UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

 

FORM 10-Q

 

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

For the quarterly period ended September 30, 2015
 
OR

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

For the transition period from          to         

Commission file number 1-10934

 

ENBRIDGE ENERGY PARTNERS, L.P.

(Exact Name of Registrant as Specified in Its Charter)

 

Delaware		39-1715850
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification No.)

1100 Louisiana Street,
Suite 3300
Houston, Texas 77002

(Address of Principal Executive Offices) (Zip Code)

(713) 821-2000

(Registrant’s Telephone Number, Including Area Code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large Accelerated Filer x		Accelerated Filer o
Non-Accelerated Filer o (Do not check if a smaller reporting company)		Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).Yes o No x

The registrant had 262,208,428 Class A common units outstanding as of October 30, 2015.

TABLE OF CONTENTS

ENBRIDGE ENERGY PARTNERS, L.P.
 
TABLE OF CONTENTS

PART I — FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Statements of Income for the three and nine months ended September 30, 2015 and 2014			1
Consolidated Statements of Comprehensive Income for the three and nine months ended September 30, 2015 and 2014			2
Consolidated Statements of Cash Flows for the nine months ended September 30, 2015 and 2014			3
Consolidated Statements of Financial Position as of September 30, 2015 and December 31, 2014			4
Notes to the Consolidated Financial Statements			5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			43
Item 3. Quantitative and Qualitative Disclosures About Market Risk			66
Item 4. Controls and Procedures			69
PART II — OTHER INFORMATION
Item 1. Legal Proceedings			69
Item 1A. Risk Factors			69
Item 5. Other Information			69
Item 6. Exhibits			69
Signatures			70
Exhibits			71

In this report, unless the context requires otherwise, references to “we,” “us,” “our,” “EEP” or the “Partnership” are intended to mean Enbridge Energy Partners, L.P. and its consolidated subsidiaries. We refer to our general partner, Enbridge Energy Company, Inc., as our “General Partner.” References to “Enbridge” refer collectively to Enbridge Inc., and its subsidiaries other than us. References to “Enbridge Management” refer to Enbridge Energy Management, L.L.C., the delegate of our General Partner that manages our business and affairs.

This Quarterly Report on Form 10-Q includes forward-looking statements, which are statements that frequently use words such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecast,” “intend,” “may,” “plan,” “position,” “projection,” “should,” “strategy,” “target,” “will” and similar words. Although we believe that such forward-looking statements are reasonable based on currently available information, such statements involve risks, uncertainties and assumptions and are not guarantees of performance. Future actions, conditions or events and future results of operations may differ materially from those expressed in these forward-looking statements. Any forward-looking statement made by us in this Quarterly Report on Form 10-Q speaks only as of the date on which it is made, and we undertake no obligation to publicly update any forward-looking statement. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors that could cause actual results to differ from those in the forward-looking statements include: (1) changes in the demand for the supply of, forecast data for, and price trends related to crude oil, liquid petroleum, natural gas and natural gas liquids, or NGLs, including the rate of development of the Alberta Oil Sands; (2) our ability to successfully complete and finance expansion projects; (3) the effects of competition, in particular, by other pipeline systems; (4) shut-downs or cutbacks at our facilities or refineries, petrochemical plants, utilities or other businesses for which we transport products or to which we sell products; (5) hazards and operating risks that may not be covered fully by insurance, including those related to Line 6B and any additional fines and penalties assessed in connection with the crude oil release on that line; (6) changes in or challenges to our tariff rates, (7) changes in laws or regulations to which we are subject, including compliance with environmental and operational safety regulations that may increase costs of system integrity testing and maintenance; and (8) permitting at federal, state and local levels in regards to the construction of new assets.

For additional factors that may affect results, see “Item-1A. Risk Factors” included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2014, which is available to the public over the Internet at the United States Securities and Exchange Commission’s, or SEC’s, website (www.sec.gov) and at our website (www.enbridgepartners.com).

TABLE OF CONTENTS

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

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

		For the three months ended September 30,								For the nine months ended September 30,
		2015				2014				2015				2014
		(unaudited; in millions, except per unit amounts)
Operating revenues:
Commodity sales (Note 12)		$	597.7			$	1,296.4			$	2,101.3			$	4,114.2
Commodity sales – affiliate (Notes 10 and 12)			12.2				50.6				62.4				174.7
Transportation and other services (Note 12)			621.4				577.6				1,744.6				1,549.4
Transportation and other services – affiliate (Note 10)			36.4				17.7				101.1				54.7
			1,267.7				1,942.3				4,009.4				5,893.0
Operating expenses:
Commodity costs (Notes 5 and 12)			503.3				1,208.5				1,912.0				3,888.4
Commodity costs – affiliate (Note 10)			19.4				29.7				60.4				98.3
Environmental costs, net of recoveries (Note 11)			1.1				50.1				1.1				93.3
Operating and administrative (Notes 6 and 11)			163.3				119.4				353.0				323.3
Operating and administrative – affiliate (Note 10)			117.3				115.9				351.9				353.6
Power (Note 12)			71.6				59.5				192.4				164.1
Depreciation and amortization (Note 6)			136.9				118.8				394.8				336.0
Goodwill impairment (Note 7)			—				—				246.7				—
Asset impairment (Note 6)			—				—				12.3				—
			1,012.9				1,701.9				3,524.6				5,257.0
Operating income			254.8				240.4				484.8				636.0
Interest expense, net (Notes 8 and 12)			(88.2	)			(137.1	)			(214.5	)			(294.2	)
Allowance for equity used during construction (Note 16)			13.7				14.5				54.0				47.8
Other income (Note 10)			8.8				1.8				20.7				2.2
Income before income tax expense			189.1				119.6				345.0				391.8
Income tax expense (Note 13)			(4.6	)			(2.1	)			(3.2	)			(6.1	)
Net income			184.5				117.5				341.8				385.7
Less: Net income attributable to:
Noncontrolling interest (Note 10)			77.8				70.7				139.1				149.4
Series 1 preferred unit distributions			22.5				22.5				67.5				67.5
Accretion of discount on Series 1 preferred units			2.1				3.8				10.1				11.1
Net income attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P.		$	82.1			$	20.5			$	125.1			$	157.7
Net income (loss) allocable to common units and i-units		$	26.1			$	(14.5	)		$	(37.4	)		$	49.5
Net income (loss) per common unit and i-unit (basic and diluted) (Note 2)		$	0.07			$	(0.04	)		$	(0.11	)		$	0.15
Weighted average common units and i-units outstanding (basic and diluted)			341.1				328.8				337.9				327.6

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

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

		For the three months ended September 30,								For the nine months ended September 30,
		2015				2014				2015				2014
		(unaudited; in millions)
Net income		$	184.5			$	117.5			$	341.8			$	385.7
Other comprehensive income (loss), net of tax expense (Note 12)			(131.0	)			55.5				(181.2	)			(80.6	)
Comprehensive income			53.5				173.0				160.6				305.1
Less:
Net income attributable to noncontrolling interest (Note 10)			77.8				70.7				139.1				149.4
Net income attributable to Series 1 preferred unit distributions			22.5				22.5				67.5				67.5
Net income attributable to accretion of discount on Series 1 preferred units			2.1				3.8				10.1				11.1
Other comprehensive income (loss) allocated to noncontrolling interest			(1.3	)			2.1				(3.9	)			1.8
Comprehensive income (loss) attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P.		$	(47.6	)		$	73.9			$	(52.2	)		$	75.3

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

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ENBRIDGE ENERGY PARTNERS, L.P.
 
CONSOLIDATED STATEMENTS OF CASH FLOWS

		For the nine months ended September 30,
		2015				2014
		(unaudited; in millions)
Cash provided by operating activities:
Net income		$	341.8			$	385.7
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization (Note 6)			394.8				336.0
Derivative fair value net losses (Note 12)			40.0				62.7
Inventory market price adjustments (Note 5)			5.4				4.8
Goodwill impairment (Note 7)			246.7				—
Environmental costs, net of recoveries (Note 11)			0.7				81.5
Distributions from investments in joint ventures (Note 10)			20.5				6.1
Equity earnings from investments in joint ventures (Note 10)			(20.5	)			(7.1	)
Income taxes (Note 13)			2.1				4.7
Loss on sales of assets			3.2				—
Allowance for equity used during construction (Note 16)			(54.0	)			(47.8	)
Asset impairment (Note 6)			12.3				—
Other			7.7				13.0
Changes in operating assets and liabilities, net of acquisitions:
Receivables, trade and other			36.2				0.9
Due from General Partner and affiliates			(28.1	)			15.3
Accrued receivables			216.2				27.7
Inventory (Note 5)			0.5				(131.0	)
Current and long-term other assets (Note 12)			(33.6	)			(28.7	)
Due to General Partner and affiliates			80.5				(23.4	)
Accounts payable and other (Notes 4 and 12)			(11.5	)			(93.1	)
Environmental liabilities (Note 11)			(34.5	)			(116.7	)
Accrued purchases			(175.1	)			(28.6	)
Interest payable			0.3				5.9
Property and other taxes payable			2.7				23.8
Net cash provided by operating activities			1,054.3				491.7
Cash used in investing activities:
Additions to property, plant and equipment (Notes 6 and 15)			(1,556.2	)			(2,055.8	)
Acquisitions (Note 3)			(85.0	)			—
Changes in restricted cash (Note 10)			65.8				31.2
Proceeds from sales of assets			5.3				—
Investments in joint ventures (Note 10)			(3.0	)			(35.4	)
Distributions from investments in joint ventures in excess of cumulative earnings			9.5				27.0
Other			(2.9	)			(0.7	)
Net cash used in investing activities			(1,566.5	)			(2,033.7	)
Cash provided by financing activities:
Net proceeds from unit issuances (Note 9)			294.8				—
Distributions to partners (Note 9)			(619.9	)			(544.2	)
Repayments to General Partner (Note 10)			(306.0	)			(12.0	)
Proceeds from issuance of long-term debt, net of discounts (Note 8)			—				398.1
Net borrowings (repayments) under credit facilities (Note 8)			785.0				30.0
Net commercial paper borrowings (repayments) (Note 8)			(291.0	)			799.8
Contributions from noncontrolling interest (Notes 9 and 10)			740.6				1,083.0
Distributions to noncontrolling interest (Notes 9 and 10)			(178.7	)			(80.9	)
Net cash provided by financing activities			424.8				1,673.8
Net increase (decrease) in cash and cash equivalents			(87.4	)			131.8
Cash and cash equivalents at beginning of year			197.9				164.8
Cash and cash equivalents at end of period		$	110.5			$	296.6

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

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ENBRIDGE ENERGY PARTNERS, L.P.
 
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

		September 30, 2015				December 31, 2014
		(unaudited; in millions)
ASSETS
Current assets:
Cash and cash equivalents (Note 4)		$	110.5			$	197.9
Restricted cash (Notes 3, 10 and 12)			46.2				97.0
Receivables, trade and other, net of allowance for doubtful accounts of $1.6 million and $1.8 million at September 30, 2015 and December 31, 2014, respectively			9.8				46.2
Due from General Partner and affiliates			69.9				41.4
Accrued receivables			44.1				260.3
Inventory (Note 5)			88.3				94.2
Other current assets (Note 12)			193.8				218.4
			562.6				955.4
Property, plant and equipment, net (Notes 6 and 16)			17,006.4				15,692.7
Goodwill (Note 7)			—				246.7
Intangible assets, net			284.3				254.8
Other assets, net (Note 12)			553.6				597.3
		$	18,406.9			$	17,746.9
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Due to General Partner and affiliates (Note 10)		$	225.4			$	143.7
Accounts payable and other (Notes 4, 12 and 16)			903.5				777.7
Environmental liabilities (Note 11)			101.6				141.7
Accrued purchases			200.6				375.7
Interest payable			74.7				74.6
Property and other taxes payable (Note 13)			99.2				96.5
Note payable to General Partner (Note 10)			—				306.0
			1,605.0				1,915.9
Long-term debt (Note 8)			7,169.8				6,675.2
Due to General Partner and affiliates (Note 10)			215.8				148.3
Other long-term liabilities (Notes 6, 11, 12 and 13)			357.0				278.1
			9,347.6				9,017.5
Commitments and contingencies (Note 11)
Partners’ capital: (Notes 9 and 10)
Series 1 preferred units (48,000,000 authorized and issued at September 30, 2015 and December 31, 2014)			1,185.7				1,175.6
Class D units (66,100,000 authorized and issued at September 30, 2015 and December 31, 2014)			2,517.6				2,516.8
Class E units (18,114,975 authorized and issued at September 30, 2015)			778.3				—
Class A common units (262,208,428 and 254,208,428 authorized and issued at September 30, 2015 and December 31, 2014, respectively)			—				235.5
Class B common units (7,825,500 authorized and issued at September 30, 2015 and December 31, 2014)			—				—
i-units (71,742,557 and 68,305,187 authorized and issued at September 30, 2015 and December 31, 2014, respectively)			399.6				712.6
Incentive distribution units (1,000 authorized and issued at September 30, 2015 and December 31, 2014)			494.9				493.0
General Partner			169.5				198.3
Accumulated other comprehensive loss (Note 12)			(388.7	)			(211.4	)
Total Enbridge Energy Partners, L.P. partners’ capital			5,156.9				5,120.4
Noncontrolling interest (Note 10)			3,902.4				3,609.0
Total partners’ capital			9,059.3				8,729.4
		$	18,406.9			$	17,746.9

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

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ENBRIDGE ENERGY PARTNERS, L.P.
 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

1. BASIS OF PRESENTATION

We have prepared the accompanying unaudited interim consolidated financial statements in accordance with generally accepted accounting principles in the United States of America, or GAAP, for interim consolidated financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. Accordingly, the unaudited interim consolidated financial statements do not include all the information and footnotes required by GAAP 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 as of September 30, 2015, our results of operations for the three and nine months ended September 30, 2015 and 2014, and our cash flows for the nine months ended September 30, 2015 and 2014. We derived our consolidated statement of financial position as of December 31, 2014, from the audited financial statements included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2014. Our results of operations for the three and nine months ended September 30, 2015 and 2014, should not be taken as indicative of the results to be expected for the full year due to seasonal fluctuations in the supply of and demand for crude oil, seasonality of portions of our natural gas business, timing and completion of our construction projects, maintenance activities, the impact of forward commodity prices and differentials on derivative financial instruments that are accounted for at fair value and the effect of environmental costs and related insurance recoveries on our Lakehead system. Our unaudited interim consolidated financial statements should be read in conjunction with our audited consolidated financial statements and notes thereto presented in our Annual Report on Form 10-K for the fiscal year ended December 31, 2014.

2. NET INCOME PER LIMITED PARTNER UNIT

We allocate our net income among our Series 1 Preferred Units, or Preferred Units, our General Partner interest and our limited partner units using the two-class method in accordance with applicable authoritative accounting guidance. Under the two-class method, we allocate our net income attributable to our General Partner and our limited partners according to the distribution formula for available cash as set forth in our partnership agreement. We allocate our net income to our limited partners owning Class D units and Class E units equal to the distributions that they receive. We also allocate any earnings in excess of distributions to our General Partner and limited partners owning Class A and Class B common units and i-units utilizing the distribution formula for available cash specified in our partnership agreement. We allocate any distributions in excess of earnings for the period to our General Partner and limited partners owning Class A and B common units and i-units based on their sharing of losses of 2% and 98%, respectively, as set forth in our partnership agreement. We calculate distributions to the General Partner and limited partners based upon the distribution rates and percentages set forth in the following table:

Distribution Targets		Portion of Quarterly Distribution Per Unit				Percentage Distributed to General Partner and IDUs(1)				Percentage Distributed to Limited partners
Minimum Quarterly Distribution			Up to $0.5435				2	%			98	%
First Target Distribution			> $0.5435				25	%			75	%

Equity Restructuring Transaction

On July 1, 2014, we entered into an equity restructuring transaction, or Equity Restructuring, with the General Partner in which the General Partner irrevocably waived its right to receive cash distributions and allocations of items of income, gain, deduction and loss in excess of 2% in respect of its general partner interest in the incentive distribution rights, or Previous IDRs, in exchange for the issuance to a wholly-owned subsidiary of the General Partner of (1) 66.1 million units of a new class of limited partner interests designated as Class D units, and (2) 1,000 units of a new class of limited partner interests designated as Incentive Distribution Units, or IDUs. Prior to this transaction we allocated distributions to the General Partner and limited partners as follows:

Distribution Targets		Portion of Quarterly Distribution Per Unit				Percentage Distributed to General Partner				Percentage Distributed to Limited partners
Minimum Quarterly Distribution			Up to $0.295				2	%			98	%
First Target Distribution			> $0.295 to $0.35				15	%			85	%
Second Target Distribution			> $0.35 to $0.495				25	%			75	%
Over Second Target Distribution			In excess of $0.495				50	%			50	%

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ENBRIDGE ENERGY PARTNERS, L.P.
 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

2. NET INCOME PER LIMITED PARTNER UNIT  – (continued)

Alberta Clipper Drop Down

On January 2, 2015, we completed a transaction to acquire from our General Partner the remaining 66.7% interest in the U.S. portion of the Alberta Clipper Pipeline. The consideration consisted of issuance to the General Partner of 18,114,975 units of a new class of limited partner interests designated as Class E units. For more information, refer to Note 9. Partners’ Capital.

We determined basic and diluted net income per limited partner unit as follows:

		For the three months ended September 30,								For the nine months ended September 30,
		2015				2014				2015				2014
		(in millions, except per unit amounts)
Net income		$	184.5			$	117.5			$	341.8			$	385.7
Less Net loss attributable to:
Noncontrolling interest			(77.8	)			(70.7	)			(139.1	)			(149.4	)
Series 1 preferred unit distributions			(22.5	)			(22.5	)			(67.5	)			(67.5	)
Accretion of discount on Series 1 preferred units			(2.1	)			(3.8	)			(10.1	)			(11.1	)
Net income attributable to general and limited partner interests in Enbridge Energy Partners, L.P.			82.1				20.5				125.1				157.7
Less distributions:
Incentive distributions			(5.3	)			(1.4	)			(13.8	)			(35.9	)
Distributed earnings attributed to our General Partner			(5.1	)			(4.5	)			(15.3	)			(12.6	)
Distributed earnings attributed to Class D and Class E units			(49.1	)			(33.1	)			(146.2	)			(69.8	)
Total distributed earnings to our General Partner, Class D and Class E units and IDUs			(59.5	)			(39.0	)			(175.3	)			(118.3	)
Total distributed earnings attributed to our common units and i-units			(199.2	)			(182.8	)			(591.2	)			(542.7	)
Total distributed earnings			(258.7	)			(221.8	)			(766.5	)			(661.0	)
Overdistributed earnings		$	(176.6	)		$	(201.3	)		$	(641.4	)		$	(503.3	)
Weighted average common units and i-units outstanding			341.1				328.8				337.9				327.6
Basic and diluted earnings per unit:
Distributed earnings per common unit and i-unit(1)		$	0.58			$	0.56			$	1.75			$	1.66
Overdistributed earnings per common unit and i-unit(2)			(0.51	)			(0.60	)			(1.86	)			(1.51	)
Net income (loss) per common unit and i-unit (basic and diluted)(3)		$	0.07			$	(0.04	)		$	(0.11	)		$	0.15

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ENBRIDGE ENERGY PARTNERS, L.P.
 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

3. ACQUISITIONS

We account for acquisitions using the acquisition method and record the identifiable assets acquired and liabilities assumed at their acquisition-date fair values. We have included the results of operations in our operating results from the acquisition date.

On February 27, 2015, Midcoast Energy Partners, L.P., or MEP, acquired the midstream business of New Gulf Resources, LLC, or NGR, in Leon, Madison and Grimes Counties, Texas. The acquisition consisted of a natural gas gathering system that is in operation. This acquisition strengthened MEP’s position into the Eaglebine play, and will continue to allow them to offer gathering and processing services while leveraging assets on their existing footprint.

MEP acquired NGR’s midstream business for $85.0 million in cash and a contingent future payment of up to $17.0 million. Of the $85.0 million purchase price, $20.0 million was placed into escrow, pending the resolution of a legal matter and NGR’s completion of additional wells connecting to our system. Since the acquisition date, MEP has released $5.0 million from escrow and paid it to NGR. The remaining $15.0 million in escrow has been classified as “Restricted cash” in our consolidated statements of financial position as of September 30, 2015.

If NGR is able to deliver volumes into the system at certain tiered volume levels over a five-year period, MEP will be obligated to make future tiered payments up to $17.0 million. This could result in a maximum total purchase price of $102.0 million. The potential payment is considered contingent consideration. At the acquisition date, the fair value of this contingent consideration, using a probability-weighted discounted cash flow model was $2.3 million. The contingent consideration is remeasured on a fair value basis each quarter until the performance bonus is paid or expires. At September 30, 2015, contingent consideration of $2.5 million, which includes $0.2 million in accretion, is included in “Other long-term liabilities” in our consolidated statements of financial position.

Funding was provided by us and MEP, based on our proportionate ownership percentages in Midcoast Operating, L.P., or Midcoast Operating, at the time of acquisition, which was 48.4% and 51.6%, respectively. This business is part of our Natural Gas segment.

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 made payments that have not yet been presented to the financial institution totaling approximately $16.9 million at September 30, 2015, and $17.9 million at December 31, 2014, are included in “Accounts payable and other” on our consolidated statements of financial position. At December 31, 2014, we reclassified book overdrafts of $40.0 million to “Accounts payable and other” on our consolidated statement of financial position. We did not have any book overdrafts at September 30, 2015.

5. INVENTORY

Our inventory is comprised of the following:

		September 30, 2015				December 31, 2014
		(in millions)
Materials and supplies		$	2.2			$	2.2
Crude oil inventory			0.8				13.2
Natural gas and NGL inventory			85.3				78.8
		$	88.3			$	94.2

“Commodity costs” on our consolidated statements of income include charges totaling $0.1 million and $1.5 million for the three months ended September 30, 2015 and 2014 respectively, and $5.4 million and $4.8 million for the nine months ended September 30, 2015 and 2014, respectively, that we recorded to reduce the cost basis of our inventory of natural gas and NGLs, to reflect the current market value.

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ENBRIDGE ENERGY PARTNERS, L.P.
 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

6. PROPERTY, PLANT AND EQUIPMENT

Our property, plant and equipment is comprised of the following:

		September 30, 2015				December 31, 2014
		(in millions)
Land		$	60.4			$	44.2
Rights-of-way			869.7				851.8
Pipelines			9,788.9				9,585.4
Pumping equipment, buildings and tanks(1)			4,092.5				3,261.8
Compressors, meters and other operating equipment			2,145.6				2,072.7
Vehicles, office furniture and equipment(1)			280.7				278.9
Processing and treating plants			632.8				516.0
Construction in progress			2,250.4				1,857.1
Total property, plant and equipment			20,121.0				18,467.9
Accumulated depreciation			(3,114.6	)			(2,775.2	)
Property, plant and equipment, net		$	17,006.4			$	15,692.7

On July 31, 2015, MEP sold its non-core Tinsley crude oil pipeline, storage facilities, and docks and its non-core Louisiana propylene pipeline for $1.3 million. These assets are part of our Natural Gas segment and had a combined carrying value of $4.5 million. The loss on disposal of $3.2 million for the three and nine months ended September 30, 2015, is included in “Operating and administrative” expense on our consolidated statement of income. The carrying amount of these assets was classified as assets held for sale in “Other current assets” on our consolidated statements of financial position before the sale. During the second quarter of 2015, we recorded $12.3 million in non-cash impairment charges on these assets, which are included in “Asset impairment” on our consolidated statements of income.

7. GOODWILL

Goodwill represents the excess of the purchase price of an entity over the estimated fair value of the assets acquired and liabilities assumed. Our goodwill originated from acquisitions that are fully associated with our natural gas business. The carrying amount of goodwill as of December 31, 2014, was $246.7 million.

We test goodwill for impairment annually or more frequently if events or changes in circumstances indicate that it is more likely than not that the fair value of a reporting unit is less than its carrying value. During May 2015, due to adverse market conditions facing our business, we learned from producers that reductions in drilling will be sustained and prolonged due to continued low prices for natural gas and NGLs. As a result, we determined that the impact on our forecasted operating profits and cash flows for the natural gas reporting unit for the next five years would be significantly reduced from our prior forecasts.

During the second quarter of 2015, we performed the first step of our goodwill impairment analysis and determined that the carrying value of the natural gas reporting unit exceeded its fair value. We completed the second step of the goodwill impairment analysis comparing the implied fair value of the reporting unit to the carrying amount of that goodwill, using amounts as of June 30, 2015, and determined that goodwill was completely impaired in the amount of $246.7 million. The impairment charge is presented as “Goodwill impairment” on our consolidated statement of income for the nine months ended September 30, 2015.

We measure the fair value of our reporting units primarily by using a discounted cash flow analysis. In addition, we also consider overall market capitalization of our business, cash flow measurement data and other factors. Our estimate of fair value required us to use significant unobservable inputs representative of a Level 3 fair value measurement, including assumptions related to the future performance of our natural gas reporting unit.

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ENBRIDGE ENERGY PARTNERS, L.P.
 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

8. DEBT

The following table presents the primary components of our outstanding indebtedness with third parties and the weighted average interest rates associated with each component as of September 30, 2015, before the effect of our interest rate hedging activities. Our indebtedness with related parties is discussed in Note 10. Related Party Transactions.

		Interest Rate				September 30, 2015				December 31, 2014
						(in millions)
EEP debt obligations:
Commercial Paper(1)			1.000%			$	321.1			$	612.3
Credit Facilities due 2016 – 2019			1.30% – 3.75%				1,885.0				1,160.0
Senior Notes due December 2016			5.875%				300.0				300.0
Senior Notes due October 2018			7.000%				100.0				100.0
Senior Notes due April 2018			6.500%				400.0				400.0
Senior Notes due March 2019			9.875%				500.0				500.0
Senior Notes due March 2020			5.200%				500.0				500.0
Senior Notes due September 2021			4.200%				600.0				600.0
Senior Notes due October 2028			7.125%				100.0				100.0
Senior Notes due June 2033			5.950%				200.0				200.0
Senior Notes due December 2034			6.300%				100.0				100.0
Senior Notes due April 2038			7.500%				400.0				400.0
Senior Notes due September 2040			5.500%				550.0				550.0
Junior subordinated notes due 2067			8.050%				400.0				400.0
MEP debt obligations:
MEP Credit Agreement due 2016 – 2018			2.672%				420.0				360.0
MEP Series A Senior Notes due September 2019			3.560%				75.0				75.0
MEP Series B Senior Notes due September 2021			4.040%				175.0				175.0
MEP Series C Senior Notes due September 2024			4.420%				150.0				150.0
Total Principal of Debt Obligations							7,176.1				6,682.3
Other:
Unamortized Discount							(6.3	)			(7.1	)
Total Long Term Debt						$	7,169.8			$	6,675.2

Interest Cost

Our interest cost for the three and nine months ended September 30, 2015, and 2014, is comprised of the following:

		For the three months ended September 30,								For the nine months ended September 30,
		2015				2014				2015				2014
		(in millions)
Interest cost incurred		$	98.8			$	148.7			$	243.4			$	329.9
Less: Interest capitalized			10.6				11.6				28.9				35.7
Interest expense		$	88.2			$	137.1			$	214.5			$	294.2

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ENBRIDGE ENERGY PARTNERS, L.P.
 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

8. DEBT  – (continued)

Credit Facilities and Commercial Paper

We have a committed multi-year senior unsecured revolving credit facility, which we refer to as the Credit Facility, and a 364-day credit agreement, which we refer to as the 364-Day Credit Facility. We refer to our Credit Facility and our 364-Day Credit Facility as the Credit Facilities. The Credit Facility permits aggregate borrowings of up to, at any one time outstanding, $1.975 billion. The maturity date on the Credit Facility is September 26, 2019; except for, $175.0 million of commitments will expire on the original maturity date of September 26, 2018. At September 30, 2015, we had $1,885.0 million outstanding under our Credit Facilities at a weighted average interest rate of 2.13%. During the nine months ended September 30, 2015, we had net borrowings of $725.0 million, which includes gross borrowings of $12,285.0 million and gross repayments of $11,560.0 million.

On July 2, 2015, we amended our 364-Day Credit Facility to extend the revolving credit termination date from July 3, 2015 to July 1, 2016. We further amended the 364-Day Credit Facility to decrease the aggregate commitments from $650.0 million to $525.0 million: (1) on a revolving basis for a 364-day period, extendible annually at the lenders’ discretion, and (2) for a 364-day term on a non-revolving basis following the expiration of all revolving periods. On August 7, 2015, we exercised our right to increase the total amount of commitments under the 364-Day Credit Facility by $100.0 million to $625.0 million.

At September 30, 2015, the Credit Facilities provide an aggregate amount of approximately $2.6 billion of bank credit, which we use to fund our general activities and working capital needs.

In addition, we have a credit agreement with Enbridge (U.S.) Inc., or EUS, an affiliate of Enbridge and the owner of our General Partner, or the EUS 364-day Credit Facility, that permits aggregate borrowing of up to, at any one time outstanding, $750.0 million, which is discussed in Note 10. Related Party Transactions.

We have a commercial paper program that provides for the issuance of up to an aggregate principal amount of $1.5 billion of commercial paper and is supported by our Credit Facilities. We access the commercial paper market primarily to provide temporary financing for our operating activities, capital expenditures and acquisitions when the available interest rates we can obtain are lower than the rates available under our Credit Facilities. At September 30, 2015, we had approximately $321.1 million in principal amount of commercial paper outstanding at a weighted average interest rate of 1.00%, excluding the effect of our interest rate hedging activities. Under our commercial paper program, we had net repayments of approximately $291.0 million during the nine months ended September 30, 2015, which includes gross borrowings of $8,436.1 million and gross repayments of $8,727.1 million. At December 31, 2014, we had approximately $612.3 million in principal amount of commercial paper outstanding at a weighted average interest rate of 0.50%, excluding the effect of our interest rate hedging activities. Our policy is to limit the amount of commercial paper we can issue by the amounts available under our Credit Facility up to an aggregate principal amount of $1.5 billion.

We have an uncommitted letter of credit arrangement, pursuant to which the lender may, on a discretionary basis and with no commitment, agree to issue standby letters of credit upon our request. The aggregate amount of this uncommitted letter of credit is not to exceed $220.0 million. While the letter of credit arrangement is uncommitted and issuance of letters of credit is at the lender’s sole discretion, we view this arrangement as a liquidity enhancement as it allows us to potentially reduce our reliance on utilizing our committed Credit Facilities for issuance of letters of credit to support our hedging activities.

The amounts we may borrow under the terms of our Credit Facilities are reduced by the face amount of our letters of credit outstanding. Our policy is to maintain availability at any time under our Credit Facilities amounts that are at least equal to the amount of commercial paper that we have outstanding at any time.

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ENBRIDGE ENERGY PARTNERS, L.P.
 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

8. DEBT  – (continued)

At September 30, 2015, we had approximately $724.6 million available under the terms of our Credit Facilities and the EUS 364-day Credit Facility, determined as follows:

		(in millions)
Total credit available under our Credit Facilities		$	2,600.0
Total credit available under the EUS 364-day Credit Facility			750.0
Less: Amounts outstanding under our Credit Facilities			1,885.0
Principal amount of commercial paper outstanding			321.1
EUS 364-day Credit Facility(1)			—
Letters of credit outstanding			419.3
Total amount available at September 30, 2015(2)		$	724.6

As of September 30, 2015, we were in compliance with the terms of all of our financial covenants under our Credit Facilities and the EUS 364-day Credit Facility.

MEP Credit Agreement

MEP, Midcoast Operating, and their material domestic subsidiaries are party to a senior revolving credit facility, which we refer to as the MEP Credit Agreement, which previously permitted aggregate borrowings of up to, at any one time outstanding, $850.0 million. The original term of the MEP Credit Agreement was three years with an initial maturity date of November 13, 2016, subject to four one-year requests for extensions. On September 3, 2015, MEP amended the MEP Credit Agreement and decreased the aggregate commitments to $810.0 million and to extend the maturity date from September 30, 2017 to September 30, 2018; except for, $140.0 million of commitments will expire on the initial maturity date of November 13, 2016 and $25 million of commitments that will expire on September 30, 2017.

At September 30, 2015, MEP had $420.0 million in outstanding borrowings under the MEP Credit Agreement at a weighted average interest rate of 2.7%. Under the MEP Credit Agreement, MEP had net borrowings of approximately $60.0 million during the nine months ended September 30, 2015, which includes gross borrowings of $4,160.0 million and gross repayments of $4,100.0 million. As of September 30, 2015, MEP was in compliance with the terms of its financial covenants.

MEP Senior Notes

MEP’s senior notes in the aggregate amount of $400.0 million were issued in a private placement on September 30, 2014 and consist of three tranches: $75.0 million of 3.56% Series A Senior Notes due in 2019; $175.0 million of 4.04% Series B Senior Notes due in 2021; and $150.0 million of 4.42% Series C Senior Notes due in 2024, collectively the Notes. All of the Notes pay interest semi-annually on March 31 and September 30, which commenced on March 31, 2015. At September 30, 2015, MEP was in compliance with the terms of its financial covenants under the note purchase agreement.

Fair Value of Debt Obligations

The carrying amounts of our outstanding commercial paper, borrowings under our Credit Facilities, and the MEP Credit Agreement approximate their fair values at September 30, 2015, and December 31, 2014, respectively, due to the short-term nature and frequent repricing of the amounts outstanding under these obligations. The fair value of our outstanding commercial paper and borrowings under our Credit Facilities and the MEP Credit Agreement are included with our long-term debt obligations since we have the ability and the intent to refinance the amounts outstanding on a long-term basis.

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ENBRIDGE ENERGY PARTNERS, L.P.
 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

8. DEBT  – (continued)

The approximate fair value of our fixed-rate debt obligations was $4.7 billion and $5.1 billion at September 30, 2015, and December 31, 2014, respectively. We determined the approximate fair values 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 value of the principal obligation to be repaid at maturity and all future interest payment obligations for any debt outstanding. The fair value of our long-term debt obligations is categorized as Level 2 within the fair value hierarchy.

9. PARTNERS’ CAPITAL

Distribution to Partners

The following table sets forth our distributions, as approved by the board of directors of Enbridge Energy Management, or Enbridge Management, during the nine months ended September 30, 2015.

Distribution      Declaration Date		Record Date				Distribution Payment Date				Distribution per Unit				Cash available for distribution				Amount of Distribution of i-units to i-unit Holders(1)				Retained from General Partner(2)				Distribution of Cash
														(in millions, except per unit amounts)
July 30, 2015			August 7, 2015				August 14, 2015			$	0.5830			$	257.9			$	41.0			$	0.8			$	216.1
April 30, 2015			May 8, 2015				May 15, 2015			$	0.5700			$	249.9			$	39.5			$	0.8			$	209.6
January 29, 2015			February 6, 2015				February 13, 2015			$	0.5700			$	233.9			$	38.9			$	0.8			$	194.2

Changes in Partners’ Capital

The following table presents significant changes in partners’ capital accounts attributable to our General Partner and limited partners as well as the noncontrolling interests in our consolidated subsidiaries, Enbridge Energy, Limited Partnership, or OLP, the North Dakota Pipeline Company LLC, or NDPC, and MEP, for the nine months ended September 30, 2015 and 2014. The noncontrolling interest in the OLP arises from the joint funding arrangements with our General Partner and its affiliate to finance: (1) expansion of our Lakehead system to transport crude oil to destinations in the Midwest United States, which we refer to as the Eastern Access Projects; and (2) further expansion of our Lakehead system to transport crude oil between Neche, North Dakota and Superior, Wisconsin, which we refer to as the Mainline Expansion Projects. Noncontrolling interest in NDPC arises from our agreement with Williston Basin Pipeline LLC, or Williston, an affiliate of Marathon Petroleum Corporation, to, among other things, become a member of NDPC. Williston funds 37.5% of the Sandpiper Project that will expand the North Dakota feeder system to Superior, Wisconsin mainline system terminal. Noncontrolling interest in MEP arises from its public unitholders’ ownership interests in MEP.

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ENBRIDGE ENERGY PARTNERS, L.P.
 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

9. PARTNERS’ CAPITAL  – (continued)

		For the nine months ended September 30,
		2015				2014
		(in millions)
Series 1 Preferred interests
Beginning balance		$	1,175.6			$	1,160.7
Net income			67.5				67.5
Accretion of discount on preferred units			10.1				11.1
Distribution payable			(67.5	)			(67.5	)
Ending balance		$	1,185.7			$	1,171.8
General and limited partner interests
Beginning balance		$	4,156.2			$	4,637.7
Proceeds from issuance of partnership interests, net of costs			294.8				—
Net income			125.1				157.7
Distributions			(619.9	)			(544.2	)
Transfer of interests in subsidiary to Midcoast Energy Partners, L.P.			—				(125.4	)
Acquisition of noncontrolling interest in subsidiary			403.7
Ending balance		$	4,359.9			$	4,125.8
Accumulated other comprehensive loss
Beginning balance		$	(211.4	)		$	(76.6	)
Changes in fair value of derivative financial instruments reclassified to earnings			(6.4	)			22.2
Changes in fair value of derivative financial instruments recognized in other comprehensive loss			(170.9	)			(104.6	)
Ending balance		$	(388.7	)		$	(159.0	)
Noncontrolling interest
Beginning balance		$	3,609.0			$	1,975.6
Capital contributions			740.6				1,083.0
Transfer of interests in subsidiary to Midcoast Energy Partners, L.P.			—				125.4
Acquisition of noncontrolling interest in subsidiary			(403.7	)			—
Other comprehensive income (loss) allocated to noncontrolling interest			(3.9	)			1.8
Net income			139.1				149.4
Distributions to noncontrolling interest			(178.7	)			(80.9	)
Ending balance		$	3,902.4			$	3,254.3
Total partners’ capital at end of period		$	9,059.3			$	8,392.9

Series 1 Preferred Unit Amendment

On July 30, 2015, we amended our limited partnership agreement to extend the deferral of distribution payments through June 30, 2018 and to allow repayment of the accumulated deferral amount in equal amounts over a twelve-quarter period beginning in the first quarter of 2019. In addition, the amendment extended the rate reset pricing date to June 30, 2020, and each subsequent five-year anniversary thereafter. The amendment also defers the conversion option date, whereby the holder of the preferred units may convert their Series 1 preferred units into Class A common units, to on or after June 30, 2018.

The amendment to the Series 1 Preferred Unit was accounted for as a modification, as the difference in the fair value of the preferred units before and after the modification was insignificant. As a result, there were no changes in the partnership capital accounts as a result of the amendment. The remaining unamortized beneficial conversion feature after the amendment will be amortized over an extended period through June 30, 2018.

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ENBRIDGE ENERGY PARTNERS, L.P.
 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

9. PARTNERS’ CAPITAL  – (continued)

Alberta Clipper Drop Down

On January 2, 2015, we completed a transaction, or the Drop Down, pursuant to which we acquired the remaining 66.7% interest in the U.S. segment of the Alberta Clipper Pipeline from our General Partner. The consideration consisted of approximately 18,114,975 units of a new class of limited partner interests designated as Class E units issued to the General Partner. The Class E units were issued at a notional value of $38.31 per unit. The notional value was determined based on the trailing five-day volume-weighted average price of our Class A common units as of December 23, 2014, which was the date on which we and the General Partner entered into a contribution agreement setting forth the terms of the Drop Down. In addition, we repaid the borrowings outstanding of $306.0 million on the A1 Term Note owed to the General Partner.

The Class E units are entitled to the same distributions as Class A common units held by the public and are convertible into Class A common units on a one-for-one basis at the General Partner’s option. The Class E units were not entitled to distributions with respect to the quarter ended December 31, 2014. The Class E units are redeemable at our option after 30 years, if not earlier converted by the General Partner.

The Class E units have a liquidation preference equal to their notional value of $38.31 per unit. If the aggregate Earnings Before Interest, Taxes, Depreciation and Amortization, or EBITDA, attributable to the Series AC interest in the OLP for calendar years 2015 and 2016 is less than $265.9 million, then 1,305,142 of the Class E units will be cancelled by us effective as of June 15, 2017, for no consideration and will no longer be deemed outstanding for any purposes under our partnership agreement.

In addition, during each taxable year during the period from January 1, 2015 through December 31, 2037 in which a majority of the Class E units issued on the closing date of the Drop Down remain outstanding, holders of Class A common units, Class B common units and Class D units (including those held by the General Partner) will be specially allocated items of gross income that would otherwise be allocated to holders of Class E units, to the extent that such an amount of gross income exists, in an annual amount equal to $40.0 million. The annual amount of such allocation will be reduced to $20.0 million for each taxable year beginning after December 31, 2037.

We recorded the Drop Down as an equity transaction. No loss on the acquisition of the remaining ownership interests in Alberta Clipper was recognized in our consolidated statement of income or comprehensive income. We reduced the carrying value of the related “Noncontrolling interest” in Alberta Clipper of $403.7 million to zero. In addition, we recorded the Class E units at their fair value of $767.7 million. We determined the fair value of the Class E units using a market approach based upon the closing price of the Class A common units as of January 2, 2015, adjusted for differences in specific rights such as the liquidation preference granted to the Class E units and other economic factors that would affect the fair value of the Class E units.

The difference of $364.0 million between the fair value of the Class E units and the carrying value of the noncontrolling interest in Alberta Clipper was recorded as a reduction to the carrying amounts of the capital accounts of the Class A and Class B common units, the i-units and the General Partner interest on a pro rata basis. The recording of this transaction reduced the carrying values of the Class A and Class B common units below zero. Our partnership agreement requires that such capital account deficits are brought back to zero, or “cured,” by additional allocations from the capital accounts of the i-units and General Partner interest on a pro-rata basis. As a result the i-units’ and General Partner interest’s capital balances were reduced by $46.7 million and $1.0 million, respectively, to cure the deficit balances in the Class A and Class B common units. This initial curing did not impact earnings allocated to either the i-units or the General Partner interest.

Additional Curing

During 2015, in addition to the curing of the Class A and Class B common units resulting from the Drop Down, the carrying amounts for the capital accounts of the Class A and Class B common units were reduced below zero due to distributions to partners in excess of earnings attributable to partners. As a result, the capital balances of the i-units and General Partner interests were reduced by $185.4 million and $13.5 million, respectively, to cure the deficit balances in the Class A and Class B common units.

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ENBRIDGE ENERGY PARTNERS, L.P.
 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

9. PARTNERS’ CAPITAL  – (continued)

Shelf-Registration Statement

From time to time, we may seek to satisfy liquidity needs through the offer and sale of debt or equity securities in public offerings. In February 2015, we filed with the SEC a new automatically effective shelf registration statement, or the 2015 Shelf, on Form S-3 that replaced our prior shelf registration statement which expired in December 2014. The 2015 Shelf allows us to issue an unlimited amount of equity and debt securities in underwritten public offerings.

Issuance of Class A Common Units

In March 2015, we sold 8 million Class A common units in an underwritten public offering pursuant to the 2015 Shelf for net proceeds of $288.8 million. The proceeds from the March 2015 offering were used to fund a portion of our capital expansion projects and for general partnership purposes.

The following table presents the net proceeds for our Class A common unit issuances for the current year.

2015 Issuance Date		Number of Class A common units Issued				Offering Price per Class A common unit				Net Proceeds to the Partnership(1)				General Partner Contribution(2)				Net Proceeds Including General Partner Contribution
		(in millions, except units and per unit amount)
March			8,000,000			$	36.70			$	288.8			$	6.0			$	294.8

10. RELATED PARTY TRANSACTIONS

Administrative and Workforce Related Services

We do not directly employ any of the individuals responsible for managing or operating our business, nor do we have any directors. Enbridge and its affiliates provide management and we obtain managerial, administrative, operational and workforce related services from our General Partner, Enbridge Management and affiliates of Enbridge pursuant to service agreements among our General Partner, Enbridge Management, affiliates of Enbridge, and us. Pursuant to these service agreements, we have agreed to reimburse our General Partner, Enbridge Management and affiliates of Enbridge, for the cost of managerial, administrative, operational and director services they provide to us. Where directly attributable, the cost of all compensation, benefits expenses and employer expenses for these employees are charged directly by Enbridge to the appropriate affiliate. Enbridge does not record any profit or margin for the administrative and operational services charged to us.

The affiliate amounts incurred by us for services received pursuant to the services agreements are reflected in “Operating and administrative — affiliate” on our consolidated statements of income.

Financing Transactions with Affiliates

EUS 364-day Credit Facility

On March 9, 2015, we entered into an unsecured revolving 364-day credit agreement with EUS, which we refer to as the EUS 364-day Credit Facility. The EUS 364-day Credit Facility is a committed senior unsecured revolving credit facility that permits aggregate borrowings of up to, at any one time outstanding, $750 million, (1) on a revolving basis for a 364-day period and (2) for a 364-day term on a non-revolving basis following the expiration of the revolving period. Loans under the EUS 364-day Credit Facility accrue interest based, at our election, on either the Eurocurrency rate or a base rate, in each case, plus an applicable margin. The EUS 364-day Credit Facility terminates on March 7, 2016, and including the option to term the revolving loan for a period of 364-days following the termination date, matures on March 6, 2017. There is no outstanding balance as of September 30, 2015 under the EUS 364-day Credit Facility.

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ENBRIDGE ENERGY PARTNERS, L.P.
 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

10. RELATED PARTY TRANSACTIONS  – (continued)

The commitment under the EUS 364-day Credit Facility may be permanently reduced by EUS, from time to time, by up to an amount equal to the net cash proceeds to us from the sale by us of (1) debt or equity securities in a registered public offering, or (2) limited partnership interests in Midcoast Operating to MEP.

Distribution from MEP

The following table presents distributions paid by MEP during the nine months ended September 30, 2015, to its public Class A common unitholders, representing the noncontrolling interest in MEP, and to us for our ownership of Class A common units.

Distribution      Declaration Date		Distribution Payment Date				Amount Paid to EEP				Amount Paid to the noncontrolling interest				Total MEP Distribution
										(in millions)
July 29, 2015			August 14, 2015			$	8.8			$	7.5			$	16.3
April 29, 2015			May 15, 2015				8.6				7.4				16.0
January 28, 2015			February 13, 2015				8.5				7.3				15.8
						$	25.9			$	22.2			$	48.1

Distribution to Series AC Interests

On January 2, 2015, we completed a transaction, or the Drop Down, pursuant to which we acquired the remaining 66.7% interest in the U.S. segment of the Alberta Clipper Pipeline from our General Partner.

The following table presents the final ownership distribution for the fourth quarter of 2014 paid by the OLP to our General Partner and its affiliate on February 13, 2015, representing the noncontrolling interest in the Series AC, and to us, as the holders of the Series AC general and limited partner interests. The distributions were declared by the board of directors of Enbridge Management, acting on behalf of Enbridge Pipelines (Lakehead) L.L.C., the managing general partner of the OLP and the Series AC interests. Pursuant to the OLP’s partnership agreement, the final ownership distribution for the Series AC interests was distributed to Series AC partners of record as of the last day of the fourth quarter.

Distribution      Declaration Date		Distribution Payment Date				Amount Paid to Partnership				Amount paid to the noncontrolling interest				Total Series AC Distribution
										(in millions)
January 29, 2015			February 13, 2015			$	13.7			$	27.5			$	41.2

Amendment of OLP Limited Partnership Agreement

On July 30, 2015, the partners amended and restated the limited partnership agreement of the OLP, pursuant to which our General Partner will temporarily forego Series EA and ME, collectively, the Series, distributions commencing in the quarter ended June 30, 2015 through the quarter ending March 31, 2016. The General Partner’s capital funding contribution requirements for each of those two Series, commencing in August 2015, will be reduced by the amount of its foregone cash distributions from the respective Series, until the earlier of December 31, 2016 and the date aggregate reductions in capital contributions for such Series are equal to the foregone cash distributions for such Series. To the extent that the General Partner’s portion of capital contributions prior to December 31, 2016 are insufficient to cover the General Partner’s foregone cash distributions for a Series, beginning with the distribution related to the first quarter of 2017 for that Series, we will receive reduced cash distributions by up to 50%, and the General Partner will receive a comparable increase in cash distributions each quarter until the General Partner has received an aggregate amount of contribution reductions and distribution increases equal to the amount of foregone cash distributions.

Joint Funding Arrangement for Eastern Access Projects

The OLP has a series of partnership interests, which we refer to as the EA interests. The EA interests were created to finance projects to increase access to refineries in the U.S. Upper Midwest and in Ontario, Canada for light crude oil produced in western Canada and the United States, which we refer to as the Eastern Access Projects. Our General Partner owns 75% of the EA interests, and, except as described above in Amendment of OLP Limited Partnership Agreement, the projects are jointly funded by our General Partner at 75% and us at 25%.

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ENBRIDGE ENERGY PARTNERS, L.P.
 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

10. RELATED PARTY TRANSACTIONS  – (continued)

Our General Partner made equity contributions totaling $119.3 million and $550.5 million to the OLP during the nine months ended September 30, 2015 and 2014, respectively, to fund its equity portion of the construction costs associated with the Eastern Access Projects.

Distribution to Series EA Interests

The following table presents distributions paid by the OLP during the nine months ended September 30, 2015, to our General Partner and its affiliate, representing the noncontrolling interest in the Series EA, and to us, as the holders of the Series EA general and limited partner interests. The distributions were declared by the board of directors of Enbridge Management, acting on behalf of Enbridge Pipelines (Lakehead), L.L.C., the managing general partner of the OLP and the Series EA interests.

Distribution      Declaration Date		Distribution Payment Date				Amount Paid to EEP				Amount Paid to the noncontrolling interest				Total Series EA Distribution
										(in millions)
July 30, 2015			August 14, 2015			$	56.5			$	—			$	56.5
April 30, 2015			May 15, 2015				17.5				52.3				69.8
January 29, 2015			February 13, 2015				22.3				67.0				89.3
						$	96.3			$	119.3			$	215.6

Joint Funding Arrangement for U.S. Mainline Expansion Projects

The OLP also has a series of partnership interests, which we refer to as the ME interests. The ME interests were created to finance projects to increase access to the markets of North Dakota and western Canada for light oil production on our Lakehead System between Neche, North Dakota and Superior, Wisconsin, which we refer to as our Mainline Expansion Projects. Our General Partner owns 75% of the ME interests, and, except as described above in Amendment of OLP Limited Partnership Agreement, the projects are jointly funded by our General Partner at 75% and us at 25%, under the Mainline Expansion Joint Funding Agreement, which is similar to the Eastern Access Joint Funding Agreement.

Our General Partner has made equity contributions totaling $552.9 million and $384.0 million to the OLP for the nine months ended September 30, 2015, and 2014, respectively, to fund its equity portion of the construction costs associated with the Mainline Expansion Projects.

Distribution to Series ME Interests

The following table presents distributions paid by the OLP during the nine months ended September 30, 2015, to our General Partner and its affiliate, representing the noncontrolling interest in the Series ME, and to us, as the holders of the Series ME general and limited partner interests. The distributions were declared by the board of directors of Enbridge Management, acting on behalf of Enbridge Pipelines (Lakehead), L.L.C., the managing general partner of the OLP and the Series ME interests.

Distribution      Declaration Date		Distribution Payment Date				Amount Paid to EEP				Amount Paid to the noncontrolling interest				Total Series ME Distribution
										(in millions)
July 30, 2015			August 14, 2015			$	14.8			$	—			$	14.8
April 30, 2015			May 15, 2015				1.5				4.5				6.0
January 29, 2015			February 13, 2015				1.8				5.2				7.0
						$	18.1			$	9.7			$	27.8

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ENBRIDGE ENERGY PARTNERS, L.P.
 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

10. RELATED PARTY TRANSACTIONS  – (continued)

Noncontrolling Interests

The following table presents the components of net income (loss) attributable to noncontrolling interests as presented on our consolidated statements of income:

		For the three months ended September 30,								For the nine months ended September 30,
		2015				2014				2015				2014
		(in millions)								(in millions)
Alberta Clipper Interests		$	—			$	16.3			$	(0.8	)		$	38.0
Eastern Access Interests			50.3				41.7				140.2				90.5
U.S. Mainline Expansion Interests			29.1				9.8				73.5				20.0
Midcoast Energy Partners, L.P.			(1.6	)			2.9				(73.8	)			0.9
Total		$	77.8			$	70.7			$	139.1			$	149.4

Sale of Accounts Receivable

We sold and derecognized receivables to a wholly-owned subsidiary of Enbridge for $911.8 million and $1,260.1 million for the three months ended September 30, 2015 and 2014, respectively, and $2,925.5 million and $3,792.8 million for the nine months ended September 30, 2015 and 2014, respectively. We received cash proceeds of $911.5 million and $1,259.8 million for the three months ended September 30, 2015 and 2014, respectively and $2,924.7 million and $3,791.8 million for the nine months ended September 30, 2015 and 2014, respectively. As of September 30, 2015, $341.3 million of the receivables were outstanding and had not been collected on behalf of the Enbridge subsidiary.

Consideration for the receivables sold is equivalent to the carrying value of the receivables less a discount for credit risk. The difference between the carrying value of the receivables sold and the cash proceeds received is recognized in “Operating and administrative — affiliate” expense in our consolidated statements of income. For the three and nine months ended September 30, 2015 and 2014, the cost stemming from the discount on the receivables sold was not material.

As of September 30, 2015 and December 31, 2014, we had $15.0 million and $71.9 million, respectively, in “Restricted cash” on our consolidated statements of financial position, consisting of cash collections related to the receivables sold that have yet to be remitted to the Enbridge subsidiary.

Affiliate Revenues and Purchases

We purchase natural gas from third-parties, which subsequently generates operating revenues from sales to Enbridge and its affiliates. These transactions are entered into at the market price on the date of sale and are presented in “Commodity sales — affiliate” on our consolidated statements of income. We also record operating revenues in our Liquids segment for storage, transportation and terminaling services we provide to affiliates, which are presented in “Transportation and other services — affiliate” on our consolidated statements of income.

We also purchase natural gas from Enbridge and its affiliates for sale to third-parties at market prices on the date of purchase. Purchases of natural gas, NGLs, and crude oil from Enbridge and its affiliates are presented in “Commodity costs — affiliate” on our consolidated statements of income.

Related Party Transactions with Joint Ventures

We have a 35% aggregate indirect interest in the Texas Express NGL system, which is comprised of two joint ventures with third parties that together include a 593-mile NGL intrastate transportation pipeline and a related NGL gathering system. Our equity investment in the Texas Express NGL system at September 30, 2015 and December 31, 2014, was $373.7 million and $380.6 million, respectively, which is included on our consolidated statements of financial position in “Other assets, net.” We recognized equity income of $8.9 million and $6.1 million for the three months ended September 30, 2015 and 2014, respectively, and $20.5 million and $7.1 million for the nine months ended September 30, 2015 and 2014, respectively, in “Other income” on our consolidated statements of income related to our investment in the system.

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ENBRIDGE ENERGY PARTNERS, L.P.
 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

10. RELATED PARTY TRANSACTIONS  – (continued)

We incurred $5.1 million and $5.4 million for the three months ended September 30, 2015 and 2014, respectively, and $13.4 million and $16.8 million for the nine months ended September 30, 2015 and 2014, respectively, of pipeline transportation and demand fees from Texas Express NGL system for our Natural Gas business. These expenses are included in “Commodity costs — affiliate” on our consolidated statements of income.

Our Natural Gas business has made commitments to transport up to 120,000 barrels per day, or Bpd, of NGLs on the Texas Express NGL system from 2015 to 2022. The current commitment level is 29,000 Bpd.

Lease and Storage Services Agreement

We have an agreement with Illinois Extension Pipeline Company, L.L.C., or IEPC, an equity method investment of our General Partner, pursuant to which IEPC built two storage tanks at our storage facility in Flanagan, Illinois. We lease the tanks from IEPC and operate them. IEPC will pay us operating fees for the operation of the tanks beginning in the fourth quarter of 2015.

11. 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 are, at times, 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. To the extent that we are unable to recover payment for environmental liabilities from insurance or other potentially responsible parties, we will be responsible for payment of liabilities arising from environmental incidents associated with the operating activities of our Liquids and Natural Gas businesses. Our General Partner has agreed to indemnify us from and against any costs relating to environmental liabilities associated with the Lakehead system assets prior to the transfer of these assets to us in 1991. This excludes any liabilities resulting from a change in laws after such transfer. We continue to voluntarily investigate past leak sites on our systems for the purpose of assessing whether any remediation is required in light of current regulations.

As of September 30, 2015 and December 31, 2014, we had $101.6 million and $141.7 million, respectively, included in “Environmental liabilities,” and $62.6 million and $60.1 million, respectively, included in “Other long-term liabilities,” on our consolidated statements of financial position that we have accrued for costs we have recognized 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.

Lakehead Lines 6A & 6B Crude Oil Releases

Line 6A Crude Oil Release

On September 9, 2010, a crude oil release occurred on Line 6A in Romeoville, Illinois, caused by a third party water pipeline failure which damaged our pipelines. One claim was filed against us and our affiliates by the State of Illinois in Illinois state court in connection with this crude oil release. On February 20, 2015, we agreed to a consent order releasing us from any claims, liability, or penalties.

Line 6B Crude Oil Release

On July 26, 2010, a release of crude oil on Line 6B of our Lakehead system was reported near Marshall, Michigan. We estimate that approximately 20,000 barrels of crude oil were leaked at the site, a portion of which reached the Kalamazoo River via Talmadge Creek, a waterway that feeds the Kalamazoo River. The released crude oil affected approximately 38 miles of shoreline along the Talmadge Creek and Kalamazoo River waterways, including residential areas, businesses, farmland and marshland between Marshall and downstream of Battle Creek, Michigan.

We continue to perform necessary remediation, restoration and monitoring of the areas affected by the Line 6B crude oil release. All the initiatives we are undertaking in the monitoring and restoration phase are intended to restore the crude oil release area to the satisfaction of the appropriate regulatory authorities.

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ENBRIDGE ENERGY PARTNERS, L.P.
 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

11. COMMITMENTS AND CONTINGENCIES  – (continued)

On March 14, 2013, we received an order from the EPA, which we refer to as the Order, that required additional containment and active recovery of submerged oil relating to the Line 6B crude oil release. In February 2015, the EPA acknowledged our completion of the Order.

In November 2014, regulatory authority was transferred from the EPA to the Michigan Department of Environmental Quality, or MDEQ. The MDEQ has oversight over submerged oil reassessment, sheen management and sediment trap monitoring and maintenance activities, through a Kalamazoo River Residual Oil Monitoring and Maintenance Work Plan.

In May 2015, Enbridge reached a settlement with the MDEQ and the Michigan Attorney General’s offices regarding the Line 6B crude oil release. As stipulated in the settlement, Enbridge agrees to: (1) provide at least 300 acres of wetland through restoration, creation, or banked wetland credits, to remain as wetland in perpetuity, (2) pay $5.0 million as mitigation for impacts to the banks, bottomlands, and flow of Talmadge Creek and the Kalamazoo River for the purpose of enhancing the Kalamazoo River watershed and restoring stream flows in the River, (3) continue to reimburse the State of Michigan for costs arising from oversight of Enbridge activities since the release, and (4) continue monitoring, restoration and invasive species control within state-regulated wetlands affected by the release and associated response activities. The timing of these activities is based upon the work plans approved by the State of Michigan.

As of September 30, 2015, our cumulative cost estimate for the Line 6B crude oil release remains at $1.2 billion.

For purposes of estimating our expected losses associated with the Line 6B crude oil release, we have included those costs that we considered probable and that could be reasonably estimated at September 30, 2015. Our estimates exclude: (1) amounts we have capitalized, (2) any claims associated with the release that may later become evident, (3) amounts recoverable under insurance, and (4) fines and penalties from other governmental agencies except as described in the Line 6B Fines and Penalties section below. Our assumptions include, where applicable, estimates of the expected number of days the associated services will be required and rates that we have obtained from contracts negotiated for the respective service and equipment providers. As we receive invoices for the actual personnel, equipment and services, our estimates will continue to be further refined. Our estimates also consider currently available facts, existing technology and presently enacted laws and regulations. These amounts also consider our and other companies’ prior experience remediating contaminated sites and data released by government organizations. Despite the efforts we have made to ensure the reasonableness of our estimates, changes to the recorded amounts associated with this release are possible as more reliable information becomes available. We continue to have the potential of incurring additional costs in connection with this crude oil release due to variations in any or all of the categories described above, including modified or revised requirements from regulatory agencies, in addition to fines and penalties as well as expenditures associated with litigation and settlement of claims.

The material components underlying our cumulative estimated loss for the cleanup, remediation and restoration associated with the Line 6B crude oil release include the following:

		(in millions)
Response personnel and equipment		$	548.5
Environmental consultants			227.0
Professional, regulatory and other			432.5
Total		$	1,208.0

For the nine months ended September 30, 2015 and 2014, we made payments of $32.0 million and $117.4 million, respectively, for costs associated with the Line 6B crude oil release. As of September 30, 2015 and December 31, 2014, we had a remaining estimated liability of $157.9 million and $195.2 million, respectively.

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ENBRIDGE ENERGY PARTNERS, L.P.
 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

11. COMMITMENTS AND CONTINGENCIES  – (continued)

Fines and Penalties

At September 30, 2015, our remaining estimated costs related to the Line 6B crude oil release included $47.5 million in fines and penalties. Of this amount, $40.0 million relates to civil penalties under the Clean Water Act of the United States. While no final fine or penalty has been assessed or agreed to date, we believe that, based on the best information available at this time, the $40.0 million represents an estimate of the minimum amount which may be assessed, excluding costs of injunctive relief that may be agreed to with the relevant governmental agencies. Given the complexity of settlement negotiations, which we expect will continue, and the limited information available to assess the matter, we are unable to reasonably estimate the final penalty which might be incurred or to reasonably estimate a range of outcomes at this time. Injunctive relief is likely to include further measures directed toward enhancing spill prevention, leak detection, and emergency response to environmental events, and the cost of compliance with such measures, when combined with any fine or penalty, could be material. We have entered into a tolling agreement with the applicable governmental agencies and discussions with these governmental agencies regarding fines, penalties, and injunctive relief are ongoing.

In June 2015, Enbridge reached a separate agreement with the United States of America (Federal Natural Resources Damages Trustees), State of Michigan (State Natural Resources Damages Trustees), Match-E-Be-Nash-She-Wish Band of the Potawatomi Indians, and the Nottawaseppi Huron Band of the Potawatomi Indians to pay approximately $3.9 million that we had accrued to cover a variety of projects, including the restoration of 175 acres of oak savanna in Fort Custer State Recreation Area and wild rice beds along the Kalamazoo River.

Insurance

We are included in the comprehensive insurance program that is maintained by Enbridge for its subsidiaries and affiliates that renew throughout the year. On May 1 of each year, our insurance program is renewed and includes commercial liability insurance coverage that is consistent with coverage considered customary for our industry and includes coverage for environmental incidents such as those we have incurred for the crude oil releases from Lines 6A and 6B, excluding costs for fines and penalties.

A majority of the costs incurred for the crude oil release for Line 6B are covered by the insurance policy that expired on April 30, 2011, which had an aggregate limit of $650.0 million for pollution liability for Enbridge and its affiliates. Including our remediation spending through September 30, 2015, costs related to Line 6B exceeded the limits of the coverage available under this insurance policy. As of September 30, 2015, we have recorded total insurance recoveries of $547.0 million for the Line 6B crude oil release, out of the $650.0 million aggregate limit. We will record receivables for additional amounts we claim for recovery pursuant to our insurance policies during the period that we deem realization of the claim for recovery to be probable.

In March 2013, we and Enbridge filed a lawsuit against the insurers of $145.0 million of coverage, as one particular insurer is disputing our recovery eligibility for costs related to our claim on the Line 6B crude oil release and the other remaining insurers assert that their payment is predicated on the outcome of our recovery with that insurer. We received a partial recovery payment of $42.0 million from the other remaining insurers and amended our lawsuit such that it included only one insurer.

Of the remaining $103.0 million coverage limit, $85.0 million is the subject matter of a lawsuit Enbridge filed against one particular insurer described above. In March 2015, Enbridge reached agreement with that insurer to submit the $85.0 million claim to binding arbitration. The recovery of the remaining $18.0 million is awaiting resolution of that arbitration, which is not scheduled to occur until fourth quarter of 2016. While we believe that those costs are eligible for recovery, there can be no assurance that we will prevail in the arbitration.

We are pursuing recovery of the costs associated with the Line 6A crude oil release from third parties; however, there can be no assurance that any such recovery will be obtained. Additionally, fines and penalties would not be covered under our existing insurance policy.

Enbridge renewed its comprehensive property and liability insurance programs, under which we, together with Enbridge and its other affiliates are insured through April 30, 2016, with a liability program aggregate limit of

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ENBRIDGE ENERGY PARTNERS, L.P.
 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

11. COMMITMENTS AND CONTINGENCIES  – (continued)

$860.0 million, which includes sudden and accidental pollution liability. In the unlikely event that multiple insurable incidents which in aggregate exceed coverage limits occur within the same insurance period, the total insurance coverage will be allocated among the Enbridge entities on an equitable basis based on an insurance allocation agreement we have entered into with Enbridge, MEP, and other Enbridge subsidiaries.

Griffith Terminal Crude Oil Release

On February 25, 2014, a release of approximately 975 barrels of crude oil occurred within the Griffith Terminal in Griffith, Indiana. A repair plan has been reviewed with PHMSA and repair work has been completed. The released oil was fully contained within our facility and substantially all of the free product was recovered. The released oil did not affect the local community, wildlife or water supply. As of September 30, 2015, we had no remaining estimated liability.

Legal and Regulatory Proceedings

We are a participant in various legal and regulatory proceedings arising in the ordinary course of business. Some of these proceedings are covered, in whole or in part, by insurance. We are also directly, or indirectly, subject to challenges by special interest groups to regulatory approvals and permits for certain of our expansion projects.

A number of governmental agencies and regulators have initiated investigations into the Line 6B crude oil release. Approximately five actions or claims are pending against us and our affiliates in state and federal courts in connection with the Line 6B crude oil release. Based on the current status of these cases, we do not expect the outcome of these actions to be material to our results of operations or financial condition.

We have accrued a provision for future legal costs and probable losses associated with the Line 6A and Line 6B crude oil releases as described above in this footnote.

12. DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES

Our net income and cash flows are subject to volatility stemming from changes in interest rates on our variable rate debt obligations and fluctuations in commodity prices of natural gas, NGLs, condensate, crude oil and fractionation margins. Fractionation margins represent the relative difference between the price we receive from NGL and condensate sales and the corresponding commodity costs of natural gas and natural gas liquids we purchase for processing. Our interest rate risk exposure results from changes in interest rates on our variable rate debt and exists at the corporate level where our variable rate debt obligations are issued. Our exposure to commodity price risk exists within each of our segments. We use derivative financial instruments, such as futures, forwards, swaps, options and other financial instruments with similar characteristics, to manage the risks associated with market fluctuations in interest rates and commodity prices, as well as to reduce volatility in our cash flows. Based on our risk management policies, all of our derivative financial instruments, including those that do not qualify for hedge accounting treatment, are employed in connection with an underlying asset, liability or forecasted transaction and are not entered into with the objective of speculating on interest rates or commodity prices. We have hedged a portion of our exposure to the variability in future cash flows associated with the risks discussed above in future periods in accordance with our risk management policies. Our derivative instruments that are designated for hedge accounting under authoritative guidance are classified as cash flow hedges.

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ENBRIDGE ENERGY PARTNERS, L.P.
 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

12. DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES  – (continued)

Derivative Positions

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

		September 30, 2015				December 31, 2014
		(in millions)
Other current assets		$	137.8			$	185.5
Other assets, net			55.6				93.3
Accounts payable and other(1)			(377.6	)			(315.4	)
Other long-term liabilities			(189.8	)			(124.6	)
Due from general partner and affiliates			—				0.3
		$	(374.0	)		$	(160.9	)

The changes in the assets and liabilities associated with our derivatives are primarily attributable to the effects of new derivative transactions we have entered at prevailing market prices, settlement of maturing derivatives and the change in forward market prices of our remaining hedges. Our portfolio of derivative financial instruments is largely comprised of the following contracts: (1) natural gas, (2) NGL, (3) crude oil and (4) interest rates.

During the first quarter of 2014, we determined that a portion of forecasted short term debt transactions were not expected to occur, due to changing funding requirements. Since we will require less short-term debt than previously forecasted, we terminated several of our existing interest rate hedges used to lock-in interest rates on our short-term debt issuances as these hedges no longer met the cash flow hedging requirements. These terminations resulted in realized losses of $0.8 million for the nine months ended September 30, 2014. We had no similar terminations of our cash flow hedges for the nine months ended September 30, 2015.

Our earnings and cash flows are exposed to the variability in longer term interest rates ahead of the anticipated fixed rate debt issuances. Forward starting interest rate swaps are used as cash flow hedges against the effect of future interest rate movements on earnings and cash flow. In order to mitigate the negative effect that increasing interest rates have on our cash flows, in the three months ended September 30, 2014, we purchased 10-year interest rate swaps with a total notional value of $2.35 billion.

In September 2014, we amended the maturity date on certain interest rate hedges of future debt issuances that were originally set to mature in 2014 and 2016 to better reflect the expected timing of future debt issuances. The ineffective portion of the hedges’ fair value in relation to the hedged future debt issuances is recognized in income at the amendment date and each quarter end. For the three and nine months ended September 30, 2015, we recognized in interest expense unrealized losses for hedge ineffectiveness of approximately $7.9 million and unrealized gains for hedge ineffectiveness of approximately $22.0 million, respectively, associated with interest rate hedges that were originally set to mature in 2014 and 2016. For the three and nine months ended September 30, 2014, we recognized in interest expense unrealized losses for hedge ineffectiveness of approximately $62.2 million, also associated with interest rate hedges that were originally set to mature in 2014 and 2016.

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ENBRIDGE ENERGY PARTNERS, L.P.
 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

12. DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES  – (continued)

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

		September 30, 2015				December 31, 2014
		(in millions)
Counterparty Credit Quality(1)
AAA		$	0.2			$	0.1
AA(2)			(106.2	)			(49.8	)
A			(128.3	)			(129.1	)
Lower than A			(139.7	)			17.9
		$	(374.0	)		$	(160.9	)

As the net value of our derivative financial instruments has decreased in response to changes in forward commodity prices and interest rates, our outstanding financial exposure to third parties has also decreased. When credit thresholds are met pursuant to the terms of our International Swaps and Derivatives Association, Inc., or ISDA®, financial contracts, we have the right to require collateral from our counterparties. We include any cash collateral received or posted in the balances listed above. At September 30, 2015 and December 31, 2014, we held $16.2 million and $28.4 million of cash collateral on our asset exposures, respectively. Cash collateral is classified as “Restricted cash” in our consolidated statements of financial position. When we are in a position of posting collateral to cover our counterparties’ exposure to our non-performance, the collateral is provided through letters of credit, which are not reflected above.

We have provided letters of credit totaling $417.7 million and $329.6 million relating to our liability exposures pursuant to the margin thresholds in effect at September 30, 2015 and December 31, 2014, respectively, under our ISDA® agreements. The ISDA® agreements and associated credit support, which govern our financial derivative transactions, contain no credit rating downgrade triggers that would accelerate the maturity dates of our 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 we are in a liability position to our counterparty, but the agreement will not automatically terminate and require immediate settlement of all future amounts due.

The ISDA® agreements, in combination with our master netting agreements, and credit arrangements governing our interest rate and commodity swaps require that collateral be posted per tiered contractual thresholds based on the credit rating of each counterparty. We generally provide 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. 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 we are holding an asset position, our counterparties are likewise required to post collateral on their liability (our asset) exposures, also determined by tiered contractual collateral thresholds. Counterparty collateral may consist of cash or letters of credit, both of which must be fulfilled with immediately available funds.

In the event that our credit ratings were to decline below the lowest level of investment grade, as determined by Standard & Poor’s and Moody’s, we would be required to provide additional amounts under our existing letters of credit to meet the requirements of our ISDA® agreements. For example, if our credit ratings had been at the lowest level of investment grade at September 30, 2015, we would have been required to provide additional letters of credit in the amount of $83.5 million.

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ENBRIDGE ENERGY PARTNERS, L.P.
 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

12. DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES  – (continued)

At September 30, 2015 and December 31, 2014, we had credit concentrations in the following industry sectors, as presented below:

		September 30, 2015				December 31, 2014
		(in millions)
United States financial institutions and investment banking entities(1)		$	(251.1	)		$	(147.1	)
Non-United States financial institutions			(149.9	)			(54.2	)
Other			27.0				40.4
		$	(374.0	)		$	(160.9	)

Gross derivative balances are presented below before the effects of collateral received or posted and without the effects of master netting arrangements. Both our assets and liabilities are adjusted for non-performance risk, which is statistically derived. This credit valuation adjustment model considers existing derivative asset and liability balances in conjunction with contractual netting and collateral arrangements, current market data such as credit default swap rates and bond spreads and probability of default assumptions to quantify an adjustment to fair value. For credit modeling purposes, collateral received is included in the calculation of our assets, while any collateral posted is excluded from the calculation of the credit adjustment. Our credit exposure for these over-the-counter, or OTC, derivatives is directly with our counterparty and continues until the maturity or termination of the contracts.

Effect of Derivative Instruments on the Consolidated Statements of Financial Position

						Asset Derivatives								Liability Derivatives
						Fair Value at								Fair Value at
		Financial Position Location				September 30, 2015				December 31, 2014				September 30, 2015				December 31, 2014
						(in millions)
Derivatives designated as hedging instruments:(1)
Interest rate contracts			Accounts payable and other			$	—			$	—			$	(319.4	)		$	(241.0	)
Interest rate contracts			Other long-term liabilities				—				—				(168.0	)			(102.0	)
Commodity contracts			Other current assets				7.4				26.1				—				—
Commodity contracts			Other assets				—				2.1				—				—
							7.4				28.2				(487.4	)			(343.0	)
Derivatives not designated as hedging instruments:
Commodity contracts			Other current assets				130.4				159.4				—				—
Commodity contracts			Other assets				55.6				91.2				—				—
Commodity contracts			Accounts payable and other	(2)			—				—				(42.0	)			(46.0	)
Commodity contracts			Other long-term liabilities				—				—				(21.8	)			(22.6	)
Commodity contracts			Due from general partner and affiliates				—				0.3				—				—
							186.0				250.9				(63.8	)			(68.6	)
Total derivative instruments						$	193.4			$	279.1			$	(551.2	)		$	(411.6	)

TABLE OF CONTENTS

ENBRIDGE ENERGY PARTNERS, L.P.
 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

12. DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES  – (continued)

Accumulated Other Comprehensive Income

We record the change in fair value of our highly effective cash flow hedges in AOCI until the derivative financial instruments are settled, at which time they are reclassified to earnings. Also included in AOCI, as of September 30, 2015 and December 31, 2014, are unrecognized losses of approximately $23.9 million and $28.4 million, respectively, associated with derivative financial instruments that qualified for and were classified as cash flow hedges of forecasted transactions that were subsequently de-designated, settled, or terminated. These losses are reclassified to earnings over the periods during which the originally hedged forecasted transactions affect earnings.

During the nine months ended September 30, 2015 and 2014, unrealized commodity hedge gains of $1.5 million and losses of $0.2 million, respectively, were de-designated as a result of the hedges no longer meeting hedge accounting criteria. We estimate that approximately $316.5 million, representing unrealized net losses from our cash flow hedging activities based on pricing and positions at September 30, 2015, will be reclassified from AOCI to earnings during the next 12 months.

Effect of Derivative Instruments on the Consolidated Statements of Income and Accumulated Other Comprehensive Income

Derivatives in Cash Flow       Hedging Relationships		Amount of Gain (Loss) Recognized in AOCI on Derivative (Effective Portion)				Location of Gain (Loss) Reclassified from AOCI to Earnings (Effective Portion)				Amount of Gain (Loss) Reclassified from AOCI to Earnings (Effective Portion)				Location of Gain (Loss) Recognized in Earnings on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)(1)				Amount of Gain (Loss) Recognized in Earnings on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)(1)
						(in millions)
For the three months ended September 30, 2015
Interest rate contracts		$	(127.0	)			Interest expense			$	(3.7	)			Interest expense			$	(7.8	)
Commodity contracts			(5.5	)			Commodity Costs				8.6				Commodity Costs				(0.1	)
Total		$	(132.5	)						$	4.9							$	(7.9	)
For the three months ended September 30, 2014
Interest rate contracts		$	44.1				Interest expense			$	(4.0	)			Interest expense			$	(62.2	)
Commodity contracts			11.2				Commodity Costs				(2.1	)			Commodity Costs				0.9
Total		$	55.3							$	(6.1	)						$	(61.3	)
For the nine months ended September 30, 2015
Interest rate contracts		$	(169.0	)			Interest expense			$	(12.0	)			Interest expense			$	24.6
Commodity contracts			(16.8	)			Commodity Costs				24.1				Commodity Costs				(4.1	)
Total		$	(185.8	)						$	12.1							$	20.5
For the nine months ended September 30, 2014
Interest rate contracts		$	(93.0	)			Interest expense			$	(12.1	)			Interest expense			$	(73.2	)
Commodity contracts			7.9				Commodity Costs				(12.4	)			Commodity Costs				1.5
Total		$	(85.1	)						$	(24.5	)						$	(71.7	)

TABLE OF CONTENTS

ENBRIDGE ENERGY PARTNERS, L.P.
 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

12. DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES  – (continued)

Components of Accumulated Other Comprehensive Income/(Loss)

		Cash Flow Hedges
		2015				2014
		(in millions)
Balance at January 1		$	(211.4	)		$	(76.6	)
Other comprehensive loss before reclassifications(1)			(170.9	)			(104.6	)
Amounts reclassified from AOCI(2)(3)			(6.4	)			22.2
Net other comprehensive loss		$	(177.3	)		$	(82.4	)
Balance at September 30		$	(388.7	)		$	(159.0	)

Reclassifications from Accumulated Other Comprehensive Income

		For the three months ended September 30,								For the nine months ended September 30,
		2015				2014				2015				2014
		(in millions)
Losses (gains) on cash flow hedges:
Interest Rate Contracts(1)(2)		$	3.6			$	4.0			$	11.9			$	12.1
Commodity Contracts(3)(4)(5)			(6.5	)			1.6				(18.3	)			10.1
Total Reclassifications from AOCI		$	(2.9	)		$	5.6			$	(6.4	)		$	22.2

Effect of Derivative Instruments on Consolidated Statements of Income

						For the three months ended September 30,								For the nine months ended September 30,
						2015				2014				2015				2014
Derivatives Not Designated         as Hedging Instruments		Location of Gain or (Loss) Recognized in Earnings				Amount of Gain or (Loss) Recognized in Earnings(1)(2)								Amount of Gain or (Loss) Recognized in Earnings(1)(2)
						(in millions)
Commodity contracts			Transportation and other services(3)			$	8.1			$	7.0			$	8.1			$	(0.6	)
Commodity contracts			Commodity sales				(7.2	)			7.6				(22.4	)			10.7
Commodity contracts			Commodity sales – affiliate				—				—				(0.3	)			0.5
Commodity contracts			Commodity costs(4)				40.8				9.5				44.3				(9.9	)
Commodity contracts			Power				—				—				—				0.5
Total						$	41.7			$	24.1			$	29.7			$	1.2

TABLE OF CONTENTS

ENBRIDGE ENERGY PARTNERS, L.P.
 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

12. DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES  – (continued)

We record the fair market value of our derivative financial and physical instruments in the consolidated statements of financial position as current and long-term assets or liabilities on a gross basis. However, the terms of the ISDA®, which govern our financial contracts and our other master netting agreements, allow the parties to elect in respect of all transactions under the agreement, in the event of a default and upon notice to the defaulting party, for the non-defaulting party to set-off all settlement payments, collateral held and any other obligations (whether or not then due), which the non-defaulting party owes to the defaulting party. The effect of the rights of set-off are outlined below.

Offsetting of Financial Assets and Derivative Assets

		As of September 30, 2015
		Gross Amount of Recognized Assets				Gross Amount Offset in the Statement of Financial Position				Net Amount of Assets Presented in the Statement of Financial Position				Gross Amount Not Offset in the Statement of Financial Position(1)				Net Amount
		(in millions)
Description:
Derivatives		$	193.4			$	—			$	193.4			$	(59.9	)		$	133.5

		As of December 31, 2014
		Gross Amount of Recognized Assets				Gross Amount Offset in the Statement of Financial Position				Net Amount of Assets Presented in the Statement of Financial Position				Gross Amount Not Offset in the Statement of Financial Position(1)				Net Amount
		(in millions)
Description:
Derivatives		$	279.1			$	—			$	279.1			$	(91.8	)		$	187.3

Offsetting of Financial Liabilities and Derivative Liabilities

		As of September 30, 2015
		Gross Amount of Recognized Liabilities(1)				Gross Amount Offset in the Statement of Financial Position				Net Amount of Liabilities Presented in the Statement of Financial Position				Gross Amount Not Offset in the Statement of Financial Position(1)				Net Amount
		(in millions)
Description:
Derivatives		$	(567.4	)		$	—			$	(567.4	)		$	59.9			$	(507.5	)

		As of December 31, 2014
		Gross Amount of Recognized Liabilities(1)				Gross Amount Offset in the Statement of Financial Position				Net Amount of Liabilities Presented in the Statement of Financial Position				Gross Amount Not Offset in the Statement of Financial Position(1)				Net Amount
		(in millions)
Description:
Derivatives		$	(440.0	)		$	—			$	(440.0	)		$	91.8			$	(348.2	)

TABLE OF CONTENTS

ENBRIDGE ENERGY PARTNERS, L.P.
 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

12. DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES  – (continued)

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 September 30, 2015 and December 31, 2014. 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.

		September 30, 2015																December 31, 2014
		Level 1				Level 2				Level 3				Total				Level 1				Level 2				Level 3				Total
		(in millions)
Interest rate contracts		$	—			$	(487.4	)		$	—			$	(487.4	)		$	—			$	(343.0	)		$	—			$	(343.0	)
Commodity contracts:
Financial			—				17.6				14.3				31.9				—				41.6				42.7				84.3
Physical			—				—				4.6				4.6				—				—				19.5				19.5
Commodity options			—				—				93.1				93.1				—				—				106.7				106.7
			—				(469.8	)			112.0				(357.8	)			—				(301.4	)			168.9				(132.5	)
Cash collateral															(16.2	)															(28.4	)
Total														$	(374.0	)														$	(160.9	)

Qualitative Information about Level 2 Fair Value Measurements

We categorize, as Level 2, the fair value of assets and liabilities that we measure with either directly or indirectly observable inputs as of the measurement date, where pricing inputs are other than quoted prices in active markets for the identical instrument. This category includes both OTC transactions valued using exchange traded pricing information in addition to assets and liabilities that we value using either models or other valuation methodologies derived from observable market data. These models are primarily industry-standard models that consider various inputs including: (1) quoted prices for assets and liabilities; (2) time value; and (3) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the assets and liabilities, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace.

Qualitative Information about Level 3 Fair Value Measurements

Data from pricing services and published indices are used to value our Level 3 derivative instruments, which are fair-valued on a recurring basis. We may also use these inputs with internally developed methodologies that result in our best estimate of fair value. The inputs listed in the table below would have a direct impact on the fair values of the listed instruments. The significant unobservable inputs used in the fair value measurement of the commodity derivatives (natural gas, NGLs, crude oil and power) are forward commodity prices. The significant unobservable inputs used in determining the fair value measurement of options are price and volatility. Increases/(decreases) in the forward commodity price in isolation would result in higher/(lower) fair values for long positions, with offsetting impacts to short positions. Increases/(decreases) in volatility would increase/(decrease) the value for the holder of the option. Generally, a change in the estimate of forward commodity prices is unrelated to a change in the estimate of volatility of prices. A change to the credit valuation adjustment would change the fair value of the positions in opposite directions.

TABLE OF CONTENTS

ENBRIDGE ENERGY PARTNERS, L.P.
 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

12. DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES  – (continued)

Quantitative Information About Level 3 Fair Value Measurements

		Fair Value at September 30, 2015(2)				Valuation Technique				Unobservable Input				Range(1)
Contract Type														Lowest				Highest				Weighted Average				Units
		(in millions)
Commodity Contracts – Financial
Natural Gas		$	0.3				Market Approach				Forward Gas Price				2.41				3.16				2.84				MMBtu
NGLs		$	14.0				Market Approach				Forward NGL Price				0.20				0.99				0.51				Gal
Commodity Contracts – Physical
Natural Gas		$	(3.9	)			Market Approach				Forward Gas Price				2.33				3.53				2.61				MMBtu
Crude Oil		$	(0.4	)			Market Approach				Forward Crude Price				31.17				47.93				44.35				Bbl
NGLs		$	8.9				Market Approach				Forward NGL Price				0.20				1.39				0.43				Gal
Commodity Options
Natural Gas, Crude and NGLs		$	93.1				Option Model				Option Volatility				10	%			62	%			35	%
Total Fair Value		$	112.0