incorporated herein by reference to a previousfiling as indicated.

| 3.1   |   | Certificate of Limited Partnership of the  Partnership (incorporated by reference to Exhibit 3.1 to the  Partnership’s Registration Statement No. 33-43425).                                                                                                                                                                                    |
|-------|--------|----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 3.2   |   | Certificate of Amendment  to Certificate of Limited Partnership of the Partnership (incorporated by  reference to Exhibit 3.2 to 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 to the Partnership’s 2000 Form 10-K/A dated  October 9, 2001).                                                                                                                                                                 |
| 4.2   |   | Registration Rights  Agreement, dated April 2, 2007 by and among Enbridge Energy Partners,  L.P. Tortoise Energy Infrastructure Corporation, Tortoise Energy Capital  Corporation and CDP Infrastructures Fund G.P. (incorporated by reference to  Exhibit 4.1 of the Partnership’s Current Report on Form 8-K  dated April 2, 2007). |
| 10.1  |   | Second Amended and  Restated Credit Agreement dated as of April 4, 2007, 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 10.1of the Partnership’s Current Report on Form 8-K  dated April 10, 2007).         |
| 31.1* |   | Certification of  Principal Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley  Act of 2002.                                                                                                                                                                                                                                            |
| 31.2* |   | Certification of  Principal Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley  Act of 2002.                                                                                                                                                                                                                                            |
| 32.1* |   | Certification of  Principal Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley  Act of 2002.                                                                                                                                                                                                                                            |
| 32.2* |   | Certification of  Principal Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley  Act of 2002.                                                                                                                                                                                                                                            |

 

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