UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

 

FORM 10-Q

 

 

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 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 May 4, 2004.

 

 

TABLE OF CONTENTS

 

PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements
	Consolidated Statements of Income for the three month periods ended March 31, 2004 and 2003
	Consolidated Statements of Comprehensive Income for the three month periods ended March 31, 2004 and 2003
	Consolidated Statements of Cash Flows for the three month periods ended March 31, 2004 and 2003
	Consolidated Statements of Financial Position as of March 31, 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 and Reports on Form 8-K
Signatures
Exhibits

 

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,” “would,” or “will” or the negative of those terms or other variations of them or by comparable terminology. In particular, statements, expressed 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.

 

2

 

PART I - FINANCIAL INFORMATION

 

ITEM 1.  FINANCIAL STATEMENTS

 

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

 

		Three months ended March 31,
		2004			2003
		(unaudited; in millions, except per unit amounts)
Operating revenue		$	982.5		$	896.1
Operating expenses
Cost of natural gas		821.8			753.5
Operating and administrative		62.3			52.6
Power		17.2			12.7
Depreciation and amortization		28.6			23.4
		929.9			842.2
Operating income		52.6			53.9
Interest expense		(21.6		)	(21.3		)
Other income (Note 8)		2.1			—
Net income		$	33.1		$	32.6
Net income allocable to common and i-units		$	27.6		$	27.7
Net income per common and i-unit (Note 3)		$	0.50		$	0.62
Weighted average units outstanding		54.7			44.6

 

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

 

3

 

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

 

		Three months ended March 31,
		2004			2003
		(unaudited; in millions)
Net income		$	33.1		$	32.6
Unrealized loss on derivative financial instruments		(19.0		)	(21.7		)
Comprehensive income		$	14.1		$	10.9

 

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

 

4

 

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

 

		Three months ended March 31,
		2004			2003
		(unaudited;in millions)
Cash provided by operating activities
Net income		$	33.1		$	32.6
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		28.6			23.4
Other		(2.0		)	3.7
Changes in operating assets and liabilities:
Receivables, trade and other		15.2			(12.6		)
Due from General Partner and affiliate		6.3			(8.3		)
Accrued gas receivables		(24.7		)	(131.8		)
Other current and noncurrent assets		17.6			(1.3		)
Due to General Partner and affiliates		5.6			(12.5		)
Accounts payable and other		13.4			6.8
Accrued gas purchases		18.6			164.9
Interest payable		19.8			12.2
Property and other taxes payable		2.1			1.3
Net cash provided by operating activities		133.6			78.4
Cash used in investing activities
Additions to property, plant and equipment		(21.6		)	(18.3		)
Changes in construction payables		1.1			(5.0		)
Asset acquisitions, net of cash acquired (Note 2)		(130.0		)	—
Net cash used in investing activities		(150.5		)	(23.3		)
Cash used in financing activities
Proceeds from unit issuances, net (Note 7)		22.0			—
Distributions to partners (Note 6)		(46.8		)	(37.2		)
Borrowings under debt agreements		583.3			897.0
Repayments of debt		(530.0		)	(909.0		)
Borrowings from General Partner and affiliates		—			48.2
Repayments to the General Partner and affiliates		—			(42.7		)
Other		—			(1.2		)
Net cash provided by (used in) financing activities		28.5			(44.9		)
Net increase in cash and cash equivalents		11.6			10.2
Cash and cash equivalents at beginning of period		64.4			60.3
Cash and cash equivalents at end of period		$	76.0		$	70.5

 

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

 

5

 

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

 

		March 31, 2004			December 31, 2003
		(unaudited; in millions)
ASSETS
Current assets
Cash and cash equivalents (Note 4)		$	76.0		$	64.4
Receivables, trade and other, net of allowance for doubtful accounts of $3.5 in 2004; $2.9 in 2003		31.1			46.3
Due from General Partner and affiliates		0.9			7.2
Accrued gas receivables		274.4			249.7
Other current assets		23.9			41.2
		406.3			408.8
Property, plant and equipment, net		2,590.0			2,465.6
Other assets, net		29.4			22.9
Goodwill		257.3			257.3
Intangibles, net		76.4			77.2
		$	3,359.4		$	3,231.8
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Due to General Partner and affiliates		$	7.4		$	1.8
Accounts payable and other (Note 4)		85.9			85.1
Accrued gas purchases		249.2			230.6
Interest payable		24.4			6.8
Property and other taxes payable		20.6			18.3
Current maturities and short-term debt (Note 5)		81.0			246.0
		468.5			588.6
Long-term debt (Note 5)		1,375.7			1,155.8
Loans from General Partner and affiliates		135.3			133.1
Commitments, contingencies and environmental liabilities  (Note 8)		5.8			7.9
Deferred credits		71.5			33.1
		2,056.8			1,918.5
Partners’ capital
Class A common units (Units issued – 40,616,134 in 2004 and 40,166,134 in 2003)		917.4			914.9
Class B common units (Units issued – 3,912,750 in 2004 and 2003)		63.7			64.2
i-units (Units issued – 10,251,168 in 2004 and 10,062,170 in 2003)		376.7			370.7
General Partner		27.8			27.5
Accumulated other comprehensive loss		(83.0		)	(64.0		)
		1,302.6			1,313.3
		$	3,359.4		$	3,231.8

 

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

 

6

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

 

1.               BASIS OF PRESENTATION

 

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 March 31, 2004 and December 31, 2003; the results of operations for the three month periods ended March 31, 2004 and 2003; and cash flows for the three month periods ended March 31, 2004 and 2003.  The results of operations for the three months ended March 31, 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.

 

2.               ACQUISITIONS

 

Mid-Continent System

 

On December 22, 2003, the Partnership entered into a definitive agreement to acquire crude oil pipeline and storage assets for $116.9 million, including transaction costs of $2.0 million.  The asset purchase closed on March 1, 2004 and the results of operations are included in the Partnership as of this date.  The assets acquired serve refineries in the U.S. Mid-Continent from Cushing, Oklahoma and include:

 

•                  The 433-mile Ozark pipeline from Cushing to Wood River, Illinois;

•                  A 1.2 million barrel storage terminal located in El Dorado, Kansas;

•                  The 47-mile West Tulsa pipeline in Oklahoma; and

•                  A storage terminal at Cushing, with 8.3 million barrels of storage capacity.

 

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 Transportation segment.

 

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

 

		(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

 

7

 

Palo Duro System

 

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.  The Palo Duro system’s results of operations are included in the Natural Gas Transportation segment from the date of acquisition.

 

3.               NET INCOME PER COMMON AND i-UNIT

 

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 on formation of the Partnership.  There are no dilutive securities.  Net income per common and i-unit was determined as follows:

 

		Three months ended March 31,
		2004			2003
		(in millions, except per unit amounts)
Net income		$	33.1		$	32.6
Net income allocated to General Partner		(0.7		)	(0.7		)
Incentive distributions to General Partner		(4.7		)	(4.1		)
Historical cost depreciation adjustments allocated to General Partner		(0.1		)	(0.1		)
		(5.5		)	(4.9		)
Net income allocable to common and i-units		$	27.6		$	27.7
Weighted average units outstanding		54.7			44.6
Net income per common and i-unit		$	0.50		$	0.62

 

4.               CASH AND CASH EQUIVALENTS

 

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 $13.4 million at March 31, 2004 and $11.9 million at December 31, 2003.

 

8

 

5.               DEBT

 

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.  The Partnership recorded a discount of $0.1 million in connection with the issuance of the Senior Notes.

 

6.               DISTRIBUTIONS TO PARTNERS

 

On January 22, 2004, Enbridge Energy Managment, L.L.C.’s ("Enbridge Management") Board of Directors declared a distribution payable on February 13, 2004, to unitholders of record as of February 2, 2004, of its available cash of $55.8 million at December 31, 2003, or $0.925 per common unit.  Of this distribution, $9.3 million was distributed in i-units to i-unit holders and $0.2 million was retained from the General Partner in respect of this i-unit distribution.  Due to the exercise of the over-allotment option on January 2, 2004, 450,000 Class A common units were outstanding at February 13, 2004, thus resulting in an additional $0.5 million distribution paid to the Class A common unit holders.

 

7.              EQUITY UNIT ISSUANCE

 

On January 2, 2004, the Partnership issued an additional 450,000 Class A common units pursuant to the 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.  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.

 

8.               COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES

 

In March 2004, the Partnership reduced its long-term environmental liabilities by $2.0 million related to certain of its Gathering and Processing 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 a 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.

 

9.               SEGMENT INFORMATION

 

The Partnership’s business is divided into operating segments, defined as components of the enterprise about which financial information is available and evaluated regularly by the Partnership in deciding how to allocate resources to an individual segment and in assessing performance of the segment.

 

9

 

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

 

		As of and for the three months ended March 31, 2004
		Liquids Transportation			Gathering and Processing			Natural Gas Transportation			Marketing			Corporate			Total
Total revenue		$	91.7		$	790.8		$	31.0		$	596.9		$	—		$	1,510.4
Less:  Intersegment revenue		—			196.9			1.2			329.8			—			527.9
Operating revenue		91.7			593.9			29.8			267.1			—			982.5
Cost of natural gas		—			541.0			16.7			264.1			—			821.8
Operating and administrative		27.8			27.4			5.0			0.8			1.3			62.3
Power		17.2			—			—			—			—			17.2
Depreciation and amortization		16.1			8.9			3.6			—			—			28.6
Operating income		30.6			16.6			4.5			2.2			(1.3		)	52.6
Interest expense		—			—			—			—			(21.6		)	(21.6		)
Other income		—			—			—			—			2.1			2.1
Net income		$	30.6		$	16.6		$	4.5		$	2.2		$	(20.8	)	$	33.1
Total assets		$	1,622.6		$	1,065.6		$	414.1		$	199.1		$	58.0		$	3,359.4
Goodwill		$	—		$	171.9		$	65.0		$	20.4		$	—		$	257.3
Capital expenditures (excluding acquisitions)		$	7.9		$	12.0		$	1.3		$	—		$	0.4		$	21.6

 

 

		As of and for the three months ended March 31, 2003
		Liquids Transportation			Gathering and Processing			Natural Gas Transportation			Marketing			Corporate			Total
Total revenue		$	85.4		$	573.9		$	31.3		$	567.7		$	—		$	1,258.3
Less:  Intersegment revenue		—			71.6			1.8			288.8			—			362.2
Operating revenue		85.4			502.3			29.5			278.9			—			896.1
Cost of natural gas		—			465.0			15.4			273.1			—			753.5
Operating and administrative		26.4			19.0			5.7			0.4			1.1			52.6
Power		12.7			—			—			—			—			12.7
Depreciation and amortization		14.4			5.6			3.4			—			—			23.4
Operating income		31.9			12.7			5.0			5.4			(1.1		)	53.9
Interest expense		—			—			—			—			(21.3		)	(21.3		)
Other income		—			—			—			—			—			—
Net income		$	31.9		$	12.7		$	5.0		$	5.4		$	(22.4	)	$	32.6
Total assets		$	1,496.2		$	750.7		$	421.9		$	269.0		$	55.1		$	2,992.9
Goodwill		$	—		$	146.1		$	72.9		$	20.3		$	—		$	239.3
Capital expenditures (excluding acquisitions)		$	4.9		$	11.2		$	1.3		—			$	0.9		$	18.3

 

10

 

10.  SUBSEQUENT EVENTS

 

Refinancing of Credit Facilities

 

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 April 26, 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, decreasing to 5.00 times thereafter, as described in the Senior Credit Facility. 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.

 

Distribution to Partners

 

On April 26, 2004, Enbridge Management's Board of Directors declared a distribution payable on May 14, 2004.  The distribution will be paid to unitholders of record as of May 5, 2004, of its available cash of $56.5 million at March 31, 2004, or $0.925 per common unit of this distribution, $9.5 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.

 

11.  COMPARATIVE AMOUNTS

 

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 have no impact on net income.

 

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

 

Results of Operations – Overview

 

The Partnership provides services to its customers and creates value for its unitholders primarily through the following activities:

 

•              Interstate transportation of crude oil and liquid petroleum;

 

•               Gathering, treating, processing and transmission of raw natural gas;

 

•               Interstate and intrastate transmission of natural gas; and

 

•               Providing supply, transmission and sales service, including purchasing and selling natural gas.

 

The Partnership primarily provides fee-based services to customers, which minimizes commodity price risks to the Partnership. However, in the Partnership’s natural gas businesses, a portion of its earnings and cash flows are exposed to movements in the prices of natural gas and natural gas liquids (“NGLs”). To substantially mitigate this exposure, the Partnership enters into derivative financial instruments to hedge forecasted transactions.

 

11

 

The Partnership conducts its business through four business segments: Liquids Transportation, Gathering and Processing, Natural Gas Transportation and Marketing. These segments are strategic business units established by senior management to facilitate the achievement of the Partnership’s long-term objectives, to aid in resource allocation decisions and to assess operational performance.

 

The following table reflects operating income by business segment and corporate charges for each of the periods presented.

 

		Three months ended March 31,
		2004			2003
		(unaudited; in millions)
Operating Income
Liquids Transportation		$	30.6		$	31.9
Gathering and Processing		16.6			12.7
Natural Gas Transportation		4.5			5.0
Marketing		2.2			5.4
Corporate, operating and administrative		(1.3		)	(1.1		)
Total Operating Income		$	52.6		$	53.9
Interest expense		(21.6		)	(21.3		)
Other income		2.1			—
Net Income		$	33.1		$	32.6

 

 

Effective December 31, 2003, the Partnership acquired natural gas gathering and processing assets in north Texas for $249.7 million.  The gathering system, referred to as the North Texas system, primarily serves the Fort Worth Basin, including the Barnett Shale producing zone, and is complementary to the Partnership’s existing natural gas systems in the area.  The North Texas system’s results of operations are included in the Gathering and Processing segment from the date of acquisition.

 

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 Transportation 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 Transportation segment from the date of acquisition.

 

Total consolidated net income for the first quarter of 2004 was $33.1 million, compared with $32.6 million for the first quarter of 2003. The increase in net income is primarily due to the inclusion of the results of operations from the newly acquired North Texas and Mid-Continent systems, which, combined, contributed approximately $6.3 million to operating income.  The increase in operating income from new acquisitions was partially offset by lower performance in the Marketing and Liquids Transportation segments and higher operating and administrative expenses.

 

Earnings per unit for the first quarter of 2004 was $0.50 per unit, compared with $0.62 per unit for the first quarter of 2003.  The positive impact of higher net income on first quarter 2004 earnings per unit was offset by a greater number of units outstanding during the first quarter of 2004.  Since the first quarter of 2003, the Partnership has issued 9,302,500 Class A common units, which increased the weighted average number of common units outstanding from 44.6 million in the first quarter of 2003 to 54.7 million in the first quarter of 2004.

 

12

 

Results of Operations – by Segment

 

Liquids Transportation

 

Operating income for the Liquids Transportation segment decreased by approximately $1.3 million to $30.6 million for the three months ended March 31, 2004, compared with $31.9 million for the same period in 2003.  Operating income was lower in 2004 as higher operating revenue was more than offset by higher power costs, operating and administrative expenses and depreciation expense.

 

Operating revenue for the first quarter of 2004 was $91.7 million, compared with $85.4 million for the first quarter of 2003.  The increase of $6.3 million was primarily due to increased volumes transported on the Lakehead system and the one-month contribution from the newly acquired Mid-Continent assets.

 

Volumes on the Lakehead system increased 6%, from 1.326 million barrels per day (“bpd”) during the first quarter of 2003 to 1.406 million bpd during the same period in 2004, which resulted in higher operating revenue of approximately $5.6 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.  During the first quarter of 2004, operating revenue on the Lakehead system was also higher due to the additional pumping day associated with leap year, which increased operating revenue by approximately $0.9 million.  These increases in first quarter 2004 Lakehead system operating revenue were partially offset by a decrease from lower System Expansion Program II (“SEP II”) tariffs, effective May 1, 2003, of approximately $3.0 million.

 

The following table sets forth the Lakehead system’s average deliveries per day, barrel miles and average haul for the periods presented.  Delivery patterns on the Lakehead system are comparable between the first quarter of 2004 and the first quarter of 2003, with slightly lower heavy crude oil volumes transported during the first quarter of 2004.

 

		Three months ended March 31,
		2004		2003
Average BBls/day
United States		1,014		951
Province of Ontario		392		375
Total deliveries (thousands)		1,406		1,326
Barrel miles (billions)		90		85
Average haul (miles)		710		709

 

The Partnership’s newly acquired Mid-Continent system contributed approximately $3.0 million to operating revenue of the Liquids Transportation segment for the month of March 2004, primarily from transportation services.  Volumes for the month of March 2004 were approximately 243,000 bpd.  Operating revenue from transportation services is derived from charging shippers a per barrel tariff rate to transport crude oil and liquid petroleum on its Ozark and West Tulsa pipeline systems.  Operating revenue related to storage services was less than $0.1 million for the month of March 2004.  The Partnership has entered into term agreements for a portion of the storage capacity at the Cushing storage terminal, which are effective starting April 1, 2004.

 

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Power costs increased by $4.5 million, from $12.7 million in the first quarter of 2003 to $17.2 million in the first 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 $0.5 million in the first quarter of 2004.

 

Operating and administrative expenses were higher by $1.4 million, at $27.8 million for the first quarter of 2004, compared with $26.4 million for the same period in 2003.  Operating and administrative expenses related to the newly acquired Mid-Continent assets were approximately $1.2 million in 2004. Related to the Lakehead and North Dakota systems, workforce-related costs were higher in the first quarter of 2004 by approximately $3.4 million, compared with the same period in 2003, primarily due to higher medical, dental and other benefit costs.  Business development costs were higher by approximately $1.1 million during the first quarter of 2004.  These costs were incurred to advance the Partnership’s broader strategy of providing greater access to new U.S. markets for growing Canadian crude oil supplies.  Oil measurement losses were higher in the first quarter of 2004 by approximately $1.0 million.  These increases in operating and administrative expenses were partially offset by lower leak remediation and repair costs of approximately $3.9 million, as the first quarter of 2003 included expenses associated with a Lakehead system leak that occurred in January 2003.  Repairs and maintenance costs were also lower on the Lakehead system by approximately $1.4 million in the first quarter of 2004 due to timing of expenditures.

 

Depreciation expense was $16.1 million for the first quarter of 2004, compared with $14.4 million for the first quarter of 2003.  The increase was primarily due to new facilities placed into service during 2003.

 

Gathering and Processing

 

Operating income for the Gathering and Processing segment increased by approximately $3.9 million to $16.6 million for the three months ended March 31, 2004, compared with $12.7 million for the same period in 2003.

 

The following table indicates the average daily volume for each of the major systems in the Partnership’s Gathering and Processing segment during the periods presented, in million British thermal units per day (“MMBtu/d”).

 

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

 

Compared with 2003, natural gas volumes on the Partnership’s major Gathering and Processing assets increased approximately 31% from 834,000 MMBtu/d to 1,095,000 MMBtu/d in 2004.  The most significant reason for the increase was the contribution of the North Texas results in the first quarter of 2004, from the date of acquisition by the Partnership on December 31, 2003.  The North Texas system contributed $5.4 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 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 integration of these assets as one integrated system, now referred to as “East Texas”.  Comparative results have been reclassified to conform with this presentation.

 

Volumes increased on the East Texas system in the first quarter of 2004 by approximately 19,000 MMBtu/d, 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 first quarter of 2004 compared with the same period in 2003.  During the first three months of 2003, historically high natural gas prices made keep-whole processing contracts non-economic for the East Texas system.  During the first three months of 2004, first of the month natural gas prices fluctuated between $5.15 and $6.15 per MMBtu, compared with $4.96 and $9.11 per MMBtu for the same period in 2003.  However, similar to the Liquids Transportation segment, operating and administrative expenses increased in 2004 due to higher workforce related costs that more than offset any positive gains from the improved volumes and processing results.  As a result, operating income on the East Texas system decreased by approximately $1.6 million, from $7.6 million during the first three months of 2003, to $6.0 million in the first quarter of 2004.

 

Volumes on the Anadarko system increased approximately 17% in the first quarter of 2004 compared with the same period in 2003.  The growth is a result of strong 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 first quarter of 2004 due to a more favorable natural gas and NGL pricing environment.  During the first three months of 2003, volatile natural gas prices adversely affected processing results on the Anadarko system.  As a result of the more stable natural gas pricing environment in 2004, processing operating income improved by $1.8 million, compared with 2003.  These improvements were partially offset by higher operating and administrative expenses related to workforce related benefit costs and variable costs associated with the increased volumes on the system.  As a result, operating income on the Anadarko system increased by approximately $2.9 million, from $0.8 million in the first quarter of 2003 to $3.7 million in the first quarter of 2004.

 

Also included in the Partnership’s Gathering and Processing segment are its trucking operations.  Trucking operations include the transportation of NGLs, crude oil and carbon dioxide by truck and railcar from wellheads to treating, processing and fractionation facilities and to wholesale customers.  During the first quarter of 2004, volumes transported were lower than for the same period of 2003, due to the timing of refinery maintenance, which impacted demand for NGLs in the markets served by the trucking operations.  Operating and administrative expenses also increased in 2004 primarily due to higher benefits costs as previously noted, as well as increased workforce related costs due to new Department of Transportation regulations decreasing the number of hours a driver can work.  As a result, operating income decreased by $1.5 million, from $2.2 million in 2003 to $0.7 million in 2004.

 

Natural Gas Transportation

 

Natural Gas Transportation systems contributed $4.5 million to operating income for the three month period ended March 31, 2004, compared with $5.0 million for the same period in 2003.  Operating income was lower in 2004 primarily due to lower fuel retainage and measurement losses on the Kansas pipeline system.

 

Performance of the Natural Gas Transportation segment depends largely upon revenues derived from reserved pipeline capacity, rather than average daily volumes on the systems.  Natural gas transportation revenue is typically higher in the winter months from increased pipeline rates and greater pipeline reservations; thus, the first and fourth quarter operating income is typically higher as compared to the second and third quarter operating income.

 

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The table below indicates the average daily volumes in MMBtu/d for each of the major systems in the Partnership’s Natural Gas Transportation segment during the periods presented.

 

		Capacity Reserved at		Three months ended March 31,
		March 31, 2004		2004		2003
				(average MMBtu/d)
Major Natural Gas Transportation Systems:
UTOS		0	%	206,000		248,000
MidLa		88	%	117,000		120,000
AlaTenn		49	%	80,000		82,000
Kansas		94	%	89,000		75,000
Bamagas		61	%	9,000		11,000
Other Major Intrastates		up to 43	%	192,000		184,000
Total				693,000		720,000

 

Volumes on the UTOS system decreased 17% in the first quarter of 2004, compared with the first quarter of 2003.  This decrease is attributable to both general declines associated with volumes received into the UTOS system and stricter enforcement of gas quality specifications by pipelines downstream of the UTOS system.  The full quarter impact to revenue in 2004 was less than $0.1 million if these 2004 volumes had remained consistent with the 2003 volumes.

 

The Natural Gas Transportation segment includes the results of the Palo Duro assets that were acquired on March 1, 2004, for $13.1 million.  This system contributed less than $0.1 million in operating income to this segment since its date of acquisition.

 

Marketing

 

Operating income for the Marketing segment was $2.2 million for the first quarter of 2004, compared with $5.4 million for the first quarter of March 31, 2003.  Stronger first quarter 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.  Operating revenue less cost of natural gas was greater due to the unusual volatility in natural gas prices during the first quarter of 2003.  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 quarter of 2004, natural gas prices were less volatile due to more stable market conditions and, therefore, negatively impacted operating income by approximately $0.9 million compared with the first quarter of 2003.  Operating results for the first quarter of 2004 are also lower as the comparable period in 2003 included a non-recurring gain of approximately $1.5 million due to the settlement of a disputed amount.

 

Typically, the first and fourth quarters will result in higher operating income for the Marketing segment due to colder weather in the market areas served by this segment. Colder weather generates significant incremental sales to the Partnership’s wholesale customers, creating the opportunity to optimize transportation and storage agreements.

 

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Corporate

 

Interest expense was $21.6 million for the three months ended March 31, 2004, compared with $21.3 million for the same period in 2003.  The impact on interest expense of higher debt balances was partially offset by a lower weighted average interest rate of approximately 5.8% during the first quarter of 2004, compared with approximately 6.4% during the same period in 2003.

 

Other income was $2.1 million in 2004, compared with $NIL in 2003.  In March 2004, the Partnership reduced its long-term environmental liabilities by $2.0 million related to certain of its Gathering and Processing assets.  During the time that these assets have been owned by the Partnership, since October 2002, management has completed a 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.

 

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 January 2, 2004, the Partnership issued an additional 450,000 Class A common units pursuant to the 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.

 

On January 9, 2004, the Partnership issued an additional $200.0 million in aggregate principal amount of its 4.0% Senior Unsecured Notes due in 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.

 

Working capital, defined as current assets less current liabilities, improved by $117.6 million to a deficit of $62.2 million at March 31, 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.  As noted above, 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.

 

At March 31, 2004, cash and cash equivalents totaled $76.0 million, compared with $64.4 million at December 31, 2003.  Of the cash balance, $56.5 million ($0.925 per unit) will be used for the distribution payable on May 14, 2004, including $9.5 million relating to the i-units and $0.2 million retained from the General Partner to maintain its 2% interest in respect of the i-unit distribution, which will both be retained by the Partnership for use in its business.  The remaining $19.5 million is available for future cash distributions, capital expenditures or other business needs.

 

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Operating Activities

 

Net cash provided by operating activities for the three months ended March 31, 2004 was $133.6 million, compared with $78.4 million for the same period in 2003.  The increase in 2004 was primarily due to the positive impact of the net increase in operating assets and liabilities.  Compared with the first quarter of 2003, the Partnership had an increase in the amounts due to the General Partner and affiliates during the first quarter of 2004, as a result of timing differences in the collection on and payment of related party accounts.  .  The remaining changes in operating assets and liabilities were primarily due to decreased natural gas prices in the first 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 three months ended March 31, 2004 was $150.5 million, compared with $23.3 million for the same period in 2003.  The increase of $127.2 million was primarily attributable to higher cash outflows made for strategic acquisitions.  On March 1, 2004, the Partnership acquired the Mid-Continent system for cash paid of $116.9 million, and the Palo Duro system for cash paid of $13.1 million.

 

Financing Activities

 

Net cash provided by financing activities during the three months ended March 31, 2004 was $28.5 million, compared with net cash used in financing activities of $44.9 million for the same period in 2003.  The increase of $73.4 million in cash flow is primarily due to net borrowings under debt agreements and proceeds from the additional Class A common units issued in January 2004, pursuant to the exercise of the over-allotment option as part of the December 2003 Class A common unit issuance, offset by an increase in distributions to partners.  Distributions to partners were higher in 2004 due to an increase in the number of units outstanding, as well as a related increase in the general partner incentive distributions.

 

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 is worn, obsolete or completing its useful life. 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.  In 2004, the Partnership anticipates capital expenditure spending to approximate:

 

		(in millions)
System enhancements		$	126.0
Core maintenance activities		33.0
Lakehead System expansion projects		40.0
East Texas expansion		105.0
		$	304.0

 

Excluding major expansion projects and acquisitions, ongoing capital expenditures are expected to average approximately $98.0 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.

 

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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.

 

OFF BALANCE SHEET ARRANGEMENTS

 

The Partnership has no off-balance sheet arrangements.

 

SUBSEQUENT EVENTS

 

Distribution Declaration

 

On April 26, 2004, Enbridge Management’s Board of Directors declared a distribution payable on May 14, 2004, to unitholders of record as of May 5, 2004, of its available cash of $56.5 million at March 31, 2004, or $0.925 per common unit.  Of this distribution, $9.5 million will be distributed in i-units to i-unit holders and $0.2 million will be retained from the General Partner in respect of this i-unit distribution.

 

Bank Credit Facilities

 

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 April 26, 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, decreasing to 5.00 times thereafter, as described in the Senior Credit Facility. 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.

 

REGULATORY MATTERS

 

Lakehead System

 

On March 17, 2004, Enbridge Energy, Limited Partnership (“Lakehead Partnership”), a subsidiary of the Partnership, filed a new tariff with the Federal Energy Regulatory Commission (“FERC”) that became effective April 1, 2004.  This new tariff reflects the annual calculation of the SEP II surcharge, as well as an adjustment to the Terrace fixed toll allocation.

 

The change in the SEP II surcharge is made pursuant to the 1998 Settlement Agreement between the Partnership and the Canadian Association of Petroleum Producers (“CAPP”), which was approved by the FERC on December 21, 1998.  The 1998 Settlement Agreement requires the Lakehead Partnership to adjust the SEP II surcharge annually to reflect the latest estimates for the upcoming year and to true-up differences between estimates and actual cost and throughput data in the prior year.  The 2004 SEP II surcharge is approximately

 

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$0.11/bbl for light crude oil movements from the Canadian border to Chicago, Illinois, which is approximately $0.016/bbl higher than the 2003 SEP II surcharge, and reflects 2003 actual and 2004 projected SEP II costs and throughput.

 

Under a tariff agreement approved by the FERC in 1998, the Partnership implemented a tariff surcharge for the Terrace expansion program of approximately $0.013 per barrel for light crude oil from the Canadian border to Chicago.  On April 1, 2001, pursuant to an agreement between the Partnership and Enbridge Pipelines Inc., the Partnership’s share of the surcharge was increased to $0.026 per barrel.  Effective April 1, 2004, the surcharge was adjusted to $0.007 per barrel for light crude oil from the Canadian border to Chicago.  This new tariff is expected to be in effect for the next six years, after which time it will return to $0.013 per barrel for the Partnership through 2013, the term of the agreement.

 

Energy Affiliate Rules

 

On April 14, 2004 the FERC clarified its Energy Affiliates Standards of Conduct rule making (“Standards of Conduct Rule”) that govern the relationship between Transmission Providers and their Energy Affiliates.  In response to petitions for rehearing and clarification of its November 2003 Standards of Conduct Rule, the FERC reaffirmed the need for the rule, noting that it protects customers in an environment where robust competition provides the economic incentives that may tempt a transmission provider to give its affiliates unduly preferential treatment—behavior that harms customers. The FERC also extended until September 2004, the date for full implementation of the Standards of Conduct Rule. Furthermore, the Standards of Conduct Rule will now expressly state that corporate governance information may be shared with permissibly-shared employees, such as officers and directors, between the Transmission Provider and the Energy Affiliate, as long as these employees do not act as a conduit for sharing information.

 

The Partnership does not believe that the effect on the operations of its interstate natural gas pipelines or its other operations, which indirectly are affected by the extent and nature of the Standards of Conduct Rule, will be affected materially differently than other companies with whom it competes.

 

ITEM 3.                         QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

 

The Partnership’s earnings and cash flows associated with its Liquids Transportation 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.  Commodity prices have a significant impact on the underlying supply of, and demand for, crude oil and NGLs that the Partnership transports.

 

The total change in value of the financial derivatives over the quarter was predominantly driven by the significant rise in near and long term natural gas forward prices.  As the Partnership’s natural gas hedge portfolio is largely comprised of long term fixed price forward sale agreements, an increase in the forward market prices will cause the unrealized hedge loss to increase.

 

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 its 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 our 2003 Form 10-K report.

 

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ITEM 4.                         CONTROLS AND PROCEDURES

 

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 March 31, 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.

 

PART II - OTHER INFORMATION

 

ITEM 1.  LEGAL PROCEEDINGS

 

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.

 

ITEM 6.  EXHIBITS AND REPORTS ON FORM 8-K

 

a)             Exhibits

 

3.1		Certificate of Limited Partnership of the Partnership (incorporated by reference to Exhibit 3.1 to the Partnership’s Registration Statement No. 33-43425)
3.2		Certificate of Amendment to Certificate of Limited Partnership of the Partnership (incorporated by reference to Exhibit 3.2 to the Partnership’s 2000 Form 10-K/A dated October 9, 2001)
3.3		Third Amended and Restated Agreement of Limited Partnership of the Partnership (incorporated by reference to Exhibit 3.1 to the Partnership’s Quarterly Report on Form 10-Q filed November 14, 2002)
4.1		Form of Certificate representing Class A Common Units (incorporated by reference to Exhibit 4.1 to the Partnership’s 2000 Form 10-K/A dated October 9, 2001)
10.1		First Amendment, dated January 12, 2004, to Amended and Restated Credit Agreement, dated January 24, 2003, among Enbridge Energy Partners, L.P., Bank of America, N.A., as administrative agent, and the lenders party thereto.
10.2		Second Amendment, dated April 26, 2004, to Amended and Restated Credit Agreement, dated January 24, 2004, among Enbridge Energy Partners, L.P., Bank of America, N.A., as administrative agent, and the lenders party thereto.
31.1		Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2		Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1		Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2		Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

 

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b)            Reports on Form 8-K

 

The Partnership filed the following current reports on Form 8-K during the first quarter of 2004:

 

A current report on Form 8-K was filed on January 6, 2004 containing the Consolidated Statements of Financial Position of Enbridge Energy Company, Inc., at September 30, 2003 and December 31, 2002.  Enbridge Energy Company, Inc., is the General Partner of the Partnership.

 

A current report on Form 8-K was filed on January 6, 2004, attaching a press release dated December 31, 2003 announcing the closing of the $247.0 million acquisition of the North Texas System that was originally announced on November 19, 2003.

 

A current report on Form 8-K was filed on January 9, 2004, containing the underwriting agreement with respect to the issue and sale by the Partnership of $200.0 million aggregate principal amount of 4% Notes due 2009 in an underwritten public offering.

 

A current report on form 8-K was filed on January 28, 2004, attaching a press release dated January 22, 2004, regarding comparative financial results for the three months and year ended December 31, 2003.

 

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SIGNATURES

 

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/ DAN C. TUTCHER
				Dan C. Tutcher
				President and Director (Principal Executive Officer)
			/s/ MARK A. MAKI
				Mark A. Maki
				Vice President, Finance (Duly Authorized Officer)
					Date:  May 4, 2004

 

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