Enbridge Energy Partners 8-K Consolidated Statements of Financial Position

EXHIBIT 99.1

ENBRIDGE ENERGY COMPANY, INC.

(a wholly-owned subsidiary of Enbridge Pipelines Inc.)

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

	June 30,     2009		December 31, 2008
	(unaudited; dollars in millions)
ASSETS
Current assets
Cash and cash equivalents (Note 4)	$	188.4	$	350.3
Restricted cash (Note 4)		—		0.1
Due from affiliates		31.6		58.8
Receivables, trade and other, net of allowance for doubtful accounts of $2.0 in 2009 and $2.6 in 2008		134.4		108.4
Accrued receivables		384.4		507.3
Loans to affiliates (Note 9)		459.9		460.4
Inventory (Note 5)		57.4		53.0
Other current assets (Note 11)		44.6		81.7
		1,300.7		1,620.0
Long-term loans to affiliates (Note 9)		639.3		608.9
Property, plant and equipment, net (Note 6)		8,540.6		8,021.7
Deferred tax assets (Note 8)		4.0		4.1
Other assets, net (Note 11)		196.0		221.5
Goodwill		366.2		366.2
Intangibles, net		96.7		98.6
	$	11,143.5	$	10,941.0
LIABILITIES AND SHAREHOLDER’S EQUITY
Current liabilities
Accounts payable and other (Notes 10 and 11)	$	229.2	$	352.3
Accrued purchases		327.0		381.2
Due to affiliates		39.3		41.2
Other current liabilities		84.0		66.8
Loans from affiliates (Note 9)		418.3		505.1
Current maturities of long-term debt (Notes 7 and 11)		251.4		420.7
		1,349.2		1,767.3
Long-term debt (Notes 7 and 11)		4,555.9		4,073.4
Loans from affiliates (Note 9)		768.8		668.9
Deferred tax liabilities (Note 8)		362.4		351.8
Other long-term liabilities (Notes 10 and 11)		165.7		182.7
		7,202.0		7,044.1
Commitments and contingencies (Note 10)
Shareholder’s equity
Common stock: Authorized—1,500,000 shares; issued—927,252 at June 30, 2009 and December 31, 2008; no par value		—		—
Contributed surplus		685.8		685.0
Retained earnings		677.0		617.3
Accumulated other comprehensive income (Notes 11 and 12)		47.9		5.7
Total Enbridge Energy Company, Inc. shareholder’s equity		1,410.7		1,308.0
Noncontrolling interest		2,530.8		2,588.9
Total shareholder’s equity		3,941.5		3,896.9
	$	11,143.5	$	10,941.0

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

F-1

ENBRIDGE ENERGY COMPANY, INC.

NOTES TO THE CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

(UNAUDITED)

1. NATURE OF OPERATIONS

Enbridge Energy Company, Inc. referred to herein as “we”, “us”, “our” and the “Company,” is the general partner of Enbridge Energy Partners, L.P. (the “Partnership”). We are owned directly by Enbridge Pipelines Inc. (“Enbridge Pipelines”), a Canadian corporation wholly-owned by Enbridge Inc. (“Enbridge”) of Calgary, Alberta, Canada.

We are the sole general partner of the Partnership and are responsible for its management. In October 2002, we delegated substantially all of our responsibility for the management of the Partnership to our affiliate, Enbridge Energy Management, L.L.C. (“Enbridge Management”). We retain certain functions and approval rights over the operations of the Partnership and have ownership interests in the Partnership at June 30, 2009 and December 31, 2008, as follows:

Ownership Interest	June 30,     2009		December 31, 2008
General Partner interest	2.0	%	2.0	%
Limited Partner interest (1)	22.7	%	22.8	%
Direct ownership	24.7	%	24.8	%
Effective ownership through Enbridge Management(2)	2.3	%	2.2	%
Direct and indirect ownership	27.0	%	27.0	%

⁽¹⁾ We owned 16,250,000 Class A common units, 3,912,750 Class B common units and 6,837,920 Class C units at June 30, 2009. At December 31, 2008, we owned 16,250,000 Class A common units, 3,912,750 Class B common units and 6,449,315 Class C units. The Class A and B common units coupled with the Class C units represent our limited partner ownership interests in the Partnership.

⁽²⁾ We owned 2,701,205 and 2,542,527 Listed and Voting Shares of Enbridge Management at June 30, 2009 and December 31, 2008, respectively, which equates to an indirect limited partner ownership interest in the Partnership.

In addition to our general partner and limited partner ownership interests in the Partnership, we also have operations that include the Spearhead and Frontier crude oil pipelines, an equity interest in the Olympic refined products pipeline and organizations that provide financial and support services in the United States and Canada.

Our wholly-owned subsidiary, Enbridge Employee Services, Inc. (“EES”), provides employees and employee benefits services to us, and our affiliates including Enbridge Management and the Partnership (collectively, the “Group”). Employees of EES are assigned to work for one or more members of the Group.

The Partnership is a publicly-traded Delaware limited partnership that owns and operates crude oil and liquid petroleum transportation and storage assets, and natural gas gathering, treating, processing, transportation and marketing assets in the United States of America. The Partnership provides the following services:

• Interstate pipeline transportation and storage of crude oil and liquid petroleum;

• Gathering, treating, processing and transportation of natural gas and natural gas liquids, or NGLs, through pipelines and related facilities; and

• Supply, transportation and sales services, including purchasing and selling natural gas and NGLs.

2. BASIS OF PRESENTATION

We have prepared the accompanying unaudited interim consolidated statements of financial position in accordance with accounting principles generally accepted in the United States of America for interim consolidated financial information. Accordingly, they do not include all the information and footnotes required

F-2

by accounting principles generally accepted in the United States of America for complete consolidated financial statements. In the opinion of management, they contain all adjustments, consisting only of normal recurring adjustments, which management considers necessary to present fairly our financial position at June 30, 2009 and December 31, 2008. Our interim consolidated statements of financial position should be read in conjunction with our consolidated statements of financial position and notes thereto as of December 31, 2008, included in the Form 8-K filed by the Partnership on June 23, 2009.

We have made changes to the presentation of amounts reported in our prior year consolidated statement of financial position to conform to our current year presentation. Beginning January 1, 2009, in conjunction with our adoption of the provisions of Financial Accounting Standard No. 160,Noncontrolling Interest in Consolidated Financial Statements,an amendment of ARB No. 51 (“SFAS 160”), we revised our presentation of our statement of financial position to include “Noncontrolling interest” in the “Shareholder’s equity” section of the statement.

3. CONSOLIDATION OF ENBRIDGE ENERGY PARTNERS, L.P.

Our consolidated statements of financial position and related notes include the accounts of the Partnership on a consolidated basis after elimination of all significant intercompany transactions. The following consolidating schedules present our consolidated statements of financial position before and after consolidation of the Partnership and the related eliminating entries as of June 30, 2009 and December 31, 2008:

F-3

Consolidating Statement of Financial Position as of June 30, 2009

	Enbridge Energy Company, Inc.		Enbridge Energy Partners, L.P.			Combined Before  Eliminations			Eliminations			Enbridge Energy Company, Inc. Consolidated
	(in millions)
ASSETS
Current assets
Cash and cash equivalents	$	55.7	$	132.7		$	188.4		$	—		$	188.4
Due from affiliates		46.3		19.0			65.3			(33.7	)		31.6
Receivables, trade and other, net of allowance for doubtful accounts of $2.0		9.3		125.1			134.4			—			134.4
Accrued receivables		—		384.4			384.4			—			384.4
Loans to affiliates		459.9		—			459.9			—			459.9
Inventory		0.2		57.2			57.4			—			57.4
Other current assets		1.0		44.9			45.9			(1.3	)		44.6
		572.4		763.3			1,335.7			(35.0	)		1,300.7
Long-term loans to affiliates		639.3		—			639.3			—			639.3
Investment in Enbridge Energy Partners, L.P.		1,763.0		—			1,763.0			(1,763.0	)		—
Property, plant and equipment, net		1,247.2		7,293.4			8,540.6			—			8,540.6
Deferred tax assets		4.0		—			4.0			—			4.0
Other assets, net		120.0		76.0			196.0			—			196.0
Goodwill		25.0		256.5			281.5			84.7			366.2
Intangibles, net		9.9		86.8			96.7			—			96.7
	$	4,380.8	$	8,476.0		$	12,856.8		$	(1,713.3	)	$	11,143.5
LIABILITIES AND SHAREHOLDER’S EQUITY
Current liabilities
Accounts payable and other	$	82.7	$	147.8		$	230.5		$	(1.3	)	$	229.2
Accrued purchases		—		327.0			327.0			—			327.0
Due to affiliates		24.7		48.3			73.0			(33.7	)		39.3
Other current liabilities		—		84.0			84.0			—			84.0
Loans from affiliates		418.3		—			418.3			—			418.3
Current maturities of long term debt		—		251.4			251.4			—			251.4
		525.7		858.5			1,384.2			(35.0	)		1,349.2
Long-term debt		956.0		3,599.9			4,555.9			—			4,555.9
Loans from affiliates		638.8		130.0			768.8			—			768.8
Deferred tax liabilities		359.5		2.9			362.4			—			362.4
Other long-term liabilities		96.6		69.1			165.7			—			165.7
		2,576.6		4,660.4			7,237.0			(35.0	)		7,202.0
Commitments and contingencies
Shareholder’s equity
Common stock: Authorized—1,500,000 shares; issued—927,252; no par value		—		—			—			—			—
Partners capital		—		3,879.0			3,879.0			(3,879.0	)		—
Contributed surplus		685.8		—			685.8			—			685.8
Retained earnings		677.0		—			677.0			—			677.0
Accumulated other comprehensive income (loss)		47.9		(63.4	)		(15.5	)		63.4			47.9
Total Enbridge Energy Company, Inc. shareholders’ equity		1,410.7		3,815.6			5,226.3			(3,815.6	)		1,410.7
Noncontrolling interest		393.5		—			393.5			2,137.3			2,530.8
Total shareholder’s equity		1,804.2		3,815.6			5,619.8			(1,678.3	)		3,941.5
	$	4,380.8	$	8,476.0		$	12,856.8		$	(1,713.3	)	$	11,143.5

F-4

Consolidating Statement of Financial Position as of December 31, 2008

	Enbridge Energy Company, Inc.		Enbridge Energy Partners, L.P.		Combined Before  Eliminations		Eliminations			Enbridge Energy Company, Inc. Consolidated
	(in millions)
ASSETS
Current assets
Cash and cash equivalents	$	10.4	$	339.9	$	350.3	$	—		$	350.3
Restricted cash		—		0.1		0.1		—			0.1
Due from affiliates		58.7		40.5		99.2		(40.4	)		58.8
Receivables, trade and other, net of allowance for doubtful accounts of $2.6		5.4		103.0		108.4		—			108.4
Accrued receivables		—		507.3		507.3		—			507.3
Loans to affiliates		460.4		—		460.4		—			460.4
Inventory		—		53.0		53.0		—			53.0
Other current assets		1.0		80.7		81.7		—			81.7
		535.9		1,124.5		1,660.4		(40.4	)		1,620.0
Long-term loans to affiliates		608.9		—		608.9		—			608.9
Investment in Enbridge Energy Partners, L.P.		1,610.3		—		1,610.3		(1,610.3	)		—
Property, plant and equipment, net		1,298.8		6,722.9		8,021.7		—			8,021.7
Deferred tax assets		4.1		—		4.1		—			4.1
Other assets, net		113.2		108.3		221.5		—			221.5
Goodwill		25.0		256.5		281.5		84.7			366.2
Intangibles, net		9.9		88.7		98.6		—			98.6
	$	4,206.1	$	8,300.9	$	12,507.0	$	(1,566.0	)	$	10,941.0
LIABILITIES AND SHAREHOLDER’S EQUITY
Current liabilities
Accounts payable and other	$	127.0	$	225.3	$	352.3	$	—		$	352.3
Accrued purchases		—		381.2		381.2		—			381.2
Due to affiliates		39.4		42.2		81.6		(40.4	)		41.2
Other current liabilities		—		66.8		66.8		—			66.8
Loans from affiliates		505.1		—		505.1		—			505.1
Current maturities of long term debt		—		420.7		420.7		—			420.7
		671.5		1,136.2		1,807.7		(40.4	)		1,767.3
Long-term debt		850.0		3,223.4		4,073.4		—			4,073.4
Loans from affiliates		538.9		130.0		668.9		—			668.9
Deferred tax liabilities		349.2		2.6		351.8		—			351.8
Other long-term liabilities		100.9		81.8		182.7		—			182.7
		2,510.5		4,574.0		7,084.5		(40.4	)		7,044.1
Commitments and contingencies
Shareholder’s equity
Common stock: Authorized—1,500,000 shares; issued—927,252; no par value		—		—		—		—			—
Partners capital		—		3,714.0		3,714.0		(3,714.0	)		—
Contributed surplus		685.0		—		685.0		—			685.0
Retained earnings		617.8		—		617.8		(0.5	)		617.3
Accumulated other comprehensive income (loss)		5.7		12.9		18.6		(12.9	)		5.7
Total Enbridge Energy Company, Inc. shareholders’ equity		1,308.5		3,726.9		5,035.4		(3,727.4	)		1,308.0
Noncontrolling interest		387.1		—		387.1		2,201.8			2,588.9
Total shareholder’s equity		1,695.6		3,726.9		5,422.5		(1,525.6	)		3,896.9
	$	4,206.1	$	8,300.9	$	12,507.0	$	(1,566.0	)	$	10,941.0

F-5

4. CASH AND CASH EQUIVALENTS

We extinguish liabilities when a creditor has relieved us of our obligation, which occurs when our financial institution honors a check that the creditor has presented for payment. Accordingly, obligations for which we have issued check payments that have not yet been presented to the financial institution totaling approximately $23.4 million at June 30, 2009 and $31.9 million at December 31, 2008, are included in “Accounts payable and other” on our consolidated statements of financial position.

Bank of America, N.A., as administrative agent to the Partnership’s Second Amended and Restated Credit Agreement, which we refer to as the Credit facility, previously required the Partnership to provide cash collateral for a portion of its letters of credit outstanding under the terms of its Credit Facility that would have been obligations of Lehman Brothers Bank, FSB, which we refer to as Lehman BB. The amount of cash collateral required to be posted was $0.1 million at December 31, 2008. On March 31, 2009, the Partnership amended its Credit Facility to remove Lehman BB, which eliminated the collateral requirement imposed on the Partnership by Bank of America, N.A., as administrative agent. At June 30, 2009, no cash collateral was required and none of our cash and cash equivalents was restricted for use.

5. INVENTORY

Inventory is comprised of the following:

	June 30,     2009		December 31, 2008
	(in millions)
Material and supplies	$	4.2	$	3.9
Crude oil inventory		2.5		7.1
Natural gas and natural gas liquids inventory		50.7		42.0
	$	57.4	$	53.0

Our inventory at June 30, 2009 and December 31, 2008 is net of amounts totaling $3.4 million and $11.6 million, respectively, that we recorded to reduce the cost basis of our natural gas and natural gas liquids, or NGLs, inventory to reflect market value.

6. PROPERTY, PLANT AND EQUIPMENT, NET

Property, Plant and Equipment is comprised of the following:

	June 30,     2009			December 31, 2008
	(in millions)
Land	$	38.5		$	22.3
Rights-of-way		494.1			440.3
Pipelines		5,365.2			4,538.3
Pumping equipment, buildings and tanks		1,165.3			1,077.9
Compressors, meters, and other operating equipment		699.2			639.3
Vehicles, office furniture and equipment		164.7			154.8
Processing and treating plants		331.2			343.1
Construction in progress		1,744.4			2,133.2
Total property, plant and equipment		10,002.6			9,349.2
Accumulated depreciation		(1,462.0	)		(1,327.5	)
Property, plant and equipment, net	$	8,540.6		$	8,021.7

F-6

7. DEBT

Enbridge Energy Company, Inc.

U.S. Construction Facility

At June 30, 2009 and December 31, 2008, Enbridge Pipelines (Southern Lights), L.L.C. had $956.0 million and $850.0 million outstanding under the terms of the U.S. Construction Facility, respectively. The U.S. Construction Facility bore interest at a rate of 2.07% and 5.16% per annum at June 30, 2009 and December 31, 2008, respectively.

Enbridge Energy Partners, L.P.

Credit Facility

On March 31, 2009, the Partnership amended its Credit Facility to remove Lehman BB, as a lender, which effectively reduced the amounts available to the Partnership under its Credit Facility. The removal of Lehman BB permanently reduced both the amount the Partnership may borrow under the terms of its Credit Facility to $1,167.5 million as well as the number of committed lenders to 13. The amendment to the Partnership’s Credit Facility did not result in any changes to the pricing, fees or other commercial terms.

At June 30, 2009, the Partnership had $543.0 million outstanding under its Credit Facility at a weighted average interest rate of 0.62% and outstanding letters of credit totaling $5.8 million. The amounts the Partnership may borrow under the terms of its Credit Facility are reduced by the balance of its outstanding letters of credit.

At June 30, 2009, the Partnership could borrow $618.7 million under the terms of its Credit Facility, determined as follows:

	(in millions)
Total credit available under Credit Facility	$	1,167.5
Less: Amounts outstanding under Credit Facility		(543.0	)
Balance of letters of credit outstanding		(5.8	)
Total amount the Partnership could borrow at June 30, 2009	$	618.7

Senior Notes

The Partnership repaid at face value $175.0 million in principal amount of its 4.0% Senior Notes that matured on January 15, 2009.

364-day Credit Facilities

In April 2009, the Partnership entered into two unsecured and non-guaranteed revolving credit facility agreements totaling $350 million for funding its general activities and working capital, which is referred to as the 364-day Credit Facilities. The 364-day Credit Facilities include a $200 million agreement with Barclays Bank PLC, as administrative agent, and Barclays Bank PLC and Export Development Canada as lenders, which is referred to as the Barclays Agreement, and a $150 million affiliate credit agreement, or the EUS Agreement, with Enbridge (U.S.) Inc., a wholly-owned subsidiary of Enbridge. The Partnership entered into each agreement concurrently with an initial maturity date of April 7, 2010 and a one-year extension, for a fee, exercisable at its option. Amounts the Partnership may borrow under the agreements comprising the 364-day Credit Facilities have the same terms, which are summarized below; however, amounts the Partnership can borrow under the EUS agreement are subordinate to amounts it can borrow under the Barclays agreement.

F-7

Under the Partnership’s 364-day Credit Facilities, borrowings can be funded through either a “Fixed Period Eurodollar Rate Loan” or “Base Rate Loan.” Borrowings drawn under the Fixed Period Eurodollar Rate Loan bear interest at a rate per annum equal to the British Bankers’ Association London Interbank Rate, or BBA Libor. Under the Base Rate Loan borrowings, interest will be at a rate per annum that is equal to the greater of (a) the Federal Funds Rate plus 0.5%; (b) the prime rate as determined by Barclays Bank PLC; or (c) the Fixed Period Eurodollar Rate plus 1.0%.

The Partnership’s 364-day Credit Facilities contain restrictive covenants that require it to maintain a maximum leverage ratio of 5.25 to 1.0 for periods ending on or before March 31, 2010 and a ratio of 5.00 to 1.0 for periods ending June 30, 2010 and following. At June 30, 2009, the Partnership’s leverage ratio was approximately 4.0 as computed pursuant to the terms of its 364-day Credit Facilities. The Partnership’s 364-day Credit Facilities also place limitations on the debt that its subsidiaries may incur directly. Accordingly, the Partnership is expected to provide debt financing to its subsidiaries as necessary.

Any repayments made on the 364-day Credit Facilities must be made pro-rata between the Barclays Agreement and the EUS Agreement, until such time as the Barclays credit facility is repaid. At June 30, 2009, the Partnership had no amounts outstanding under its 364-day Credit Facilities and the full amount remains available for the Partnership’s use. Both the Barclays Agreement and EUS Agreement rank equally to the Partnership’s Credit Facility and senior indebtedness and superior to its current and future junior notes.

Fair Value of Debt Obligations

The table below presents the carrying amounts and approximate fair values of our third-party debt obligations. The carrying amounts of our U.S. Construction Facility and the Partnership’s credit facility borrowings approximate their fair values at June 30, 2009 and December 31, 2008, due to the short-term nature of these obligations. The approximate fair values of our and the Partnership’s long-term debt obligations are determined using a standard methodology that incorporates pricing points that are obtained from independent third party investment dealers who actively make markets in our debt securities. We use these pricing points to calculate the present values of the principal obligations to be repaid at maturity and all future interest payment obligations for any debt outstanding.

	June 30, 2009				December 31, 2008
	Carrying  Amount		Fair Value		Carrying  Amount		Fair Value
	(in millions)
U.S. Construction Facility	$	956.0	$	956.0	$	850.0	$	850.0
Credit Facility		543.0		543.0		166.8		166.8
9.150% First Mortgage Notes		93.0		100.0		93.0		93.8
5.358% Senior unsecured zero coupon notes due 2022		220.4		225.2		214.7		211.0
4.000% Senior Notes due 2009		—		—		175.0		175.2
7.900% Senior Notes due 2012		100.0		105.8		99.9		93.7
4.750% Senior Notes due 2013		199.9		189.6		199.9		163.4
5.350% Senior Notes due 2014		199.9		191.9		199.9		151.3
5.875% Senior Notes due 2016		299.8		293.5		299.8		234.5
7.000% Senior Notes due 2018		99.9		102.3		99.9		81.9
6.500% Senior Notes due 2018		398.1		398.3		398.0		317.7
9.875% Senior Notes due 2019		499.7		614.2		499.7		500.4
7.125% Senior Notes due 2028		99.8		96.0		99.8		72.7
5.950% Senior Notes due 2033		199.7		160.1		199.7		119.7
6.300% Senior Notes due 2034		99.8		83.1		99.8		62.3
7.500% Senior Notes due 2038		398.9		382.0		398.9		289.2
8.050% Junior subordinated notes due 2067		399.4		291.5		399.3		209.3
Total	$	4,807.3	$	4,732.5	$	4,494.1	$	3,792.9

F-8

8. DEFERRED INCOME TAXES

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

	June 30,     2009			December 31, 2008
	(in millions)
Net book basis of assets in excess of tax basis	$	415.4		$	403.9
Employee Benefit Plans		(50.5	)		(49.8	)
Other		(6.5	)		(6.4	)
Net deferred tax liabilities	$	358.4		$	347.7

At June 30, 2009 we have no remaining federal net operating losses that can be carried forward to offset future federal taxable income.

Accounting for Uncertainty in Income Taxes

As of June 30, 2009 there are no unrecognized tax benefits that would affect our effective tax rate. We do not anticipate further adjustments to the unrecognized tax benefits during the next twelve months that would have a material impact on our financial statements.

Listed below are the tax years that remain subject to examination by major tax jurisdictions:

Jurisdiction	Open Tax Years
United States – Federal	2000-2007

Undistributed Earnings

We have not provided deferred taxes on the unremitted earnings of our foreign investments that we do not intend to repatriate in the foreseeable future. The earnings relate to ongoing operations and at June 30, 2009 were approximately $381.9 million. At this time, it is not practicable to determine, due to the availability of U.S. foreign tax credits, the deferred income tax liability that would be payable if such earnings were not reinvested indefinitely.

F-9

9. RELATED PARTY TRANSACTIONS

We routinely enter into borrowing and lending arrangements with our affiliates. The outstanding principal amounts of loans to and from our affiliates are presented below in U.S. dollars:

	Currency	Rate*	Maturity	June 30,     2009		December 31, 2008
				(principal outstanding; in millions)
Current loans to affiliates
Enbridge Pipelines (Athabasca) Inc.	Canadian	CDOR + 0.30%	Demand	$	231.3	$	219.6
Enbridge Pipelines (Athabasca) Inc.	Canadian	CDOR + 0.25%	Demand		209.4		198.8
Enbridge (U.S.) Inc.	U.S.	130% AFR	Demand		4.7		5.0
Enbridge Inc.	Canadian	0.00%	Demand		9.6		9.1
Enbridge Inc.	U.S.	LIBOR + 0.15%	Demand		—		23.0
Olympic Pipeline Company	U.S.	LIBOR + 3.0%	2010		4.9		4.9
Total current loans to affiliates				$	459.9	$	460.4
Long-term loans to affiliates
Enbridge Pipelines (Athabasca) Inc.	Canadian	5.47%	2010	$	196.6	$	186.7
Enbridge Pipelines (Athabasca) Inc.	Canadian	5.25%	2012		145.6		138.3
Enbridge Pipelines (Athabasca) Inc.	Canadian	6.50%	2018		258.1		244.9
Olympic Pipe Line Company	U.S.	7.19%	2011		39.0		39.0
Total long-term loans to affiliates				$	639.3	$	608.9
Current loans from affiliates
Enbridge Energy Company, Inc.
Enbridge (U.S.) Inc.	U.S.	5.69%	Demand	$	368.8	$	451.9
Enbridge (U.S.) Inc.	U.S.	130% AFR	Demand		49.5		50.7
Enbridge (U.S.) Inc.	U.S.	130% AFR	Demand		—		2.5
Total current loans from affiliates				$	418.3	$	505.1
Long-term loans from affiliates
Enbridge Energy Partners, L.P.
Enbridge Hungary Liquidity Management LLC	U.S.	8.40%	2017	$	130.0	$	130.0
Enbridge Energy Company, Inc.
Enbridge Hungary Liquidity Management LLC	U.S.	7.75%	2010		499.8		499.9
Enbridge Hungary Liquidity Management LLC	U.S.	7.14%	2011		39.0		39.0
Enbridge Hungary Liquidity Management LLC	U.S.	9.00%	2019		60.0		—
Enbridge Hungary Liquidity Management LLC	U.S.	8.65%	2019		40.0		—
Total long-term loans from affiliates				$	768.8	$	668.9

* AFR – Applicable Federal Rate

* CDOR – Canadian Depository Offering Rate

* LIBOR – London Interbank Offered Rate

UTOS Disposition

In January 2009, the Partnership sold its member interests of its UTOS system for minimal consideration to Enbridge Offshore (Gas Transportation), L.L.C., a wholly-owned subsidiary of Enbridge. The UTOS system transports natural gas from offshore platforms on a fee for service basis to other pipelines onshore for further delivery and does not have long-term contracts. The UTOS system was not considered strategic to the ongoing operations of the Partnership, but is strategically aligned with Enbridge’s offshore operations.

F-10

EUS Credit Facility

In April 2009, the Partnership entered into a $150 million unsecured and non-guaranteed revolving credit facility agreement with Enbridge (U.S.) Inc., as discussed in Note 7—Debt—364-day Credit Facilities.

10. COMMITMENTS AND CONTINGENCIES

Environmental Liabilities

We are subject to federal and state laws and regulations relating to the protection of the environment. Environmental risk is inherent to liquid hydrocarbon and natural gas pipeline operations and we could, at times, be subject to environmental cleanup and enforcement actions. We manage this environmental risk through appropriate environmental policies and practices to minimize any impact our operations may have on the environment.

As of June 30, 2009 and December 31, 2008, we have recorded $5.7 million and $5.5 million, respectively, in “Accounts payable and other” and $2.5 million and $2.8 million, respectively, in “Other long-term liabilities,” primarily to address remediation of contaminated sites, asbestos-containing materials, management of hazardous waste material disposal, outstanding air quality measures for certain of our liquids and natural gas assets, and penalties we have been or expect to be assessed.

IRS Legal Proceedings

We are the former owner of Midcoast, which we sold to the Partnership in 2002. The IRS challenged Midcoast’s tax treatment of its 1999 acquisition of several partnerships that owned a natural gas pipeline system in Kansas (these assets were subsequently sold by the Partnership in 2007). In March 2008, an unfavorable court decision was received sustaining the IRS position, decreasing the U.S. tax basis for the pipeline assets. We continue to believe that the tax treatment of the acquisition and the related tax deductions claimed were appropriate and have appealed the decision.

Legal Proceedings

We are also a participant in various legal proceedings arising in the ordinary course of business. Some of the proceedings are covered in whole or in part, by insurance. We believe that the outcome of all these proceedings will not, individually or in the aggregate have a material adverse effect on our financial condition unless otherwise indicated.

11. DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES

We and the Partnership are exposed to interest rate risk in connection with our variable rate debt obligations. We are also exposed to foreign currency risk associated with the operations of our Canadian subsidiaries. Additionally, the Partnership is exposed to commodity price risk associated with fluctuations in prices of natural gas, NGLs, condensate and fractionation margins (the relative price differential between NGL sales and the related natural gas purchases). We and the Partnership use derivative instruments including futures, forwards, swaps, options and other financial instruments with similar characteristics to manage the risks associated with market fluctuations in commodity prices, interest rates and foreign currencies. Based on our risk management policies, all of our derivative instruments are employed in connection with an underlying asset, liability and/or forecasted transaction and are not entered into with the objective of speculating on interest rates, commodity prices, or exchange rates.

F-11

Accounting Treatment

We record all derivative instruments in our consolidated statements of financial position at fair market value which we adjust each period for changes in the fair market value, which we refer to as marking to market, or mark-to-market. The fair market value of these derivative instruments reflects the estimated amounts that we would pay or receive, other than in a forced or liquidation sale, to terminate or close the contracts at the reporting date, taking into account the current unrealized losses or gains on open contracts. We use actively traded external market quotes and indices to value substantially all of the financial instruments we utilize.

In accordance with the authoritative accounting guidance, if a derivative instrument does not qualify as a hedge, or is not designated as a hedge, changes in the fair value of the instrument are not recorded as increases or decreases in “Accumulated other comprehensive income,” or AOCI. The actual derivative contract is settled by making or receiving a payment to or from the counterparty or by making or receiving a payment for entering into a contract that exactly offsets the original derivative contract. Typically, we settle our derivative contracts when the physical transaction that underlies the derivative instrument occurs.

If a derivative instrument qualifies and is designated as a cash flow hedge, a hedge of a forecasted transaction or future cash flows, any unrealized change in fair market value is deferred in AOCI, a component of “Shareholder’s equity,” until the underlying hedged transaction occurs. At inception and on a quarterly basis, we formally assess whether the hedge contract is highly effective in offsetting changes in cash flows of hedged items. Unrealized changes in fair market value of cash flow hedges deferred in AOCI for which hedge accounting has been discontinued, remain in AOCI until the underlying physical transaction occurs unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period, or within an additional two-month period of time thereafter. Generally, our preference is for our derivative instruments to receive hedge accounting treatment whenever possible. To qualify for cash flow hedge accounting as set forth in the authoritative accounting guidance, very specific requirements must be met in terms of hedge structure, hedge objective and hedge documentation.

If a derivative instrument is designated and qualifies as a fair value hedge or a foreign currency hedge, the change in fair market value of the underlying asset or liability, in addition to the derivative instrument, are recorded in our consolidated statement of financial position. However, unlike cash flow hedges, the changes in fair value the derivative instrument are not recorded to AOCI. Similar to derivative instruments designated as cash flow hedges, very specific requirements must be met in terms of hedge structure, hedge objective and hedge documentation.

Non-Qualified Hedges

Many of our derivative instruments qualify for hedge accounting treatment as set forth in the authoritative accounting guidance. However, we have several transaction types associated with our commodity and interest rate derivative financial instruments where the hedge structure does not meet the requirements to apply hedge accounting. As a result, these derivative financial instruments do not qualify for hedge accounting and are referred to as “non-qualified.” These non-qualified derivative financial instruments are marked-to-market each period, but the change in fair value is not included in AOCI.

The following transaction types do not qualify for hedge accounting:

Commodity Price Exposures:

• Transportation—When the Partnership transports natural gas from one location to another the pricing index used for natural gas sales is usually different from the pricing index used for natural gas purchases, which exposes the Partnership to basis price risk relative to changes in those two indices. By entering into a basis swap, the Partnership can effectively lock in the margin or “spread,” representing the difference between the sales price and the purchase price, on the combined natural gas purchase and

F-12

natural gas sale, thereby removing locational price risk on the physical transactions. Although this represents a sound economic hedging strategy, the derivative instruments (i.e., the basis swaps) associated with these transportation contracts do not qualify for hedge accounting, since only the future margin has been fixed and not the future cash flow.

• Storage—the Partnership uses derivative instruments (i.e., natural gas swaps) to hedge the relative difference between the injection price paid to purchase and store natural gas and the withdrawal price at which the natural gas is sold from storage. The intent of these derivative financial instruments is to lock representing the difference between the price paid for the natural gas injected and the price received upon withdrawal of the gas from storage in a future period. The Partnership does not pursue cash flow hedge accounting treatment for these storage transactions since the underlying forecasted injection or withdrawal of natural gas may not occur in the period as originally forecast. This can occur because the Partnership retains the flexibility to make changes in the underlying injection or withdrawal schedule, given changes in market conditions. In addition, since the physical natural gas is recorded at the lower of cost or market, timing differences can result when the derivative financial instrument is settled in a period that is different from when the physical natural gas is sold from storage.

• Natural Gas Collars—The Partnership previously entered into natural gas collars to hedge the sales price of natural gas. The natural gas collars were based on a NYMEX price, while the physical gas sales were based on a different index. To better align the index of the natural gas collars with the index of the underlying sales, the Partnership de-designated the original cash flow hedging relationship with the intent of contemporaneously re-designating the natural gas collars as hedges of forecasted physical natural gas sales with a NYMEX pricing index. However, because the fair value of these derivative instruments was a liability to the Partnership at re-designation, they are considered net written options and pursuant to the authoritative accounting guidance, do not qualify for hedge accounting.

• Optional Natural Gas Processing Volumes—The Partnership uses derivative instruments to hedge the volumes of NGLs produced from its natural gas processing facilities. Many of the Partnership’s natural gas contracts allow it the option of processing natural gas when it is economical, and to cease to do so when it becomes economic the “fractionation spread,” representing the relative difference between the price received for the NGLs produced less the cost of natural gas used for processing, become uneconomic. The Partnership has entered into derivative instruments to fix the sales price of a portion of the NGLs that it produces at its discretion and to fix the associated purchases of natural gas required for processing when it is probable the processing will occur. Because the Partnership’s processing forecasts fluctuate due to market conditions, these derivative instruments are deemed “non-qualifying” hedges.

• Forward Contracts—The Partnership uses forward contracts to fix the price of NGLs it purchases and stores in inventory and fixes the price of NGLs that it sells from inventory to meet the demands of its customers that sell and purchase NGLs. Prior to April 1, 2009, forward contracts were not treated as derivative financial instruments pursuant to the normal purchase normal sale, or NPNS, exception allowed under authoritative accounting guidance, since the forward contracts resulted in physical receipt or delivery of NGLs. However, evolving markets for NGLs have increased opportunities for a portion of the Partnership’s forward contracts to be settled net rather than physically receiving or delivering the NGLs. Accordingly, the Partnership has revoked the NPNS exception on forward contracts associated with its liquids marketing operations of Dufour Petroleum, L.P., its wholly-owned subsidiary, executed after April 1, 2009. The forward contracts for which the Partnership has revoked the NPNS election do not qualify for hedge accounting.

Interest Rate Risk Exposures:

• Interest Rate Caps—The Partnership’s variable interest rate borrowing cost is determined at the time of each borrowing or interest rate reset based upon a posted LIBOR rate for the period of borrowing or

F-13

interest rate reset, plus a defined credit spread. In order to mitigate the economic effects that can result in a rising interest rate environment, the Partnership has entered into interest rate caps, which establish a ceiling averaging approximately 1.12% on the interest rates it pays on up to $400 million of its variable rate indebtedness. Although the Partnership’s interest rate caps protect it from the adverse effect of higher interest rates, they do not qualify for hedge accounting.

In each of the instances described above, the underlying physical purchase, storage and sale of natural gas and NGLs are accounted for on a historical cost or market basis rather than on the mark-to-market basis the Partnership utilizes for the derivative instruments employed to mitigate the commodity price risk associated with its storage and transportation assets.

Derivative Positions

Our derivative financial instruments are included at their fair values in our consolidated statements of financial position as follows:

	June 30,     2009			December 31, 2008
	(in millions)
Other current assets	$	27.5		$	70.6
Other assets, net		36.6			75.7
Accounts payable and other		(29.0	)		(40.6	)
Other long-term liabilities		(58.6	)		(71.0	)
	$	(23.5	)	$	34.7

The changes in net assets and liabilities associated with the Partnership’s derivative activities are primarily due to the increase in current and forward NGL prices from December 31, 2008 to June 30, 2009. The Partnership’s portfolio of derivative financial instruments is largely comprised of long-term fixed price natural gas and NGL sales and purchase agreements.

The Partnership records the change in fair value of its highly effective cash flow hedges in AOCI until the derivative financial instruments are settled, at which time they are reclassified out of AOCI. Also included in AOCI are unrecognized losses of approximately $1.3 million associated with derivative financial instruments that qualified for and were classified as cash flow hedges of forecasted commodity transactions that were subsequently de-designated. These losses are reclassified from AOCI over the periods during which the originally hedged forecasted transactions affect earnings. For the six months ended June 30, 2009, we reclassified unrealized net gains of $19.8 million from AOCI for the fair value of derivative financial instruments that were settled. The Partnership estimates that approximately $0.9 million of AOCI, representing unrealized net losses on cash flow hedging activities based on pricing and positions at June 30, 2009, will be reclassified from AOCI during the next twelve months.

F-14

The table below summarizes our derivative balances by counterparty credit quality (negative amounts represent our net obligations to pay the counterparty).

	June 30,     2009			December 31, 2008
	(in millions)
Counterparty Credit Quality
AAA	$	—		$	—
AA		4.3			(39.6	)
A		(27.6	)		73.3
Lower than A		(0.9	)		(1.2	)
		(24.2	)		32.5
Credit valuation adjustment		0.7			2.2
Total	$	(23.5	)	$	34.7

* As determined by nationally recognized statistical ratings organizations.

As the net value of the Partnership’s derivative financial instruments has decreased in response to changes in forward commodity prices, the outstanding financial exposure has also declined. When credit thresholds are met pursuant to the terms of the Partnership’s ISDA^® financial contracts, it has the right to require collateral from its counterparties. The Partnership has included any cash collateral received in the balances listed above. When the Partnership is in a position of posting collateral to cover its counterparties’ exposure to its non-performance, the collateral is provided through letters of credit, which are not reflected above.

The ISDA^® agreements and associated credit support, which govern the Partnership’s financial derivative transactions, contain no credit rating downgrade triggers that would accelerate the maturity dates of its outstanding transactions. A change in ratings is not an event of default under these instruments, and the maintenance of a specific minimum credit rating is not a condition to transacting under the ISDA^® agreements. In the event of a credit downgrade, additional collateral may be required to be posted under the agreement if the Partnership is in a liability position to its counterparty, but the agreement will not automatically terminate or require immediate settlement of amounts due.

The ISDA^® agreements, in combination with the Partnership’s master netting agreements, and credit arrangements governing its interest rate and commodity swaps require that collateral be posted per tiered contractual thresholds based on each counterparty’s credit rating. The Partnership generally provides letters of credit to satisfy such collateral requirements under our ISDA^® agreements. These agreements will require additional collateral postings of up to 100% on net liability positions in the event of a credit downgrade below investment grade, but the agreements do not contain additional triggers or automatic termination clauses relating to credit downgrades. Automatic termination clauses which exist are related only to non-performance activities, such as the refusal to post collateral when contractually required to do so. When the Partnership is holding an asset position, its counterparties are likewise required to post collateral on their liability (our asset) exposures, also determined by the tiered contractual collateral thresholds. Counterparty collateral may consist of cash or letters of credit, both of which must be fulfilled with immediately available funds.

At June 30, 2009, the Partnership was in an overall net liability position of $23.5 million, which included assets of $64.1 million. Based on its forward positions at June 30, 2009, if the Partnership’s credit ratings were downgraded to BBB- by Standard & Poor’s or Baa3 by Moody’s Investors Service, the Partnership would be required to provide an additional $27.0 million in the form of either cash collateral or letters of credit to satisfy the requirements of our ISDA^® agreements.

Counterparties to the Partnership’s derivative financial instruments include credit concentrations with U.S. financial institutions, international financial institutions, investment banking entities and, to a lesser extent, international integrated oil companies. At June 30, 2009, approximately $26.6 million of receivables were

F-15

payable to the Partnership from U.S. financial institutions, including investment banks. The Partnership is also in net liability positions of $9.4 million and $40.7 million with integrated oil companies and non-U.S. financial institutions, respectively, representing amounts payable to the Partnership. The Partnership is holding no cash collateral on its asset exposures nor has it posted any amounts under letters of credit relating to its liability exposure pursuant to the margin thresholds in effect at June 30, 2009 under our ISDA^®.

Gross derivative balances are presented below without the effects of collateral received or posted and without the effects of master netting arrangements. The Partnership’s assets are adjusted for the non-performance risk of its counterparties using their credit default swap spread rates. Likewise, in the case of its liabilities, the Partnership’s nonperformance risk is considered in the valuation, and is also adjusted based on current credit default swap spread rates on its outstanding indebtedness. The Partnership’s credit exposure for these over-the-counter derivatives is directly with its counterparty and continues until the maturity or termination of the contracts. A reconciliation between these schedules presented at gross values rather than the net amounts the Partnership presents in its other derivative schedules, is also provided below.

Effect of Derivative Instruments on the Consolidated Statements of Financial Position

	June 30, 2009
	Asset Derivatives			Liability Derivatives
	Financial Position Location	Fair Value		Financial Position Location	Fair Value
	(in millions)
Derivatives designated as hedging instruments under SFAS No. 133
Interest rate contracts	Other current assets	$	—	Accounts payable and other	$	(0.7	)
Interest rate contracts	Other assets, net		0.1	Other long-term liabilities		(13.6	)
Commodity contracts	Other current assets		35.6	Accounts payable and other		(36.5	)
Commodity contracts	Other assets, net		32.5	Other long-term liabilities		(53.3	)
			68.2			(104.1	)
Derivatives not designated as hedging instruments under SFAS No. 133
Interest rate contracts	Other current assets		5.6	Accounts payable and other		(4.5	)
Interest rate contracts	Other assets, net		7.7	Other long-term liabilities		(4.5	)
Commodity contracts	Other current assets		18.7	Accounts payable and other		(19.7	)
Commodity contracts	Other assets, net		19.9	Other long-term liabilities		(10.8	)
			51.9			(39.5	)
Total derivative instruments		$	120.1		$	(143.6	)

Effect of Derivative Instruments on Accumulated Other Comprehensive Income

For the six months ended June 30, 2009
Derivatives in SFAS No. 133 Cash Flow Hedging Relationships	Amount recognized in AOCI on Derivative (Effective Portion)			Amount reclassified out from AOCI (Effective Portion)
(in millions)
Interest rate contracts	$	(14.2	)	$	(0.9	)
Commodity contracts		(62.6	)		19.8
Total	$	(76.8	)	$	18.9

F-16

Gross to Net Presentation Reconciliation of Derivative Assets and Liabilities

	June 30, 2009
	Assets			Liabilities			Total
	(in millions)
Fair value of derivatives—gross presentation	$	120.1		$	(143.6	)	$	(23.5	)
Effects of netting agreements		(56.0	)		56.0			—
Fair value of derivatives—net presentation	$	64.1		$	(87.6	)	$	(23.5	)

Inputs to Fair Value Derivative Instruments

The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2009. We classify financial assets and liabilities in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect our valuation of the financial assets and liabilities and their placement within the fair value hierarchy.

	June 30, 2009												December 31, 2008
Recurring fair value measures	Level 1			Level 2			Level 3			Total			Level 1			Level 2		Level 3			Total
	(in millions)
Assets:
Derivative instruments, net	$	8.9		$	13.4		$	49.4		$	71.7		$	20.4		$	—	$	119.6		$	140.0
Liabilities:
Derivative instruments, net		(61.3	)		(23.4	)		(10.5	)		(95.2	)		(77.5	)		—		(27.8	)		(105.3	)
Total	$	(52.4	)	$	(10.0	)	$	38.9		$	(23.5	)	$	(57.1	)	$	—	$	91.8		$	34.7

The table below provides a reconciliation of changes in the fair value of our Level 3 financial assets and liabilities from January 1, 2009 to June 30, 2009. Interest rate swaps totaling $1.8 million were reclassified to Level 2 following our evaluation of the inputs used to compute fair value for these financial instruments and determination that the valuation inputs meet the qualifications for Level 2 classification.

	2009
	(in millions)
Beginning balance as of January 1	$	91.8
Realized and unrealized net losses		(49.4	)
Purchases		(1.7	)
Transfer out of Level 3		(1.8	)
Balance as of June 30	$	38.9
Change in unrealized net losses relating to instruments still held at June 30:
For the six months ended June 30	$	(38.9	)

F-17

Fair Value of Commodity Price Derivatives

The following table provides summarized information about the fair values of our outstanding commodity derivative financial instruments at June 30, 2009 and December 31, 2008.

	At June 30, 2009											At December 31, 2008
			Wtd. Average Price (2)				Fair Value(3)					Fair Value (3)
	Commodity	Notional (1)	Receive		Pay		Asset		Liability			Asset		Liability
Contracts maturing in 2009
Swaps
Receive variable/pay fixed	Natural Gas	12,259,562	$	3.96	$	6.75	$	0.4	$	(34.5	)	$	2.5	$	(56.0	)
	NGL	44,863		20.78		37.81		—		(2.1	)		—		(6.5	)
Receive fixed/pay variable	Natural Gas	12,490,056		5.70		4.19		21.9		(3.1	)		38.7		(19.6	)
	NGL	1,965,672		45.82		38.27		16.7		(1.9	)		70.0		—
	Crude Oil	374,728		66.62		71.92		1.2		(2.9	)		5.8		(0.6	)
Receive variable/pay variable	Natural Gas	68,097,561		3.93		3.91		5.5		(3.7	)		8.9		(12.8	)
Options
Calls (written)	Natural Gas	184,000		4.31		4.38		—		(0.1	)		—		(0.6	)
Puts (purchased)	Natural Gas	184,000		4.38		3.40		—		—			—		(1.2	)
	NGL	656,328		36.57		35.41		2.9		—			9.3		—
	Crude Oil	128,800		71.92		64.86		0.2		—			—		—
Forward Sales
Receive variable/pay fixed	NGL	568,620		46.30		43.85		1.4		—			—		—
Receive fixed/pay variable	NGL	1,021,718		46.53		48.63		—		(2.2	)		—		—
Contracts maturing in 2010
Swaps
Receive variable/pay fixed	Natural Gas	10,397,990	$	5.69	$	6.43	$	2.4	$	(10.0	)	$	2.5	$	(6.5	)
	NGL	200,322		49.58		46.50		3.7		(1.0	)		—		(1.3	)
Receive fixed/pay variable	Natural Gas	16,814,622		4.97		5.83		5.5		(19.9	)		2.2		(27.5	)
	NGL	2,615,225		46.07		42.87		19.1		(10.8	)		28.0		—
	Crude Oil	720,790		71.95		75.35		3.9		(6.3	)		5.5		(0.5	)
Receive variable/pay variable	Natural Gas	75,292,893		5.72		5.70		2.9		(1.6	)		0.8		(3.1	)
Options
Calls (written)	Natural Gas	365,000		4.31		6.06		—		(0.6	)		—		(1.0	)
Puts (written)	Crude Oil	36,500		67.75		75.35		—		(0.2	)		—		—
Puts (purchased)	Natural Gas	365,000		6.06		3.40		—		—			—		—
	NGL	595,680		46.04		42.85		6.0		—			5.2		—
	Crude Oil	255,500		75.41		69.76		1.5		—			—		—
Forward Sales
Receive variable/pay fixed	NGL	10,000		36.18		28.56		0.1		—			—		—
Receive fixed/pay variable	NGL	95,122		39.67		41.68		—		(0.2	)		—		—
Contracts maturing in 2011
Swaps
Receive variable/pay fixed	Natural Gas	2,944,510	$	6.58	$	7.20	$	2.4	$	(4.1	)	$	2.6	$	(3.4	)
	NGL	2,857		66.72		47.67		2.2		—			—		—
Receive fixed/pay variable	Natural Gas	9,301,675		4.19		6.82		1.4		(25.1	)		1.1		(28.1	)
	NGL	581,810		55.84		42.01		9.1		(1.3	)		13.0		(0.3	)
	Crude Oil	621,875		71.24		78.39		1.1		(5.6	)		3.3		(0.8	)
Receive variable/pay variable	Natural Gas	15,885,000		6.73		6.69		1.3		(0.6	)		—		(1.0	)
Options
Calls (written)	Natural Gas	365,000		4.31		6.89		—		(0.9	)		—		(1.0	)
Puts (purchased)	Natural Gas	365,000		6.89		3.40		—		—			—		—
	NGL	83,220		63.34		38.41		2.3		—			2.7		—
Contracts maturing in 2012
Swaps
Receive variable/pay fixed	Natural Gas	1,661,265	$	6.85	$	7.94	$	0.7	$	(2.4	)	$	0.8	$	(2.1	)
	NGL	36,600		38.16		55.58		—		(0.6	)		—		(0.9	)
Receive fixed/pay variable	Natural Gas	2,175,556		4.68		7.25		0.2		(5.5	)		—		(5.8	)
	NGL	458,232		70.56		44.05		11.3		—			15.7		—
	Crude Oil	366,000		75.72		80.30		—		(1.6	)		0.8		—
Receive variable/pay variable	Natural Gas	1,089,000		6.84		6.48		0.4		—			—		—
Options
Puts (purchased)	NGL	128,832		66.80		41.22		3.7		—			4.4		—
Contracts maturing in 2013
Swaps
Receive variable/pay fixed	Natural Gas	896,805	$	6.90	$	6.88	$	0.1	$	(0.1	)	$	—	$	—
Receive fixed/pay variable	Natural Gas	1,626,805		8.20		6.92		2.0		(0.1	)		2.0		—
	Crude Oil	292,000		86.41		81.88		2.7		(1.5	)		3.4		—

⁽¹⁾ Volumes of Natural gas are measured in millions of British Thermal Units, or MMBtu, whereas volumes of NGL and Crude are measured in barrels, or Bbl.

⁽²⁾ Weighted average prices received and paid are in $/MMBtu for Natural gas and in $/Bbl for NGL and Crude.

F-18

⁽³⁾ The fair value is determined based on quoted market prices at June 30, 2009 and December 31, 2008, respectively, discounted using the swap rate for the respective periods to consider the time value of money. Fair values are presented in millions of dollars.

Fair Value of Interest Rate Derivatives

The Partnership enters into interest rate swaps, collars and derivative financial instruments with similar characteristics to manage the cash flow associated with future interest rate movements on our indebtedness. The following table provides information about our current interest rate derivatives for the specified periods.

			Partnership			Fair Value
	Notional Principal		Pays	Receives	Maturity Date	June 30,     2009			December 31, 2008
	(dollars in millions)					(dollars in millions)
Interest Rate Swaps
Floating to Fixed:
	$	50.0	4.6175%	LIBOR(2)	January 15, 2009	$	—		$	—
	$	50.0	4.6130%	LIBOR	January 29, 2009		—			—
	$	50.0	4.6525%	LIBOR	February 13, 2009		—			(0.1	)
	$	50.0	4.5875%	LIBOR	February 20, 2009		—			(0.2	)
	$	50.0	1.6510%	LIBOR	December 2, 2010		(0.1	)		—
	$	50.0	1.6570%	LIBOR	December 5, 2010		(0.1	)		—
	$	50.0	1.6870%	LIBOR	December 12, 2010		(0.1	)		—
	$	50.0	1.7040%	LIBOR	December 14, 2010		(0.1	)		—
	$	50.0	1.7180%	LIBOR	December 18, 2010		(0.1	)		—
	$	50.0	4.3700%	LIBOR-21 bps(1)	June 1, 2013		(3.7	)		(5.3	)
	$	50.0	4.3425%	LIBOR-21 bps	June 1, 2013		(3.6	)		(5.2	)
	$	25.0	4.3100%	LIBOR-25 bps	June 1, 2013		(1.8	)		(2.7	)
	$	50.0	4.1160%	LIBOR	December 2, 2013		(0.7	)		—
	$	50.0	4.1250%	LIBOR	December 4, 2013		(0.7	)		—
	$	50.0	4.1320%	LIBOR	December 8, 2013		(0.7	)		—
	$	50.0	4.1270%	LIBOR	December 10, 2013		(0.7	)		—
	$	50.0	4.1570%	LIBOR	December 12, 2013		(0.7	)		—
	$	50.0	4.1720%	LIBOR	December 14, 2013		(0.7	)		—
	$	75.0	4.1380%	LIBOR	December 15, 2013		(1.0	)		—
	$	50.0	4.1740%	LIBOR	December 18, 2013		(0.7	)		—
	$	50.0	4.1920%	LIBOR	December 22, 2013		(0.7	)		—
	$	125.0	4.1680%	LIBOR	December 31, 2013		(1.8	)		—
Fixed to Floating:
	$	25.0	LIBOR-25 bps	4.7500%	June 1, 2013		2.2			3.1
	$	50.0	LIBOR-21 bps	4.7500%	June 1, 2013		4.4			6.1
	$	50.0	LIBOR-21 bps	4.7500%	June 1, 2013		4.4			6.1
Treasury Locks:
	$	20.0	4.6230%	LIBOR	June 30, 2020		(0.5	)		—
	$	200.0	4.6190%	LIBOR	June 30, 2020		(5.0	)		—
Interest Rate Caps:
	$	25.0	1.0900%	N/A	December 17, 2010		0.1			—
	$	50.0	1.1500%	N/A	December 22, 2010		0.3			—
	$	125.0	1.0700%	N/A	December 31, 2010		0.8			—
	$	50.0	1.1450%	N/A	January 4, 2011		0.3			—
	$	25.0	1.1500%	N/A	January 8, 2011		0.2			—
	$	50.0	1.1150%	N/A	January 10, 2011		0.3			—
	$	75.0	1.1500%	N/A	January 15, 2011		0.5			—

⁽¹⁾ A bps refers to a basis point. One basis point is equivalent to 1/100th of 1 percent.

⁽²⁾ LIBOR refers to the three-month U.S. London Interbank Offered Rate.

F-19

12. ACCUMULATED OTHER COMPREHENSIVE INCOME—COMPONENTS

The components of accumulated other comprehensive income are as follows, net of tax:

	June 30,     2009			December 31, 2008
	(in millions)
Foreign currency translation adjustments	$	105.2		$	50.7
Unrecognized post-employment benefit costs		(51.2	)		(51.9	)
Unrealized gains (losses) in fair value of derivatives		(6.1	)		6.9
Total	$	47.9		$	5.7

13. REGULATORY ACCOUNTING

Certain of our liquids and natural gas activities are subject to regulation by the FERC and various state authorities. Regulatory bodies exercise statutory authority over matters such as construction, rates and underlying accounting practices, and ratemaking agreements with customers. The rates the Partnership is allowed to charge shippers associated with its Southern Access expansion project includes an allowance that provides a rate of return to its partners. For rate-making purposes, the Partnership has capitalized approximately $102.0 million that has not been reflected on our consolidated statements of financial position at June 30, 2009.

14. RECENT ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED

FASB Accounting Standards Codification^™

In June 2009, the Financial Accounting Standards Board, or FASB, approved the FASB Accounting Standards Codification^™, which we refer to as the FASB ASC, or codification, as the single source of authoritative, nongovernmental Generally Accepted Accounting Principles, or GAAP. The FASB ASC reorganizes all of the pronouncements under GAAP and displays them in approximately 90 accounting topics. The reorganization and codification of GAAP was initiated by the FASB in an effort to:

• Reduce the amount of time and effort required to solve an accounting research issue.

• Mitigate the risk of noncompliance with standards through improved usability of the literature.

• Provide accurate information with real-time updates as new standards are released.

• Assist FASB with the research and convergence efforts required during the standard setting process.

• Become the authoritative source of literature for the completed XBRL taxonomy.

Included in the codification are relevant portions of authoritative content issued by the Securities and Exchange Commission, or SEC, as well as selected SEC staff interpretations and administrative guidance. The FASB ASC will be effective for both interim and annual reporting periods ending after September 15, 2009. We do not expect our adoption of the codification in the third quarter of 2009 to have a significant effect on our financial statements.

15. SUBSEQUENT EVENTS

We have evaluated events subsequent to June 30, 2009 through August 3, 2009, the date we issued these financial statements, and identified the events disclosed below.

Zero Coupon Senior Notes

On July 21, 2009, the Partnership received notice that the holders of its senior, unsecured zero coupon notes due on August 28, 2022, referred to as the Zero Coupon Notes, have elected to exercise the call feature of the

F-20

notes that require early repayment of the debt. The Partnership will be required to repay the Zero Coupon Notes on August 28, 2009 at an amount of approximately $222.3 million, representing the principal amount of the Zero Coupon Notes on the repayment date. The carrying amount of the Partnership’s Zero Coupon Notes is currently included in “Current maturities of long-term debt” on our consolidated statement of financial position.

Affiliate Borrowings

On July 31, 2009, we established a $400 million credit facility with Enbridge Hungary Liquidity Management Limited Liability Company, which we refer to as Enbridge Hungary, a wholly-owned subsidiary of Enbridge. Our credit facility with Enbridge Hungary bears interest at one-month LIBOR plus 235 basis points that is payable monthly in arrears and matures January 31, 2011. We initially borrowed $155.9 million from our credit facility with Enbridge Hungary. We also borrowed approximately $128 million on a demand note payable to Enbridge that bears interest at one-month LIBOR plus 30 basis points with semi-annual interest payments. We used the proceeds from these borrowings in connection with our participation in funding the Alberta Clipper construction project.

F-21