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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q/A
AMENDMENT NO. 1

ý	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2004
OR
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                             to

Commission file number 1-31383

ENBRIDGE ENERGY PARTNERS, L.P.
(Exact name of registrant as specified in its charter)

Delaware (State or other jurisdiction of incorporation or organization)		61-1414604 (I.R.S. Employer Identification No.)
1100 Louisiana Suite 3300 Houston, TX 77002 (Address of principal executive offices and zip code)
(713) 821-2000 (Registrant's telephone number, including area code)

        Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý    No o

        Indicate by checkmark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes ý    No o

        The Registrant had 40,616,134 Class A common units outstanding as of July 30, 2004.

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TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION
Item 2.		Management's Discussion and Analysis of Financial Condition and Results of Operations		4
Signature				14

        This Quarterly Report on Form 10-Q/A contains forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. They use words such as "anticipate," "believe," "continue," "estimate," "expect," "forecast," "intend," "may," "plan," "position," "projection," "strategy," or "will," or the negative of those terms or other variations of them or by comparable terminology. In particular, statements, express or implied, concerning future actions, conditions or events or future operating results or the ability to generate sales, income or cash flow or to make distributions are forward-looking statements. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. Future actions, conditions or events and future results of operations may differ materially from those expressed in these forward-looking statements. Many of the factors that will determine these results are beyond the ability of Enbridge Energy Partners, L.P. (the "Partnership") to control or predict. For additional discussion of risks, uncertainties, and assumptions, see the Partnership's Annual Report on Form 10-K for the fiscal year ended December 31, 2003.

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EXPLANATORY NOTE

        This Amendment No. 1 to Quarterly Report on Form 10-Q/A to the Quarterly Report on Form 10-Q of Enbridge Energy Partners, L.P. (the "Partnership") filed with the Securities and Exchange Commission ("SEC") on August 9, 2004, is to clarify certain information in Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations, to state the amount of capital expenditures that have been expended as of June 30, 2004 and to amend a table detailing the types of capital expenditures forecast during 2004. In particular, under the caption "Capital Expenditures," the amount of capital expenditures that have been expended as of June 30, 2004 was changed to $70 million from $200 million to match the applicable line item on the statement of cash flows. As well, the table under such caption was amended to delete the Acquisitions row and change the amount of forecast capital expenditures on the System enhancements row to $200.0 million from $70.0 million. No other changes were made in Item 2.

        Item 2 of the Partnership's Quarterly Report on Form 10-Q for the three and six months ended June 30, 2004, which is amended and restated herein as follows:

1.

Part I, Item 2—Management's Discussion and Analysis of Financial Condition and Results of Operations



2.

The certificates required by Sections 302 and 906 of the Sarbanes-Oxley Act of 2002 have been re-executed.

        Except as otherwise expressly noted herein, this Amendment No.1 to our Quarterly Report on Form 10-Q/A does not reflect events occurring after the August 9, 2004 filing of the Partnership's Quarterly Report on Form 10-Q for the three and six months ended June 30, 2004, or modify or update the disclosures set forth in that Quarterly Report on Form 10-Q in any way, except as required to reflect the effects of the items described in Part I, Item 2 above.

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ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

        This discussion summarizes the significant factors affecting the Partnership's consolidated operating results, liquidity and capital resources during the six months ended June 30, 2004. This discussion should be read in conjunction with the financial statements and financial statement footnotes that are included in the Partnership's Annual Report on Form 10-K for the fiscal year ended December 31, 2003.

OVERVIEW OF SECOND QUARTER 2004 RESULTS

        During the second quarter of 2004, the Partnership achieved record quarterly net income as it realized progress on its strategic plan, which focuses on the development and acquisition of complementary businesses and expansion of existing assets.

        Operating income was $58.0 million for the second quarter of 2004, an increase of 35% over the same quarter in 2003. Increases were recorded in the Partnership's Liquids and Natural Gas segments. Acquisitions made since December 2003 contributed to the majority of the increase, along with improved deliveries on the Lakehead system and higher volumes on some of the Partnership's natural gas systems.

        Operating income was $110.6 million for the first six months of 2004, an increase of 14% over the same period in 2003. Contributions from acquisitions accounted for the majority of the increase, offset by lower earnings in the Marketing segment.

        Earnings per unit increased 44% to $0.56 per unit for the second quarter of 2004, compared with $0.39 for the same quarter of 2003. Earnings per unit was higher for the second quarter of 2004 due to the increase in net income, partially offset by an increase in the number of common units outstanding. Since the first quarter of 2003, the Partnership has issued 9,302,500 Class A common units and 1,003,079 i-units, which increased the weighted average number of common units outstanding from 46.8 million during the second quarter of 2003 to 54.9 million in the second quarter of 2004.

BUSINESS SEGMENTS

        During the second quarter of 2004, the Partnership changed its reporting segments. The Natural Gas Transportation segment was combined with the Gathering and Processing segment to form one new segment called "Natural Gas". Liquids Transportation was renamed to "Liquids" and there were no changes to the Marketing segment. These changes were a result of newly stated internal performance measures for the Partnership. The new segments are consistent with how management

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makes resource allocation decisions, evaluates performance, and furthers the achievement of the Partnership's long-term objectives. Financial information for prior periods was reclassified to reflect the new segmentation.

ACQUISITIONS

        Effective March 1, 2004, the Partnership acquired crude oil pipeline and storage systems for $116.9 million, including transaction costs of $2.0 million. The assets, referred to as the Mid-Continent system, serve refineries in the U.S. Mid-Continent from Cushing, Oklahoma, and consist of over 480 miles of crude oil pipelines and 9.5 million barrels of storage capacity. The Mid-Continent system's results of operations are included in the Liquids segment from the date of acquisition.

        Effective March 1, 2004, the Partnership acquired natural gas transmission and gathering pipeline assets for $13.1 million. The assets, referred to as the Palo Duro system, are located in Texas and are complementary to the Partnership's existing natural gas systems in the area. The Palo Duro system's results of operations are included in the Natural Gas segment from the date of acquisition.

RESULTS OF OPERATIONS BY SEGMENT

Liquids

Three months ended June 30, 2004 compared with three months ended June 30, 2003

        Operating income for the Liquids segment increased by approximately $8.0 million to $35.4 million for the three months ended June 30, 2004, compared with $27.4 million for the same period in 2003. The most significant reason for the increase was the full-quarter contribution from the Mid-Continent system from the date of acquisition by the Partnership on March 1, 2004. The Mid-Continent system contributed $5.2 million to operating income during the second quarter. The Mid-Continent system derives approximately two-thirds of its revenues from fee-based services on pipelines regulated by the Federal Energy Regulatory Commission (the "FERC"). Consistent with the Partnership's other liquids pipelines, the Mid-Continent's pipeline tariffs are subject to inflation indexing effective July 1 of each year. The balance of the revenue on the Mid-Continent system is from storage contracts, the majority of which are longer-term.

        Operating revenue for the second quarter of 2004 was $102.7 million, compared with $81.8 million for the second quarter of 2003. The increase of $20.9 million was primarily due to the full-quarter contribution from the Mid-Continent system of $10.1 million, as well as increased volumes transported on the Lakehead system.

        Deliveries on the Lakehead system increased 13%, from 1,294 thousand barrels per day ("bpd") during the second quarter of 2003 to 1,458 thousand bpd during the same period in 2004, which resulted in higher operating revenue of approximately $10 million. Production of western Canadian crude oil increased over 2003 primarily due to the start up of the Athabasca Oil Sands Project ("AOSP") in June 2003. The AOSP is owned by Shell Canada Limited, Chevron Canada Limited and Western Oil Sands L.P., and consists of oil sands mining and bitumen extraction operations. The positive impact to revenue of the increased deliveries was offset slightly by a decrease in overall tariffs,

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primarily due to the reduction of the Terrace incremental surcharge effective April 1, 2004. The following table sets forth the operating statistics for the Liquids assets for the periods presented.

        Power costs increased by $4.1 million, from $13.0 million in the second quarter of 2003 to $17.1 million in the second quarter of 2004. The increase was primarily related to the growth in volumes on the Lakehead system and higher mill-rates attributable to higher demand costs, as well as escalating fuel costs. Power costs associated with the Mid-Continent system were $1.0 million in the second quarter of 2004.

        Operating and administrative expenses increased by $6.5 million, from $26.9 million in the second quarter of 2003 to $33.4 million for the second quarter of 2004. The recently acquired Mid-Continent assets accounted for approximately $2.6 million of the increase. Related to the Lakehead and North Dakota systems, oil measurement losses were higher in the second quarter of 2004 by approximately $2.9 million when compared with the second quarter of 2003, due to refinements in the process of valuing oil measurement losses and an increase in physical losses. Physical losses are part of normal operating conditions and occur through evaporation, shrinkage, differences in measurements between receipt and delivery locations, and other incidents. Operating and administrative expenses were also higher in the second quarter of 2004 by approximately $2.2 million when compared with the second quarter of 2003, due to increased property taxes. The Partnership has experienced a trend of increasing property taxes partially due to new facilities placed into service, and also due to increases from the taxing authorities in counties and states where pipeline assets are located. These increases in operating and administrative expenses were partially offset by lower leak remediation and repair costs of approximately $2.4 million, as the second quarter of 2003 included expenses associated with Lakehead system leaks that occurred during the first six months of 2003.

        Depreciation expense was $16.8 million for the second quarter of 2004, compared with $14.5 million for the second quarter of 2003. Depreciation on the Mid-Continent system accounted for $1.2 million and the balance relates to new facilities placed into service during 2003.

Six months ended June 30, 2004 compared with six months ended June 30, 2003

        Operating income increased for the six months ended June 30, 2004 by $6.7 million to $66.0 million, compared with $59.3 million for the six months ended June 30, 2003. Operating income was higher in 2004 primarily due to the four-month contribution from the Mid-Continent system of $6.0 million.

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        Operating revenue for the first six months of 2004 increased by $27.2 million to $194.4 million, compared with $167.2 million for the same period in 2003. Approximately half of the increase was due to contributions from the Mid-Continent system and the remainder from the Lakehead system for the same reasons as noted above in the three-month analysis.

        Operating and administrative expenses for the first six months of 2004 increased by $7.9 million to $61.2 million, compared with $53.3 million for the same period in 2003. Approximately half of the increase was due to contributions from the Mid-Continent system and the remainder from the Lakehead system for the same reasons as noted above in the three-month analysis.

        Depreciation expense was $32.9 million for the six months ended June 30, 2004, compared with $28.9 million in 2003. Depreciation related to the Mid-Continent system was $1.6 million and the balance was due to the same reasons as noted above in the three-month analysis.

Natural Gas

        The following table indicates the average daily volume for each of the major systems in the Partnership's Natural Gas segment during the periods presented, in million British thermal units per day ("MMBtu/d").

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*Note: East Texas now includes the combined systems previously referred to as East Texas and Northeast Texas.

Three months ended June 30, 2004 compared with three months ended June 30, 2003

        Operating income for the Natural Gas segment increased by $8.1 million to $22.6 million for the three months ended June 30, 2004, compared with $14.5 million for the same period in 2003.

        Compared with the second quarter of 2003, average daily volumes on the Partnership's major Natural Gas systems increased approximately 20% from 1,511,000 MMBtu/d to 1,815,000 MMBtu/d in the second quarter of 2004. The most significant reason for the increase was the contribution of the North Texas results in the second quarter of 2004, from the date of acquisition by the Partnership on December 31, 2003. The North Texas system contributed $6.2 million to operating income during this period. The North Texas system derives the majority of its revenues from the sharing of sales proceeds net of costs, of natural gas and natural gas liquids under contracts with natural gas producers. The direct commodity price exposure inherent in such contracts has been largely mitigated through a hedging strategy. The remainder of the revenue is derived from fees charged for gathering and treating of natural gas volumes and other related services.

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        The East Texas system includes the combined results of the systems previously referred to as East Texas and Northeast Texas. The Partnership has completed projects that allow for operation of these assets as one integrated system, now referred to as "East Texas". Comparative results have been reclassified to conform with this presentation.

        Volumes on the East Texas system increased by 13% in the second quarter of 2004 compared with the same period in 2003, as a result of increased drilling by producers of gas wells in the areas served by this system. In addition, processing results improved on the East Texas system in the second quarter of 2004 due to more favorable natural gas liquids ("NGLs") pricing conditions compared with the same period in 2003. Operating and administrative expenses increased in 2004 due to higher workforce related costs and timing of repairs and maintenance activities that mostly offset the positive gains from the improved volumes and processing results. As a result, operating income on the East Texas system decreased slightly by approximately $0.3 million, from $7.0 million during the second quarter of 2003, to $6.7 million in the second quarter of 2004.

        Volumes on the Anadarko system increased 27% in the second quarter of 2004 compared with the same period in 2003. The growth is a result of increased drilling activity in the Texas panhandle and western Oklahoma regions. Similar to the East Texas system, processing results improved on the Anadarko system during the second quarter of 2004 due to a more favorable natural gas and NGL pricing environment. These improvements were partially offset by higher operating and administrative expenses related to variable costs associated with the increased volumes on the system and higher property taxes. As a result, operating income on the Anadarko system increased by approximately $3.6 million, from $3.3 million in the second quarter of 2003 to $6.9 million in the second quarter of 2004.

        Volumes on the KPC system decreased 36% in the second quarter of 2004, compared with the second quarter of 2003. This decrease is attributable to warmer weather in 2004, creating less demand by KPC customers. As the revenues of KPC depend largely upon fees derived from reserved pipeline capacity, this volume decline did not impact revenue. Operating income was lower by $2.3 million during the second quarter of 2004 primarily due to lower fuel retainage, revaluations of operational balancing agreements and measurement losses.

        The remainder of the improved operating income in the Natural Gas segment was due to net positive results on a number of natural gas systems.

Six months ended June 30, 2004 compared with six months ended June 30, 2003

        Operating income for the Natural Gas segment increased by $11.5 million to $43.7 million for the six months ended June 30, 2004, compared with $32.2 million for the same period in 2003. The most significant reason for the increase was the contribution of the North Texas results in the first half of 2004. The North Texas system contributed $11.6 million to operating income during this period. On the Partnership's other major Natural Gas systems, positive impacts from increased drilling activity and favorable processing earnings were offset by higher operating and administrative costs, as noted above in the three-month analysis.

Marketing

Three months ended June 30, 2004 compared with three months ended June 30, 2003

        Operating income for the Marketing segment was $0.7 million for the second quarter of 2004, compared with $1.8 million for the second quarter of 2003. Operating income in 2004 included a charge of $1.3 million associated with hedges that do not qualify for hedge accounting treatment under Statement of Financial Accounting Standards ("SFAS") No. 133. The Partnership enters into financial natural gas basis swap transactions to mitigate the risk on index pricing differentials between its

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physical gas purchases and corresponding gas sales. When the gas sales pricing index is different from the gas purchase pricing index, the Partnership is exposed to relative changes in those two index levels. By entering into a basis swap between those two indices, the Partnership can effectively lock in the margin on the combined gas purchase and the gas sale, removing any market price risk on the physical transactions. Although this is a sound economic hedging strategy, these types of financial transactions do not qualify for hedge accounting under the SFAS No. 133 guidelines. As such, the unqualified hedges are accounted for on a mark to market basis, and the periodic change in their market value will impact the income statement.

Six months ended June 30, 2004 compared with six months ended June 30, 2003

        Operating income for the Marketing segment was $2.9 million for the six months ended June 30, 2004, compared with $7.2 million for the same period in 2003. Stronger results in 2003 were due to the Partnership's ability to optimize natural gas supply to areas of strongest demand and profit within its operational area during the first four months of 2003. Operating revenue less cost of natural gas was greater due to the unusual volatility in natural gas prices during this time period. This volatility was due to unusually cold weather, lower volumes of natural gas in storage and, generally, a tighter supply of natural gas in North America. During the first six months of 2004, natural gas prices were less volatile due to more stable market conditions. Also contributing to the stronger operating results in 2003 was a non-recurring gain of approximately $2.0 million due to the settlement of disputed amounts. As well, the results for the first six months of 2004 include the mark to market losses of $1.7 million as noted above.

LIQUIDITY AND CAPITAL RESOURCES

        The Partnership believes that it will continue to have adequate liquidity to fund future recurring operating and investing activities. The Partnership's primary cash requirements consist of normal operating expenses, maintenance and expansion capital expenditures, debt service payments, distributions to partners and acquisitions of new assets or businesses. Short-term cash requirements, such as operating expenses, maintenance capital expenditures and quarterly distributions to partners, are expected to be funded by operating cash flows. Long-term cash requirements for expansion projects and acquisitions are expected to be funded by several sources, including cash flows from operating activities, borrowings under credit facilities and the issuance of additional equity and debt securities, including common units and i-units. The Partnership's ability to complete future debt and equity offerings and the timing of any such offerings will depend on various factors, including prevailing market conditions, interest rates and the financial condition of the Partnership and its credit rating at the time.

        On April 26, 2004, the Partnership amended its unsecured multi-year revolving credit facility and terminated its existing 364-day revolving credit facility, each of which was originally entered into in January 2003. The amended facility consists of a $600.0 million three-year term senior credit facility (the "Senior Credit Facility"), which matures in 2007. Interest is charged on amounts drawn under this facility at a variable rate equal to the Base Rate or a Eurodollar rate as defined in the facility agreement. In the case of Eurodollar rate loans, an additional margin is charged which varies depending on the Partnership's credit rating and the amounts drawn under the facility. A facility fee is payable on the entire amount of the facility whether or not drawn. The facility fee varies depending on the Partnership's credit rating. As of June 30, 2004, the facility fee was 0.175%. The Senior Credit Facility contains restrictive covenants that require the Partnership to maintain a minimum interest coverage ratio of 2.75 times and a maximum leverage ratio of 5.25 times for eighteen months until September 2005, decreasing to 5.00 times thereafter, as described in the Senior Credit Facility. At June 30, 2004, the interest coverage ratio was approximately 4.2 and the leverage ratio was approximately 4.1. The Senior Credit Facility also places limitations on the amount of debt that may be

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incurred directly by the Partnership's subsidiaries. Accordingly, it is expected that the Partnership will provide debt financing to its subsidiaries as required. As of June 30, 2004, $380.0 million was drawn on the Partnership's Senior Credit Facility at a weighted average interest rate of 1.9%.

        On January 9, 2004, the Partnership issued an additional $200.0 million in aggregate principal amount of its 4.0% Senior Unsecured Notes due 2009 in a public offering, from which it received net proceeds of $198.3 million. The Partnership used the proceeds to repay a portion of its outstanding debt under bank credit facilities.

        On January 2, 2004, the Partnership issued an additional 450,000 Class A common units pursuant to the underwriters' exercise of the over-allotment option as part of the December 2003 Class A common unit issuance, resulting in additional proceeds to the Partnership, net of underwriters' fees and discounts, commissions and issuance expenses, of approximately $21.6 million. In addition to the proceeds generated from the unit issuance, the General Partner contributed $0.4 million to the Partnership to maintain its 2% general partner interest in the Partnership.

        Working capital, defined as current assets less current liabilities, improved by $208.9 million to $29.1 million at June 30, 2004, compared with a deficit of $179.8 million at December 31, 2003. This improvement was primarily due to the reduction in current maturities and short-term debt related to the 364-day credit facility. The Partnership used a portion of the net proceeds from its issuance of Senior Unsecured Notes in January 2004 to repay a portion of its outstanding debt under bank credit facilities, and terminated the balance of the facilities at the end of April 2004, as noted above.

        At June 30, 2004, cash and cash equivalents totaled $70.5 million, compared with $64.4 million at December 31, 2003. Of this amount, $56.7 million ($0.925 per unit) will be used for the cash distribution declared on July 22, 2004. Of the cash available for distribution, $9.7 million will be retained from i-unitholders and $0.2 million retained from the General Partner, to be used by the Partnership in its business.

Operating Activities

        Net cash provided by operating activities for the six months ended June 30, 2004 was $154.1 million, compared with $86.7 million for the same period in 2003. Improved operating cash flow was the result of contributions from the North Texas and Mid-Continent assets, as well as improved results from the Partnership's existing assets. The remaining changes in cash from operating activities were due to changes in the operating assets and liabilities from increased natural gas prices in the second quarter of 2004 and general timing differences in the collection on and payment of the Partnership's current accounts.

Investing Activities

        Net cash used in investing activities during the six months ended June 30, 2004 was $199.7 million, compared with $51.4 million for the same period in 2003. The increase of $148.3 million was primarily attributable to higher cash outflows made for strategic acquisitions, as well as increased cash outflow for expansion and growth opportunities.

Financing Activities

        Net cash provided by financing activities during the six months ended June 30, 2004 was $51.7 million, compared with net cash used in financing activities of $21.4 million for the same period in 2003. The increase of $73.1 million in cash flow is primarily due to a reduction in the repayments of debt. The improvement in cash flow is offset by an increase in cash used for distributions to partners, and a reduction in the proceeds from additional Class A common unit issuances in 2004, compared with 2003. Distributions to partners were higher in 2004 due to an increase in the number of units outstanding, as a result of the unit issuances in May and December 2003, and January 2004, as well as a related increase in the general partner incentive distributions resulting from higher distributions to unit holders.

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CAPITAL EXPENDITURES

        Capital expenditures are categorized by the Partnership as either core maintenance or enhancement expenditures. Core maintenance expenditures are those expenditures that are necessary to maintain the service capability of the existing assets and includes the replacement of system components and equipment which are worn, obsolete or completing their useful lives. Enhancement expenditures improve the service capability of the existing assets, extend asset useful lives, increase capacities from existing levels, reduce costs or enhance revenues and enable the Partnership to respond to governmental regulations and developing industry standards. For the full year 2004, the Partnership anticipates capital expenditures to approximate $368.0 million, as illustrated in the table that follows. Of the $368.0 million, approximately $70 million has been expended as of June 30, 2004.

        As of June 30, 2004, the Partnership has entered into contractual commitments of approximately $60 million. Of this amount, approximately $45 million relates to the East Texas expansion, and the balance relates to a processing plant and additional compression facilities on the Anadarko system. Substantially, all of the amounts are expected to be settled by December 31, 2004.

        Excluding major expansion projects and acquisitions, ongoing capital expenditures are expected to average approximately $125 million annually (approximately 35% for core maintenance and 65% for system enhancements).

        The Partnership anticipates funding the expenditures temporarily through its bank credit facilities, with permanent debt and equity funding being provided when appropriate.

        The Partnership expects to incur continuing annual capital and operating expenditures for pipeline integrity measures to ensure both regulatory compliance and to maintain the overall integrity of the pipeline systems. Expenditure levels have continued to increase as pipelines age and require higher levels of inspection or maintenance; however, these are viewed to be consistent with industry trends. Included in the anticipated capital expenditures spending for system enhancements in 2004 is approximately $25.0 million of capital expenditures to ensure regulatory compliance on the Lakehead system. This spending is for pressure testing of the Lakehead system to establish operating pressures in excess of operating limits that would otherwise be allowed under current circumstances.

FUTURE PROSPECTS

Natural Gas

        During the first half of 2004, a variety of pipeline infrastructure assets have been tendered for sale with other significant asset packages anticipated to be for sale. Competition among prospective acquirers of assets has been significant, and management of the Partnership has observed that prices paid for assets in these competitive settings has increased. Despite the increasingly competitive environment, management of the Partnership continues to pursue its strategy of growth by acquisition and remains committed to making accretive acquisitions in or near areas where the Partnership already operates. These situations present the best opportunities for consolidation savings and enhancement of the Partnership's market position.

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        Natural gas development activity in and around the Partnership's Texas-based natural gas assets continues to be robust. To service increased amounts of natural gas flowing through the Partnership's systems, management and the Board of Directors have approved several projects around the East Texas, Anadarko and North Texas systems. These projects include the installation of a processing plant on the Anadarko System, and compression, pipeline and interconnect facilities on all systems. In the aggregate, these projects total approximately $40 million and will enter into service later in 2004 or early 2005. Additional expansions approximating $40 million may be undertaken if appropriate customer support can be obtained.

        The Partnership has placed an order for pipe and has requested bids from contractors for construction of the previously announced $150 million East Texas expansion. Sufficient contractual support for the expansion has been obtained from customers to proceed with construction and completion of the project is expected by May 2005. Approximately two thirds of the cost of the expansion will be incurred in 2004, with the remainder in early 2005.

Liquids

        The Partnership is initiating work on eight new storage tanks at its Cushing, Oklahoma terminal with an aggregate capacity of 3.7 million barrels. The storage tanks will be contracted to customers, with the Partnership earning a fee on the contracted tankage. Four of the storage tanks are expected to be placed in-service during mid-2005, with the remainder placed in-service in late 2005 or early 2006.

        Two market access initiatives previously announced by the Partnership and Enbridge Inc. ("Enbridge"), the Southern Access project and the Spearhead Pipeline, respectively, continue to be pursued with customers. To date, customer support for the projects has not been sufficient to initiate the reversal of Enbridge's Spearhead line or commence construction on Southern Access. Management of Enbridge and the Partnership continues to pursue both projects or alternatives to each project. Competitors of the Partnership have advocated competitive proposals to the Southern Access project. Management believes that Southern Access, or a similar project, presents the most cost-effective alternative for its customers.

OFF BALANCE SHEET ARRANGEMENTS

        The Partnership has no off-balance sheet arrangements.

SUBSEQUENT EVENT

Distribution Declaration

        On July 22, 2004, the Partnership's Board of Directors declared a distribution payable on August 13, 2004. The distribution will be paid to unitholders of record as of August 2, 2004, of its available cash of $56.7 million at June 30, 2004, or $0.925 per common unit. Of this distribution, $9.7 million will be distributed in i-units to its i-unit holder and $0.2 million will be retained from the General Partner in respect of this i-unit distribution.

REGULATORY MATTERS

        Effective July 1, 2004, in compliance with the indexed rate ceilings allowed by the FERC, the Partnership increased its rates for transportation on the Lakehead, North Dakota and Ozark systems, crude oil pipelines by an average of approximately 3.17%. For the Lakehead system, indexing only applies to its base rates. The Partnership anticipates that the increase in tariff rates will not have a material impact on the Partnership's financial condition and results of operations.

        Included with the July 1, 2004 tariff filing for the Lakehead system are tariff increases related to a Facilities Surcharge that was filed as an Offer of Settlement with the FERC on May 20, 2004 in Docket

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No. OR -04-2-000. This offer of settlement was approved by the FERC on June 30, 2004 as being fair, reasonable and in the public interest. The Facilities Surcharge has the support of the Canadian Association of Petroleum Producers ("CAPP"), an association that represents the producers of virtually all of the crude petroleum transported on the Lakehead system. The Facilities Surcharge included in the filing represents cost recoveries for four projects that have been completed or are expected to be in operation in the near future. The projects were undertaken by the Partnership at shipper requests for enhancements or modifications to permit greater flexibility in the types of crude oil handled or greater access by shippers to particular markets or crude oil types. The Partnership anticipates that the increase in tariff rates will not have a material impact on the Partnership's financial condition and results of operations. On the Lakehead system, the new rate for light crude movements from the International Border to Chicago is $0.69 per barrel, which reflects an approximate 2 cents per barrel increase over rates filed effective April 1, 2004.

        On July 20, 2004, the U.S. Court of Appeals for the District of Columbia Circuit issued a decision regarding the proper income tax allowance for SFPP, a pipeline owned by another publicly traded partnership, BP West Coast Products LLC v. FERC (No. 99-1020) ("BP West Coast"). The FERC had included an income tax allowance in the SFPP cost of service representing the percentage interest in the SFPP limited partnership held by SFPP, Inc., a subchapter C corporation. The Court of Appeals, eliminated the tax allowance in the SFPP cost of service because the SFPP limited partnership itself had no tax liability and remanded the case to the FERC for further review. Further appellate review of the BP West Coast decision is discretionary with the courts, and the Partnership cannot predict whether it will occur.

        The Partnership's rates have been established under a variety of different circumstances including settlements and tariff indexing. Since an income tax allowance is only one of many elements supporting a pipeline's rates for service, the Partnership cannot predict with certainty what rates it will be allowed to charge in the future, or the potential impacts of the BP West Coast decision.

        Parties can challenge the rates on the Partnership's common carrier interstate liquids pipelines on the basis that those rates are not just and reasonable. Such a challenge could seek a prospective change in the pipelines' rates, as well as reparations (i.e., damages for overcharges for specific shippers) for up to two years prior to the date of the complaint. An income tax allowance is one of many elements supporting a pipeline's rates for service (others include, but are not limited to, equity investment, rate of return, operation and maintenance expenses, depreciation and volumes). If a rate review process were to be initiated, and the BP West Coast decision were followed, the Partnership's rates for its interstate liquids pipelines would no longer include an income tax allowance. Depending on the conclusions reached with respect to the other various rate elements, apart from the income tax allowance, such a ruling could reduce the Partnership's rates, which would impact the Partnership's results of operations and cash flows.

        The Court's decision on income tax allowance in BP West Coast does not address the rate methodology for interstate natural gas pipelines regulated by the FERC. If the rationale in the BP West Coast decision were extended to FERC regulated natural gas pipelines, the future rates charged by the Partnership's interstate natural gas pipelines may not include an income tax allowance. Such a change would be prospective only and would not include reparations for prior periods.

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SIGNATURE

        Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		ENBRIDGE ENERGY PARTNERS, L.P.       (Registrant)
		By:	Enbridge Energy Management, L.L.C. as delegate of Enbridge Energy Company, Inc. as General Partner
				/s/  MARK A. MAKI       Mark A. Maki Vice President, Finance and Principal Financial Officer (Duly Authorized Officer)

Date: August 16, 2004                        

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EXPLANATORY NOTE

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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