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 September 30, 2003

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)

Yes ý No o

The Registrant had 35,166,134 Class A Common Units outstanding as of November 13, 2003.

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION

Item 1.	Financial Statements
	Consolidated Statements of Income for the three and nine month periods ended September 30, 2003 and 2002

	Consolidated Statements of Comprehensive Income for the three and nine month periods ended September 30, 2003 and 2002

	Consolidated Statements of Cash Flows for the nine month periods ended September 30, 2003 and 2002

	Consolidated Statements of Financial Position as of September 30, 2003 and December 31, 2002

	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

Signature

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 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, 2002.

PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

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

	Three months ended September 30,						Nine months ended September 30,
(unaudited; dollars in millions, except per unit amounts)	2003			2002			2003			2002

Operating revenue	$	760.5		$	237.6		$	2,411.9		$	642.5

Operating expenses
Cost of natural gas	625.3			141.7			2,002.2			362.1
Operating and administrative	52.6			32.4			157.5			91.1
Power	14.2			13.3			39.9			39.3
Depreciation and amortization (Note 8)	23.4			18.5			70.3			55.4

	715.5			205.9			2,269.9			547.9

Operating income	45.0			31.7			142.0			94.6

Other income (expense)	(0.1		)	(0.5		)	1.7			(0.3		)
Interest expense	(21.4		)	(13.5		)	(64.3		)	(41.7		)
Minority interest	—			(0.1		)	—			(0.5		)

Net income	$	23.5		$	17.6		$	79.4		$	52.1

Net income per unit (Note 2)	$	0.38		$	0.42		$	1.39		$	1.24

Weighted average units outstanding (millions)	48.9			35.2			46.8			34.7

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

	Three months ended September 30,				Nine months ended September 30,
(unaudited; dollars in millions)	2003		2002		2003			2002

Net income	$	23.5	$	17.6	$	79.4		$	52.1

Unrealized gain (loss) on derivative financial instruments (Note 7)	20.2		4.3		(42.9		)	(13.8		)

Comprehensive income	$	43.7	$	21.9	$	36.5		$	38.3

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

	Nine months ended September 30,
(unaudited; dollars in millions)	2003			2002

Cash provided by operating activities
Net income	$	79.4		$	52.1
Adjustments to reconcile net income to cash provided by operating activities
Depreciation and amortization	70.3			55.4
Payments made upon settlement of derivative (Note 7)	(6.1		)	—
Other	(0.2		)	(6.1		)
Changes in operating assets and liabilities, Receivables, trade and other	(2.0		)	(33.8		)
Accrued gas sales	(62.9		)	—
Other current assets	(15.4		)	(1.9		)
General Partner and affiliates	(6.2		)	6.0
Accounts payable and other	(7.1		)	45.4
Accrued gas purchases	64.4			—
Interest payable	18.4			11.8
Property and other taxes	1.5			(2.8		)

Cash provided by operating activities	134.1			126.1

Investing activities
Repayments from affiliate	—			0.2
Additions to property, plant and equipment	(92.9		)	(177.8		)
Changes in construction payables	(4.5		)	(0.1		)
Asset acquisitions	(0.5		)	(5.1		)

Cash used in investing activities	(97.9		)	(182.8		)

Financing activities
364-day facility	(102.0		)	168.0
Revolving credit facility	—			(137.0		)
Three-year credit facility	(52.0		)	185.0
Issuance of senior unsecured notes (Note 6)	396.3			—
Loans from Enbridge Energy Company, Inc.	(313.2		)	(117.9		)
Proceeds from unit issuance (Note 4)	169.0			93.3
Distributions to partners	(115.6		)	(102.2		)
Other	(0.1		)	(0.7		)

Cash (used in) provided by financing activities	(17.6		)	88.5

Net increase in cash and cash equivalents	18.6			31.8

Cash and cash equivalents at beginning of period	60.3			40.2

Cash and cash equivalents at end of period	$	78.9		$	72.0

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

(unaudited; dollars in millions)	September 30, 2003			December 31, 2002

*ASSETS*

Current assets
Cash and cash equivalents (Note 5)	$	78.9		$	60.3
Receivables, trade and other, net of allowance for doubtful accounts of $3.4 in 2003 and $3.7 in 2002	34.6			35.0
Accrued gas receivables	245.8			182.9
Other current assets	33.0			19.3
	392.3			297.5

Property, plant and equipment, net	2,277.4			2,253.3
Goodwill	239.3			241.1
Other assets, net	52.5			43.0

	$	2,961.5		$	2,834.9

*LIABILITIES AND PARTNERS’ CAPITAL*

Current liabilities
Due to General Partner and affiliate	$	75.9		$	63.1
Accounts payable and other	73.3			99.1
Accrued gas purchases	206.5			142.1
Interest payable	25.4			7.0
Property and other taxes payable	17.8			16.3
Current maturities and short-term debt (Note 6)	141.0			31.0
	539.9			358.6

Long-term debt (Note 6)	1,146.8			1,011.4
Loans from General Partner and affiliates	130.9			444.1
Environmental liabilities	5.4			5.6
Deferred credits	57.0			23.2
Minority interest	—			0.4
	1,880.0			1,843.3

Commitments and contingencies (Note 10)	—			—

Partners’ capital
Class A common units (Units authorized and issued – 35,166,134 in 2003 and 31,313,634 in 2002)	711.3			604.8
Class B common units (Units authorized and issued – 3,912,750 in 2003 and 2002)	53.3			48.7
i-units (Units authorized and issued – 9,865,753 in 2003 and 9,228,655 in 2002)	353.8			335.6
General Partner	22.3			18.8
Accumulated other comprehensive loss	(59.2		)	(16.3		)
	1,081.5			991.6

	$	2,961.5		$	2,834.9

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 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 at September 30, 2003 and December 31, 2002; the results of operations for the three and nine month periods ended September 30, 2003 and 2002; and cash flows for the nine month periods ended September 30, 2003 and 2002. The results of operations for the three and nine month periods ended September 30, 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 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, 2002.

2. Net Income per Unit

Net income per unit is computed by dividing net income, after deduction of the Enbridge Energy Company, Inc. (the “General Partner”) allocation, by the weighted average number of Class A and Class B common units and i-units outstanding. The General Partner’s allocation is equal to an amount based upon its general partner interest, adjusted to reflect an amount equal to incentive distributions and an amount required to reflect depreciation on the General Partner’s historical cost basis for assets contributed upon formation of the Partnership. Net income per unit was determined as follows:

	Three months ended September 30,						Nine months ended September 30,
(in millions, except per unit amounts)	2003			2002			2003			2002

Net income	$	23.5		$	17.6		$	79.4		$	52.1

Net income allocated to General Partner	(0.5		)	(0.1		)	(1.6		)	(0.5		)
Incentive distributions and historical cost depreciation adjustments	(4.2		)	(2.8		)	(12.7		)	(8.6		)
	(4.7		)	(2.9		)	(14.3		)	(9.1		)

Net income allocable to common units and i-units	$	18.8		$	14.7		$	65.1		$	43.0

Weighted average units outstanding	48.9			35.2			46.8			34.7

Net income per unit	$	0.38		$	0.42		$	1.39		$	1.24

3. Distributions to Unitholders

On October 22, 2003, the Partnership’s Board of Directors declared a distribution payable on November 14, 2003, to unitholders of record as of October 31, 2003, of its available cash of $50.4 million at September 30, 2003, or $0.925 per common unit. Of this distribution, $9.1 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.

The following table sets forth the distributions, as approved by the Board of Directors for each period in 2003 (dollars in millions, except per unit amounts).

Distribution Declaration Date	Distribution Payment Date	Ex-Distribution Date	Distribution per Unit		Cash available for distribution		Amount of Distribution of i-units to i- unit holders		Retained from General Partner		Distribution of Cash
July 23, 2003	August 14, 2003	July 31, 2003	$	0.925	$	50.3	$	8.9	$	0.2	$	41.2
April 24, 2003	May 15, 2003	April 30, 2003	$	0.925	46.1		8.7		0.2		37.2
January 23, 2003	February 14, 2003	January 31, 2003	$	0.925	45.9		8.5		0.2		37.2
Total					$	142.3	$	26.1	$	0.6	$	115.6

4. Equity Unit Issuance

In May 2003, the Partnership issued 3.85 million Class A Common Units at $44.79 per unit, which generated proceeds, net of underwriters’ fees and discounts, commissions and issuance expenses, of approximately $165.5 million. Proceeds from this offering were used to reduce borrowings under the Partnership’s credit facility and an affiliate loan from Enbridge (U.S.) Inc. In addition to the proceeds generated from the unit issuances, the General Partner contributed $3.5 million to the Partnership to maintain its 2% general partner interest in the Partnership.

5. Reclassification of outstanding checks

The Partnership utilizes a cash management system that includes zero balance accounts. When outstanding checks result in negative cash balances for such accounts, these balances are reclassified to liabilities for presentation purposes in the consolidated statement of financial position. As of September 30, 2003 and December 31, 2002, $10.8 million and $2.9 million, respectively, of outstanding checks were classified to liabilities.

6. Debt

On May 27, 2003, the Partnership issued $200.0 million in aggregate principal amount of its 4.75% Notes due 2013 and $200.0 million in aggregate principal amount of its 5.95% Notes due 2033 (the “Notes”) in a private placement. The Partnership used the proceeds of approximately $396.3 million, net of expenses of approximately $3.0 million, to repay loans from affiliates of the Partnership and other bank debt. The Partnership recorded a discount of $0.7 million in connection with the issuance of the Notes. On June 30, 2003, the Partnership completed a Form S-4 with the Securities and Exchange Commission (the “SEC”), which registered the exchange of the unregistered Notes for publicly registered Notes.

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 $300.0 million three-year facility, which matures in 2006, subject to extension as provided in the facilities, and the amended and restated $300.0 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 the changes to the facilities, the Partnership must maintain a minimum interest coverage ratio of 2.75 to 1.00 as of the end of each fiscal quarter and a maximum leverage ratio of 4.75 to 1.00 as defined in the facilities. The Partnership is no longer required to maintain a particular credit rating. Although subsidiaries may incur debt subject to certain restrictions and limitations under the new facilities, the Partnership expects to provide funding to its subsidiaries. As of September 30, 2003, $110.0 million and $200.0 million were outstanding under the 364-day and three-year facilities, respectively.

7. Derivative Instruments and Hedging Activities

Effective September 29, 2003, the Partnership entered into two floating-to-fixed interest rate swap contracts with a notional amount of $100.0 million maturing on October 6 and 7, 2004, for the purpose of locking in LIBOR interest rates on existing floating rate debt borrowings. As of September 30, 2003, the fair value of the swaps was insignificant. The swaps are fully effective cash flow hedges under the guidelines set forth in FASB Statement 133. All changes to the fair value of the derivative instrument are recorded in accumulated other comprehensive income.

Effective August 15, 2003, the Partnership entered into three fixed-to-floating interest rate swap contracts with a notional amount of $125.0 million maturing June 1, 2013, to hedge the fair value of an existing term debt issuance. This hedge effectively converts the fixed rate debt instrument into a LIBOR based floating rate debt instrument. As of September 30, 2003, the fair value of the swaps totaled $4.5 million. The hedges are fully effective fair value hedges under the guidelines set forth in FASB Statement 133. All changes to the fair value of both the derivative instrument and the hedged debt are recorded to income.

In May 2003, the Partnership entered into a notional $104.0 million treasury lock contract for the purpose of locking in the U.S. Treasury bond interest rate on an anticipated fixed rate term debt offering. The hedge has been amended to mature on December 1, 2003. As of September 30, 2003, the fair value of the hedge totaled $0.6 million and is deemed to be an effective cash flow hedge under the guidelines set forth in FASB Statement 133. All changes to the fair value of the derivative instrument are recorded in accumulated other comprehensive income.

The changes in the market value of natural gas hedging instruments that are attributable to hedge ineffectiveness, measured on a quarterly basis, are included in cost of natural gas expense in the period in which they occur. During the second and third quarters of 2003, the Partnership recorded, insignificant gains and losses related to the ineffective portions of certain hedge transactions.

8. 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. The annual composite rate was reduced from 3.9% to 3.1%. Depreciation expense for the nine months ended September 30, 2003 was $43.3 million for the Liquids Transportation segment. Using the revised rates, depreciation expense was $10.5 million lower than it would have been had the Partnership used previous depreciation rates. Compared to the same period in 2002, this reduction was offset by $5.8 million additional depreciation as a result of facilities placed into service during the fourth quarter 2002.

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.

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

	As of and for the three months ended September 30, 2003
	Liquids Transportation		Gathering and Processing		Natural Gas Transportation		Marketing		Corporate			Total
Total revenues	$	83.8	$	510.2	$	27.1	$	499.4	$	—		$	1,120.5
Less: Intersegment revenues	—		80.3		0.6		279.1		—			360.0
Operating revenues	83.8		429.9		26.5		220.3		—			760.5
Cost of natural gas	—		391.3		15.8		218.2		—			625.3
Operating and administrative	26.5		20.4		4.5		0.5		0.7			52.6
Power	14.2		—		—		—		—			14.2
Depreciation and amortization	14.4		5.8		3.2		—		—			23.4
Operating income	28.7		12.4		3.0		1.6		(0.7		)	45.0
Other income (expense)	—		—		—		—		(0.1		)	(0.1		)
Interest expense	—		—		—		—		(21.4		)	(21.4		)
Net income	$	28.7	$	12.4	$	3.0	$	1.6	$	(22.2	)	$	23.5

Total assets	$	1,535.8	$	762.8	$	418.5	$	203.6	$	40.8		$	2,961.5
Goodwill	$	—	$	146.1	$	72.9	$	20.3	$	—		$	239.3
Capital expenditures (excluding acquisitions)	$	33.1	$	12.6	$	1.0	$	—	$	0.6		$	47.3

	As of and for the three months ended September 30, 2002
	Liquids Transportation		Gathering and Processing		Natural Gas Transportation		Marketing		Corporate			Total
Total revenues	$	82.5	$	155.1	$	—	$	—	$	—		$	237.6
Less: Intersegment revenues	—		—		—		—		—			—
Operating revenues	82.5		155.1		—		—		—			237.6
Cost of natural gas	—		141.7		—		—		—			141.7
Operating and administrative	27.9		5.9		—		—		(1.4		)	32.4
Power	13.3		—		—		—		—			13.3
Depreciation and amortization	16.0		2.5		—		—		—			18.5
Operating income	25.3		5.0		—		—		1.4			31.7
Other income (expense)	—		—		—		—		(0.5		)	(0.5		)
Interest expense	—		—		—		—		(13.5		)	(13.5		)
Minority interest	—		—		—		—		(0.1		)	(0.1		)
Net income	$	25.3	$	5.0	$	—	$	—	$	(12.7	)	$	17.6

Total assets	$	1,511.9	$	272.7	$	—	$	—	$	48.8		$	1,833.4
Goodwill	$	—	$	15.0	$	—	$	—	$	—		$	15.0
Capital expenditures (excluding acquisitions)	$	75.2	$	—	$	—	$	—	$	—		$	75.2

	As of and for the nine months ended September 30, 2003
	Liquids Transportation		Gathering and Processing		Natural Gas Transportation		Marketing		Corporate			Total
Total revenues	$	251.0	$	1,585.0	$	94.5	$	1,551.9	$	—		$	3,482.4
Less: Intersegment revenues	—		211.1		3.5		855.9		—			1,070.5
Operating revenues	251.0		1,373.9		91.0		696.0		—			2,411.9
Cost of natural gas	—		1,261.9		54.5		685.8		—			2,002.2
Operating and administrative	79.8		58.5		15.5		1.3		2.4			157.5
Power	39.9		—		—		—		—			39.9
Depreciation and amortization	43.3		16.9		10.0		0.1		—			70.3
Operating income	88.0		36.6		11.0		8.8		(2.4		)	142.0
Other income (expense)	—		—		—		—		1.7			1.7
Interest expense	—		—		—		—		(64.3		)	(64.3		)
Net income	$	88.0	$	36.6	$	11.0	$	8.8	$	(65.0	)	$	79.4
Total assets	$	1,535.8	$	762.8	$	418.5	$	203.6	$	40.8		$	2,961.5
Goodwill	$	—	$	146.1	$	72.9	$	20.3	$	—		$	239.3
Capital expenditures (excluding acquisitions)	$	53.1	$	33.9	$	3.4	$	0.1	$	2.4		$	92.9

	As of and for the nine months ended September 30, 2002
	Liquids Transportation		Gathering and Processing		Natural Gas Transportation		Marketing		Corporate			Total
Total revenues	$	246.1	$	396.4	$	—	$	—	$	—		$	642.5
Less: Intersegment revenues	—		—		—		—		—			—
Operating revenues	246.1		396.4		—		—		—			642.5
Cost of natural gas	—		362.1		—		—		—			362.1
Operating and administrative	74.6		16.5		—		—		—			91.1
Power	39.3		—		—		—		—			39.3
Depreciation and amortization	48.0		7.4		—		—		—			55.4
Operating income	84.2		10.4		—		—		—			94.6
Other income (expense)	—		—		—		—		(0.3		)	(0.3		)
Interest expense	—		—		—		—		(41.7		)	(41.7		)
Minority interest	—		—		—		—		(0.5		)	(0.5		)
Net income	$	84.2	$	10.4	$	—	$	—	$	(42.5	)	$	52.1
Total assets	$	1,511.9	$	272.7	$	—	$	—	$	48.8		$	1,833.4
Goodwill	$	—	$	15.0	$	—	$	—	$	—		$	15.0
Capital expenditures (excluding acquisitions)	$	172.3	$	5.5	$	—	$	—	$	—		$	177.8

10. Commitments and contingencies

From 1998, when the Kansas Pipeline system (“KPC”) became subject to the FERC jurisdiction, until November 9, 2002, at which time KPC’s rate case became effective, the FERC established initial rates based upon an annual cost of service of approximately $31 million. Since that time, these initial rates have been the subject of various ongoing challenges that remain unresolved.

that the FERC address the question of an appropriate rate refund. In prior KPC orders in this proceeding, the FERC determined that it had no authority to impose a refund condition on initial rates. On October 3, 2003, KPC filed a pleading at FERC requesting the issuance of an order finding that it had no refund obligation and requesting termination of the proceedings on remand. There are other actions and administrative proceedings that may be undertaken in connection with the Court’s determination. The outcome of KPC’s motion or any other proceedings, including the amount of any refunds that may be ordered, is uncertain. If the FERC determines refunds are required, after all administrative options and court appeals are exhausted, the amount of the refunds effecting the Partnership's earnings may range from $Nil to $9.0 million.

11. New Accounting Pronouncements

In June 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations, which must be adopted in years beginning after June 15, 2002. This standard requires legal obligations associated with the retirement of long-lived tangible assets to be recognized at fair value. When the liability is initially recorded, the cost is capitalized by increasing the assets carrying value, which is subsequently depreciated over its useful life. The new standard was adopted January 1, 2003 and did not have a material impact on the Partnership’s financial position, results of operations, or cash flows.

In April 2003, the FASB issued SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities. This statement amends and clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts (collectively referred to as derivatives) and for hedging activities under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. In particular, this statement: (1) clarifies under what circumstances a contract with an initial net investment meets the characteristic of a derivative discussed in paragraph 6(b) of SFAS No. 133, (2) clarifies when a derivative contains a financing component, (3) amends the definition of an underlying to conform it to language used in FASB Interpretation No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others, and (4) amends certain other existing pronouncements. Those changes will result in more consistent reporting of contracts as either derivatives or hybrid instruments. The new standard was adopted July 1, 2003 and did not have a significant impact on the Partnership’s financial position, results of operations, or cash flows.

12. 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 - - Overview

Net income for the third quarter of 2003 improved by $5.9 million, or 34%, to $23.5 million compared with $17.6 million for the third quarter of 2002. Net income for the nine months ended September 30, 2003 improved $27.3 million, or 52%, to $79.4 million compared with $52.1 million for the nine months ended September 30, 2002. The increase in net income in both periods in 2003 was primarily due to the inclusion of the Midcoast System results. The comparable numbers for 2002 did not include earnings from the Midcoast System, as these assets were purchased in the fourth quarter of 2002.

Earnings per unit for the third quarter of 2003 was $0.38 per unit, compared with $0.42 for the third quarter of 2002. Earnings per unit for the nine months ended September 30, 2003 was $1.39 per unit, compared with $1.24 per unit for the nine months ended September 30, 2002. Earnings per unit was higher for the nine months ended September 30, 2003 due to an increase in net income primarily due to the Midcoast acquisition, partially offset by an increase in the number of units outstanding. Due to the i-unit issuance in October 2002 and a Class A common unit issuance in May 2003, the weighted average number of common units outstanding increased. On a quarterly basis, the weighted average number of common units outstanding increased from 35.2 million in the third quarter of 2002 to 48.9 million in the third quarter of 2003. On a year-to-date basis, it increased from 34.7 million in the first nine months of 2002 to 46.8 million in the first nine months of 2003.

The Partnership’s reportable segments are based on the types 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, Gathering and Processing, Natural Gas Transportation, 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 table reflects operating income by business segment and corporate charges for each of the three and nine-month periods ended September 30, 2003 and 2002.

	Three months ended September 30,						Nine months ended September 30,
(unaudited; dollars in millions)	2003			2002			2003			2002

Operating Income
Liquids Transportation	$	28.7		$	25.3		$	88.0		$	84.2
Gathering and Processing	12.4			5.0			36.6			10.4
Natural Gas Transportation	3.0			—			11.0			—
Marketing	1.6			—			8.8			—
Corporate, operating and administrative	(0.7		)	1.4			(2.4		)	—
Total Operating Income	$	45.0		$	31.7		$	142.0		$	94.6
Other income (expense), net	(21.5		)	(14.1		)	(62.6		)	(42.5		)
Net Income	$	23.5		$	17.6		$	79.4		$	52.1

Results of Operations – by Segment

Liquids Transportation

Three months ended September 30, 2003 compared with three months ended September 30, 2002

Operating income increased by approximately $3.4 million to $28.7 million for the three months ended September 30, 2003, compared with $25.3 million for the same period in 2002. Operating income was higher in the 2003 period due to higher revenue, lower operating expenses and lower depreciation.

Operating revenue for the third quarter of 2003 was $83.8 million compared with $82.5 million for the third quarter of 2002. The increase of $1.3 million in 2003 was primarily due to an improvement in deliveries on the Lakehead system, partially offset by lower tariffs. Production of western Canadian crude oil has increased over last year due to the start up of new oil sands projects in the Province of Alberta. During the third quarter of 2003, deliveries on the Lakehead system were lower than expected due to the August power outage that occurred in the northeastern United States and Canada, and supply disruptions in Alberta. While portions of the Lakehead system were out of service for only 3 days as a result of the power outage, most lines in the Lakehead system had reduced rates over the second half of August to accommodate processing limitations of downstream refiners as they returned to prior operating levels. As a result of this interruption, tankage levels were close to

capacity along the Lakehead system, with carry-over volumes to be delivered in the fourth quarter of 2003. Crude oil supply was also impacted during the third quarter of 2003 by continued production volatility at some of the new oil sands projects. Tariffs were lower due to the negative Federal Energy Regulatory Commission (“FERC”) indexed-tariff adjustment effective July 1, 2003, and a decrease in the SEP II tariff effective May 1, 2003.

The following table sets forth the Lakehead system’s average deliveries per day, barrel miles, and average haul for the three and nine month periods ending September 30, 2003 and 2002:

	Three months ended September 30,		Nine months ended September 30,
	2003	2002	2003	2002
Average BBls/day
United States	1,014	905	971	926
Province of Ontario	318	337	347	362
Total deliveries (thousands)	1,332	1,242	1,318	1,288

Barrel miles (billions)	84	83	250	252
Average haul (miles)	690	720	696	715

Operating and administrative expenses were $26.5 million for the third quarter of 2003, compared with $27.9 million in the same period of 2002. Increased oil measurement losses and property taxes of $3.2 million, in aggregate, were more than offset by lower leak remediation, repair costs, and other general and administrative costs in 2003. The third quarter of 2002 included repair, restoration and pipeline integrity costs of approximately $4.0 million associated with a Lakehead system leak that occurred in July 2002.

Depreciation expense was $14.4 million for the third quarter of 2003, compared with $16.0 million in the third quarter of 2002. The decrease was primarily due to revised depreciation rates on the Lakehead system. The revised rates better represent the expected remaining service life of the pipeline system. Using the revised rates, depreciation expense was approximately $4.4 million lower than it would have been using previous depreciation rates. Compared to the same period in 2002, this reduction was offset by $2.8 million additional depreciation as a result of facilities placed into service during the fourth quarter of 2002.

Nine months ended September 30, 2003 compared with nine months ended September 30, 2002

Operating income increased for the nine months ended September 30, 2003 by approximately $3.8 million to $88.0 million, as compared with $84.2 million for the nine months ended September 30, 2002. Operating income was higher in 2003 primarily due to higher revenues and lower depreciation, partially offset by higher operating expenses.

Operating revenue for the first nine months of 2003 increased by $4.9 million to $251.0 million from $246.1 million for the same period in 2002 for the same reasons as noted above in the three-month analysis.

Operating and administrative expenses for the first nine months of 2003 increased $5.2 million to $79.8 million from $74.6 million for the same period in 2002. The increase was due to higher workforce related costs, as well as an increase in costs associated with the cleanup and remediation of leaks that occurred during 2003 on the Lakehead system.

Depreciation expense was $43.3 million for the nine months ended September 30, 2003, compared with $48.0 million in 2002. The decrease of $4.7 million was due to revised depreciation rates on the Lakehead system, offset by additional depreciation on facilities placed into service during the fourth quarter 2002. Depreciation expense for the nine months ended September 30, 2003, was approximately $10.5 million lower than it would have been using previous depreciation rates.

Gathering and Processing

The East Texas System was acquired on November 30, 2001, and additional 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.

Volatility in natural gas prices can impact the operating income of the Gathering and Processing segment. When natural gas prices are high, processing activities may be non-economic on certain facilities where processing is mandatory as a result of downstream pipeline quality specifications. Operating income from this segment is derived from fixed fee contract structures, percentage-of-index contract structures, and trucking operations.

During the first nine months of 2003, historically high natural gas prices made keep-whole processing contracts non-economic for the gathering and processing segment. A negative processing margin of approximately $1.6 million was recorded for the first nine months of 2003, whereas $5.8 million of processing margin was expected for the same period. First of the month natural gas prices fluctuated between $4.93 and $9.11 per Mmbtu resulting in an average price of approximately $5.65 per Mmbtu during the nine months ended September 30, 2003. Due to fluctuations in both the natural gas and natural gas liquids prices, the processing margin was positive in some months and negative in others. When processing margins were positive, the Partnership processed volumes beyond the contractual mandatory levels. Assuming an approximate $5 per Mmbtu natural gas price and stable NGL prices, it is expected that processing margins in the Gathering and Processing segment will break even for the remainder of the year. Should natural gas prices increase by $1 per Mmbtu and remain constant for the last quarter of 2003, processing margins could be negative approximately $2.0 million for the last three months of 2003. This estimate assumes constant NGL prices, expected natural gas volumes, and other assumptions. Natural gas price changes will also impact contractual in-kind natural gas operational balancing agreements, which are revalued monthly at market prices.

The following table indicates the average daily volume for each of the major systems in the Partnership’s Gathering and Processing segment during the three and nine months ended September 30, 2003 and 2002, in million British thermal units per day (“Mmbtu/d”).

	Three months ended September 30,		Nine months ended September 30,
	2003	2002	2003	2002
Gathering Systems:
East Texas	450	411	441	397
Anadarko	262	N/A	249	N/A
Northeast Texas	129	N/A	133	N/A
Tilden	37	N/A	36	N/A
Total	878	411	859	397

East Texas System. Operating income for the third quarter of 2003 of $6.3 million was improved by $1.3 million compared with the same period in 2002. Higher volumes were offset by lower processing margins due to higher gas prices during 2003. Operating income for the East Texas System was $13.1 million for the nine months ended 2003 compared with $10.4 million for the same period ended September 30, 2002. The increase of $2.7 million was primarily due to higher volumes and the absence of expenses related to treating plant maintenance shutdowns that occurred during the first half of 2002, offset by less favorable processing in 2003. Higher volumes are a result of an increase in natural gas production and new drilling by producers in the East Texas area.

Other Gathering and Processing systems. Operating income on the Anadarko system was positively impacted by higher volumes and improved processing margins, which were realized from lower natural gas prices and higher natural gas liquid (“NGL”) prices during the third quarter of 2003. The increase in operating income was partially offset by higher operating costs. Volumes on the Northeast Texas system were slightly lower during the third quarter of 2003 due to well declines. Expectations are for a stable supply on the Northeast Texas system during the remainder of 2003.

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 systems contributed $3.0 million and $11.0 million to operating income for the three and nine month periods ended September 30, 2003, respectively. Performance of the Natural Gas Transportation segment is largely dependent upon revenues derived from reserved pipeline capacity. 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.

The table below indicates the average daily volumes in Mmbtu/d for the major systems in the Partnership’s Natural Gas Transportation segment for the three and nine-month periods ended September 30, 2003.

	Three months ended September 30, 2003	Nine months ended September 30, 2003
	(average Mmbtu/d)
Major Natural Gas Transportation Systems:
UTOS Pipeline	184	222
MidLa Pipeline	106	116
AlaTenn Pipeline	44	59
Kansas Pipeline	22	46
Bamagas Pipeline	24	17
Other Major Intrastates	179	182
Total	559	642

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, as such, there is no comparative data for prior periods.

Operating income for the Marketing segment was $1.6 million for the three months and $8.8 million for the nine months ended September 30, 2003. Colder weather during the first four months of 2003 created greater demand for natural gas. This increased the ability to optimize firm transportation contracts in competitive markets, because of strong demand from wholesale customers. Results for the Marketing segment for the nine months ended September 30, 2003 also include the positive impact of approximately $1.9 million due to the settlement of disputed amounts. 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 because colder weather generates significant incremental sales to the Partnership’s wholesale customers and creates the opportunity to optimize transportation and storage agreements.

Corporate

Other income (expense) was $(0.1) million for the three month period ending September 30, 2003 and $1.7 million for the nine-month period ending September 30, 2003, compared with ($0.5) million for the three months and ($0.3) million for the nine months ended September 30, 2002. The balance for 2003 is primarily due to gains related to settlements of previously disputed amounts associated with certain assets purchased in the Midcoast acquisition in October 2002.

Interest expense was $21.4 million for the three months ended September 30, 2003, compared with $13.5 million for the same period in 2002. Interest expense was $64.3 million for the nine months ended September 30, 2003, compared with $41.7 million for the same period in 2002. The increase in both periods is due to higher debt balances in the 2003 period compared to the 2002 period, coupled with higher interest rates.

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 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.

Working capital decreased by $86.5 million to ($147.6) million at September 30, 2003, compared with ($61.1) million at

December 31, 2002, primarily due to the net increase in current maturities and short-term debt, as well as interest payable on long-term debt. The increase of current maturities of long-term debt relates to the 364-day credit facility, which is 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 September 30, 2003, cash and cash equivalents totaled $78.9 million, compared with $60.3 million at December 31, 2002. Of the cash balance, $50.4 million ($0.925 per unit) will be used for the distribution payable November 14, 2003, including $9.1 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 be retained by the Partnership for use in its business. The remaining $28.5 million is available for future cash distributions, capital expenditures or other business needs.

Cash flow from operating activities for the nine months ended September 30, 2003 was $134.1 million as compared with $126.1 million for the same period last year. The increase of $8.0 million is primarily due to an increase in net income and depreciation expense, which was offset by increased payments to the General Partner and affiliates, an increase in the gas in storage, and a payment made upon settlement of derivative transactions related to an interest rate hedge that was entered into place for the May 2003 debt issuance.

Cash flow used in investing activities during the nine months ended September 30, 2003 was $97.9 million, compared with $182.8 million for the same period in 2002. The decrease of $84.9 million is primarily due to a decrease in additions to property, plant and equipment, which is a result of the Terrace Phase III expansion. The majority of the construction activity related to the Terrace Phase III expansion occurred during 2002.

Cash flow used in financing activities during the nine months ended September 30, 2003 was $17.6 million, compared with cash flow provided by financing activities of $88.5 million for the same period in 2002. The decrease in cash flow is primarily due to changes in debt, which include the net repayments of loans from the General Partner of $313.2 million and other repayments of $102.0 million outstanding under credit facilities, as compared to additional net borrowings of $168.0 million in 2002. This was partially offset by the issuance of senior unsecured Notes of $396.3 million and Class A common unit issuances of $169.0 million in May 2003, compared to only $93.3 million in Class A common unit issuances during the nine months ended September 30, 2002.

In May 2003, the Partnership issued 3.85 million Class A common units at $44.79 per unit, which generated proceeds, net of underwriters’ fees and discounts, commissions and issuance expenses, of approximately $165.5 million. Proceeds from this offering were used to reduce borrowings under the Partnership’s credit facility and an affiliate loan from Enbridge (U.S.) Inc. In addition to the proceeds generated from the unit issuances, the General Partner contributed $3.5 million to the Partnership to maintain its 2% general partner interest in the Partnership.

On May 27, 2003, the Partnership issued $200.0 million in aggregate principal amount of its 4.75% Notes due 2013 and $200.0 million in aggregate principal amount of its 5.95% Notes due 2033 (the “Notes”) in a private placement. The Partnership used the proceeds of approximately $396.3 million, net of expenses of approximately $3.0 million, to repay existing loans from affiliates of Enbridge Inc. and other bank debt. The Partnership recorded a discount of $0.7 million in conjunction with the issuance of the two series of Notes. On June 30, 2003, the Partnership completed a Form S-4 with the Securities and Exchange Commission (the “SEC”) to register offers to exchange the unregistered Notes for publicly registered Notes.

The Partnership has in effect a universal shelf registration statement with the SEC. The Partnership may offer and sell debt securities or Class A Common Units, from time to time, up to a total of $1.5 billion, with the amount, price and terms to be determined at the time of the sale. The Partnership expects to use the net proceeds from any future sales of securities under the universal shelf registration statement for operations and for other general corporate purposes, including repayment or refinancing of borrowings, working capital, capital expenditures, or acquisitions of businesses or assets. As of September 30, 2003, the Partnership has not issued any securities pursuant to the shelf registration statement.

In May 2003, Moody’s assigned the Partnership’s senior unsecured debt a Baa2 rating. In May 2003, Moody’s also lowered its senior unsecured debt rating of Enbridge Energy, Limited Partnership, a wholly-owned subsidiary of the Partnership, from A3 to Baa1.

The Partnership anticipates spending approximately $84.0 million for pipeline system enhancements, $27.0 million for core maintenance and $39.0 million for Lakehead System expansion projects in 2003. Excluding major expansion projects, ongoing capital expenditures are expected to average approximately $70.0 million on an annual basis (approximately 40% for core maintenance and 60% 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 estimates noted in this paragraph.

General Matters

From 1998, when the Kansas Pipeline system (“KPC”) became subject to the FERC jurisdiction, until November 9, 2002, when KPC’s rate case rates became effective, the FERC established initial rates based upon an annual cost of service of approximately $31 million. Since that time, these initial rates have been the subject of various ongoing challenges that remain unresolved.

The United States Court of Appeals for the D.C. Circuit issued an order on August 12, 2003 vacating the FERC’s 2001 remand order and 2002 rehearing order and remanded the issue of KPC’s initial rates back to the FERC with directions that the FERC address the question of an appropriate rate refund. In prior KPC orders in this proceeding, the FERC determined that it had no authority to impose a refund condition on initial rates. On October 3, 2003, KPC filed a pleading at the FERC requesting the issuance of an order finding that it had no refund obligation and requesting termination of the proceedings on remand. There are other actions and administrative proceedings that may be undertaken in connection with the Court’s determination. The outcome of KPC’s motion or any proceedings, including the amount of any refunds that may be ordered, is uncertain. If the FERC determines refunds are required, after all administrative options and court appeals are exhausted, the amount of the refunds effecting the Partnership's earnings may range from $Nil to $9.0 million.

On June 25, 2003, the Partnership and Williams Field Services (“Williams”) mutually agreed to terminate an agreement for the sale by Williams of certain South Texas natural gas transmission lines to the Partnership. On May 2, 2003, the FERC issued an order denying the abandonment of the South Texas system, reversing a previous ruling granting the approvals necessary for the sale. This decision effectively prevents the sale from proceeding under the terms of the purchase and sale agreement.

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 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.

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.

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 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.

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 as of September 30, 2003. 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.

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

The Partnership is a participant in other 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

31.1 Sarbanes-Oxley Section 302(a) Certification of Principal Executive Officer.

31.2 Sarbanes-Oxley Section 302(a) Certification of Principal Financial Officer.

32.1 Certification of Principal Executive Officer.

32.2 Certification of Principal Financial Officer.

b) Reports on Form 8-K

The Partnership filed the following reports on Form 8-K during the third quarter of 2003:

A report on Form 8-K was filed on July 31, 2003 that contains the Consolidated Statements of Financial Position of Enbridge Energy Company, Inc., at June 30, 2003 and December 31, 2002. Enbridge Energy Company, Inc., is the General Partner of the Partnership.

A report on Form 8-K was filed on July 29, 2003 attaching a press release dated July 23, 2003 regarding the financial results of the Partnership for the three and six months ended June 30, 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)


				Date: November 13, 2003

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

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

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

Item 1.

Legal Proceedings

Three months ended September 30, 2003 compared with three months ended September 30, 2002