ENBRIDGE ENERGY PARTNERS LP - 10-Q Quarterly Report

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

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

The Registrant had 44,296,134 Class A common units outstanding as of November 5, 2004.

This Quarterly Report on Form 10-Q 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," "could," "should," or "will" or the negative of those terms or other variations of them or comparable terminology. In particular, statements, expressed or implied, concerning future actions, conditions or events or future operating results or the ability to generate revenues, income or cash flow 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.

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

ENBRIDGE ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

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

The accompanying unaudited interim consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America for interim consolidated financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. Accordingly, they do not include all the information and footnotes required by accounting principles generally accepted in the United States of America for complete consolidated financial statements. In the opinion of management, they contain all adjustments, consisting only of normal recurring adjustments, which management considers necessary to present fairly the financial position as of September 30, 2004 and December 31, 2003; the results of operations for the three and nine month periods ended September 30, 2004 and 2003; and cash flows for the nine month periods ended September 30, 2004 and 2003. The results of operations for the three and nine months ended September 30, 2004 should not be taken as indicative of the results to be expected for the full year, due to seasonality of portions of the natural gas business and maintenance activities. The interim consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto of Enbridge Energy Partners, L.P. (the "Partnership"), presented in the Partnership's Annual Report on Form 10-K for the fiscal year ended December 31, 2003.

On March 1, 2004, the Partnership acquired crude oil pipeline and storage assets, known as the Mid-Continent system, for $116.9 million, including transaction costs of $2.0 million. The results of operations are included in the Partnership's financial statements as of the acquisition date. The assets acquired serve refineries in the U.S. Mid-Continent from Cushing, Oklahoma and include:

These systems were acquired to provide cash flows primarily from toll or fee-based revenues from a combination of regulated assets and contracted unregulated assets. The assets and results of operations are included in the Partnership's Liquids segment from the date of acquisition.

The purchase price and the allocation to assets acquired and liabilities assumed were as follows:

		(dollars in millions)
Purchase Price:
	Cash paid, including transaction costs	$	116.9

Allocation of purchase price:
	Property, plant and equipment, including construction in progress	$	117.5
	Current assets		0.1
	Current liabilities		(0.2	)
	Environmental liabilities		(0.5	)

Total		$	116.9

On March 1, 2004, the Partnership purchased natural gas transmission and gathering pipeline assets for $13.1 million. The assets, referred to as the "Palo Duro" system, are located in Texas between the Partnership's existing Anadarko system and the recently acquired North Texas system, and are expected to increase natural gas delivery flexibility to the Partnership's customers. The assets purchased include approximately 400 miles of natural gas transmission and gathering pipelines, together with 5,200 horsepower of compression. There was no goodwill recorded for the purchase of the Palo Duro system. The Palo Duro system's results of operations are included in the Partnership's Natural Gas segment from the date of acquisition.

During the third quarter of 2004, the Partnership completed two separate acquisitions of natural gas assets in Texas and Mississippi for a total of $9.9 million. The acquisition in Texas was made to provide complimentary facilities to the Partnership's North Texas system. The acquisition in Mississippi is expected to consolidate redundant natural gas processing facilities. The purchase price for these acquisitions was applied to property, plant, and equipment and there was no goodwill recorded. The results of operations for both acquisitions are included in the Partnership's Natural Gas segment from their respective dates of acquisition.

Net income per common and i-unit is computed by dividing net income, after deduction of Enbridge Energy Company, Inc.'s. (the "General Partner") allocation, by the weighted average number of Class A and Class B common units and i-units outstanding. The General Partner's allocation is equal to an amount based upon its general partner interest, adjusted to reflect an amount equal to incentive distributions and an amount required to reflect depreciation on the General Partner's historical cost basis for assets contributed upon formation of the Partnership. There are no dilutive securities. Net income per common and i-unit was determined as follows:

		Three months ended September 30,						Nine months ended September 30,
		2004			2003			2004			2003
		(dollars and units in millions, except per unit amounts)
Net income		$	27.6		$	23.5		$	96.6		$	79.4

Allocations to the General Partner:
	Net income		(0.5	)		(0.5	)		(1.9	)		(1.6	)
	Incentive distributions		(5.0	)		(4.2	)		(14.5	)		(12.6	)
	Historical cost depreciation adjustments		—			—			(0.1	)		(0.1	)

Net income allocable to common and i-units		$	22.1		$	18.8		$	80.1		$	65.1

Weighted average common and i-units outstanding			55.7			48.9			55.1			46.8

Net income per common and i-unit		$	0.39		$	0.38		$	1.45		$	1.39

Net income and cash flows are subject to volatility stemming from changes in market prices such as interest rates, natural gas prices, natural gas liquids prices and fractionation margins. In order to manage the risks, the Partnership uses a variety of derivative financial instruments to create offsetting positions to specific commodity or interest rate exposures. Under SFAS No. 133 all derivative financial instruments are reflected in the balance sheet at their fair value. For those instruments that qualify for hedge accounting, the accounting treatment depends on each instrument's intended use and how it is designated. For those instruments that do not qualify for hedge accounting, the change in market value is recorded as cost of natural gas in the Consolidated Statement of Income.

For cash flow hedges, changes in the derivative fair values, to the extent that the hedges are determined to be highly effective, are recorded as a component of accumulated other comprehensive income until the hedged transactions occur and are recognized in earnings. Any ineffective portion of a cash flow hedge's change in value is recognized immediately in earnings. For fair value hedges, the change in mark to market value of the financial instrument is determined each period and is taken into earnings. In conjunction with this, the change in the value of the hedged item is also calculated and taken into earnings. To the extent that the two valuations offset, the hedge is effective and there should not be a net earnings effect.

The change in value of the Partnership's financial derivatives in the third quarter of 2004 compared to the same period in 2003 is primarily due to sharp increases in forward natural gas and NGL prices. As a result of the Partnership's hedge portfolio, which is largely comprised of long-term fixed price sale agreements, the significant increase in forward commodity prices quarter over quarter have decreased the value of the hedges.

The Partnership's hedging activities are included at the fair values in the Consolidated Statements of Financial Position as follows:

The changes in the market value of natural gas hedging instruments that are attributable to hedge ineffectiveness, measured on a quarterly basis, are included in the cost of natural gas expense in the Consolidated Statements of Income in the period in which they occur. The following table sets forth the hedge ineffectiveness for the periods presented.

The hedge transaction ineffectiveness for the three and nine months ended September 30, 2004, which relates to the Partnership's natural gas basis swap financial transactions, is reflected in the Marketing segment. The hedge transaction ineffectiveness for the three and nine months ended September 30, 2003, which relates to certain natural gas financial transactions on the Partnership's East Texas system, are reflected in the Natural gas segment.

The Partnership extinguishes liabilities when a creditor has relieved the Partnership of the obligation, which occurs when the Partnership's financial institution honors a check that the creditor has presented for payment. As such, included in accounts payable and other are obligations for which the Partnership has issued check payments that have not yet been presented to the financial institution of approximately $21.8 million at September 30, 2004 and $11.9 million at December 31, 2003.

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 September 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 September 30, 2004, the interest coverage ratio was approximately 4.0 and the leverage ratio was approximately 4.0. The Senior Credit Facility also places limitations on the amount of debt that may be incurred directly by the Partnership's subsidiaries. Accordingly, it is expected that the Partnership will provide debt financing to its subsidiaries as required and as of September 30, 2004 the Partnership's subsidiaries had no amounts outstanding under this facility. As of September 30, 2004, the Partnership has drawn $320.0 million on the Senior Credit Facility at a weighted average interest rate of 2.1%.

On January 9, 2004, the Partnership issued $200.0 million in aggregate principal amount of its 4.0% Senior Notes due 2009. The Partnership used the proceeds of approximately $198.3 million, net of expenses of approximately $1.6 million, to repay a portion of its outstanding debt under bank credit facilities.

For the nine months ended September 30, 2004 and 2003, the Partnership converted interest payable related to loans from the General Partner in the amount of $6.7 million and $2.8 million, respectively, into long-term debt to the General Partner.

The following table sets forth the distributions, as approved by the Board of Directors, for each period in the nine months ended September 30, 2004.

On September 15, 2004, the Partnership issued 3.68 million Class A common units at $47.90 per unit, which generated proceeds, net of underwriters' discounts, commissions and issuance expenses, of approximately $168.6 million. Proceeds from this offering were used to reduce borrowings under the Partnership's three-year Senior Credit Facility by approximately $165.0 million. The remaining proceeds were used to fund the general operations of the Partnership. In addition, the General Partner contributed $3.6 million to the Partnership to maintain its 2% general partner interest in the Partnership.

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 expense, of approximately $21.6 million. The proceeds from the over-allotment were used to reduce the Senior Credit Facility. 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.

As of September 30, 2004, the Partnership has entered into contractual commitments of approximately $125.0 million. Of this amount, approximately $102.0 million relates to the expansion of the East Texas system, $5.0 million relates to the construction of storage tanks on the Mid-Continent system and the balance relates to a processing plant and additional compression facilities on the Anadarko system. Approximately $108.0 million of the contractual commitments are expected to be settled by December 31, 2004, with the remaining $17.0 million expected to be settled in the year ended December 31, 2005.

In March 2004, the Partnership reduced its long-term environmental liabilities by $2.0 million related to certain of its Natural Gas segment assets that were originally recorded upon acquisition of these assets. During the time that these assets have been owned by the Partnership, since October 2002,

management has completed an updated review of the affected sites and determined that suspected contamination is less significant than originally estimated. This assessment was based upon information gathered during the ownership period, existing technology, presently enacted laws and regulations and prior experience in remediating contaminated sites for similar assets.

Effective June 30, 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 "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 makes resource allocation decisions, evaluates performance and furthers the achievement of the Partnership's long-term objectives. Financial information for prior periods were reclassified to reflect the new segmentation.

The following tables present certain financial information relating to the Partnership's business segments (dollars in millions):

On October 22, 2004, the Partnership's Board of Directors declared a distribution payable on November 12, 2004. The distribution will be paid to unitholders of record as of November 1, 2004. Of its available cash of $60.7 million at September 30, 2004, $50.6 million or $0.925 per common unit, will be paid to common unitholders, $9.9 million will be retained by the Partnership and distributed in i-units to its i-unitholders and $0.2 million will be retained from the General Partner in respect of the i-unit distribution.

On October 8, 2004, the Federal Energy Regulatory Commission ("FERC") issued an Order on Remand ("Remand Order") relating to initial rates on the Partnership's Kansas Pipeline System ("KPC") for the period of time between December 1997 and November 2002. The Partnership acquired KPC on October 17, 2002. The Remand Order was issued in response to a United States Court of Appeals ruling in August 2003 requiring the FERC to address the issue of appropriate rate refunds, if any, with respect to KPC's initial rates. In the Remand Order, the FERC found that the proper initial rates are lower than the rates previously charged to customers pending resolution of this contested rate case. In accordance with the FERC's findings, any difference between what was collected and these revised initial Section 7 Rates for the period of time between December 1997 and November 2002, plus interest compounded quarterly, is subject to refund. The Remand Order requires a compliance filing and a refund plan to be submitted within 30 days.

The Partnership estimates the amount of the refund will be approximately $12.0 million, including interest of approximately $2.6 million, which has been recorded in the Consolidated Statement of Income as of September 30, 2004. The refund plan is subject to the approval of the FERC. The rate refunds relate almost entirely to a time period prior to the Partnership's ownership of KPC.

Certain reclassifications have been made to the prior period's reported amounts to conform to the classifications used in the 2004 consolidated financial statements. These reclassifications were made to the Statement of Financial Position, the Statement of Cash Flows, the Financial Instruments footnote, and the Segment Information footnote and have no impact on net income.

In March 2004, the Emerging Issues Task Force issued Statement No. 03-06, "Participating Securities and the Two-Class Method under Financial Accounting Standards Board Statement No. 128. Earnings Per Share" ("EITF 03-06"), which addresses a number of questions regarding the computation of earnings per share by companies that have issued securities other than common stock that contractually entitle the holder to participate in dividends and earnings of the company when, and if, it declares dividends on its common stock. The issue also provides further guidance in applying the two-class method of calculating earnings per share, clarifying what constitutes a participating security and how to apply the two-class method of computing earnings per share once it is determined that a security is participating, including how to allocate undistributed earnings to such a security. EITF 03-06 was effective for fiscal periods beginning after March 31, 2004. The adoption of EITF 03-06 did not result in a change in the Partnership's net income per unit for any of the periods presented and prior periods.

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 three and nine months ended September 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.

During the third quarter of 2004, the Partnership continued to realize progress on its strategic plan, which focuses on the development and acquisition of complementary businesses and expansion of existing assets.

Operating income was $61.6 million for the third quarter of 2004, an increase of 37% 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 a majority of the increase, along with improved deliveries on the Lakehead system and higher volumes and processing margins on some of the Partnership's natural gas systems.

Operating income was $172.2 million for the first nine months of 2004, an increase of 21% over the same period in 2003. Contributions from acquisitions accounted for a majority of the increase, offset by lower earnings in the Marketing segment.

Net earnings per unit increased to $0.39 per unit for the third quarter of 2004, compared with $0.38 for the same quarter of 2003. Net earnings per unit was only slightly higher for the third quarter of 2004, due to the approximate $0.22 per unit impact of a Federal Energy Regulatory Commission ("FERC") decision ordering rate refunds on the Partnership's Kansas Pipeline System ("KPC"). Net earnings per unit was also impacted by an increase in the number of common units outstanding.

measures for the Partnership. The new segments are consistent with how management 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.

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.

During the third quarter of 2004, the Partnership completed two separate acquisitions of natural gas assets in Texas and Mississippi for a total of $9.9 million. The acquisition in Texas was made to provide complimentary facilities to the Partnership's North Texas system. The acquisition in Mississippi is expected to consolidate redundant natural gas processing facilities. The purchase price for these acquisitions was applied to property, plant, and equipment. The results of operations for both acquisitions are included in the Partnership's Natural Gas segment from their respective dates of acquisition.

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

Operating income for the Liquids segment increased by approximately $9.1 million to $37.8 million for the three months ended September 30, 2004, compared with $28.7 million for the same period in 2003. The most significant reason for the increase was the Mid-Continent system, which contributed $4.8 million to operating income during the third quarter of 2004. The Mid-Continent system derives approximately two-thirds of its revenues from fee-based services on pipelines regulated by 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 related to storage contracts, the majority of which are longer term.

Operating revenue for the third quarter of 2004 was $107.1 million, compared with $83.8 million for the third quarter of 2003. The increase of $23.3 million was primarily due to the contribution from the Mid-Continent system of $12.8 million.

Deliveries on the Lakehead system increased 5%, from 1,332 thousand barrels per day ("bpd") during the third quarter of 2003 to 1,394 thousand bpd during the same period in 2004, which resulted in higher operating revenue of approximately $5.3 million. Production of western Canadian crude oil increased compared with 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. Operating revenue was also enhanced by tariff increases due to the positive index adjustment effective July 1, 2004, and a longer average haul.

The following table sets forth the operating statistics for the Liquids assets for the periods presented.

Power costs increased by $5.5 million, from $14.2 million in the third quarter of 2003 to $19.7 million in the third 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 $2.0 million in the third quarter of 2004.

Operating and administrative expenses increased by $5.5 million, from $26.5 million for the third quarter of 2003 to $32.0 million for the third quarter of 2004. The recently acquired Mid-Continent assets accounted for approximately $4.9 million of the increase. On the Lakehead system, increased operating and administrative expenses were the result of higher workforce related costs of $1.1 million, higher leak remediation costs associated with old leak sites of $0.7 million and higher property taxes of $0.8 million. 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 oil measurement losses of $1.6 million.

Depreciation expense was $17.6 million for the third quarter of 2004, compared with $14.4 million for the third quarter of 2003. Depreciation on the Mid-Continent system accounted for $1.1 million of the increase and the balance relates to new facilities placed into service in the Liquids segment during 2003 and 2004.

Nine months ended September 30, 2004 compared with nine months ended September 30, 2003

Operating income increased by $15.8 million, to $103.8 million for the nine months ended September 30, 2004, compared with $88.0 million for the nine months ended September 30, 2003. Operating income was higher in 2004 primarily due to the seven-month contribution of $10.8 million from the Mid- Continent system.

Operating revenue increased by $50.5 million, to $301.5 million for the first nine months of 2004, compared with $251.0 million for the same period in 2003. Approximately half of the increase was due to the Mid-Continent system and the remainder from the Lakehead system was primarily due to the increase of 101,000 bpd in deliveries compared to the same period last year.

Operating and administrative expenses increased by $13.4 million, to $93.2 million for the first nine months of 2004, compared with $79.8 million for the same period in 2003. Approximately two-thirds of

the increase was due to contributions from the Mid-Continent system and the remainder from the Lakehead and North Dakota systems. On the Lakehead system, costs were higher for the nine-month period in 2004 due to higher workforce related costs of $5.5 million, increased property taxes of $3.0 million, oil measurement losses of $2.4 million and business development costs related to expansion opportunities on the Lakehead system of $2.2 million. Offsetting these cost increases were lower leak remediation and clean-up costs of $3.9 million due to the lower number of leaks that occurred in 2004, lower repairs and maintenance of $2.4 million due to timing of projects, and higher capitalized labor of $1.5 million due to the number of capital projects in place during 2004.

Depreciation expense was $50.5 million for the nine months ended September 30, 2004, compared with $43.3 million in 2003. Depreciation related to the Mid-Continent system was $2.7 million and the balance of the increase was due to the same reasons as noted above in the three-month analysis.

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").

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

Operating income for the Natural Gas segment increased by $8.0 million to $23.4 million for the three months ended September 30, 2004, compared with $15.4 million for the same period in 2003.

Compared with the third quarter of 2003, average daily volumes on the Partnership's major Natural Gas systems increased approximately 37%, from 1,437,000 MMBtu/d to 1,966,000 MMBtu/d, in the third quarter of 2004. The most significant reason for the increase was the contribution of the North Texas results from the date of acquisition by the Partnership on December 31, 2003, in the third quarter of 2004, the North Texas system contributed $5.3 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.

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 the "East Texas system". Comparative results have been reclassified to conform to this presentation.

Volumes on the East Texas system increased by approximately 20% in the third 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. Unit margins realized on natural gas volumes vary by location. Natural gas producers have concentrated their development efforts on regions that have a smaller incremental benefit to the Partnership than some of the natural gas volumes that the new volumes replace. More than offsetting this effect is improved processing results improved on the East Texas system in the third quarter of 2004 due to more favorable natural gas liquids ("NGLs") pricing conditions compared with the same period in 2003. This was offset by higher costs associated with settlements of customer disputes of approximately $1.2 million. Included in the 2003 results were favorable items associated with hedge instrument ineffectiveness of $0.5 million, and other typical estimate-to-actual revenue and measurement true-ups, making 2003 favorable to 2004 by $1.4 million. In addition, operating and administrative expenses increased in 2004 due to higher administrative workforce related costs and legal fees. As a result, operating income on the East Texas system decreased by approximately $2.0 million, from $8.8 million during the third quarter of 2003, to $6.8 million in the third quarter of 2004.

Volumes on the Anadarko system increased by approximately 42% in the third 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 third 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. As a result, operating income on the Anadarko system increased by approximately $5.6 million, from $3.3 million for the third quarter of 2003 to $8.9 million for the third quarter of 2004.

Volumes on the UTOS system increased 41% in the third quarter of 2004, compared with the third quarter of 2003. This increase is attributable to higher volumes that were diverted to the UTOS system as maintenance was completed on a competitor's pipeline. The volume increase did not have a material impact to the Partnership due to low transportation rates on the system.

The remainder of the change in operating income in the Natural Gas segment was due to slightly lower results on the balance of the natural gas systems.

Nine months ended September 30, 2004 compared with nine months ended September 30, 2003

Operating income for the Natural Gas segment increased by $19.5 million to $67.1 million for the nine months ended September 30, 2004, compared with $47.6 million for the same period in 2003. The most significant reason for the increase was the contribution of the North Texas results, which contributed $17.0 million to operating income during the nine months ended September 30, 2004. 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.

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

Operating income for the Marketing segment was $1.7 million for the third quarter of 2004, compared with $1.6 million for the third quarter of 2003. Operating income in 2004 included a gain of $0.3 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 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. The gain recorded during the three-month period ended September 30, 2004 lowers the mark to market loss recorded earlier in 2004.

Nine months ended September 30, 2004 compared with nine months ended September 30, 2003

Operating income for the Marketing segment was $4.6 million for the nine months ended September 30, 2004, compared with $8.8 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 nine months of 2004, natural gas prices, while generally higher, 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 resulting from the settlement of disputed amounts. As well, the results for the first nine months of 2004 include the mark to market losses of $1.4 million associated with financial instruments that do not qualify for hedge accounting under the SFAS No. 133.

Included in the Partnership's results for the third quarter of 2004 is a charge of $12.0 million related to rate refunds on its Kansas Pipeline System ("KPC").

On October 8, 2004, the FERC issued an Order on Remand ("Remand Order") relating to initial rates on KPC for the period of time from December 1997 to November 2002. The Partnership acquired KPC October 17, 2002. The Remand Order was issued in response to a United States Court of Appeals ruling in August 2003 requiring the FERC to address the issue of appropriate rate refunds, if any, with respect to KPC's initial rates. In the Remand Order, the FERC found that the proper initial rates are lower than the rates previously approved by the FERC. In accordance with the FERC's findings, any difference between what was collected and these revised initial Section 7 Rates for the period of time between December 1997 and November 2002, plus interest compounded quarterly, is subject to refund. The Remand Order requires a compliance filing and a refund plan to be submitted within 30 days.

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.

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 September 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 September 30, 2004, the interest coverage ratio was approximately 4.0 and the leverage ratio was approximately 4.0. The Senior Credit Facility also places limitations on the amount of debt that may be 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 September 30, 2004, $320.0 million was drawn on the Partnership's Senior Credit Facility at a weighted average interest rate of 2.1%.

In September 2004, Standard and Poors lowered the corporate rating of the Partnership from BBB+ (negative outlook) to BBB (stable outlook). However, Standard & Poors confirmed the senior unsecured debt rating of Enbridge Energy Partners, L.P. at BBB. Standard and Poors also lowered the senior unsecured debt rating of Enbridge Energy, Limited Partnership, a wholly-owned subsidiary of the Partnership, from BBB+ to BBB and lowered the First Mortgage Notes rating of Enbridge Energy, Limited Partnership from A- to BBB+. Management does not expect this action by Standard and Poors to have a material impact on the financing capability of the Partnership.

On September 15, 2004, the Partnership issued 3.68 million Class A common units at $47.90 per unit, which generated proceeds, net of underwriters' discounts, commissions and issuance expenses, of approximately $168.6 million. Proceeds from this offering were used to reduce borrowings under the Partnership's three year Senior Credit Facility by approximately $165.0 million. The remaining proceeds were used to fund the general operations of the Partnership. In addition, the General Partner contributed $3.6 million to the Partnership to maintain its 2% general partner interest in the Partnership.

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. The proceeds from the over-allotment were used to reduce the Senior Credit Facility. 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 $207.9 million to $28.1 million at September 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 bank credit facilities. 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 September 30, 2004, cash and cash equivalents totaled $94.0 million, compared with $64.4 million at December 31, 2003. Of its available cash for distribution of $60.7 million at September 30, 2004, $50.6 million or $0.925 per common unit, will be used for the cash distribution which was declared on October 22, 2004, $9.9 million will be retained from i-unitholders and $0.2 million retained from the General Partner.

Net cash provided by operating activities for the nine months ended September 30, 2004 was $225.9 million, compared with $136.9 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 previously 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 2004 and general timing differences in the collection on and payment of the Partnership's current accounts.

Net cash used in investing activities during the nine months ended September 30, 2004 was $313.4 million, compared with $97.9 million for the same period in 2003. The increase of $215.5 million was primarily attributable to strategic acquisitions cash outflows of $139.9 million in 2004, compared with $0.5 million in 2003, as well as an increase of $81.7 million of cash outflows for expansion and growth opportunities of existing assets.

Net cash provided by financing activities during the nine months ended September 30, 2004 was $117.1 million, compared with net cash used in financing activities of $20.4 million for the same period in 2003. The improvement in cash flow is primarily due to higher net borrowings under external and related party debt agreements and higher proceeds from unit offerings partially offset by an increase in cash used for distributions to partners. Distributions to partners were higher in 2004 due to an increase in the number of units outstanding, as a result of the unit issuances, as well as a related increase in the general partner incentive distributions resulting from higher distributions to unitholders.

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 $350.0 million, as illustrated in the table that follows. Of the $350.0 million, approximately $175.0 million has been expended as of September 30, 2004.

	(dollars in millions)
System enhancements	$	186.0
Core maintenance activities		36.0
Lakehead system expansion projects		27.0
East Texas system expansion		101.0

	$	350.0

As of September 30, 2004, the Partnership has entered into contractual commitments totaling approximately $125.0 million. Of this amount, approximately $102.0 million relates to the East Texas system expansion, $5.0 million relates to the construction of storage tanks on the Mid-Continent system and the balance relates to a processing plant and additional compression facilities on the Anadarko system. Contractual commitments of approximately $108.0 million are expected to be settled by December 31, 2004, with the remaining $17.0 million expected to be settled in the year ended December 31, 2005.

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 are approximately $18.0 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.

The Partnership has finalized commercial commitments for the first stage of its tankage project on the Mid-Continent system. This first stage will add 2.3 million barrels of crude oil storage at the Partnership's Cushing, Oklahoma terminal. The storage tanks have been contracted to a customer, with the Partnership earning a fee on the contracted tankage. The four storage tanks for this first stage are expected to be placed in service during late 2005. Commercial negotiations on the second stage of the project, which involves the construction of an additional four storage tanks, are progressing with interested parties.

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. The Canadian Association of Petroleum Producers ("CAPP") continues to review pipeline expansion options. CAPP has been presented with a review of the Southern Access project, which has been revised for consideration as a phased multi-stage expansion. Ongoing discussions with CAPP and individual customers indicate that a phased expansion approach is a cost effective way to provide capacity when required.

During September 2004, Enbridge announced an open season for its Spearhead Pipeline project. The open season is progressing and is expected to result in the execution of firm contracts upon

conclusion in early November. A successful open season will be a strategically positive development for the Partnership as it provides additional outlets for western Canadian crude oil, which would flow through the Lakehead system. The Spearhead project involves the reversal of 650 miles of existing pipeline previously in service from Cushing to Chicago.

The Partnership continues to assess various acquisition and expansion opportunities to pursue its strategy for growth. The market for acquiring energy transportation assets is active and competition among prospective acquirers of assets has been significant. Management of the Partnership 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.

The Partnership's expansion of its East Texas system between Bethel and Carthage, Texas remains on track to meet an in-service date of June 1, 2005. All of the necessary right-of-ways and permits were secured and ground was broken during the first week of October. The project consists of a new natural gas transmission line and gathering laterals. The estimated total cost of the project remains at $150 million, with approximately two-thirds of the cost to be incurred in 2004, with the remainder in early 2005.

Construction has commenced on the Partnership's Anadarko system expansion. This expansion will add 100 million cubic feet per day of processing capacity. The Anadarko system has experienced consistent increases in throughput since being acquired by the Partnership in late 2002. The $29-million project includes additional compression facilities and pipeline interconnects associated with the new processing plant, and the service date is expected to be in early 2005. Management of the Partnership is currently considering increasing the scale of the processing plant, which would provide for incremental capacity over the current scope in the second quarter of 2005. Depending on the final capacity specifications for the plant and associated facilities, the estimated project costs could increase to between $34 and $48 million.

On October 22, 2004, the Partnership's Board of Directors declared a distribution payable on November 12, 2004. The distribution will be paid to unitholders of record as of November 1, 2004. Of its available cash of $60.7 million at September 30, 2004, $50.6 million or $0.925 per common unit, will be paid to common unitholders, $9.9 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.

On October 8, 2004, the FERC issued a Remand Order relating to initial rates on KPC, for the period of time between December 1997 and November 2002. The Partnership acquired KPC on October 17, 2002. The Remand Order was issued in response to a United States Court of Appeals ruling in August 2003 requiring the FERC to address the issue of appropriate rate refunds, if any, with respect to KPC's initial rates. In the Remand Order, the FERC found that the proper initial rates are lower than the rates previously charged to customers pending resolution of this contested rate case. In accordance with the FERC's findings, any difference between what was collected and these revised initial Section 7 Rates for the period of time between December 1997 and November 2002, plus

interest compounded quarterly, is subject to refund. The Remand Order requires a compliance filing and a refund plan to be submitted within 30 days.

The Partnership's earnings and cash flows associated with its Liquids systems are not significantly impacted by changes in commodity prices, as the Partnership does not own the crude oil and NGLs it transports. However, the Partnership has commodity risk related to degradation losses associated with the fluctuating differentials between the price of heavy crude oil relative to light crude oil. Furthermore, commodity prices may have a significant impact on the underlying supply of, and demand for, crude oil and NGLs that the Partnership transports.

A portion of the Partnership's earnings and cash flows are exposed to movements in the prices of natural gas and NGLs. The Partnership has entered into hedge transactions to mitigate exposure to movements in these prices. Pursuant to policies approved by the Board of Directors of the General Partner, the Partnership may not enter into derivative instruments for speculative purposes. All financial derivative transactions must be undertaken with creditworthy counter parties.

There have been no material changes in market risk exposures that would affect the quantitative and qualitative disclosures presented as of December 31, 2003, in Item 7A of the Partnership's Annual Report on Form 10-K for the year ended December 31, 2003.

The Partnership and Enbridge Inc. maintain systems of disclosure controls and procedures designed to provide reasonable assurance that the Partnership is able to record, process, summarize and report the information required in the Partnership's annual and quarterly reports under the Securities Exchange Act of 1934. Management of the Partnership has evaluated the effectiveness of its disclosure controls and procedures as of September 30, 2004. Based upon that evaluation, the Partnership's principal executive officer and principal financial officer concluded that its disclosure controls and procedures are effective to accomplish their purpose. In conducting this assessment, management of the Partnership relied on similar evaluations conducted by employees of Enbridge Inc. affiliates who provide certain treasury, accounting and other services on behalf of the Partnership. No significant changes were made to the Partnership's internal controls or other factors that could significantly affect these controls subsequent to the date of their evaluation, nor were any corrective actions with respect to significant deficiencies and material weaknesses necessary subsequent to that date.

During the third quarter of 2004, there have been no changes in the Partnership's internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the Partnership's internal control over financial reporting.

The Partnership is a participant in various legal proceedings arising in the ordinary course of business. Some of these proceedings are covered, in whole or in part, by insurance. The Partnership believes that the outcome of all these proceedings will not, individually or in the aggregate, have a material adverse effect on the financial condition of the Partnership.

For information regarding other legal proceedings arising in 2003 or with regard to which material developments were reported during 2003, see "Part I. Item 3. Legal Proceedings," in the Partnership's Annual Report on Form 10-K for the year ended December 31, 2003.

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.

ý	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 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

Delaware (State or other jurisdiction of incorporation or organization)		39-1715850 (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)

PART I. FINANCIAL INFORMATION
Item 1.		Financial Statements
		Consolidated Statements of Income for the three and nine month periods ended September 30, 2004 and 2003
		Consolidated Statements of Comprehensive Income (Loss) for the three and nine month periods ended September 30, 2004 and 2003
		Consolidated Statements of Cash Flows for the nine month periods ended September 30, 2004 and 2003
		Consolidated Statements of Financial Position as of September 30, 2004 and December 31, 2003
		Notes to Consolidated Financial Statements
Item 2.		Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 3.		Quantitative and Qualitative Disclosures About Market Risk
Item 4.		Controls and Procedures
PART II. OTHER INFORMATION
Item 1.		Legal Proceedings
Item 6.		Exhibits
Signature

	Three months ended September 30,					Nine months ended September 30,
	2004			2003		2004			2003
	(unaudited; dollars in millions)
Net income	$	27.6		$	23.5	$	96.6		$	79.4
Unrealized gain (loss) on derivative financial instruments (Note 4)		(47.7	)		20.2		(72.6	)		(42.9	)

Comprehensive (loss) income	$	(20.1	)	$	43.7	$	24.0		$	36.5

				Nine months ended September 30,
				2004			2003
				(unaudited; dollars in millions)
Cash provided by operating activities
	Net income			$	96.6		$	79.4
	Adjustments to reconcile net income to net cash provided by operating activities:
		Depreciation and amortization			89.2			70.3
		Hedge transaction ineffectiveness (Note 4)			1.4			—
		Environmental liabilities (Note 9)			(2.0	)		—
		Other			0.2			(0.2	)
		Changes in operating assets and liabilities:
			Receivables, trade and other		(30.1	)		5.6
			Due from General Partner and affiliate		7.2			—
			Accrued receivables		(39.7	)		(70.5	)
			Current and long-term other assets		(36.7	)		(15.4	)
			Due to General Partner and affiliates		4.7			(6.2	)
			Accounts payable and other		55.1			(30.6	)
			Accrued purchases		48.5			81.8
			Interest payable		25.5			21.2
			Property and other taxes payable		6.0			1.5

Net cash provided by operating activities				$	225.9		$	136.9

Cash used in investing activities
	Additions to property, plant and equipment				(174.6	)		(92.9	)
	Changes in construction payables				0.8			(4.5	)
	Asset acquisitions, net of cash acquired (Note 2)				(139.9	)		(0.5	)
	Other				0.3			—

Net cash used in investing activities				$	(313.4	)	$	(97.9	)

Cash provided by (used in) financing activities
	Proceeds from unit issuance, net (Note 8)				194.2			169.0
	Distributions to partners (Note 7)				(140.4	)		(115.6	)
	Borrowings under debt agreements				2,042.8			396.3
	Repayments of debt				(1,979.5	)		(154.0	)
	Repayments to General Partner and affiliates				—			(316.0	)
	Other				—			(0.1	)

Net cash provided by (used in) financing activities				$	117.1		$	(20.4	)

Net increase in cash and cash equivalents				$	29.6		$	18.6
Cash and cash equivalents at beginning of period				$	64.4		$	60.3

Cash and cash equivalents at end of period				$	94.0		$	78.9

		September 30, 2004			December 31, 2003
		(unaudited; dollars in millions)
*ASSETS*
Current assets
	Cash and cash equivalents (Note 5)	$	94.0		$	64.4
	Receivables, trade and other, net of allowance for doubtful accounts of $3.6 in 2004 and $2.9 in 2003		76.4			46.3
	Due from General Partner and affiliates		—			7.2
	Accrued receivables		289.4			249.7
	Other current assets		90.2			41.2

			550.0			408.8
Property, plant and equipment, net			2,693.7			2,465.6
Other assets, net			25.5			22.9
Goodwill			257.0			257.3
Intangibles, net			74.8			77.2

		$	3,601.0		$	3,231.8

*LIABILITIES AND PARTNERS' CAPITAL*
Current liabilities
	Due to General Partner and affiliates	$	6.5		$	1.8
	Accounts payable and other (Note 5)		155.2			85.1
	Accrued purchases		279.1			230.6
	Interest payable		25.6			6.8
	Property and other taxes payable		24.5			18.3
	Current maturities and short-term debt (Note 6)		31.0			246.0

			521.9			588.6
Long-term debt (Note 6)			1,435.7			1,155.8
Loans from General Partner and affiliates			139.8			133.1
Commitments, contingencies and environmental liabilities (Note 9)			6.4			7.9
Deferred credits			106.1			33.1

			2,209.9			1,918.5

Partners' capital
	Class A common units (Units issued—44,296,134 in 2004 and 40,166,134 in 2003)		1,036.0			914.9
	Class B common units (Units issued—3,912,750 in 2004 and 2003)		67.8			64.2
	i-units (Units issued—10,677,833 in 2004 and 10,062,170 in 2003)		392.8			370.7
	General Partner		31.1			27.5
	Accumulated other comprehensive loss		(136.6	)		(64.0	)

			1,391.1			1,313.3

		$	3,601.0		$	3,231.8

	September 30, 2004			December 31, 2003
	(dollars in millions)
Accounts receivable, trade and other	$	12.4		$	3.1
Other assets, net		9.0			4.0
Accounts payable and other		(56.0	)		(41.4	)
Deferred credits		(97.6	)		(23.9	)

	$	(132.2	)	$	(58.2	)

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
					(dollars in millions, except per unit amounts)
January 22, 2004	February 13, 2004	February 2, 2004	$	0.925	$	56.3	$	9.3	$	0.2	$	46.8
April 26, 2004	May 14, 2004	May 5, 2004		0.925		56.5		9.5		0.2		46.8
July 22, 2004	August 13, 2004	August 2, 2004		0.925		56.6		9.6		0.2		46.8

					$	169.4	$	28.4	$	0.6	$	140.4

		As of and for the three months ended September 30, 2004
		Liquids		Natural Gas		Marketing		Corporate			Total
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			—		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 (expense)			—		—		—		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

		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 (Duly Authorized Officer)

		Three months ended September 30,		Nine months ended September 30,
		2004	2003	2004	2003
Lakehead (deliveries, 000 bpd)
United States		1,063	1,014	1,060	971
Province of Ontario		331	318	359	347

	Total deliveries	1,394	1,332	1,419	1,318

Barrel miles (billions)		92	84	274	250

Average haul (miles)		715	690	705	696

Mid-Continent (deliveries, 000 bpd)		264	—	236	—

North Dakota (deliveries, 000 bpd)		85	78	81	77

		Three months ended September 30,		Nine months ended September 30,
		2004	2003	2004	2003
Natural Gas Systems:
	East Texas*	693,000	579,000	643,000	574,000
	Anadarko	371,000	262,000	321,000	249,000
	North Texas	196,000	—	192,000	—
	South Texas	38,000	37,000	42,000	36,000
	UTOS	259,000	184,000	227,000	222,000
	Midla	103,000	106,000	106,000	116,000
	AlaTenn	47,000	44,000	60,000	59,000
	KPC	20,000	22,000	45,000	46,000
	Bamagas	55,000	24,000	33,000	17,000
	Other major intrastates	184,000	179,000	187,000	182,000

Total		1,966,000	1,437,000	1,856,000	1,501,000