UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

ý		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2003

OR

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

For the transition period from to

Commission file number 1-10934

ENBRIDGE ENERGY PARTNERS, L.P.

(Exact name of Registrant as specified in its charter)

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

	1100 Louisiana Suite 3300 Houston, TX 77002
	(Address of principal executive offices and zip code)

	(713) 821-2000
	(Registrant’s telephone number, including area code)

Indicate by check 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) ý Yes o No

The Registrant had 31,313,634 Class A Common Units outstanding as at May 1, 2003.

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION

Item 1.		Financial Statements	1

		Consolidated Statements of Income for the three month periods ended March 31, 2003 and 2002	1

		Consolidated Statements of Comprehensive Income for the three month periods ended March 31, 2003 and 2002	2

		Consolidated Statements of Cash Flows for the three month periods ended March 31, 2003 and 2002	3

		Consolidated Statements of Financial Position as at March 31, 2003 and December 31, 2002	4

		Consolidated Statement of Partners’ Capital for the three month period ended March 31, 2003	5

		Notes to Consolidated Financial Statements	6

Item 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations	8

Item 3.		Quantitative and Qualitative Disclosures About Market Risk	12

Item 4.		Controls and Procedures	12

PART II. OTHER INFORMATION

Item 1.	Legal Proceedings		13

Item 6.	Exhibits and Reports on Form 8-K		13

Signatures			14

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” 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 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 the Partnership to control or predict. For additional discussion of risks, uncertainties and assumptions, see the Partnership’s 2002 Annual Report on Form 10-K.

PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ENBRIDGE ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF INCOME

(unaudited; dollars in millions, except per unit amounts)

Three months ended March 31,	2003			2002

Operating revenue	$	896.1		$	181.8

Expenses
Power	12.7			13.6
Cost of natural gas	753.5			89.6
Operating and administrative	52.6			27.8
Depreciation and amortization (Note 3)	23.4			18.3

	842.2			149.3

Operating income	53.9			32.5

Interest and other income	—			0.1

Interest expense	(21.3		)	(14.7		)

Minority interest	—			(0.2		)

Net income	$	32.6		$	17.7

Net income per unit (Note 2)	$	0.62		$	0.43

Weighted average units outstanding (millions)	44.6			33.7

The accompanying notes to the Consolidated Financial Statements are an integral part of these statements.

ENBRIDGE ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited; dollars in millions)

Three months ended March 31,	2003			2002

Net income	$	32.6		$	17.7

Unrealized loss on derivative financial instruments	(21.7		)	(14.5		)

Comprehensive income	$	10.9		$	3.2

The accompanying notes to the Consolidated Financial Statements are an integral part of these statements.

ENBRIDGE ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited; dollars in millions)

Three months ended March 31,	2003			2002

Cash provided from operating activities
Net income	$	32.6		$	17.7
Adjustments to reconcile net income to cash provided from operating activities:
Depreciation and amortization	23.4			18.3
Other	3.7			0.1
Changes in operating assets and liabilities,
Accounts receivable and other	(147.3		)	(14.2		)
Oil shortage/overage balance	(3.3		)	0.9
Materials and supplies	0.8			—
General Partner and affiliates	(20.8		)	10.2
Accounts payable and other	175.8			6.1
Interest payable	12.2			12.3
Property and other taxes	1.3			1.3

	78.4			52.7

Investing activities
Additions to property, plant and equipment	(18.3		)	(30.0		)
Changes in construction payables	(5.0		)	0.4

	(23.3		)	(29.6		)

Financing activities
Revolving Credit Facility	—			(137.0		)
364-Day Facility	30.0			99.0
Three-year term facility	(42.0		)	105.0
Issuance of / (repayments to) General Partner and affiliates, net	5.5			(124.7		)
Proceeds from unit issuance, net	—			90.8
Distributions to partners	(37.2		)	(32.6		)
Minority interest	—			(0.1		)
Other	(1.2		)	(1.4		)

	(44.9		)	(1.0		)

Increase in cash and cash equivalents	10.2			22.1

Cash and cash equivalents at beginning of period	60.3			40.2

Cash and cash equivalents at end of period	$	70.5		$	62.3

The accompanying notes to the Consolidated Financial Statements are an integral part of these statements.

ENBRIDGE ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

(dollars in millions)

	March 31, 2003			December 31, 2002
	(unaudited)
*ASSETS*

Current assets
Cash and cash equivalents	$	70.5		$	60.3
Due from General Partner and affiliates	8.3			—
Trade receivables, net of allowance for doubtful accounts of $4.1 in 2003; $3.7 in 2002	349.0			206.9
Accounts receivable and other	25.7			20.7
Oil overage balance	0.1			—
Materials and supplies	8.8			9.6
	462.4			297.5
Property, plant and equipment, net	2,249.4			2,253.3
Other assets, net	41.8			43.0
Goodwill	239.3			241.1

	$	2,992.9		$	2,834.9

*LIABILITIES AND PARTNERS’ CAPITAL*

Current liabilities
Due to General Partner and affiliate	$	—		$	12.5
Accounts payable and other	159.3			146.5
Oil shortage balance	—			3.2
Accrued gas purchases	304.8			142.1
Interest payable	19.2			7.0
Property and other taxes payable	17.6			16.3
Current maturities and short-term debt (Note 4)	273.0			31.0
	773.9			358.6

Long-term debt (Note 4)	757.4			1,011.4
Loans from General Partner and affiliates	449.6			444.1
Environmental liabilities	5.6			5.6
Deferred credits	40.9			23.2
Minority interest	0.4			0.4
	2,027.8			1,843.3

Partners’ capital
Class A common units (Units authorized and issued – 31,313,634 in 2003 and 2002)	595.0			604.8
Class B common unitholders (Units authorized and issued – 3,912,750 in 2003 and 2002)	47.8			48.7
i-units (Units authorized and issued - 9,454,342 in 2003 and 9,228,655 in 2002)	341.2			335.6
General Partner	19.1			18.8
Accumulated other comprehensive loss	(38.0		)	(16.3		)
	$	965.1		$	991.6

	$	2,992.9		$	2,834.9

The accompanying notes to the Consolidated Financial Statements are an integral part of these statements.

ENBRIDGE ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL

(unaudited; dollars in millions)

	Units	Amount

Class A Units:
Beginning balance at December 31, 2002	31,313,634	$	604.8
Net income allocation	—	19.2
Allocation of net proceeds from unit issuance	—	—
Distributions to partners	—	(29.0		)
Ending balance at March 31, 2003	31,313,634	595.0

Class B Units:
Beginning balance at December 31, 2002	3,912,750	48.7
Net income allocation	—	2.7
Allocation of net proceeds from unit issuance	—	—
Distributions to partners	—	(3.6		)
Ending balance at March 31, 2003	3,912,750	47.8

i-units:
Beginning balance at December 31, 2002	9,228,655	335.6
Net income allocation	—	5.8
Allocation of net proceeds from unit issuance	—	(0.2		)
Distributions to partners	225,687	—
Ending balance at March 31, 2003	9,454,342	341.2

General Partner:
Beginning balance at December 31, 2002	—	18.8
Net income allocation	—	4.9
Allocation of net proceeds from unit issuance	—	—
General Partner contribution	—	—
Distributions to partners	—	(4.6		)
Ending balance at March 31, 2003	—	19.1

Accumulated other comprehensive loss:
Beginning balance at December 31, 2002	—	(16.3		)
Unrealized loss on derivative financial instruments	—	(21.7		)
Ending balance at March 31, 2003	—	(38.0		)

Total Partners’ Capital at March 31, 2003	44,680,726	$	965.1

The accompanying notes to the Consolidated Financial Statements are an integral part of these statements.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

1. Basis of Presentation

The accompanying unaudited consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America for interim 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 generally accepted accounting principles for complete 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 at March 31, 2003 and December 31, 2002; the results of operations for the three month periods ended March 31, 2003 and 2002; and cash flows for the three month periods ended March 31, 2003 and 2002. The results of operations for the three months ended March 31, 2003 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 financial statements should be read in conjunction with Enbridge Energy Partners, L.P.’s (the “Partnership”) consolidated financial statements and notes thereto presented in the Partnership’s 2002 Annual Report on Form 10-K.

2. Net Income per Unit

Net income per unit is computed by dividing net income, after deduction of the General Partner’s 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. Net income per unit was determined as follows.

(in millions; except per unit amounts)

Period ended March 31,	2003			2002
Net income	$	32.6		$	17.7

Net income allocated to General Partner	(0.7		)	(0.2		)
Incentive distributions and historical cost depreciation adjustments	(4.2		)	(3.0		)

	(4.9		)	(3.2		)

Net income allocable to Common Units and i-units	$	27.7		$	14.5

Weighted average units outstanding	44.6			33.7

Net income per unit	$	0.62		$	0.43

3. Depreciation

Based on a third-party study commissioned by management, revised depreciation rates for the Lakehead System were implemented effective January 1, 2003, which represent the expected remaining service life of the pipeline system. The third-party study will be filed with the Federal Energy Regulatory Commission (“FERC”) to conform regulatory and financial accounting depreciation rates of the Lakehead System. Depreciation expense for the three months ended March 31, 2003 was $3.1 million lower than it would have been using previous depreciation rates. The annual composite rate changed from 3.9% to 3.22%.

4. Credit Facilities

On January 24, 2003, the Partnership amended and restated the terms of its two unsecured revolving credit facilities. The new facilities consist of the amended and restated $300 million three-year facility, which matures in 2006, subject to extension as provided in the facility, and the amended and restated $300

million 364-day facility, which matures in 2004, subject to a one-year term out option and extension as provided in the facility. The Partnership is the sole borrower under the new facilities and there are no guarantees of the obligations under either facility. The amended and restated terms of the facilities are substantially similar to the original facilities with the exception of certain amendments to the covenants. Among other changes, under the new facilities, the Partnership must maintain a minimum interest coverage ratio as defined in the amended and restated terms of the facilities, of 2.75 to 1.00, as of the end of each fiscal quarter and is no longer required to maintain a particular credit rating. Although subsidiaries may incur debt with certain restrictions and limitations under the new facilities, the Partnership expects to provide funding to its subsidiaries. As at March 31, 2003, $242.0 million related to the 364-day facility and $210.0 million related to the three-year facility were outstanding.

5. 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.

The Partnership’s reportable segments are based on the type of business activity and management control. Each segment is managed separately because each business requires different operating strategies. The Partnership has five reportable business segments: Liquids Transportation, Natural Gas Transportation, Gathering and Processing, Marketing and Corporate.

Due to the purchase of natural gas assets in October 2002, the Partnership changed the organization of its business segments effective in the fourth quarter of 2002. Prior to the fourth quarter of 2002, the Partnership reported Transportation as one segment, which consisted of receipt and delivery of crude oil, liquid hydrocarbons, natural gas and natural gas liquids. These activities are now reported within 3 segments – Liquids Transportation, Natural Gas Transportation and Gathering and Processing. Prior period segment results have been restated to conform to the Partnership’s current organization.

The following tables present certain financial information relating to the Partnership’s business segments as of or for the quarters ended March 31, 2003 and 2002.

	As of and for the Quarter Ended March 31, 2003
(dollars in millions)	Liquids Transportation		Natural Gas Transportation		Gathering and Processing		Marketing		Corporate			Total
Operating revenues	$	85.4	$	29.5	$	502.3	$	278.9	$	—		$	896.1
Power	12.7		—		—		—		—			12.7
Cost of natural gas	—		15.4		465.0		273.1		—			753.5
Operating and administrative	26.4		5.7		19.0		0.4		1.1			52.6
Depreciation and amortization	14.4		3.4		5.6		—		—			23.4
Operating income	31.9		5.0		12.7		5.4		(1.1		)	53.9
Interest and other income	—		—		—		—		—			—
Interest expense	—		—		—		—		(21.3		)	(21.3		)
Minority interest	—		—		—		—		—			—
Net income	$	31.9	$	5.0	$	12.7	$	5.4	$	(22.4	)	$	32.6
Total assets	$	1,496.2	$	421.9	$	750.7	$	269.0	$	55.1		$	2,992.9
Goodwill	—		72.9		146.1		20.3		—			239.3
Capital expenditures (excluding acquisitions)	$	4.9	$	1.3	$	11.2	$	—	$	0.9		$	18.3

	As of and for the Quarter Ended March 31, 2002
(dollars in millions)	Liquids Transportation		Natural Gas Transportation		Gathering and Processing		Marketing		Corporate			Total
Operating revenues	$	82.6	$	—	$	99.2	$	—	$	—		$	181.8
Power	13.6		—		—		—		—			13.6
Cost of natural gas	—		—		89.6		—		—			89.6
Operating and administrative	22.7		—		4.9		—		0.2			27.8
Depreciation and amortization	15.9		—		2.4		—		—			18.3
Operating income	30.4		—		2.3		—		(0.2		)	32.5
Interest and other income	—		—		—		—		0.1			0.1
Interest expense	—		—		—		—		(14.7		)	(14.7		)
Minority interest	—		—		—		—		(0.2		)	(0.2		)
Net income	$	30.4	$	—	$	2.3	$	—	$	(15.0	)	$	17.7
Total assets	$	1,407.4	$	—	$	275.2	$	—	$	—		$	1,682.6
Goodwill	—		—		15.0		—		—			15.0
Capital expenditures (excluding acquisitions)	$	26.6	$	—	$	3.4	$	—	$	—		$	30.0

6. Comparative Amounts

Certain reclassifications have been made to the prior period’s reported amounts to conform to the classifications used in the 2003 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

Net income for the first quarter of 2003 was $32.6 million, or $0.62 per unit, compared with $17.7 million, or $0.43 per unit, for the first quarter of 2002. The increase in net income was primarily due to the inclusion of the Midcoast System results in 2003. The comparable numbers for the first quarter of 2002 did not include earnings from the Midcoast System, as these assets were purchased in the fourth quarter of 2002. Earnings per unit were higher due to increased net income, offset partially by a greater number of units outstanding. The weighted-average number of Common Units outstanding increased from 33.7 million for the first quarter of 2002 to 44.6 million for first quarter of 2003, primarily due to the i-unit issuance in October 2002.

The following table reflects income by business segment and corporate charges for each of the quarters ended March 31, 2003 and 2002.

(unaudited; dollars in millions)	2003			2002

Operating Income
Liquids Transportation	$	31.9		$	30.4
Natural Gas Transportation	5.0			—
Gathering and Processing	12.7			2.3
Marketing	5.4			—
Corporate, operating and administrative	(1.1		)	(0.2		)
Total Operating Income	53.9			32.5
Corporate	(21.3		)	(14.8		)
Net Income	$	32.6		$	17.7

Liquids Transportation

Operating income. Operating income for the first quarter of 2003 was $31.9 million compared with $30.4 million for 2002. Operating income was higher in 2003 compared with 2002 primarily due to higher revenues, partially offset by higher operating expenses.

Operating revenue. Operating revenue for the first quarter of 2003 was $85.4 million compared with $82.6 million in 2002. Operating revenue was higher in 2003 compared to 2002 due to increased average tariffs and deliveries on both the Lakehead and North Dakota systems. Average tariffs were higher due to the positive FERC indexed-tariff adjustment effective July 1, 2002. As well, the amount of heavy oil transported on the Lakehead System, which attracts a higher tariff, was higher in 2003 compared to 2002.

Deliveries. Deliveries on the Lakehead System averaged 1.326 million barrels per day (“bpd”) for the first quarter of 2003 compared with 1.314 million bpd in the first quarter of 2002. The Partnership anticipates that deliveries will improve over the second half of 2003 to average between 1.37 and 1.47 million bpd on a full-year basis. Deliveries on the North Dakota System averaged approximately 72 thousand bpd on the trunkline and approximately 7.6 thousand bpd on the gathering system for the first quarter of 2003. This compares with approximately 64 thousand bpd on the trunkline and approximately 8.1 thousand bpd on the gathering system for the first quarter of 2002.

Operating and administrative expenses. Operating and administrative expenses were $26.4 million for the first quarter of 2003 compared with $22.7 million in the first quarter of 2002. Operating and administrative expenses were higher in 2003 compared to 2002 primarily due to costs associated with the cleanup and

remediation of a leak that occurred in January 2003, of approximately $3.5 million. Total costs of the leak are expected to approximate $4.0 million.

Depreciation expense. Depreciation expense was $14.4 million for the first quarter of 2003 compared with $15.9 million in the first quarter of 2002. The decrease was due to revised depreciation rates on the Lakehead System that will be filed with FERC to be effective on January 1, 2003, to better represent the expected remaining service life of the pipeline system. Depreciation expense for the three-months ended March 31, 2003, was $3.1 million lower than it would have been under previous depreciation rates.

Natural Gas Transportation

The Natural Gas Transportation segment was established upon the acquisition of the Midcoast System on October 17, 2002. This segment’s results of operations are included in the Partnership’s results since that date and, therefore, there is no comparative data for prior periods.

Natural Gas Transportation assets contributed $5.0 million to operating income during the quarter. Performance of the Natural Gas Transportation segment is largely dependent upon revenues derived from reserved pipeline capacity. There were no significant changes in reserved pipeline capacity during the quarter. Certain Natural Gas Transportation systems are sensitive to volume fluctuations. During the quarter, the Partnership's UTOS system experienced lower than expected natural gas volume, as supply was diverted to competing pipelines due to the unusually high natural gas prices in markets accessed by the competing pipeline systems. The UTOS system supply diversion had a relatively minor impact on results of operations for the first quarter of 2003.

The table below indicates the first quarter 2003 average daily volumes, as well as total capacity reserved at March 31, 2003, for the major assets on the Partnership’s Natural Gas Transportation segment in millions of British thermal units per day (“Mmbtu/d”).

	Average Mmbtu/d	Capacity	Reserved
Major Natural Gas Transportation Systems:
MidLa Pipeline	120	200	79	%
AlaTenn Pipeline	82	200	52	%
UTOS Pipeline	248	1,200	—
Kansas Pipeline	75	160	97	%
Bamagas Pipeline	11	450	61	%
Other Major Intrastates	184	625	Up to 48	%
Total	720	2,835

Gathering and Processing

The East Texas System was acquired on November 30, 2001, and the remaining gathering and processing systems were purchased as part of the Midcoast System acquisition on October 17, 2002. Therefore, comparative results for 2002 include only the results of operations from the East Texas System.

Operating income for the East Texas System was $4.0 million for the first quarter of 2003 compared with $2.3 million for the first quarter of 2002. The increase of $1.7 million was primarily due to higher volumes and the absence of a treating plant maintenance shutdown that occurred during the first quarter of 2002. Volume on the East Texas System has increased from 427 Mmbtu/d during the first quarter of 2002 to 483 Mmbtu/d during the first quarter of 2003. This increase in volume is due to higher natural gas production and new producer drilling in the East Texas area. During the first quarter of 2003, operating income was negatively impacted by approximately $1.5 million in charges associated with non-cash revaluation expenses recognized on natural gas operational balancing agreements (“OBA’s”), which were the result of unusually high natural gas prices during this period. Volatility in natural gas prices can impact the operating income of this segment making processing non-economic on certain facilities where processing is

mandatory as a result of downstream pipeline quality specifications. Natural gas price changes will also impact contractual in-kind natural gas OBA’s that are revalued monthly at market prices. Unusually cold weather can negatively impact the production of natural gas, however, operations personnel overcame difficult conditions during the quarter and significant operational outages were avoided. Due to expected moderation of natural gas prices, results for the East Texas System are anticipated to improve in the second quarter of 2003. Moderation of natural gas prices since March 2003 is anticipated to modestly improve processing margins compared with the first quarter. In addition, a significant portion of the OBA revaluation expense will reverse as a result of lower natural gas prices.

The remaining Gathering and Processing assets were also impacted by unusual volatility in natural gas prices during the quarter. Negative processing margins and non-cash OBA charges on the Anadarko system were approximately $1.4 million. Weaker performance on the Anadarko system was partially offset by positive performance on other assets, including the DPI trucking unit, the South Texas and Harmony systems. The DPI trucking unit benefited from stronger commodity prices and improved demand for propane and other liquid hydrocarbons. Volumes of natural gas and favorable commodity pricing positively impacted the performance of the South Texas system. This system benefited from contract structures that increased margins associated with intra-month price volatility. Volumes of natural gas on the Northeast Texas system have stabilized due to recent supply additions and expectations are for modest increases in supply during 2003.

Volumes. The following table indicates the average daily volume for each of the major systems in the Partnership’s Gathering and Processing segment during the first quarter of 2003 and 2002, in Mmbtu/d.

Gathering Systems:	2003	2002
East Texas System	427	383
Anadarko	235	N/A
Northeast Texas System	136	N/A
Tilden	36	N/A
Total	834	383

Marketing

The Marketing segment was established upon the acquisition of the Midcoast System on October 17, 2002. This segment’s results of operations are included in the Partnership’s results since that date, and therefore there is no comparative data for prior periods.

During the first quarter of 2003, operating income was $5.4 million. Operating performance in the Marketing segment is seasonal in nature with the first and fourth quarters typically being the strongest. Strong first quarter segment results in 2003 were due to the ability to optimize natural gas supply to areas of strongest demand and margin within the Partnership’s operational area. Due to the unusual volatility in the quarter, margins on natural gas sales were stronger than observed in recent heating seasons. This was due to the unusually cold weather, lower volumes of natural gas in storage, and generally, a tighter supply of natural gas in North America. Results of the Marketing segment also include the positive impact of a non-recurring gain of approximately $1.5 million due to the settlement of a disputed amount. Results were stronger than anticipated during the first quarter, due to the unusual market conditions and should not be taken as indicative of future results. During the quarter, high natural gas prices resulted in unusually large natural gas payable and receivable balances being associated with this segment. Customer credit is monitored closely, particularly during periods of volatility, and exceptions to credit limits are closely monitored and are routinely reported to Senior Management.

Corporate

Interest expense was $21.3 million in the first quarter of 2003 compared with $14.7 million in 2002. The increase was due to higher debt in 2003 related to the purchase of natural gas assets in October 2002.

Liquidity and Capital Resources

The Partnership believes that it will continue to have adequate liquidity to fund future recurring operating and investing activities. The primary cash requirements for the Partnership consist of normal operating expenses, maintenance and expansion capital expenditures, debt service payments, distributions to partners and acquisitions of new 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 bank credit facilities, i-unit payment in-kind distributions in lieu of cash 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.

During the first quarter of 2003, working capital, or current assets ($462.4 million) less current liabilities ($773.9 million), decreased by $250.4 million to $(311.5) million, primarily due to the increase in current maturities and short-term debt. The increase relates to the 364-Day Facility, which becomes due in January 2004. To the extent that an outstanding balance exists at maturity, the Partnership anticipates refinancing through an extended or renegotiated credit facility.

At March 31, 2003, cash and cash equivalents totaled $70.5 million, as compared to $60.3 million at December 31, 2002. Of this $70.5 million, $37.4 million ($0.925 per unit) will be used for the cash distribution payable May 15, 2003, and $8.7 million relating to the i-units, will be retained by the Partnership for use in its business. The remaining $24.4 million is available for future cash distributions, capital expenditures or other business needs.

Cash flow from operating activities for first quarter 2003 was $78.4 million, as compared with $52.7 million for the same period last year. Cash flow from operating activities increased primarily due to higher net income.

The Partnership anticipates spending approximately $54 million for pipeline system enhancements, $27 million for core maintenance and $42 million for Lakehead System expansion projects in 2003. Excluding major expansion projects, ongoing capital expenditures are expected to average approximately $60 million on an annual basis (approximately 45% for core maintenance and 55% for enhancement of the systems). Core maintenance activities, such as the replacement of equipment and planned major maintenance programs, will be undertaken to enable the Partnership’s systems to continue to operate at their maximum operating capacity. Enhancements to the systems, such as renewal and replacement of pipe, are expected to extend the life of the systems, reduce costs or enhance revenues and permit the Partnership to respond to developing industry and government standards and the changing service expectations of its customers. The Partnership continuously evaluates capital projects that may impact the amounts noted in this paragraph.

General

Regulatory Issues

On March 31, 2003, Enbridge Energy, Limited Partnership (“Lakehead Partnership”), a subsidiary of the Partnership, filed a new tariff with the Federal Energy Regulatory Commission (“FERC”), that took effect May 1, 2003. This new tariff reflects the annual calculation of the SEP II surcharge, including a forecast cost of service for SEP II for 2003 and an adjustment to actuals for 2002 based on final costs and deliveries. The revenue requirement used to calculate the SEP II surcharge for 2003 is $49.6 million, which is approximately $3.1 million less than the 2002 revenue requirement, and results in a decrease in the surcharge of approximately US $0.02/bbl for light movements between the International Border and Chicago. The SEP II surcharge allows the Lakehead Partnership to recover the cost of service for SEP II

facilities and earn a return on its SEP II equity investment, which varies with the utilization of SEP II capacity on the Enbridge System. During 2003, the Lakehead Partnership will earn a 7.5% return on its SEP II equity investment, the minimum provided in the SEP II Tariff Agreement.

On February 24, 2003, the FERC issued an Order on Remand, which replaced the current annual index of Producers Price Index for Finished Goods (“PPI”) less one percent with an index of PPI without the minus one percent. The FERC is allowing current ceiling levels to increase to reflect PPI indexing from July 1, 2001. The March 31 filing reflects this change in indexing by increasing the indexed toll from its current level by approximately 2%, or US $0.01/bbl for light movements between the International Border and Chicago.

The net effect of the March 31, 2003 filing is a decrease in tolls of approximately 1% or US $0.01/bbl for light crude movements between the International Border and Chicago.

Subsequent Events

On April 14, 2003, the Lakehead System was temporarily shut down when an oil leak was detected near Trail, Minnesota. It is estimated that 125 barrels of oil leaked into a remote area. Enbridge personnel worked with local, state and federal agencies to investigate the incident and remediate the area. Clean up of the leak and repair of the pipeline has been completed. Total costs of remediation and repair are expected to approximate $1 million.

On April 30, 2003, the Federal Energy Regulatory Commission ("FERC") approved a draft order on rehearing in docket number CP02-141-001 regarding Transcontinental Gas Pipe Line Corporation's ("Transco") request for authorization to abandon a portion of its system in the south Texas area and the sale of that portion of its system to the Partnership. The FERC had previously approved the abandonment and sale, however, certain customers on the system and Transco had requested rehearing of portions of the FERC's previous order. On rehearing, the FERC has reversed its position and denied the abandonment of the Transco South Texas system for sale to the Partnership. The Partnership is still evaluating the draft order, however, the FERC's order may prevent or delay the Partnership's acquisition of the South Texas system for $41 million.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

The Partnership’s financial instrument market risk is impacted by changes in interest rates. The Partnership’s exposure to movements in interest rates is managed through its long-term debt ratio target, its allocation of fixed and floating rate debt and the use of interest rate risk management agreements. Information about the Partnership’s financial instruments, which are sensitive to changes in interest rates has not changed from that presented in the Partnership’s 2002 Annual Report on Form 10-K. Approximately $520 million of the Partnership’s total outstanding debt carries a floating interest rate. Of the $520 million, $100 million has been hedged with an interest rate swap effective through September 30, 2003.

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 natural gas liquids ("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.

With the Partnership’s acquisition of the East Texas System on November 30, 2001, and the natural gas assets in October 2002, 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 substantially 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 counterparties. As at March 31, 2003, all financial counterparties were rated at least “A” by all major credit rating agencies.

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 our disclosure controls and procedures within 90 days prior to the filing date of this report. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our 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 our 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 2002 or with regard to which material developments were reported during 2002, see Part I. Item 3., “Legal Proceedings,” in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2002.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

a) Exhibits

99.1 Certification of Principal Executive Officer.

99.2 Certification of Principal Financial Officer.

b) Reports on Form 8-K

The Partnership did not file any reports on Form 8-K during the first quarter of 2003.

SIGNATURE

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


ENBRIDGE ENERGY PARTNERS, L.P.
		(Registrant)

By:	Enbridge Energy Management, L.L.C.
	as delegate of
	Enbridge Energy Company, Inc.
	as General Partner


/s/ Mark A. Maki
			Mark A. Maki
			Vice President, Finance
			(Duly Authorized Officer)


Dated: May 2, 2003

Sarbanes-Oxley Section 302(a) Certification

I, Dan C. Tutcher, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Enbridge Energy Partners, L.P.;

2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

a) designed such disclosure, controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

6. The registrant’s other certifying officers and I have indicated in this quarterly report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

Date: May 2, 2003

/s/ Dan C. Tutcher
Dan C. Tutcher
President and Principal Executive Officer

Sarbanes-Oxley Section 302(a) Certification

I, Mark A. Maki, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Enbridge Energy Partners, L.P.;

b) evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

Date: May 2, 2003

/s/ Mark A. Maki
Mark A. Maki
Vice President, Finance and Principal Financial Officer

Item 1.

Legal Proceedings

13

CONSOLIDATED STATEMENTS OF CASH FLOWS

Results of Operations

Natural Gas Transportation

General

Vice President, Finance

(Duly Authorized Officer)