Edgar Filing: ENBRIDGE ENERGY PARTNERS LP

QuickLinks -- Click here to rapidly navigate through this document

SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 8-K

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

DATE OF REPORT (DATE OF EARLIEST EVENT REPORTED): October 17, 2002

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

Delaware (State or other jurisdiction of incorporation or organization)		1-10934 (Commission File Number)		39-1715850 (I.R.S. Employer Identification No.)
1100 Louisiana, Suite 3300 Houston, Texas (Address of principal executive offices)				(Zip code) 77002

Registrant's telephone number, including area code: (713) 650-8900

Item 2. Acquisition or Disposition of Assets.

On October 17, 2002, Enbridge Energy Partners, L.P. ("Enbridge Partners") acquired from Enbridge Energy Company, Inc. ("Enbridge Energy Company"), certain natural gas transportation, gathering and processing assets (the "Assets"). The Assets acquired include the following:

•: Midcoast System—approximately 4,000 miles of natural gas gathering and transmission pipelines with an aggregate throughput capacity of approximately four billion cubic feet per day, and natural gas treating and processing assets in the Mid-Continent and Gulf Coast regions of the United States.
•: Northeast Texas System—approximately 1,200 miles of natural gas gathering pipelines, five natural gas treating plants, all of which are currently active, and four natural gas processing plants, three of which are currently active.
•: South Texas System—approximately 175 miles of natural gas gathering pipelines, a hydrogen sulfide treating plant and an inactive natural gas processing plant. This system also interconnects with a 500-mile natural gas transmission pipeline system that Enbridge Partners has the right to acquire for $41 million.

Enbridge Partners intends to continue to use the Assets in the same business that Enbridge Energy Company conducted prior to the acquisition of the Assets by Enbridge Partners.

Enbridge Energy Company is the general partner of Enbridge Partners and owns a 2% general partner interest in Enbridge Partners and 3,912,750 Class B Common Units, which represent an approximate 8.7% limited partner interest in Enbridge Partners. The consideration received by Enbridge Energy Company for the Assets was $820 million, not including the effect of certain customary closing adjustments. Enbridge Partners funded this consideration through the assumption of $805 million in debt related to the Assets, the issuance to Enbridge Energy Company of an additional $8.5 million equity interest in Enbridge Partners and the payment to Enbridge Energy Company of $6.5 million in cash. The cash portion of the consideration was funded by Enbridge Partners with borrowings under its 365-day revolving credit facility as to which Bank of America, N.A. serves as syndication agent.

The purchase price and the other terms of the acquisition were determined through negotiations between representatives of Enbridge Energy Company, acting on its own behalf, and a committee of independent members of the board of directors of Enbridge Energy Company, acting on behalf of Enbridge Partners. The committee, which was represented by its own legal and financial advisors, recommended that the board of directors of Enbridge Energy Company approve the acquisition on behalf of Enbridge Partners.

The Assets were acquired by Enbridge Partners through the contribution to Enbridge Partners of Enbridge Midcoast Energy, Inc. by Enbridge Energy Company.

Item 7. Financial Statements and Exhibits.

(a): Financial Statements of Business Acquired

The financial statements of Enbridge Midcoast Energy, Inc. set forth under the caption "Index to Financial Statements—Historical Financial Statements of Enbridge Midcoast Energy, Inc." beginning on page F-1 hereto are filed with this Current Report on Form 8-K and are hereby incorporated herein by reference.

(b): Pro Forma Financial Information

The pro forma financial statements appearing under the caption "Index to Financial Statements—Pro Forma Financial Statements (Unaudited) of Enbridge Energy Partners, L.P." beginning on page F-1 hereto are filed with this Current Report on Form 8-K and are hereby incorporated herein by reference.

(c): Exhibits

The documents listed on the Exhibit Index following the financial statements that are attached hereto are filed with this Current Report on Form 8-K and are hereby incorporated herein by reference.

SIGNATURES

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

		ENBRIDGE ENERGY PARTNERS, L.P. (REGISTRANT)
		By:	Enbridge Energy Management, L.L.C., as delegee of Enbridge Energy Company, Inc., its General Partner
			/s/ JODY L. BALKO Jody L. Balko Controller

Dated: October 31, 2002

INDEX TO FINANCIAL STATEMENTS

HISTORICAL FINANCIAL STATEMENTS OF ENBRIDGE MIDCOAST ENERGY, INC.

Consolidated Statement of Income for the Four Months Ended April 30, 2001, the Two Months Ended June 30, 2001 and the Six Months Ended June 30, 2002		F-2
Consolidated Statement of Cash Flows for the Four Months Ended April 30, 2001, the Two Months Ended June 30, 2001 and the Six Months Ended June 30, 2002		F-3
Consolidated Statement of Financial Position as at December 31, 2001 and June 30, 2002		F-4
Notes to the Consolidated Financial Statements		F-5
Report of Independent Accountants		F-7
Report of Independent Accountants		F-8
Consolidated Balance Sheets as at December 31, 2000 and 2001		F-9
Consolidated Statements of Operations for the years ended December 31, 1999 and 2000, the Four Months Ended April 30, 2001 and the Eight Months Ended December 31, 2001		F-10
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 1999 and 2000, the Four Months Ended April 30, 2001 and the Eight Months Ended December 31, 2001		F-11
Consolidated Statements of Shareholders' Equity for the Years Ended December 31, 1999 and 2000, the Four Months Ended April 30, 2001 and the Eight Months Ended December 31, 2001		F-12
Consolidated Statements of Cash Flows for the Years Ended December 31, 1999 and 2000, the Four Months Ended April 30, 2001 and the Eight Months Ended December 31, 2001		F-13
Notes to Consolidated Financial Statements		F-14
PRO FORMA FINANCIAL STATEMENTS (Unaudited) OF ENBRIDGE ENERGY PARTNERS, L.P.
Introduction		F-34
Unaudited Pro Forma Consolidated Statement of Income for the Year Ended December 31, 2001		F-36
Unaudited Pro Forma Consolidated Statement of Income for the Six Months Ended June 30, 2001		F-37
Unaudited Pro Forma Consolidated Statement of Income for the Six Months Ended June 30, 2002		F-38
Unaudited Pro Forma Consolidated Statement of Financial Position as at June 30, 2002		F-39
Notes to Unaudited Pro Forma Consolidated Financial Statements		F-40

F-1

ENBRIDGE MIDCOAST ENERGY, INC.

(an indirectly owned subsidiary of Enbridge Inc.)

CONSOLIDATED STATEMENT OF INCOME

		Four Months ended April 30, 2001			Two Months ended June 30, 2001			Six Months ended June 30, 2002
		(Predecessor) (audited)			(unaudited, in millions)
Operating revenue
	Energy marketing	$	374.8		$	60.5		$	209.1
	Transportation		18.2			15.0			43.5
	Processing		12.7			55.7			226.6
	Other		1.3			—			—

			407.0			131.2			479.2

Expenses
	Cost of natural gas		390.9			110.8			412.4
	Operating and administrative		29.5			9.0			37.1
	Depreciation and amortization		5.7			4.2			11.3

			426.1			124.0			460.8

Operating income			(19.1	)		7.2			18.4
Interest and other income			0.6			(0.1	)		0.8
Interest expense			(9.4	)		(2.9	)		(11.3	)
Minority interest			(0.1	)		—			—

Income before income taxes			(28.0	)		4.2			7.9

Provision for income taxes
	Current		8.5			(0.8	)		5.0
	Deferred		0.9			(0.6	)		(8.0	)

			9.4			(1.4	)		(3.0	)
Income before cumulative effect of change in accounting principle		$	(18.6	)	$	2.8		$	4.9

Cumulative effect of change in accounting principle, net of income tax provision of $0.5			(0.9	)		—			—

Net Income (loss)		$	(19.5	)	$	2.8		$	4.9

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

F-2

ENBRIDGE MIDCOAST ENERGY, INC.

(an indirectly owned subsidiary of Enbridge Inc.)

CONSOLIDATED STATEMENT OF CASH FLOWS

			Four Months ended April 30, 2001			Two Months ended June 30, 2001			Six Months ended June 30, 2002
			(Predecessor) (audited)			(unaudited, in millions)
Cash provided from operating activities
	Net income		$	(19.5	)	$	2.8		$	4.9
	Adjustments to reconcile net income to cash
	provided from operating activities:
		Depreciation and amortization		5.7			4.2			11.3
		Deferred income taxes		1.3			0.6			8.1
		Other		(0.2	)		(0.3	)		(3.1	)
		Changes in operating assets and liabilities		12.2			(9.5	)		(5.4	)

				(0.5	)		(2.2	)		15.8

Investing activities
	Acquisitions (Note 2)			—			—			(208.1	)
	Capital expenditures			(10.8	)		(4.4	)		(37.4	)
	Proceeds from sale (Note 3)			—			—			5.9
	Other			(0.6	)		—			1.7

				(11.4	)		(4.4	)		(237.9	)

Financing activities
	Bank debt, net			7.2			3.2			—
	Due to affiliates			—			7.0			221.7
	Other			2.4			—			(0.2	)

				9.6			10.2			221.5

Increase (decrease) in cash and cash equivalents				(2.3	)		3.6			(0.6	)
Cash and cash equivalents at beginning of period				4.6			2.4			1.9

Cash and cash equivalents at end of period			$	2.3		$	6.0		$	1.3

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

F-3

ENBRIDGE MIDCOAST ENERGY, INC.

(an indirectly owned subsidiary of Enbridge Inc.)

CONSOLIDATED STATEMENT OF FINANCIAL POSITION

		December 31, 2001			June 30, 2002
		(audited)			(unaudited)
		(in millions)
ASSETS
Current assets
	Cash and cash equivalents	$	1.9		$	1.3
	Accounts receivable, net of allowance of $4.4		69.6			127.8
	Other current assets		17.1			7.2

			88.6			136.3
Other non-current assets			217.0			256.0
Property, plant and equipment, net			482.1			682.1

		$	787.7		$	1,074.4

LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
	Accounts payable and other liabilities	$	77.9		$	88.9
	Due to affiliates		2.2			30.2

			80.1			119.1
Due to affiliates			319.2			540.9
Other liabilities			7.9			30.3
Deferred income taxes			16.7			20.4
Minority interest			0.5			0.4

			424.4			711.1
Shareholder's equity:
	Paid-in-capital		368.0			368.9
	Retained earnings		3.1			8.0
	Accumulated other comprehensive loss		(7.8	)		(13.6	)

			363.3			363.3

		$	787.7		$	1,074.4

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

F-4

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

(in millions; except per unit amounts)

1.: Basis of Presentation

The accompanying unaudited consolidated financial statements have been prepared in accordance with United States generally accepted accounting principles for interim financial information. Accordingly, they do not include all the information and footnotes required by generally accepted accounting principles for complete financial statements. In the opinion of management, they contain all adjustments, consisting only of normal recurring adjustments, which management considers necessary to present fairly the financial position as at June 30, 2001 and June 30, 2002; the results of operations for the two month period ended June 30, 2001 and the six month period ended June 30, 2002; and cash flows for the four month period ended April 30, 2001, the two month period ended June 30, 2001 and the six month period ended June 30, 2002. The results of operations for the four months ended April 30, 2001, the two months ended June 30, 2001 and the six months ended June 30, 2002 should not be taken as indicative of the results to be expected for the full year. The interim financial statements should be read in conjunction with Enbridge Midcoast Energy, Inc.'s consolidated financial statements and notes thereto.

2.: Acquisitions

In the first half of 2002, the Company acquired natural gas transportation, gathering and processing facilities in Texas for cash consideration of $208.1 million. The facilities are complementary to Enbridge Midcoast's assets. The results of operations have been included in the consolidated financial statements from the respective date of acquisition. Assets acquired during the first half of 2002 were: the Northeast Texas assets for $180.6 million, the South Texas assets for $9.0 million, Hobart Ranch for $5.9 million, and compression assets for $12.6 million, as summarized below.

Fair value of assets acquired:
	Property, plant and equipment	$	179.6
	Goodwill		37.0
	Working capital deficiency		(8.5	)

		$	208.1

The acquisitions were funded with loans from affiliated companies.

3.: Proceeds from Sale

In June 2002, the Company sold the Provost facilities located in Canada for net US$5.9 million. The sale was recorded in the financial statements as of June 30, 2002.

4.: Kansas Pipeline Company Rate and Regulatory Matters

Enbridge Midcoast Energy is involved in two disputes regarding the current tariff rates that it charges shippers on its Kansas pipeline system as well as a rate proceeding before the FERC to establish new tariff rates for that system.

Initial Rate Dispute. When the Kansas pipeline system became subject to FERC jurisdiction in 1998, 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 challenges, including an appeal of the FERC's decision to the District of Columbia Court of Appeals by the Missouri Public Service Commission on behalf of customers of the Kansas pipeline system. On remand from the District of Columbia Court of Appeals, the FERC affirmed the initial rates and then

F-5

subsequently denied requests for a rehearing of its order affirming the initial rates. The Missouri Public Service Commission and the Kansas Corporation Commission have recently appealed the FERC's decision to affirm the initial rates to the District of Columbia Court of Appeals.

FERC Rate Proceeding. In 1999, Enbridge Midcoast Energy initiated a rate proceeding for the Kansas pipeline system. In September 2002, the FERC issued an order requiring that Enbridge Midcoast Energy charge rates for service on the Kansas pipeline system based on an annual cost of service of approximately $21 million. Enbridge Midcoast Energy has requested rehearing of the FERC's order.

Kansas Gas Service Dispute. Kansas Gas Service, a major customer of the Kansas pipeline system, has been paying only a portion of the amount it has been invoiced for service on the Kansas pipeline system based on its claim that it is contractually entitled to a lower tariff rate. Enbridge Midcoast Energy disputes this claim. The monthly amount of the underpayment averaged $890,000 per month during the six months ended June 30, 2002, and the total amount of the underpayments was approximately $12.5 million as of June 30, 2002. Because these receivables are not included in the assets being acquired by Enbridge Partners under the contribution agreement, Enbridge Inc. will retain the account receivable for the total amount of the underpayments as of the closing date of the acquisition of the Midcoast system by Enbridge Partners, and the amount of any underpayment by Kansas Gas Service after that date will be the responsibility of Enbridge Partners. This dispute is the subject of ongoing state and federal court proceedings as well as proceedings before the FERC, and it is likely that additional FERC and/or federal court proceedings will be instituted by Enbridge Midcoast Energy in the near future.

In a Kansas state court proceeding initiated by Kansas Gas Service, Kansas Gas Service claimed that it should be charged lower rates established under a 1997 settlement agreement instead of the higher initial rates approved by the FERC for service on the Kansas pipeline system. On October 15, 2001, the Kansas state trial judge granted Enbridge Partners' motion to dismiss Kansas Gas Service's claims, finding that, even if Kansas Gas Service prevailed in state court, the lower rate may still not apply because of the "filed rate doctrine," which generally requires that pipeline owners only charge rates on file with and approved by the FERC. Kansas Gas Service's appeal of the trial judge's dismissal is pending in a Kansas court of appeals. In an unrelated proceeding, the FERC issued an order on July 23, 2002 stating that, because certain agreements involving Kansas Gas Service were already on file with the FERC, charging the lower rate would not violate the "filed rate doctrine." Enbridge Midcoast Energy intends to appeal the FERC's order to a United States Court of Appeals having jurisdiction. In addition, Enbridge Midcoast Energy intends to file with the FERC to enforce the tariff rates currently in effect for the Kansas pipeline system.

F-6

Report of Independent Accountants

To the Shareholder and Board of Directors
of Enbridge Energy Company, Inc.:

In our opinion, the accompanying consolidated balance sheet and the related consolidated statements of operations, of comprehensive income, of shareholders' equity, and of cash flows present fairly, in all material respects, the financial position of Enbridge Midcoast Energy, Inc. and its subsidiaries (formerly known as Midcoast Energy Resources, Inc.) at December 31, 2001, and the results of their operations and their cash flows for the period from May 1, 2001 to December 31, 2001 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

PricewaterhouseCoopers LLP
Houston, Texas
May 15, 2002

F-7

Report of Independent Accountants

To the Shareholder and Board of Directors
of Enbridge Energy Company, Inc.:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of comprehensive income, of shareholders' equity, and of cash flows present fairly, in all material respects, the financial position of Midcoast Energy Resources, Inc. and its subsidiaries at December 31, 2000, and the results of their operations and their cash flows for the period from January 1, 2001 to April 30, 2001 and for each of the two years in the period ended December 31, 2000 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As discussed in Note 2 to the consolidated financial statements, the Company changed its method of accounting for derivative instruments and hedging activities effective January 1, 2001.

PricewaterhouseCoopers LLP
Houston, Texas
May 15, 2002

F-8

ENBRIDGE MIDCOAST ENERGY, INC.
(an indirectly owned subsidiary of Enbridge Inc.)

CONSOLIDATED BALANCE SHEETS

(In thousands, except share and per share data)

			December 31,
			2000			2001
			(Predecessor)
ASSETS
Current Assets
	Cash and cash equivalents		$	4,619		$	1,924
	Accounts and notes receivable, net of allowance of $1,096 and $4,434, respectively			144,649			69,599
	Inventory			7,730			17,158

		Total Current Assets		156,998			88,681

Property, Plant and Equipment, net (Note 4)				416,046			482,075
Other Assets (Note 5)				26,276			216,958

		Total Assets	$	599,320		$	787,714

LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
	Accounts payable and accrued liabilities		$	146,347		$	80,126
Long-term Debt (Note 6)				255,999			—
Other Liabilities				782			7,876
Due to Affiliates (Note 10)				—			319,200
Deferred Income Taxes (Note 13)				17,746			16,685
Commitments and Contingencies (Note 14)
Minority Interest in Consolidated Subsidiaries				595			451
Shareholders' Equity:
	Common stock, par value $.01 and $1,000 per share; authorized 31,250,000 and 1 shares; issued 12,738,109 and 1, respectively			127			1
	Paid-in capital			166,028			368,039
	Retained earnings			14,941			3,080
	Accumulated other comprehensive income			2			(7,744	)
	Treasury stock (at cost), 201,908 and 0 treasury shares, respectively			(3,247	)		—

		Total Shareholders' Equity		177,851			363,376

		Total Liabilities and Shareholders' Equity	$	599,320		$	787,714

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

F-9

ENBRIDGE MIDCOAST ENERGY, INC.
(an indirectly owned subsidiary of Enbridge Inc.)

CONSOLIDATED STATEMENTS OF OPERATIONS

(In thousands, except share and per share data)

				For the Years Ended December 31,						Four Months Ended April 30,			Eight Months Ended December 31,
				1999			2000			2001			2001
				(Predecessor)			(Predecessor)			(Predecessor)
Operating Revenues:
	Energy marketing revenue			$	346,956		$	690,935		$	374,805		$	380,387
	Transportation and gathering fees				26,657			59,407			18,175			33,615
	Natural gas processing and treating revenue				15,564			38,871			12,650			19,022
	Other.				2,394			3,133			1,323			5,450

		Total operating revenues			391,571			792,346			406,953			438,474

Operating Expenses:
	Energy marketing expenses				319,207			656,990			383,364			355,559
	Natural gas processing and treating costs				11,244			25,520			7,481			9,082
	Other operating expenses				21,556			30,737			11,614			22,422
	Depreciation and amortization				7,545			15,695			5,715			15,527
	General and administrative				6,708			13,975			16,439			11,854
	Taxes other than income				1,723			3,925			1,445			2,853
	Unusual charges				2,685			—			—			—

		Total operating expenses			370,668			746,842			426,058			417,297

		Operating income/(loss)			20,903			45,504			(19,105	)		21,177
Non-Operating Items:
	Interest expense				(6,533	)		(18,489	)		(9,431	)		(13,976	)
	Minority interest in consolidated subsidiaries				(43	)		(88	)		(55	)		(42	)
	Other income/(expense), net				(137	)		1,837			616			167

		Total non-operating items			(6,713	)		(16,740	)		(8,870	)		(13,851	)

Income/(loss) before income taxes and extraordinary item					14,190			28,764			(27,975	)		7,326
Provision for income taxes:
	Current				(1,833	)		(684	)		8,442			2,130
	Deferred				(336	)		(6,712	)		890			(6,376	)

Income/(loss) before extraordinary item and cumulative effect of change in accounting principle					12,021			21,368			(18,643	)		3,080
Extraordinary item, net of income tax provision of $300					(582	)		—			—			—
Cumulative effect of change in accounting principle, net of income tax provision of $457					—			—			(850	)		—

Net income/(loss)				$	11,439		$	21,368		$	(19,493	)	$	3,080

Earnings per common share:
	Basic
		Income/(loss) before extraordinary item and cumulative effect of change in accounting principle		$	1.31		$	1.71		$	(1.48	)
		Extraordinary item			(.06	)		—			—
		Cumulative effect of change in accounting principle									(0.07	)

			Net income/(loss)	$	1.25		$	1.71		$	(1.55	)

	Diluted
		Income/(loss) before extraordinary item and cumulative effect of change in accounting principle		$	1.28		$	1.68		$	(1.48	)
		Extraordinary item			(.06	)		—			—
		Cumulative effect of change in accounting principle			—						(0.07	)

			Net income/(loss)	$	1.22		$	1.68		$	(1.55	)

Weighted Average Number of Common Shares Outstanding:
		Basic			9,176,201			12,506,346			12,569,640

		Diluted			9,400,754			12,756,414			12,569,640

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

F-10

ENBRIDGE MIDCOAST ENERGY, INC.
(an indirectly owned subsidiary of Enbridge Inc.)

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In thousands)

		For the Years Ended December 31,					For the Four Months Ended April 30,			For the Eight Months Ended December 31,
		1999		2000			2001			2001
		(Predecessor)		(Predecessor)			(Predecessor)
Net income/(loss)		$	11,439	$	21,368		$	(19,493	)	$	3,080
Derivative financial instruments:
	Cumulative effect of transition adjustment, net of tax of $2,971		—		—			3,847			—
	Loss on fair value, net of tax recovery of $2,845 and $4,330, respectively		—		—			(4,735	)		(6,715	)
Foreign currency translation adjustment			71		(69	)		(26	)		(1,029	)

Comprehensive (loss)/income		$	11,510	$	21,299		$	(20,407	)	$	(4,664	)

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

F-11

ENBRDIGE MIDCOAST ENERGY INC.
(an indirectly owned subsidiary of Enbridge Inc.)

CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY

(In thousands)

	Common Stock											Accumulated Other Comprehensive Income			Treasury Stock
	Common Stock					Paid-in Capital			Retained Earnings (Deficit)						Treasury Stock					Total Shareholders' Equity
	Shares		Amounts			Paid-in Capital			Retained Earnings (Deficit)						Shares		Amounts			Total Shareholders' Equity
Balance, December 31, 1998 (predecessor)	7,150		$	71		$	80,955		$	(11,947	)	$	—		(181	)	$	(2,791	)	$	66,288
Net income	—			—			—			11,439			—		—			—			11,439
Stock options exercised	—			—			42			—			—		—			—			42
Sale of common stock	5,572			56			84,772			—			—		—			—			84,828
Treasury stock purchased	—			—			—			—			—		(144	)		(2,406	)		(2,406	)
Treasury stock issued in connection with acquisitions	—			—			195			—			—		164			2,627			2,822
Foreign currency translation adjustment	—			—			—			—			71		—			—			71
Common stock dividends, $0.27 per share	—			—			—			(2,407	)		—		—			—			(2,407	)

Balance, December 31, 1999 (predecessor)	12,722		$	127		$	165,964		$	(2,915	)	$	71		(161	)	$	(2,570	)	$	160,677

Net income	—			—			—			21,368			—		—			—			21,368
Stock options exercised	6			—			90			—			—		—			—			90
Warrants exercised	10			—			—			—			—		—			—			—
Treasury stock purchased	—			—			—			—			—		(101	)		(1,566	)		(1,566	)
Treasury stock issued in connection with acquisitions	—			—			165			—			—		60			889			1,054
Foreign currency translation adjustment	—			—			—			—			(69	)	—			—			(69	)
Common stock dividends, $0.28 per share	—			—			—			(3,512	)		—		—			—			(3,512	)
Other	—			—			(191	)		—			—		—			—			(191	)

Balance, December 31, 2000 (predecessor)	12,738		$	127		$	166,028		$	14,941		$	2		(202	)	$	(3,247	)	$	177,851

Net loss										(19,493	)										(19,493	)
Treasury stock purchased	—			—			—			—			—		(2	)		(64	)		(64	)
Other comprehensive income/(loss)	—			—			—			—			(914	)	—			—			(914	)
Common stock dividends, $0.10 per share	—			—			—			(2,149	)		—		—			—			(2,149	)
Options exercised	166			8			1,839			—			—		—			—			1,847
Other	—			—			(44	)		(175	)		—		—			—			(219	)

Balance, April 30, 2001 (predecessor)	12,904		$	135		$	167,823		$	(6,876	)	$	(912	)	(204	)	$	(3,311	)	$	156,859

Purchase price adjustments at May 1, 2001	(12,903	)		(134	)		193,014			6,876			912		204			3,311			203,979
Balance May 1, 2001, as adjusted	1			1			360,837			—			—		—			—			360,838
Net income							—			3,080											3,080
Other comprehensive income/(loss)	—			—			—			—			(7,744	)	—			—			(7,744	)
Capital contribution	—			—			7,000			—			—		—			—			7,000
Other	—			—			202			—			—		—			—			202

Balance December 31, 2001	1		$	1		$	368,039		$	3,080		$	(7,744	)	—		$	—		$	363,376

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

F-12

ENBRIDGE MIDCOAST ENERGY, INC.,
(an indirectly owned subsidiary of Enbridge Inc.)

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

					For the Year Ended December 31,						For the Four Months Ended April 30,			For the Eight Months Ended December 31,
					1999			2000			2001			2001
					(Predecessor)			(Predecessor)			(Predecessor)
Cash Flows from Operating Activities:
	Net income/(loss)				$	11,439		$	21,368		$	(19,493	)	$	3,080
	Adjustments to arrive at net cash (used)/provided by operating activities:
		Depreciation and amortization				7,545			15,695			5,715			15,527
		Deferred income taxes				336			6,712			1,347			6,376
		Extraordinary charge, net of tax				582			—			—			—
		Other				(129	)		(3,577	)		(178	)		(1,649	)
		Changes in working capital accounts:
			Decrease (Increase) in accounts receivable			(11,396	)		(86,199	)		59,107			13,842
			Decrease (Increase) in other current assets			186			(3,146	)		1,899			4,311
			(Decrease) Increase in accounts payable and accrued liabilities			8,136			75,113			(48,859	)		(63,281	)

				Net cash (used)/provided by operating activities		16,699			25,966			(462	)		(21,794	)

Cash Flows from Investing Activities:
	Acquisitions, net of cash acquired					(238,104	)		(22,752	)		—			(1,229	)
	Capital expenditures					(16,562	)		(16,528	)		(10,773	)		(50,185	)
	Other					368			(1,157	)		(656	)		42

				Net cash used by investing activities		(254,298	)		(40,437	)		(11,429	)		(51,372	)

Cash Flows from Financing Activities:
	Bank debt borrowings					194,658			125,806			31,760			156,628
	Bank debt repayments					(33,599	)		(109,878	)		(24,600	)		(419,786	)
	Net proceeds from equity offerings					84,870			—			—			—
	Financing costs					(1,372	)		—			1,581			—
	Contribution from affiliate.					—			—			—			7,000
	Loans from affiliates					—			—			—			319,200
	Cash overdrafts					—			6,659			—			10,295
	Treasury stock purchases					(2,406	)		(1,566	)		(64	)		—
	Dividends on common stock					(2,407	)		(3,512	)		(879	)		—
	Other					—			(764	)		1,849			(622	)

				Net cash provided by financing activities		239,744			16,745			9,647			72,715

Net (Decrease) Increase in Cash and Cash Equivalents						2,145			2,274			(2,244	)		(451	)

Cash and Cash Equivalents, beginning of period						200			2,345			4,619			2,375

Cash and Cash Equivalents, end of period					$	2,345		$	4,619		$	2,375		$	1,924

Supplemental Disclosures:
	Cash paid for interest, net of amounts capitalized				$	7,357		$	19,928		$	4,021		$	11,982

	Cash paid for income taxes				$	460		$	1,813		$	98		$	—

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

F-13

Enbridge Midcoast Energy, Inc.
(an indirectly owned subsidiary of Enbridge Inc.)

Notes to Consolidated Financial Statements

Note 1. Organization and Business:

The Company, along with its subsidiaries and its affiliated companies, is primarily engaged in the transportation, gathering, processing and marketing of natural gas and other petroleum products. The Company owns and operates four interstate transmission pipeline systems, 20 intrastate transmission and wholesale customer pipeline systems, and gathering systems, in total representing approximately 4,000 miles of pipeline with an aggregate daily throughput capacity of approximately 4.0 billion cubic feet of natural gas per day. Operations also include three gas processing and two treating plants, 98 natural gas liquid, crude oil and carbon dioxide trucks and trailers and 45 rail cars. The Company's principal business consists of providing transportation services to natural gas producers and wholesale customers, providing natural gas marketing services to these customers and processing natural gas. In connection with these services, the Company acquires and constructs pipelines to meet these customers' needs. The Company's principal assets are located in the Gulf Coast and Mid-Continent areas.

On May 11, 2001, Midcoast Energy Resources, Inc. was acquired by Enbridge Inc. ("Enbridge"). Enbridge acquired all of the common stock of Midcoast for $27 per share in cash and assumed long-term debt.

The purchase price of $623.8 million was determined based on negotiations between management of Enbridge and Midcoast and was approved by their respective boards of directors.

The purchase price was allocated to the assets acquired and the liabilities assumed based on estimated fair market values, with the residual assigned to goodwill. The purchase price was allocated at the acquisition date to the assets acquired and the liabilities assumed as follows:

			($ millions)
Assets Acquired:
	Current Assets		$	99.3
	Goodwill			212.0
	Other Assets			24.4
	Property, Plant & Equipment, Net			436.9

				772.6
Less – Liabilities Assumed:
	Current Liabilities			123.1
	Deferred Income Taxes			25.7

				148.8

		Total Purchase Price	$	623.8

Note 2. Summary of Significant Accounting Policies:

Basis of Presentation

The consolidated financial statements include the accounts of the Company and all of its subsidiaries. Investments in entities which are not subsidiaries, but over which the Company exercises significant influence, are accounted for using the equity method. Other investments are

F-14

accounted for at cost. The financial statements for previous periods include certain reclassifications that were made to conform to the current year presentation. Such reclassifications have no impact on reported net income or shareholders' equity.

Use of Estimates

The preparation of the Company's consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires the Company's management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities that exist at the date of the financial statements. Actual results could differ from those estimates.

Regulation

Certain of the Company's activities are subject to regulation by various authorities, including the Federal Energy Regulatory Commission ("FERC"), and follow the provisions of Statement of Financial Accounting Standards ("SFAS") No. 71, "Accounting for the Effects of Certain Types of Regulation." Regulatory bodies exercise statutory authority over matters such as construction, rates and underlying accounting practices, and ratemaking agreements with customers. In order to achieve a proper matching of revenues and expenses, the timing of recognition of certain revenues and expenses in these operations may differ from that otherwise expected, in the absence of SFAS No. 71. Approximately 50% of the Company's operations are subject to regulation.

Cash and Cash Equivalents

The Company considers short-term, highly liquid investments that have an original maturity of three months or less at the time of purchase to be cash equivalents.

Operational Balancing Agreements

To facilitate deliveries of natural gas and provide for operating flexibility, the Company has operational balancing agreements in place with other interconnecting pipelines. A balancing agreement ensures that the volume of gas a shipper schedules for transportation between two interconnecting pipelines equals the volume actually delivered. If natural gas moves between pipelines in volumes that are more or less than the volumes previously scheduled, the difference results in a net receivable or payable balance between the interconnecting pipelines. These are settled through cash-out procedures specified in each tariff or operational balancing agreements or recovered or repaid through the receipt or delivery of natural gas in the future. Such imbalances are recorded as current assets or current liabilities on the balance sheet using the posted index prices of the applicable FERC-approved tariffs, which approximate market rates or our weighted average cost of gas ("WACOG").

Inventories

Inventories consist primarily of materials and supplies, natural gas and liquid petroleum products. Inventories of materials and supplies utilized for ongoing replacements and expansions

F-15

are carried at average cost and are reviewed regularly and adjusted to their net realizable value. The natural gas and liquid petroleum products are carried at lower of cost or market.

Property, Plant and Equipment

Interstate and intrastate natural gas transmission, distribution and processing facilities and other equipment are stated at cost and depreciated by the straight-line method at rates based on the following estimated useful lives of the assets:

Interstate natural gas transmission facilities	15 - 66	Years
Intrastate natural gas transmission facilities	15 - 60	Years
Pipeline right-of-ways	17	Years
Natural gas processing facilities	30	Years
Other property and equipment	3 - 10	Years

For regulated interstate natural gas transmission facilities, the cost of additions to property, plant and equipment includes direct labor and material, allocable overhead and an allowance for the estimated cost of funds used during construction ("AFUDC"). Such provisions for AFUDC are not reflected separately in the accompanying consolidated statements of operations due to the amounts not being material. Maintenance and repairs, including the cost of renewals of minor items of property, are charged principally to expense as incurred. Major additions, replacements and improvements of property are charged to the appropriate property accounts. Upon retirement of a pipeline plant asset, its cost is charged to accumulated depreciation together with the cost of removal, less salvage value.

For all other non-regulated assets, repairs and maintenance are charged to expense as incurred; renewals and betterments are capitalized including any direct labor. Upon retirement or disposal, the net book value of the assets, net of any sale proceeds or retirement costs, is recorded as a charge or credit to income.

Impairment of Long-Lived Assets

In accordance with SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of," the Company evaluates the long-lived assets, including related intangibles, of identifiable business activities for impairment when events or changes in circumstances indicate, in management's judgment, that the carrying value of such assets may not be recoverable. The determination of whether an impairment has occurred is based on management's estimate of undiscounted future cash flows attributable to the assets as compared to the carrying value of the assets. If an impairment has occurred, the amount of the impairment recognized is determined by estimating the fair value for the assets and recording a provision for loss if the carrying value is greater than fair value. For assets identified to be disposed of in the future, the carrying value of these assets is compared to the estimated fair value less the cost to sell to determine if an impairment is required. Until the assets are disposed of, an estimate of the fair value is redetermined when related events or circumstances change.

F-16

Goodwill

Goodwill represents the excess of the purchase price over the fair value of net assets upon acquisition of a business and is amortized on a straight-line basis over 30 years. Effective January 1, 2002, the Company adopted SFAS No. 142 related to goodwill and other intangible assets. Under the new standard, goodwill will not be amortized but will be tested for impairment at least annually and written down if recorded value exceeds fair value.

Revenue Recognition

Revenues are recorded when products have been delivered or services have been performed. Certain of the Company's operations are subject to regulation. In these situations, revenue is recognized in a manner that is consistent with the underlying rate design as mandated by the regulatory authority.

Income Taxes

Income taxes are based on income reported for tax return purposes along with a provision for deferred income taxes. Deferred income taxes are provided to reflect the tax consequences in future years of differences between the financial statement and tax bases of assets and liabilities. Tax credits are accounted for under the flow-through method, which reduces the provision for income taxes in the year the tax credits first become available. Deferred tax assets are reduced by a valuation allowance when, based upon management's estimates, it is more likely than not that a portion of the deferred tax asset will not be realized in a future period. The estimates utilized in the recognition of deferred tax assets are subject to revision in future periods based on new facts or circumstances.

Derivative Financial Instruments

In accordance with SFAS No. 133, the Company recognizes all derivative financial instruments as assets and liabilities and measures them at fair value. For derivative financial instruments that are designated and qualify as a cash flow hedge, the effective portions of changes in fair value of the derivative are recorded in other comprehensive income and are recognized in the income statement when the hedged item affects earnings. Changes in the fair value of derivatives that do not qualify for hedge treatment are recognized currently in earnings. The related cash flows from those derivative financial instruments accounted for as hedges are classified in the same category as the items being hedged.

Prior to December 31, 2000, unrealized gains and losses on hedge contracts are deferred and recognized in income in the same manner as the hedged item. These contracts are initially and regularly evaluated to determine that there is a high correlation between changes in the fair value of the hedge contract and fair value of the hedged item. In instances where the anticipated correlation of price movements does not occur, hedge accounting is terminated and future changes in the value of the instruments are recognized as gains or losses in the statement of operations. If the hedged item of the underlying transaction is sold or settled, the instrument is recognized in income. The income effect and cash flows from these items are included in the same balances as the underlying transactions on the statement of operations and of cash flows.

F-17

Net income and cash flows are subject to volatility stemming mainly from changes in interest rates, natural gas prices, and fractionation margins. In order to manage the risks, the Company uses a variety of derivative financial instruments to create offsetting positions to specific commodity or interest rate exposures. All of these financial instruments are employed in connection with an underlying asset, liability or anticipated transaction and are not used for speculative purposes.

Derivative financial instruments are used primarily to hedge against the effect of future interest rate movements, to manage natural gas purchases and to hedge fractionation margins associated with processing assets. (See Note 11 for additional information.)

Capitalization of Interest

The Company capitalizes interest on major projects during construction. Interest is capitalized on borrowed funds and, where regulation by the FERC exists, on internally generated funds. The rates used by regulated companies are calculated in accordance with FERC rules. Rates used by unregulated companies are based on the average interest rate on related debt.

Foreign Currency Translation

Assets and liabilities of certain foreign subsidiaries with functional currencies other than the U.S. dollar are translated at the spot foreign currency exchange rate in effect at the applicable reporting date, and the combined statements of operations are translated at the average rates in effect during the applicable period. The resulting cumulative translation adjustment is recorded as a separate component of other comprehensive income.

New Accounting Pronouncements

In June 1998, the Financial Accounting Standards Board ("FASB") issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." This Statement requires that all derivatives be recognized at fair value in the balance sheet and all changes in fair value be recognized currently in earnings or deferred as a component of other comprehensive income, depending on the intended use of the derivative. The Company adopted SFAS No. 133 on January 1, 2001. The cumulative effect of the accounting change associated with the initial adoption of SFAS No. 133 resulted in a $3.8 million increase in other comprehensive income, net of taxes and a $0.9 million charge to earnings as a cumulative effect change in accounting principle.

In June 2001, the FASB issued SFAS No. 141, "Business Combinations." This Statement requires the use of the purchase method for all business combinations. In addition, it requires the reassessment of intangible assets to determine if they are appropriately classified either separately or within goodwill. This Statement is effective for business combinations initiated after June 30, 2001. The Company adopted SFAS No. 141 on July 1, 2001 with no impact on results of operations, financial position or cash flows.

In July 2001, the FASB issued SFAS No. 142, "Goodwill and Other Intangible Assets". Under SFAS No.142, goodwill and intangible assets with indefinite lives will not be amortized but will be reviewed for impairment at least annually. Intangible assets with finite lives will continue to be amortized over their useful lives, which will not be limited to a maximum life of forty years. The

F-18

Company adopted SFAS No.142 on January 1, 2002. As of May 15, 2002, the initial impairment assessment has not been completed. With the adoption of SFAS No. 142, goodwill of $207.5 million is no longer subject to amortization.

In July 2001, the FASB issued SFAS No. 143 "Accounting for Asset Retirement Obligations" under which retirement obligations will be recognized at fair value in the period they are incurred. When the liability is initially recorded, the cost is capitalized by increasing the asset's carrying value, which is subsequently depreciated over its useful life. SFAS No.143 is effective for fiscal years beginning after June 15, 2002. The Company is currently evaluating the potential effects if any, of adopting SFAS No. 143, on its financial condition and results of operations as well as the timing of its adoption.

Also, in October 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets". SFAS No. 144 establishes a single accounting model for long-lived assets to be disposed of by sale. The Statement retains most of the requirements in SFAS No. 121 related to the recognition of impairment of long-lived assets to be held and used. The Company adopted SFAS No. 144 on January 1, 2002. This standard is not expected to have a material impact on results of operations, financial position or cash flows.

Note 3. Acquisitions:

Northeast Texas Acquisition

In March 2002, the Company purchased natural gas gathering and processing facilities in Northeast Texas for $178.0 million. The Northeast Texas facilities include 1,200 miles of natural gas gathering pipelines, five gas treating plants with an elemental sulphur capacity of more than 1,100 long tons per day, four gas processing plants with a capacity of 165 million cubic feet per day ("mmcfd"), and two nitrogen rejection plants with a capacity of 75 mmcfd.

South Texas Acquisition

In October 2001, the Company agreed to purchase natural gas gathering, treating and transmission assets in south Texas. The Company agreed to acquire 492 miles of gas mainlines regulated by the FERC and 175 miles of non-FERC regulated assets including gathering systems and pipeline laterals for $50.0 million. As of May 2002 the Company had purchased the non-FERC regulated assets for a total of $9.0 million in cash consideration. Closing of the acquisition of the FERC-regulated assets is subject to, among other things, certain regulatory approvals including an order of the FERC approving the abandonment by sale and granting a determination that the facilities will not be subject to the jurisdiction of the FERC in the hands of Enbridge Partners. If this FERC order is not obtained, Enbridge Partners may seek to renegotiate the terms of this acquisition or may determine not to complete it.

The Kansas Pipeline Company Acquisition

In November 1999, the Company acquired KPC and other related entities for cash consideration of approximately $195.2 million which included the repayment of $68.4 million in existing KPC senior secured notes and other indebtedness. KPC owns and operates a 1,120-mile

F-19

regulated interstate natural gas pipeline system. The system extends into two major segments from northwestern and northeastern Oklahoma through Wichita and into the Kansas City metropolitan area. The system's two principal customers are divisions of ONEOK, Inc. and Southern Union Company, which are the local distribution companies for Wichita and Kansas City. KPC derives 97% of its gross margin from a series of long-term transportation contracts with these two principal customers. KPC is capable of delivering approximately 140 mmcfd and 21 mmcfd of natural gas into the Kansas City and Wichita marketplaces, respectively. KPC is one of only three pipeline systems currently capable of delivering natural gas into the Kansas City metropolitan market. The acquisition was funded through the Company's credit facility.

In conjunction with the acquisition of KPC, the Company opted to terminate a revenue sharing agreement with an affiliate of the selling party by agreeing to pay approximately $10.8 million in January 2000.

In addition to the acquisition discussed above, the Company made several additional, individually insignificant acquisitions in 1999. The Company utilized the purchase method of accounting to record all of its acquisitions. Accordingly, the operating results of these acquired businesses have been included in the statements of operations from the date of acquisition. At the acquisition date, the respective assets and liabilities acquired were recorded at their estimated fair values. Any excess of the purchase price over fair value was allocated to goodwill. In connection with its 1999 acquisition activity, the Company acquired certain assets and liabilities to include approximately $229.8 million in property, plant and equipment, $35.4 million in other non-cash assets and $24.3 million in assumed liabilities. Furthermore, the Company issued approximately $2.8 million of treasury stock as consideration.

Note 4. Property, Plant, and Equipment:

Property, plant, and equipment consisted of the following (in thousands):

		December 31,
		2000		2001
		(predecessor)
Property, Plant, and Equipment:
	Transmission	$	326,774	$	339,977
	Gathering and Processing		95,513		102,783
	Marketing		170		639
	Corporate and Other		4,391		27,306
	Construction in Progress		15,679		52,673

			442,527		523,378
Less: Accumulated Depreciation			26,481		41,303

Total Property, Plant, and Equipment, net		$	416,046	$	482,075

F-20

Note 5. Other Assets:

Other assets are summarized as follows (in thousands):

	December 31,
	2000		2001
	(predecessor)
Regulatory assets, net of accumulated amortization of $7,450 and $2,282	$	18,165	$	7,483
Goodwill, net of accumulated amortization of $310 and $4,540		4,822		207,482
Other		3,289		1,993

	$	26,276	$	216,958

Goodwill at December 31, 2001 is related entirely to the acquisition of Midcoast Energy Resources, Inc. by Enbridge Inc. and represents the excess of cost over the fair value of the assets acquired.

Note 6. Long-term Debt:

At December 31, 2000, the Company had a revolving credit line with a bank under a $300 million promissory note bearing interest at 8.22% with $256.0 million outstanding. In 2001, the revolving credit line was settled with proceeds received from affiliate loans and the promissory note was cancelled.

Note 7. Capital Stock:

Effective May 1, 2001 and pursuant to the acquisition by Enbridge Inc., all outstanding shares of Common Stock purchased were replaced by one share held by Enbridge Energy Company, Inc., an indirect wholly owned subsidiary of Enbridge Inc., as the sole shareholder of the Company.

In May 1999, the Company sold 3.57 million shares of its Common Stock at an offering price of $16.31 per share. Proceeds of $54.5 million, net of issuance costs, were used to pay down existing long-term debt.

In December 1999, the Company sold 2 million shares of its Common Stock at an offering price of $16.06 per share. Proceeds of $30.2 million, net of issuance costs, were used to repay existing long-term debt, consummate an acquisition and provide working capital for general corporate purposes.

Note 8. Stock Option Plans:

Prior to the acquisition by Enbridge Inc., the Company had two stock option plans: the 1996 Incentive Stock Plan (the "Incentive Plan") and the 1997 Non-Employee Director Stock Option Plan (the "Director's Plan"). Pursuant to the acquisition by Enbridge Inc. in 2001, the Incentive Plan, the Director's Plan, and all outstanding options were cancelled.

In May 1996, the Board adopted the Incentive Plan, which was subsequently approved by the Company's shareholders in May 1997. All employees, including officers (whether or not directors) and consultants of the Company and its subsidiaries, are currently eligible to participate in the Incentive Plan. Persons who are not in an employment or consulting relationship with the Company

F-21

or any of its subsidiaries, including non-employee directors, are not eligible to participate in the Incentive Plan. Under the Incentive Plan, 1,000,000 shares of the Company's common stock are reserved for issuance.

The Incentive Plan provides for the grant of (i) incentive stock options, (ii) shares of restricted stock, (iii) performance awards payable in cash or common stock, (iv) shares of phantom stock, and (v) stock bonuses. In addition, the Incentive Plan provides for the grant of cash bonuses payable when a participant is required to recognize income for federal income tax purposes in connection with the vesting of shares of restricted stock or the issuance of shares of common stock upon the grant of a performance award or a stock bonus, provided that such cash bonus may not exceed the fair market value (as defined) of the shares of Common Stock received on the grant or exercise, as the case may be, of an Incentive Award.

With respect to incentive stock options, no option may be granted more than ten years after the effective date of the stock option plan or exercised more than ten years after the date of the grant (five years if the optionee owns more than 10% of the common stock of the Company at the date of the grant). Additionally, with regard to incentive stock options, the exercise price of the options may not be less than the fair market value of the common stock at the date of the grant (110% if the optionee owns more than 10% of the common stock of the Company). Subject to certain limited exceptions, options may not be exercised unless, at the time of the exercise, the optionee is in the service of the Company. In general, options granted under the incentive plan vest at a rate of one-fifth each year.

Transactions with regard to incentive stock options issued pursuant to the Incentive Plan are as follows:

		Stock Options
		1999				2000				2001
		Number of Shares Underlying Options		Weighted Average Exercise Price		Number of Shares Underlying Options		Weighted Average Exercise Price		Number of Shares Underlying Options		Weighted Average Exercise Price
Outstanding at beginning of the year		441,814		$	11.32	464,689		$	11.55	630,864		12.67
	Granted	64,375			16.68	195,925			15.80	117,500		22.10
	Exercised	(2,500	)		16.80	(5,750	)		15.66	(65,226	)	10.83
	Forfeited/Repurchased	(39,000	)		17.14	(24,000	)		15.73	—		—
	Cancelled on acquisition	—			—	—			—	(683,138	)	14.46

Outstanding at end of year		464,689		$	11.55	630,864		$	12.67	—		—

Exercisable at end of year		152,289		$	9.92	232,173		$	10.37	—		—

In April 1997, the Board adopted the Director's Plan, which was subsequently approved by the Company's shareholders in May 1997. The Director's Plan is for the benefit of Directors of the Company, who at the time of their service, are not employees of the Company or any of its subsidiaries. Under the Director's Plan, 150,000 shares of the Company's common stock are reserved for issuance.

F-22

The Director's Plan provides for the granting of non-qualified stock options ("NQO"), the provisions of which do not qualify as "incentive stock options" under the Internal Revenue Code. Options granted under the Director's Plan must have an exercise price at least equal to the fair market value of the Company's common stock on the date of the grant. Pursuant to the Director's Plan, options to purchase 15,000 shares of common stock are granted to each non-employee director upon their initial election to the Board. In addition, all non-employee Directors are eligible to receive a NQO to purchase 5,000 shares of common stock at the time of the Directors re-election to the Board, subject to share availability. Options granted under the Director's Plan are fully vested upon issue and expire ten years after the date of the grant.

The fair value of each stock option granted is estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted-average assumptions:

Assumption:	1999		2000		2001
Expected Term in Years	6.35		6.64		7
Expected Volatility	33.04	%	26.43	%	24.91	%
Expected Dividends	0.4	%	1.8	%	1.3	%
Risk-Free Interest Rate	5.95	%	6.60	%	5.16	%

The Black-Scholes weighted average fair value of all options granted under both plans during 2001, 2000, and 1999 was $7.32, $5.36, and $7.10, respectively.

The Company applies Accounting Pronouncement Bulletin (APB) No. 25 and related Interpretations in accounting for its plans. Accordingly, no compensation cost has been recognized for its stock option plans. Had compensation expense for the Company's stock-based compensation plans been determined applying the provisions of SFAS No. 123, the Company's net income and net income per common share for 2001, 2000, and 1999 would approximate the pro forma amounts below (in thousands, except per share data):

	Year Ended December 31, 1999				Year Ended December 31, 2000				Four Months Ended April 30, 2001
	As Reported		Pro Forma		As Reported		Pro Forma		As Reported			Pro Forma
Net income/(loss)	$	11,439	$	11,121	$	21,368	$	21,194	$	(19,493	)	$	(19,692	)
Basic earnings/(loss) per share	$	1.25	$	1.21	$	1.71	$	1.69	$	(1.55	)	$	(1.56	)
Diluted earnings/(loss) per share	$	1.22	$	1.18	$	1.68	$	1.66	$	(1.55	)	$	(1.56	)

Note 9. Employee Benefits:

In December 1996, the Company established a defined contribution 401(k) Profit Sharing Plan for its employees. The plan provides participants with a mechanism for making contributions for retirement savings. Each participant may contribute certain amounts of eligible compensation. The Company made a matching contribution to the plan, which is recognized as compensation expense in the year incurred, of approximately $305,000, $410,000, $179,000, and $345,000 for years ended December 31, 1999 and 2000 and the four months ended April 30, 2001 and the eight months ended December 31, 2001, respectively.

F-23

Effective January 1, 2002 employees of the Company became employees of Enbridge Employee Services Inc. and became eligible to participate in the Enbridge 401(K) Savings Plan. The employees' contributions are matched up to a maximum of 5% of each employee's contribution. The Company (through its parent, Enbridge Energy Company, Inc.) sponsors other plans for the benefit of employees. These plans include health and dental care, life insurance, accidental death and dismemberment, short-term disability, long-term disability and business travel accident insurance.

Note 10. Related Party Transactions:

Affiliates refer to Enbridge Inc. and companies that are either directly or indirectly owned by Enbridge Inc.

In December 2001, the Company obtained $229.2 million from an affiliate, Enbridge (U.S.) Inc., in the form of three promissory notes that bear interest at three month LIBOR plus 150 basis points and are for a 5 year term. Proceeds were used to repay existing debt and working capital requirements.

In September 2001, the Company obtained $90 million from an affiliate of Enbridge Inc. This promissory note has a 5-year term, interest rate of 6.39% with interest payable semi-annually on June 15 and December 15. Proceeds were used to repay existing debt.

The Company receives certain administrative and treasury services from affiliates. These services, which are charged at cost in accordance with service agreements or which reflect normal commercial trade terms, amounted to $4.2 million for the eight months ended December 31, 2001. At December 31, 2001, accounts payable and accrued liabilities included $2.2 million due to affiliates.

Note 11. Financial Instruments

Derivative Financial Instruments used for Risk Management

The Company is exposed to movements in interest rates and the price of energy commodities, primarily natural gas. In order to manage these exposures, the Company utilizes derivative financial instruments to create offsetting positions to specific exposures. These instruments are not used for speculative purposes.

These instruments require the Company to exchange with counterparties the difference between fixed and variable amounts, calculated by reference to specific interest rates or energy commodity price indices, based on a notional principal amount or notional energy commodity quantity. The notional amounts are not recorded in the financial statements as they do not represent amounts exchanged by the counterparties.

Derivative financial instruments involve credit and market risks. Credit risk arises from the possibility that a counterparty will default on its contractual obligations and is limited to those contracts where the Company would incur a loss in replacing the instrument. The Company minimizes credit risk by entering into risk management transactions only with creditworthy institutions that possess investment grade credit ratings or with approved forms of collateral. For

F-24

transactions with terms greater than five years, the Company may also retain the right to require a counterparty, who would otherwise meet the Company's credit criteria, to provide collateral.

Interest Costs

To hedge against the effect of future interest rate movements on its short to long-term borrowing requirements, the Company enters into forward interest rate agreements, swaps and collars.

Energy Commodity Costs

The Company's commodity price risk exposure arises from holding inventory and purchase and sale commitments. The Company uses over-the-counter commodity price swaps, futures, options and collars to manage exposures to natural gas and natural gas liquids prices.

Fair Values

The fair values of derivatives have been estimated using year-end market rates and approximate the amount that the Company would receive or pay to terminate the contracts at December 31. The following derivative instruments qualify as cash flow hedges and have been recorded in the consolidated balance sheet as of December 31, 2001.

		December 31,
		2000						2001
*(millions of dollars)*		Notional Principal or Quantity		Fair Value (Payable)			Maturity	Notional Principal or Quantity		Fair Value (Payable)			Maturity
				(predecessor)
Energy Commodities
	Natural gas (bcf)		4.3	$	(1.1	)	2001-2004		12.8	$	(10.7	)	2002-2004
Interest rates
	Interest rate swaps	$	140.0	$	(0.4	)	2003	$	140.0	$	(6.8	)	2003

As the Company does not settle hedging instruments in advance of the hedged transactions, there were no gains or losses deferred for any of the Company's hedges of anticipated transactions at December 31, 2001 and 2000. Credit risk was insignificant at December 31, 2001 and 2000 as all derivative instruments were in payable positions.

Fair Values of Other Financial Instruments

The fair value of financial instruments, other than derivatives, represents the amounts that would have been received from or paid to counterparties, calculated at the reporting date, to settle these instruments. The carrying amount of all financial instruments classified as current approximates fair value because of the short maturities of these instruments. The estimated fair values of all other financial instruments are based on quoted market prices or, in the absence of specific market prices, on quoted market prices for similar instruments and other valuation techniques.

F-25

The carrying amounts of all financial instruments, except as shown below, approximate fair value.

	December 31,
	2000				2001
*(millions of dollars)*	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(predecessor)
Long-term debt	$	256.0	$	256.0		—		—
Due to affiliates		—		—	$	319.2	$	319.8

Note 12. Concentration of Credit Risk:

The Company derives revenue from commercial companies located in the United States and Canada. The Company performs ongoing evaluations of its customers and generally does not require collateral. The Company assesses its credit risk and provides an allowance for doubtful accounts for any accounts that it deems doubtful of collection.

Note 13. Income Taxes:

The tax effects of significant temporary differences representing deferred tax assets and liabilities are as follows (in thousands):

		December 31, 2000			December 31, 2001
		(predecessor)
Net operating loss and other carryforwards		$	6,304		$	18,509
Valuation allowance			(480	)		—
Book value of assets in excess of tax net book value of assets			(23,570	)		(39,244	)
Unrealized holding gains/losses			—			4,748
Other			—			(698	)

	Net deferred tax liabilities	$	(17,746	)	$	(16,685	)

The Company has non-operating loss ("NOL") carryforwards of approximately $51 million at December 31, 2001, expiring in various amounts from 2002 through 2021. A portion of these loss carryforwards were acquired through corporate acquisitions. The ability of the Company to utilize the carryforwards is dependent upon the Company generating sufficient taxable income and will be affected by annual limitations under section 382 of the Internal Revenue Code. No valuation allowance was deemed necessary due to management's view that the NOLs are anticipated to be utilized.

F-26

A reconciliation of the provision for income taxes to the statutory U.S. rate is as follows (in thousands):

		Year Ended December 31, 1999 (34%)			Year Ended December 31, 2000 (34%)			Four Months Ended April 30, 2001 (34%)			Eight Months Ended December 31, 2001 (35%)
		(predecessor)			(predecessor)			(predecessor)
Federal income tax expense (benefit) computed at statutory rate		$	4,832		$	9,780		$	(9,956	)	$	2,565
Utilization of net operating loss carryforwards			(1,989	)		(240	)		—			—
Effect of goodwill amortization			—			—			—			1,603
Reduction in valuation allowance			(581	)		(1,984	)		—			—
Foreign and state taxes			(146	)		(200	)		122			7
Other			53			40			45			71

	Actual provision	$	2,169		$	7,396		$	(9,789	)	$	4,246

Prior to May 1, 2001, United States income taxes were not provided on the cumulative undistributed earnings of the Company's Canadian subsidiaries, as it was management's intention not to repatriate these earnings. Tax has been provided on these earnings at May 1, 2001 in conjunction with the acquisition.

Note 14. Commitments and Contingencies:

Leases

The Company leases facilities and equipment under various operating leases. The Company incurred net lease expenses of $0.2 million, $1.7 million, $3.0 million and $0.8 million during the periods ended December 31, 1999 and 2000, April 30, 2001 and December 31, 2001, respectively. As of December 31, 2001, future minimum lease payments due under these leases are approximately $1.8 million, $2.1 million, $2.0 million, $2.1 million, and $1.2 million for the years ended December 31, 2002, 2003, 2004, 2005 and 2006, respectively.

MIT Acquisition Contingency

As part of the MIT acquisition in 1997, the Company has agreed to pay additional contingent annual payments to the seller, not to exceed $250,000 per year, which will be treated as deferred purchase price adjustments. The amount each year is dependent upon revenues received by the Company from certain natural gas transportation contracts. The contingency is due over an eight-year period commencing April 1, 1998 and payable at the end of each anniversary date. The Company is obligated to pay the lesser of 50% of the gross revenues received under these contracts or $250,000. As of December 31, 2001, the Company has made payments of $750,000 and has accrued an additional $187,500 under the contingency.

F-27

Note 14. Commitments and Contingencies:

The Kansas Pipeline Company Rate and Regulatory Matters

The pipeline assets of KPC were held in three partnerships prior to May 11, 1998. KansOk Partnership owned intrastate pipelines whose rates were regulated by state agencies or the FERC. Kansas Pipeline Partnership owned an intrastate pipeline in Kansas whose rates were determined by the Kansas Corporation Commission. Riverside Pipeline Company, L.P., owned interstate assets in Kansas, Oklahoma and Missouri that connected the assets of the other two partnerships at the state lines of Missouri, Kansas and Oklahoma.

Effective May 11, 1998, after more than two years of jurisdictional proceedings before the FERC, the FERC asserted jurisdiction over the assets of these three entities, which were combined into a single, FERC-regulated entity, KPC. The new company's initial rates, by order of the FERC, were approximately equal to its then-existing rates. That discussion was affirmed by the FERC in its order to Remand issued on November 9, 2001. The FERC's order also ordered the company to file a Section 4 Rate Case by September 10, 1999.

In accordance with the FERC's order, KPC filed a rate case pursuant to Section 4 of the Natural Gas Act ("NGA") on August 27, 1999 (FERC Docket No. RP99-485-000). KPC's proposed rates reflect an annual revenue increase when compared to its initial FERC-approved rates. The rates have been protested by KPC's two principal customers and by the state public utility commissions that regulate them. On September 30, 1999, the FERC issued an order that set KPC's proposed rates for hearing and accepted and suspended the rates to be effective March 1, 2000, subject to possible refund. However, through December 31, 2001, KPC is continuing to charge its customers the initial lower FERC-approved rates. Additionally, the two customers have been paying only a portion of the Company's invoices pursuant to their protest of the current rates. The resultant net unpaid balance from both customers at December 31, 2001 was approximately $4.4 million, for which no reserve has been recorded. The Section 4 rate case proceeding will determine the rates by KPC for interstate transportation of natural gas prospective from the date of approval. The hearing related to the proposed increase commenced on September 26, 2000 and concluded on October 20, 2000. The presiding Administrative Law Judge issued and "Initial Decision" on July 31, 2001, recommending a cost of service of $20 million, which is approximately $11 million less than the cost of service included in the current rates. A final Commission decision is not expected until at least the fourth quarter of 2002.

Note 15. Segment Data:

The Company's operations are segregated into reportable segments based on the type of business activity and type of customer served. The Company's transmission pipelines primarily receive and deliver natural gas to and from other pipelines, and, secondarily, provide wholesale customer or gathering functions. Transportation fees are received by the Company for transporting natural gas owned by other parties through the Company's pipeline systems. The transmission pipelines segment also includes wholesale customer pipelines providing natural gas and natural gas transportation services to industrial customers, municipalities or electrical generating facilities through interconnect natural gas pipelines constructed or acquired by the Company. These pipelines provide a direct supply of natural gas to new industrial facilities or to existing facilities as an alternative to the local distribution company. The Company's natural gas gathering and

F-28

processing systems typically consist of a network of pipelines which collect natural gas or crude oil from points near producing wells, treat and process the natural gas, and transport oil and natural gas to larger pipelines for further transmission. The Company's natural gas processing revenues are realized from the extraction and sale of NGLs as well as the sale of the residual natural gas. In addition, the Company provides natural gas marketing services to its customers within each of the three segments. The Company's marketing activities include providing natural gas supply and sales services to some of its wholesale customers by purchasing the natural gas supply from other marketers or pipeline affiliates and reselling the natural gas to the wholesale customer. The Company also purchases natural gas directly from well operators on many of the Company's gathering systems and resells the natural gas to other marketers or pipeline affiliates. Many of the contracts pertaining to the Company's natural gas marketing activities are month-to-month spot market transactions with numerous natural gas suppliers or producers in the industry. The Company also offers other natural gas services to some of its customers including management of capacity release and gas balancing.

The Company evaluates each of its segments on a gross margin basis, which is defined as the revenues of the segment less related direct costs and expenses of the segment and does not include depreciation and amortization, interest or allocated corporate overhead. Gross margin reflects total revenues net of energy marketing expenses, natural gas processing and treating costs, and other operating expenses. The "Other" column includes results of processing plant construction projects, which includes planning, fabrication, installation and facility operations and management, as well as general corporate items. Foreign amounts primarily relate to the Company's Canadian operations, which are not considered material for separate disclosure. No customers constituted more than 10% of revenues during the periods ended December 31, 2001, April 30, 2001, or the years ended December 31, 2000, and 1999. The accounting policies of the segments are the same as those described in the summary of significant accounting policies (see Note 2).

F-29

The following tables present certain financial information relating to the Company's business segments as of or for the eight months ended December 31, 2001, the four months ended April 30, 2001 and the years ended December 31, 2000, and 1999:

		As of or for the Eight Months Ended December 31, 2001
		Transmission Pipelines			Marketing			Gathering and Processing			Other			Total
		(In thousands)
Revenues
	Domestic	$	59,418		$	180,787		$	193,807		$	—		$	434,012
	Foreign		—			—			4,462			—			4,462

Total Revenues			59,418			180,787			198,269			—			438,474
Gross Margin			30,550			1,973			18,888			—			51,411
Depreciation and Amortization			(7,422	)		(48	)		(3,374	)		(4,683	)		(15,527	)
General and Administrative, including taxes other than income												(14,707	)		(14,707	)
Interest Expense												(13,976	)		(13,976	)
Other, net												125			125

Income before Income Taxes		$	23,128		$	1,925		$	15,514		$	(33,241	)	$	7,326

Assets
	Domestic	$	390,364		$	33,021		$	119,606		$	220,158		$	763,149
	Foreign		—			—			24,565			—			24,565

Total Assets		$	390,364		$	33,021		$	144,171		$	220,158		$	787,714

Capital Expenditures (excluding acquisitions)		$	38,582		$	51		$	8,668		$	2,884		$	50,185

F-30

		As of or for the four months Ended April 30, 2001 (predecessor)
		Transmission Pipelines			Marketing			Gathering and Processing			Other			Total
		(In thousands)
Revenues
	Domestic	$	33,115		$	229,485		$	140,543		$	—		$	403,143
	Foreign		—			—			3,810			—			3,810

Total Revenues			33,115			229,485			144,353			—			406,953
Gross Margin			17,834			(18,555	)		5,218			(3	)		4,494
Depreciation and Amortization			(3,459	)		(17	)		(1,761	)		(478	)		(5,715	)
General and Administrative, including taxes other than income			—			—			—			(17,884	)		(17,884	)
Interest Expense			—			—			—			(9,431	)		(9,431	)
Other, net			—			—			—			561			561

Income before Income Taxes		$	14,375		$	(18,572	)	$	3,457		$	(27,235	)	$	(27,975	)

Capital Expenditures (excluding acquisitions)		$	8,230		$	77		$	2,253		$	213		$	10,773

F-31

		As of or for the Year Ended December 31, 2000 (predecessor)
		Transmission Pipelines			Marketing			Gathering and Processing			Other			Total
		(In thousands)
Revenues
	Domestic	$	87,838		$	411,266		$	280,721		$	—		$	779,825
	Foreign		—			—			12,521			—			12,521

Total Revenues			87,838			411,266			293,242			—			792,346
Gross Margin			49,175			5,180			24,744			—			79,099
Depreciation and Amortization			(10,345	)		(15	)		(4,315	)		(1,020	)		(15,695	)
General and Administrative, including taxes other than income			—			—			—			(17,900	)		(17,900	)
Interest Expense			—			—			—			(18,489	)		(18,489	)
Other, net			—			—			—			1,749			1,749

Income before Income Taxes and Extraordinary Charge		$	38,830		$	5,165		$	20,429		$	(35,660	)	$	28,764

Assets
	Domestic	$	366,395		$	79,706		$	113,824		$	13,334		$	573,259
	Foreign		—			—			26,061			—			26,061

Total Assets		$	366,395		$	79,706		$	139,885		$	13,334		$	599,320

Capital Expenditures (excluding acquisitions)		$	8,526		$	313		$	5,855		$	1,834		$	16,528

F-32

		As of or for the Year Ended December 31, 1999 (predecessor)
		Transmission Pipelines			Marketing			Gathering and Processing			Other			Total
		(In thousands)
Revenues
	Domestic	$	53,606		$	201,107		$	134,668		$	—		$	389,381
	Foreign		—			—			2,190			—			2,190

Total Revenues			53,606			201,107			136,858			—			391,571
Gross Margin			20,095			4,972			14,497			—			39,564
Depreciation and Amortization			(4,078	)		(21	)		(3,015	)		(431	)		(7,545	)
	General and Administrative, including taxes other than income		—			—			—			(8,431	)		(8,431	)
Interest Expense			—			—			—			(6,533	)		(6,533	)
Other, net			—			—			—			(2,865	)		(2,865	)

Income before Income Taxes and extraordinary charge		$	16,017		$	4,951		$	11,482		$	(18,260	)	$	14,190

Assets
	Domestic	$	348,017		$	23,937		$	81,770		$	9,821		$	463,545
	Foreign		—			—			14,827			—			14,827

Total Assets		$	348,017		$	23,937		$	96,597		$	9,821		$	478,372

Capital Expenditures (excluding acquisitions)		$	8,753		$	143		$	3,928		$	3,738		$	16,562

Note 16. Unusual Charge:

During the fourth quarter of fiscal 1999, the Company recorded a pre-tax unusual charge totaling $2.7 million ($2.2 million after tax) related to the restructuring efforts announced in November 1999. The charge primarily related to the severance and benefits of approximately 50 employees who were involuntarily terminated. All employees had been terminated by December 31, 2000 and the accrued liability was reduced to nil.

F-33

Unaudited Pro Forma Financial Statements

Introduction

The following pro forma financial information has been prepared to assist in your analysis of the financial effects of the acquisition by Enbridge Partners of Enbridge Midcoast Energy, which includes the Northeast Texas, South Texas, compression and Hobart Ranch asset acquisitions. The acquisition excludes certain Canadian and other assets that were retained by Enbridge Energy Company.

The pro forma consolidated statement of financial position presents the combined financial position of Enbridge Partners and the acquisitions assuming they had occurred as of June 30, 2002. In addition, the results of operations of Enbridge Partners and the acquisitions have also been combined for the six months ended June 30, 2002 and 2001, and for the year ending December 31, 2001. The pro forma consolidated statements of income assume the acquisition was effective as of the beginning of the fiscal period presented. This pro forma information is based on the following information:

•: The audited and unaudited financial statements of Enbridge Midcoast Energy. Financial data is adjusted as necessary to include the Northeast Texas, South Texas, compression and Hobart Ranch acquisitions, all of which closed on October 17, 2002. Enbridge Midcoast Energy acquired the South Texas system on January 2, 2002, the Northeast Texas system on March 1, 2002, the Hobart Ranch assets on May 1, 2002, $12.6 million of compression assets on June 30, 2002 and the remaining $7.5 million of the compression assets effective September 1, 2002. The pro forma as adjusted financial information reflects the results of operations of these systems as of the beginning of the period presented.
•: Financial data of the Northeast Texas, South Texas, compression and Hobart Ranch assets are unaudited. This financial data was largely derived from the records of previous owners and is believed to be reliable.
•: The acquisition is being accounted for using the purchase method of accounting. Under the purchase method of accounting, the assets acquired (including intangible assets) and the liabilities assumed are recorded at fair market value rather than historical book value of the predecessor companies. Any excess purchase price over fair market value of assets is attributed to goodwill.
•: The acquisition by Enbridge Partners of the acquired systems for $820 million, consisting of the assumption of $805 million in debt related to the acquired systems, payment of $6.5 million in cash and issuance of an additional $8.5 million equity interest in Enbridge Partners to Enbridge Energy Company.
•: The receipt by Enbridge Partners of $332.7 million in proceeds from the sale of its i-units to Enbridge Energy Management, L.L.C. ("Enbridge Management"), which represents 9,000,000 shares at $39.00 per share, net of the underwriting discount, expected expenses and $500,000 paid by Enbridge Management to Enbridge Inc. in respect of its purchase obligation and tax indemnities, and the use by Enbridge Partners of these proceeds to repay a portion of the debt it assumed in connection with the acquisition.
•: Cash distributions per unit by Enbridge Partners in each quarter of 2001 are assumed to be unaffected by the acquisition of Enbridge Midcoast Energy. Distributions by Enbridge Partners of its available cash, as defined in the partnership agreement, generally are made 98.0% to the common unitholders and 2.0% to the general partner of Enbridge Partners, subject to the payment of incentive distributions to the general partner of Enbridge Partners to the extent that certain target levels of cash distributions to the common unitholders are

F-34

achieved. The incremental incentive distributions payable to the general partner of Enbridge Partners are 15.0%, 25.0% and 50.0% of all quarterly distributions of available cash that exceed target levels of $0.59, $0.70 and $0.99 per common unit, respectively. Due to the incentive distributions received by the general partner of Enbridge Partners, an increase in the level of distributions per unit paid to limited partners will result in a disproportionate sharing of cash available for distribution in favor of the General Partner. As a result, the net earnings per unit attributable to common unitholders would decline assuming no other changes in other income statement items. Conversely, a reduction in the level of cash distributed per unit paid to unitholders would reduce the General Partner's share of income, thereby improving net income per unit to the limited partners. For the year ended December 31, 2001 and the six months ended June 30, 2001 and 2002, the pro forma incentive distribution to the general partner of Enbridge Partners increased, while pro forma net income decreased. This was a result of the assumed issuance of 9 million new units for pro forma purposes and cash distributions on such units.

•: Enbridge Partners' objective is to continue to increase cash distributions to unitholders. The cash distribution policy and the amount of quarterly cash distributions of Enbridge Partners will be determined by the Board of Directors of Enbridge Management. The Board of Directors periodically reviews the distribution policy whereby it considers a number of factors including the amount of cash available to Enbridge Partners for distribution to unitholders, the amount and timing of capital expenditures and the target capital structure of the Partnership. Enbridge Partners anticipates that it will continue to have adequate liquidity to fund future cash distributions at current levels from operating cash flows.
•: Enbridge Partners incurs no U.S. federal income tax liability; accordingly, no income tax expense is reflected in pro forma results of operations.

The purpose of pro forma as adjusted financial information is to illustrate the results of operations given the effect of certain transactions. The pro forma as adjusted financial information presented here is not necessarily indicative of full year results of the combined entity on a recurring basis due, among other things, to the following:

•: During the first four months of 2001, Enbridge Midcoast Energy's results of operations were impacted by a series of charges totaling approximately $13 million, primarily associated with natural gas imbalance accounts, operational balancing agreements and the failure to capture certain marketing transactions. These charges were the result of the volatility of prices in the natural gas market in late 2000 and early 2001.
•: Enbridge Midcoast Energy has completed the Bamagas project, which has contributed approximately $0.4 million of EBITDA per month beginning in February 2002. Results from this project and other projects and agreements, including an agreement Enbridge Midcoast Energy has with a major oil company to transport propylene, have not been included in the pro forma financial information.
•: The pro forma as adjusted financial information reflects a major plant turn-around on the Northeast Texas system in the December 2001 to February 2002 time period. The pro forma as adjusted financial information has not been adjusted to reflect the impact of the plant turn-around.
•: The results of operations of Enbridge Midcoast Energy for 2001 were abnormally impacted by other charges including expenses related to the sale of Enbridge Midcoast Energy to Enbridge Energy Company in early 2001, and acquisition integration costs.

The pro forma information is presented for illustrative purposes only. If the acquisition of Enbridge Midcoast Energy had occurred in the past, Enbridge Partner's financial position, and results of operations, could have been materially different than that represented in the pro forma financial information. The pro forma financial information should not be considered indicative of results of future operations following the acquisition of Enbridge Midcoast Energy.

F-35

Unaudited Pro Forma Consolidated Statement of Income

Year Ended December 31, 2001

		Enbridge Partners			Enbridge Midcoast Energy			Midcoast Pro Forma Adjustments			Other Assets Pro Forma Adjustments		Depreciation and Financing Related Pro Forma Adjustments			Pro Forma Results
		(Audited)
		(In millions, except per unit amounts)
								(Note 3)			(Note 4)		(Note 2 & 6)
Revenues:
	Transportation	$	311.7		$	51.8		$	(4.2	)	$	4.1	$	—		$	363.4
	Energy marketing		26.1			755.2			(1.9	)		135.8		—			915.2
	Processing		2.6			38.4			(3.0	)		15.7		—			53.7

			340.4			845.4			(9.1	)		155.6		—			1,332.3
Expenses:
	Power		49.9			—			—			—		—			49.9
	Cost of natural gas		26.3			755.5			(2.1	)		105.2		—			884.9
	Operating and administrative		104.5			66.6			(3.6	)		21.7		—			189.2
	Depreciation and amortization (Note 6)		63.8			21.2			(1.1	)		—		6.4			90.3

			244.5			843.3			(6.8	)		126.9		6.4			1,214.3

Operating income			95.9			2.1			(2.3	)		28.7		(6.4	)		118.0
Interest and other income			2.8			0.8			—			—		—			3.6
Interest expense			(59.3	)		(23.4	)		23.4			—		(33.5	)		(92.8	)

Income (loss) before minority interest			39.4			(20.5	)		21.1			28.7		(39.9	)		28.8
Minority interest			(0.5	)		(0.1	)		—			—		—			(0.6	)

Net income (loss)		$	38.9		$	(20.6	)	$	21.1		$	28.7	$	(39.9	)	$	28.2

Net income allocated to limited partners		$	29.8													$	15.6

Net income per unit		$	0.98													$	0.40

Weighted average units outstanding (millions)			30.2											9.0			39.2

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

F-36

Unaudited Pro Forma Consolidated Statement of Income

Six Months Ended June 30, 2001

		Enbridge Partners			Enbridge Midcoast Energy			Midcoast Pro Forma Adjustments			Other Assets Pro Forma Adjustments		Depreciation and Financing Related Pro Forma Adjustments			Pro Forma Results
		(In Millions, except per unit amounts)
								(Note 3)			(Note 4)		(Note 2 & 6)
Revenues:
	Transportation	$	153.0		$	33.2		$	(2.5	)	$	1.9				$	185.6
	Natural gas gathering and marketing		—			435.3			(1.7	)		69.7					503.3
	Processing		—			69.7			(1.7	)		7.3					75.3

			153.0			538.2			(5.9	)		78.9					764.2
Expenses:
	Power		24.5			—			—			—					24.5
	Cost of natural gas		—			501.6			(1.7	)		59.3					559.2
	Operating and administrative		46.8			38.5			(2.1	)		10.4					93.6
	Depreciation and amortization (Note 6)		31.1			10.0			(0.7	)		—		3.8			44.2

			102.4			550.1			(4.5	)		69.7		3.8			721.5

Operating income			50.6			(11.9	)		(1.4	)		9.2		(3.8	)		42.7
Interest and other income			1.5			0.6			—			—					2.1
Interest expense			(30.2	)		(12.4	)		12.4			—		(16.7	)		(46.9	)

Income (loss) before minority interest			21.9			(23.7	)		11.0			9.2		(20.5	)		(2.1	)
Minority interest			(0.2	)		(0.1	)		—			—		—			(0.3	)

Net (loss) income		$	21.7		$	(23.8	)	$	11.0		$	9.2	$	(20.5	)	$	(2.4	)

Net income (loss) allocated to common unitholders		$	17.3													$	(8.6	)

Net income (loss) per unit		$	0.59													$	(0.22	)

Weighted average units outstanding (millions)			29.3											9.0			38.3

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

F-37

Unaudited Pro Forma Consolidated Statement of Income

Six Months Ended June 30, 2002

		Enbridge Partners			Enbridge Midcoast Energy			Midcoast Pro Forma Adjustments			Other Assets Pro Forma Adjustments		Depreciation and Financing Related Pro Forma Adjustments			Pro Forma Results
		(In Millions, except per unit amounts)
								(Note 3)			(Note 4)		(Note 2 & 6)
Revenues:
	Transportation	$	164.4		$	43.5			—			—		—		$	207.9
	Natural gas gathering and marketing		223.5			209.1			—			12.3		—			444.9
	Processing		16.0			226.6			(2.4	)		5.2		—			245.4

			403.9			479.2			(2.4	)		17.5		—			898.2
Expenses:
	Power		26.0			—			—			—		—			26.0
	Cost of natural gas		220.4			412.4			(0.4	)		13.4		—			645.8
	Operating and administrative		58.7			37.1			(1.0	)		1.3		—			96.1
	Depreciation and amortization (Note 6)		36.9			11.3			(0.4	)		—		0.1			47.9

			342.0			460.8			(1.8	)		14.7		0.1			815.8

Operating income			61.9			18.4			(0.6	)		2.8		(0.1	)		82.4
Interest and other income			1.2			0.8			(0.4	)		—		—			1.6
Interest expense			(28.2	)		(11.3	)		11.3			—		(16.7	)		(44.9	)

Income (loss) before minority interest			34.9			7.9			10.3			2.8		(16.8	)		39.1
Minority interest			(0.4	)		—			—			—		—			(0.4	)

Net income (loss)		$	34.5		$	7.9		$	10.3		$	2.8	$	(16.8	)	$	38.7

Net income allocated to common unitholders		$	28.3													$	30.6

Net income per unit		$	0.82													$	0.70

Weighted average units outstanding (millions)			34.4											9.0			43.4

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

F-38

Unaudited Pro Forma Consolidated Statement of Financial Position

June 30, 2002

		Enbridge Partners			Pro Forma Acquired Assets and Liabilities		Pro Forma Financing and Other Adjustments			Pro Forma Results
		(In Millions)
					(Note 1)		(Note 2)
Assets
Current Assets
	Cash and cash equivalents	$	53.9			—	$	(2.0	)	$	51.9
	Advances to affiliate		2.7			—		—			2.7
	Accounts receivable and other		79.1			120.4		—			199.5
	Materials, supplies and inventory		8.2			7.3		—			15.5

			143.9			127.7		(2.0	)		269.6
Goodwill			15.0			190.0		—			205.0
Other assets			25.4			3.0		2.0			30.4
Property, plant and equipment, net			1,556.3			659.3		—			2,215.6

		$	1,740.6		$	980.0	$	—		$	2,720.6

Liabilities and Partners' Capital
Current Liabilities
	Due to General Partner and affiliate	$	14.8		$	27.5		—		$	42.3
	Accounts payable and other		96.3			100.2		—			196.5
	Loans from General Partner		58.5			—		—			58.5
	Current maturities and short-term debt		168.0			—		—			168.0

			337.6			127.7		—			465.3
Long-term debt			708.4			813.5		(332.7	)		1,189.2
Minority interest			3.3			—		—			3.3
Deferred credits			4.8			30.3		—			35.1

			1,054.1			971.5		(332.7	)		1,692.9
Partners' Capital
	Class A common unitholders		633.3			—		—			633.3
	Class B common unitholders		51.8			—		—			51.8
	Class I common unitholder		—			—		332.7			332.7
	General Partner		7.6			8.5		—			16.1
	Accumulated other comprehensive loss		(6.2	)		—		—			(6.2	)

			686.5			8.5		332.7			1,027.7

		$	1,740.6		$	980.0	$	—		$	2,720.6

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

F-39

Notes to the Unaudited Pro Forma Consolidated Financial Statements

(in millions, except per unit amounts)

1. Accounting for the acquisition

New accounting standards require that Enbridge Partners account for the acquisition of Enbridge Midcoast Energy using the purchase method of accounting. Accordingly, all assets and liabilities of Enbridge Midcoast Energy are being valued at fair market value with excess purchase price assigned to goodwill.

The purchase price assumed in the pro forma financial statements is based upon the purchase price negotiated between Enbridge Energy Company and a special committee of Enbridge Energy Company's Board of Directors on behalf of Enbridge Partners. The special committee engaged independent financial and legal advisors to assist with evaluation of the transaction.

Fair market value of working capital items is expected to approximate book value. Property, plant and equipment, intangible assets, and goodwill will be valued through an independent appraisal process to be undertaken in connection with the acquisition of Enbridge Midcoast Energy. Due to the recent timing of the Enbridge Midcoast Energy acquisition by Enbridge Energy Company in May 2001, it is expected that amounts disclosed on the statement of financial position will not vary materially from that indicated in the pro forma statement of financial position.

The purchase price of $820.0 million plus acquisition costs of $2 million was allocated at the acquisition date to the assets acquired and the liabilities assumed as follows:

			($ millions)
Assets Acquired:
	Accounts Receivable and Other		$	118.4
	Materials, Supplies and Inventory			7.3
	Goodwill			190.0
	Other Assets			5.0
	Property, Plant & Equipment, Net			659.3

				980.0
Less—Liabilities Assumed:
	Current Liabilities			127.7
	Other Deferred Costs			30.3

				158.0

		Total Purchase Price	$	822.0

The pro forma statement of financial position reflects goodwill of $190.0 million. In addition, approximately $3 million has been assigned as the fair market value of other intangible assets pending completion of the formal asset appraisal. Under new accounting standards, goodwill is no longer subject to annual amortization. However, it is subject to annual impairment testing. Other intangible assets are expected to be largely comprised of customer contracts, potential customer lists, and certain regulatory assets associated with our FERC regulated companies. These assets are expected to be relatively minor and will be amortized over a period not to exceed the remaining life of the underlying Enbridge Midcoast Energy pipeline systems.

Fair market value of the property, plant and equipment is estimated to be $659.3 million. Pipeline systems underlying this value are depreciated over their varying economic useful lives. For purposes of the pro forma calculations, a composite life of 30 years has been assumed as it

F-40

approximates the results obtained by using the estimated useful lives of the underlying individual assets based on preliminary estimates of fair market value.

As Enbridge Partners incurs no U.S. federal income tax liability, no tax adjustments impact the pro forma financial statements.

2. Transaction financing, issuance of equity and retirement of long-term debt

The acquisition was financed through the assumption of approximately $487 million of existing Enbridge Midcoast Energy debt and approximately $318 million of existing Enbridge Energy Company debt.

The proceeds of the equity offering are being used to repay a portion of the assumed debt. The remaining assumed debt will be refinanced with longer term debt. The pro forma statement of financial position and related results of operation reflect the issuance of 9,000,000 new limited partner interests called i-units by Enbridge Partners at $39.00 per unit, before underwriting and transaction costs. A corresponding 2% contribution, approximating $8.5 million, by Enbridge Energy Company, as general partner, is required.

Debt financing is assumed to bear an interest rate of 6.96%. This interest rate is based on the assumption that 80% of the debt requirement is funded with long term debt and 20% is funded with short term debt. The long term debt financing cost is estimated at 7.6%, which is based on an estimated yield for 10-year United States Treasury Bonds plus an estimated credit spread applicable to Enbridge Partners. The short term debt financing cost is estimated at 4.5%, which is based on 3-month Libor plus a credit spread applied to borrowings under Energy Partners existing revolving bank credit facilities. If interest rates vary ¹/8 of one-percent from the assumed rate interest expense will increase or decrease by approximately $0.6 million.

3. Enbridge Midcoast Energy adjustments to results of operations

The acquisition of Enbridge Midcoast Energy does not include certain Canadian and other assets that were retained by Enbridge Energy Company. The results of operations of these assets,

F-41

together with other assets disposed of in 2001, are reflected in this column for each of the noted periods. The adjustments are summarized as follows (in millions):

		Year Ended December 31, 2001			Six Months Ended June 30, 2002
		Canadian Assets	Assets Sold	Total	Canadian Assets	Assets Sold	Total
Revenues:
	Transportation	3.4	0.8	4.2	—	—	—
	Energy marketing	1.9	—	1.9	1.5	—	1.5
	Processing	3.0	—	3.0	0.9	—	0.9

		8.3	0.8	9.1	2.4	—	2.4
Expenses
	Cost of natural gas	2.1	—	2.1	0.4	—	0.4
	Operating and administrative	3.6	—	3.6	1.0	—	1.0
	Depreciation and amortization	0.9	0.2	1.1	0.4	—	0.4

		6.6	0.2	6.8	1.8	—	1.8

Operating income		1.7	0.6	2.3	0.6	—	0.6

Enbridge Energy Company recognized goodwill on its acquisition of Enbridge Midcoast Energy. Under accounting standards in effect during 2001, Enbridge Midcoast Energy amortized goodwill as required. Effective January 1, 2002, goodwill is no longer subject to amortization. Goodwill amortization of the $4.6 million is included in historical depreciation and amortization amount for the year-ended December 31, 2001.

4. Acquired assets adjustments to results of operations

Enbridge Midcoast Energy acquired the South Texas assets in January 2002, the Northeast Texas assets in March 2002, and the Hobart assets in May 2002. Enbridge Midcoast Energy's results of operations include the contributions of these assets from their dates of acquisition. Enbridge Midcoast Energy acquired compression assets of $12.6 million on June 30, 2002 and $7.5 million effective September 1, 2002. The pro forma results of operations for the compression assets are included in the Other Assets Pro Forma Adjustments column. The following table highlights the adjustments required to show the full-period impact of the purchases of the South Texas, Northeast Texas, Hobart and compression assets as if they had been owned by Enbridge

F-42

Midcoast Energy since January 1, 2001. These adjustments are based on unaudited financial information provided by third parties.

		Year Ended December 31, 2001						Six Months Ended June 30, 2002
		South Texas	Northeast Texas	Hobart	Compression		Total	South Texas	Northeast Texas		Hobart	Compression		Total
					(a)			(b)	(c)
Revenues:
	Transportation	—	4.1	—	—		4.1	—	—		—	—		—
	Energy marketing	—	135.8	—	—		135.8	—	12.3		—	—		12.3
	Processing	2.9	7.0	5.8	—		15.7	—	3.3		1.9	—		5.2

		2.9	146.9	5.8	—		155.6	—	15.6		1.9	—		17.5
Expenses
	Cost of natural gas	—	101.2	4.0	—		105.2	—	12.1		1.3	—		13.4
	Operating and administrative	2.1	24.6	0.9	(5.9	)	21.7	—	4.0		0.3	(3.0	)	1.3

		2.1	125.8	4.9	(5.9	)	126.9	—	16.1		1.6	(3.0	)	14.7

Operating margin		0.8	21.1	0.9	5.9		28.7	—	(0.5	)	0.3	3.0		2.8

		Six Months Ended June 30, 2001
		South Texas	Northeast Texas	Hobart	Compression		Total
Revenues:
	Transportation	—	1.9	—	—		1.9
	Energy marketing	—	69.7	—	—		69.7
	Processing	1.4	3.0	2.9	—		7.3

		1.4	74.6	2.9	—		78.9
Expenses
	Cost of natural gas	—	57.3	2.0	—		59.3
	Operating and administrative	1.1	11.9	0.4	(3.0	)	10.4

		1.1	69.2	2.4	(3.0	)	69.7

Operating margin		0.3	5.4	0.5	3.0		9.2

(a): This column reflects the pro forma impact of the acquisition of natural gas compression assets. These assets were leased by the previous owner of the Northeast Texas system at a net annual cost of $5.9 million. Enbridge Midcoast Energy acquired $20.1 million of these compression assets on or subsequent to June 30, 2002. Ownership of these assets would have reduced operating and administrative expenses, resulting in an increase in operating margin of $5.9 million on a pro forma basis. The purchase price of the compression assets is being financed by short-term borrowings. The depreciation and interest expense related to this acquisition are reflected in the Depreciation and Financing Related Pro Forma Adjustments column in the Consolidated Statements of Income for the Year Ended December 31, 2001 and the Six Months Ended June 30, 2002. The cost of the assets and the related debt are reflected in the Pro Forma Acquired Assets and Liabilities column in the Consolidated Statement of Financial Position as at June 30, 2002.
(b): Included in Enbridge Midcoast Energy's results of operations from January 1, 2002 forward therefore no adjustment is necessary in this period.

F-43

(c): Included in Enbridge Midcoast Energy's results of operations from March 1, 2002 forward therefore the adjustment reflects operating data for January and February of 2002.

5. Net Income allocated to limited partners

Net income allocated to limited partners is computed by subtracting income allocated to the General Partner, incentive distributions and historical cost depreciation adjustments from net income. Net income allocated to the General Partner is equal to an amount based upon its 1% general partner interest in Enbridge Partners, while incentive distributions depend upon the amount of cash distributions per unit paid to unitholders. Distributions by Enbridge Partners of its available cash, as defined in the partnership agreement, generally are made 98.0% to the common unitholders and 2.0% to the General Partner, subject to the payments of incentive distributions to the General Partner to the extent that certain target levels of cash distributions to the common unitholders are achieved. The incremental incentive distributions payable to the General Partner are 15.0%, 25.0% and 50.0% of all quarterly distributions of available cash that exceed target levels of $0.59, $0.70 and $0.99 per common unit, respectively. Historical cost depreciation adjustments reflect depreciation on the General Partner's historical cost basis of the assets contributed to Enbridge Partners in 1991.

	Year Ended December 31, 2001					Six Months Ended June 30, 2002
($ in millions)	Enbridge Partners		Proforma Results			Enbridge Partners		Proforma Results
Net income	$	38.9	$	28.2		$	34.5	$	38.7
Less:
Net income allocated to general partner		0.4		0.5			0.3		0.5
Incentive distributions		8.6		12.0	(A)		5.8		7.5	(A)
Historical cost depreciation adjustments		0.1		0.1			0.1		0.1

Net income allocated to limited partners	$	29.8	$	15.6		$	28.3	$	30.6

Among other factors, the level of net income allocated to limited partners will be primarily dependent upon the results of operations, the amount of quarterly distributions per unit paid to unitholders and the number of units outstanding.

Note (A)

2001 Simplified Pro Forma Incentive Income Recalculation:
	Distribution per Unit; $0.875 per quarter or $3.50 annually		$3.50

F-44

Weighted Average Units Outstanding for Distribution Calculation

39,900,000

(b)

	Quarterly Per Unit Amount	Annual Per Unit Amount	Limited Partner's Percentage		General Partner's Percentage		Total Cash for Limited Partners		Total Cash for General Partner		Total Cash
Minimum quarterly distribution	$0.00-$0.59	$0.00-$2.36	99	%	1	%	$	94.2	$	1.0	$	95.2
First target distribution	$0.59-$0.70	$2.36-$2.80	85	%	15	%		17.6		3.1		20.7
Second target distribution	$0.70-$0.99	$2.80-$3.96	75	%	25	%		27.9		9.3		37.2
Thereafter	$0.99 and above	$3.96 and above	50	%	50	%		0.0		0.0		0.0
Total Cash							$	139.7	$	13.4	$	153.1
General Partner minimum distribution based on 1% ownership percentage									$	1.4
Incentive Income to General Partner									$	12.0

2002 Simplified Pro Forma Incentive Income Recalculation:
	Distribution per Unit; $0.90 per quarter or $1.80 semi-annually	$1.825	(c)
	Weighted Average Units Outstanding for Distribution Calculation	44,200,000

	Quarterly Per Unit Amount	Semi-annual Per Unit Amount	Limited Partner's Percentage		General Partner's Percentage		Total Cash for Limited Partners		Total Cash for General Partner			Total Cash
Minimum quarterly distribution	$0.00-$0.59	$0.00-$1.18	99	%	1	%	$	52.2	$	0.5		$	52.7
First target distribution	$0.59-$0.70	$1.18-$1.40	85	%	15	%		9.7		1.7			11.4
Second target distribution	$0.70-$0.99	$1.40-$1.98	75	%	25	%		18.8		6.3			25.1
Thereafter	$0.99 and above	$1.98 and above	50	%	50	%		0.0		0.0			0.0
Total Cash							$	80.7	$	8.5		$	89.2
General Partner minimum distribution based on 1% ownership percentage									$	0.8
Incentive Income to General Partner									$	7.7	(a)

Explanatory Notes:

(a): Amount of incentive income will approximate total noted above due to rounding and other simplifying assumptions.
(b): Number of units outstanding varies from the value used for weighted average units outstanding ("WAUOS") in net income per unit calculation due to WAUOS being computed based on the date units are issued. For distribution purposes, if unit is outstanding on or before the record date, a full quarter's distribution is attributed to the unit outstanding.
(c): Incentive income for the fourth quarter of 2001 was not accrued based on the proposed distribution increase as the Board of Directors had not approved the increase as at December 31, 2001. The increase is included in the first quarter of 2002 and is reflected in the $1.825 rate of distribution above.

6. Depreciation and amortization

The depreciation adjustment noted in column "Depreciation and Financing Related Pro Forma Adjustments" is the increase necessary to balance depreciation expense for the pro forma period to the amount implied by the 30-year composite depreciable life assumed for the acquired pipeline systems. The 30-year composite depreciable life is not expected to differ materially from the results obtained by using the estimated useful lives of the underlying individual assets.

F-45

EXHIBIT INDEX

Exhibit No.		Description
23.1		Consent of PricewaterhouseCoopers LLP.
99.1		Contribution Agreement, dated as of May 16, 2002, between Enbridge Energy Company, Inc. ("Enbridge Energy") and Enbridge Energy Partners, L.P. (the "Registrant") (incorporated by reference to Exhibit 10.1 to Amendment No. 1 to the Registrant's Registration Statement on Form S-3, as filed with the SEC on July 8, 2002; SEC File No. 333-89588).
99.2		First Amendment to Contribution Agreement, dated as of September 23, 2002, between Enbridge Energy and the Registrant (incorporated by reference to Exhibit 10.8 to Amendment No. 4 to the Registrant's Registration Statement on Form S-3, as filed with the SEC on September 24, 2002; SEC File No. 333-89588).
99.3		Second Amendment to Contribution Agreement, dated as of October 17, 2002.

QuickLinks