**UNITED STATESSECURITIES AND EXCHANGE COMMISSION**

**Washington,D.C. 20549**

**FORM 10-Q**

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

 

**Forthe quarterly period ended September 30, 2005**

**OR**

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

 

**Forthe transition period from              to              **

**Commissionfile number 1-10934**

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

(Exact name of registrantas specified in its charter)

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

 

**1100 LouisianaSuite 3300Houston, TX 77002**

(Address of principalexecutive offices and zip code)

**(713) 821-2000**

(Registrant’s telephonenumber, including area code)

Indicate by check markwhether the registrant: (1) has filed all reports required to be filed by Section 13or 15(d) of the Securities Exchange Act of 1934 during the preceding 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 an accelerated filer (as defined in Rule 12b-2of the Exchange Act). Yes x No o

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

TheRegistrant had 46,802,634 Class A common units outstanding as of October 28,2005.

 

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**TABLE OF CONTENTS**

**PART I.FINANCIAL INFORMATION**

| Item 1.        |   | Financial  Statements                                                                                                                         |       |   |       |
|----------------|--------|-----------------------------------------------------------------------------------------------------------------------------------------------|------------|--------|------------|
|           |   | Consolidated  Statements of Income for the three and nine month periods ended  September 30, 2005 and 2004                          |       | 3      |       |
|           |   | Consolidated  Statements of Comprehensive Income for the three and nine month periods ended  September 30, 2005 and 2004                 |       | 4      |       |
|           |   | Consolidated  Statements of Cash Flows for the nine month periods ended September 30,  2005 and 2004       |       | 5      |       |
|           |   | Consolidated  Statements of Financial Position as of September 30, 2005 and  December 31, 2004             |       | 6      |       |
|           |   | Notes  to Consolidated Financial Statements                                                                                                   | ** ** | 7      | ** ** |
| Item 2.        |   | Management’s  Discussion and Analysis of Financial Condition and Results of  Operations                                                  | ** ** | 17     | ** ** |
| Item 3.        |   | Quantitative  and Qualitative Disclosures About Market Risk                                                                                   |       | 35     |       |
| Item 4.        |   | Controls  and Procedures                                                                                                                      |       | 41     |       |
| ** **     |   | **PART II.  OTHER INFORMATION**                                                                                                          |       |   |       |
| Item 1.        |   | Legal Proceedings                                                                                                                             |       | 42     |       |
| Item 5.        |   | Other  Information                                                                                                                            |       | 42     |       |
| Item 6.        |   | Exhibits                                                                                                                                      |       | 42     |       |
| **Signatures** |   | 43                                                                                                                                            |       |
| **Exhibits**   |   |                                                                                                                                          |       |

 

*In this report, unless the context requiresotherwise, references to “we”, “us”, “our”, or the “Partnership” are intendedto mean Enbridge Energy Partners, L.P. and its consolidated subsidiaries.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 our Annual Report on Form 10-Kfor the fiscal year ended December 31, 2004.*

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**PART I—FINANCIAL INFORMATION**

**Item 1.**                        FinancialStatements

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

| ** **                                                            | ** ** | **Three months ended  September 30,**                                | ** ** | **Nine months ended  September 30,** | ** ** |
|-----------------------------------------------------------------------|------------|-------------------------------------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                                                            | ** ** | **2005**                                                                            | ** ** | **2004**                                            | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                                                            | ** ** | **(unaudited; in millions, except per unit amounts)** | ** ** |
| Operating revenue                                                     |       | $                                                                                   | 1,809.6    |                                                | $          | 1,004.8 |   | $ | 4,392.4 |   | $ | 2,957.0 |   |
| Operating  expenses                                                   |       |                                                                                |       |                                                |       |   |   |   |   |
| Cost of natural gas (Note 4)                                          |       | 1,659.8                                                                             |       | 824.5                                               |       | 3,882.4 |   | 2,443.8 |   |
| Operating and administrative                                          |       | 82.4                                                                                |       | 67.3                                                |       | 237.2 |   | 197.8 |   |
| Power                                                                 |       | 19.0                                                                                |       | 19.7                                                |       | 53.2 |   | 54.0 |   |
| Depreciation and amortization (Note 6)                                |       | 36.5                                                                                |       | 31.7                                                |       | 103.9 |   | 89.2 |   |
|                                                                  |       | 1,797.7                                                                             |       | 943.2                                               |       | 4,276.7 |   | 2,784.8 |   |
| Operating income                                                      |       | 11.9                                                                                |       | 61.6                                                |       | 115.7 |   | 172.2 |   |
| Interest expense                                                      |       | (28.4                                                                               | )          | (22.2                                               | )          | (79.6 | ) | (65.8 | ) |
| Rate refunds                                                          |       | —                                                                              |       | (12.0                                               | )          | — |   | (12.0 | ) |
| Other income                                                          |       | 2.1                                                                                 |       | 0.2                                                 |       | 3.4 |   | 2.2 |   |
| Net income (loss)                                                     |       | $                                                                                   | (14.4      | )                                                   | $          | 27.6 |   | $ | 39.5 |   | $ | 96.6 |   |
| Net income (loss) allocable to common and i-units                     |       | $                                                                                   | (19.5      | )                                                   | $          | 22.1 |   | $ | 22.6 |   | $ | 80.1 |   |
| Net income (loss) per common and i-unit (basic  and diluted) (Note 3) |       | $                                                                                   | (0.32      | )                                                   | $          | 0.39 |   | $ | 0.37 |   | $ | 1.45 |   |
| Weighted average  units outstanding                                   |       | 62.1                                                                                |       | 55.7                                                |       | 61.5 |   | 55.1 |   |

 

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

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**ENBRIDGE ENERGY PARTNERS, L.P.CONSOLIDATED STATEMENTSOF COMPREHENSIVE INCOME**

| ** **                                                    | ** ** | **Three months ended  September 30,** | ** ** | **Nine months ended  September 30,** | ** ** |
|---------------------------------------------------------------|------------|------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                                                    | ** ** | **2005**                                             | ** ** | **2004**                                            | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                                                    | ** ** | **(unaudited; in millions)**               | ** ** |
| Net income (loss)                                             |       | $                                                    | (14.4      | )                                                   | $          | 27.6 |   | $ | 39.5 |   | $ | 96.6 |   |
| Unrealized loss on derivative financial instruments  (Note 4) |       | (138.4                                               | )          | (47.7                                               | )          | (224.1 | ) | (72.6 | ) |
| Comprehensive  (loss) income                                  |       | $                                                    | (152.8     | )                                                   | $          | (20.1 | ) | $ | (184.6 | ) | $ | 24.0 |   |

 

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

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

| ** **                                                                         | ** ** | **Nine months ended  September 30,** | ** ** |
|------------------------------------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                                                                         | ** ** | **2005**                                            | ** ** | **2004** | ** ** |
| ** **                                                                         | ** ** | **(unaudited; in millions)**              | ** ** |
| Cash provided by  operating activities                                             |       |                                                |       |   |   |
| Net income                                                                         |       | $                                                   | 39.5       |   | $ | 96.6 |   |
| Adjustments to  reconcile net income to net cash provided by operating activities: |       |                                                |       |   |   |
| Depreciation and amortization (Note 6)                                             |       | 103.9                                               |       | 89.2 |   |
| Derivative fair value loss (Note 4)                                                |       | 69.4                                                |       | 1.4 |   |
| Environmental liabilities                                                          |       | —                                              |       | (2.0 | ) |
| Other                                                                              |       | (0.1                                                | )          | 0.2 |   |
| Changes in  operating assets and liabilities, net of cash acquired:                |       |                                                |       |   |   |
| Receivables, trade and other                                                       |       | (13.1                                               | )          | (30.1 | ) |
| Due from General Partner and affiliates                                            |       | (6.2                                                | )          | 7.2 |   |
| Accrued receivables                                                                |       | (338.8                                              | )          | (39.7 | ) |
| Inventory                                                                          |       | (66.2                                               | )          | (49.0 | ) |
| Current and long-term other assets                                                 |       | (3.3                                                | )          | 12.3 |   |
| Due to General Partner and affiliates                                              |       | 13.5                                                |       | 4.7 |   |
| Accounts payable and other                                                         |       | (2.0                                                | )          | 55.1 |   |
| Accrued purchases                                                                  |       | 385.5                                               |       | 48.5 |   |
| Interest payable                                                                   |       | 24.5                                                |       | 25.5 |   |
| Property and other taxes payable                                                   |       | 1.6                                                 |       | 6.0 |   |
| Net cash provided by operating activities                                          |       | 208.2                                               |       | 225.9 |   |
| Cash used in  investing activities                                                 |       |                                                |       |   |   |
| Additions to property, plant and equipment                                         |       | (261.9                                              | )          | (174.6 | ) |
| Changes in construction payables                                                   |       | 3.3                                                 |       | 0.8 |   |
| Asset acquisitions, net of cash acquired (Note 2)                                  |       | (186.4                                              | )          | (139.9 | ) |
| Other                                                                              |       | 2.7                                                 |       | 0.3 |   |
| Net cash used in investing activities                                              |       | (442.3                                              | )          | (313.4 | ) |
| Cash provided by  financing activities                                             |       |                                                |       |   |   |
| Proceeds from unit issuances, net (Note 8)                                         |       | 127.5                                               |       | 194.2 |   |
| Distributions to partners (Note 8)                                                 |       | (157.3                                              | )          | (140.4 | ) |
| Borrowings under debt agreements                                                   |       | 2,851.0                                             |       | 2,042.8 |   |
| Repayments of debt                                                                 |       | (2,571.0                                            | )          | (1,979.5 | ) |
| Other                                                                              |       | (1.0                                                | )          | — |   |
| Net cash provided by financing activities                                          |       | 249.2                                               |       | 117.1 |   |
| Net increase in cash and cash equivalents                                          |       | 15.1                                                |       | 29.6 |   |
| Cash and cash equivalents at beginning of year                                     |       | 78.3                                                |       | 64.4 |   |
| Cash and cash  equivalents at end of period                                        |       | $                                                   | 93.4       |   | $ | 94.0 |   |

 

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

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

| ** **                                                                                              | ** ** | **September 30,  2005**           | ** ** | **December 31,  2004** | ** ** |
|---------------------------------------------------------------------------------------------------------|------------|----------------------------------------|------------|-----------------------------|------------|
| ** **                                                                                              | ** ** | **(unaudited; in millions)** | ** ** |
| ***ASSETS***                                                                                            |       |                                   |       |                        |       |   |   |   |   |
| Current assets                                                                                          |       |                                   |       |                        |       |   |   |   |   |
| Cash and cash  equivalents (Note 5)                                                                     |       |                                   | $          | 93.4                        |       |   |   | $ | 78.3 |   |   |
| Receivables, trade and  other, net of allowance for doubtful accounts of $4.3 in 2005 and $4.0 in  2004 |       |                                   | 84.8       |                        |       |   | 71.7 |   |   |
| Due from General Partner  and affiliates                                                                |       |                                   | 13.9       |                        |       |   | 7.7 |   |   |
| Accrued receivables                                                                                     |       |                                   | 717.0      |                        |       |   | 378.2 |   |   |
| Inventory                                                                                               |       |                                   | 147.6      |                        |       |   | 84.5 |   |   |
| Other current assets                                                                                    |       |                                   | 22.8       |                        |       |   | 13.4 |   |   |
|                                                                                                    |       |                                   | 1,079.5    |                        |       |   | 633.8 |   |   |
| Property, plant and  equipment, net (Note 6)                                                            |       |                                   | 3,111.5    |                        |       |   | 2,778.0 |   |   |
| Other assets, net                                                                                       |       |                                   | 26.2       |                        |       |   | 27.7 |   |   |
| Goodwill                                                                                                |       |                                   | 258.2      |                        |       |   | 257.2 |   |   |
| Intangibles, net                                                                                        |       |                                   | 85.6       |                        |       |   | 74.0 |   |   |
|                                                                                                    |       |                                   | $          | 4,561.0                     |       |   |   | $ | 3,770.7 |   |   |
| ***LIABILITIES  AND PARTNERS’ CAPITAL***                                                           |       |                                   |       |                        |       |   |   |   |   |
| Current liabilities                                                                                     |       |                                   |       |                        |       |   |   |   |   |
| Due to General Partner  and affiliates                                                                  |       |                                   | $          | 23.4                        |       |   |   | $ | 9.9 |   |   |
| Accounts payable and  other (Note 5)                                                                    |       |                                   | 271.7      |                        |       |   | 136.4 |   |   |
| Accrued purchases                                                                                       |       |                                   | 736.9      |                        |       |   | 351.4 |   |   |
| Interest payable                                                                                        |       |                                   | 29.6       |                        |       |   | 12.3 |   |   |
| Property and other taxes  payable                                                                       |       |                                   | 24.9       |                        |       |   | 23.3 |   |   |
| Current maturities of  long-term debt                                                                   |       |                                   | 31.0       |                        |       |   | 31.0 |   |   |
|                                                                                                    |       |                                   | 1,117.5    |                        |       |   | 564.3 |   |   |
| Long-term debt (Note 7)                                                                                 |       |                                   | 1,838.4    |                        |       |   | 1,559.4 |   |   |
| Loans from General  Partner and affiliates                                                              |       |                                   | 149.3      |                        |       |   | 142.1 |   |   |
| Environmental  liabilities (Note 8)                                                                     |       |                                   | 5.4        |                        |       |   | 5.3 |   |   |
| Other long-term  liabilities (Note 4)                                                                   |       |                                   | 267.0      |                        |       |   | 101.7 |   |   |
|                                                                                                    |       |                                   | 3,377.6    |                        |       |   | 2,372.8 |   |   |
| Commitments and contingencies (Note 8)                                                                  |       |                                   |       |                        |       |   |   |   |   |
| Partners’ capital                                                                                  |       |                                   |       |                        |       |   |   |   |   |
| Class A common  units (Units issued—46,802,634 in 2005 and 44,296,134 in 2004)                |       |                                   | 1,025.1    |                        |       |   | 1,021.6 |   |   |
| Class B common  units (Units issued—3,912,750 in 2005 and 2004)                               |       |                                   | 62.8       |                        |       |   | 66.7 |   |   |
| i-units (Units  issued—11,497,555 in 2005 and 10,902,409 in 2004)                                  |       |                                   | 408.9      |                        |       |   | 399.4 |   |   |
| General Partner                                                                                         |       |                                   | 31.5       |                        |       |   | 31.0 |   |   |
| Accumulated other  comprehensive loss (Note 4)                                                          |       |                                   | (344.9     | )                           |       |   | (120.8 | ) |   |
|                                                                                                    |       |                                   | 1,183.4    |                        |       |   | 1,397.9 |   |   |
|                                                                                                    |       |                                   | $          | 4,561.0                     |       |   |   | $ | 3,770.7 |   |   |

 

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

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**NOTESTO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)**

**1.**   BASIS OFPRESENTATION

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 September 30,2005 and December 31, 2004; and the results of operations for the threeand nine month periods ended September 30, 2005 and 2004; and cash flowsfor the nine month periods ended September 30, 2005 and 2004. The resultsof operations for the three and nine month periods ended September 30,2005, should not be taken as indicative of the results to be expected for thefull year due to seasonality of portions of the natural gas business,maintenance activities and the impact of forward natural gas prices anddifferentials on certain derivative financial instruments that are accountedfor using mark-to-market accounting. In addition, prior periodinformation presented in these consolidated financial statements includesreclassifications that were made to conform to the current period presentation.These reclassifications have no effect on previously reported net income orpartners’ capital. The interim consolidated financial statements should be readin conjunction with our consolidated financial statements and notes presentedin our Annual Report on Form 10-K for the fiscal year ended December 31,2004.

**2.**   ACQUISITIONS

***North Texas Natural Gas System***

In January 2005,we acquired natural gas gathering and processing assets for $164.6 million incash, including transaction costs of $0.5 million. We funded the acquisitionwith borrowings under our existing credit facilities. The assets acquired servethe Fort Worth Basin, which is mature, but experiencing minimal productiondecline rates and include:

·       2,200miles of gas gathering pipelines; and

·       fourprocessing plants with aggregate processing capacity of 121 million cubic feetof natural gas per day (“MMcf/d”).

The system provides cash flow primarily frompurchasing raw natural gas from producers at the wellhead, processing thenatural gas and then selling the natural gas liquids (“NGL” or “NGLs”) andresidue natural gas streams. The assets and results of operations are includedin our Natural Gas segment from the date of acquisition.

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Thepurchase price and the allocation to assets acquired and liabilities assumedwas as follows (in millions):

| Purchase Price:                                                    |   |   |   |
|--------------------------------------------------------------------|--------|--------|--------|
| Cash paid, including transaction costs                             |   | $      | 164.6  |   |
| Allocation of  purchase price:                                     |   |   |   |
| Property, plant and equipment, including construction  in progress |   | 151.6  |   |
| Intangibles, including contracts                                   |   | 14.3   |   |
| Current liabilities                                                |   | (0.9   | )      |
| Contingent liabilities                                             |   | (0.4   | )      |
| Total                                                              |   | $      | 164.6  |   |

 

***Other Acquisitions***

In June 2005, weacquired for $20.1 million in cash, a natural gas pipeline and relatedfacilities consisting of 92 miles of a 20-inch diameter pipeline thatextends from Pampa, Texas into western Oklahoma and has interconnects with ourAnadarko system. We integrated this pipeline into our existing Anadarko systemand have included the assets and operating results in our Natural Gas segmentfrom the date of acquisition. The purchase price for this acquisition wasallocated to property, plant and equipment for $19.1 million and goodwill for$1.0 million. We have also acquired other gathering and processing assetsduring 2005 for cash totaling approximately $1.7 million.

**3.**   NET INCOME PERCOMMON 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  September 30,**                 | ** ** | **Nine months ended  September 30,**                  | ** ** |
|--------------------------------------------------------------|------------|----------------------------------------------------------------------|------------|----------------------------------------------------------------------|------------|
| ** **                                                   | ** ** | **     2005     ** | ** ** | **     2004     ** | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                                                   | ** ** | **(in millions, except per unit amounts)**  | ** ** |
| Net income (loss)                                            |       |                                                                 | $          | (14.4                                                                | )          |   |   | $ | 27.6 |   |   | $ | 39.5 |   | $ | 96.6 |   |
| Allocations to  the General Partner:                         |       |                                                                 |       |                                                                 |       |   |   |   |   |   |   |   |   |
| Net (income) loss allocated to General Partner               |       |                                                                 | 0.3        |                                                                 |       |   | (0.5 | ) |   | (0.8 | ) | (1.9 | ) |
| Incentive distributions to General Partner                   |       |                                                                 | (5.4       | )                                                                    |       |   | (5.0 | ) |   | (16.0 | ) | (14.5 | ) |
| Historical cost depreciation adjustments                     |       |                                                                 | —     |                                                                 |       |   | — |   |   | (0.1 | ) | (0.1 | ) |
|                                                         |       |                                                                 | (5.1       | )                                                                    |       |   | (5.5 | ) |   | (16.9 | ) | (16.5 | ) |
| Net income (loss)  allocable to common and i-units           |       |                                                                 | $          | (19.5                                                                | )          |   |   | $ | 22.1 |   |   | $ | 22.6 |   | $ | 80.1 |   |
| Weighted average units outstanding                           |       |                                                                 | 62.1       |                                                                 |       |   | 55.7 |   |   | 61.5 |   | 55.1 |   |
| Net income (loss)  per common and i-unit (basic and diluted) |       |                                                                 | $          | (0.32                                                                | )          |   |   | $ | 0.39 |   |   | $ | 0.37 |   | $ | 1.45 |   |

 

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**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/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 noncash earnings volatility that arises under mark-to-marketaccounting treatment. To qualify for cash flow hedge accounting, very specificrequirements must be met in terms of hedge structure, hedge objective and hedgedocumentation.

***Non-Qualified Hedges***

Many of our derivative financial instruments qualifyfor hedge accounting treatment under the specific requirements of SFAS No. 133.However, we have three primary instances where the hedge structure does notmeet the requirements to apply hedge accounting and, therefore, these financialinstruments are considered ‘non-qualified’ under SFAS No. 133. Thesenon-qualified derivative financial instruments must be adjusted to their fairmarket value, or marked-to-market, each period, with the increasesand decreases in fair value recorded as increases and decreases in Cost ofnatural gas in our Consolidated Statements of Income. These mark-to-marketadjustments produce a degree of earnings volatility that can often be 

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significant from period toperiod, but have no cash flow impact relative to changes in market prices. Thecash flow impact occurs when the underlying physical transaction takes place inthe future and an associated financial 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.This can occur because we have the flexibility to make these changes in the underlyinginjection or withdrawal schedule, given changes in market conditions.Therefore, these transactions do not qualify for hedge accounting treatmentunder SFAS No. 133, as the forecasted transaction is no longer probable ofoccurring as originally set forth in the hedge documentation established at theinception 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 and contemporaneously re-designated thenatural gas collars as hedges of physical natural gas sales with a NYMEXpricing index to better match the indices, which was a sound economic hedgingstrategy. However, because the fair value of these derivative instruments was aliability to us at re-designation, they are considered net writtenoptions under SFAS No. 133 and do not qualify for hedge accounting. Thesederivatives are now accounted for in the Consolidated Statements of Incomethrough mark-to-market accounting, with the changes in fair valuefrom the date of de-designation recorded to earnings each period. As aresult, our operating income will be subject to greater volatility due tomovements in the prices of natural gas until the underlying long-termtransactions are settled.

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

***Discontinuance of Hedge Accounting***

During the second quarter of 2005, we discontinuedapplication of hedge accounting in connection with some of our derivativefinancial instruments designated as hedges of forecasted sales and purchases ofnatural gas. We discontinued application of hedge accounting when we determinedit was no longer probable that the originally forecasted purchases and sales ofnatural gas would occur by the end of the originally specified time period, orwithin an additional two-month period of time thereafter. As discussed above,this can occur because we have the flexibility to make changes to the underlyingdelivery points for 

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our transportation assetsand to the underlying injection or withdrawal schedule for our storage assets,given changes in market conditions. One of the key criteria to achieve hedgeaccounting under SFAS No. 133 is that the forecasted transaction beprobable of occurring as originally set forth in the hedge documentation. As aresult, during the second quarter of 2005, we recognized previously deferredunrealized losses in our Marketing segment of approximately $9.0 million fromthe discontinuance of hedge accounting. In doing so, we reclassified the $9.0million to Cost of natural gas on our Consolidated Statements of Income fromOCI. Going forward, the discontinued derivative financial instruments areconsidered to be non-qualified under SFAS No. 133, and must be marked-to-marketeach period, with the increases and decreases in fair value recorded asincreases and decreases in earnings. Also included in the loss fromdiscontinuance are approximately $2.1 million of net mark-to-market losses thatrelate to hedge positions that were closed out during the second quarter.

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  September 30,** | ** ** | **Nine months ended  September 30,** | ** ** |
|--------------------------------------------------------------|------------|------------------------------------------------------|------------|-----------------------------------------------------|------------|
| **Derivative fair value gains (losses)** | ** ** | ** **                                           | ** ** | **   2005   **        | ** ** | **   2004   ** | ** ** | **   2005   ** | ** ** | **   2004   ** | ** ** |
| ** **                                                   | ** ** | **(in millions)**                               | ** ** |
| Natural Gas  segment                                         |       |                                                 |       |                                                |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Ineffectiveness                                              |       |                                                 | $          | 0.1                                                 |       |   |   | $ | — |   |   |   | $ | (1.9 | ) |   |   | $ | — |   |   |
| Non-qualified hedges                                         |       |                                                 | (9.6       | )                                                   |       |   | — |   |   |   | (20.7 | ) |   |   | — |   |   |
| Marketing                                                    |       |                                                 |       |                                                |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Non-qualified hedges                                         |       |                                                 | (43.1      | )                                                   |       |   | 0.3 |   |   |   | (37.8 | ) |   |   | (1.4 | ) |   |
| Discontinuance                                               |       |                                                 | —     |                                                |       |   | — |   |   |   | (9.0 | ) |   |   | — |   |   |
| Derivative fair value  gains (losses)                        |       |                                                 | $          | (52.6                                               | )          |   |   | $ | 0.3 |   |   |   | $ | (69.4 | ) |   |   | $ | (1.4 | ) |   |
|                                                              |            |                                                      |            |                                                     |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

We record the change in fair value of our highlyeffective cash flow hedges in our OCI until the derivative financialinstruments are settled, at which time they are reclassified to earnings. Forthe three and nine months ended September 30, 2005, we reclassifiedunrealized losses of $11.5 million and $36.7 million from OCI to Cost ofnatural gas on our Consolidated Statements of Income for the fair value ofderivative financial instruments that were settled.

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

| ** **                   | ** ** | **September 30,  2005** | ** ** | **December 31,  2004** | ** ** |
|------------------------------|------------|------------------------------|------------|-----------------------------|------------|
| ** **                   | ** ** | **(in millions)**       | ** ** |
| Receivables, trade and other |       |                         | $          | 16.2                        |       |   |   | $ | 8.2 |   |   |
| Other assets, net            |       |                         | 7.0        |                        |       |   | 10.1 |   |   |
| Accounts payable  and other  |       |                         | (177.9     | )                           |       |   | (45.9 | ) |   |
| Other long-term  liabilities |       |                         | (264.4     | )                           |       |   | (99.6 | ) |   |
|                         |       |                         | $          | (419.1                      | )          |   |   | $ | (127.2 | ) |   |

 

The increase in our obligation associated with ourderivative activities from December 31, 2004 to September 30, 2005 isprimarily due to the significant increases in forward natural gas and NGLprices. The Partnership’s portfolio of derivative financial instruments islargely comprised of long-term fixed price sales agreements.

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

**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$29.8 million at September 30, 2005 and $25.3 million at December 31,2004, are included in Accounts payable and other on the Consolidated Statementsof Financial Position.

**6.**   PROPERTY, PLANT ANDEQUIPMENT

Based on a third-partystudy commissioned by management, revised depreciation rates for the Anadarko,North Texas and East Texas systems were implemented effective August 1,2005. The annual composite rate, which represents the expected remainingservice life of these natural gas systems, was reduced from 4.0% to 3.4%.Depreciation expense for the three and nine months ended September 30,2005 was approximately $1.0 million lower as a result of the new depreciationrates.

**7.**   DEBT

***Amendments to Credit Agreement***

In April 2005, we entered into the thirdamendment to the Amended and Restated Credit Agreement dated as of January 24,2003 (as amended, the “Credit Facility”) to, among other things, extend thematurity of the Credit Facility for a period of five years to April 2010;increase the letter of credit sub limit from $100 million to$175 million; and grant us the right to request, subject to approval bythe Board of Directors of Enbridge Energy Management, L.L.C. (“Enbridge Management”),an increase in commitments available under the Credit Facility up to anaggregate outstanding principal amount of $1 billion.

In September 2005, weentered into the fourth amendment to the Credit Facility to, among otherthings, extend the letter of credit sub limit from $175 million to $300million, increase the commitments available under the Credit Facility from $600million to $800 million, decrease the “Applicable Rate” as set forth in theCredit Facility, and extend from September 2005 to December 31, 2006,the requirement to maintain a Consolidated Leverage Ratio, as defined in theCredit Facility, of not more than 5.25 to 1. At September 30, 2005, wehave no outstanding borrowings under the Credit Facility.

***Commercial Paper Program***

In April 2005, we successfully entered thecommercial paper market with the establishment of our $600 million commercialpaper program that is supported by our long-term Credit Facility. We access thecommercial paper market primarily to provide temporary financing for ouroperating activities, capital expenditures and acquisitions, at rates that aregenerally lower than the rates available under our Credit Facility. We repaidthe entire amount previously outstanding under our Credit Facility withproceeds we obtained from issuing commercial paper under this program. OurCredit Facility remains undrawn and available to support our commercial paperprogram. Under the terms of our commercial paper program, we can issue up to$600 million of commercial paper. However, the amount of commercial paper wemay issue is reduced by any balance of outstanding letters of credit in excessof $200 million. At September 30, 2005, we had outstanding $455.0 millionof commercial paper at a weighted average interest rate of 3.84% andoutstanding letters of credit totaling $179.6 million. At September 30,2005, we could issue an additional $145 million under our commercial paperprogram.

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**8.**   PARTNERS’ CAPITAL

Thefollowing table sets forth the distributions, as approved by the Board ofDirectors of Enbridge Management through September 30, 2005:

| **Distribution  Declaration  Date** | ** ** | **Distribution  Payment Date** | ** ** | **Ex-Distribution  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)** | ** ** |
| July 28, 2005                  |       | August 12,  2005               |       | August 5,  2005      |       |                            | $          | 0.925                                                               |       |                                                                          |       | $                                       | 64.0       |                           |       |   | $ | 10.5 |   |   |   | $ | 0.2 |   |   |   | $ | 53.3 |   |   |
| April 25, 2005                 |       | May 13,  2005                  |       | May 4,  2005         |       |                            | 0.925      |                                                                |       |                                                                          | 63.8       |                                    |       |                           | 10.3       |   |   |   | 0.2 |   |   |   | 53.3 |   |   |
| January 24, 2005               |       | February 14,  2005             |       | February 3,  2005    |       |                            | 0.925      |                                                                |       |                                                                          | 61.0       |                                    |       |                           | 10.1       |   |   |   | 0.2 |   |   |   | 50.7 |   |   |
|                                |       |                                |       |                      |       |                            |       |                                                                |       |                                                                          | $          | 188.8                                   |       |                           |       | $ | 30.9 |   |   |   | $ | 0.6 |   |   |   | $ | 157.3 |   |   |

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(1)                 The Partnershiphas issued 595,146 i-units to Enbridge Management, the sole owner of thePartnership’s i-units during 2005 in lieu of cash distributions.

(2)                 The Partnershipretains an amount equal to 2% of the i-unit distribution from the GeneralPartner in respect of its 2% general partner interest.

***Common unit offering***

On February 11, 2005,we issued 2,506,500 Class A common units at $49.875 per unit, whichgenerated proceeds of approximately $124.8 million, net of offering expenses.Additionally, the General Partner contributed $2.7 million to us tomaintain its 2% general partner interest in the Partnership. We used theproceeds from this offering to repay amounts outstanding under our CreditFacility.

**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 September 30,2005 and December 31, 2004, we have recorded $4.2 million and$3.6 million in current liabilities and $5.4 million and$5.3 million in long-term liabilities, respectively, primarily toaddress remediation of contaminated sites, asbestos containing materials, managementof hazardous waste material disposal, and outstanding air quality measures forcertain liquids and natural gas assets.

***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.**   SEGMENT INFORMATION

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

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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.

Thefollowing tables present certain financial information relating to our businesssegments:

| ** **                                     | ** ** | **As of and for the three months ended September 30, 2005** | ** ** |
|------------------------------------------------|------------|---------------------------------------------------------------------------------------------------------------|------------|
| ** **                                     | ** ** | **Liquids**                                                                                                   | ** ** | **Natural Gas** | ** ** | **Marketing** | ** ** | **Corporate** | ** ** | **Total** | ** ** |
| ** **                                     | ** ** | **(in millions)**                                                                                        | ** ** |
| Total revenue                                  |       | $                                                                                                             | 104.1      |   |   | $ | 1,267.5 |   |   |   | $ | 1,162.6 |   |   |   | $ | — |   |   | $ | 2,534.2 |   |
| Less:  Intersegment revenue                    |       | —                                                                                                        |       |   | 669.6 |   |   |   | 55.0 |   |   |   | — |   |   | 724.6 |   |
| Operating revenue                              |       | 104.1                                                                                                         |       |   | 597.9 |   |   |   | 1,107.6 |   |   |   | — |   |   | 1,809.6 |   |
| Cost of natural  gas (Note 4)                  |       | —                                                                                                        |       |   | 513.9 |   |   |   | 1,145.9 |   |   |   | — |   |   | 1,659.8 |   |
| Operating and  administrative                  |       | 36.1                                                                                                          |       |   | 44.3 |   |   |   | 1.4 |   |   |   | 0.6 |   |   | 82.4 |   |
| Power                                          |       | 19.0                                                                                                          |       |   | — |   |   |   | — |   |   |   | — |   |   | 19.0 |   |
| Depreciation and  amortization                 |       | 18.3                                                                                                          |       |   | 18.1 |   |   |   | 0.1 |   |   |   | — |   |   | 36.5 |   |
| Operating income                               |       | 30.7                                                                                                          |       |   | 21.6 |   |   |   | (39.8 | ) |   |   | (0.6 | ) |   | 11.9 |   |
| Interest expense                               |       | —                                                                                                        |       |   | — |   |   |   | — |   |   |   | (28.4 | ) |   | (28.4 | ) |
| Other income                                   |       | —                                                                                                        |       |   | — |   |   |   | — |   |   |   | 2.1 |   |   | 2.1 |   |
| Net income (loss)                              |       | $                                                                                                             | 30.7       |   |   | $ | 21.6 |   |   |   | $ | (39.8 | ) |   |   | $ | (26.9 | ) |   | $ | (14.4 | ) |
| Capital  expenditures (excluding acquisitions) |       | $                                                                                                             | 17.3       |   |   | $ | 69.2 |   |   |   | $ | — |   |   |   | $ | 0.7 |   |   | $ | 87.2 |   |

 

| ** **                                     | ** ** | **As of and for the three months ended September 30, 2004** | ** ** |
|------------------------------------------------|------------|---------------------------------------------------------------------------------------------------------------|------------|
| ** **                                     | ** ** | **Liquids**                                                                                                   | ** ** | **Natural Gas** | ** ** | **Marketing** | ** ** | **Corporate** | ** ** | **Total** | ** ** |
| ** **                                     | ** ** | **(in millions)**                                                                                        | ** ** |
| Total revenue                                  |       | $                                                                                                             | 107.1      |   |   | $ | 659.0 |   |   |   | $ | 659.6 |   |   |   | $ | — |   |   | $ | 1,425.7 |   |
| Less:  Intersegment revenue                    |       | —                                                                                                        |       |   | 384.1 |   |   |   | 36.8 |   |   |   | — |   |   | 420.9 |   |
| Operating revenue                              |       | 107.1                                                                                                         |       |   | 274.9 |   |   |   | 622.8 |   |   |   | — |   |   | 1,004.8 |   |
| Cost of natural  gas (Note 4)                  |       | —                                                                                                        |       |   | 204.2 |   |   |   | 620.3 |   |   |   | — |   |   | 824.5 |   |
| Operating and  administrative                  |       | 32.0                                                                                                          |       |   | 33.3 |   |   |   | 0.8 |   |   |   | 1.2 |   |   | 67.3 |   |
| Power                                          |       | 19.7                                                                                                          |       |   | — |   |   |   | — |   |   |   | — |   |   | 19.7 |   |
| Depreciation and  amortization                 |       | 17.6                                                                                                          |       |   | 14.0 |   |   |   | — |   |   |   | 0.1 |   |   | 31.7 |   |
| Operating income                               |       | 37.8                                                                                                          |       |   | 23.4 |   |   |   | 1.7 |   |   |   | (1.3 | ) |   | 61.6 |   |
| Interest expense                               |       | —                                                                                                        |       |   | — |   |   |   | — |   |   |   | (22.2 | ) |   | (22.2 | ) |
| Rate refunds                                   |       | —                                                                                                        |       |   | — |   |   |   | — |   |   |   | (12.0 | ) |   | (12.0 | ) |
| Other income                                   |       | —                                                                                                        |       |   | — |   |   |   | — |   |   |   | 0.2 |   |   | 0.2 |   |
| Net income                                     |       | $                                                                                                             | 37.8       |   |   | $ | 23.4 |   |   |   | $ | 1.7 |   |   |   | $ | (35.3 | ) |   | $ | 27.6 |   |
| Capital  expenditures (excluding acquisitions) |       | $                                                                                                             | 29.8       |   |   | $ | 71.8 |   |   |   | $ | — |   |   |   | $ | 2.2 |   |   | $ | 103.8 |   |

 

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| ** **                                    | ** ** | **As of and for the nine months ended September 30, 2005** | ** ** |
|-----------------------------------------------|------------|--------------------------------------------------------------------------------------------------------------|------------|
| ** **                                    | ** ** | **Liquids**                                                                                                  | ** ** | **Natural Gas** | ** ** | **Marketing** | ** ** | **Corporate** | ** ** | **Total** | ** ** |
| ** **                                    | ** ** | **(in millions)**                                                                                       | ** ** |
| Total revenue                                 |       | $                                                                                                            | 303.1      |   |   | $ | 3,180.1 |   |   |   | $ | 2,658.5 |   |   |   | $ | — |   |   | $ | 6,141.7 |   |
| Less: Intersegment  revenue                   |       | —                                                                                                       |       |   | 1,635.3 |   |   |   | 114.0 |   |   |   | — |   |   | 1,749.3 |   |
| Operating revenue                             |       | 303.1                                                                                                        |       |   | 1,544.8 |   |   |   | 2,544.5 |   |   |   | — |   |   | 4,392.4 |   |
| Cost of natural gas  (Note 4)                 |       | —                                                                                                       |       |   | 1,299.9 |   |   |   | 2,582.5 |   |   |   | — |   |   | 3,882.4 |   |
| Operating and  administrative                 |       | 105.5                                                                                                        |       |   | 126.3 |   |   |   | 3.1 |   |   |   | 2.3 |   |   | 237.2 |   |
| Power                                         |       | 53.2                                                                                                         |       |   | — |   |   |   | — |   |   |   | — |   |   | 53.2 |   |
| Depreciation and  amortization                |       | 53.6                                                                                                         |       |   | 49.9 |   |   |   | 0.4 |   |   |   | — |   |   | 103.9 |   |
| Operating income                              |       | 90.8                                                                                                         |       |   | 68.7 |   |   |   | (41.5 | ) |   |   | (2.3 | ) |   | 115.7 |   |
| Interest expense                              |       | —                                                                                                       |       |   | — |   |   |   | — |   |   |   | (79.6 | ) |   | (79.6 | ) |
| Other income                                  |       | —                                                                                                       |       |   | — |   |   |   | — |   |   |   | 3.4 |   |   | 3.4 |   |
| Net income                                    |       | $                                                                                                            | 90.8       |   |   | $ | 68.7 |   |   |   | $ | (41.5 | ) |   |   | $ | (78.5 | ) |   | $ | 39.5 |   |
| Total Assets                                  |       | $                                                                                                            | 1,672.8    |   |   | $ | 2,239.4 |   |   |   | $ | 557.4 |   |   |   | $ | 91.4 |   |   | $ | 4,561.0 |   |
| Goodwill                                      |       | $                                                                                                            | —     |   |   | $ | 237.8 |   |   |   | $ | 20.4 |   |   |   | $ | — |   |   | $ | 258.2 |   |
| Capital expenditures (excluding acquisitions) |       | $                                                                                                            | 52.0       |   |   | $ | 206.5 |   |   |   | $ | — |   |   |   | $ | 3.4 |   |   | $ | 261.9 |   |

 

| ** **                                    | ** ** | **As of and for the nine months ended September 30, 2004** | ** ** |
|-----------------------------------------------|------------|--------------------------------------------------------------------------------------------------------------|------------|
| ** **                                    | ** ** | **Liquids**                                                                                                  | ** ** | **Natural Gas** | ** ** | **Marketing** | ** ** | **Corporate** | ** ** | **Total** | ** ** |
| ** **                                    | ** ** | **(in millions)**                                                                                       | ** ** |
| Total revenue                                 |       | $                                                                                                            | 301.5      |   |   | $ | 1,953.9 |   |   |   | $ | 1,921.0 |   |   |   | $ | — |   |   | $ | 4,176.4 |   |
| Less: Intersegment  revenue                   |       | —                                                                                                       |       |   | 1,109.4 |   |   |   | 110.0 |   |   |   | — |   |   | 1,219.4 |   |
| Operating revenue                             |       | 301.5                                                                                                        |       |   | 844.5 |   |   |   | 1,811.0 |   |   |   | — |   |   | 2,957.0 |   |
| Cost of natural gas  (Note 4)                 |       | —                                                                                                       |       |   | 639.8 |   |   |   | 1,804.0 |   |   |   | — |   |   | 2,443.8 |   |
| Operating and  administrative                 |       | 93.2                                                                                                         |       |   | 99.0 |   |   |   | 2.4 |   |   |   | 3.2 |   |   | 197.8 |   |
| Power                                         |       | 54.0                                                                                                         |       |   | — |   |   |   | — |   |   |   | — |   |   | 54.0 |   |
| Depreciation and  amortization                |       | 50.5                                                                                                         |       |   | 38.6 |   |   |   | — |   |   |   | 0.1 |   |   | 89.2 |   |
| Operating income                              |       | 103.8                                                                                                        |       |   | 67.1 |   |   |   | 4.6 |   |   |   | (3.3 | ) |   | 172.2 |   |
| Interest expense                              |       | —                                                                                                       |       |   | — |   |   |   | — |   |   |   | (65.8 | ) |   | (65.8 | ) |
| Rate refunds                                  |       | —                                                                                                       |       |   | — |   |   |   | — |   |   |   | (12.0 | ) |   | (12.0 | ) |
| Other income                                  |       | —                                                                                                       |       |   | — |   |   |   | — |   |   |   | 2.2 |   |   | 2.2 |   |
| Net income                                    |       | $                                                                                                            | 103.8      |   |   | $ | 67.1 |   |   |   | $ | 4.6 |   |   |   | $ | (78.9 | ) |   | $ | 96.6 |   |
| Total assets                                  |       | $                                                                                                            | 1,665.8    |   |   | $ | 1,653.0 |   |   |   | $ | 252.7 |   |   |   | $ | 29.5 |   |   | $ | 3,601.0 |   |
| Goodwill                                      |       | $                                                                                                            | —     |   |   | $ | 236.6 |   |   |   | $ | 20.4 |   |   |   | $ | — |   |   | $ | 257.0 |   |
| Capital expenditures (excluding acquisitions) |       | $                                                                                                            | 56.6       |   |   | $ | 114.5 |   |   |   | $ | — |   |   |   | $ | 3.5 |   |   | $ | 174.6 |   |

 

**11.**   SUBSEQUENTEVENTS

***Distribution toPartners***

On October 26, 2005,Enbridge Management’s Board of Directors declared a distribution payable to ourpartners on November 14, 2005. The distribution will be paid tounitholders of record as of November 3, 2005, of our available cash of$64.1 million at September 30, 2005, or $0.925 per common unit. Ofthis distribution, $53.3 million will be paid in cash, $10.6 millionwill be distributed in i-units to our i-unitholder and$0.2 million will be retained from the General Partner in respect of thisi-unit distribution.

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***Gathering andProcessing Asset Sale***

On October 20, 2005,we entered into agreements to sell a processing plant and related facilitiesand other gathering and processing assets located in our East and South Texassystems for $106.0 million. The facilities represent non-strategic assetswithin our Natural Gas segment and are not in our core geographic areas ofinterest. We intend to use the proceeds from this sale to finance otherprojects in our core geographic areas of interest.

**12.**   RECENTACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED

***Accounting forConditional Asset Retirement Obligations***

In March 2005, theFinancial Accounting Standards Board (“FASB”) issued FASB Interpretation No. 47,*Accounting for Conditional Asset RetirementObligations, an interpretation of FASB Statement No. 143*. Thisinterpretation clarifies the meaning of “conditional asset retirementobligation” as used in FASB Statement No. 143, *Accounting for Asset Retirement Obligations*, as referring to a legal obligationto perform an asset retirement activity where the timing and/or method ofsettlement are conditional on a future event that may or may not be within thecontrol of an entity. The obligation to perform the retirement activity isunconditional even though uncertainty may exist about the timing and/or methodof settlement. The interpretation requires an entity to recognize a liabilityfor the fair value of a conditional asset retirement obligation if the fairvalue of the liability can be reasonably estimated. This interpretation iseffective no later than the end of fiscal years ending after December 15,2005. We are currently evaluating the effect that application of thisinterpretation will have on our financial statements.

***Accounting Changesand Error Corrections***

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

***FERC Guidance onAccounting for Integrity Management Costs***

In June 2005, the Federal Energy RegulatoryCommission (“FERC”) issued guidance describing how FERC-regulated companiesshould account for costs associated with implementing the pipeline integritymanagement requirements of the U.S. Department of Transportation’s Office ofPipeline Safety. Under the guidance, costs to 1) prepare a plan to implementthe program, 2) identify high consequence areas, 3) develop and maintain arecord keeping system and 4) inspect, test and report on the condition ofaffected pipeline segments to determine the need for repairs or replacements,are required to be expensed. Costs of modifying pipelines to permit in-lineinspections, certain costs associated with developing or enhancing computersoftware and costs associated with remedial and mitigation actions to correctan identified condition can be capitalized. The guidance is effective January 1,2006, to be applied prospectively. We are currently evaluating the effect thatapplication of this order will have on our financial statements.

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

**RESULTSOF OPERATIONS—OVERVIEW**

Weprovide services to our customers and provide returns for our unitholdersprimarily through the following activities:

·       Interstatetransportation and storage of crude oil and liquid petroleum;

·       Gathering,treating, processing and transmission of natural gas; and

·       Providingsupply, transmission and sales services, including purchasing and sellingnatural gas and natural gas liquids (“NGLs”).

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.

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.

The following tablereflects operating income by business segment and corporate charges for each ofthe periods presented.

| ** **                              | ** ** | **Three months ended  September 30,** | ** ** | **Nine months ended  September 30,** | ** ** |
|-----------------------------------------|------------|------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                              | ** ** | **   2005   **         | ** ** | **   2004   **        | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                              | ** ** | **(unaudited; in millions)**               | ** ** |
| **Operating Income**                    |       |                                                 |       |                                                |       |   |   |   |   |   |   |   |   |
| Liquids                                 |       |                                                 | $          | 30.7                                                |       |   |   | $ | 37.8 |   |   | $ | 90.8 |   | $ | 103.8 |   |
| Natural Gas                             |       |                                                 | 21.6       |                                                |       |   | 23.4 |   |   | 68.7 |   | 67.1 |   |
| Marketing                               |       |                                                 | (39.8      | )                                                   |       |   | 1.7 |   |   | (41.5 | ) | 4.6 |   |
| Corporate, operating and administrative |       |                                                 | (0.6       | )                                                   |       |   | (1.3 | ) |   | (2.3 | ) | (3.3 | ) |
| **Total Operating Income**              |       |                                                 | 11.9       |                                                |       |   | 61.6 |   |   | 115.7 |   | 172.2 |   |
| Interest expense                        |       |                                                 | (28.4      | )                                                   |       |   | (22.2 | ) |   | (79.6 | ) | (65.8 | ) |
| Rate refunds                            |       |                                                 | —     |                                                |       |   | (12.0 | ) |   | — |   | (12.0 | ) |
| Other income                            |       |                                                 | 2.1        |                                                |       |   | 0.2 |   |   | 3.4 |   | 2.2 |   |
| **Net  Income (Loss)**                  |       |                                                 | $          | (14.4                                               | )          |   |   | $ | 27.6 |   |   | $ | 39.5 |   | $ | 96.6 |   |

 

Our results for ourNatural Gas and Marketing businesses for the three and nine months ended September 30,2005, were adversely affected by significant non-cash volatility associatedwith our portfolio of derivative financial instruments that do not qualify forhedge accounting treatment under SFAS No. 133. Under SFAS No. 133,all financial instruments are recorded in the consolidated financial statementsat fair market value. For those financial instruments that do not qualify forhedge accounting, all changes in fair market value are recorded through theConsolidated Statements of Income each period. The 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,although that is not our intent.

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A volatile naturalgas and NGL pricing environment during the three and nine months ended September 30,2005, produced non-cash mark-to-market losses of $52.6 million and $67.3million, respectively, and negatively affected our results. While thesemark-to-market losses create volatility in our results, they do not affect ourcash flow. We expect to offset these non-cash losses in future quarters as wesettle the derivative financial instruments and the underlying physicaltransactions.

The following tablepresents the unrealized, non-cash, mark-to-market gains and losses by segment,associated with our derivative financial instruments for the three and ninemonth periods ended September 30, 2005 and 2004:

| ** **                                                   | ** ** | **Three months ended  September 30,** | ** ** | **Nine months ended  September 30,**      | ** ** |
|--------------------------------------------------------------|------------|------------------------------------------------------|------------|----------------------------------------------------------|------------|
| **Derivative fair value gains (losses)** | ** ** | ** **                                           | ** ** | **    2005    ** | ** ** | **    2004    ** | ** ** | **    2005    ** | ** ** | **    2004    ** | ** ** |
| ** **                                                   | ** ** | **(in millions)**                               | ** ** |
| Natural Gas  segment                                         |       |                                                 |       |                                                     |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Ineffectiveness                                              |       |                                                 | $          | 0.1                                                      |       |   |   | $ | — |   |   |   | $ | (1.9 | ) |   |   | $ | — |   |   |
| Non-qualified hedges                                         |       |                                                 | (9.6       | )                                                        |       |   | — |   |   |   | (20.7 | ) |   |   | — |   |   |
| Marketing                                                    |       |                                                 |       |                                                     |       |   |   |   |   |   |   |   |   |   |   |   |   |
| Non-qualified hedges                                         |       |                                                 | (43.1      | )                                                        |       |   | 0.3 |   |   |   | (37.8 | ) |   |   | (1.4 | ) |   |
| Discontinuance                                               |       |                                                 | —     |                                                     |       |   | — |   |   |   | (9.0 | ) |   |   | — |   |   |
| Derivative fair value  loss                                  |       |                                                 | $          | (52.6                                                    | )          |   |   | $ | 0.3 |   |   |   | $ | (69.4 | ) |   |   | $ | (1.4 | ) |   |
|                                                              |            |                                                      |            |                                                          |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

 

Average daily volumes ofour Natural Gas operations for the three and nine months ended September 30,2005, were up 17 percent and 20 percent, respectively over the comparableperiods in 2004. The increase in volumes is attributable to historically highnatural gas and NGL prices, which encourage producers to generate greatervolumes of natural gas and NGL. Additionally, during the quarter we benefitedfrom completion of the construction of our East Texas expansion project whichwas placed in service late in the second quarter of 2005, and partiallyalleviated physical pipeline constraints being experienced by our Natural Gasand Marketing segments. The favorable effect of these higher volumes was offsetby continued lower transportation volumes in our Liquids segment and non-cashmark-to-market losses related to our derivative transactions that do notqualify for hedge accounting treatment under SFAS No. 133.

During the thirdquarter of 2005, we sustained minor damage to our on- and offshore natural gasgathering and processing facilities as a result of hurricanes Katrina and Rita.Our facilities in Mississippi and Louisiana sustained physical damage,including a CO2 processing plant, four tractor vehicles used totransport bulk liquid trailers, several compressor stations and on-siteoffices, in addition to electrical equipment and process controls that weredamaged due to flooding. Certain of our other natural gas gathering andprocessing systems were indirectly affected by third-party facility disruptionsresulting from the storms. These temporary disruptions curtailed our ability togather unprocessed natural gas at our processing plants. However, we were ableto substantially mitigate the impact of extensive gathering and processingsystem shutdowns by arranging for NGLs to be transported from our plants bytruck and by working with the interconnecting natural gas pipelines to managenatural gas quality at major receipt points. Although we continue to assess thedamage caused by these two hurricanes, we do not expect the effect on netincome to be more than $5 million during 2005, including lost revenue less costof natural gas resulting from system downtime and repairs. We do not anticipaterecovery of any significant amounts from insurance for these losses. We expectthat a majority of our facilities will return to normal operation before yearend.

In January 2005, weacquired natural gas gathering and processing assets in North Texas. Thefacilities acquired include approximately 2,200 miles of natural gasgathering pipelines and four natural gas processing plants with an aggregateprocessing capacity of 121 million cubic feet per day (“MMcf/d”) of 

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naturalgas. This system predominantly serves producers in the Fort Worth BasinConglomerate formation and is located in an area where we expect futuredrilling by producers extending the Barnett Shale play’s western side. Wecombined these assets with our existing North Texas assets and have includedthem in the operating results of our Natural Gas segment from the date ofacquisition. In late June 2005, we also acquired an idle 92-milenatural gas pipeline that extends from the Texas Panhandle to Western Oklahomawhich we integrated with our existing Anadarko system. We expect this pipelineto improve service to existing customers and allow us to attract additionalproduction in future periods. We have also acquired other small pipelines thatare complementary to our existing natural gas assets.

**RESULTSOF OPERATIONS—BY SEGMENT**

***Liquids***

The following tables setforth the operating results and statistics of our Liquids segment assets forthe periods presented:

| ** **                              | ** ** | **Three months ended  September 30,** | ** ** | **Nine months ended  September 30,** | ** ** |
|-----------------------------------------|------------|------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                              | ** ** | **   2005   **         | ** ** | **   2004   **        | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                              | ** ** | **(unaudited; in millions)**               | ** ** |
| **Operating Results**                   | ** ** |                                                 | ** ** | ** **                                          |       |   | ** ** | ** ** |   | ** ** | ** ** | ** ** | ** ** |
| Operating  revenues                     |       |                                                 | $          | 104.1                                               | ** ** |   |   | $ | 107.1 | ** ** |   | $ | 303.1 |   | $ | 301.5 |   |
| Operating and  administrative           |       |                                                 | (36.1      | )                                                   |       |   | (32.0 | ) |   | (105.5 | ) | (93.2 | ) |
| Power                                   |       |                                                 | (19.0      | )                                                   |       |   | (19.7 | ) |   | (53.2 | ) | (54.0 | ) |
| Depreciation and  amortization          |       |                                                 | (18.3      | )                                                   |       |   | (17.6 | ) |   | (53.6 | ) | (50.5 | ) |
| Operating  expenses                     |       |                                                 | (73.4      | )                                                   |       |   | (69.3 | ) |   | (212.3 | ) | (197.7 | ) |
| **Operating Income**                    |       |                                                 | $          | 30.7                                                |       |   |   | $ | 37.8 |   |   | $ | 90.8 |   | $ | 103.8 |   |
| **Operating  Statistics**               |       |                                                 |       |                                                |       |   |   |   |   |   |   |   |   |
| **Lakehead  system:**                   |       |                                                 |       |                                                |       |   |   |   |   |   |   |   |   |
| United States(1)                        |       |                                                 | 1,007      |                                                |       |   | 1,063 |   |   | 1,023 |   | 1,060 |   |
| Province of Ontario(1)                  |       |                                                 | 283        |                                                |       |   | 331 |   |   | 295 |   | 359 |   |
| **Total deliveries**(1)                 |       |                                                 | 1,290      |                                                |       |   | 1,394 |   |   | 1,318 |   | 1,419 |   |
| **Barrel miles (billions)**             |       |                                                 | 82         |                                                |       |   | 92 |   |   | 249 |   | 274 |   |
| **Average haul (miles)**                |       |                                                 | 691        |                                                |       |   | 715 |   |   | 691 |   | 705 |   |
| **Mid-Continent  system deliveries**(1) |       |                                                 | 259        |                                                |       |   | 264 |   |   | 225 |   | 236 |   |
| **North Dakota system deliveries**(1)   |       |                                                 | 84         |                                                |       |   | 85 |   |   | 87 |   | 81 |   |

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

***Three months ended September 30,2005 compared with three months ended September 30, 2004***

OurLiquids segment accounted for $30.7 million of operating income during thethree months ended September 30, 2005, representing a decrease of $7.1million over the same period in 2004. Lower results on the Lakehead andMid-Continent systems were slightly offset by stronger results on the NorthDakota system.

Operating revenue for thethird quarter of 2005 decreased by approximately $3.0 million to $104.1 millionfrom $107.1 million for the same period in 2004. Overall tariff increases andlonger hauls on our North Dakota system were more than offset by lowerdeliveries on our Lakehead system.

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Increases in averagetariffs on all three Liquids systems resulted in higher operating revenue byapproximately $3.4 million. These tariff increases were mostly the result of theannual index rate increase of approximately 3.63% allowed by the Federal EnergyRegulatory Commission (“FERC”) effective July 1, 2005, on our base systemtariffs. On the 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 third quarter of 2004. Longerhauls on our North Dakota system also contributed to a higher average tariff,as production in Montana continues to be strong during the third quarter of2005.

Volumes on the Lakeheadsystem decreased approximately 7%, from 1.394 million Bpd during the thirdquarter of 2004 to 1.290 million Bpd during the same period in 2005. Thisresulted in lower operating revenue of approximately $6.4 million. Thedecrease is the result of lower than expected crude oil supply in WesternCanada from two sources. First, Suncor, an oil sands producer in Alberta,Canada, had a fire at their upgrader site on January 4, 2005. Since thattime, their production has been reduced by an average of 89,000 Bpd during2005. In late September, Suncor announced that repairs to the upgrader site andan expansion were completed and production capacity has increased as a result. Asa result, we expect deliveries on the Lakehead system to increase in the fourthquarter 2005. Western Canadian crude oil supply available for delivery on ourLakehead system was also reduced due to lower bitumen supplies. The nature ofthe cyclic steaming process used to extract bitumen from the ground can causeproduction timing differences during the year. Finally, during the secondquarter of 2005, Terasen Inc. completed an expansion on its Express Pipeline,which transports western Canadian crude to the U.S. Rocky Mountain market. Thisexpansion increased capacity on this pipeline by approximately 108,000 Bpd.Given the volume commitments on the Express Pipeline expansion, coupled withthe lower western Canadian crude oil supply as noted above, deliveries on ourLakehead system were negatively impacted during the third quarter of 2005. We believethat holders of firm capacity on the Express Pipeline will first satisfy theircommitments to that pipeline before moving incremental barrels on the Lakeheadsystem.

Operating andadministrative expenses for the Liquids segment increased $4.1 million or 13%in the third quarter of 2005, compared with the same period in 2004. Theincrease is driven primarily from higher workforce related costs ofapproximately $2.2 million, and lower capital project recoveries byapproximately $1.0 million due to a decrease in utilization of our workforce oncapital projects and a reduction in construction activity on our Lakeheadsystem.

***Nine months ended September 30,2005 compared with nine months ended September 30, 2004***

Our Liquids segmentaccounted for $90.8 million of operating income, representing a decrease of$13.0 million from the same period in 2004.Lower results on the Lakehead system were modestly offset by stronger resultson our North Dakota system and a full nine-month contribution from ourMid-Continent system compared with a seven-month contribution for the sameperiod in 2004.

Operatingrevenue for the first nine months of 2005 increased by $1.6 million to$303.1 million, compared with $301.5 million for the same period in2004. The increase in average tariffs on our Liquids systems resulted inhigher operating revenue of approximately $10.5 million for the reasons notedabove in the three-month analysis. Our Mid-Continent assets contributed higheroperating revenue of approximately $6.3 million for the additional twomonths of ownership in 2005 compared with 2004. These increases were mostlyoffset by lower deliveries on the Lakehead system for the same reason as notedabove in the three-month analysis, which resulted in a decrease ofapproximately $18.0 million in operating revenue in the nine-month period.

Operating andadministrative expenses for the first nine months of 2005 increased by$12.3 million to $105.5 million, compared with $93.2 million forthe same period in 2004. The increase is driven primarily 

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by higher oil measurementlosses of approximately $7.0 million and workforce related costs of approximately$4.5 million on the Lakehead system for the nine-month period.

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 nine monthsended September 30, 2005, the increase in oil measurement losses was afunction of three factors:

1.                Highervolumetric physical losses associated with changes in commodity properties andmeasurement, coupled with higher oil prices that made the monetary value ofnormal physical losses more expensive. During the first nine months of 2005,the average West Texas Intermediate crude oil price was approximately $55 perbarrel compared with approximately $39 per barrel during the same periodin 2004;

2.                Widerlight/heavy crude price differentials made degradation losses more expensive.During the first nine months of 2005, light/heavy differentials wereapproximately $20 per barrel compared with approximately $11 per barrel in2004; and

3.                Limited marketliquidity is available to settle specific crude oil positions that arenaturally created by our pipeline system’s operations. Market liquidity isespecially constrained when a price trend is anticipated by third-party crudeoil marketers. As a result, we carried net short positions that we could notphysically settle during the first three months of 2005, on which weexperienced a loss prior to settling the position.

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***Natural Gas***

The following tables setforth the operating results of our Natural Gas segment assets and average dailyvolumes of our major systems in millions of British Thermal units per day (“MMBtu/d”)for the periods presented:

| ** **                            | ** ** | **Three months ended  September 30,** | ** ** | **Nine months ended  September 30,** | ** ** |
|---------------------------------------|------------|------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                            | ** ** | **2005**                                             | ** ** | **2004**                                            | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                            | ** ** | **(unaudited; in millions)**               | ** ** |
| **Operating Results**                 | ** ** |                                                 |       |                                                |       |   |   |   |   |
| Operating revenues                    | ** ** | $                                                    | 597.9      |                                                | $          | 274.9 |   | $ | 1,544.8 |   | $ | 844.5 |   |
| Cost of natural gas                   | ** ** | (513.9                                               | )          | (204.2                                              | )          | (1,299.9 | ) | (639.8 | ) |
| Operating and  administrative         | ** ** | (44.3                                                | )          | (33.3                                               | )          | (126.3 | ) | (99.0 | ) |
| Depreciation and  amortization        | ** ** | (18.1                                                | )          | (14.0                                               | )          | (49.9 | ) | (38.6 | ) |
| Operating expenses                    | ** ** | (576.3                                               | )          | (251.5                                              | )          | (1,476.1 | ) | (777.4 | ) |
| **Operating Income**                  | ** ** | $                                                    | 21.6       |                                                | $          | 23.4 |   | $ | 68.7 |   | $ | 67.1 |   |
| **Average Daily Volume****(MMBtu/d)** | ** ** | ** **                                           | ** ** | ** **                                          | ** ** | ** ** | ** ** | ** ** | ** ** |
| East Texas                            |       | 904,000                                              |       | 693,000                                             |       | 841,000 |   | 643,000 |   |
| Anadarko(1)                           |       | 489,000                                              |       | 388,000                                             |       | 473,000 |   | 334,000 |   |
| North Texas                           |       | 267,000                                              |       | 196,000                                             |       | 264,000 |   | 192,000 |   |
| South Texas                           |       | 31,000                                               |       | 38,000                                              |       | 34,000 |   | 42,000 |   |
| UTOS                                  |       | 154,000                                              |       | 259,000                                             |       | 181,000 |   | 227,000 |   |
| MidLa                                 |       | 129,000                                              |       | 103,000                                             |       | 113,000 |   | 106,000 |   |
| AlaTenn                               |       | 42,000                                               |       | 47,000                                              |       | 59,000 |   | 60,000 |   |
| KPC                                   |       | 8,000                                                |       | 20,000                                              |       | 29,000 |   | 45,000 |   |
| Bamagas                               |       | 110,000                                              |       | 55,000                                              |       | 44,000 |   | 33,000 |   |
| Other major intrastates(1)            |       | 164,000                                              |       | 167,000                                             |       | 197,000 |   | 174,000 |   |
| Total                                 |       | 2,298,000                                            |       | 1,966,000                                           |       | 2,235,000 |   | 1,856,000 |   |

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(1)                 Anadarkoincludes the combined systems previously referred to separately as Anadarko andPalo Duro. The Palo Duro volumes were formerly included with Other majorintrastates.

***Three months ended September 30,2005 compared with three months ended September 30, 2004***

Aportion of our Natural Gas segment is exposed to commodity price risksassociated with percent of proceeds or percentage of index contracts that wenegotiate with producers. Under the terms of these contracts, we retain aportion of the natural gas and NGLs we process in exchange for providing theseproducers with our services. In order to protect our unitholders from thevolatility in cash flows that can result from fluctuations in commodity prices,we enter into derivative financial instruments to fix the sales price of thenatural gas and NGLs we anticipate receiving under the terms of these contracts.As a result of entering into these derivative financial instruments, we havelargely fixed the amount of cash that we will receive in the future when wesell the processed natural gas and NGLs, although the market price of thesecommodities will continue to fluctuate during that time. The remainder of therevenue we receive is derived from fees charged for gathering and treating ofnatural gas volumes and other related services.

Our Natural Gas segment contributed $21.6 million ofoperating income in the third quarter of 2005, representing a decrease of $1.8million from the $23.4 million of operating income contributed in thecorresponding period of 2004. Operating income of our Natural Gas segment forthe third quarter of 2005 includes non-cash, mark-to-market net losses of $9.5million, of which a gain of $0.1 million is due to 

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ineffectiveness on ourqualified cash flow hedges and a loss of $9.6 million is attributable tocertain derivative financial instruments that do not qualify for hedge accountingtreatment under SFAS No. 133 (refer also to the discussions included belowunder Derivative Transactions, Note 4 of Item 1. Financial Statements, and Item3. Quantitative and Qualitative Disclosures About Market Risk). These non-cashlosses primarily resulted from the significant increases in forward natural gasand NGL prices during the quarter. The increase in prices reduces the fairmarket value of these derivative financial instruments because the fixed pricecomponent of these derivatives is significantly less than the market price ofnatural gas at each of the forward settlement points. Although changes in thefair value of these specific derivative financial instruments do not affect ourcash flow, we anticipate these changes will continue to create volatility inour Consolidated Statements of Income going forward due to the inherentvolatility of natural gas and NGL prices.

A relatively small,but variable element of the Natural Gas segment’s operating income is derivedfrom keep-whole processing of natural gas. This contract structurerequires us to process natural gas at times when it may not be economical to doso. This can happen when natural gas prices are unusually high or NGL pricesare unusually low. During the third quarter of 2005, although natural gasprices were unusually high, they were more than offset by favorable NGL prices.Operating revenue less cost of natural gas derived from keep-wholeprocessing for the three months ended September 30, 2005, wasapproximately $8.7 million compared with $7.2 million for the sameperiod in 2004.

Average daily volumes on our major natural gas systemsincreased 17% in the third quarter of 2005, compared with the correspondingperiod in 2004. The increase in volumes is primarily the result of additionalwellhead supply contracts on our East Texas and Anadarko systems, as well asthe additional volumes on the North Texas system associated with the gatheringand processing assets we acquired in January 2005. Drilling activitycontinues to increase in the Anadarko Basin, Bossier Trend and Barnett Shaleareas. Additionally, completion of the East Texas expansion project in late June 2005contributed modestly to the growth in volumes for the three months ended September 30,2005. With continued investment in our systems to expand capacity, we expectour major natural gas systems to benefit from the increase in productionvolumes expected to result. The increases in volumes on our major natural gassystems were minimally offset by seasonal weather-related decreases on our KPCsystem and the effect of hurricanes Katrina and Rita on our UTOS and othermajor intrastate pipelines.

The positive growth in ournatural gas and NGL gathering, processing and transportation volumes for thethird quarter of 2005 was partially offset by increases in operating costs thatare mostly variable with volumes. The higher volumes on the systems resulted inincreases of workforce related costs approximating $3.7 million and repairand maintenance costs of approximately $1.0 million. Operating costs were alsohigher in 2005 by $2.0 million of incremental costs associated with the naturalgas gathering and processing assets we acquired in January 2005.

***Nine months ended September 30,2005 compared with nine months ended September 30, 2004***

The $68.7 million ofoperating income generated by our Natural Gas segment during the nine monthsended September 30, 2005 includes non-cash, mark-to-market losses of $22.6million, $1.9 million of which is due to ineffectiveness on our qualified cashflow hedges and $20.7 million of which is attributable to natural gas collarsthat do not qualify for hedge accounting treatment under SFAS No. 133(refer also to the discussions included below under Derivative Transactions,Note 4 of Item 1. Financial Statements, and Item 3. Quantitative andQualitative Disclosures About Market Risk). These non-cash losses primarilyresulted from the significant increases in forward natural gas and NGL pricesas noted previously in our three month analysis.

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Operating revenue lesscost of natural gas derived from keep-whole processing for the ninemonths ended September 30, 2005, was approximately $18.7 millioncompared with $10.2 million for the same period in 2004. The increase wasdue to the same reasons as previously noted in our three-month analysis.

Average daily volumes onour major natural gas systems increased 20%, or approximately 380,000 MMBtu/d,for the nine months ended September 30, 2005, compared with thecorresponding period in 2004. The increase in volumes is consistent with thereasons cited above in our three-month analysis.

Operatingand administrative costs associated with our Natural Gas segment were $27.3 milliongreater for the nine months ended September 30, 2005, than for the sameperiod in 2004. The volume growth on our systems contributed approximately $11.4 million in workforce related costs.Additionally, the natural gas gathering and processing assets we acquired in January 2005contributed to the cost increases by approximately $5.2 million. The volumegrowth on our systems, in addition to three processing plants that went downduring the nine months ended September 30, 2005, increased maintenancecosts by approximately $5.8 million, and also contributed to the increase in materialsand supply costs of $1.8 million.

Our depreciation andamortization expense for the nine months ended September 30, 2005 exceededthe amount reported for the same period in 2004 by approximately $11.3 million,primarily as a result of acquisitions and increased capital expenditures. Theincrease was partially offset by modest extensions of the depreciable lives ofour major pipeline systems as a result of a depreciation study completed duringthe third quarter of 2005.

***Marketing***

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

| ** **                      | ** ** | **Three months ended  September 30,** | ** ** | **Nine months ended  September 30,** | ** ** |
|---------------------------------|------------|------------------------------------------------------|------------|-----------------------------------------------------|------------|
| ** **                      | ** ** | **2005**                                             | ** ** | **2004**                                            | ** ** | **2005** | ** ** | **2004** | ** ** |
| ** **                      | ** ** | **(unaudited; in millions)**               | ** ** |
| Operating revenues              |       | $                                                    | 1,107.6    |                                                | $          | 622.8 |   | $ | 2,544.5 |   | $ | 1,811.0 |   |
| Cost of natural  gas            |       | (1,145.9                                             | )          | (620.3                                              | )          | (2,582.5 | ) | (1,804.0 | ) |
| Operating and  administrative   |       | (1.4                                                 | )          | (0.8                                                | )          | (3.1 | ) | (2.4 | ) |
| Depreciation and  amortizationn |       | (0.1                                                 | )          | —                                              |       | (0.4 | ) | — |   |
| Operating  expenses             |       | (1,147.4                                             | )          | (621.1                                              | )          | (2,586.0 | ) | (1,806.4 | ) |
| **Operating Income (loss)**     |       | $                                                    | (39.8      | )                                                   | $          | 1.7 |   | $ | (41.5 | ) | $ | 4.6 |   |

 

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***Three months ended September 30, 2005 comparedwith three months ended September 30, 2004***

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

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

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

During the quarter ended September 30, 2005,disruptions of natural gas supplies from facilities in the Gulf of Mexicoregion caused by hurricanes Katrina and Rita created greater demand for naturalgas production from our onshore Natural Gas segment pipeline assets, increasingour ability to optimize natural gas supply to areas of strongest demand. As aresult of the hurricanes, unusual volatility in the prices of natural gascreated greater spreads on our natural gas volumes.

Although our Marketing segment was not adverselyaffected from the temporary supply disruptions in the Gulf of Mexico, wegenerally continue to be affected by lower unit margins on natural gas volumespurchased due to physical pipeline constraints. The recent completion of ourEast Texas system expansion 

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has partially alleviatedthese constraints; however, increasing production volumes will continue tocreate additional constraints, which will require continued use of third-partypipelines in East Texas. This situation is not limited to the East Texasregion. Pricing in our natural gas supply markets is expected to continue toexperience increasing pressure due to a greater supply of natural gas from theRocky Mountains, Midcontinent and North Texas. For this reason we haveincreased our commitments on third-party pipelines to provide insuranceagainst pipeline constraints and to provide more attractive market outlets forour natural gas supply. However, there continue to be timing differencesbetween the acquisition of new third-party pipeline capacity and thenegotiation of applicable downstream sales agreements. Until new markets aredeveloped, our Marketing segment sells greater portions of its natural gassupply in less attractive short-term markets.

In the third quarter of2005, our Marketing segment incurred losses of $39.8 million compared withearning $1.7 million of operating income for the corresponding period in2004. Included in operating loss for the third quarter of 2005 are non-cash,mark-to-market losses of approximately $43.1 million associated with derivativefinancial instruments that do not qualify for hedge accounting treatment underSFAS No. 133. In the second quarter of 2005, we revised our businessstrategy for the use of derivative financial instruments associated with the transportationand storage of natural gas to afford us the ability to respond to changingeconomic conditions. The flexibility provided by the revised strategy precludesus from continuing the use of hedge accounting with regard to thesetransactions. Under SFAS No. 133, if the forecasted transaction is nolonger probable of occurring as originally set forth in the hedgedocumentation, the financial instruments must be marked-to-market each periodwith the change in fair market value recorded in earnings. However, SFAS No. 133does not allow us to mark-to-market the change in value of the relatedunderlying physical transaction which creates earnings volatility when the “spreads”move. We expect these net mark-to-market losses to be offset when the relatedphysical transactions are settled (refer also to the discussion included belowunder Derivative Transactions, Note 4 of Item 1. FinancialStatements, and Item 3. Quantitative and Qualitative Disclosures AboutMarket Risk).

***Nine months ended September 30, 2005 comparedwith nine months ended September 30, 2004***

Our Marketing segment incurred an operating loss of$41.5 million for the nine months ended September 30, 2005, comparedwith $4.6 million of operating income for the corresponding period in2004. Included in the operating loss for the nine months of 2005 are non-cashmark-to-market losses of approximately $37.8 million associated withderivative financial instruments that do not qualify for hedge accountingtreatment under SFAS No. 133 and approximately $9.0 million resulting fromthe discontinuance of hedge accounting for derivative financial instrumentsassociated with forecasted transactions that we determined were not probable ofoccurring, as noted above in our three-month analysis.

In the second quarter of2005, we revised our business strategy as discussed above in our three-monthanalysis. Approximately $2.1 million of the $9.0 million of loss from thediscontinuance of hedge accounting will not be recoverable and relates tohedges we closed out during the second quarter. This $2.1 million will berealized as reduced cash flows over an approximate 15-month period intothe fourth quarter of 2006. The Partnership will use its best efforts tomitigate or recover economic losses on this portion of the discontinuedderivative financial instruments (refer also to the discussion included underDerivative Transactions, Note 4 of Item 1. Financial Statements, andItem 3. Quantitative and Qualitative Disclosures About Market Risk).

***Corporate***

Interest expense was $28.4 million and $79.6 millionfor the three and nine months ended September 30, 2005, respectively,compared with $22.2 million and $65.8 million for the correspondingperiods in 2004. The increases are the result of higher debt balances andhigher weighted average interest 

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rates of approximately5.68% and 5.80% during the three and nine months ended September 30, 2005,respectively, compared with approximately 5.29% and 5.61% during the sameperiods in 2004. Our weighted average debt balances at September 30, 2005,are greater than the amounts at September 30, 2004 due to the gatheringand processing assets in North Texas we acquired in January 2005, inaddition to the capital expenditures we have made to expand our existingsystems to improve the service capabilities of our assets.

Included in our resultsfor the third quarter of 2004 was a charge related to rate refunds payable onour Kansas Pipeline System (“KPC”) for $12.0 million associated with ratescharged to customers of KPC prior to our ownership. We extinguished thisobligation in the first quarter of 2005 and have not incurred any similar raterefunds during the three and nine month periods ended September 30, 2005.

**LIQUIDITY AND CAPITAL RESOURCES**

We believe that our ability to generate cash flow, inaddition to our access to capital resources, is sufficient to meet the demandsof our current and future operating growth and investment needs. Our primarycash requirements consist of normal operating expenses, maintenance andexpansion capital expenditures, debt service payments, distributions topartners, acquisitions of new assets or businesses, and payments associatedwith our derivative transactions. Short-term cash requirements, such asoperating expenses, maintenance capital expenditures and quarterlydistributions to partners, are expected to be funded from our operating cashflows. Margin requirements associated with our derivative transactions aregenerally supported by letters of credit issued under our Credit Facility. Weexpect to fund long-term cash requirements for expansion projects andacquisitions from several sources, including cash flows from operatingactivities, borrowings under the commercial paper program we established in April 2005,our credit facilities, and the issuance of additional equity and debtsecurities. Our ability to complete future debt and equity offerings and thetiming of any such offerings will depend on various factors, includingprevailing market conditions, interest rates, our financial condition andcredit rating at the time.

In April 2005, we entered into the thirdamendment to the Amended and Restated Credit Agreement dated as of January 24,2003 (as amended, the “Credit Facility”) to, among other things, extend thematurity of the Credit Facility for a period of five years to April 2010;increase the letter of credit sub limit from $100 million to $175 million;and grant us the right to request, subject to approval by the Board ofDirectors of Enbridge Management, L.L.C. (“Enbridge Management”), an increasein commitments available under the Credit Facility up to an aggregateoutstanding principal amount of $1 billion.

In September 2005, we entered into the fourthamendment to the Credit Facility to, among other things, extend the letter ofcredit sub limit from $175 million to $300 million, increase the commitmentsavailable under the Credit Facility from $600 million to $800 million, decreasethe “Applicable Rate” as set forth in the Credit Facility, and extend from September 2005to December 31, 2006, the requirement to maintain a Consolidated LeverageRatio, as defined in the Credit Facility, of not more than 5.25 to 1.

Also in April 2005, we successfully entered thecommercial paper market with the establishment of our $600 million commercialpaper program that is supported by our long-term Credit Facility. We access thecommercial paper market primarily to provide temporary financing for ouroperating activities, capital expenditures and acquisitions, at rates that aregenerally lower than the rates available under our Credit Facility. We haverepaid the entire amount previously outstanding under our Credit Facility withproceeds we obtained from issuing commercial paper under this program. OurCredit Facility remains undrawn and available to support our commercial paperprogram. Under the terms of our commercial paper program, we may issue up to$600 million of commercial paper. However, the amount of commercial paper wemay issue is reduced by any balance of outstanding letters of credit in excessof $200 million. At September 30, 2005, we had $455.0 million ofcommercial paper outstanding at a weighted average interest rate of 3.84% 

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and outstanding letters ofcredit totaling $179.6 million. At September 30, 2005, we could issue anadditional $145 million under our commercial paper program.

On February 11, 2005, we issued an additional2,506,500 Class A common units at $49.875 per unit, which generatedproceeds, net of offering expenses, of approximately $124.8 million.Additionally, the General Partner contributed $2.7 million to us tomaintain its 2% general partner interest in the Partnership. We used theproceeds from this offering to repay borrowings under our Credit Facility.

Working capital, defined as current assets lesscurrent liabilities, decreased by $107.5 million to a net liability of $38million at September 30, 2005, compared with an asset of$69.5 million at December 31, 2004. This decrease was primarilyattributable to increases in liabilities associated with the changes in fairvalue of our derivative financial instruments.

At September 30,2005, cash and cash equivalents totaled $93.4 million, compared with$78.3 million at December 31, 2004. Of the cash balance,$64.1 million ($0.925 per unit) is available for cash distributions to ourunitholders on November 14, 2005. Of this distribution, $53.3 millionwill be paid in cash, $10.6 million will be distributed in i-unitsto our i-unitholder and $0.2 million retained from our General Partner inrespect of this i-unit distribution.

***Operating Activities***

Net cash provided byoperating activities for the nine months ended September 30, 2005 was$208.2 million, compared with $225.9 million for the same period in2004. The decrease in 2005 was primarily due to general timing differences inthe collection on and payment of our related party and current accounts.

***Investing Activities***

Net cash used in investingactivities during the nine months ended September 30, 2005 was $442.3 million,compared with $313.4 million for the same period in 2004. The increase of$128.9 million was partially attributable to greater amounts we expendedfor the acquisition of the North Texas Gathering system and other natural gasgathering assets in 2005 than the amount we paid for the Mid-Continentand Palo Duro systems acquired in 2004. We acquired gathering and processingassets in north Texas for approximately $164.6 million in January 2005and other natural gas gathering assets for approximately $21.8 million duringthe nine months ended September 30, 2005. In addition to our acquisitions,we spent $261.9 million in connection with our core maintenance and systemenhancement projects, representing an increase of $87.3 million over the$174.6 million we spent for the same period of 2004. This increase wasprimarily due to the construction of our East Texas system expansion, which wascompleted in June 2005, and several smaller projects to expand ourexisting natural gas transmission and processing capacity as well as crude oilstorage facilities. Additional information regarding our capital expendituresis provided below.

***Financing Activities***

Net cash provided byfinancing activities during the nine months ended September 30, 2005 was$249.2 million, compared with $117.1 million for the correspondingperiod in 2004. The increase of $132.1 million in cash flow is primarilydue to net borrowings under our commercial paper program and Credit Facility,partially offset by an increase in distributions to our partners. Distributionsto our partners were higher in 2005 due to an increase in the number of unitsoutstanding, as well as a related increase in the general partner incentivedistributions resulting from the larger number of units outstanding.

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**CAPITAL EXPENDITURES**

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 orotherwise access the necessary capital resources is sufficient to meet thedemands of our current and future operating growth needs. Although we currentlyintend to make the forecasted expenditures discussed below, we may adjust thetiming and amounts of projected expenditures as necessary to adapt to changesin economic conditions.

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

Wecategorize capital expenditures as either core maintenance or systemenhancement expenditures. Core maintenance expenditures are those expendituresthat are necessary to maintain the service capability of our existing assetsand include the replacement of system components and equipment which are worn,obsolete or approaching the end of their useful lives. 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$261.9 million, including $23.1 million on core maintenanceactivities, during the nine months ended September 30, 2005. For the fullyear 2005, we anticipate capital expenditures to approximate $411 million,as illustrated in the following table:

| ** **                   | ** ** | **(in millions)** | ** ** |
|------------------------------|------------|------------------------|------------|
| System enhancements          |       |                   | $          | 311 |   |   |
| Core maintenance  activities |       |                   | 36         |   |   |
| East Texas  expansion        |       |                   | 64         |   |   |
|                         |       |                   | $          | 411 |   |   |

 

As of September 30, 2005, we have contractualcommitments totaling $32.5 million for materials and services related to ourorganic growth projects. We expect to settle these commitments during theremainder of 2005 and 2006.

We expect to incurcontinuing annual capital and operating expenditures for pipeline integritymeasures to both ensure regulatory compliance and to maintain the overallintegrity of our pipeline systems. Expenditure levels have continued toincrease as pipelines age and require higher levels of inspection ormaintenance; however, these are viewed to be consistent with industry trends.

**DERIVATIVE ACTIVITIES**

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

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Thefollowing table provides summarized information about the timing and expectedsettlement amounts of our outstanding commodity derivative financialinstruments at September 30, 2005 for each of the indicated calendaryears: 

| ** **             | ** **   | **Notional**                  | ** **   | **2005**     | ** **   | **2006**     | ** **   | **2007**     | ** **   | **2008**     | ** **   | **2009**     | ** **   | **2010**     | ** **   | **2011**     | ** **   | **2012**     | ** **   |
|------------------------|--------------|-------------------------------|--------------|--------------|--------------|--------------|--------------|--------------|--------------|--------------|--------------|--------------|--------------|--------------|--------------|--------------|--------------|--------------|--------------|
| ** **             | ** **   | **($ in millions)** | ** **   |
| **Swaps**              | *** *** | *** ***                  | *** *** | *** *** | *** *** | *** *** | *** *** | *** *** | *** *** | *** *** | *** *** | *** *** | *** *** | *** *** | *** *** | *** *** | *** *** | *** *** | *** *** |
| Natural gas(1)         |         | 575,618,282                   |         | $            | (29.8        | )            | $            | (81.7        | )            | $            | (47.6        | )            | $            | (39.9        | )            | $            | (25.6        | )            | $            | (20.3 | ) | $ | (19.5 | ) | $ | (4.5 | ) |
| NGL(2)                 |         | 291,654,468                   |         | (21.1        | )            | (39.0        | )            | (30.3        | )            | (7.8         | )            | —       |         | —       |         | —       |         | —       |         |
| Crude(2)               |         | 1,372,169                     |         | (2.8         | )            | (9.0         | )            | (8.2         | )            | (5.4         | )            | (1.1         | )            | —       |         | —       |         | —       |         |
| **Options—calls** |         |                          |         |         |         |         |         |         |         |         |         |         |         |         |         |         |         |         |         |
| Natural gas(1)         |         | 6,849,000                     |         | (2.5         | )            | (7.4         | )            | (5.2         | )            | (3.9         | )            | (3.1         | )            | (2.5         | )            | (2.6         | )            | —       |         |
| **Options—puts**  |         |                          |         |         |         |         |         |         |         |         |         |         |         |         |         |         |         |         |         |
| Natural gas(1)         |         | 7,079,000                     |         | —       |         | —       |         | —       |         | —       |         | 0.1          |         | 0.1          |         | 0.2          |         | —       |         |
| Totals                 |         |                          |         | $            | (56.2        | )            | $            | (137.1       | )            | $            | (91.3        | )            | $            | (57.0        | )            | $            | (29.7        | )            | $            | (22.7 | ) | $ | (21.9 | ) | $ | (4.5 | ) |

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(1)                 Notional amounts for natural gas arerecorded in millions of British thermal units (“MMBtu”).

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

**OFF-BALANCE SHEET ARRANGEMENTS**

We do not have any off-balancesheet arrangements.

**SUBSEQUENT EVENTS**

***Distribution Declaration***

On October 26, 2005,Enbridge Management’s Board of Directors declared a distribution payable on November 14,2005. The distribution will be paid to unitholders of record as of November 3,2005, of our available cash of $64.1 million at September 30, 2005,or $0.925 per common unit. Of this distribution, $53.3 million willbe paid in cash, $10.6 million will be distributed in i-units to ouri-unitholder and $0.2 million will be retained from the GeneralPartner in respect of this i-unit distribution.

***Gathering and Processing Asset Sale***

On October 20, 2005,we entered into agreements to sell a processing plant and related facilitiesand other gathering and processing assets located in our East and South Texassystems for $106.0 million. The facilities represent non-strategic assetswithin our Natural Gas segment and are not in our core geographic areas ofinterest. We intend to use the proceeds from this sale to finance otherprojects in our core geographic areas of interest. Completion of the sale issubject to normal closing conditions and is expected to occur in the fourthquarter of 2005.

**FUTURE PROSPECTS**

***Business Strategy***

During 2005, we have shifted our business strategytowards developing and expanding our existing assets, with less focus onacquisitions. This shift primarily results from two factors. First, acquisitionprices have been inflated by increased competition for stable energy assetsthat we seek for the Partnership. The competition includes several new masterlimited partnerships and private equity investors. We do not rule outmaking significant acquisitions in the future; however, while prices remainhigh, our acquisitions will likely be limited to situations where we havenatural advantages to create additional value in the 

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future. Second, over thepast few years, we have expanded and diversified our asset base, particularlyin our Natural Gas business. As a result, a significant number of internalprojects are emerging from the assets in our focus regions, primarily Texas. Weanticipate that the combination of strong production profiles of the majorbasins we serve and increasing natural gas supply from the Rocky Mountains and liquefiednatural gas (“LNG”) imports will require new market access outside of thetraditional Texas market. In addition to our East Texas transmission pipelinethat we completed in June 2005, we are focusing on an additional marketoption for our natural gas customers.

This internal growth inour Natural Gas business, coupled with our Southern Access Program on ourLakehead system (see ‘Future Prospects—Liquids’), will lead to significantexpenditures of capital over the next several years. A disadvantage of internalgrowth is that it usually entails carrying the cost of constructing new assetsbefore earning a return on those assets. This will be the case with thePartnership’s major expansion commitments over the next few years. Over thatperiod, it may not be prudent to increase the cash distribution rate tounitholders from its current level, assuming no significant acquisitions.

***Liquids***

Average daily crude oildeliveries on our Lakehead system are expected to decrease by approximately20,000 Bpd during 2005 to approximately 1.38 million Bpd, from ourprevious forecast of 1.40 million Bpd. This also represents a year-over-yeardecrease of approximately 42,000 Bpd, from 2004 deliveries of1.422 million Bpd. The decrease is primarily attributable to the early January 2005fire at the Suncor oil sands plant in Alberta, a major producer of crude oil inwestern Canada. During September 2005, Suncor completed repair work on thedamaged portions of its facility. With Suncor’s return to full productioncapacity, along with the completion of an expansion to its oil sands upgradingoperation in September 2005, we expect an increase in western Canadiancrude oil supply and deliveries on our Lakehead system in the fourth quarter of2005.

In June 2005, an openseason was commenced by the Partnership and Enbridge Inc. (“Enbridge”) toconfirm shipper support for the Southern Access Mainline Expansion andExtension Program (“Southern Access Program”). The Southern Access Program isdesigned to facilitate access to new and expanding supplies of crude oil fromthe western Canadian oil sands by the PADD II region of the United States, themajor oil hub at Cushing, and, through interconnecting lines, the Texas GulfCoast. The main elements of the Southern Access Program are:

*Mainline Expansion:*   TheMainline Expansion consists of up to three separate phases, which in aggregateis designed to provide an additional 400,000 Bpd of crude oil capacity on theEnbridge/Lakehead mainline system from Hardisty, Alberta, to Chicago, Illinois.Aggregate capital costs for the Mainline Expansion are currently estimated tobe approximately $900 million, of which approximately $760 million isattributable to the U.S. portion of the expansion and will be financed by us. Thisamount includes cost savings resulting from proceeding concurrently with allthree phases of the Mainline Expansion. The balance of the capital costs forthe Mainline Expansion is attributable to the Canadian portion of the mainlinesystem and will be financed by Enbridge.

*Southern Access Extension:*   TheSouthern Access Extension will involve the construction of a new 30-inchdiameter pipeline and related facilities designed to transport up to 300,000Bpd of crude oil from a new interconnection with our Lakehead system, nearChicago, to hubs at Wood River or Patoka, Illinois, or both. The SouthernAccess Extension will be financed and constructed by Enbridge at an estimatedcost of approximately $320 million.

The Partnership and Enbridge expect to recover ourcosts and earn an annual return of approximately 9%, plus inflation that isamortized over the life of the project, on our equity investment in the U.S.portion of the Southern Access Program. These costs will be collected through asystem-wide surcharge on 

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theLakehead system tolls using a standard cost of service model. The SouthernAccess Extension will be integrated with our Lakehead system for rate-makingpurposes.

In July 2005, thePartnership and Enbridge completed the open season in which we solicited andobtained from shippers non-binding indications of support for the constructionof all phases of the Southern Access Program. The open season results weresupportive of the entire program. For the Mainline Expansion portion of theprogram, although offered in stages, the shippers indicated interest inproceeding with all three phases concurrently to ensure adequate pipelinecapacity. Discussions with shippers are proceeding with the objective of filingagreed tolling principles with the FERC and undertaking preliminaryconstruction preparations this year. For the Southern Access Extension, therewas significant support and interest to warrant continued discussion withshippers on project timing and terms of binding commitments. The SouthernAccess Expansion Program is expected to be in full service in the first quarterof 2009.

A proposal that could competewith our Southern Access Program was announced on October 14, 2005, byAltex Energy Ltd., which proposed a crude oil pipeline from northern Albertadirectly to the U.S. Gulf Coast. This concept is subject to shipper support andregulatory approval. The Partnership and Enbridge believe that our SouthernAccess Program, together with initiatives by Enbridge to provide access to newmarkets in the Midwest, Midcontinent and Gulf Coast, offer more flexiblesolutions to future transportation requirements of western Canadian crude oilproducers, and the in-service timing of these solutions is much more in linewith prospective shipper needs.

In June 2005,Enbridge acquired the remaining 10% stake in the Spearhead Pipeline, giving it100% ownership in the pipeline, which runs from Cushing, Oklahoma to Chicago.After a successful open season in the fall of 2004, Enbridge is currently inthe process of reversing the flow of the Spearhead Pipeline so that it willprovide capacity to deliver 125,000 Bpd into the major oil hub at Cushingby 2006. This line could subsequently be expanded to accommodate up to160,000 Bpd. The FERC approved the application for Spearheadtransportation tariffs on March 3, 2005. A portion of the SpearheadPipeline’s revenue requirement will be rolled into Enbridge’s Canadian mainlinetariffs, which were approved in the second quarter of 2005 by Canada’s NationalEnergy Board (“NEB”). The NEB decision has been appealed by one intervenerbased on jurisdictional grounds and an appeal has been granted by Canada’sFederal Court of Appeal. Enbridge expects that this appeal will not besuccessful and, therefore, is proceeding with the reversal project. We expectto benefit following the reversal, as western Canadian crude oil will becarried on the Lakehead system as far as Chicago, and then transferred to theSpearhead Pipeline to continue to this new market.

During 2004, ExxonMobilPipeline Company (“ExxonMobil”) approached the Canadian Association ofPetroleum Producers and prospective shippers with a proposal to reverse thedirection of flow on its Beaumont, Texas to Corsicana, Texas and its Corsicanato Patoka pipelines. The combined reversed pipeline will be linked to ourLakehead system at Chicago via the Mustang Pipe Line Partners system to Patoka.The Mustang Pipe Line Partners system is 30% owned by an affiliate of Enbridge.ExxonMobil completed a successful open season with commitments of 50,000 Bpd,and has stated that it will proceed with the reversal, with plans to bein-service by the end of 2005. The reversed pipeline is expected to transport65,000 Bpd of western Canadian heavy crude to the refinery market located in Beaumonton the U.S. Gulf Coast. The connection of the Lakehead system with this newmarket should also support increased throughput on the Lakehead system. Thishas been evidenced by the results of an open season conducted by MustangPipeline Partners, which resulted in commitments for higher volumes fortransportation from the Lakehead system to Patoka. However, the reversed systemwill also be capable of transporting western Canadian crude moved via othercompeting pipelines into Patoka.

Two proposals are currently being pursued to increasepipeline capacity for transportation of crude oil from the oil sands in Albertato the west coast of Canada, where it could be shipped by tanker to China,other Asia-Pacific markets and California. The Gateway Pipeline is a new 30-inchcrude oil pipeline with 

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designcapacity of 400,000 Bpd. In April 2005, a memorandum of understanding wasentered into between Enbridge and PetroChina International Company Limited tocooperate on the development of the Gateway Pipeline in order to supplyapproximately 200,000 Bpd of crude oil to China. A regulatory application forthe $2.5 billion (Canadian dollars), 720-mile pipeline would have to bemade in 2006 to achieve a 2010 in-service date, which is when Enbridge’swestern Canada crude oil supply forecast indicates that oil sands productionwill have increased to the level that access to a major new market will bebeneficial to producers. Enbridge estimates that between 600,000 and 800,000Bpd of incremental oil sands production will be available by 2010.

Terasen Inc.’s TMX projectis a proposed expansion of its existing Trans Mountain Pipeline system, whichruns from Alberta to British Columbia, Canada and Washington State. In July 2005,Terasen Inc. filed an application with the NEB to increase the capacity of itsTrans Mountain Pipeline system from 225,000 Bpd to 260,000 Bpd., with a plannedin-service date of the first quarter of 2007. This is the first phase of amulti-phased expansion of the Trans Mountain Pipeline. The next phase wouldinclude the construction of a 30-inch pipeline loop between Hinton,Alberta and Valemont, British Columbia.

These pipeline expansionsare in line with the Partnership’s expectations for increased access to new andexisting markets for western Canadian crude oil. The Partnership expects thegrowing supply of crude oil from the Alberta oil sands to exceed the pipelinecapacity to current and proposed markets which will require the development ofnew pipelines out of Western Canada.

***Natural Gas***

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

We completed constructionin June 2005 of our new 500 MMcf/d East Texas Expansion PipelineProject. This new pipeline represents a strategic link between producers bothin the Barnett Shale area of North Central Texas and the Bossier/Cotton Valleyhorizons in East Texas and new markets accessible through the pipeline hub atCarthage, Texas. Carthage access is important to natural gas shippers becauseit offers a number of pipeline connections which generally provide higherwellhead gas prices for producers. The pipeline is operating within itsoriginally projected capacity with continued increases in utilization expectedthrough the remainder of the year resulting from negotiation of additionalcommercial arrangements, organic supply growth, and other growth initiatives onour East Texas system.

In addition to thecompletion of the East Texas Expansion Pipeline Project, we initiated a seriesof new projects to restart as well as construct certain treating and processingfacilities on our East Texas system. We expect to complete these new projectsin early 2006 at an estimated cost of approximately $75 million. Completionof these new projects will expand the service offerings we currently provide toour customers on the East Texas system.

Construction on ourAnadarko system expansion continues. The first phase of the expansion added100 MMcf/d of processing capacity which we placed in service in April 2005and we are proceeding with the second phase of the project to increase thescale of the processing plant to 160 MMcf/d. The total cost of both phasesof the project is approximately $52 million and we expect it to becomplete by the end of the fourth quarter of 2005. On October 26, 2005,Enbridge Management’s Board of Directors approved a project to build a new 125MMcf/d processing plant to accommodate additional supply growth in thisoperating area. This facility is expected to be operation in early 2007.

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Our Bamagas system has agreements to providetransportation of up to 276,000 MMBtu/d of natural gas for a remaining periodof 17 years to two utility plants that are indirectly owned by CalpineCorporation (“Calpine”). The Bamagas system receives a fixed demand charge of$0.07 per MMBtu of natural gas for 200,000 MMBtu/d, regardless of whether thecapacity is used. Calpine has recently experienced financial difficulties thatit is actively working to alleviate. Although we fully expect our customer toremain solvent and its plants to meet their obligations to us under the termsof the transportation agreements, we are exposed to a potential assetimpairment of up to $50 million, representing the book value of the pipeline,should they be unable to fulfill their commitments. We are actively monitoringCalpine’s financial condition and evaluating alternate uses for the system.

As a result of the widespread damage caused byhurricanes Katrina and Rita, the major credit rating agencies have issuednegative credit implications for several of our industrial and utilitycustomers. Although we do not anticipate any significant deterioration in thecredit standing of these customers, we continue to monitor their financialcondition, and expect improvement in their credit standing as system outagesare restored and property damage repaired.

**REGULATORY MATTERS**

***FERC Transportation Tariffs-***Liquids

Effective July 1, 2005, in compliance with theindexed rate ceilings allowed by the FERC, the Partnership increased its ratesfor transportation on the Lakehead, North Dakota and Ozark systems by anaverage of approximately 3.63%. For the Lakehead system, indexing only appliesto its base rates, not the surcharges for the System Expansion Program II (“SEPII”), the Terrace Expansion Program (“Terrace”) and other surcharges. We expectthe increase in tariff rates to contribute approximately $5 million to ourresults of operations for 2005. On the Lakehead system, the new rate for heavycrude movements from the International Border to Chicago is $0.89 per barrel,which reflects an approximate $0.025 cents per barrel increase over rates filedeffective April 1, 2005.

Effective April 1,2005, we filed our annual tariff with the FERC for our Lakehead System. Thistariff reflected the annual calculation of the SEP II and other surchargesbased on true-ups of prior year amounts and estimates for 2005, and an adjustmentfor the Terrace surcharge as a result of lower than expected volumes moving onthe Lakehead system. This filing increased the tariff for heavy crude oilmovements from the Canadian border to Chicago, Illinois, by approximately$0.035 per barrel, to approximately $0.865 per barrel.

***FERC Policy on Income Tax Allowances***

On May 4, 2005, the FERC adopted a policy topermit cost-of-service rates to reflect an actual or potential income taxliability for all public utility assets, regardless of the form of ownership.The policy statement stems from an opinion issued by the U.S. Court ofAppeals for the District of Columbia Circuit in *BP West Coast Products, LLC v. FERC* that remanded the FERC’sdecisions on tax allowance treatment in an oil pipeline rate proceedinginvolving SFPP, L.P., an unrelated pipeline company.

Under the policy, allentities or individuals owning public utility assets would be permitted anincome tax allowance on the income from those assets, provided that they havean actual or potential income tax liability on that public utility income. As aresult, a taxpaying corporation, partnership, limited liability corporation, orother pass-through entity would be permitted an income tax allowance on theincome imputed to the corporation, or to the partners or the members of pass-throughentities. Any pass-through entity seeking an income tax allowance in a specificrate proceeding will be required to establish that its partners or members havean actual or potential income tax obligation on the entity’s public utilityincome. Management is evaluating the new FERC policy. At this time we do notbelieve the adoption of this policy by the FERC will have a material effect onour financial position, results of operations or cash flows.

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

In June 2005, theFERC issued guidance describing how FERC-regulated companies should account forcosts associated with implementing the pipeline integrity managementrequirements of the U.S. Department of Transportation’s Office of PipelineSafety. Under the guidance, costs to 1) prepare a plan to implement theprogram, 2) identify high consequence areas, 3) develop and maintain a recordkeeping system and 4) inspect, test and report on the condition of affected pipelinesegments to determine the need for repairs or replacements, are required to beexpensed. Costs of modifying pipelines to permit in-line inspections, certaincosts associated with developing or enhancing computer software and costsassociated with remedial and mitigation actions to correct an identifiedcondition can be capitalized. The guidance is effective January 1, 2006,to be applied prospectively. We are currently evaluating the effect thatapplication of this order will have on our financial statements.

**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, as amended, for the yearended December 31, 2004, in addition to information presented in Items 1and 2 of 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, liabilityand/or anticipated transaction and are not entered into with the objective ofspeculating on commodity prices.

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Thefollowing tables provide information about our derivative financial instrumentsat September 30, 2005 and December 31, 2004, with respect to ourcommodity price risk management activities for natural gas and NGLs, includingcrude:

|                                  | ** ** | **At September 30, 2005** | ** ** | **At December 31,   2004** | ** ** |
|----------------------------------|------------|------------------------------------------|------------|--------------------------------------|------------|
| ** **                       | ** ** | ** **                               | ** ** | ** **                           | ** ** | **Wtd Avg Price**(2) | ** ** | **Fair Value**(3) | ** ** | **Fair Value**(3) | ** ** |
| ** **                       | ** ** | **Commodity**                            | ** ** | **Notional**(1)                      | ** ** | **Receive** | ** ** | **Pay** | ** ** | **Asset** | ** ** | **Liability** | ** ** | **Asset** | ** ** | **Liability** | ** ** |
| ***Contracts maturing in 2005*** |       |                                     |       |                                 |       |   |   |   |   |   |   |   |   |   |   |   |   | *** *** |   |
| *Swaps*                          |       |                                     |       |                                 |       |   |   |   |   |   |   |   |   |   |   |   |   | *** *** |   |
| Receive variable                 |       |                                     |       |                                 |       |   |   |   |   |   |   |   |   |   |   |   |   | *** *** |   |
| /pay fixed                  |       | Natural Gas                              |       | 50,900,877                           |       | $ | 12.99 |   | $ | 6.96 |   | $ | 305.4 |   | $ | — |   | $ | 8.1 |   |   | $ | (54.5 | ) |   |
| Receive fixed                    |       | Natural Gas                              |       | 52,529,055                           |       | 6.99 |   | 13.36 |   | — |   | (333.1 | ) | 48.3 |   |   | (25.9 | ) |   |
| /pay variable                    |       | NGL                                      |       | 42,534,912                           |       | 0.65 |   | 1.15 |   | — |   | (21.1 | ) | 1.0 |   |   | (8.0 | ) |   |
|                             |       | Crude                                    |       | 86,940                               |       | 34.41 |   | 66.40 |   | — |   | (2.8 | ) | — |   |   | (3.2 | ) |   |
| Receive variable                 |       |                                     |       |                                 |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| /pay variable                    |       | Natural Gas                              |       | 6,068,630                            |       | 12.69 |   | 13.03 |   | 1.0 |   | (3.1 | ) | 0.7 |   |   | (2.4 | ) |   |
| *Options*                        |       |                                     |       |                                 |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Calls (written)                  |       | Natural Gas                              |       | 276,000                              |       | 13.78 |   | 4.74 |   | — |   | (2.5 | ) | — |   |   | (1.7 | ) |   |
| Puts                             |       | Natural Gas                              |       | 506,000                              |       | 13.92 |   | 4.13 |   | — |   | — |   | 0.1 |   |   | — |   |   |
| ***Contracts maturing in 2006*** |       |                                     |       |                                 |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| *Swaps*                          |       |                                     |       |                                 |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Receive variable                 |       |                                     |       |                                 |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| /pay fixed                  |       | Natural Gas                              |       | 139,182,126                          |       | 11.24 |   | 7.00 |   | 574.8 |   | — |   | 4.2 |   |   | (7.8 | ) |   |
| Receive fixed                    |       | Natural Gas                              |       | 145,903,926                          |       | 6.95 |   | 11.57 |   | — |   | (655.9 | ) | 7.8 |   |   | (23.3 | ) |   |
| /pay variable                    |       | NGL                                      |       | 109,318,230                          |       | 0.68 |   | 1.05 |   | — |   | (39.0 | ) | 0.5 |   |   | (4.1 | ) |   |
|                             |       | Crude                                    |       | 417,725                              |       | 44.58 |   | 66.81 |   | — |   | (9.0 | ) | 0.4 |   |   | (1.4 | ) |   |
| Receive variable                 |       |                                     |       |                                 |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| /pay variable               |       | Natural Gas                              |       | 4,625,281                            |       | 11.53 |   | 11.64 |   | 0.9 |   | (1.5 | ) | — |   |   | (0.2 | ) |   |
| *Options*                        |       |                                     |       |                                 |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Calls (written)                  |       | Natural Gas                              |       | 1,095,000                            |       | 11.70 |   | 4.74 |   | — |   | (7.4 | ) | — |   |   | (1.8 | ) |   |
| Puts                             |       | Natural Gas                              |       | 1,095,000                            |       | 11.70 |   | 3.40 |   | — |   | — |   | — |   |   | — |   |   |
| ***Contracts maturing in 2007*** |       |                                     |       |                                 |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| *Swaps*                          |       |                                     |       |                                 |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Receive variable                 |       |                                     |       |                                 |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| /pay fixed                  |       | Natural Gas                              |       | 49,839,298                           |       | 9.40 |   | 7.20 |   | 102.2 |   | — |   | 0.6 |   |   | (8.2 | ) |   |
| Receive fixed                    |       | Natural Gas                              |       | 56,856,016                           |       | 6.94 |   | 9.78 |   | — |   | (150.2 | ) | 8.5 |   |   | (15.8 | ) |   |
| /pay variable                    |       | NGL                                      |       | 109,164,930                          |       | 0.66 |   | 0.96 |   | — |   | (30.3 | ) | 0.4 |   |   | (4.0 | ) |   |
|                             |       | Crude                                    |       | 388,680                              |       | 42.05 |   | 64.85 |   | — |   | (8.2 | ) | 0.2 |   |   | (1.3 | ) |   |
| Receive variable                 |       |                                     |       |                                 |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| /pay variable               |       | Natural Gas                              |       | 2,769,000                            |       | 9.37 |   | 9.23 |   | 0.4 |   | — |   | — |   |   | — |   |   |
| *Options*                        |       |                                     |       |                                 |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Calls (written)                  |       | Natural Gas                              |       | 1,095,000                            |       | 9.81 |   | 4.74 |   | — |   | (5.2 | ) | — |   |   | (1.5 | ) |   |
| Puts                             |       | Natural Gas                              |       | 1,095,000                            |       | 9.81 |   | 3.40 |   | — |   | — |   | — |   |   | — |   |   |
|                                  |            |                                          |            |                                      |            |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |

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| ***Contracts maturing in 2008***     |   |        |   |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
|--------------------------------------|--------|-------------|--------|------------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|--------|
| *Swaps*                              |   |        |   |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Receive variable                     |   |        |   |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| /pay fixed                      |   | Natural Gas |   | 10,236,065 |   | 8.35   |   | 7.23   |   | 10.3   |   | — |   | — |   |   | (1.9   | )      |   |
| Receive fixed                        |   | Natural Gas |   | 21,922,508 |   | 6.17   |   | 8.81   |   | — |   | (51.3  | )      | 2.3    |   |   | (12.2  | )      |   |
| /pay variable                        |   | NGL         |   | 30,636,396 |   | 0.61   |   | 0.90   |   | — |   | (7.8   | )      | 0.7    |   |   | (0.2   | )      |   |
|                                 |   | Crude       |   | 323,699    |   | 44.18  |   | 63.03  |   | — |   | (5.4   | )      | 0.5    |   |   | — |   |   |
| Receive variable                     |   |        |   |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| /pay variable                   |   | Natural Gas |   | 3,294,000  |   | 8.20   |   | 7.83   |   | 1.1    |   | — |   | — |   |   | — |   |   |
| *Options*                            |   |        |   |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Calls (written)                      |   | Natural Gas |   | 1,098,000  |   | 8.62   |   | 4.74   |   | — |   | (3.9   | )      | — |   |   | (1.2   | )      |   |
| Puts                                 |   | Natural Gas |   | 1,098,000  |   | 8.62   |   | 3.40   |   | — |   | — |   | 0.1    |   |   | — |   |   |
| ***Contracts maturing in 2009***     |   |        |   |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| *Swaps*                              |   |        |   |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Receive fixed                        |   | Natural Gas |   | 11,497,500 |   | 5.02   |   | 7.74   |   | — |   | (26.4  | )      | — |   |   | (9.8   | )      |   |
| /pay variable                        |   | Crude       |   | 155,125    |   | 53.13  |   | 61.76  |   | — |   | (1.1   | )      | — |   |   | — |   |   |
| Receive variable                     |   |        |   |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| /pay variable                   |   | Natural Gas |   | 4,197,500  |   | 7.32   |   | 7.10   |   | 0.8    |   | — |   | — |   |   | — |   |   |
| *Options*                            |   |        |   |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Calls (written)                      |   | Natural Gas |   | 1,095,000  |   | 7.74   |   | 4.74   |   | — |   | (3.1   | )      | — |   |   | (1.1   | )      |   |
| Puts                                 |   | Natural Gas |   | 1,095,000  |   | 7.74   |   | 3.40   |   | 0.1    |   | — |   | 0.2    |   |   | — |   |   |
| ***Contracts  maturing after 2009*** |   |        |   |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| *Swaps*                              |   |        |   |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Receive fixed                        |   |        |   |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| /pay variable                        |   | Natural Gas |   | 15,796,500 |   | 3.63   |   | 7.22   |   | — |   | (44.3  | )      | — |   |   | (18.3  | )      |   |
| *Options*                            |   |        |   |       |   |   |   |   |   |   |   |   |   |   |   |   |   |   |   |
| Calls (written)                      |   | Natural Gas |   | 2,190,000  |   | 7.12   |   | 4.74   |   | — |   | (5.1   | )      | — |   |   | (2.0   | )      |   |
| Puts                                 |   | Natural Gas |   | 2,190,000  |   | 7.12   |   | 3.40   |   | $      | 0.3    |   | — |   | 0.5    |   |   | — |   |   |
|                                      |        |             |        |            |        |        |        |        |        |        |        |        |        |        |        |        |        |        |        |  |

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(1)                 Volumesof Natural gas are measured in MMBtu, whereas volumes of NGL and Crude aremeasured in Bbl.

(2)                 Weightedaverage prices received and paid are in $/MMBtu for Natural gas and in $/Bblfor NGL and Crude.

(3)                 Thefair value is determined based on quoted market prices at September 30,2005 and December 31, 2004, respectively, discounted using the swap ratefor the respective periods to consider the time value of money. Fair values arepresented in millions of dollars.

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***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 fairmarket value of these derivative financial instruments reflects the estimatedamounts that we would pay or receive to terminate or close the contracts at thereporting date, taking into account the current unrealized losses or gains onopen contracts. We use external market quotes and indices to valuesubstantially all of the financial instruments we utilize.

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/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 our derivativefinancial instruments to receive hedge accounting treatment to mitigate thenoncash earnings 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. These non-qualifiedderivative financial instruments must be adjusted to their fair market value,or marked-to-market, each period, with the increases and decreases in fairvalue recorded as increases and decreases in Cost of natural gas in ourConsolidated Statements of Income. These mark-to-market adjustments produce adegree of earnings volatility that can often be significant from period toperiod, but have no cash flow impact relative to changes in market prices. Thecash flow impact occurs when the underlying physical transaction takes place inthe future and an associated financial 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 

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derivative transactions donot qualify for hedge accounting under SFAS No. 133, as the ultimate cashflow has not been 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 as we have the flexibility to make these changes in theunderlying injection or withdrawal schedule, given changes in marketconditions. Therefore, these transactions do not qualify for hedge accountingtreatment under SFAS No. 133, as the forecasted transaction is no longerprobable of occurring as originally set forth in the hedge documentationestablished at the inception of the hedge.

3.                **Natural Gas Collars**—In our Natural Gas segment, we hadpreviously entered into natural gas collars to hedge the sales price of naturalgas. The natural gas collars were based on a NYMEX price, while the physicalgas sales were based on a different index. To better align the index of thenatural gas collars with the index of the underlying sales, we de-designatedthe original hedging relationship and contemporaneously re-designated thenatural 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 written optionsunder SFAS No. 133 and do not qualify for hedge accounting. Thesederivatives are now accounted for in the Consolidated Statements of Income throughmark-to-market accounting, with the changes in fair value from the date of de-designationrecorded to earnings each period. As a result, our operating income will besubject to greater volatility due to movements in the prices of natural gasuntil the underlying long-term transactions are settled.

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

***Discontinuance of Hedge Accounting***

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

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loss from discontinuanceare approximately $2.1 million of net mark-to-market losses relating to hedgepositions that were closed out during the second quarter.

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  September 30,**     | ** ** | **Nine months ended  September 30,**      | ** ** |
|--------------------------------------------------------------|------------|------------------------|------------|----------------------------------------------------------|------------|----------------------------------------------------------|------------|
| **Derivative fair value gains (losses)** | ** ** | ** **             | ** ** | **    2005    ** | ** ** | **    2004    ** | ** ** | **    2005    ** | ** ** | **    2004    ** | ** ** |
| ** **                                                   | ** ** | **(in millions)** | ** ** |
| Natural Gas  segment                                         |       |                   |       |                                                     |       |                                                     |       |   |   |   |   |   |   |   |   |   |   |
| Ineffectiveness                                              |       |                   | $          | 0.1                                                      |       |                                                     |       | $ | — |   |   |   | $ | (1.9 | ) |   |   | $ | — |   |   |
| Non-qualified hedges                                         |       |                   | (9.6       | )                                                        |       |                                                     | —     |   |   |   | (20.7 | ) |   |   | — |   |   |
| Marketing                                                    |       |                   |       |                                                     |       |                                                     |       |   |   |   |   |   |   |   |   |   |   |
| Non-qualified hedges                                         |       |                   | (43.1      | )                                                        |       |                                                     | 0.3        |   |   |   | (37.8 | ) |   |   | (1.4 | ) |   |
| Discontinuance                                               |       |                   | —     |                                                     |       |                                                     | —     |   |   |   | (9.0 | ) |   |   | — |   |   |
| Derivative fair value  gains (losses)                        |       |                   | $          | (52.6                                                    | )          |                                                     |       | $ | 0.3 |   |   |   | $ | (69.4 | ) |   |   | $ | (1.4 | ) |   |

 

We record the change in fair value of our highlyeffective cash flow hedges in our OCI until the derivative financialinstruments are settled, at which time they are reclassified to earnings. Forthe three and nine months ended September 30, 2005, we reclassifiedunrealized losses of $11.5 million and $36.7 million from OCI to Cost ofnatural gas on our Consolidated Statements of Income for the fair value ofderivative financial instruments that were settled.

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

| ** **                   | ** ** | **September 30,  2005** | ** ** | **December 31,  2004** | ** ** |
|------------------------------|------------|------------------------------|------------|-----------------------------|------------|
| ** **                   | ** ** | **(in millions)**       | ** ** |
| Receivables, trade and other |       |                         | $          | 16.2                        |       |   |   | $ | 8.2 |   |   |
| Other assets, net            |       |                         | 7.0        |                        |       |   | 10.1 |   |   |
| Accounts payable  and other  |       |                         | (177.9     | )                           |       |   | (45.9 | ) |   |
| Other long-term  liabilities |       |                         | (264.4     | )                           |       |   | (99.6 | ) |   |
|                         |       |                         | $          | (419.1                      | )          |   |   | $ | (127.2 | ) |   |

 

The increase in our obligation associated with ourderivative activities from December 31, 2004 to September 30, 2005 isprimarily due to the significant increases in forward natural gas and NGLprices. The Partnership’s portfolio of derivative financial instruments islargely comprised of long-term fixed price sales agreements.

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

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**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 September 30, 2005. Based upon thatevaluation, our principal executive officer and principal financial officerconcluded that our disclosure controls and procedures are effective toaccomplish their purpose. In conducting this assessment, our management reliedon similar evaluations conducted by employees of Enbridge affiliates whoprovide certain treasury, accounting and other services on our behalf. Nochanges in our internal control over financial reporting were made during thethree months ended September 30, 2005, that would materially affect ourinternal control over financial reporting, nor were any corrective actions withrespect to significant deficiencies or material weaknesses necessary subsequentto 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 5.**                        OtherInformation

The Partnership hasadopted a set of Corporate Governance Guidelines, which affirm our commitmentto maintaining a high standard of corporate governance. The guidelines areapplicable to all of our employees, officers and directors. A copy of theCorporate Governance Guidelines are available on our website atwww.enbridgepartners.com. Additionally, this material is available in print,free of charge, to any person who requests the information. Persons wishing toobtain this printed material should submit a request to Corporate Secretary,c/o Enbridge Energy Partners, L.P., 1100 Louisiana, Suite 3300, Houston, TX77002.

**Item 6.**                        Exhibits

Eachexhibit identified below is filed as part of this document. Exhibits notincorporated by reference to a prior filing are designated by an “*”; allexhibits not so designated are incorporated herein by reference to a previousfiling as indicated.
| 3.1   |   | Certificate of Limited Partnership of the  Partnership (incorporated by reference to Exhibit 3.1 to the  Partnership’s Registration Statement No. 33-43425).                                                                                                                                                                                                                                                                                                                                                                          |
|-------|--------|------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------|
| 3.2   |   | Certificate of Amendment  to Certificate of Limited Partnership of the Partnership (incorporated by  reference to Exhibit 3.2 to the Partnership’s 2000 Form 10-K/A  dated October 9, 2001).                                                                                                                                                                                                                                                                                                                                     |
| 3.3   |   | 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).                                                                                                                                                                                                                                                                                                                                                       |
| 10.1  |   | Fourth Amendment to the  Amended and Restated Credit Agreement, dated January 24, 2003 (as  amended by the First Amendment, dated January 12, 2004, the Second  Amendment, dated April 26, 2004, and the Third Amendment dated  April 14, 2005), by and among the Partnership, the lenders from time to  time parties thereto, and Bank of America, N.A., as administrative agent  (incorporated by reference to Exhibit 10.1 to the Partnership’s Current  Report on Form 8-K filed on September 21, 2005). |
| 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:  October 28, 2005 | By:      | /s/ DAN C. TUTCHER                                                                                          |
|                         |     | Dan C. Tutcher                                                                                              |
| * *                     | * * | *President and Director*                                                                                    |
| * *                     | * * | *(Principal Executive Officer)*                                                                             |
| Date October 28,  2005  | By:      | /s/ MARK A. MAKI                                                                                            |
| * *                     |     | Mark A. Maki                                                                                                |
| * *                     | * * | *Vice President, Finance*                                                                                   |
| * *                     | * * | *(Principal Financial Officer)*                                                                             |

 

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