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 June 30, 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)

 

 

 

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 August 14, 2003.

 

 

TABLE OF CONTENTS

 

PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements
	Consolidated Statements of Income for the three and six month periods ended June 30, 2003 and 2002
	Consolidated Statements of Comprehensive Income for the three and six month periods ended June 30, 2003 and 2002
	Consolidated Statements of Cash Flows for the six month periods ended June 30, 2003 and 2002
	Consolidated Statements of Financial Position as of June 30, 2003 and December 31, 2002
	Consolidated Statement of Partners’ Capital for six month period ended June 30, 2003
	Notes to Consolidated Financial Statements
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 3.	Quantitative and Qualitative Disclosures About Market Risk
Item 4.	Controls and Procedures
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings
Item 6.	Exhibits and Reports on Form 8-K
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.

 

1

 

PART I - FINANCIAL INFORMATION

 

ITEM 1.  FINANCIAL STATEMENTS

 

ENBRIDGE ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF INCOME

 

		Three months ended June 30,						Six months ended June 30,
(unaudited; dollars in millions, except per unit amounts)		2003			2002			2003			2002
Operating revenue		$	755.3		$	223.1		$	1,651.4		$	404.9
Operating Expenses
Cost of natural gas		623.4			130.8			1,376.9			220.4
Operating and administrative		52.3			30.9			104.9			58.7
Power		13.0			12.4			25.7			26.0
Depreciation and amortization (Note 7)		23.5			18.6			46.9			36.9
		712.2			192.7			1,554.4			342.0
Operating income		43.1			30.4			97.0			62.9
Interest and other income (expense)		1.8			0.1			1.8			0.2
Interest expense		(21.6		)	(13.5		)	(42.9		)	(28.2		)
Minority interest		—			(0.2		)	—			(0.4		)
Net income		$	23.3		$	16.8		$	55.9		$	34.5
Net income per unit (Note 2)		$	0.39		$	0.39		$	1.01		$	0.82
Weighted average units outstanding (millions)		46.8			35.2			45.7			34.4

 

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

 

2

 

ENBRIDGE ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

 

		Three months ended June 30,						Six months ended June 30,
(unaudited; dollars in millions)		2003			2002			2003			2002
Net income		$	23.3		$	16.8		$	55.9		$	34.5
Unrealized loss on derivative financial instruments		(41.9		)	(3.6		)	(63.6		)	(18.1		)
Change associated with ineffectiveness of current period hedge transactions		0.5			—			0.5			—
Comprehensive income (loss) (Note 6)		$	(18.1	)	$	13.2		$	(7.2	)	$	16.4

 

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

 

3

 

ENBRIDGE ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

(unaudited; dollars in millions) Six months ended June 30,		2003			2002
Cash provided by operating activities
Net income		$	55.9		$	34.5
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization		46.9			36.9
Hedge transactions ineffectiveness (Note 6)		0.5			—
Payments made upon termination of derivative (Note 6)		(6.1		)	—
Other		0.3			0.2
Changes in operating assets and liabilities, Receivables, trade and other		(87.1		)	(20.9		)
Other current assets		(6.0		)	(3.2		)
General Partner and affiliates		(11.1		)	(15.1		)
Accounts payable and other		(9.7		)	22.0
Accrued gas purchases		91.0			—
Interest payable		2.7			0.3
Property and other taxes		(1.7		)	(3.9		)
Cash provided by operating activities		75.6			81.0
Investing activities
Repayments from affiliate		—			0.2
Additions to property, plant and equipment		(45.6		)	(102.6		)
Changes in construction payables		(5.4		)	2.4
Asset acquisitions, net of cash acquired		(0.4		)	(3.7		)
Cash used in investing activities		(51.4		)	(103.7		)
Financing activities
364-day facility		(132.0		)	274.0
Revolving credit facility		—			(137.0		)
Three-year credit facility		(52.0		)	(7.0		)
Issuance of senior unsecured notes, net (Note 5)		396.3			—
Loans from Enbridge Energy Company, Inc., net		(316.0		)	(117.7		)
Proceeds from unit issuance, net (Note 4)		168.2			93.2
Distributions to partners		(74.3		)	(67.3		)
Other		(0.5		)	(1.8		)
Cash (used in) provided by financing activities		(10.3		)	36.4
Net increase in cash and cash equivalents		13.9			13.7
Cash and cash equivalents at beginning of period		60.3			40.2
Cash and cash equivalents at end of period		$	74.2		$	53.9

 

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

 

4

 

ENBRIDGE ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

 

(unaudited; dollars in millions)		June 30, 2003			December 31, 2002
ASSETS
Current assets
Cash and cash equivalents		$	74.2		$	60.3
Receivables, trade and other, net of allowance for  doubtful accounts of $3.4 in 2003 and $3.7 in 2002		305.1			217.9
Other current assets		25.6			19.3
		404.9			297.5
Property, plant and equipment, net		2,253.1			2,253.3
Goodwill		239.3			241.1
Other assets, net		45.1			43.0
		$	2,942.4		$	2,834.9
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Due to General Partner and affiliate		$	52.0		$	63.1
Accounts payable and other		92.2			99.1
Accrued gas purchases		233.1			142.1
Interest payable		9.7			7.0
Property and other taxes payable		14.6			16.3
Current maturities and short-term debt (Note 5)		111.0			31.0
		512.6			358.6
Long-term debt (Note 5)		1,146.7			1,011.4
Loans from General Partner and affiliates		128.1			444.1
Environmental liabilities		5.6			5.6
Deferred credits		71.1			23.2
Minority interest		—			0.4
		1,864.1			1,843.3
Partners’ capital
Class A common units (Units authorized and issued – 35,166,134 in 2003 and 31,313,634 in 2002)		729.8			604.8
Class B common units (Units authorized and issued – 3,912,750 in 2003 and 2002)		55.3			48.7
i-units (Units authorized and issued – 9,673,843 in 2003 and 9,228,655 in 2002)		350.0			335.6
General Partner		22.6			18.8
Accumulated other comprehensive loss		(79.4		)	(16.3		)
		1,078.3			991.6
		$	2,942.4		$	2,834.9

 

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

 

5

 

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		—		32.3
Allocation of net proceeds from unit issuance (Note 4)		3,852,500		150.6
Distributions to partners		—		(57.9		)
Ending balance at June 30, 2003		35,166,134		$	729.8
Class B Units:
Beginning balance at December 31, 2002		3,912,750		48.7
Net income allocation		—		4.5
Allocation of net proceeds from unit issuance		—		9.3
Distributions to partners		—		(7.2		)
Ending balance at June 30, 2003		3,912,750		$	55.3
i-units:
Beginning balance at December 31, 2002		9,228,655		335.6
Net income allocation		—		9.5
Allocation of net proceeds from unit issuance		—		4.9
Distributions to partners		445,188		—
Ending balance at June 30, 2003		9,673,843		$	350.0
General Partner:
Beginning balance at December 31, 2002		—		18.8
Net income allocation		—		9.6
Allocation of net proceeds from unit issuance		—		(0.2		)
General Partner contribution		—		3.9
Distributions to partners		—		(9.5		)
Ending balance at June 30, 2003		—		$	22.6
Accumulated other comprehensive loss:
Beginning balance at December 31, 2002		—		(16.3		)
Unrealized loss on derivative financial instruments		—		(63.6		)
Change from current period hedge transactions ineffectiveness		—		0.5
Ending balance at June 30, 2003		—		$	(79.4	)
Total Partners’ Capital at June 30, 2003				$	1,078.3

 

The accompanying notes to the Consolidated Financial Statements are an integral part of this statement.

 

6

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

 

1.              Basis of Presentation

 

The accompanying unaudited interim consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America for interim consolidated financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X.  Accordingly, they do not include all the information and footnotes required by accounting principles generally accepted in the United States of America for complete consolidated financial statements. In the opinion of management, they contain all adjustments, consisting only of normal recurring adjustments, which management considers necessary to present fairly the financial position as at June 30, 2003 and December 31, 2002; the results of operations for the three and six month periods ended June 30, 2003 and 2002; and cash flows for the six month periods ended June 30, 2003 and 2002.  The results of operations for the three and six month periods ended June 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 Enbridge Energy Partners, L.P.’s (the “Partnership”) consolidated financial statements and notes thereto 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 Enbridge Energy Company, Inc.’s (the “General Partner”) allocation, by the weighted average number of Class A and Class B Common Units and i-units outstanding.  The General Partner’s allocation is equal to an amount based upon its general partner interest, adjusted to reflect an amount equal to incentive distributions and an amount required to reflect depreciation on the General Partner’s historical cost basis for assets contributed on formation of the Partnership.  Net income per unit was determined as follows:

 

		Three months ended June 30,						Six months ended June 30,
(in millions; except per unit amounts)		2003			2002			2003			2002
Net income		$	23.3		$	16.8		$	55.9		$	34.5
Net income allocated to General Partner		(0.4		)	(0.2		)	(1.1		)	(0.4		)
Incentive distributions and historical cost depreciation adjustments		(4.3		)	(2.8		)	(8.5		)	(5.8		)
		(4.7		)	(3.0		)	(9.6		)	(6.2		)
Net income allocable to Common Units and i-units		$	18.6		$	13.8		$	46.3		$	28.3
Weighted average units outstanding		46.8			35.2			45.7			34.4
Net income per unit		$	0.39		$	0.39		$	1.01		$	0.82

 

3.              Distributions

 

On July 23, 2003, the Partnership’s Board of Directors declared a distribution payable on August 14, 2003, to unitholders of record as of July 31, 2003, of its available cash of $50.3 million or $0.925 per common unit, including $8.9 million relating to the i-units that will be retained by the Partnership for use in its business.

 

On April 24, 2003, the Partnership’s Board of Directors declared a distribution payable on May 15, 2003, to unitholders of record as of April 30, 2003, of its available cash of $46.1 million or $0.925 per common unit, including $8.7 million relating to the i-units that was retained by the Partnership for its use in its business.

 

On January 23, 2003, the Partnership’s Board of Directors declared a distribution payable on February 14, 2003, to unitholders of record as of January 31, 2003, of its available cash of $45.9 million or $0.925 per common unit, including $8.5 million relating to the i-units that was retained by the Partnership for its use in its business.

 

7

 

4.              Equity Unit Issuance

 

On May 12, 2003, the Partnership issued 3.35 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 $143.4 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.  On May 15, 2003, the Partnership issued an additional 502,500 Class A Common Units to the underwriters pursuant to the exercise of the over-allotment option, resulting in additional proceeds to the Partnership, net of underwriters’ fees and discounts, commissions and issuance expenses, of approximately $21.3 million.  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.              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 filed a Form S-4 with the Securities and Exchange Commission (the “SEC”) to register 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 other changes under the new 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 amended and restated terms of 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 June 30, 2003, $80.0 million and $200.0 million were outstanding under the 364-day and three-year facilities, respectively.

 

6.              Derivative Instruments and Hedging Activities

 

In May 2003 prior to the issuance of the Notes, the Partnership entered into 10 year and 30 year treasury lock agreements (the “agreements”) to hedge the fluctuations in the U.S. Treasury bond interest rates between the execution date of the swaps and the issuance date of the fixed rate debt.  The agreements were designated as cash flow hedges of future interest expense.  Upon issuance of the Notes, the agreements were terminated and their aggregate mark to market value of $6.1 million was paid and recorded in accumulated other comprehensive income and is being amortized to interest expense over the term of the Notes.

 

In May 2003, the Partnership entered into a treasury lock contract, maturing on October 1, 2003, for the purpose of locking in the U.S. Treasury bond interest rate on anticipated debt offerings.  As of June 30, 2003, the lock totaled $0.3 million and is deemed fully effective.  All changes to the market value of the derivative instrument have been 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 quarter 2003, the Partnership recorded $0.5 million in cost of natural gas expense to reflect the ineffective portion of certain hedge transactions.

 

8

 

7.              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 six months ended June 30, 2003 was $46.2 million.  Depreciation expense was $6.1 million lower than it would have been had the Partnership used previous depreciation rates, which was offset by $3.0 million additional depreciation incurred on facilities placed into service during the fourth quarter 2002.  The annual composite rate changed from 3.9% to 3.22%.

 

8.              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 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 tables present certain financial information relating to the Partnership’s business segments.

 

		As of and for the Three Months Ended June 30, 2003
		Liquids Transportation			Gathering and Processing			Natural Gas Transportation			Marketing			Corporate			Total
Operating revenues		$	81.8		$	441.7		$	35.0		$	196.8		$	—		$	755.3
Cost of natural gas		—			405.6			23.3			194.5			—			623.4
Operating and administrative		26.9			19.1			5.3			0.4			0.6			52.3
Power		13.0			—			—			—			—			13.0
Depreciation and amortization		14.5			5.5			3.4			0.1			—			23.5
Operating income		27.4			11.5			3.0			1.8			(0.6		)	43.1
Interest and other income		—			—			—			—			1.8			1.8
Interest expense		—			—			—			—			(21.6		)	(21.6		)
Net income		$	27.4		$	11.5		$	3.0		$	1.8		$	(20.4	)	$	23.3
Total assets		$	1,498.5		$	746.5		$	417.8		$	225.0		$	54.6		$	2,942.4
Goodwill		$	—		$	146.1		$	72.9		$	20.3		$	—		$	239.3
Capital expenditures (excluding acquisitions)		$	15.1		$	10.1		$	1.1		$	0.1		$	0.9		$	27.3

 

9

 

		As of and for the Three Months Ended June 30, 2002
		Liquids Transportation			Gathering and Processing			Natural Gas Transportation			Marketing			Corporate			Total
Operating revenues		$	81.0		$	142.1		$	—		$	—		$	—		$	223.1
Cost of natural gas		—			130.8			—			—			—			130.8
Operating and administrative		24.1			5.6			—			—			1.2			30.9
Power		12.4			—			—			—						12.4
Depreciation and amortization		16.1			2.5			—			—			—			18.6
Operating income		28.4			3.2			—			—			(1.2		)	30.4
Interest and other income		—			—			—			—			0.1			0.1
Interest expense		—			—			—			—			(13.5		)	(13.5		)
Minority interest		—			—			—			—			(0.2		)	(0.2		)
Net income		$	28.4		$	3.2		$	—		$	—		$	(14.8	)	$	16.8
Total assets		$	1,451.9		$	286.5		$	—		$	—		$	2.2		$	1,740.6
Goodwill		$	—		$	15.0		$	—		$	—		$	—		$	15.0
Capital expenditures (excluding acquisitions)		$	70.2		$	2.4		$	—		$	—		$	—		$	72.6

 

		As of and for the Six Months Ended June 30, 2003
		Liquids Transportation			Gathering and Processing			Natural Gas Transportation			Marketing			Corporate			Total
Operating revenues		$	167.2		$	944.0		$	64.5		$	475.7		$	—		$	1,651.4
Cost of natural gas		—			870.6			38.7			467.6			—			1,376.9
Operating and administrative		53.3			38.1			11.0			0.8			1.7			104.9
Power		25.7			—			—			—			—			25.7
Depreciation and amortization		28.9			11.1			6.8			0.1			—			46.9
Operating income		59.3			24.2			8.0			7.2			(1.7		)	97.0
Interest and other income		—			—			—			—			1.8			1.8
Interest expense		—			—			—			—			(42.9		)	(42.9		)
Net income		$	59.3		$	24.2		$	8.0		$	7.2		$	(42.8	)	$	55.9
Total assets		$	1,498.5		$	746.5		$	417.8		$	225.0		$	54.6		$	2,942.4
Goodwill		$	—		$	146.1		$	72.9		$	20.3		$	—		$	239.3
Capital expenditures (excluding acquisitions)		$	20.0		$	21.3		$	2.4		$	0.1		$	1.8		$	45.6

 

		As of and for the Six Months Ended June 30, 2002
		Liquids Transportation			Gathering and Processing			Natural Gas Transportation			Marketing			Corporate			Total
Operating revenues		$	163.6		$	241.3		$	—		$	—		$	—		$	404.9
Cost of natural gas		—			220.4			—			—			—			220.4
Operating and administrative		46.7			10.6			—			—			1.4			58.7
Power		26.0			—			—			—			—			26.0
Depreciation and amortization		32.0			4.9			—			—			—			36.9
Operating income		58.9			5.4			—			—			(1.4		)	62.9
Interest and other income		—			—			—			—			0.2			0.2
Interest expense		—			—			—			—			(28.2		)	(28.2		)
Minority interest		—			—			—			—			(0.4		)	(0.4		)
Net income		$	58.9		$	5.4		$	—		$	—		$	(29.8	)	$	34.5
Total assets		$	1,451.9		$	286.5		$	—		$	—		$	2.2		$	1,740.6
Goodwill		$	—		$	15.0		$	—		$	—		$	—		$	15.0
Capital expenditures (excluding acquisitions)		$	96.8		$	5.8		$	—		$	—		$	—		$	102.6

 

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9.              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.

 

10.   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.

 

11.   Subsequent Event

 

In 1998, when the Kansas Pipeline system (“KPC”) became subject to the FERC jurisdiction, 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.  The Partnership is currently considering its options, including filing for rehearing of the Court’s August 12, 2003 Order.  There are other actions and administrative proceedings that may be undertaken in connection with the Court’s determination.  The outcome of 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 may be material to the earnings of the Partnership.

 

 

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

 

Results of Operations - Overview

 

Net income for the second quarter of 2003 improved 39% to $23.3 million compared with $16.8 million for the second quarter of 2002.  Net income for the six months ended June 30, 2003 improved 62% to $55.9 million compared with $34.5 million for the six months ended June 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 second quarter of 2003 was $0.39 per unit, unchanged from the second quarter of 2002.  Earnings per unit for the six months ended June 30, 2003 was $1.01 per unit compared with $0.82 per unit for the six months ended June 30, 2002.  Earnings per unit was higher for the six months ended June 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 second quarter of 2002 to 46.8 million in the second quarter of 2003.  On a half year basis, it increased from 34.4 million in the first six months of 2002 to 45.7 million in the first six months of 2003.

 

The following table reflects operating income by business segment and corporate charges for each of the three and six-month periods ended June 30, 2003 and 2002.

 

 

Results of Operations – by Segment

 

Liquids Transportation

 

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

 

Operating income.  Operating income decreased for the three months ended June 30, 2003 by approximately $1.0 million to $27.4 million as compared with $28.4 million for the three months ended June 30, 2002.  Operating income was lower in 2003 primarily due to slightly higher operating and administrative expenses primarily related to costs associated with pipeline leaks on the Lakehead system that occurred subsequent to June 30, 2002.

 

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Operating revenue.  Operating revenue for the second quarter of 2003 was $81.8 million compared with $81.0 million in 2002.  Operating revenue was higher in 2003 compared to 2002, as slightly lower deliveries on the Lakehead system were more than offset by higher tariffs.  Tariffs were higher due to the positive Federal Energy Regulatory Commission (“FERC”) indexed-tariff adjustment effective July 1, 2002, and an increase in the SEP II tariff effective May 1, 2003.  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 1.294 million barrels per day (“bpd”) for the second quarter of 2003 compared with 1.310 million bpd in the second quarter of 2002.  Deliveries were lower than expected due to customer start-up problems at the new Alberta oil sands projects, as well as the continuing maintenance problems at two of the existing oil sands operations in northern Alberta.  Contingent upon these crude oil supply problems lessening, the Partnership anticipates that deliveries will improve over the second half of 2003 to average between 1.34 and 1.40 million bpd on a full-year basis.  Deliveries on the North Dakota System averaged approximately 64.5 thousand bpd on the trunkline and approximately 8.2 thousand bpd on the gathering system for the second quarter of 2003.  This compares with approximately 56.2 thousand bpd on the trunkline and approximately 8.7 thousand bpd on the gathering system for the second quarter of 2002.

 

Operating and administrative expenses.  Operating and administrative expenses were $26.9 million for the second quarter of 2003 compared with $24.1 million in the second quarter of 2002.  Operating and administrative expenses were higher in 2003, primarily due to costs related to recent leaks on the Lakehead system of approximately $1.0 million and higher post-retirement benefits and pension costs.

 

Depreciation expense.  Depreciation expense was $14.5 million for the second quarter of 2003 compared with $16.1 million in the second quarter of 2002.  The decrease was primarily due to revised depreciation rates, offset by an increase in depreciation expense associated with additional facilities placed into service during the fourth quarter 2002.  The revised depreciation rates on the Lakehead System 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 June 30, 2003, was $3.0 million lower than it would have been using previous depreciation rates.

 

Six months ended June 30, 2003 compared with six months ended June 30, 2002

 

Operating income.  Operating income increased for the six months ended June 30, 2003 by approximately $0.4 million to $59.3 million as compared with $58.9 million for the six months ended June 30, 2002.  Operating income was higher in 2003 primarily due to higher revenues and lower depreciation, partially offset by higher operating expenses.

 

Operating revenue.  Operating revenue for the first six months of 2003 was $167.2 million compared with $163.6 million in 2002 for the same reasons as noted above in the three-month analysis.

 

Deliveries.  Deliveries on the Lakehead System averaged 1.310 million bpd for the six months ended June 30, 2003 compared with 1.312 million bpd in 2002.  For the six-month period ending June 30, 2003, deliveries were lower than last year for the same reasons as noted above in the three-month analysis.  Deliveries on the North Dakota System averaged approximately 68.5 thousand bpd on the trunkline and approximately 7.9 thousand bpd on the gathering system for the period ended June 30, 2003.  This compares with approximately 56.8 thousand bpd on the trunkline and approximately 8.6 thousand bpd on the gathering system for the same period in 2002.

 

Operating and administrative expenses.  Operating and administrative expenses were $53.3 million for the six months ended June 30, 2003, compared with $46.7 million in the second 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 recent leaks on the Lakehead System of $4.7 million (net of expected insurance recoveries of $1.7 million) and higher post-retirement benefits and pension costs.

 

Depreciation expense.  Depreciation expense was $28.9 million for the six months ended June 30, 2003 compared with $32.0 million in 2002.  The decrease of $3.1 million was due to revised depreciation rates on the Lakehead system, offset by additional depreciation expense incurred on facilities placed into service during the fourth quarter 2002.    Depreciation expense for the six months ended June 30, 2003, was $6.1 million lower than it would have been using previous depreciation rates.

 

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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.

 

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 three and six months ended June 30, 2003 and 2002, in million British thermal units per day (“Mmbtu/d”).

 

 

East Texas System.  Operating income for the second quarter of 2003 of $2.9 million was slightly lower by $0.3 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 $6.8 million for the six months ended 2003 compared with $5.4 million for the same period ended June 30, 2002.  The increase of $1.4 million was primarily due to higher volumes and the absence of expenses related to a treating plant maintenance shutdown that occurred during the first half of 2002.  Volume on the East Texas System increased from 390 Mmbtu/d during the six months ended June 30, 2002 to 436 Mmbtu/d during the six months ended June 30, 2003.  This increase in volume is due to higher natural gas production and new drilling by producers in the East Texas area.

 

Other Gathering and Processing systems.  Operating income related to processing on the Anadarko system was negatively impacted by high natural gas prices during the second quarter of 2003.  Volumes on the Northeast Texas system continued to be stable during the second quarter of 2003 due to recent supply additions.  Expectations are for stable supply on the Northeast Texas system during the last half of 2003.

 

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.  Total processing margin is expected to account for approximately 15% of the total operating income for this segment during the full year of 2003. The remaining operating income associated with this segment is derived from fixed fee, percentage-of-index contract structures, and trucking operations.

 

During the first six months of 2003, historically high natural gas prices made keep-whole processing contracts non-economic for the gathering and processing segment and resulted in a negative processing margin of approximately $2.0 million.  First of the month natural gas prices fluctuated between $4.96 and $9.11 per Mmbtu resulting in an average price of approximately $6 per Mmbtu during the six months ended June 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 entire second half of 2003, processing margins could be negative approximately $4.0 million for the last six 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.

 

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.

 

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Natural Gas Transportation systems contributed $3.0 million to operating income for the three months and $8.0 million for the six months ended June 30, 2003.  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 rates and pipeline reserve capacities, 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 six-month periods ended June 30, 2003.

 

 

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.

 

Operating income for the Marketing segment was $1.8 million for the three months and $7.2 million for the six months ended June 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 six months ended June 30, 2003, also include the positive impact of gains 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

 

Interest and other income (expense) was $1.8 million for both the three and six-month periods ending June 30, 2003, compared with $0.1 million for the three months and $0.2 million for the six months ended June 30, 2002.  The balance for 2003 is largely explained by non-recurring gains related to settlements of previously disputed amounts associated with certain assets purchased in the Midcoast acquisition in October 2002.

 

Interest expense was $21.6 million for the three months ended June 30, 2003, compared with $13.5 million for the same period in 2002.  Interest expense was $42.9 million for the six months ended June 30, 2003, compared with $28.2 million for the same period in 2002.  The increase in both periods is due to higher debt balances in 2003 compared to 2002, partially offset by lower 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 businesses.  Short-term

 

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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 $46.6 million to ($107.7) million at June 30, 2003, compared with ($61.1) million at December 31, 2002, primarily due to the net increase in current maturities and short-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 June 30, 2003, cash and cash equivalents totaled $74.2 million, compared with $60.3 million at December 31, 2002.  Of this $74.2 million, $50.3 million ($0.925 per unit) will be used for the distribution payable August 14, 2003, including $8.9 million relating to the i-units, which will be retained by the Partnership for use in its business.  The remaining $23.9 million is available for future cash distributions, capital expenditures or other business needs.

 

Cash flow from operating activities for the six months ended June 30, 2003 was $75.6 million compared with $81.0 million for the same period last year.  The decrease of $5.4 million is primarily due to changes in accounts payable and accounts receivable, which was partially offset by an increase in net income and accrued gas purchases.  The nature of the Partnership's operating activities are different in the period ending June 30, 2003 compared with the same period in 2002, due to the acquisition of the Midcoast natural gas assets in October 2002. The price of natural gas can impact the variability of the accounts payable, accrued gas purchases and accounts receivable balances related to the Partnership’s natural gas business.  Cash from operating activities for the six months ended June 30, 2003 was also negatively impacted by a $6.1 million payment made upon termination of derivative transactions related to an interest rate hedge that was put into place for the May 2003 debt issuance.

 

Cash flow used in investing activities during the six months ended June 30, 2003 was $51.4 million, compared with $103.7 million for the same period in 2002.  The decrease of $52.3 million is primarily due to a decrease in additions to property, plant and equipment associated with the Terrace Phase III expansion during 2003 as compared to 2002.  The majority of the construction activity related to the Terrace Phase III expansion occurred during 2002.

 

Cash flow used in financing activities during the six months ended June 30, 2003 was ($10.3) million, compared with cash flow provided by financing activities of $36.4 million for the same period in 2002.  The decrease in cash flow is primarily due to the changes in debt, which include the repayments of loans from the general partner of $316.0 million and other debt repayments of $184.0 million for credit facilities, as compared to additional net borrowings of $130.0 million in 2002.  This was partially offset by the issuance of senior unsecured Notes of $396.3 million and Class A common unit issuances in May 2003 of $168.2 million, compared to only $93.2 million in Class A common unit issuances during the first six months of 2002.

 

On May 12, 2003, the Partnership issued 3.35 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 $143.4 million.  Proceeds from this offering were used to reduce external borrowings on the Partnership’s credit facility and an affiliate loan from Enbridge (U.S.) Inc.  On May 15, 2003, the Partnership issued an additional 502,500 Class A Common Units to the underwriters in the above offering upon exercise of their over-allotment option, resulting in additional proceeds to the Partnership, net of underwriters’ fees and discounts, commissions and issuance expenses, of approximately $21.3 million.  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 filed a Form S-4 with the Securities and Exchange Commission (the “SEC”) to register offers to exchange the unregistered Notes for publicly registered Notes.

 

On June 30, 2003, the Partnership filed 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

 

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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.

 

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’s, a wholly-owned subsidiary of the Partnership, from A3 to Baa1.

 

The Partnership anticipates spending approximately $84 million for pipeline system enhancements, $27 million for core maintenance and $51 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 estimates noted in this paragraph.

 

General Matters

 

In 1998, when the Kansas Pipeline system (“KPC”) became subject to the FERC jurisdiction, 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.  The Partnership is currently considering its options, including filing for rehearing of the Court’s August 12, 2003 Order.  There are other actions and administrative proceedings that may be undertaken in connection with the Court’s determination.  The outcome of 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 may be material to the earnings of the Partnership.

 

UTOS Pipeline (“UTOS”) filed a rate case pursuant to Section 4 of the Natural Gas Act (“NGA”) on March 31, 2003 in FERC Docket No. RP03-335-000.  The rates proposed by UTOS would result in an increase in revenue of approximately $1 million when compared to its currently effective rates.  On April 30, 2003, the FERC accepted and suspended the proposed increase until the earlier of October 1, 2003 or on the date the FERC specifies in any future order issued in this proceeding.  On May 30, 2003, UTOS filed an offer settlement, which would resolve all issues in this case and would result in the continued use of UTOS’ current rates for three years.  An order approving the proposed settlement was received on July 23, 2003.

 

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.  The Partnership understands that Williams intends to pursue an alternative transaction with the Partnership or other buyers under a structure that is responsive to the FERC order.

 

Effective July 1, 2003, in compliance with the indexed rate ceilings allowed by the FERC, the Partnership decreased its rates for transportation on the Lakehead and North Dakota Systems by an average of approximately 1.3%.  The Partnership anticipates that the decrease in tariff rates will not have a material impact on the Partnership’s financial condition and results of operations.

 

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 $280.0 million of the Partnership’s total outstanding debt carries a floating interest rate.  Of the $280.0 million, $240.0 million has been hedged with interest rate swaps effective through November 3, 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 NGLs it transports.  However, the Partnership has commodity risk related to degradation losses associated with the fluctuating differentials between the price

 

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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 our 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 counterparties.

 

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

 

A settlement became final on July 7, 2003 with Kansas Gas Services (KGS), Kansas Corporation Commission and the Partnership; therefore the Partnership will invoice KGS retroactively for the settlement rates from November 1, 2002 in August 2003.  The settlement is not expected to have a material impact on the results of the Partnership.

 

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.

 

 

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b)            Reports on Form 8-K

 

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

 

A report on Form 8-K was filed on June 20, 2003 to provide additional historical financial information related to Enbridge Midcoast Energy, Inc. and additional pro forma financial information related to the acquisition of Assets as described in the Partnership’s Form 8-K filed on October 31, 2002.

 

A report on Form 8-K was filed on May 29, 2003 attaching a press release dated May 20, 2003 announcing a private offering of $200.0 million principal amount of 4.75% Notes due 2013 and $200.0 principal amount of 5.95% Notes due 2033.

 

A report on Form 8-K was filed on May 8, 2003 announcing that on May 6, 2003 the Partnership entered into an Underwriting Agreement relating to the offering of up to 3,852,500 Class A Common Units representing limited partner interests in the Partnership, including an over-allotment option to purchase 502,500 Class A Common Units.

 

A report on Form 8-K was filed on May 5, 2003 that contains the Consolidated Statements of Financial Position of Enbridge Energy Company, Inc., at December 31, 2002 and December 31, 2001.  Enbridge Energy Company, Inc., is the General Partner of the Partnership.

 

A report on Form 8-K was filed on May 5, 2003 to file a preliminary prospectus supplement and accompanying prospectus for the offering of 2,750,000 Class A Common Units.  The prospectus supplement also relates to an option granted by the Partnership to the underwriters to purchase an additional 412,500 Class A Common Units to cover any over-allotments.

 

A report on Form 8-K was filed on April 24, 2003 attaching a press release dated April 24, 2003 regarding the financial results for the three months ended March 31, 2003.

 

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SIGNATURE

 

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

 

 

	ENBRIDGE ENERGY PARTNERS, L.P.
		(Registrant)
	By:		Enbridge Energy Management, L.L.C.
			as delegate of
			Enbridge Energy Company, Inc.
			as General Partner
				/s/ Mark A. Maki
					Mark A. Maki
					Vice President, Finance
					(Duly Authorized Officer)
						Date:  August 14, 2003

 

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