**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, 2006**

**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 Louisiana  Suite 3300  Houston, TX 77002**(Address of principal executive offices and zip code) |
|-------------------------------------------------------------------------------------------------------------|
| **(713) 821-2000**(Registrant’s telephone number, 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 12months (or for such shorter period that the registrant was required to filesuch reports), and (2) has been subject to such filing requirements forthe past 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-2 ofthe Exchange Act). Yes o  No x

The Registrant had49,938,834 Class A common units outstanding as of April 28, 2006.

 

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**TABLEOF CONTENTS**
| **PART I. FINANCIAL  INFORMATION** |
|-----------------------------------------|
| Item 1.                                 |   | Financial  Statements |   | 3 |   |
|                                    |   | Consolidated  Statements of Income for the three month periods ended March 31, 2006  and 2005 |   | 3 |   |
|                                    |   | Consolidated  Statements of Comprehensive Income for the three month periods ended  March 31, 2006 and 2005 |   | 4 |   |
|                                    |   | Consolidated  Statements of Cash Flows for the three month periods ended  March 31, 2006 and 2005 |   | 5 |   |
|                                    |   | Consolidated  Statements of Financial Position as of March 31, 2006 and  December 31, 2005 |   | 6 |   |
|                                    |   | Notes  to Consolidated Financial Statements |   | 7 | ** ** |
| Item 2.                                 |   | Management’s  Discussion and Analysis of Financial Condition and Results of Operations |   | 14 | ** ** |
| Item 3.                                 |   | Quantitative  and Qualitative Disclosures About Market Risk |   | 27 |   |
| Item 4.                                 |   | Controls  and Procedures |   | 31 |   |
| **PART II.  OTHER INFORMATION**    |
| Item 1.                                 |   | Legal  Proceedings |   | 32 |   |
| Item 1A.                                |   | Risk Factors |   | 32 |   |
| Item 6.                                 |   | Exhibits |   | 34 |   |
| **Signatures**                          |   | 35 |   |
| **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, 2005 and in Part II, Item 1A of ourquarterly reports on Form 10-Q.*

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**PART I—FINANCIALINFORMATION**

**Item 1.**                        FinancialStatements

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

| ** **                                                     | ** ** | **Three months ended  March 31,**                                | ** ** |
|----------------------------------------------------------------|------------|---------------------------------------------------------------------------------|------------|
| ** **                                                     | ** ** | **     2006     **            | ** ** | **     2005     ** | ** ** |
| ** **                                                     | ** ** | **(unaudited; in millions,  except per unit amounts)** | ** ** |
| Operating revenue                                              |       |                                                                            | $          | 1,888.6 |   |   |   | $ | 1,250.1 |   |   |
| Operating  expenses                                            |       |                                                                            |       |   |   |   |   |   |   |
| Cost of natural gas (Note 3 and 4)                             |       |                                                                            | 1,647.7    |   |   |   | 1,072.2 |   |   |
| Operating and administrative                                   |       |                                                                            | 73.9       |   |   |   | 74.4 |   |   |
| Power                                                          |       |                                                                            | 26.3       |   |   |   | 17.0 |   |   |
| Depreciation and amortization (Note 6)                         |       |                                                                            | 32.7       |   |   |   | 33.3 |   |   |
|                                                           |       |                                                                            | 1,780.6    |   |   |   | 1,196.9 |   |   |
| Operating income                                               |       |                                                                            | 108.0      |   |   |   | 53.2 |   |   |
| Interest expense                                               |       |                                                                            | (27.9      | ) |   |   | (25.6 | ) |   |
| Other income                                                   |       |                                                                            | 1.0        |   |   |   | 0.6 |   |   |
| Net income                                                     |       |                                                                            | $          | 81.1 |   |   |   | $ | 28.2 |   |   |
| Net income allocable to common and i-units                     |       |                                                                            | $          | 73.9 |   |   |   | $ | 22.2 |   |   |
| Net income per common and i-unit (basic and  diluted) (Note 2) |       |                                                                            | $          | 1.12 |   |   |   | $ | 0.37 |   |   |
| Weighted average  units outstanding                            |       |                                                                            | 65.7       |   |   |   | 60.6 |   |   |

 

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

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

| ** **                                 | ** ** | **Three months ended  March 31,**         | ** ** |
|--------------------------------------------|------------|----------------------------------------------------------|------------|
| ** **                                 | ** ** | **    2006    ** | ** ** | **    2005    ** | ** ** |
| ** **                                 | ** ** | **(unaudited; in millions)**                   | ** ** |
| Net income                                 |       |                                                     | $          | 81.1 |   |   |   | $ | 28.2 |   |   |
| Other comprehensive income (loss) (Note 4) |       |                                                     | 34.1       |   |   |   | (74.2 | ) |   |
| Comprehensive  income (loss)               |       |                                                     | $          | 115.2 |   |   |   | $ | (46.0 | ) |   |

 

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,**                     | ** ** |
|------------------------------------------------------------------------------------|------------|----------------------------------------------------------------------|------------|
| ** **                                                                         | ** ** | **     2006     ** | ** ** | **     2005     ** | ** ** |
| ** **                                                                         | ** ** | **(unaudited; in millions)**                               | ** ** |
| Cash provided by  operating activities                                             |       |                                                                 |       |   |   |   |   |   |   |
| Net income                                                                         |       |                                                                 | $          | 81.1 |   |   |   | $ | 28.2 |   |   |
| Adjustments to  reconcile net income to net cash provided by operating activities: |       |                                                                 |       |   |   |   |   |   |   |
| Depreciation and amortization (Note 6)                                             |       |                                                                 | 32.7       |   |   |   | 33.3 |   |   |
| Derivative fair value (gain) loss (Note 4)                                         |       |                                                                 | (27.7      | ) |   |   | 7.0 |   |   |
| Inventory market price adjustment (Note 3)                                         |       |                                                                 | 8.0        |   |   |   | — |   |   |
| Other                                                                              |       |                                                                 | (1.1       | ) |   |   | (0.3 | ) |   |
| Changes in  operating assets and liabilities, net of cash acquired:                |       |                                                                 |       |   |   |   |   |   |   |
| Receivables, trade and other                                                       |       |                                                                 | (15.7      | ) |   |   | (6.9 | ) |   |
| Due from General Partner and affiliates                                            |       |                                                                 | (1.3       | ) |   |   | 1.8 |   |   |
| Accrued receivables                                                                |       |                                                                 | 105.5      |   |   |   | 31.2 |   |   |
| Inventory                                                                          |       |                                                                 | 26.7       |   |   |   | 15.5 |   |   |
| Current and long-term other assets                                                 |       |                                                                 | (0.5       | ) |   |   | (0.7 | ) |   |
| Due to General Partner and affiliates                                              |       |                                                                 | 1.9        |   |   |   | (7.8 | ) |   |
| Accounts payable and other                                                         |       |                                                                 | (36.8      | ) |   |   | (15.0 | ) |   |
| Accrued purchases                                                                  |       |                                                                 | (101.7     | ) |   |   | (18.5 | ) |   |
| Interest payable                                                                   |       |                                                                 | 19.9       |   |   |   | 21.2 |   |   |
| Property and other taxes payable                                                   |       |                                                                 | 5.4        |   |   |   | 0.3 |   |   |
| Net cash provided by operating activities                                          |       |                                                                 | 96.4       |   |   |   | 89.3 |   |   |
| Cash used in  investing activities                                                 |       |                                                                 |       |   |   |   |   |   |   |
| Additions to property, plant and equipment                                         |       |                                                                 | (98.7      | ) |   |   | (72.9 | ) |   |
| Changes in construction payables                                                   |       |                                                                 | (6.8       | ) |   |   | (6.7 | ) |   |
| Asset acquisitions, net of cash acquired                                           |       |                                                                 | —     |   |   |   | (165.7 | ) |   |
| Other                                                                              |       |                                                                 | (0.3       | ) |   |   | (0.7 | ) |   |
| Net cash used in investing activities                                              |       |                                                                 | (105.8     | ) |   |   | (246.0 | ) |   |
| Cash provided by  financing activities                                             |       |                                                                 |       |   |   |   |   |   |   |
| Proceeds from unit issuances, net                                                  |       |                                                                 | —     |   |   |   | 127.5 |   |   |
| Distributions to partners (Note 8)                                                 |       |                                                                 | (56.6      | ) |   |   | (50.7 | ) |   |
| Borrowings under credit facilities, net                                            |       |                                                                 | —     |   |   |   | 70.0 |   |   |
| Net issuances of commercial paper                                                  |       |                                                                 | 110.0      |   |   |   | — |   |   |
| Other                                                                              |       |                                                                 | —     |   |   |   | 0.1 |   |   |
| Net cash provided by financing activities                                          |       |                                                                 | 53.4       |   |   |   | 146.9 |   |   |
| Net increase (decrease) in cash and cash equivalents                               |       |                                                                 | 44.0       |   |   |   | (9.8 | ) |   |
| Cash and cash equivalents at beginning of year                                     |       |                                                                 | 89.8       |   |   |   | 78.3 |   |   |
| Cash and cash  equivalents at end of period                                        |       |                                                                 | $          | 133.8 |   |   |   | $ | 68.5 |   |   |

 

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,  2006**               | ** ** | **December 31,  2005** | ** ** |
|--------------------------------------------------------------------------------------------------------|------------|----------------------------------------|------------|-----------------------------|------------|
| ** **                                                                                             | ** ** | **(unaudited; in millions)** | ** ** |
| ***ASSETS***                                                                                           |       |                                   |       |                        |       |   |   |   |   |
| Current assets                                                                                         |       |                                   |       |                        |       |   |   |   |   |
| Cash and cash equivalents (Note 5)                                                                     |       |                                   | $          | 133.8                       |       |   |   | $ | 89.8 |   |   |
| Receivables, trade and other, net of allowance for  doubtful accounts of $4.9 in 2006 and $4.5 in 2005 |       |                                   | 125.4      |                        |       |   | 109.7 |   |   |
| Due from General Partner and affiliates                                                                |       |                                   | 21.4       |                        |       |   | 20.1 |   |   |
| Accrued receivables                                                                                    |       |                                   | 509.8      |                        |       |   | 615.3 |   |   |
| Inventory (Note 3)                                                                                     |       |                                   | 104.2      |                        |       |   | 138.9 |   |   |
| Other current assets                                                                                   |       |                                   | 5.4        |                        |       |   | 11.5 |   |   |
|                                                                                                   |       |                                   | 900.0      |                        |       |   | 985.3 |   |   |
| Property, plant and equipment, net (Note 6)                                                            |       |                                   | 3,148.0    |                        |       |   | 3,080.0 |   |   |
| Other assets, net                                                                                      |       |                                   | 24.9       |                        |       |   | 22.2 |   |   |
| Goodwill                                                                                               |       |                                   | 258.2      |                        |       |   | 258.2 |   |   |
| Intangibles, net                                                                                       |       |                                   | 81.7       |                        |       |   | 82.7 |   |   |
|                                                                                                   |       |                                   | $          | 4,412.8                     |       |   |   | $ | 4,428.4 |   |   |
| ***LIABILITIES  AND PARTNERS’ CAPITAL***                                                          |       |                                   |       |                        |       |   |   |   |   |
| Current  liabilities                                                                                   |       |                                   |       |                        |       |   |   |   |   |
| Due to General Partner and affiliates                                                                  |       |                                   | $          | 14.4                        |       |   |   | $ | 12.5 |   |   |
| Accounts payable and other (Note 5)                                                                    |       |                                   | 164.9      |                        |       |   | 247.9 |   |   |
| Accrued purchases                                                                                      |       |                                   | 545.0      |                        |       |   | 646.7 |   |   |
| Interest payable                                                                                       |       |                                   | 28.8       |                        |       |   | 11.4 |   |   |
| Property and other taxes payable                                                                       |       |                                   | 27.2       |                        |       |   | 21.8 |   |   |
| Current maturities of long-term debt                                                                   |       |                                   | 31.0       |                        |       |   | 31.0 |   |   |
|                                                                                                   |       |                                   | 811.3      |                        |       |   | 971.3 |   |   |
| Long-term debt (Note 7)                                                                                |       |                                   | 1,792.5    |                        |       |   | 1,682.9 |   |   |
| Loans from  General Partner and affiliates                                                             |       |                                   | 154.3      |                        |       |   | 151.8 |   |   |
| Environmental  liabilities (Note 9)                                                                    |       |                                   | 5.2        |                        |       |   | 4.8 |   |   |
| Other long-term  liabilities (Note 4)                                                                  |       |                                   | 227.3      |                        |       |   | 253.8 |   |   |
|                                                                                                   |       |                                   | 2,990.6    |                        |       |   | 3,064.6 |   |   |
| Commitments and  contingencies (Note 9)                                                                |       |                                   |       |                        |       |   |   |   |   |
| Partners’ capital  (Note 8)                                                                       |       |                                   |       |                        |       |   |   |   |   |
| Class A common units (Units issued—49,938,834 in  2006 and 2005)                                  |       |                                   | 1,152.2    |                        |       |   | 1,142.4 |   |   |
| Class B common units (Units issued—3,912,750 in 2006  and 2005)                                   |       |                                   | 68.1       |                        |       |   | 67.2 |   |   |
| i-units (Units issued—11,933,019 in 2006 and  11,704,948 in 2005)                                 |       |                                   | 434.8      |                        |       |   | 421.7 |   |   |
| General Partner                                                                                        |       |                                   | 35.1       |                        |       |   | 34.6 |   |   |
| Accumulated other comprehensive loss (Note 4)                                                          |       |                                   | (268.0     | )                           |       |   | (302.1 | ) |   |
|                                                                                                   |       |                                   | 1,422.2    |                        |       |   | 1,363.8 |   |   |
|                                                                                                   |       |                                   | $          | 4,412.8                     |       |   |   | $ | 4,428.4 |   |   |

 

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

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**NOTESTO 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 to Form 10-Qand Rule 10-01 of Regulation S-X. Accordingly, they donot include all the information and footnotes required by accounting principlesgenerally accepted in the United States of America for complete consolidatedfinancial statements. In the opinion of management, they contain alladjustments, consisting only of normal recurring adjustments, which managementconsiders necessary to present fairly the financial position as of March 31,2006 and December 31, 2005, the results of operations and cash flows forthe three month periods ended March 31, 2006 and 2005. The results ofoperations for the three month period ended March 31, 2006, should not betaken as indicative of the results to be expected for the full year due toseasonality of portions of the natural gas business, maintenance activities andthe impact of forward natural gas prices and differentials on certainderivative financial instruments that are accounted for using mark-to-marketaccounting. In addition, prior period information presented in theseconsolidated financial statements includes reclassifications that were made toconform to the current period presentation. These reclassifications have noeffect on previously reported net income or partners’ capital. The interimconsolidated financial statements should be read in conjunction with ourconsolidated financial statements and notes presented in our Annual Report on Form 10-Kfor the fiscal year ended December 31, 2005.

**2.**   NETINCOME PER COMMON AND i-UNIT

Netincome per common and i-unit is computed by dividing net income, afterdeduction of Enbridge Energy Company, Inc.’s (the “General Partner”)allocation, by the weighted average number of Class A and Class Bcommon units and i-units outstanding. The General Partner’s allocation isequal to an amount based upon its general partner interest, adjusted to reflectan amount equal to its incentive distributions and an amount required toreflect depreciation on the General Partner’s historical cost basis for assetscontributed on formation of the Partnership. We have no dilutive securities.Net income per common and i-unit was determined as follows:

| ** **                                            | ** ** | **Three months ended  March 31,**                                                                                             | ** ** |
|-------------------------------------------------------|------------|----------------------------------------------------------------------------------------------------------------------------------------------|------------|
| ** **                                            | ** ** | **           2006           ** | ** ** | **           2005           ** | ** ** |
| ** **                                            | ** ** | **(in millions, except per unit amounts)**                                                                          | ** ** |
| Net income                                            |       |                                                                                                                                         | $          | 81.1 |   |   |   | $ | 28.2 |   |   |
| Allocations to  the General Partner:                  |       |                                                                                                                                         |       |   |   |   |   |   |   |
| Net income allocated to General Partner               |       |                                                                                                                                         | (1.6       | ) |   |   | (0.6 | ) |   |
| Incentive distributions to General Partner            |       |                                                                                                                                         | (5.6       | ) |   |   | (5.3 | ) |   |
| Historical cost depreciation adjustments              |       |                                                                                                                                         | —     |   |   |   | (0.1 | ) |   |
|                                                  |       |                                                                                                                                         | (7.2       | ) |   |   | (6.0 | ) |   |
| Net income  allocable to common and i-units           |       |                                                                                                                                         | $          | 73.9 |   |   |   | $ | 22.2 |   |   |
| Weighted average units outstanding                    |       |                                                                                                                                         | 65.7       |   |   |   | 60.6 |   |   |
| Net income per  common and i-unit (basic and diluted) |       |                                                                                                                                         | $          | 1.12 |   |   |   | $ | 0.37 |   |   |

 

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**3.   INVENTORY**

Inventoryis comprised of the following:

| ** **                     | ** ** | **March 31,  2006**            | ** ** | **December 31,  2005** | ** ** |
|--------------------------------|------------|-------------------------------------|------------|-----------------------------|------------|
| ** **                     | ** ** | **(dollars in millions)** | ** ** |
| Material and  supplies         |       |                                | $          | 8.4                         |       |   |   | $ | 8.3 |   |   |
| Liquids inventory              |       |                                | 8.8        |                        |       |   | 11.1 |   |   |
| Natural gas and  NGL inventory |       |                                | 87.0       |                        |       |   | 119.5 |   |   |
|                           |       |                                | $          | 104.2                       |       |   |   | $ | 138.9 |   |   |

 

We recorded an $8.0million reduction to the cost basis of our natural gas inventory to reflect themarket value at March 31, 2006, which is included in the Cost of naturalgas in our Marketing segment on our Consolidated Statement of Income. 

**4.**   FINANCIALINSTRUMENTS—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 offsetting natural gas purchases). Thismarket price exposure exists within our Natural Gas and Marketing segments. Tomitigate the volatility of our cash flows, we use derivative financialinstruments (i.e., futures, forwards, swaps, options and other financialinstruments with similar characteristics) to manage the purchase and salesprices of the commodities. Based on our risk management policies, all of ourderivative financial instruments are employed in connection with an underlyingasset, liability and/or anticipated transaction and are not entered into withthe objective of speculating on commodity prices.

***Accounting Treatment***

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

Under the guidance of Statement of FinancialAccounting Standards No. 133, *Accountingfor Derivative Transactions and Hedging Activities* (“SFAS No. 133”),if a derivative financial instrument does not qualify as a hedge or is notdesignated as a hedge, a change in the fair market value, both realized andunrealized, is recognized currently in our income statement as a derivativefair value gain (loss) and recorded in Cost of natural gas. Cash flow is onlyimpacted to the extent the actual derivative contract is settled by making orreceiving a payment to or from the counterparty or by making or receiving apayment for entering into a contract that exactly offsets the originalderivative contract. Typically, a derivative contract is settled when thefuture physical transaction that underlies the derivative financial instrumentoccurs.

If a derivative financialinstrument is designated as a cash flow hedge and qualifies for hedgeaccounting, any unrealized gain or loss is deferred in Accumulated othercomprehensive income (“OCI”), a component of Partners’ Capital, until the underlyinghedged transaction occurs. Any ineffective portion of a cash flow hedge’schange 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 inthe period the hedged transaction occurs. Gains and losses deferred in OCIrelated to cash flow hedges for which hedge accounting has been discontinued, 

8

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remainin OCI 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. Our preference, whenever possible, is for our derivative financialinstruments to receive hedge accounting treatment to mitigate the non-cashearnings volatility that arises under mark-to-market accountingtreatment. To qualify for cash flow hedge accounting, very specificrequirements must be met in terms of hedge structure, hedge objective and hedgedocumentation.

***Non-Qualified Hedges***

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

The three instances of non-qualified hedges are asfollows:

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

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

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

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In each of the three instances described above, theunderlying physical purchase, storage and sale of natural gas and NGLs areaccounted for on a historical cost basis rather than on the mark-to-marketbasis we utilize for the derivatives used to mitigate the commodity price riskassociated with our storage and transportation assets. This difference inaccounting (i.e., the financial sideof the transaction is recorded at fair market values while the physical side ofthe transaction is not) can and has resulted in volatility in ourreported net income, even though the economic margin is essentially unchangedfrom the date the transactions were consummated.

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)** | ** ** | ** **                                       | ** ** | **2006** | ** ** | **2005** | ** ** |
| ** **                                                   | ** ** | **(in millions)**                           | ** ** |
| Natural Gas  segment                                         |       |                                             |       |   |   |
| Ineffectiveness                                              |       | $                                                | —     |   | $ | (0.2 | ) |
| Non-qualified hedges                                         |       | 1.8                                              |       | (8.2 | ) |
| Marketing                                                    |       |                                             |       |   |   |
| Non-qualified hedges                                         |       | 25.9                                             |       | 1.4 |   |
| Derivative fair value  gains (losses)                        |       | $                                                | 27.7       |   | $ | (7.0 | ) |
|                                                              |            |                                                  |            |  |  |  |  |  |  |

 

We record the change in fair value of our highlyeffective cash flow hedges in OCI until the derivative financial instrumentsare settled, at which time they are reclassified to earnings. Also included inOCI are unrecognized losses of approximately $7.1 million associated withderivative financial instruments that qualified for and were classified as cashflow hedges of forecasted transactions that were subsequently de-designated.These unrecognized losses are reclassified to earnings over the periods duringwhich the originally hedged forecasted transactions affect earnings. For thethree months ended March 31, 2006, we reclassified unrealized losses of$24.8 million from OCI to Cost of natural gas on our Consolidated Statements ofIncome for the fair value of derivative financial instruments that were settled.

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

| ** **                   | ** ** | **March 31,  2006** | ** ** | **December 31,  2005** | ** ** |
|------------------------------|------------|--------------------------|------------|-----------------------------|------------|
| ** **                   | ** ** | **(in millions)**   | ** ** |
| Other current  assets        |       |                     | $          | 0.8                         |       |   |   | $ | 5.8 |   |   |
| Other assets, net            |       |                     | 6.4        |                        |       |   | 4.2 |   |   |
| Accounts payable  and other  |       |                     | (87.9      | )                           |       |   | (129.2 | ) |   |
| Other long-term  liabilities |       |                     | (217.4     | )                           |       |   | (243.0 | ) |   |
|                         |       |                     | $          | (298.1                      | )          |   |   | $ | (362.2 | ) |   |

 

The decrease in our obligation associated with derivativeactivities from December 31, 2005 to March 31, 2006 is primarily dueto the significant decreases in current and forward natural gas prices. ThePartnership’s portfolio of derivative financial instruments is largelycomprised of long-term fixed price sales and purchase agreements.

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

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**5.**   CASH AND CASHEQUIVALENTS

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$27.2 million at March 31, 2006 and $46.5 million at December 31,2005, are included in Accounts payable and other on the Consolidated Statementsof Financial Position.

**6.**   PROPERTY, PLANTAND EQUIPMENT

Based on a third-partystudy commissioned by management, revised depreciation rates for the Lakeheadsystem were implemented effective January 1, 2006. The annual compositerate, which represents the expected remaining service life of the pipelinesystem, was reduced from 3.20% to 2.63%. Depreciation expense for the threemonths ended March 31, 2006 was approximately $2.5 million lower as aresult of the new depreciation rates.

**7.**   DEBT

***Credit Facility***

In March 2006, weobtained an increase from $800 million to $1 billion in the aggregatecommitment available to us under the terms of our Credit Facility. At March 31,2006 and December 31, 2005, we had no amounts outstanding under our CreditFacility and had letters of credit totaling $107.4 million and$149.3 million, respectively. The amounts we may borrow under the terms ofour Credit Facility are reduced by the principal amount of our commercial paperissuances and the balance of our letters of credit outstanding. At March 31,2006, we could borrow $452.6 million under the terms of our Credit Facilitywithout consideration to additional borrowings under our commercial paperprogram.

During the three monthsended March 31, 2005, we net settled borrowings of approximately $360 million,on a non-cash basis.

***Commercial PaperProgram***

Under the terms of ourcommercial paper program, we can issue up to $600 million of commercial paper.However, the amount of commercial paper we may issue is reduced by any balanceof outstanding letters of credit in excess of $400 million. At March 31,2006, we had outstanding $438.9 million of commercial paper, net of unamortizeddiscount of $1.1 million, bearing interest at a weighted average rate of 4.82%.At December 31, 2005, we had $329.3 million of commercial paperoutstanding, net of $0.7 million of unamortized discount, at a weightedaverage interest rate of 4.36%. At March 31, 2006, we could issue anadditional $160 million in principal amount under our commercial 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, 2006:

| **Distribution  Declaration  Date** | ** ** | **Distribution  Payment Date** | ** ** | **Record  Date**      | ** ** | **Distribution  per Unit** | ** ** | **Cash  available for  distribution**                          | ** ** | **Amount of  Distribution  of i-units  to i-unit  Holders**(1) | ** ** | **Retained  from  General  Partner**(2) | ** ** | **Distribution  of Cash** | ** ** |
|-------------------------------------|------------|-------------------------------------|------------|-----------------------|------------|---------------------------------|------------|---------------------------------------------------------------------|------------|-------------------------------------------------------------------------------|------------|-----------------------------------------|------------|--------------------------------|------------|
| ** **                          | ** ** | ** **                          | ** ** | ** **            | ** ** | ** **                      | ** ** | **(in millions, except per unit amounts)** | ** ** |
| January 30, 2006               |       | February 14, 2006              |       | February 7, 2006 |       |                            | $          | 0.925                                                               |       |                                                                          |       | $                                       | 67.6       |                           |       |   | $ | 10.8 |   |   |   | $ | 0.2 |   |   |   | $ | 56.6 |   |   |
|                                     |            |                                     |            |                       |            |                                 |            |                                                                     |            |                                                                               |            |                                         |            |                                |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

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(1)                    The Partnership has issued 228,071 i-units toEnbridge Management, the sole owner of the Partnership’s i-units, during2006 in lieu of cash distributions.

(2)                    The Partnership retains an amount equal to2% of the i-unit distribution from the General Partner in respect of its2% general partner interest.

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**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 and natural gas pipeline operations and we could, attimes, be subject to environmental cleanup and enforcement actions. We managethis environmental risk through appropriate environmental policies andpractices to minimize any impact on the environment of our pipeline operations.

As of March 31, 2006 and December 31, 2005,we have recorded $3.5 million and $4.0 million, respectively, incurrent liabilities and $5.2 million and $4.8 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 April 2006, anatural gas release and fire near a valve site on our Midla natural gastransmission pipeline in Concordia Parish, Louisiana, resulted in property andequipment damage in the area. We estimate our losses from this incident toapproximate $1 million, which we will recognize in the second quarter of 2006. 

***Legal Proceedings***

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

**10.**   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 relating to our businesssegments:

| ** **                                          | ** ** | **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 (Note 4)                       |       |                                                                                                      | —     |   |   |   | 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                                          |       |                                                                                                      | $          | 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 |   |

 

| ** **                                          | ** ** | **As of and for the three months ended March 31, 2005** | ** ** |
|-----------------------------------------------------|------------|-----------------------------------------------------------------------------------------------------------|------------|
| ** **                                          | ** ** | **Liquids**                                                                                               | ** ** | **Natural Gas** | ** ** | **Marketing** | ** ** | **Corporate**(1) | ** ** | **Total** | ** ** |
| ** **                                          | ** ** | **(in millions)**                                                                                    | ** ** |
| Total revenue                                       |       | $                                                                                                         | 96.5       |   |   | $ | 924.6 |   |   |   | $ | 693.8 |   |   |   | $ | — |   |   | $ | 1,714.9 |   |
| Less:  Intersegment revenue                         |       | —                                                                                                    |       |   | 439.0 |   |   |   | 25.8 |   |   |   | — |   |   | 464.8 |   |
| Operating revenue                                   |       | 96.5                                                                                                      |       |   | 485.6 |   |   |   | 668.0 |   |   |   | — |   |   | 1,250.1 |   |
| Cost of natural  gas (Note 4)                       |       | —                                                                                                    |       |   | 406.5 |   |   |   | 665.7 |   |   |   | — |   |   | 1,072.2 |   |
| Operating and  administrative                       |       | 31.9                                                                                                      |       |   | 41.1 |   |   |   | 0.8 |   |   |   | 0.6 |   |   | 74.4 |   |
| Power                                               |       | 17.0                                                                                                      |       |   | — |   |   |   | — |   |   |   | — |   |   | 17.0 |   |
| Depreciation and  amortization                      |       | 17.6                                                                                                      |       |   | 15.6 |   |   |   | 0.1 |   |   |   | — |   |   | 33.3 |   |
| Operating income                                    |       | 30.0                                                                                                      |       |   | 22.4 |   |   |   | 1.4 |   |   |   | (0.6 | ) |   | 53.2 |   |
| Interest expense                                    |       | —                                                                                                    |       |   | — |   |   |   | — |   |   |   | (25.6 | ) |   | (25.6 | ) |
| Other income                                        |       | —                                                                                                    |       |   | — |   |   |   | — |   |   |   | 0.6 |   |   | 0.6 |   |
| Net income                                          |       | $                                                                                                         | 30.0       |   |   | $ | 22.4 |   |   |   | $ | 1.4 |   |   |   | $ | (25.6 | ) |   | $ | 28.2 |   |
| Total assets                                        |       | $                                                                                                         | 1,654.5    |   |   | $ | 1,908.0 |   |   |   | $ | 279.0 |   |   |   | $ | 80.5 |   |   | $ | 3,922.0 |   |
| Capital  expenditures (excluding acquisitions) |       | $                                                                                                         | 13.1       |   |   | $ | 58.7 |   |   |   | $ | — |   |   |   | $ | 1.1 |   |   | $ | 72.9 |   |

 

**11.**   SUBSEQUENTEVENT

***Distribution to Partners***

On April 27, 2006, the Board of Directors ofEnbridge Management declared a distribution payable to our partners on May 15,2006. The distribution will be paid to unitholders of record as of May 5, 2006,of our available cash of $67.9 million at March 31, 2006, or $0.925per common unit. Of this distribution, $56.7 million will be paid in cash,$11.0 million will be distributed in i-units to our i-unitholderand $0.2 million will be retained from the General Partner in respect ofthis i-unit distribution.

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**Item2.**                        Management’sDiscussion and Analysis of Financial Condition and Results of Operations

**RESULTS OF OPERATIONS—OVERVIEW**

Weprovide services to our customers and returns for our unitholders primarilythrough 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, transmission and sales services, including purchasing and sellingnatural gas and NGLs.

We conduct our businessthrough three business segments: Liquids, Natural Gas and Marketing. Thesesegments are strategic business units established by senior management tofacilitate the achievement of our long-term objectives, to aid inresource allocation decisions and to assess operational performance.

We primarily provide fee-basedservices to our customers to minimize 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 thePartnership’s cash flow, we enter into derivative financial instrumenttransactions. Certain of these transactions qualify for hedge accounting underStatement of Financial Accounting Standards No. 133, *Accounting for Derivative Transactions and HedgingActivities* (“SFAS No. 133”); some however, must beaccounted for using the mark-to-market method of accounting andthis can expose our earnings to significant volatility.

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

| ** **                               | ** ** | **    2006    ** | ** ** | **    2005    ** | ** ** |
|------------------------------------------|------------|----------------------------------------------------------|------------|----------------------------------------------------------|------------|
| ** **                               | ** ** | **(unaudited; in millions)**                   | ** ** |
| **Operating  Income**                    |       |                                                     |       |                                                     |       |   |   |   |   |
| Liquids                                  |       |                                                     | $          | 51.8                                                     |       |   |   | $ | 30.0 |   |   |
| Natural Gas                              |       |                                                     | 37.2       |                                                     |       |   | 22.4 |   |   |
| Marketing                                |       |                                                     | 19.6       |                                                     |       |   | 1.4 |   |   |
| Corporate, operating and  administrative |       |                                                     | (0.6       | )                                                        |       |   | (0.6 | ) |   |
| **Total  Operating Income**              |       |                                                     | 108.0      |                                                     |       |   | 53.2 |   |   |
| Interest expense                         |       |                                                     | (27.9      | )                                                        |       |   | (25.6 | ) |   |
| Other income                             |       |                                                     | 1.0        |                                                     |       |   | 0.6 |   |   |
| **Net  Income**                          |       |                                                     | $          | 81.1                                                     |       |   |   | $ | 28.2 |   |   |

 

***Summary Analysis ofOperating Results***

*Liquids*

OurLiquids segment produced operating income of $51.8 million for the three monthsended March 31, 2006, a 73 percent increase over the $30.0 million earnedin the same period of 2005. The following primary factors contributed to theincrease in operating income of our Liquids segment:

·       Highervolumes on our Lakehead system following completion of the repair and expansionof a major oil sands plant that was damaged by a fire in early January 2005;

·       Shut-inoil production in the Gulf of Mexico that resulted from hurricanes Katrina andRita caused refinery procurement patterns to shift, increasing the volumes onour Mid-Continent system;

·       Theannual index rate increase effective July 1, 2005, which increased ouraverage tariffs; and

·       Longerhauls on our Lakehead and North Dakota systems.

14

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*Natural Gas*

Operatingincome from our Natural Gas segment grew 66 percent to $37.2 million for thethree months ended March 31, 2006 over the same period of 2005. Theincreased contribution of our Natural Gas segment is primarily attributable tothe following:

·       Additional processing capacity on our Anadarkosystem and favorable NGL prices have improved the operating results of ourprocessing assets;

·       Growth in average daily volumes on our majornatural gas systems stemming from additional wellhead supply contracts on theEast Texas and Anadarko systems; and

·       Continued strong drilling activity in theAnadarko Basin and East Texas Bossier trend.

*Marketing*

Operatingincome from our Marketing segment increased by $18.2 million to $19.6 millionfor the three months ended March 31, 2006 from $1.4 million for the sameperiod in 2005. The increase in operating income of our Marketing segment ispredominantly the result two factors:

·       Unrealized,non-cash mark-to-market gains of $25.9 million for the quarter that resultedfrom the change in market value of our derivative financial instruments that donot qualify for hedge accounting; offset partially by

·       Anon-cash loss of $8.0 million attributable to reducing the cost basis of ournatural gas inventory to fair market value associated with the decrease in themarket price of natural gas during the quarter.

***DerivativeTransactions and Hedging Activities***

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

During the quarter ended March 31,2006, natural gas prices began trending lower as a warmer than expected winterreduced the demand for natural gas supplies.  However, NGL prices, which tend to move inrelation to crude oil prices, have continued to trend higher due to supplyinstability in the crude oil market. While the natural gas and NGL pricingenvironment continues to remain volatile, the mark-to-market gains and lossescreated by this volatility do not affect our cash flow. We expect thesenon-cash gains and losses to be offset in future quarters as we settle thederivative financial instruments and the underlying physical 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, 2006 and 2005:

| ** **                                                   | ** ** | **Three months ended  March 31,** | ** ** |
|--------------------------------------------------------------|------------|--------------------------------------------------|------------|
| **Derivative fair value gains (losses)** | ** ** | ** **                                       | ** ** | **    2006    ** | ** ** | **    2005    ** | ** ** |
| ** **                                                   | ** ** | **(in millions)**                           | ** ** |
| Natural Gas segment                                          |       |                                             |       |   |   |   |   |   |   |
| Ineffectiveness                                              |       |                                             | $          | — |   |   |   | $ | (0.2 | ) |   |
| Non-qualified hedges                                         |       |                                             | 1.8        |   |   |   | (8.2 | ) |   |
| Marketing                                                    |       |                                             |       |   |   |   |   |   |   |
| Non-qualified hedges                                         |       |                                             | 25.9       |   |   |   | 1.4 |   |   |
| Derivative fair value  gains (losses)                        |       |                                             | $          | 27.7 |   |   |   | $ | (7.0 | ) |   |
|                                                              |            |                                                  |            |  |  |  |  |  |  |  |  |  |  |

 

15

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In December 2005, we settled natural gas collarsrepresenting derivative financial instruments on forecasted sales of 2,000million British thermal units per day, or MMBtu/d, of natural gas through 2011.The settlement of these collars reduced the amount of non-cash gains reflectedabove in our Natural Gas segment at March 31, 2006.

**RESULTS OFOPERATIONS—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,**         | ** ** |
|---------------------------------------------|------------|----------------------------------------------------------|------------|
| ** **                                  | ** ** | **    2006    ** | ** ** | **    2005    ** | ** ** |
| ** **                                  | ** ** | **(unaudited; in millions)**                   | ** ** |
| **Operating Results**                       | ** ** |                                                     | ** ** | ** ** |   |   | ** ** | ** ** |   |
| Operating revenue                           |       |                                                     | $          | 122.6 |   |   |   | $ | 96.5 |   |   |
| Operating and  administrative               |       |                                                     | (28.6      | ) |   |   | (31.9 | ) |   |
| Power                                       |       |                                                     | (26.3      | ) |   |   | (17.0 | ) |   |
| Depreciation and  amortization              |       |                                                     | (15.9      | ) |   |   | (17.6 | ) |   |
| Operating  expenses                         |       |                                                     | (70.8      | ) |   |   | (66.5 | ) |   |
| **Operating  Income**                       |       |                                                     | $          | 51.8 |   |   |   | $ | 30.0 |   |   |
| **Operating  Statistics**                   | ** ** |                                                     | ** ** | ** ** |   |   | ** ** | ** ** |   |
| **Lakehead  system:**                       |       |                                                     |       |   |   |   |   |   |   |
| United States(1)                            |       |                                                     | 1,161      |   |   |   | 1,009 |   |   |
| Province of Ontario(1)                      |       |                                                     | 348        |   |   |   | 327 |   |   |
| **Total deliveries****(1)**                 |       |                                                     | 1,509      |   |   |   | 1,336 |   |   |
| **Barrel miles (billions)**                 |       |                                                     | 100        |   |   |   | 83 |   |   |
| **Average haul (miles)**                    |       |                                                     | 738        |   |   |   | 689 |   |   |
| **Mid-Continent  system deliveries****(1)** |       |                                                     | 237        |   |   |   | 189 |   |   |
| **North Dakota system deliveries****(1)**   |       |                                                     | 90         |   |   |   | 89 |   |   |

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(1)                Averagebarrels per day (“Bpd”) in thousands.

***Three months ended March 31,2006 compared with three months ended March 31, 2005***

Our Liquids segmentaccounted for $51.8 million of operating income during the three monthsended March 31, 2006, representing a $21.8 million increase over the sameperiod in 2005. The majority of the increase related to significantly improvedresults on our Lakehead system, along with stronger performance on our Mid-Continentand North Dakota systems.

Operatingrevenue for the first quarter of 2006 increased by approximately $26.1 millionto $122.6 million from $96.5 million for the same period in 2005. Volumeson our Lakehead system increased approximately 13%, from 1.336 million Bpdduring the first quarter of 2005 to 1.509 million Bpd during the same period in2006, which resulted in higher operating revenue of approximately$10.5 million. The increase in deliveries on our Lakehead system is theresult of higher crude oil production in Western Canada primarily from threesources:

1.                 Suncor,an oil sands producer in Alberta, Canada, had a fire at their upgrader site on January 4,2005, which affected production for the majority of 2005. In late September 2005,

16

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Suncor announcedthat repairs to their upgrader site and an expansion were completed. Suncor’sproduction levels have increased since that time.

2.                 Duringthe first quarter of 2006, the synthetic plants were functioning without asmany operational problems as were experienced in the first quarter of 2005. Also,with warmer winter weather in western Canada during 2006, there were fewerseasonal maintenance issues.

3.                 Lastly,supply from conventional production was higher in the first quarter of 2006,likely in response to the sustained high crude oil prices.

Deliveries on ourMid-Continent system increased 25% to 237,000 Bpd in the first quarter of 2006,as continued shut-in production in the Gulf of Mexico caused refineryprocurement patterns to shift in favor of our system.

Increases in averagetariffs on all three Liquids systems resulted in higher operating revenue byapproximately $9.7 million. These tariff increases were mostly the result ofthe annual index rate increase of approximately 3.63% allowed by the FederalEnergy Regulatory Commission (“FERC”) effective July 1, 2005, on our basesystem tariffs. On our Lakehead system, new tariffs also went into effect on April 1,2005 for an adjustment on the Terrace expansion program surcharge due to lowerthan expected volumes moving on the Lakehead system, and new facilities inservice, which were not in effect during the first quarter of 2005. Longerhauls on our North Dakota system also contributed to a higher average tariff,as production in Montana continues to be strong during the first quarter of2006.

Operating andadministrative expenses for the Liquids segment decreased $3.3 million for thefirst quarter of 2006, compared with the same period in 2005. The decrease isdriven primarily from lower oil measurement losses of $6.3 million, offset byhigher workforce related costs of approximately $2.2 million.

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

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

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

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

During the fourth quarterof 2005, we identified certain operating conditions on connected third-partysystems that were contributing to higher levels of physical losses on ourLakehead system. Improvements to oil measurement processes have resulted inlower physical losses during the first quarter of 2006. We expect theseimprovements to have a continuing positive impact on our oil measurement lossesgoing forward. We estimate that total oil measurement losses for 2006 will beapproximately $10 million, compared with $18 million in 2005, assuming crudeoil prices remain comparable to 2005 levels.

Power costs increased $9.3million in the first quarter of 2006, compared with the same period in 2005,primarily due to the higher deliveries on our Lakehead system, along withhigher millrates from the power producers. We have experienced a trend ofincreasing millrates from our power suppliers due to higher natural gas costs.

We recently completed adepreciation study of the Lakehead system that resulted in our extending theuseful life of the system from 23 to 26 years in the first quarter of 2006. Theeffect of this change was a decrease to depreciation expense of approximately$2.5 million for the three months ended March 31, 2006. We expect theimpact of the depreciation study to be a reduction of depreciation expense byapproximately $10 million for the full year of 2006.

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*Future Prospects Update for Liquids*

Enbridge Inc. (“Enbridge”)and the Partnership continue to actively work with our customers to developtransportation options that will allow western Canadian crude oil access to newmarkets. In 2005, the Partnership and Enbridge announced approval of the400,000 Bpd Southern Access expansion project, which received endorsement fromthe Canadian Association of Petroleum Producers (“CAPP”). We are undertakingthe U.S. portion of the expansion on our Lakehead System with the first stageto add approximately 44,000 Bpd of capacity in 2007 and up to an additional146,000 Bpd by early 2008. The first stage includes a new pipeline betweenSuperior and Delavan, Wisconsin, along with pump station enhancements upstreamand downstream 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 36-inch, 454-milepipeline with approximately 400,000 Bpd of incremental capacity on our Lakeheadsystem. The design will also permit a further 400,000 Bpd increase in capacityfor minimal additional cost, in conjunction with a corresponding expansionupstream of Superior, when required by shippers.

On March 16, 2006,the Federal Energy Regulatory Commission (“FERC”) approved an Offer ofSettlement with respect to tariff principles for the Southern Access expansion,which were negotiated with CAPP, a trade association that represents a vastmajority of the Lakehead system’s customers. Fieldwork has commenced on theproject to ensure full completion in early 2009. In anticipation of long term demands for pipeline capacitydriven by oil sands production, we have decided to further increase thediameter of the pipeline to 42 inches. This increase will bring the estimated costof the Southern Access expansion project to approximately $1.3 billion. Weexpect increasing the diameter of the pipeline will benefit the project bylowering power costs and positioning the system for low-cost future expansionafter 2009. Further, increasing the diameter of the pipeline will provide anadditional 800,000 Bpd of capacity available for transport into the Chicagohub, bringing the total incremental capacity potential to 1.2 million Bpd overthe capacity available today.

Subject to the support ofour customers, we expect to increase the scope of our previously announcedNorth Dakota system expansion. This expansion will add approximately 30,000 Bpdof mainline throughput capacity and expand the system’s feeder segment at anestimated cost of $70 million. The expansion is supported by increasingcrude oil production from the Williston Basin in Montana and North Dakota andis expected to be completed in the latter half of 2007.

During the first quarterof 2006, Enbridge completed the reversal of its Spearhead Pipeline that nowflows from Chicago, Illinois to Cushing, Oklahoma, with a capacity of 125,000Bpd. In March 2006, the first western Canadian crude oil was deliveredthrough this system into the major oil hub at Cushing. We expect to benefitfollowing the reversal, as western Canadian crude oil will be carried on theLakehead system as far as Chicago, and then transferred to the Spearheadpipeline.

In April 2006,ExxonMobil announced it had completed the reversal of two of its crude oilpipelines allowing up to 66,000 Bpd of Canadian crude oil to flow from the U.S.Midwest to the U.S. Gulf Coast. The combined reversed pipeline is linked to ourLakehead system at Chicago via the Mustang Pipe Line Partners system to Patoka,Illinois. Mustang Pipe Line Partners system is 30% owned by an affiliate ofEnbridge. Exxon has received firm commitments from Canadian shippers for anaverage of 50,000 Bpd of capacity on the lines from Patoka, to Nederland, Texasfor the next five years.  The connectionof our Lakehead system with this new market should also support increasedthroughput on our Lakehead system, however, the reversed ExxonMobil system willalso be capable of transporting western Canadian crude oil moved via othercompeting pipelines into the Patoka market.

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***Natural Gas***

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

| ** **                             | ** ** | **Three months ended  March 31,**         | ** ** |
|----------------------------------------|------------|----------------------------------------------------------|------------|
| ** **                             | ** ** | **    2006    ** | ** ** | **    2005    ** | ** ** |
| ** **                             | ** ** | **(unaudited; in millions)**                   | ** ** |
| **Operating Results**                  |       |                                                     |       |   |   |
| Operating revenue                      |       | $                                                        | 871.0      |   | $ | 485.6 |   |
| Cost of natural  gas                   |       | (773.5                                                   | )          | (406.5 | ) |
| Operating and  administrative          |       | (43.7                                                    | )          | (41.1 | ) |
| Depreciation and  amortization         |       | (16.6                                                    | )          | (15.6 | ) |
| Operating  expenses                    |       | (833.8                                                   | )          | (463.2 | ) |
| **Operating  Income**                  |       | $                                                        | 37.2       |   | $ | 22.4 |   |
| **Average  Daily Volume****(MMBtu/d)** |       |                                                     |       |   |   |
| East Texas(1)                          |       | 921,000                                                  |       | 787,000 |   |
| Anadarko                               |       | 563,000                                                  |       | 452,000 |   |
| North Texas                            |       | 279,000                                                  |       | 265,000 |   |
| South Texas(1)                         |       | —                                                   |       | 38,000 |   |
| UTOS                                   |       | 199,000                                                  |       | 198,000 |   |
| MidLab                                 |       | 83,000                                                   |       | 105,000 |   |
| AlaTenn                                |       | 54,000                                                   |       | 83,000 |   |
| KPC                                    |       | 47,000                                                   |       | 59,000 |   |
| Bamagas                                |       | 37,000                                                   |       | 13,000 |   |
| Other major  intrastates               |       | 158,000                                                  |       | 220,000 |   |
| Total                                  |       | 2,341,000                                                |       | 2,220,000 |   |

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(1)                Wesold the South Texas assets and a sour gas system in East Texas in December 2005,which had a combined average daily volume for the three months ended March 31,2005 of approximately 60,000 MMBtu/d.

***Three months ended March 31, 2006 compared withthree months ended March 31, 2005***

Our Natural Gas segment produced $37.2 million ofoperating income in the first quarter of 2006, an increase of $14.8 millionfrom the $22.4 million of operating income generated in the correspondingperiod of 2005. The increase in operating income is primarily due to theexpansion of our existing processing and transportation capacity to accommodatethe additional production volumes that have been developed  in the basins served by our natural gasassets, combined with favorable commodity prices.

Average daily volumes on our major natural gas systemswere up five percent in the first quarter of 2006, compared with thecorresponding period in 2005. The increase in volumes is primarily the resultof additional wellhead supply contracted to our East Texas, North Texas andAnadarko systems. Drilling activity continues to increase in the AnadarkoBasin, Bossier Trend and Barnett Shale areas served by our systems.Additionally, completion of the East Texas expansion project in late June 2005contributed to the growth in volumes for the three months ended March 31,2006. We expect increasing volumes on our major natural gas systems to resultfrom our continuing investments to expand the capacity of our systems.

Also contributing to the increase in operating incomeof our Natural Gas segment for the first quarter of 2006 are non-cash,mark-to-market net gains of $1.8 million. In the first quarter of 2005, ouroperating income was reduced by the $8.4 million of losses that we incurred. Thenon-cash mark-to-market net gains 

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in 2006 are derived fromour derivative financial instruments that do not qualify for hedge accountingtreatment under SFAS No. 133 (refer also to the discussions included inNote 4 of Item 1. Financial Statements, below under Derivative Activities, andItem 3. Quantitative and Qualitative Disclosures About Market Risk).

These gains primarily resulted from declines inforward natural gas prices during the quarter.  The previously recognized mark-to-marketlosses associated with our derivative financial instruments are reduced as theprice of natural gas moves closer to the contract prices on these derivativefinancial instruments, producing unrealized, non-cash mark-to-market gains. Declinesin the price of natural gas reduce the unrealized losses on our derivativefinancial instruments because the related contract prices are fixed at amountsthat are generally less than the market price of natural gas at each of theforward settlement points. Although changes in the fair value of these specificderivative financial instruments do not affect our cash flow, we anticipatethese changes will continue to create volatility in our Consolidated Statementsof Income going forward due to the inherent volatility of natural gas and NGLprices.

A portion of our Natural Gas segment is exposed tocommodity price risks associated with percent of proceeds or percentage ofindex contracts that we negotiate with producers. Under the terms of thesecontracts, we retain a portion of the natural gas and NGLs we process inexchange for providing these producers with our services. In order to protectour unitholders from the volatility in cash flows that can result fromfluctuations in commodity prices, we enter into derivative financialinstruments to fix the sales price of the natural gas and NGLs we anticipatereceiving under the terms of these contracts. As a result of entering intothese derivative financial instruments, we have largely fixed the amount ofcash that we will receive in the future when we sell the processed natural gasand NGLs, although the market price of these commodities will continue tofluctuate during that time. Another significant portion of the revenue wereceive is derived from fees charged for gathering and treating of natural gasvolumes and other related services which is not directly dependent on commodityprices.

A variable element of the Natural Gas segment’soperating income is derived from keep-whole processing of natural gas.During the first quarter of 2006, NGL prices were increasing in concert withrising crude oil prices, while natural gas prices were declining. As a result,operating income derived from our keep-whole processing for the threemonths ended March 31, 2006, was approximately $10.2*** ***millioncompared with $4.2 million for the same period in 2005.

The operating andadministrative costs and depreciation expense for our Natural Gas business wereslightly higher in the first quarter of 2006 as compared to the first quarterof 2005 due to the expansion of our natural gas systems during 2005. We expectthese costs to increase during the remainder of 2006 relative to the continuedexpansion of our systems.

*Future ProspectsUpdate for Natural Gas*

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

Results of our natural gas gathering and processingbusiness depend upon the drilling activities of natural gas producers in theareas we serve. During the first quarter of 2006, 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 third-party reserve studies and the increase in rig counts in theareas served by our systems.

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Late in the first quarter of 2006, we completed anexpansion of our existing Zybach processing facility to a capacity of 150million cubic feet per day, or MMcf/d, of natural gas from the initial capacityof 100 MMcf/d when we placed the plant in service in April 2005. We arecontinuing to make progress in constructing additional processing capacity andfield compression to accommodate the volume growth the Anadarko systemrequires, which we expect to place in service in early 2007.

In the East Texasregion, we initiated construction on several projects in the first quarter of2006 to increase our gathering and treating infrastructure and market accesscapability. These projects continue to progress according to schedule andinclude:

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

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

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

When fully operational in late 2007, the new assetswill be an additional source of stable cash flow for us. We continue to evaluate other projects that couldfurther integrate our major Texas-centered pipeline systems.

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. In April 2006, Calpine announced its intent to sellapproximately 20 of its non-core and non-strategic power plants, although theplants to be sold have not been announced.  Calpine has continued to perform under theterms of its agreement with Bamagas and we remain confident that any losses wemay incur with respect to Calpine’s bankruptcy will be minimal. We continue tomonitor the Calpine bankruptcy proceedings and will recognize any losses thatmay result when it becomes evident that a loss has been incurred.

***Marketing***

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

| ** **                     | ** ** | **Three months ended  March 31,**                     | ** ** |
|--------------------------------|------------|----------------------------------------------------------------------|------------|
| ** **                     | ** ** | **     2006     ** | ** ** | **     2005     ** | ** ** |
| ** **                     | ** ** | **(unaudited; in millions)**                               | ** ** |
| Operating revenue              |       |                                                                 | $          | 895.0 |   |   |   | $ | 668.0 |   |   |
| Cost of natural  gas           |       |                                                                 | (874.2     | ) |   |   | (665.7 | ) |   |
| Operating and  administrative  |       |                                                                 | (1.1       | ) |   |   | (0.8 | ) |   |
| Depreciation and  amortization |       |                                                                 | (0.1       | ) |   |   | (0.1 | ) |   |
| Operating  expenses            |       |                                                                 | (875.4     | ) |   |   | (666.6 | ) |   |
| **Operating Income**           |       |                                                                 | $          | 19.6 |   |   |   | $ | 1.4 |   |   |

 

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***Three months ended March 31, 2006 compared withthree months ended March 31, 2005***

A majority of the operating income of our Marketingsegment is derived from selling natural gas received from producers on ourNatural Gas segment pipeline assets to 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 naturalgas to these markets where it can be sold to our customers. However, physicalpipeline constraints often require our Marketing business to transport naturalgas to alternate market points. Under these circumstances, our Marketingsegment will sell the purchased gas at a pricing index that is different fromthe pricing index at which the gas was purchased. This creates a price exposurethat arises from the relative difference in natural gas prices between thecontracted index at which the natural gas is purchased and the index underwhich it is sold, otherwise known as the “spread.” The spread can varysignificantly due to local supply and demand factors. Wherever possible, thispricing exposure is economically hedged using derivative financial instruments.However, the structure of these economic hedges often precludes our use ofhedge accounting under the requirements of SFAS No. 133, which can createvolatility in the operating results of our Marketing segment.

To ensure that we have access to primary pipelinedelivery points, we often enter into firm transportation agreements oninterstate and intrastate pipelines. To offset the demand charges associatedwith these firm transportation contracts, we look for market conditions thatallow us to lock in the price differential or spread between the pipelinereceipt point and pipeline delivery point. This allows our Marketing businessto lock in a fixed sales margin inclusive of pipeline demand charges. Weaccomplish this by transacting basis swaps between the index where the naturalgas is purchased and the index where the natural gas is sold. By transacting abasis swap between those two indices, we can effectively lock in a margin onthe combined natural gas purchase and the natural gas sale, mitigating thedemand charges on firm transportation agreements and limiting the Partnership’sexposure to cash flow volatility that could arise in markets where the firmtransportation becomes uneconomic. However, the structure of these transactionsprecludes our use of hedge accounting under the requirements of SFAS No. 133,which can create volatility in the operating results of our Marketing segment.

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

In the first quarter of 2006, the operating income ofour Marketing segment increased $18.2 million to $19.6 million, from$1.4 million for the corresponding period in 2005. Included in operatingincome for the first quarter of 2006 are unrealized, non-cash, mark-to-marketgains of approximately $26 million associated with derivative financialinstruments that do not qualify for hedge accounting treatment under SFAS No. 133.These mark-to-market gains are primarily driven by the decline in natural gasprices since December 31, 2005. As the price of natural gas moves closerto the contract prices associated with our derivative financial instruments,the mark-to-market losses that were recorded in 2005, when natural gas priceswere increasing, are reduced producing unrealized, non-cash mark-to-marketgains in the current period. We expect the net mark-to-market gains and lossesto be offset when the related physical 

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transactions are settled(refer also to the discussion included below under Derivative Activities,Note 4 of Item 1. Financial Statements, and Item 3. Quantitativeand Qualitative Disclosures About Market Risk).

Partially offsetting themark-to-market gains is a non-cash loss of $8.0 million attributable toreducing the cost basis of our natural gas inventory to fair market value. Generally,we accumulate natural gas inventory during the summer months for withdrawalduring late fall through early spring. During the time we were accumulatingnatural gas for our storage inventory, natural gas prices increasedsignificantly as a result of supply disruptions in the Gulf of Mexico caused byhurricanes Katrina and Rita, in addition to other market factors. As a resultof the increase in natural gas prices, the weighted average cost of our naturalgas inventory at December 31, 2005 also increased. Natural gas prices aspublished by Gas Daily for Henry Hub were approximately $10.08 per millionBritish thermal units, or MMBtu, at December 31, 2005, which had declinedto $6.99 per MMBtu at March 31, 2006. As a result of the decline in theprice of natural gas from December 31, 2005 to March 31, 2006, theweighted average cost of our natural gas inventory at March 31, 2006,exceeded the market price of natural gas by approximately $8.0 million. As aresult of this decline, we reduced the cost basis of our inventory to fairmarket value at March 31, 2006 by recording a non-cash charge for $8.0million. Due to our hedging structures, we expect that a majority of this losswill be offset by future financial transactions that will settle at the timethe natural gas inventory is sold.

***Corporate***

Interest expense was $27.9million for the three months ended March 31, 2006, compared with$25.6 million for the corresponding period in 2005. The increase is theresult of modestly higher debt balances, less interest capitalized onconstruction projects and slightly higher weighted average interest rates ofapproximately 5.9% during the three months ended March 31, 2006, comparedwith approximately 5.7% during the same period in 2005.

**LIQUIDITY ANDCAPITAL RESOURCES**

***General***

We believe that our ability to generate cash flow, inaddition to our access to capital markets, is sufficient to meet the demands ofour current and future operating growth and investment needs. Our primary cashrequirements consist of normal operating expenses, maintenance and expansioncapital expenditures, debt service payments, distributions to partners,acquisitions of new assets or businesses, and payments associated with ourderivative transactions. Short-term cash requirements, such as operatingexpenses, maintenance capital expenditures and quarterly distributions topartners, are expected to be funded from our operating cash flows. Marginrequirements associated with our derivative transactions are generallysupported by letters of credit issued under our Credit Facility. We expect tofund long-term cash requirements for expansion projects and acquisitionsfrom several sources, including cash flows from operating activities,borrowings under our commercial paper program, our credit facilities, and theissuance of additional equity and debt securities. Our ability to completefuture debt and equity offerings and the timing of any such offerings willdepend on various factors, including prevailing market conditions, interestrates, our financial condition and credit rating at the time.

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

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beforewe will begin to realize a return on them. While these major projects are underconstruction, our ability to increase distributions, while funding theseprojects is likely to be limited.

***Capital Resources***

*Available Credit*

A significant source of our liquidity is provided bythe commercial paper market. We have a $600 million commercial paper programthat is supported by our long-term Credit Facility which we access primarily toprovide temporary financing for our operating activities, capital expendituresand acquisitions, at rates that are generally lower than the rates availableunder our Credit Facility. Under the terms of our commercial paper program, wemay issue up to $600 million of commercial paper. However, the amount ofcommercial paper we may issue is reduced by any balance of outstanding lettersof credit in excess of $400 million. At March 31, 2006, we had $440.0million in principal amount of commercial paper outstanding and could issue anadditional $160.0 million in principal amount of commercial paper.

Our Credit Facility alsoprovides us with another significant source of liquidity. In March 2006,we obtained an increase from $800 million to $1 billion in the aggregatecommitment available to us under the terms of our Credit Facility. The amountswe may borrow under the terms of our Credit Facility are reduced by theprincipal amount of our commercial paper issuances and the balance of our lettersof credit outstanding. At March 31, 2006, no amounts had been borrowedagainst our Credit Facility and we had approximately $107.4 million of lettersof credit outstanding. At March 31, 2006, we could borrow$452.6 million under the terms of our Credit Facility withoutconsideration to additional borrowings under our commercial paper program.

***Cash Requirements for Future Growth***

*Capital Spending*

We rely upon cash flow from our operating activitiesand access to the capital markets to provide the funds necessary to execute ourgrowth strategy and complete our projects. Our success with generating andraising capital is a critical factor that determines how much we spend inconnection with our growth objectives. We believe our ability to generate or otherwiseaccess the necessary capital resources is sufficient to meet the demands of ourcurrent and future operating growth needs. Although we currently intend to makethe forecasted expenditures discussed below, we may adjust the timing andamounts of projected expenditures as necessary to adapt to changes in economicconditions.

We estimate our capital expenditures based on our longrange strategic operating and growth plans. These estimates may change due tofactors beyond our control, including changes in supplier prices, resourceconstraints and poor economic conditions. Additionally, estimates may change asa result of decisions made at a later date, which may include acquisitions,scope changes or operational considerations.

We categorize our capital expenditures as either coremaintenance or enhancement expenditures. Core maintenance expenditures arethose expenditures that are necessary to maintain the service capability of ourexisting assets and include the replacement of system components and equipmentwhich is worn, obsolete or completing its useful life. Enhancement expendituresimprove the service capability of our existing assets, extend asset usefullives, increase capacities from existing levels, reduce costs or enhancerevenues, and enable us to respond to governmental regulations and developingindustry standards. We made capital expenditures of approximately$98.7 million, including $7.9 million on core maintenance activities,during the three months ended March 31, 2006.

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Forthe full year of 2006, we anticipate our capital expenditures to approximatethe following in millions:

| System enhancements         |   | $   | 390    |   |
|-----------------------------|--------|-----|--------|--------|
| Core maintenance activities |   | 55  |   |
| Southern Access expansion   |   | 300 |   |
| East Texas expansion        |   | 365 |   |
|                        |   | $   | 1,110  |   |

 

We continue to expect ongoing capital expenditures tobe significant over the next three years due to the East Texas expansion andSouthern Access projects. Core maintenance capital is also anticipated toincrease over that period of time due to growth in our pipeline systems andaging of infrastructure.

We anticipate funding the system enhancement capitalexpenditures temporarily through the issuance of commercial paper, 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.

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

As of March 31, 2006, we have contractualcommitments totaling $172.2 million for materials and services related to ourorganic growth projects. We expect to settle these commitments during theremainder of 2006; however, we will incur additional commitments as our capitalprojects continue to progress.

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 to increaseas pipelines age and require higher levels of inspection or maintenance;however, these are consistent with industry trends.

*Acquisitions*

We continue to assess various acquisition andexpansion opportunities to grow our business. However, the market for acquiringenergy transportation assets continues to remain competitive. While we remaincommitted to making accretive acquisitions in or near areas where we alreadyoperate or have a competitive advantage, we will continue to focus our effortson development of our existing pipeline systems. Additionally, we may pursueopportunities to divest any non-strategic assets as conditions warrant.

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

***Derivative Activities***

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

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Thefollowing table provides summarized information about the timing and expectedsettlement amounts of our outstanding commodity derivative financialinstruments at March 31, 2006 for each of the indicated calendar years: 

| ** **             | ** ** | **Notional**           | ** ** | **2006** | ** ** | **2007** | ** ** | **2008** | ** ** | **2009** | ** ** | **2010** | ** ** | **2011** | ** ** | **2012** | ** ** |
|------------------------|------------|------------------------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------|------------|----------|------------|
| ** **             | ** ** | **(in millions)** | ** ** |
| **Swaps**              |       |                   |       |     |       |     |       |     |       |     |       |     |       |     |       |     |       |
| Natural gas(1)         |       | 430,197,401            |       | $        | (33.1      | )        | $          | (53.3    | )          | $        | (44.6      | )        | $          | (33.0    | )          | $        | (24.9      | ) | $ | (19.9 | ) | $ | (4.8 | ) |
| NGL(2)                 |       | 7,374,950              |       | (19.3    | )          | (27.5    | )          | (7.2     | )          | (1.1     | )          | (1.3     | )          | —   |       | —   |       |
| Crude(2)               |       | 1,266,229              |       | (7.5     | )          | (10.0    | )          | (7.0     | )          | (1.9     | )          | (0.5     | )          | —   |       | —   |       |
| **Options—calls** |       |                   |       |     |       |     |       |     |       |     |       |     |       |     |       |     |       |
| Natural gas(1)         |       | 2,101,000              |       | (1.0     | )          | (1.8     | )          | (1.6     | )          | (1.3     | )          | (1.1     | )          | (0.9     | )          | —   |       |
| **Options—puts**  |       |                   |       |     |       |     |       |     |       |     |       |     |       |     |       |     |       |
| Natural gas(1)         |       | 2,101,000              |       | —   |       | —   |       | —   |       | —   |       | —   |       | 0.1      |       | —   |       |
| Totals                 |       |                   |       | $        | (60.9      | )        | $          | (92.6    | )          | $        | (60.4      | )        | $          | (37.3    | )          | $        | (27.8      | ) | $ | (20.7 | ) | $ | (4.8 | ) |

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(1)                Notional amountsfor natural gas are recorded in MMBtu.

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

***OperatingActivities***

Net cash provided byoperating activities for the three months ended March 31, 2006 was$96.4 million, an increase of $7.1 million over the $89.3 million forthe same period in 2005. The improved operating cash flow is primarilyattributable to income contributions from our natural gas processing assets andincreased deliveries on our Lakehead system, as well as the general timingdifferences in the collection on and payment of our current and related partyaccounts.

***InvestingActivities***

We used $140.2 millionless in our investing activities during the three months ended March 31,2006 in relation to the same period in 2005. The decrease is primarilyattributable to the $164.6 million we spent in January 2005 for theacquisition of the gathering and processing assets in north Texas, partiallyoffset by the approximate $26 million increase in our investments in property,plant and equipment during the first quarter of 2006 over the amount spent duringthe same period of 2005. The increase in our capital expenditures in the firstquarter of 2006 is directly attributable to our previously announced expansionprojects.

***FinancingActivities***

Net cash provided byfinancing activities during the three months ended March 31, 2006 was$53.4 million, compared with $146.9 million for the correspondingperiod in 2005. In the first quarter of 2006 we did not issue any additionalunits, whereas in the first quarter of 2005 we raised $127.5 million from unitissuances.  Additionally, during thefirst quarter of 2006 we had net commercial paper issuances of $110 million,which include gross issuances of $860 million and gross repayments of $750million. During the first quarter of 2005, we borrowed $70 million, net ofrepayments, under the terms of our credit facility, including borrowings and repayments of $360 million representing netnon-cash settlements with the parties to our credit facilities. Distributionsto our partners were higher in the first quarter of 2006 due to an increase inthe weighted average number of units outstanding and the related increase inthe general partner incentive distributions resulting from the larger number ofunits outstanding.

**OFF-BALANCE SHEET ARRANGEMENTS**

We do not have any off-balance sheetarrangements.

26

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**SUBSEQUENT EVENTS**

***Distribution Declaration***

On April 27, 2006,Enbridge Management’s Board of Directors declared a distribution payable onMay 15, 2006. The distribution will be paid to unitholders of record as ofMay 5, 2006, of our available cash of $67.9 million at March 31,2006, or $0.925 per common unit. Of this distribution, $56.7 millionwill be paid in cash, $11.0 million will be distributed in i-unitsto our i-unitholder and $0.2 million will be retained from theGeneral Partner in respect of this i-unit distribution.

**REGULATORY MATTERS**

***FERC Transportation Tariffs-***Liquids

Effective April 1,2006, 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 for2006, and an adjustment for the Terrace surcharge as a result of lower thanexpected volumes moving on the Lakehead system in 2005. This filing increasedthe tariff for heavy crude oil movements from the Canadian border to Chicago,Illinois, by approximately $0.008 per barrel, to approximately $0.898 perbarrel.

**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 endedDecember 31, 2005, in addition to information presented in Items 1 and 2of this Quarterly Report 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 offsetting natural gas purchases). This market price exposureexists within our Natural Gas and Marketing segments. To mitigate thevolatility of our cash flows, we use derivative financial instruments (i.e.,futures, forwards, swaps, options and other financial instruments with similarcharacteristics) to manage the purchase and sales prices of the commodities.Based on our risk management policies, all of our derivative financialinstruments are employed in connection with an underlying asset, liability oranticipated transaction and are not entered into with the objective ofspeculating on commodity prices.

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

| ** **                        | ** **   | **At March 31, 2006** | ** **   | **At December 31,  2005** | ** ** |
|-----------------------------------|--------------|--------------------------------------|--------------|-------------------------------------|------------|
| ** **                        | ** **   | ** **                           | ** **   | ** **                          | ** ** | **Wtd Avg Price**(2) | ** ** | **Fair Value**(3) | ** ** | **Fair Value**(3) | ** ** |
| ** **                        | ** **   | **Commodity**                        | ** **   | **Notional**(1)                     | ** ** | **Receive** | ** ** | **Pay** | ** ** | **Asset** | ** ** | **Liability** | ** ** | **Asset** | ** ** | **Liability** | ** ** |
| ***Contracts  maturing in 2006*** | *** *** |                                 | *** *** | *** ***                        |       |   | *** *** | *** *** |   |   | *** *** | *** *** |   | *** *** | *** *** |   | *** *** | *** *** |   |   | *** *** | *** *** |   | *** *** | *** *** |   | *** *** | *** *** |   |
| *Swaps*                           | * *     |                                 | * *     | *** ***                        |       |   | * * | *** *** |   |   | * * | *** *** |   | * * | * * |   | * * | *** *** |   |   | * * | * * |   | * * | * * |   | * * | * * |   |
| Receive variable/pay fixed        |         |                                 | Natural  gas | *** ***                        |       |   | 104,298,742 | *** *** |   |   | $ | 7.26 | *** *** |   | $ | 7.03 |   |   | $ | 46.6 | *** *** |   |   | $ | (23.3 | ) |   | $ | 380.6 |   |   | $ | (11.7 | ) |   |
| Receive fixed/pay variable        |         |                                 | Natural  gas | *** ***                        |       |   | 104,681,622 | *** *** |   |   | 6.98 | *** *** |   | 7.51 |   |   | 28.4 | *** *** |   |   | (82.8 | ) |   | 14.5 |   |   | (467.8 | ) |   |
|                              |         |                                 | NGL          | *** ***                        |       |   | 3,134,577 | *** *** |   |   | 33.94 | *** *** |   | 40.26 |   |   | 0.7 | *** *** |   |   | (20.0 | ) |   | — |   |   | (29.7 | ) |   |
|                              |         |                                 | Crude  oil   | *** ***                        |       |   | 307,475 | *** *** |   |   | 44.32 | *** *** |   | 68.99 |   |   | — | *** *** |   |   | (7.5 | ) |   | 0.2 |   |   | (7.8 | ) |   |
| Receive variable/pay variable     |         |                                 | Natural  gas | *** ***                        |       |   | 19,834,196 | *** *** |   |   | 6.96 | *** *** |   | 7.06 |   |   | 2.0 | *** *** |   |   | (4.0 | ) |   | 5.2 |   |   | (5.2 | ) |   |
| *Options*                         | * *     |                                 | * *     | *** ***                        |       |   | * * | *** *** |   |   | * * | *** *** |   | * * | * * |   | * * | *** *** |   |   | * * | * * |   | * * | * * |   | * * | * * |   |
| Calls (written)                   |         |                                 | Natural  gas | *** ***                        |       |   | 275,000 | *** *** |   |   | 8.04 | *** *** |   | 4.31 |   |   | — | *** *** |   |   | (1.0 | ) |   | — |   |   | (2.0 | ) |   |
| Puts                              |         |                                 | Natural  gas | *** ***                        |       |   | 275,000 | *** *** |   |   | 8.04 | *** *** |   | 3.40 |   |   | — | *** *** |   |   | — |   |   | — |   |   | — |   |   |
|                                   |              |                                      |              |                                     |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

27

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| ** **                           | ** **   | **At March 31, 2006** | ** **   | **At December 31,  2005** | ** ** |
|--------------------------------------|--------------|--------------------------------------|--------------|-------------------------------------|------------|
| ** **                           | ** **   | ** **                           | ** **   | ** **                          | ** ** | **Wtd Avg Price**(2) | ** ** | **Fair Value**(3) | ** ** | **Fair Value**(3) | ** ** |
| ** **                           | ** **   | **Commodity**                        | ** **   | **Notional**(1)                     | ** ** | **Receive** | ** ** | **  Pay  ** | ** ** | **Asset** | ** ** | **Liability** | ** ** | **Asset** | ** ** | **Liability** | ** ** |
| ***Contracts  maturing in 2007***    | *** *** |                                 | *** *** | *** ***                        |       |   | *** *** | *** *** |   |   | *** *** | *** *** |   |   | *** *** | *** *** |   |   | *** *** | *** *** |   |   | *** *** | *** *** |   |   | *** *** | *** *** |   |   | *** *** | *** *** |   |
| *Swaps*                              | * *     |                                 | * *     | *** ***                        |       |   | * * | *** *** |   |   | * * | *** *** |   |   | * * | *** *** |   |   | * * | *** *** |   |   | * * | * * |   |   | * * | *** *** |   |   | * * | * * |   |
| Receive variable/pay fixed           |         |                                 | Natural gas  | *** ***                        |       |   | 55,195,237 | *** *** |   |   | 8.87 | *** *** |   |   | 7.45 | *** *** |   |   | 80.5 | *** *** |   |   | (6.8 | ) |   |   | 112.0 | *** *** |   |   | (1.0 | ) |   |
| Receive fixed/pay variable           |         |                                 | Natural gas  | *** ***                        |       |   | 63,194,865 | *** *** |   |   | 7.26 | *** *** |   |   | 9.41 | *** *** |   |   | 7.1 | *** *** |   |   | (134.7 | ) |   |   | 0.5 | *** *** |   |   | (170.0 | ) |   |
|                                 |         |                                 | NGL          | *** ***                        |       |   | 2,698,810 | *** *** |   |   | 28.06 | *** *** |   |   | 37.80 | *** *** |   |   | — | *** *** |   |   | (27.5 | ) |   |   | — | *** *** |   |   | (22.5 | ) |   |
|                                 |         |                                 | Crude oil    | *** ***                        |       |   | 388,680 | *** *** |   |   | 42.05 | *** *** |   |   | 69.66 | *** *** |   |   | — | *** *** |   |   | (10.0 | ) |   |   | — | *** *** |   |   | (7.9 | ) |   |
| Receive variable/pay variable        |         |                                 | Natural gas  | *** ***                        |       |   | 7,594,666 | *** *** |   |   | 9.32 | *** *** |   |   | 9.23 | *** *** |   |   | 1.3 | *** *** |   |   | (0.7 | ) |   |   | 0.7 | *** *** |   |   | (0.1 | ) |   |
| *Options*                            | * *     |                                 | * *     | *** ***                        |       |   | * * | *** *** |   |   | * * | *** *** |   |   | * * | *** *** |   |   | * * | *** *** |   |   | * * | * * |   |   | * * | *** *** |   |   | * * | * * |   |
| Calls (written)                      |         |                                 | Natural gas  | *** ***                        |       |   | 365,000 | *** *** |   |   | 9.60 | *** *** |   |   | 4.31 | *** *** |   |   | — | *** *** |   |   | (1.8 | ) |   |   | — | *** *** |   |   | (2.0 | ) |   |
| Puts                                 |         |                                 | Natural gas  | *** ***                        |       |   | 365,000 | *** *** |   |   | 9.60 | *** *** |   |   | 3.40 | *** *** |   |   | — | *** *** |   |   | — |   |   |   | — | *** *** |   |   | — |   |   |
| ***Contracts  maturing in 2008***    | *** *** |                                 | *** *** | *** ***                        |       |   | *** *** | *** *** |   |   | *** *** | *** *** |   |   | *** *** | *** *** |   |   | *** *** | *** *** |   |   | *** *** | *** *** |   |   | *** *** | *** *** |   |   | *** *** | *** *** |   |
| *Swaps*                              | * *     |                                 | * *     | *** ***                        |       |   | * * | *** *** |   |   | * * | *** *** |   |   | * * | *** *** |   |   | * * | *** *** |   |   | * * | * * |   |   | * * | *** *** |   |   | * * | * * |   |
| Receive variable/pay fixed           |         |                                 | Natural gas  | *** ***                        |       |   | 10,968,065 | *** *** |   |   | 8.94 | *** *** |   |   | 6.98 | *** *** |   |   | 19.4 | *** *** |   |   | (0.1 | ) |   |   | 18.5 | *** *** |   |   | — |   |   |
| Receive fixed/pay variable           |         |                                 | Natural gas  | *** ***                        |       |   | 22,654,508 | *** *** |   |   | 6.09 | *** *** |   |   | 9.27 | *** *** |   |   | 0.2 | *** *** |   |   | (64.7 | ) |   |   | — | *** *** |   |   | (66.3 | ) |   |
|                                 |         |                                 | NGL          | *** ***                        |       |   | 729,438 | *** *** |   |   | 25.59 | *** *** |   |   | 36.62 | *** *** |   |   | — | *** *** |   |   | (7.2 | ) |   |   | — | *** *** |   |   | (7.2 | ) |   |
|                                 |         |                                 | Crude oil    | *** ***                        |       |   | 323,699 | *** *** |   |   | 44.18 | *** *** |   |   | 68.61 | *** *** |   |   | — | *** *** |   |   | (7.0 | ) |   |   | — | *** *** |   |   | (5.2 | ) |   |
| Receive variable/pay variable        |         |                                 | Natural gas  | *** ***                        |       |   | 4,204,000 | *** *** |   |   | 9.08 | *** *** |   |   | 8.92 | *** *** |   |   | 0.6 | *** *** |   |   | — |   |   |   | 1.0 | *** *** |   |   | — |   |   |
| *Options*                            | * *     |                                 | * *     | *** ***                        |       |   | * * | *** *** |   |   | * * | *** *** |   |   | * * | *** *** |   |   | * * | *** *** |   |   | * * | * * |   |   | * * | *** *** |   |   | * * | * * |   |
| Calls (written)                      |         |                                 | Natural gas  | *** ***                        |       |   | 366,000 | *** *** |   |   | 9.12 | *** *** |   |   | 4.31 | *** *** |   |   | — | *** *** |   |   | (1.6 | ) |   |   | — | *** *** |   |   | (1.7 | ) |   |
| Puts                                 |         |                                 | Natural gas  | *** ***                        |       |   | 366,000 | *** *** |   |   | 9.12 | *** *** |   |   | 3.40 | *** *** |   |   | — | *** *** |   |   | — |   |   |   | — | *** *** |   |   | — |   |   |
| ***Contracts  maturing in 2009***    | *** *** |                                 | *** *** | *** ***                        |       |   | *** *** | *** *** |   |   | *** *** | *** *** |   |   | *** *** | *** *** |   |   | *** *** | *** *** |   |   | *** *** | *** *** |   |   | *** *** | *** *** |   |   | *** *** | *** *** |   |
| *Swaps*                              | * *     |                                 | * *     | *** ***                        |       |   | * * | *** *** |   |   | * * | *** *** |   |   | * * | *** *** |   |   | * * | *** *** |   |   | * * | * * |   |   | * * | *** *** |   |   | * * | * * |   |
| Receive variable/pay fixed           |         |                                 | Natural gas  | *** ***                        |       |   | 730,000 | *** *** |   |   | 8.44 | *** *** |   |   | 3.57 | *** *** |   |   | 3.0 | *** *** |   |   | — |   |   |   | — | *** *** |   |   | — |   |   |
| Receive fixed/pay variable           |         |                                 | Natural gas  | *** ***                        |       |   | 12,227,500 | *** *** |   |   | 4.93 | *** *** |   |   | 8.44 | *** *** |   |   | — | *** *** |   |   | (36.3 | ) |   |   | — | *** *** |   |   | (34.5 | ) |   |
|                                 |         |                                 | NGL          | *** ***                        |       |   | 494,575 | *** *** |   |   | 32.83 | *** *** |   |   | 54.01 | *** *** |   |   | — | *** *** |   |   | (1.1 | ) |   |   | — | *** *** |   |   | (0.6 | ) |   |
|                                 |         |                                 | Crude oil    | *** ***                        |       |   | 155,125 | *** *** |   |   | 53.13 | *** *** |   |   | 67.55 | *** *** |   |   | — | *** *** |   |   | (1.9 | ) |   |   | — | *** *** |   |   | (1.0 | ) |   |
| Receive variable/pay variable        |         |                                 | Natural gas  | *** ***                        |       |   | 4,197,500 | *** *** |   |   | 8.02 | *** *** |   |   | 7.92 | *** *** |   |   | 0.3 | *** *** |   |   | — |   |   |   | 1.1 | *** *** |   |   | — |   |   |
| *Options*                            | * *     |                                 | * *     | *** ***                        |       |   | * * | *** *** |   |   | * * | *** *** |   |   | * * | *** *** |   |   | * * | *** *** |   |   | * * | * * |   |   | * * | *** *** |   |   | * * | * * |   |
| Calls (written)                      |         |                                 | Natural gas  | *** ***                        |       |   | 365,000 | *** *** |   |   | 8.44 | *** *** |   |   | 4.31 | *** *** |   |   | — | *** *** |   |   | (1.3 | ) |   |   | — | *** *** |   |   | (1.4 | ) |   |
| Puts                                 |         |                                 | Natural gas  | *** ***                        |       |   | 365,000 | *** *** |   |   | 8.44 | *** *** |   |   | 3.40 | *** *** |   |   | — | *** *** |   |   | — |   |   |   | — | *** *** |   |   | — |   |   |
| ***Contracts  maturing in 2010***    | *** *** |                                 | *** *** | *** ***                        |       |   | *** *** | *** *** |   |   | *** *** | *** *** |   |   | *** *** | *** *** |   |   | *** *** | *** *** |   |   | *** *** | *** *** |   |   | *** *** | *** *** |   |   | *** *** | *** *** |   |
| *Swaps*                              | * *     |                                 | * *     | *** ***                        |       |   | * * | *** *** |   |   | * * | *** *** |   |   | * * | *** *** |   |   | * * | *** *** |   |   | * * | * * |   |   | * * | *** *** |   |   | * * | * * |   |
| Receive variable/pay fixed           |         |                                 | Natural gas  | *** ***                        |       |   | 730,000 | *** *** |   |   | 7.79 | *** *** |   |   | 3.57 | *** *** |   |   | 2.5 | *** *** |   |   | — |   |   |   | — | *** *** |   |   | — |   |   |
| Receive fixed/pay variable           |         |                                 | Natural gas  | *** ***                        |       |   | 9,490,000 | *** *** |   |   | 4.11 | *** *** |   |   | 7.70 | *** *** |   |   | 0.1 | *** *** |   |   | (27.5 | ) |   |   | 0.1 | *** *** |   |   | (25.9 | ) |   |
|                                 |         |                                 | NGL          | *** ***                        |       |   | 317,550 | *** *** |   |   | 30.60 | *** *** |   |   | 35.51 | *** *** |   |   | — | *** *** |   |   | (1.3 | ) |   |   | — | *** *** |   |   | (0.4 | ) |   |
|                                 |         |                                 | Crude oil    | *** ***                        |       |   | 91,250 | *** *** |   |   | 59.00 | *** *** |   |   | 66.54 | *** *** |   |   | — | *** *** |   |   | (0.5 | ) |   |   | — | *** *** |   |   | (0.1 | ) |   |
| *Options*                            | * *     |                                 | * *     | *** ***                        |       |   | * * | *** *** |   |   | * * | *** *** |   |   | * * | *** *** |   |   | * * | *** *** |   |   | * * | * * |   |   | * * | *** *** |   |   | * * | * * |   |
| Calls (written)                      |         |                                 | Natural gas  | *** ***                        |       |   | 365,000 | *** *** |   |   | 7.79 | *** *** |   |   | 4.31 | *** *** |   |   | — | *** *** |   |   | (1.1 | ) |   |   | — | *** *** |   |   | (1.1 | ) |   |
| Puts                                 |         |                                 | Natural  gas | *** ***                        |       |   | 365,000 | *** *** |   |   | 7.79 | *** *** |   |   | 3.40 | *** *** |   |   | — | *** *** |   |   | — |   |   |   | — | *** *** |   |   | — |   |   |
| ***Contracts  maturing after 2010*** | *** *** |                                 | *** *** | *** ***                        |       |   | *** *** | *** *** |   |   | *** *** | *** *** |   |   | *** *** | *** *** |   |   | *** *** | *** *** |   |   | *** *** | *** *** |   |   | *** *** | *** *** |   |   | *** *** | *** *** |   |
| *Swaps*                              | * *     |                                 | * *     | *** ***                        |       |   | * * | *** *** |   |   | * * | *** *** |   |   | * * | *** *** |   |   | * * | *** *** |   |   | * * | * * |   |   | * * | *** *** |   |   | * * | * * |   |
| Receive variable/pay fixed           |         |                                 | Natural  gas | *** ***                        |       |   | 850,000 | *** *** |   |   | 7.47 | *** *** |   |   | 3.57 | *** *** |   |   | 2.5 | *** *** |   |   | — |   |   |   | — | *** *** |   |   | — |   |   |
| Receive fixed/pay variable           |         |                                 | Natural  gas | *** ***                        |       |   | 9,346,500 | *** *** |   |   | 3.62 | *** *** |   |   | 7.46 | *** *** |   |   | — | *** *** |   |   | (27.2 | ) |   |   | — | *** *** |   |   | (26.1 | ) |   |
| *Options*                            | * *     |                                 | * *     | *** ***                        |       |   | * * | *** *** |   |   | * * | *** *** |   |   | * * | *** *** |   |   | * * | *** *** |   |   | * * | * * |   |   | * * | *** *** |   |   | * * | * * |   |
| Calls (written)                      |         |                                 | Natural  gas | *** ***                        |       |   | 365,000 | *** *** |   |   | 7.25 | *** *** |   |   | 4.31 | *** *** |   |   | — | *** *** |   |   | (0.9 | ) |   |   | — | *** *** |   |   | (0.9 | ) |   |
| Puts                                 |         |                                 | Natural gas  | *** ***                        |       |   | 365,000 | *** *** |   |   | 7.25 | *** *** |   |   | 3.40 | *** *** |   |   | 0.1 | *** *** |   |   | — |   |   |   | — | *** *** |   |   | — |   |   |
|                                      |              |                                      |              |                                     |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

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(1)                 Volumes of Natural gas are measured in MMBtu, whereasvolumes of NGL and Crude are measured in Barrels, or Bbl.

(2)                 Weighted average prices received and paid are 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, 2006 and December 31, 2005,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 adjusted each period for changes inthe fair market value (“mark-to-market”). The 

28

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fair market value of thesederivative financial instruments reflects the estimated amounts that we wouldpay or receive to terminate or close the contracts at the reporting date,taking into account the current unrealized losses or gains on open contracts.We use external market quotes and indices to value substantially all of thefinancial 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, a change in the fair market value, both realized andunrealized, is recognized currently in our income statement as a derivativefair value gain (loss) and recorded in Cost of natural gas. Cash flow is onlyimpacted to the extent the actual derivative contract is settled by making orreceiving a payment to or from the counterparty or by making or receiving apayment for entering into a contract that exactly offsets the originalderivative contract. Typically, a derivative contract is settled when thefuture physical transaction that underlies the derivative financial instrumentoccurs.

If a derivative financialinstrument is designated as a cash flow hedge and qualifies for hedgeaccounting, any unrealized gain or loss is deferred in Accumulated othercomprehensive income (“OCI”), a component of Partners’ Capital, until theunderlying hedged transaction occurs. Any ineffective portion of a cash flowhedge’s change in fair market value is recognized each period in earnings.Realized gains and losses on derivative financial instruments that aredesignated as hedges and qualify for hedge accounting are included in Cost ofnatural gas in the period the hedged transaction occurs. Gains and lossesdeferred in OCI related to cash flow hedges for which hedge accounting has beendiscontinued, remain in OCI until the underlying physical transaction occursunless it is probable that the forecasted transaction will not occur by the endof the originally specified time period or within an additional two-monthperiod of time thereafter. Our preference, whenever possible, is for ourderivative financial instruments to receive hedge accounting treatment tomitigate the non-cash earnings volatility that arises under mark-to-marketaccounting treatment. To qualify for cash flow hedge accounting, very specificrequirements must be met in terms of hedge structure, hedge objective and hedgedocumentation.

***Non-Qualified Hedges***

Many of our derivative financial instruments qualifyfor hedge accounting treatment under the specific requirements of SFASNo. 133. However, we have three primary instances where the hedgestructure does not meet the requirements to apply hedge accounting and,therefore, these financial instruments are considered ‘non-qualified’ underSFAS No. 133. These non-qualified derivative financial instruments must beadjusted to their fair market value, or marked-to-market, each period, with theincreases and decreases in fair value recorded as increases and decreases inCost of natural gas in our Consolidated Statements of Income. Thesemark-to-market adjustments produce a degree of earnings volatility that canoften be significant from period to period, but have no cash flow impactrelative to changes in market prices. The cash flow impact occurs when theunderlying physical transaction takes place in the future and an associatedfinancial instrument contract settlement is made.

The three instances of non-qualified hedges are asfollows:

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

2.                **Storage**—In our Marketing segment, when we use derivativefinancial instruments to hedge market spreads around our owned or contractedassets, such as our gas storage portfolio, the underlying forecastedtransaction may or may not occur in the same period as originally forecast. 

29

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This can occur as we havethe flexibility to make changes in the underlying injection or withdrawalschedule, given changes in market conditions. Therefore, these transactions donot qualify for hedge accounting treatment under SFAS No. 133, as theforecasted transaction is no longer probable of occurring as originally setforth in the hedge documentation established at the inception of the hedge.

3.                **Natural Gas Collars**—In our Natural Gas segment, we hadpreviously entered into natural gas collars to hedge the sales price of naturalgas. The natural gas collars were based on a NYMEX price, while the physicalgas sales were based on a different index. To better align the index of thenatural gas collars with the index of the underlying sales, we de-designatedthe original hedging relationship with the intent of contemporaneouslyre-designating the natural gas collars as hedges of physical natural gas saleswith a NYMEX pricing index to better match the indices, which was a soundeconomic hedging strategy. However, because the fair value of these derivativeinstruments was a liability to us at re-designation, they are considered netwritten options under SFAS No. 133 and do not qualify for hedgeaccounting. These derivatives are now accounted for in the ConsolidatedStatements of Income through mark-to-market accounting, with the changes infair value from the date of de-designation recorded to earnings each period. Asa result, our operating income will be subject to greater volatility due tomovements in the prices of natural gas until the underlying long-termtransactions are settled.

In each of the three instances described above, theunderlying physical purchase, storage and sale of natural gas and NGLs areaccounted for on a historical cost basis rather than on the mark-to-marketbasis we utilize for the derivatives used to mitigate the commodity price riskassociated with our storage and transportation assets. This difference inaccounting (i.e., the financial sideof the transaction is recorded at fair market values while the physical side ofthe transaction is not) can and has resulted in volatility in ourreported net income, even though the economic margin is essentially unchangedfrom the date the transactions were consummated.

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)** | ** ** | ** **                                       | ** ** | **    2006    ** | ** ** | **    2005    ** | ** ** |
| ** **                                                   | ** ** | **(in millions)**                           | ** ** |
| Natural Gas segment                                          |       |                                             |       |   |   |   |   |   |   |
| Ineffectiveness                                              |       |                                             | $          | — |   |   |   | $ | (0.2 | ) |   |
| Non-qualified hedges                                         |       |                                             | 1.8        |   |   |   | (8.2 | ) |   |
| Marketing                                                    |       |                                             |       |   |   |   |   |   |   |
| Non-qualified hedges                                         |       |                                             | 25.9       |   |   |   | 1.4 |   |   |
| Derivative fair  value gains (losses)                        |       |                                             | $          | 27.7 |   |   |   | $ | (7.0 | ) |   |
|                                                              |            |                                                  |            |  |  |  |  |  |  |  |  |  |  |

 

We record the change in fair value of our highlyeffective cash flow hedges in OCI until the derivative financial instrumentsare settled, at which time they are reclassified to earnings. Also included inOCI are unrecognized losses of approximately $7.1 million associated withderivative financial instruments that qualified for and were classified as cashflow hedges of forecasted transactions that were subsequently de-designated.These unrecognized losses are reclassified to earnings over the periods duringwhich the originally hedged forecasted transactions affect earnings. For thethree months ended March 31, 2006, we reclassified unrealized losses of$24.8 million from OCI to Cost of natural gas on our Consolidated Statements ofIncome for the fair value of derivative financial instruments that were settled.

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

| ** **                   | ** ** | **March 31,  2006** | ** ** | **December 31,  2005** | ** ** |
|------------------------------|------------|--------------------------|------------|-----------------------------|------------|
| ** **                   | ** ** | **(in millions)**   | ** ** |
| Other current  assets        |       |                     | $          | 0.8                         |       |   |   | $ | 5.8 |   |   |
| Other assets, net            |       |                     | 6.4        |                        |       |   | 4.2 |   |   |
| Accounts payable  and other  |       |                     | (87.9      | )                           |       |   | (129.2 | ) |   |
| Other long-term  liabilities |       |                     | (217.4     | )                           |       |   | (243.0 | ) |   |
|                         |       |                     | $          | (298.1                      | )          |   |   | $ | (362.2 | ) |   |

 

The decrease in our obligation associated with derivativeactivities from December 31, 2005 to March 31, 2006 is primarily dueto the significant decreases in current and forward natural gas prices. ThePartnership’s portfolio of derivative financial instruments is largelycomprised of long-term fixed price sales and purchase agreements.

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, 2006. Based upon that evaluation,our principal executive officer and principal financial officer concluded thatour disclosure controls and procedures are effective to accomplish their purpose.In conducting this assessment, our management relied on similar evaluationsconducted by employees of Enbridge affiliates who provide certain treasury,accounting and other services on our behalf. No changes in our internal controlover financial reporting were made during the three months ended March 31,2006, that would materially affect our internal control over financialreporting, nor were any corrective actions with respect to significantdeficiencies or material weaknesses necessary subsequent to that date.

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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

The risk factors presented below update and should beconsidered in addition to the risk factors previously disclosed in our AnnualReport on Form 10-K for the fiscal year ended December 31,2005.

***Our partnership agreement and thedelegation of control agreement limit the fiduciary duties that EnbridgeManagement and our general partner owe to our unitholders and restricts theremedies available to our unitholders for actions taken by Enbridge Managementand our general partner that might otherwise constitute a breach of a fiduciaryduty.***

Our partnershipagreement contains provisions that modify the fiduciary duties that our generalpartner would otherwise owe to our unitholders under state fiduciary duty law.Through the delegation of control agreement, these modified fiduciary dutiesalso apply to Enbridge Management as the delegate of our general partner. Forexample, our partnership agreement:

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

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

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

These and similar provisions in our partnershipagreement may restrict the remedies available to our unitholders for actionstaken by Enbridge Management or our general partner that might otherwiseconstitute a breach of a fiduciary duty.

***Potential conflicts of interestmay arise among Enbridge and its shareholders, on the one hand, and us and ourunitholders and Enbridge Management and its shareholders, on the other hand. Becausethe fiduciary duties of the directors of our general partner and EnbridgeManagement have been modified, the directors may be permitted to make decisionsthat benefit Enbridge and its shareholders or Enbridge Management and itsshareholders more than us and our unitholders.***

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

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

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

·       whetherEnbridge Management will issue additional shares;

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

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

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

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

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

In other situations,Enbridge may take certain actions, including engaging in businesses thatcompete with us, that are adverse to us and our unitholders. For example,although Enbridge and its subsidiaries are generally restricted from engagingin any business that is in direct material competition with our businesses,that restriction is subject to the following significant exceptions:

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

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

·       Enbridgeand its subsidiaries are not prohibited from acquiring any business thatmaterially and directly competes with us as part of a larger acquisition, solong as the majority of the value of the business or assets acquired, inEnbridge’s reasonable judgment, is not attributable to the competitivebusiness; and

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

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

These exceptions alsoexpressly permitted the reversal by Enbridge in 1999 of one of its pipelinesthat extends from Sarnia, Ontario to Montreal, Quebec. As a result of thisreversal, Enbridge competes with us to supply crude oil to the Ontario, Canadamarket.

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**Item 6.**                        Exhibits

Each exhibit identifiedbelow is filed as part of this document. Exhibits not incorporated by referenceto a prior filing are designated by an “*”; all exhibits not so designated areincorporated herein by reference to a previous filing 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   |   | Third Amended and  Restated Agreement of Limited Partnership of the Partnership (incorporated by  reference to Exhibit 3.1 to the Partnership’s Quarterly Report on  Form 10-Q filed November 14, 2002). |
| 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).                               |
| 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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**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 28,  2006 | By:        | /s/ DAN C. TUTCHER                                                                                          |
|                       |       | Dan C. Tutcher                                                                                              |
| * *                   | * *   | *President*                                                                                                 |
| * *                   | * *   | *(Principal Executive Officer)*                                                                             |
| Date: April 28,  2006 | By:        | /s/ MARK A. MAKI                                                                                            |
| * *                   |       | Mark A. Maki                                                                                                |
| * *                   | * *   | *Vice President, Finance*                                                                                   |
| * *                   | * *   | *(Principal Financial Officer)*                                                                             |

 

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