10-Q

 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 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, 2016
 
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 1-31383

 

ENBRIDGE ENERGY MANAGEMENT, L.L.C.

(Exact Name of Registrant as Specified in Its Charter)

 

Delaware	61-1414604
(State or Other Jurisdiction of Incorporation or Organization)	(I.R.S. Employer Identification No.)

1100 Louisiana, 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 79,995,975 Listed Shares outstanding as of October 28, 2016.

DOCUMENTS INCORPORATED BY REFERENCE:

Quarterly Report on Form 10-Q of Enbridge Energy Partners, L.P. for the quarterly period ended
September 30, 2016.

 

ENBRIDGE ENERGY MANAGEMENT, L.L.C.
 
TABLE OF CONTENTS

PART I — FINANCIAL INFORMATION
Item 1. Financial Statements
Statements of Income for the three and nine months ended September 30, 2016 and 2015		1
Statements of Comprehensive Income for the three and nine months ended September 30, 2016 and 2015		2
Statements of Cash Flows for the nine months ended September 30, 2016 and 2015		3
Statements of Financial Position as of September 30, 2016 and December 31, 2015		4
Notes to the Financial Statements		5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		10
Item 3. Quantitative and Qualitative Disclosures About Market Risk		11
Item 4. Controls and Procedures		12
PART II — OTHER INFORMATION
Item 1. Legal Proceedings		13
Item 1A. Risk Factors		13
Item 6. Exhibits		13
Signatures		14
Exhibits		15

In this report, unless the context requires otherwise, references to “we,” “us,” “our,” the “Company” or “Enbridge Management” are intended to mean Enbridge Energy Management, L.L.C. We are a limited partner of Enbridge Energy Partners, L.P., which we refer to as the “Partnership.” References to “Enbridge” refer collectively to Enbridge Inc. and its subsidiaries other than us.

This Quarterly Report on Form 10-Q includes forward-looking statements, which are statements that frequently use words such as “anticipate,” “believe,” “consider,” “continue,” “could,” “estimate,” “evaluate,” “expect,” “explore,” “forecast,” “intend,” “may,” “opportunity,” “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. Our results of operations, financial position and cash flows are dependent on the results of operations, financial position and cash flows of the Partnership. Many of the factors that will determine these results are beyond the Partnership’s or 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, including the rate of development of the Alberta Oil Sands; (2) the Partnership’s 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 the Partnership’s facilities or refineries, petrochemical plants, utilities or other businesses for which the Partnership transports products or to which it sells 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 the Partnership’s tariff rates; (7) changes in laws or regulations to which we or the Partnership 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 Partnership’s construction of new assets.

For additional factors that may affect results, see “Item 1A. Risk Factors” of our Annual Report on Form 10-K for the year ended December 31, 2015, which is available to the public over the Internet at the U.S. Securities and Exchange Commission’s, or the SEC’s, website (www.sec.gov) and at our website (www.enbridgemanagement.com). Also see information regarding forward-looking statements and “Item 1A. Risk Factors” included in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2015 for a discussion of risks to the Partnership that also may affect us.

i

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

ENBRIDGE ENERGY MANAGEMENT, L.L.C.
 
STATEMENTS OF INCOME

	For the three months ended September 30,						For the nine months ended September 30,
	2016			2015			2016			2015
	(unaudited; in millions, except per share amounts)
Equity loss from investment in Enbridge Energy Partners, L.P. (Note 1)	$	(1.9	)	$	(117.3	)	$	(120.0	)	$	(192.3	)
Loss before income tax benefit (expense)		(1.9	)		(117.3	)		(120.0	)		(192.3	)
Income tax benefit (expense) (Note 3)		0.6			(160.5	)		1.2			(132.8	)
Net loss	$	(1.3	)	$	(277.8	)	$	(118.8	)	$	(325.1	)
Net loss per share, (basic and diluted)	$	(0.02	)	$	(3.91	)	$	(1.54	)	$	(4.65	)
Weighted average shares outstanding		79.1			71.7			76.9			69.9

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

1

ENBRIDGE ENERGY MANAGEMENT, L.L.C.
 
STATEMENTS OF COMPREHENSIVE INCOME

	For the three months ended September 30,						For the nine months ended September 30,
	2016			2015			2016			2015
	(unaudited; in millions)
Net loss	$	(1.3	)	$	(277.8	)	$	(118.8	)	$	(325.1	)
Equity in other comprehensive income (loss) of Enbridge Energy Partners, L.P., net of tax expense (benefit) of $0.6 million, $(10.0) million, $1.2 million and $(14.4) million, respectively		1.3			(16.5	)		(13.7	)		(24.1	)
Comprehensive loss	$	—		$	(294.3	)	$	(132.5	)	$	(349.2	)

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

2

ENBRIDGE ENERGY MANAGEMENT, L.L.C.
 
STATEMENTS OF CASH FLOWS

	For the nine months ended September 30,
	2016			2015
	(unaudited; in millions)
Cash provided by operating activities:
Net loss	$	(118.8	)	$	(325.1	)
Adjustments to reconcile net loss to net cash in operating activities:
Equity loss from investment in Enbridge Energy Partners, L.P.		120.0			192.3
Changes in operating assets and liabilities:
Due from affiliates		—			0.2
Due to affiliates		—			(0.1	)
Deferred income taxes		(1.2	)		132.8
Net cash provided by operating activities		—			0.1
Cash used in investing activities:
Net cash used in investing activities		—			—
Cash provided by financing activities:
Net cash provided by financing activities		—			—
Net increase in cash and cash equivalents		—			0.1
Cash and cash equivalents at beginning of year		0.8			0.7
Cash and cash equivalents at end of period	$	0.8		$	0.8

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

3

ENBRIDGE ENERGY MANAGEMENT, L.L.C.
 
STATEMENTS OF FINANCIAL POSITION

	September 30, 2016			December 31, 2015
	(unaudited; in millions)
ASSETS
Cash	$	0.8		$	0.8
Investment in Enbridge Energy Partners, L.P. (Note 2)		—			132.5
	$	0.8		$	133.3
LIABILITIES AND SHAREHOLDERS’ EQUITY
Commitments and contingencies
Shareholders’ equity (Note 2)
Voting shares – unlimited authorized; 6.03 and 5.53 issued and outstanding at September 30, 2016 and December 31, 2015, respectively	$	—		$	—
Listed shares – unlimited authorized; 79,995,975 and 73,285,734 issued and outstanding at September 30, 2016 and December 31, 2015, respectively		1,576.3			1,443.8
Accumulated deficit		(1,517.7	)		(1,266.4	)
Accumulated other comprehensive loss		(57.8	)		(44.1	)
	$	0.8		$	133.3

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

4

ENBRIDGE ENERGY MANAGEMENT, L.L.C.
 
NOTES TO THE FINANCIAL STATEMENTS (unaudited)

1. BASIS OF PRESENTATION

We are a limited partner of Enbridge Energy Partners, L.P., which we refer to as the Partnership, through our ownership of i-units, a special class of the Partnership’s limited partner interests. Under a delegation of control agreement among us, the Partnership and its general partner, Enbridge Energy Company, Inc., referred to as the General Partner, we manage the Partnership’s business and affairs. The General Partner is an indirect, wholly-owned subsidiary of Enbridge Inc., an energy company based in Calgary, Alberta, Canada that we refer to herein as Enbridge.

We have prepared the accompanying unaudited interim financial statements in accordance with generally accepted accounting principles in the United States of America, or GAAP, for interim financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. Accordingly, they do not include all the information and footnotes required by GAAP for complete financial statements. In the opinion of management, they contain all adjustments, consisting only of normal recurring adjustments, which management considers necessary to present fairly our financial position at September 30, 2016, our results of operations for the three and nine months ended September 30, 2016 and 2015 and our cash flows for the nine months ended September 30, 2016 and 2015. We derived our statements of financial position as of December 31, 2015 from the audited financial statements included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2015. Our results of operations for the three and nine months ended September 30, 2016 and 2015 should not be taken as indicative of the results to be expected for the full year.

The unaudited interim financial statements should be read in conjunction with our financial statements and notes thereto presented in our Annual Report on Form 10-K for the fiscal year ended December 31, 2015. Our results of operations, financial position and cash flows are dependent on the results of operations, financial position and cash flows of the Partnership. As a result, these unaudited interim financial statements should also be read in conjunction with the Partnership’s audited consolidated financial statements and notes thereto presented in its Annual Report on Form 10-K for the fiscal year ended December 31, 2015, as well as the Partnership’s unaudited interim consolidated financial statements presented in its Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2016.

Variable Interest Entities

On January 1, 2016, we adopted Accounting Standards Update No. 2015-02, which amended consolidation guidance to, among other things, eliminate the specialized consolidation model and guidance for limited partnerships, including the presumption that the general partner should consolidate a limited partnership. As a result, we have determined that the Partnership, which historically has not been consolidated by us under this presumption as we are not the general partner, is a variable interest entity, or VIE. Further, we determined that we are not the primary beneficiary of the Partnership. While the amended guidance did not impact our conclusion that the Partnership should not be consolidated, because the Partnership is now considered a VIE, additional disclosures are necessary. We have applied this amended guidance retrospectively to our disclosures.

Upon inception of a contractual agreement, we perform an assessment to determine whether the arrangement contains a variable interest in a legal entity and whether that legal entity is a VIE. We assess all aspects of our interests in an entity and use judgment when determining if we are the primary beneficiary. The primary beneficiary has both the power to direct the activities of the VIE that most significantly impact the entity’s economic performance and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. Other qualitative factors that are considered include decision-making responsibilities, the VIE capital structure, risk and rewards sharing, contractual agreements with the VIE, voting rights and level of involvement of other parties. A reassessment of the primary beneficiary conclusion is conducted when there are changes in the facts and circumstances related to a VIE.

5

ENBRIDGE ENERGY MANAGEMENT, L.L.C.
 
NOTES TO THE FINANCIAL STATEMENTS (unaudited)

1. BASIS OF PRESENTATION  – (continued)

As discussed above, we are a limited partner of the Partnership, through our ownership of i-units, a special class of the Partnership’s limited partner interests. At September 30, 2016, we owned approximately 16.3% of the Partnership through our ownership of the i-units. Further, under a delegation of control agreement among us, the Partnership and the General Partner, we manage the Partnership’s business and affairs. However, the General Partner has the ultimate responsibility to direct the activities that most significantly impact the Partnership’s economic performance. Further, the General Partner has the power to direct the activities that most significantly impact our economic performance through its 100% ownership interest in our voting shares. As a result, we have determined that we are not the primary beneficiary of the Partnership.

Partnership Incentive and Other Distributions

The General Partner receives distributions from the Partnership through a wholly-owned subsidiary’s ownership of Incentive Distribution Units, or IDUs, on the portion of cash distributions that exceed certain target thresholds on a per unit basis under the Seventh Amended and Restated Agreement of the Limited Partnership of the Partnership dated as of January 2, 2015, as amended, or the Partnership Agreement. The IDUs entitle the holder thereof to receive 23% of the incremental cash distributions paid by the Partnership in excess of $0.5435 per unit per quarter on its Class A and Class B common units, collectively, the common units, the i-units we own, the Class D Units, and the Class E Units.

In addition, the General Partner receives distributions from the Partnership through its ownership of Preferred Units, Class D units, and Class E units. The Preferred Units are entitled to annual distributions of 7.50% of the issue price, payable quarterly. Class D and Class E units entitle the holders thereof to receive quarterly distributions equal to the amount derived by multiplying the number of Class D and Class E units outstanding by the distribution rate on the Partnership’s common units and i-units.

Distributions to holders of the IDUs, Preferred Units, Class D units, and Class E units reduce the amount of income that is allocated to the Partnership’s remaining limited partners: (1) Class A common units, (2) Class B common units, and (3) i-units on a pro-rata basis based on our ownership interest in the Partnership. Thus, our “Equity income (loss) from the investment in Enbridge Energy Partners, L.P.” on our statements of income reflects our pro-rata share of these allocations every quarter.

The Partnership Agreement does not permit capital deficits to accumulate in the capital account of any limited partner and thus requires that such capital account deficits brought to zero, or “cured,” by additional allocations from the positive capital accounts of the common units, i-units, and General Partner, generally on a pro-rata basis. Our equity income from the Partnership is adjusted for our pro-rata share of such reallocations. Until we discontinued equity accounting for our investment in the Partnership on March 31, 2016, our equity earnings were reduced by $121.3 million, for our pro-rata share of the allocation needed to cure the capital account deficits of the Class A and Class B common units.

During the first quarter of 2016, our share of losses in the Partnership, driven primarily from curing losses, exceeded the carrying amount of our investment in the Partnership. As a result, we ceased recognition of our equity interest in the earnings of the Partnership when the carrying amount of our investment was reduced to zero and will no longer provide for additional losses as we are not obligated to provide further financial support to the Partnership. Further, our accumulated other comprehensive income is comprised of our historical interest in the Partnership’s other comprehensive income, which is based primarily on the effective mark-to-market changes in the Partnership’s underlying cash flow hedge contracts. We will amortize into earnings the remaining accumulated other comprehensive loss on a straight-line basis over the remaining term of the Partnership’s underlying hedge contracts.

6

ENBRIDGE ENERGY MANAGEMENT, L.L.C.
 
NOTES TO THE FINANCIAL STATEMENTS (unaudited)

2. SHAREHOLDERS’ EQUITY

The following table presents significant changes in Shareholders’ equity during the nine months ended September 30, 2016 and 2015.

	For the nine months ended September 30,
	2016			2015
	(in millions)
Listed Shares:
Beginning balance	$	1,443.8		$	1,358.0
Capital account adjustments		—			(75.6	)
Share distributions		132.5			119.5
Ending balance	$	1,576.3		$	1,401.9
Accumulated deficit:
Beginning balance	$	(1,266.4	)	$	(592.7	)
Net loss		(118.8	)		(325.1	)
Share distributions		(132.5	)		(119.5	)
Ending balance	$	(1,517.7	)	$	(1,037.3	)
Accumulated other comprehensive loss:
Beginning balance	$	(44.1	)	$	(23.7	)
Equity in other comprehensive income of the Partnership		(13.7	)		(24.1	)
Ending balance	$	(57.8	)	$	(47.8	)
Total Shareholders’ equity	$	0.8		$	316.8

Share Distributions

The following table sets forth the details regarding our share distributions, as approved by our board of directors, for the nine months ended September 30, 2016:

Distribution Declaration Date	Record Date		Distribution Payment Date		Distribution per Unit of the Partnership		Average Closing Price of the Listed Shares		Additional i-units Owned		Listed Shares Distributed to Public		Shares Distributed to General Partner
					(in millions, except per unit and per share amounts)
July 28, 2016		August 5, 2016		August 12, 2016	$	0.5830	$	22.84		1,991,304		1,758,587		232,717
April 29, 2016		May 6, 2016		May 13, 2016	$	0.5830	$	21.14		2,093,257		1,848,626		244,631
January 29, 2016		February 5, 2016		February 12, 2016	$	0.5830	$	16.27		2,625,681		2,318,827		306,854

We had non-cash operating activities in the form of i-units distributed to us by the Partnership and corresponding non-cash financing activities in the form of share distributions to our shareholders in the amounts of $132.5 million and $119.5 million during the nine months ended September 30, 2016 and 2015, respectively.

3. INCOME TAXES

The terms of the i-units provide that the units owned by us will not be allocated income, gain, loss or deductions of the Partnership for tax purposes until such time that we dispose of our investment in the Partnership. As a result, actual realization of any long-term deferred income tax asset or liability would only occur upon liquidation of our investment in the Partnership.

Based on the estimates of our future operating income included in our forecasts, including curing impacts, we have concluded that it is not more likely than not that our deferred tax assets will be realized. As a result, we continue to maintain a full valuation allowance on those tax assets as of September 30, 2016.

7

ENBRIDGE ENERGY MANAGEMENT, L.L.C.
 
NOTES TO THE FINANCIAL STATEMENTS (unaudited)

3. INCOME TAXES  – (continued)

The effective income tax rates for the three and nine months ended September 30, 2016 and 2015 are presented in the following table.

	For the three months ended September 30,						For the nine months ended September 30,
	2016			2015			2016			2015
	(unaudited; in millions except for tax rate amounts)
Loss before income tax benefit	$	(1.9	)	$	(117.3	)	$	(120.0	)	$	(192.3	)
Income tax benefit (expense)		0.6			44.2			44.3			71.9
Tax Rate change		(3.7	)		0.3			(3.7	)		0.3
Valuation allowance		3.7			(205.0	)		(39.4	)		(205.0	)
Total income tax benefit (expense)(1)	$	0.6		$	(160.5	)	$	1.2		$	(132.8	)
Effective income tax rate		31.6	%		(136.8	)%		1.0	%		(69.1	)%

⁽¹⁾ Amortization of accumulated other comprehensive income into earnings is recorded before tax to recognize the related tax benefit. Recognition of the tax benefit in earnings does not impact the balance of the deferred tax asset and associated full valuation allowance, which were previously recorded when the losses were reflected in Other Comprehensive Income.

4. SUMMARIZED FINANCIAL INFORMATION FOR ENBRIDGE ENERGY PARTNERS, L.P.

	For the three months ended September 30,					For the nine months ended September 30,
	2016			2015		2016			2015
	(in millions)
Operating revenue	$	1,120.6		$	1,267.7	$	3,231.1		$	4,009.4
Operating expenses		1,599.5			1,012.9		3,180.3			3,524.6
Operating income (loss)	$	(478.9	)	$	254.8	$	50.8		$	484.8
Net income (loss)	$	(574.6	)	$	184.5	$	(224.5	)	$	341.8
Less: Net income (loss) attributable to:
Noncontrolling interest		(191.9	)		77.8		(52.8	)		139.1
Series 1 preferred unit distributions		22.5			22.5		67.5			67.5
Accretion of discount on Series 1 Preferred Units		1.2			2.1		3.5			10.1
Net income (loss) attributable to Enbridge Energy Partners, L.P.	$	(406.4	)	$	82.1	$	(242.7	)	$	125.1
Less: Net income attributable to the General Partner(1)		46.2			56.0		158.1			162.5
Net income (loss) attributable to common units and i-units(2)	$	(452.6	)	$	26.1	$	(400.8	)	$	(37.4	)

⁽¹⁾ Net income attributable to the General Partner includes net income attributable to the general partner interest as well as to Class D units, Class E units, and IDUs.

⁽²⁾ The Partnership allocates its net income among the holders of Preferred Units, the General Partner and limited partners first using preferred unit distributions and then the two-class method in accordance with applicable authoritative accounting guidance. Under the two-class method, the Partnership allocates its net income, after noncontrolling interest and preferred unit distributions, to the General Partner and its limited partners, including us, according to the distribution formula for available cash as set forth in the Partnership Agreement.

We owned approximately 16.3% and 14.8% of the Partnership at September 30, 2016 and 2015, respectively.

8

ENBRIDGE ENERGY MANAGEMENT, L.L.C.
 
NOTES TO THE FINANCIAL STATEMENTS (unaudited)

5. SUBSEQUENT EVENTS

Share Distribution

On October 28, 2016, our board of directors declared a share distribution payable on November 14, 2016, to shareholders of record as of November 7, 2016, based on the $0.5830 per limited partner unit distribution declared by the Partnership. The Partnership’s distribution increases the number of i-units that we own. The amount of this increase is calculated by dividing the cash amount distributed by the Partnership per common unit by the average closing price of one of our Listed Shares on the New York Stock Exchange for the 10 trading day period immediately preceding the ex-dividend date for our shares, multiplied by the number of shares outstanding on the record date. We distribute additional Listed Shares to our shareholders and additional voting shares to the General Partner in respect of these additional i-units.

9

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

RESULTS OF OPERATIONS

The information set forth under Part I, Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations of the Partnership’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2016 is hereby incorporated by reference, as our results of operations, financial position and cash flows are dependent on the results of operations, financial position and cash flows of the Partnership.

Our results of operations consist of our share of earnings from Enbridge Energy Partners, L.P., or the Partnership, attributed to our ownership of the i-units, a special class of limited partner interest in the Partnership. At September 30, 2016 and 2015, through our ownership of i-units, we had an approximate 16.3% and 14.8%, respectively, limited partner voting interest in the Partnership. Our percentage ownership of the Partnership will change over time as the number of i-units we own becomes a different percentage of the total limited partner interests outstanding due to our ownership of additional i-units and other issuances of limited partner interests by the Partnership. Historically, our share of the Partnership’s earnings was reduced by (1) allocations of income to the Preferred Units, Class D and Class E units, and IDUs, and (2) curing impacts on limited partnership interests whose capital account balances become negative during a quarter.

During the first quarter of 2016, our share of losses in the Partnership, driven primarily from curing losses, exceeded the carrying amount of our investment in the Partnership. As a result, we discontinued application of the equity method of accounting when the carrying amount of our investment was reduced to zero and will no longer provide for additional losses as we are not obligated to provide further financial support to the Partnership. Further, we will amortize into earnings the remaining accumulated other comprehensive loss on a straight-line basis over the remaining term of the Partnership’s underlying hedge contracts. As a result, our net loss of $1.3 million for the three months ended September 30, 2016, and future losses will consist only of amortization of remaining accumulated other comprehensive income.

The following table presents our results of operations for each of the three and nine months ended September 30, 2016 and 2015:

	For the three months ended September 30,						For the nine months ended September 30,
	2016			2015			2016			2015
	(in millions)
Equity loss from investment in Enbridge Energy Partners, L.P	$	(1.9	)	$	(117.3	)	$	(120.0	)	$	(192.3	)
Loss before income tax benefit (expense)		(1.9	)		(117.3	)		(120.0	)		(192.3	)
Income tax benefit (expense)		0.6			(160.5	)		1.2			(132.8	)
Net loss	$	(1.3	)	$	(277.8	)	$	(118.8	)	$	(325.1	)

Our net loss of $118.8 million for the nine months ended September 30, 2016, and our net loss of $277.8 million and $325.1 million for the three and nine months ended September 30, 2015, respectively, represent our equity in earnings attributable to the i-units that we own, adjusted for deferred income tax expense or benefit.

For the three months ended September 30, 2016, our net loss decreased by $276.5 million as compared to the net loss in the same period in 2015, due primarily to the discontinuance of equity method accounting at March 31, 2016, which limited the amount of losses recorded during the applicable period to the amortization of the remaining accumulated other comprehensive income as discussed above. Additionally, during the third quarter of 2015, we recognized a full valuation allowance against our deferred tax asset, which resulted in additional tax expense of $205.0 million. No similar charge was recorded during the same period in 2016.

For the nine months ended September 30, 2016, our net loss decreased by $206.3 million, as compared to the net loss in the same period in 2015. The decrease in the net loss is predominately attributable to additional tax expense of $205.0 million during the third quarter of 2015 due to recognition of a full valuation allowance, as discussed above, with no similar charge recorded in 2016. Additionally, the decrease in net losses are attributable to increases in curing impacts of the i-units, during the first quarter of 2016, which were curing the negative capital balances of both the Partnership’s Class A and Class B common units. For the nine months ended September 30, 2015, the i-units shared the curing burden of the Class B common units with the Class A common units. As discussed above, after the discontinuance of the equity method of accounting, no losses were recognized during the second and third quarters of 2016, other than amortization of losses from accumulated other comprehensive income.

10

LIQUIDITY AND CAPITAL RESOURCES

Our authorized capital structure consists of two classes of limited liability company interests: (1) our Listed Shares, which are traded on the New York Stock Exchange, or NYSE, and represent limited liability company interests with limited voting rights, and (2) our voting shares, which represent limited liability company interests with full voting rights and are held solely by the General Partner. At September 30, 2016, our issued capitalization consisted of $1,576.3 million associated with our 79,995,975 Listed Shares outstanding.

We use our capital to invest in i-units of the Partnership. We have, from time to time, raised capital through public equity offerings. Any net cash proceeds we receive from the sale of additional shares will immediately be used to purchase additional i-units. We have not issued additional shares in 2016. The number of our shares outstanding, including the voting shares owned by the General Partner, will at all times equal the number of i-units we own in the Partnership. Typically, the General Partner and owners of the Partnership’s Class A and B common units, Class D units, Class E units, and IDUs will receive distributions from the Partnership in cash. Instead of receiving cash distributions on the i-units we own, however, we receive additional i-units under the terms of the Partnership Agreement. The number of additional i-units we receive is calculated by dividing the amount of the cash distribution paid by the Partnership on each of its common units by the average closing price of one of our Listed Shares on the NYSE for the 10 trading day period immediately preceding the ex-dividend date for our shares, multiplied by the number of our shares outstanding on the record date. We make share distributions to our shareholders concurrently with the i-unit distributions we receive from the Partnership that increase the number of i-units we own. As a result of our share distributions, the number of shares outstanding is equal to the number of i-units that we own in the Partnership.

We are not permitted to borrow money or incur debt other than with Enbridge and its affiliates without the approval of holders owning at least a majority of our shares.

If we incur liabilities or other obligations in connection with the performance of our obligations under the delegation of control agreement, we are entitled to be reimbursed or to be indemnified by the Partnership or the General Partner. Thus, we expect that our expenditures associated with managing the business and affairs of the Partnership and the reimbursement of these expenses that we receive will continue to be equal. As previously stated, we do not receive quarterly distributions of cash on the i-units we hold. Therefore, we expect neither to generate nor to require significant amounts of cash in ongoing operations. Any net cash proceeds we receive from the sale of additional shares will immediately be used to purchase additional i-units. Accordingly, we do not anticipate any other sources of or needs for additional liquidity.

SUBSEQUENT EVENTS

Share Distribution

On October 28, 2016, our board of directors declared a share distribution payable on November 14, 2016, to shareholders of record as of November 7, 2016, based on the $0.5830 per limited partner unit distribution declared by the Partnership. The Partnership’s distribution increases the number of i-units that we own. The amount of this increase is calculated by dividing the cash amount distributed by the Partnership per common unit by the average closing price of one of our Listed Shares on the NYSE for the 10 trading day period immediately preceding the ex-dividend date for our shares, multiplied by the number of shares outstanding on the record date. We distribute additional Listed Shares to our shareholders and additional voting shares to the General Partner in respect of these additional i-units.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The nature of our business and operations is such that we do not conduct activities or enter into transactions of the type requiring discussion under this item.

For a discussion of these matters as they pertain to the Partnership, please read the information set forth under Part I, Item 3. Quantitative and Qualitative Disclosures About Market Risk of the Partnership’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2016, which is hereby incorporated by reference, as activities of the Partnership have an impact on our results of operations and financial position.

11

Item 4. Controls and Procedures

We and Enbridge Inc., or Enbridge, maintain systems of disclosure controls and procedures designed to provide reasonable assurance that we are able to record, process, summarize and report the information required to be disclosed in the reports that we file or submit under the Securities Exchange Act of 1934, as amended, or the Exchange Act, within the time periods specified in the rules and forms of the SEC, and that such information is accumulated and communicated to our management, including our principal executive and principal financial officers, as appropriate, to allow timely decisions regarding required disclosure. Our management, with the participation of our principal executive and principal financial officers, has evaluated the effectiveness of our disclosure controls and procedures as of September 30, 2016. Based upon that evaluation, our principal executive and principal financial officers concluded that our disclosure controls and procedures are effective at a reasonable assurance level. In conducting this assessment, our management relied on similar evaluations conducted by employees of Enbridge affiliates who provide certain treasury, accounting and other services on our behalf.

There have been no changes in internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting during the three months ended September 30, 2016.

12

PART II — OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

There have been no material changes to the risk factors previously disclosed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2015.

Item 6. Exhibits

Reference is made to the “Index of Exhibits” following the signature page, which is hereby incorporated into this Item.

13

SIGNATURES

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

	Enbridge Energy Management, L.L.C. (Registrant)
Date: October 31, 2016	By: /s/ Mark A. Maki Mark A. Maki President and Principal Executive Officer
Date: October 31, 2016	By: /s/ Stephen J. Neyland Stephen J. Neyland Vice President — Finance (Principal Financial Officer)

14

Index of Exhibits

Each exhibit identified below is filed as a part of this Quarterly Report on Form 10-Q. Exhibits included in this filing are designated by an asterisk; all exhibits not so designated are incorporated by reference to a prior filing as indicated.

Exhibit Number	Description
31.1*	Certification of Principal Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Principal Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*	Certification of Principal Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*	Certification of Principal Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.1*	Enbridge Energy Partners, L.P.’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2016.
101.INS*	XBRL Instance Document.
101.SCH*	XBRL Taxonomy Extension Schema Document.
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF*	XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB*	XBRL Taxonomy Extension Label Linkbase Document.
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase Document.

15

EX-31.1

Exhibit 31.1

CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Mark A. Maki, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Enbridge Energy Management, L.L.C.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: October 31, 2016	By: /s/ Mark A. Maki Mark A. Maki President and Principal Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Stephen J. Neyland, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Enbridge Energy Management, L.L.C.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: October 31, 2016	By: /s/ Stephen J. Neyland Stephen J. Neyland Vice President — Finance (Principal Financial Officer)

EX-32.1

Exhibit 32.1

CERTIFICATION OF PRINCIPAL EXECUTIVE OFFICER
Pursuant to Section 906(a) of the Sarbanes-Oxley Act of 2002
Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18 of the United States Code

The undersigned, being the Principal Executive Officer of Enbridge Energy Management, L.L.C. (the “Company”), hereby certifies that the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2016 (the “Quarterly Report”), filed with the United States Securities and Exchange Commission pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m(a) or 78o(d)), as amended, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and that the information contained in the Quarterly Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: October 31, 2016	By: /s/ Mark A. Maki Mark A. Maki President and Principal Executive Officer

EX-32.2

Exhibit 32.2

CERTIFICATION OF PRINCIPAL FINANCIAL OFFICER
Pursuant to Section 906(a) of the Sarbanes-Oxley Act of 2002
Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18 of the United States Code

The undersigned, being the Principal Financial Officer of Enbridge Energy Management, L.L.C. (the “Company”), hereby certifies that the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2016 (the “Quarterly Report”), filed with the United States Securities and Exchange Commission pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m(a) or 78o(d)), as amended, fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and that the information contained in the Quarterly Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: October 31, 2016	By: /s/ Stephen J. Neyland Stephen J. Neyland Vice President — Finance (Principal Financial Officer)

EX-99.1

Exhibit 99.1

Quarterly Report on
Form 10-Q
of
Enbridge Energy Partners, L.P.

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, 2016
 
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 28, 2016.

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, 2016 and 2015		1
Consolidated Statements of Comprehensive Income for the three and nine months ended September 30, 2016 and 2015		2
Consolidated Statements of Cash Flows for the nine months ended September 30, 2016 and 2015		3
Consolidated Statements of Financial Position as of September 30, 2016 and December 31, 2015		4
Notes to the Consolidated Financial Statements		5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		41
Item 3. Quantitative and Qualitative Disclosures About Market Risk		63
Item 4. Controls and Procedures		66
PART II — OTHER INFORMATION
Item 1. Legal Proceedings		67
Item 1A. Risk Factors		67
Item 6. Exhibits		67
Signatures		68
Exhibits		69

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,” “consider,” “continue,” “could,” “estimate,” “evaluate,” “expect,” “explore,” “forecast,” “intend,” “may,” “opportunity,” “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 or our joint venture partners’ ability, as applicable, to successfully complete and finance expansion projects including the Bakken Pipeline system transaction; (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) costs in connection with complying with the settlement consent decree related to Line 6B and Line 6A, which is still subject to court approval, or the failure to receive court approval of, or material modifications to, such decree; (7) changes in or challenges to our tariff rates; (8) 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 (9) permitting at federal, state and local levels in regards to the construction of new assets.

i

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, 2015, which is available to the public over the Internet at the U.S. Securities and Exchange Commission’s, or SEC’s, website (www.sec.gov) and at our website (www.enbridgepartners.com).

ii

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,
	2016			2015			2016			2015
	(unaudited; in millions, except per unit amounts)
Operating revenues:
Commodity sales (Note 12)	$	440.7		$	597.7		$	1,197.9		$	2,101.3
Commodity sales – affiliate (Notes 10 and 12)		1.3			12.2			7.9			62.4
Transportation and other services (Note 12)		649.9			621.4			1,944.1			1,744.6
Transportation and other services – affiliate (Note 10)		28.7			36.4			81.2			101.1
		1,120.6			1,267.7			3,231.1			4,009.4
Operating expenses:
Commodity costs (Notes 5 and 12)		396.1			503.3			1,082.0			1,912.0
Commodity costs – affiliate (Note 10)		7.9			19.4			29.1			60.4
Environmental costs, net of recoveries (Note 11)		(8.7	)		1.1			8.3			1.1
Operating and administrative		113.6			163.3			312.4			353.0
Operating and administrative – affiliate (Note 10)		111.0			117.3			339.6			351.9
Power		74.3			71.6			206.8			192.4
Depreciation and amortization		148.6			136.9			434.4			394.8
Goodwill impairment		—			—			—			246.7
Asset impairment (Note 6)		756.7			—			767.7			12.3
		1,599.5			1,012.9			3,180.3			3,524.6
Operating income (loss)		(478.9	)		254.8			50.8			484.8
Interest expense, net (Notes 8 and 12)		(112.3	)		(88.2	)		(326.7	)		(214.5	)
Allowance for equity used during construction (Note 16)		10.1			13.7			35.7			54.0
Other income		8.7			8.8			22.9			20.7
Income (loss) before income tax expense		(572.4	)		189.1			(217.3	)		345.0
Income tax expense (Note 13)		(2.2	)		(4.6	)		(7.2	)		(3.2	)
Net income (loss)		(574.6	)		184.5			(224.5	)		341.8
Less: Net income (loss) attributable to:
Noncontrolling interest (Note 9)		(191.9	)		77.8			(52.8	)		139.1
Series 1 preferred unit distributions		22.5			22.5			67.5			67.5
Accretion of discount on Series 1 preferred units		1.2			2.1			3.5			10.1
Net income (loss) attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P.	$	(406.4	)	$	82.1		$	(242.7	)	$	125.1
Net income (loss) allocable to common units and i-units	$	(452.6	)	$	26.1		$	(400.8	)	$	(37.4	)
Net income (loss) per common unit and i-unit (basic and diluted) (Note 2)	$	(1.31	)	$	0.07		$	(1.16	)	$	(0.11	)
Weighted average common units and i-units outstanding (basic and diluted)		349.1			341.1			347.0			337.9

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

1

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

	For the three months ended September 30,						For the nine months ended September 30,
	2016			2015			2016			2015
	(unaudited; in millions)
Net income (loss)	$	(574.6	)	$	184.5		$	(224.5	)	$	341.8
Other comprehensive income (loss), net of tax expense (Note 12)		14.7			(131.0	)		(104.6	)		(181.2	)
Comprehensive income (loss)		(559.9	)		53.5			(329.1	)		160.6
Less:
Net income (loss) attributable to noncontrolling interest (Note 9)		(191.9	)		77.8			(52.8	)		139.1
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		1.2			2.1			3.5			10.1
Other comprehensive loss allocated to noncontrolling interest		—			(1.3	)		—			(3.9	)
Comprehensive income (loss) attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P.	$	(391.7	)	$	(47.6	)	$	(347.3	)	$	(52.2	)

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

2

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

	For the nine months ended September 30,
	2016			2015
	(unaudited; in millions)
Cash provided by operating activities:
Net income (loss)	$	(224.5	)	$	341.8
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization		434.4			394.8
Derivative fair value net losses (Note 12)		97.9			40.0
Inventory market price adjustments (Note 5)		—			5.4
Goodwill impairment		—			246.7
Environmental costs, net of recoveries (Note 11)		6.3			0.7
Distributions from investments in joint ventures		22.0			20.5
Equity earnings from investments in joint ventures		(22.0	)		(20.5	)
Loss on sales of assets		1.6			3.2
Allowance for equity used during construction		(35.7	)		(54.0	)
Amortization of debt issuance and hedging costs		31.3			8.8
Asset impairment		767.7			12.3
Other		3.8			1.0
Changes in operating assets and liabilities, net of acquisitions:
Receivables, trade and other		15.0			36.2
Due from General Partner and affiliates		(43.7	)		(28.1	)
Accrued receivables		30.8			216.2
Inventory		(32.0	)		0.5
Current and long-term other assets		(22.6	)		(33.6	)
Due to General Partner and affiliates		20.2			80.5
Accounts payable and other		(84.8	)		(11.5	)
Environmental liabilities		(15.1	)		(34.5	)
Accrued purchases		(8.0	)		(175.1	)
Interest payable		20.3			0.3
Property and other taxes payable		(1.8	)		2.7
Net cash provided by operating activities		961.1			1,054.3
Cash used in investing activities:
Additions to property, plant and equipment (Note 15)		(891.1	)		(1,556.2	)
Asset acquisitions		—			(85.0	)
Changes in restricted cash		19.1			65.8
Proceeds from the sale of net assets		13.6			5.3
Investments in joint ventures		—			(3.0	)
Distributions from investments in joint ventures in excess of cumulative earnings		12.3			9.5
Other		(3.5	)		(2.9	)
Net cash used in investing activities		(849.6	)		(1,566.5	)
Cash provided by (used in) financing activities:
Net proceeds from unit issuances (Note 9)		—			294.8
Distributions to partners (Note 9)		(648.1	)		(619.9	)
Repayments to General Partner		—			(306.0	)
Net borrowings under credit facilities (Note 8)		510.0			785.0
Net commercial paper repayments (Note 8)		(33.8	)		(291.0	)
Contributions from noncontrolling interest (Note 10)		79.2			740.6
Distributions to noncontrolling interest (Note 10)		(125.2	)		(178.7	)
Other		(0.8	)		—
Net cash provided by (used in) financing activities		(218.7	)		424.8
Net decrease in cash and cash equivalents		(107.2	)		(87.4	)
Cash and cash equivalents at beginning of year		148.1			197.9
Cash and cash equivalents at end of period	$	40.9		$	110.5

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

3

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

	September 30, 2016			December 31, 2015
	(unaudited; in millions)
ASSETS
Current assets:
Cash and cash equivalents (Note 4)	$	40.9		$	148.1
Restricted cash (Note 4)		15.5			37.6
Receivables, trade and other, net of allowance for doubtful accounts of $2.3 million and $2.5 million at September 30, 2016 and December 31, 2015, respectively		20.0			25.2
Due from General Partner and affiliates (Note 10)		103.1			59.4
Accrued receivables		47.1			77.9
Inventory (Note 5)		66.9			35.1
Other current assets (Notes 12 and 16)		119.5			173.0
		413.0			556.3
Property, plant and equipment, net (Notes 6 and 16)		16,894.0			17,412.4
Intangible assets, net		263.8			280.0
Other assets, net (Notes 8 and 12)		529.2			525.6
	$	18,100.0		$	18,774.3
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Due to General Partner and affiliates (Note 10)	$	211.1		$	190.9
Accounts payable and other (Notes 4, 12 and 16)		420.8			654.9
Environmental liabilities (Note 11)		104.8			95.8
Accrued purchases		138.1			146.1
Interest payable		119.2			98.9
Property and other taxes payable (Note 13)		101.9			103.7
Current maturities of long-term debt (Note 8)		300.0			300.0
		1,395.9			1,590.3
Long-term debt (Note 8)		8,208.4			7,728.4
Due to General Partner and affiliates (Note 10)		305.8			238.3
Other long-term liabilities (Notes 11, 12 and 13)		368.5			305.2
		10,278.6			9,862.2
Commitments and contingencies (Note 11)
Partners’ capital: (Note 9)
Series 1 preferred units (48,000,000 authorized and issued at September 30, 2016 and December 31, 2015)		1,190.3			1,186.8
Class D units (66,100,000 authorized and issued at September 30, 2016 and December 31, 2015)		2,517.6			2,517.6
Class E units (18,114,975 authorized and issued at September 30, 2016 and December 31, 2015)		778.2			778.2
Class A common units (262,208,428 authorized and issued at September 30, 2016 and December 31, 2015)		—			—
Class B common units (7,825,500 authorized and issued at September 30, 2016 and December 31, 2015)		—			—
i-units (79,995,981 and 73,285,739 authorized and issued at September 30, 2016 and December 31, 2015, respectively)		—			212.6
Incentive distribution units (1,000 authorized and issued at September 30, 2016 and December 31, 2015)		495.1			495.0
General Partner		(530.9	)		147.4
Accumulated other comprehensive loss (Note 12)		(474.6	)		(370.0	)
Total Enbridge Energy Partners, L.P. partners’ capital		3,975.7			4,967.6
Noncontrolling interest (Note 9)		3,845.7			3,944.5
Total partners’ capital		7,821.4			8,912.1
	$	18,100.0		$	18,774.3

Variable Interest Entities (VIEs) — see Note 7.

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

4

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, 2016, our results of operations for the three and nine months ended September 30, 2016 and 2015, and our cash flows for the nine months ended September 30, 2016 and 2015. We derived our consolidated statement of financial position as of December 31, 2015 from the audited financial statements included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2015. Our results of operations for the three and nine months ended September 30, 2016 and 2015, 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, 2015.

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	%

⁽¹⁾ For distributions in excess of the Minimum Quarterly Distribution, this percentage includes both the General Partner’s distributions of 2% and the distribution to the Incentive Distribution Unit holder, a wholly-owned subsidiary of our General Partner.

5

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

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

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,
	2016			2015			2016			2015
	(in millions, except per unit amounts)
Net income (loss)	$	(574.6	)	$	184.5		$	(224.5	)	$	341.8
Less: Net income (loss) attributable to:
Noncontrolling interest		(191.9	)		77.8			(52.8	)		139.1
Series 1 preferred unit distributions		22.5			22.5			67.5			67.5
Accretion of discount on Series 1 preferred units		1.2			2.1			3.5			10.1
Net income (loss) attributable to general and limited partner interests in Enbridge Energy Partners, L.P.		(406.4	)		82.1			(242.7	)		125.1
Distributions:
Incentive distributions		(5.3	)		(5.3	)		(15.7	)		(13.8	)
Distributed earnings attributed to our General Partner		(5.2	)		(5.1	)		(15.7	)		(15.3	)
Distributed earnings attributed to Class D and Class E units		(49.1	)		(49.1	)		(147.3	)		(146.2	)
Total distributed earnings to our General Partner, Class D and Class E units and IDUs		(59.6	)		(59.5	)		(178.7	)		(175.3	)
Total distributed earnings attributed to our common units and i-units		(204.1	)		(199.2	)		(608.7	)		(591.2	)
Total distributed earnings		(263.7	)		(258.7	)		(787.4	)		(766.5	)
Overdistributed earnings	$	(670.1	)	$	(176.6	)	$	(1,030.1	)	$	(641.4	)
Weighted average common units and i-units outstanding		349.1			341.1			347.0			337.9
Basic and diluted earnings per unit:
Distributed earnings per common unit and i-unit(1)	$	0.58		$	0.58		$	1.75		$	1.75
Overdistributed earnings per common unit and i-unit(2)		(1.89	)		(0.51	)		(2.91	)		(1.86	)
Net income (loss) per common unit and i-unit (basic and diluted)(3)	$	(1.31	)	$	0.07		$	(1.16	)	$	(0.11	)

⁽¹⁾ Represents the total distributed earnings to common units and i-units divided by the weighted average number of common units and i-units outstanding for the period.

⁽²⁾ Represents the common units’ and i-units’ share (98%) of distributions in excess of earnings divided by the weighted average number of common units and i-units outstanding for the period and overdistributed earnings allocated to the common units and i-units based on the distribution waterfall that is outlined in our partnership agreement.

⁽³⁾ For the three and nine months ended September 30, 2016 and 2015, 43,201,310 anti-dilutive Preferred units, 66,100,000 anti-dilutive Class D units and 18,114,975 anti-dilutive Class E units were excluded from the if-converted method of calculating diluted earnings per unit.

3. ACQUISITIONS

On February 27, 2015, Midcoast Energy Partners, L.P., or MEP, acquired a midstream business which consisted of a natural gas gathering system in Leon, Madison and Grimes Counties, Texas. MEP acquired the 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 completion and connection of additional wells to the system by February 2016. Since the acquisition date, MEP released $17.0 million from escrow for additional wells connected to our system and for the resolution of the legal matter. During the first quarter of 2016, $3.0 million in escrow was returned to MEP as some of the additional wells were not connected to the system by February 2016. As a result, a $3.0 million gain was

6

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

3. ACQUISITIONS  – (continued)

recognized as a reduction to “Operating and administrative” expense, which is reflected in our consolidated statements of income for the nine months ended September 30, 2016. At September 30, 2016, no amounts remained in escrow.

The purchase and sale agreement contained a provision whereby MEP would have been obligated to make future tiered payments of up to $17.0 million if volumes are delivered into the system at certain tiered volume levels over a five-year period. MEP determined at the time of the acquisition that the potential payment was 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 was re-measured on a fair value basis each quarter until December 31, 2015, which resulted in an addition to the liability of $0.3 million for accretion. During the first quarter of 2016, and subsequent reassessments, MEP determined, based on current and forecasted volumes, that it is remote that MEP will be obligated to make any payments at the expiration of the five-year period. Consequently, the liability was reversed and a $2.6 million gain was recognized as a reduction to “Operating and administrative” expense, which is reflected in our consolidated statements of income for the nine months ended September 30, 2016.

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 $7.0 million and $21.5 million at September 30, 2016, and December 31, 2015, respectively, are included in “Accounts payable and other” on our consolidated statements of financial position.

Restricted Cash

Restricted cash is comprised of the following:

	September 30, 2016		December 31, 2015
	(in millions)
Cash collected on behalf of Enbridge subsidiary for accounts receivable sales and not yet remitted to the Enbridge subsidiary (see Note 10)	$	15.5	$	19.0
Cash held in escrow for acquisitions (see Note 3)		—		6.0
Cash collateral for derivative activities (see Note 12)		—		12.6
	$	15.5	$	37.6

5. INVENTORY

Our inventory is comprised of the following:

	September 30, 2016		December 31, 2015
	(in millions)
Materials and supplies	$	1.8	$	2.2
Crude oil inventory		2.1		1.6
Natural gas and NGL inventory		63.0		31.3
	$	66.9	$	35.1

“Commodity costs” on our consolidated statements of income include charges totaling $0.1 million and $5.4 million for the three and nine months ended September 30, 2015, respectively, that we recorded to reduce the cost basis of our inventory of natural gas and natural gas liquids, or NGLs, to reflect the current market value. For the three and nine months ended September 30, 2016, we did not have any similar material charges related to our inventory of natural gas and NGLs.

7

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, 2016			December 31, 2015
	(in millions)
Land	$	101.9		$	62.9
Rights-of-way		937.9			952.5
Pipelines		10,475.9			10,376.3
Pumping equipment, buildings and tanks		4,937.7			4,232.3
Compressors, meters and other operating equipment		2,180.1			2,147.6
Vehicles, office furniture and equipment		237.9			280.0
Processing and treating plants		630.0			627.8
Construction in progress		972.8			1,968.8
Total property, plant and equipment		20,474.2			20,648.2
Accumulated depreciation		(3,580.2	)		(3,235.8	)
Property, plant and equipment, net	$	16,894.0		$	17,412.4

On August 15, 2016, MEP sold certain trucks, trailers and related facilities which we include in our Natural Gas segment. The sales price was $12.1 million and the assets had a total carrying amount of $14.0 million at the date of sale. The loss on disposal of $1.9 million for the three and nine months ended September 30, 2016, 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 2016, MEP recorded $10.6 million in non-cash impairment charges on these assets, which are included in “Asset impairment” on our consolidated statements of income.

On September 1, 2016, we announced that we applied for the withdrawal of regulatory applications pending with the Minnesota Public Utilities Commission, or MNPUC, for the Sandpiper Project which is included in our Liquids segment. In connection with this announcement and other factors, we evaluated the project for impairment. As a result of the analysis, we recognized an impairment loss of $756.7 million for the three and nine months ended September 30, 2016, which is included in “Asset impairment” on our consolidated statements of income. Of that amount, $267.4 million is attributable to noncontrolling interest, or NCI. The estimated remaining fair value of $54.5 million of the Sandpiper Project is based on the estimated price that would be received to sell unused pipe, land and other related equipment in its current condition, considering the current market conditions for sale of these assets. The valuation considered a range of potential selling prices from various alternatives that could be used to dispose of these assets. The estimated fair value, with the exception of $2.6 million in land, has been reclassified into “Other assets, net” on our consolidated statement of financial position as of September 30, 2016.

7. VARIABLE INTEREST ENTITIES

Principles of Consolidation

On January 1, 2016, we adopted Accounting Standards Update, or ASU, No. 2015-02, which amended consolidation guidance to, among other things, eliminate the specialized consolidation model and guidance for limited partnerships, including the presumption that the general partner should consolidate a limited partnership. As a result, we have determined that certain entities that we historically consolidated under this presumption are variable interest entities, or VIEs. Further, we determined that we are the primary beneficiary for these VIEs and will continue to consolidate these entities under the amended guidance. While the amended guidance did not impact our conclusion that such entities should be consolidated, because such entities are now considered VIEs, additional disclosures are necessary. We have applied this amended guidance retrospectively to our disclosures.

8

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

7. VARIABLE INTEREST ENTITIES  – (continued)

The consolidated financial statements include our accounts, and accounts of our subsidiaries and VIEs for which we are the primary beneficiary. Upon inception of a contractual agreement, we perform an assessment to determine whether the arrangement contains a variable interest in a legal entity and whether that legal entity is a VIE. Where we conclude we are the primary beneficiary of a VIE, we consolidate the accounts of that entity.

We assess all aspects of our interests in an entity and use judgment when determining if we are the primary beneficiary. The primary beneficiary has both the power to direct the activities of the VIE that most significantly impact the entity’s economic performance and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. Other qualitative factors that are considered include decision-making responsibilities, the VIE capital structure, risk and rewards sharing, contractual agreements with the VIE, voting rights and level of involvement of other parties. Reassessment of the primary beneficiary conclusion is conducted on an ongoing basis as there are changes in the facts and circumstances related to each VIE.

All significant intercompany accounts and transactions are eliminated upon consolidation. Ownership interests in subsidiaries represented by other parties that do not control the entity are presented in the consolidated financial statements as activities and balances attributable to NCI. Investments and entities over which we exercise significant influence are accounted for using the equity method.

Midcoast Energy Partners, L.P.

MEP is a publicly-traded Delaware limited partnership. As of September 30, 2016, we owned a 51.9% direct limited partner interest in MEP. In addition, we own MEP’s general partner, Midcoast Holdings GP, L.L.C. The public owns the remaining interests in MEP. We are the primary beneficiary of MEP because (1) through our ownership of MEP’s general partner and our majority limited partner interest, we have the power to direct the activities that most significantly impact MEP’s economic performance; and (2) we have the obligation to absorb losses and the right to receive residual returns that potentially could be significant to MEP.

As of September 30, 2016 and December 31, 2015, our consolidated statements of financial position include total assets of $4,979.4 million and $5,227.2 million, respectively, and total liabilities of $1,146.9 million and $1,220.7 million, respectively, related to MEP. Only the assets of MEP can be used to settle MEP’s obligations. We currently do not have any obligation to provide financial support to MEP other than through certain contractual obligations, as prescribed by the terms of certain indemnities and guarantees, to pay specified liabilities of MEP.

Midcoast Operating, L.P.

Midcoast Operating is a Texas limited partnership. As of September 30, 2016, we and MEP owned 48.4% and 51.6%, respectively, of direct limited partner interest in Midcoast Operating. In addition, MEP owns Midcoast Operating’s general partner, Midcoast OLP GP, L.L.C. MEP is the primary beneficiary of Midcoast Operating because (1) through MEP’s ownership in Midcoast Operating’s general partner and majority limited partner interest, MEP has the power to direct the activities that most significantly impact Midcoast Operating’s economic performance; and (2) MEP has the obligation to absorb losses and the right to receive residual returns that potentially could be significant to Midcoast Operating. In addition, MEP is the entity within the related party group that is most closely associated with Midcoast Operating. As such, MEP consolidates Midcoast Operating. As discussed above, we consolidate MEP, and by extension also consolidate Midcoast Operating.

Enbridge Energy, Limited Partnership

Enbridge Energy, Limited Partnership, or OLP, is a Delaware limited partnership that has established several series of partnership interests. As of September 30, 2016, we owned, directly or indirectly, 100% of the general partner interests in each series of OLP, as well as 100% of the Series LH and Series AC limited partner interests in OLP. In addition, including our ownership of the general partner interests, we directly and indirectly owned 25% of the Series EA and Series ME interests in OLP. Our General Partner owns the remaining 75% interests in Series EA and Series ME interests in OLP. We are the primary beneficiary of OLP because (1) through our ownership of the general partner interests in each of the OLP’s series and our limited partner interests in each series, we have the power to direct the activities that most significantly impact OLP’s economic performance; and (2) we have the obligation to absorb losses and the right to receive residual returns that potentially could be significant to OLP. In addition, we are the entity within the related party group that is most closely associated with OLP.

9

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

7. VARIABLE INTEREST ENTITIES  – (continued)

As of September 30, 2016 and December 31, 2015, our consolidated statements of financial position include total assets of $11,394.7 million and $11,074.9 million, respectively, and total liabilities of $772.7 million and $998.2 million, respectively, related to OLP. Only the assets of OLP can be used to settle OLP’s obligations. We currently do not have any obligation to provide financial support to OLP, although from time to time, we may provide certain indemnities and guarantees for payment of specified liabilities to third parties in the event that OLP becomes in default under contracts with those third parties.

North Dakota Pipeline Company LLC

North Dakota Pipeline Company LLC, or NDPC, is a Delaware limited liability company. As of September 30, 2016, we directly owned 100% of the Class A units and 62.5% of the Class B units in NDPC. Williston Basin Pipeline LLC, or Williston, an affiliate of Marathon Petroleum Corporation, or MPC, owns the remaining 37.5% of Class B units in NDPC, which were used to fund the Sandpiper Project. We are the primary beneficiary of NDPC because (1) through our 100% ownership in NDPC’s Class A units and majority ownership in its Class B units, we have the power to direct the activities that most significantly impact NDPC’s economic performance; and (2) we have the obligation to absorb losses and the right to receive residual returns that potentially could be significant to NDPC.

As of September 30, 2016 and December 31, 2015, our consolidated statements of financial position include total assets of $1,047.7 million and $1,746.3 million, respectively, and total liabilities of $55.9 million and $84.8 million, respectively, related to NDPC. Only the assets of NDPC can be used to settle NDPC’s obligations. We currently do not have any obligation to provide financial support to NDPC, although from time to time we may provide certain indemnities and guarantees for payment of specified liabilities to third parties in the event that NDPC becomes in default under contracts with those third parties.

The following table includes assets to be used to settle liabilities of our consolidated VIEs and liabilities of our consolidated VIEs for which creditors do not have recourse to our general credit as the primary beneficiary. These assets and liabilities are included in our consolidated balance sheet.

	September 30, 2016		December 31, 2015
	(in millions)
ASSETS
Cash and cash equivalents	$	40.9	$	108.7
Restricted cash	$	6.7	$	20.6
Receivables, trade and other, net	$	19.1	$	22.8
Due from General Partner and affiliates	$	94.4	$	51.9
Accrued receivables	$	45.6	$	77.4
Inventory	$	64.9	$	35.1
Other current assets	$	116.8	$	165.3
Property, plant and equipment, net	$	16,243.6	$	16,766.6
Intangible assets, net	$	263.7	$	279.8
Other assets, net	$	526.1	$	520.2
LIABILITIES
Due to General Partner and affiliates	$	129.2	$	123.4
Accounts payable and other	$	265.2	$	534.2
Environmental liabilities	$	104.7	$	95.7
Accrued purchases	$	137.8	$	144.1
Interest payable	$	8.2	$	8.7
Property and other taxes payable	$	96.6	$	100.5
Long-term debt	$	1,047.7	$	1,087.4
Other long-term liabilities	$	186.1	$	209.7

10

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, 2016, 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, 2016			December 31, 2015
				(in millions)
EEP debt obligations:
Commercial Paper(1)		1.435	%	$	292.6		$	326.1
Credit Facilities due 2017-2020		1.756	%		1,660.0			1,110.0
Senior Notes due December 2016		5.875	%		300.0			300.0
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 October 2020		4.375	%		500.0			500.0
Senior Notes due September 2021		4.200	%		600.0			600.0
Senior Notes due October 2025		5.875	%		500.0			500.0
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
Senior Notes due October 2045		7.375	%		600.0			600.0
Junior subordinated notes due 2067		8.050	%		400.0			400.0
OLP debt obligations:
Senior Notes due October 2018		7.000	%		100.0			100.0
Senior Notes due October 2028		7.125	%		100.0			100.0
MEP debt obligations:
MEP Credit Agreement		3.431	%		450.0			490.0
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 amount of debt obligations					8,552.6			8,076.1
Other:
Unamortized discount					(5.9	)		(6.2	)
Current maturities of long-term debt					(300.0	)		(300.0	)
Unamortized debt issuance costs					(38.3	)		(41.5	)
Total long term debt				$	8,208.4		$	7,728.4

⁽¹⁾ Individual issuances of commercial paper generally mature in 90 days or less, but are supported by our Credit Facilities and are therefore considered long-term debt.

On January 1, 2016, we adopted ASU No. 2015-03, which requires us to present debt issuance costs in the balance sheet as a reduction to the carrying amount of the debt liability, rather than as an asset. We have retrospectively adopted this guidance for all periods presented. The adoption of this guidance did not have a material impact on our consolidated financial statements.

11

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

8. DEBT  – (continued)

Interest Cost

Our interest cost for the three and nine months ended September 30, 2016, and 2015, is comprised of the following:

	For the three months ended September 30,				For the nine months ended September 30,
	2016		2015		2016		2015
	(in millions)
Interest cost incurred(1)	$	123.0	$	98.8	$	367.9	$	243.4
Less: Interest capitalized		10.7		10.6		41.2		28.9
Interest expense	$	112.3	$	88.2	$	326.7	$	214.5

⁽¹⁾ Interest cost incurred increased period-over-period, due to an increase in our average outstanding debt balances and in part due to an increase in unrealized losses associated with interest rate derivatives for the nine months ended September 30, 2015, that did not occur during the same period in 2016.

Credit Facilities and Commercial Paper

Our multi-year senior unsecured revolving credit facility, which we refer to as the Credit Facility, permits aggregate borrowings of up to, at any one time outstanding, $2.0 billion. The increase in the permitted aggregate borrowings under the Credit Facility from the second quarter of 2016 reflects an amendment on July 28, 2016 to increase the lending commitments by $25.0 million. The Credit Facility matures September 26, 2020; however, $175.0 million of commitments will expire on the original maturity date of September 26, 2018.

Our 364-day revolving credit agreement, which we refer to as the 364-Day Credit Facility, permits aggregate borrowings of up to $625.0 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. The current revolving credit termination date is June 30, 2017.

At September 30, 2016, the Credit Facility and 364-Day Credit Facility, together referred to as 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. The amounts we may borrow under the terms of our Credit Facilities are reduced by the face amount of our letters of credit outstanding. During the nine months ended September 30, 2016, we had net borrowings of $550.0 million, which includes gross borrowings of $13,590.0 million and gross repayments of $13,040.0 million.

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. The EUS 364-day Credit Facility is discussed in Note 11. Related Party Transactions.

We are party to 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 $175.0 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.

Our commercial paper program 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. During the nine months ended September 30, 2016, we had net repayments of approximately $33.8 million, which includes gross borrowings of $6,084.1 million and gross repayments of $6,117.9 million. Our policy is to limit the amount of

12

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

8. DEBT  – (continued)

commercial paper we can issue by the amounts available under our Credit Facility up to an aggregate principal amount of $1.5 billion as mentioned above.

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.

At September 30, 2016, we had approximately $1,172.2 million of unutilized commitments under the terms of our Credit Facilities and the EUS 364-day Credit Facility, determined as follows:

	(in millions)
Total commitments under our Credit Facilities	$	2,625.0
Total commitments under the EUS 364-day Credit Facility		750.0
Less: Amounts outstanding under our Credit Facilities		1,660.0
Principal amount of commercial paper outstanding		292.6
Letters of credit outstanding		250.2
Total unutilized commitments at September 30, 2016	$	1,172.2

MEP Credit Agreement

MEP, Midcoast Operating, and their material subsidiaries are party to a senior revolving credit facility, which we refer to as the MEP Credit Agreement, which permits aggregate borrowings of up to $810.0 million, at any one time outstanding. 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 at the lenders’ discretion, two of which we have utilized. The MEP Credit Agreement’s current maturity date is September 30, 2018; however, $140.0 million of commitments expire on the original maturity date of November 13, 2016, and an additional $25.0 million of commitments expire on September 30, 2017. During the nine months ended September 30, 2016, MEP had net repayments of approximately $40.0 million, which includes gross borrowings of $5,715.0 million and gross repayments of $5,755.0 million.

Debt Covenants

As of September 30, 2016, we and our consolidated subsidiaries were in compliance with the terms of our financial covenants under our consolidated debt agreements.

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, 2016, and December 31, 2015, 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.

The approximate fair value of our fixed-rate debt obligations was $6.8 billion and $5.9 billion at September 30, 2016, and December 31, 2015, 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.

13

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

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, 2016.

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 28, 2016		August 5, 2016		August 12, 2016	$	0.5830	$	262.5	$	45.5	$	0.9	$	216.1
April 29, 2016		May 6, 2016		May 13, 2016	$	0.5830	$	261.2	$	44.3	$	0.9	$	216.0
January 29, 2016		February 5, 2016		February 12, 2016	$	0.5830	$	259.6	$	42.7	$	0.9	$	216.0

⁽¹⁾ We issued 6,710,242 i-units to Enbridge Management, the sole owner of our i-units, during 2016 in lieu of cash distributions.

⁽²⁾ We retained an amount equal to 2% of the i-unit distribution from our General Partner to maintain its 2% general partner interest in us.

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, for the nine months ended September 30, 2016 and 2015.

	For the nine months ended September 30,
	2016			2015
	(in millions)
Series 1 Preferred interests
Beginning balance	$	1,186.8		$	1,175.6
Net income		67.5			67.5
Accretion of discount on preferred units		3.5			10.1
Distribution payable		(67.5	)		(67.5	)
Ending balance	$	1,190.3		$	1,185.7
General and limited partner interests
Beginning balance	$	4,150.8		$	4,156.2
Proceeds from issuance of partnership interests, net of costs		—			294.8
Net income (loss)		(242.7	)		125.1
Distributions		(648.1	)		(619.9	)
Acquisition of noncontrolling interest in subsidiary		—			403.7
Ending balance	$	3,260.0		$	4,359.9
Accumulated other comprehensive loss
Beginning balance	$	(370.0	)	$	(211.4	)
Changes in fair value of derivative financial instruments reclassified to earnings		29.7			(6.4	)
Changes in fair value of derivative financial instruments recognized in other comprehensive loss		(134.3	)		(170.9	)
Ending balance	$	(474.6	)	$	(388.7	)
Noncontrolling interest
Beginning balance	$	3,944.5		$	3,609.0
Capital contributions		79.2			740.6
Acquisition of noncontrolling interest in subsidiary		—			(403.7	)
Other comprehensive loss allocated to noncontrolling interest		—			(3.9	)
Net income (loss)		(52.8	)		139.1
Distributions to noncontrolling interest		(125.2	)		(178.7	)
Ending balance	$	3,845.7		$	3,902.4
Total partners’ capital at end of period	$	7,821.4		$	9,059.3

14

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

9. PARTNERS’ CAPITAL  – (continued)

Curing

Our limited partnership agreement does not permit capital deficits to accumulate in the capital accounts of any limited partner and thus requires that such capital account deficits be “cured” by additional allocations from the positive capital accounts of the common units, i-units, and our General Partner, generally on a pro-rata basis. For the nine months ended September 30, 2016, the carrying amounts for the capital accounts of the Class A and Class B common units were reduced below zero due to distributions to limited partners in excess of earnings attributable to such limited partners. As a result, the capital balances of the i-units and our General Partner interests were reduced by $120.0 million and $657.4 million, respectively, to cure the applicable deficit balances.

Noncontrolling Interests

We have noncontrolling interests in the following consolidated subsidiaries: OLP, NDPC, and MEP. The noncontrolling interest in the OLP arises from the joint funding arrangements with our General Partner and its affiliate to finance certain expansion projects on our Lakehead system, which we refer to as the Eastern Access, or EA, and Mainline Expansion, or ME, Projects. Noncontrolling interest in NDPC arose from our agreement with Williston, an affiliate of MPC, to, among other things, fund 37.5% of the Sandpiper Project. Noncontrolling interest in MEP arises from its public unitholders’ ownership interests in MEP.

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,
	2016			2015			2016			2015
	(in millions)
Alberta Clipper Interests	$	—		$	—		$	—		$	(0.8	)
Eastern Access Interests		48.3			50.3			153.0			140.2
U.S. Mainline Expansion Interests		39.0			29.1			99.7			73.5
North Dakota Pipeline Company Interests(1)		(269.6	)		—			(269.6	)		—
Midcoast Energy Partners, L.P.		(9.6	)		(1.6	)		(35.9	)		(73.8	)
Total	$	(191.9	)	$	77.8		$	(52.8	)	$	139.1

⁽¹⁾ Inclusive of impairment on the Sandpiper Project attributable to noncontrolling interest.

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.

Enbridge and its affiliates allocated direct workforce costs to us for our construction projects of $21.7 million and $19.1 million for the nine months ended September 30, 2016 and 2015, respectively, that we recorded as additions to “Property, plant and equipment, net” on our consolidated statements of financial position.

15

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

10. RELATED PARTY TRANSACTIONS  – (continued)

Affiliate Revenues and Purchases

We sell NGLs and crude oil at market prices on the date of sale to Enbridge and its affiliates. The sales to Enbridge and its affiliates 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 NGLs and crude oil from Enbridge and its affiliates for sale to third parties at market prices on the date of purchase. Purchases of 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, 2016 and December 31, 2015, was $359.6 million and $372.3 million, respectively, which is included on our consolidated statements of financial position in “Other assets, net.”

We recognized equity income of $8.3 million and $8.9 million for the three months ended September 30, 2016 and 2015, respectively, and $22.0 million and $20.5 million for the nine months ended September 30, 2016 and 2015, respectively, in “Other income” on our consolidated statements of income related to our investment in the system.

We incurred $4.6 million and $5.1 million for the three months ended September 30, 2016 and 2015, respectively, and $14.9 million and $13.4 million for the nine months ended September 30, 2016 and 2015, 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 segment has made commitments to transport up to 120,000 barrels per day, or Bpd, of NGLs on the Texas Express NGL system by 2022. Our current commitment level is 29,000 Bpd and the average commitment level will increase to 75,000 Bpd in 2017.

Sale of Accounts Receivable

We sold and derecognized receivables of $851.5 million and $911.8 million for the three months ended September 30, 2016 and 2015, respectively, and $2,485.0 million and $2,925.5 million for the nine months ended September 30, 2016 and 2015, respectively, to an indirect, wholly-owned subsidiary of Enbridge. We received cash proceeds of $851.1 million and $911.5 million for the three months ended September 30, 2016 and 2015, respectively, and $2,483.9 million and $2,924.7 million for the nine months ended September 30, 2016 and 2015, respectively.

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, 2016 and 2015, the expense stemming from the discount on the receivables sold was not material.

As of September 30, 2016 and December 31, 2015, we had $15.5 million and $19.0 million, respectively, in “Restricted cash” on our consolidated statements of financial position, for cash collections related to sold and derecognized receivables that have yet to be remitted to the Enbridge subsidiary. As of September 30, 2016 and December 31, 2015, outstanding receivables of $277.2 million and $317.0 million, respectively, which had been sold and derecognized, had not been collected on behalf of the Enbridge subsidiary.

16

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

10. RELATED PARTY TRANSACTIONS  – (continued)

Financing Transactions with Affiliates

EUS 364-day Credit Facility

On July 26, 2016, we entered into an unsecured revolving 364-day credit agreement, which we refer to as the EUS 364-day Credit Facility, with EUS. 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, at our election, based on either the Eurocurrency rate or a base rate, in each case, plus an applicable margin. The EUS 364-day Credit Facility terminates on July 25, 2017. At that time, we may elect to convert any outstanding loans to term loans, which would mature on July 24, 2018. As of September 30, 2016, there were no outstanding borrowings under this facility.

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, 2016, 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 27, 2016		August 12, 2016	$	8.9	$	7.6	$	16.5
April 28, 2016		May 13, 2016	$	8.9	$	7.6	$	16.5
January 28, 2016		February 12, 2016	$	8.9	$	7.6	$	16.5
			$	26.7	$	22.8	$	49.5

Omnibus Agreement

We, Midcoast Holdings, MEP and Enbridge are parties to the Omnibus Agreement under which we agreed to, among other things, indemnify MEP for certain matters, including environmental, right-of-way and permit matters. Our obligation to indemnify MEP for these matters is subject to a $500,000 aggregate deductible before MEP is entitled to indemnification. Additionally, there is a $15.0 million aggregate cap on the amounts for which we will indemnify MEP for under the Omnibus Agreement. During the first quarter of 2016, we paid indemnification proceeds to MEP under the Omnibus Agreement of $12.2 million for the acquisition of title to right-of-way assets that were pending at the time of MEP’s initial public offering and associated legal fees. No other payments have been made to MEP under the Omnibus Agreement.

Financial Support Agreement

At September 30, 2016, we had no letters of credit outstanding and $24.8 million of guarantees to Midcoast Operating under a Financial Support Agreement with Midcoast Operating. At December 31, 2015, we provided $7.5 million of letters of credit outstanding and $21.7 million of guarantees to Midcoast Operating under this agreement.

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 agreed to temporarily forego Series EA and ME, collectively, the Series, distributions commencing in the quarter ended June 30, 2015 through the quarter ended 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

17

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

10. RELATED PARTY TRANSACTIONS  – (continued)

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 the Eastern Access 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. 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%.

Our General Partner made equity contributions totaling $7.2 million and $119.3 million to the OLP for the nine months ended September 30, 2016 and 2015, 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, 2016, 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 28, 2016		August 12, 2016	$	21.0	$	63.0	$	84.0
April 29, 2016		May 13, 2016	$	79.0	$	—	$	79.0
January 29, 2016		February 12, 2016	$	79.2	$	—	$	79.2
			$	179.2	$	63.0	$	242.2

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 the Mainline Expansion 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. 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 $58.5 million and $552.9 million to the OLP for the nine months ended September 30, 2016, and 2015, respectively, to fund its equity portion of the construction costs associated with the Mainline Expansion Projects.

18

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

10. RELATED PARTY TRANSACTIONS  – (continued)

Distribution to Series ME Interests

The following table presents distributions paid by the OLP during the nine months ended September 30, 2016, 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 28, 2016		August 12, 2016	$	13.1	$	39.4	$	52.5
April 29, 2016		May 13, 2016	$	43.2	$	—	$	43.2
January 29, 2016		February 12, 2016	$	40.8	$	—	$	40.8
			$	97.1	$	39.4	$	136.5

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, 2016 and December 31, 2015, we had $104.8 million and $95.8 million, respectively, included in “Environmental liabilities,” and $56.2 million and $64.0 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 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.

As of September 30, 2016, our cumulative cost estimate for the Line 6B crude oil release remains at $1.2 billion. This includes a reduction of estimated remediation efforts offset by an increase in civil penalties under the Clean Water Act of the United States, as described below under Fines and Penalties.

19

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

11. COMMITMENTS AND CONTINGENCIES  – (continued)

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, 2016. 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 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 components underlying our cumulative estimated loss for the cleanup, remediation and restoration associated with the Line 6B crude oil release, the majority of which have been paid, include the following:

	(in millions)
Response personnel and equipment	$	548.8
Environmental consultants		226.9
Professional, regulatory, fines and penalties and other		447.3
Total	$	1,223.0

For the nine months ended September 30, 2016 and 2015, we made payments of $17.3 million and $32.0 million, respectively, for costs associated with the Line 6B crude oil release. As of September 30, 2016 and December 31, 2015, we had a remaining estimated liability of $150.3 million and $149.8 million, respectively.

Line 6B Fines and Penalties

At September 30, 2016, our total estimated costs related to the Line 6B crude oil release include $68.5 million in fines and penalties. Of this amount, $61.0 million relates to civil penalties under the Clean Water Act of the United States, which we have fully reserved in our contingency accrual but have not yet paid.

Consent Decree

On July 20, 2016, a Consent Decree was filed with the United States District Court for the Western District of Michigan, Southern Division, or the Court. The Consent Decree is our signed settlement agreement with the U.S. Environmental Protection Agency and the U.S. Department of Justice regarding Lines 6A and 6B crude oil releases. Pursuant to the Consent Decree, we will pay $62.0 million in civil penalties: $61.0 million in respect of Line 6B and $1.0 million in respect of Line 6A. The Consent Decree will take effect upon approval by the Court.

In addition to the monetary fines and penalties, the Consent Decree calls for replacement of Line 3, which we initiated in 2014 and is currently under regulatory review in the State of Minnesota. The Consent Decree contains a variety of injunctive measures, including, but not limited to, enhancements to our comprehensive in-line inspection (ILI)-based spill prevention program; enhanced measures to protect the Straits of Mackinac; improved leak detection requirements; installation of new valves to control product loss in the event of an incident; continued enhancement of control room operations; and improved spill response capabilities. Collectively, these measures build on continuous improvements we have implemented since 2010 to our leak detection program, control center operations, and emergency response program. We estimate the total cost of these measures to be approximately $110.0 million, most of which is already incorporated into existing long-term capital investment and operational expense planning and guidance. Compliance with the terms of the Consent Decree is not expected to materially impact our overall financial performance.

20

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

11. COMMITMENTS AND CONTINGENCIES  – (continued)

Insurance

We are included in the comprehensive insurance program that is maintained by Enbridge for its subsidiaries and affiliates. 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.

Enbridge, together with us and its other affiliates, renewed its comprehensive property and liability insurance programs, under which we are insured through April 30, 2017, with a liability program aggregate limit of $900.0 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.

A majority of the costs incurred for the Line 6B crude oil release, other than fines and penalties, 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, 2016, costs related to Line 6B exceeded the limits of the coverage available under this insurance policy. As of September 30, 2016, 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 asserted that their payment was 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 includes 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 scheduled to begin in the fourth quarter of 2016. While we believe that those costs are eligible for recovery, there can be no assurance that we will prevail.

In addition, and separate from the Line 6B claim, for the three and nine months ended September 30, 2016, we recorded an insurance recovery of $10.0 million associated with the Line 6A crude oil release, which occurred in 2010. This is the total insurance recovery available for that incident.

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. Three actions or claims are pending against us and our affiliates in state 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 6B crude oil release 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

21

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

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

NGLs 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 are not designated 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.

Derivative Positions

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

	September 30, 2016			December 31, 2015
	(in millions)
Other current assets	$	53.6		$	123.9
Other assets, net		9.0			39.7
Accounts payable and other(1)		(172.3	)		(130.9	)
Other long-term liabilities		(161.8	)		(90.6	)
	$	(271.5	)	$	(57.9	)

⁽¹⁾ Includes $12.6 million held of cash collateral at December 31, 2015.

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 natural gas, NGLs and crude oil sales and purchase contracts and interest rate contracts.

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

	September 30, 2016			December 31, 2015
	(in millions)
Counterparty Credit Quality(1)
AA(2)		(99.1	)		(12.4	)
A		(109.1	)		(10.5	)
Lower than A		(63.3	)		(35.0	)
	$	(271.5	)	$	(57.9	)

⁽¹⁾ As determined by nationally-recognized statistical ratings organizations.

⁽²⁾ Includes $12.6 million held of cash collateral at December 31, 2015.

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, 2016, we did not have any cash

22

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

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

collateral on our asset exposures. At December 31, 2015, we held $12.6 million of cash collateral on our asset exposures. Cash collateral is classified as “Restricted cash” in our consolidated statements of financial position.

We provided letters of credit totaling $248.6 million and $120.1 million relating to our liability exposures pursuant to the margin thresholds in effect at September 30, 2016 and December 31, 2015, 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 below the lowest level of investment grade at September 30, 2016, we would have been required to provide additional letters of credit in the amount of $54.2 million related to our positions.

At September 30, 2016 and December 31, 2015, we had credit concentrations in the following industry sectors, as presented below:

	September 30, 2016			December 31, 2015
	(in millions)
United States financial institutions and investment banking entities(1)	$	(172.5	)	$	(30.9	)
Non-United States financial institutions		(109.1	)		(51.0	)
Other		10.1			24.0
	$	(271.5	)	$	(57.9	)

⁽¹⁾ Includes $12.6 million held of cash collateral at December 31, 2015.

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.

23

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

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

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, 2016		December 31, 2015		September 30, 2016			December 31, 2015
			(in millions)
Derivatives designated as hedging instruments:(1)
Interest rate contracts		Accounts payable and other	$	—	$	—	$	(135.7	)	$	(85.2	)
Interest rate contracts		Other long-term liabilities		—		—		(153.6	)		(72.3	)
				—		—		(289.3	)		(157.5	)
Derivatives not designated as hedging instruments:
Commodity contracts		Other current assets		53.6		123.9		—			—
Commodity contracts		Other assets		9.0		39.7		—			—
Commodity contracts		Accounts payable and other(2)		—		—		(36.6	)		(33.1	)
Commodity contracts		Other long-term liabilities		—		—		(8.2	)		(18.3	)
				62.6		163.6		(44.8	)		(51.4	)
Total derivative instruments			$	62.6	$	163.6	$	(334.1	)	$	(208.9	)

⁽¹⁾ Includes items currently designated as hedging instruments. Excludes the portion of de-designated hedges which may have a component remaining in accumulated other comprehensive income, or AOCI.

⁽²⁾ Liability derivatives exclude $12.6 million held of cash collateral at December 31, 2015.

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. As of September 30, 2016 and December 31, 2015, we included in AOCI unrecognized losses of approximately $231.7 million and $255.5 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, unrealized commodity hedge gains of $1.5 million were de-designated as a result of the hedges no longer meeting hedge accounting criteria. No commodity hedges were de-designated during the nine months ended September 30, 2016. We estimate that approximately $52.7 million, representing net losses from our cash flow hedging activities based on pricing and positions at September 30, 2016, will be reclassified from AOCI to earnings during the next 12 months.

24

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

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

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, 2016
Interest rate contracts	$	6.9			Interest expense	$	(10.0	)		Interest expense	$	—
Commodity contracts		—			Commodity Costs		0.1			Commodity Costs		—
Total	$	6.9				$	(9.9	)			$	—
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 nine months ended September 30, 2016
Interest rate contracts	$	(128.3	)		Interest expense	$	(29.9	)		Interest expense	$	(3.4	)
Commodity contracts		—			Commodity Costs		0.2			Commodity Costs		—
Total	$	(128.3	)			$	(29.7	)			$	(3.4	)
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

⁽¹⁾ Includes only the ineffective portion of derivatives that are designated as hedging instruments and does not include net gains or losses associated with derivatives that do not qualify for hedge accounting treatment.

Components of Accumulated Other Comprehensive Income/(Loss)

	Cash Flow Hedges
	2016			2015
	(in millions)
Balance at January 1	$	(370.0	)	$	(211.4	)
Other comprehensive loss before reclassifications(1)		(134.3	)		(170.9	)
Amounts reclassified from AOCI(2)(3)		29.7			(6.4	)
Net other comprehensive loss	$	(104.6	)	$	(177.3	)
Balance at September 30	$	(474.6	)	$	(388.7	)

⁽¹⁾ Excludes NCI gain of $1.8 million reclassified from AOCI at September 30, 2015.

⁽²⁾ Excludes NCI loss of $5.7 million reclassified from AOCI at September 30, 2015.

⁽³⁾ For additional details on the amounts reclassified from AOCI, reference the Reclassifications from Accumulated Other Comprehensive Income table below.

25

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

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

Reclassifications from Accumulated Other Comprehensive Income

	For the three months ended September 30,						For the nine months ended September 30,
	2016			2015			2016			2015
	(in millions)
Losses (gains) on cash flow hedges:
Interest Rate Contracts(1)(2)	$	10.0		$	3.6		$	29.9		$	11.9
Commodity Contracts(3)(4)(5)		(0.1	)		(6.5	)		(0.2	)		(18.3	)
Total Reclassifications from AOCI	$	9.9		$	(2.9	)	$	29.7		$	(6.4	)

⁽¹⁾ Loss reported within “Interest expense, net” in the consolidated statements of income.

⁽²⁾ Excludes NCI gain of $0.1 million reclassified from AOCI for the three and nine months ending September 30, 2015.

⁽³⁾ Gains reported within “Commodity costs” in the consolidated statements of income.

⁽⁴⁾ Excludes NCI gain of $2.1 million reclassified from AOCI for the three months ending September 30, 2015.

⁽⁵⁾ Excludes NCI loss of $5.8 million reclassified from AOCI for the nine months ended September 30, 2015.

Effect of Derivative Instruments on Consolidated Statements of Income

			For the three months ended September 30,					For the nine months ended September 30,
			2016		2015			2016			2015
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)	$	1.0	$	8.1		$	(2.1	)	$	8.1
Commodity contracts		Commodity sales		1.7		(7.2	)		(1.8	)		(22.4	)
Commodity contracts		Commodity sales – affiliate		—		—			—			(0.3	)
Commodity contracts		Commodity costs(4)		2.4		40.8			(22.4	)		44.3
Total			$	5.1	$	41.7		$	(26.3	)	$	29.7

⁽¹⁾ Does not include settlements associated with derivative instruments that settle through physical delivery.

⁽²⁾ Includes only net gains or losses associated with those derivatives that do not receive hedge accounting treatment and does not include the ineffective portion of derivatives that are designated as hedging instruments.

⁽³⁾ Includes settlement gains of $1.2 million and $7.0 million for the three months ended September 30, 2016 and 2015, respectively and settlement gains of $4.9 million and $19.2 million for the nine months ended September 30, 2016 and 2015, respectively.

⁽⁴⁾ Includes settlement gains of $18.7 million and $27.3 million for the three months ended September 30, 2016 and 2015, respectively and settlement gains of $63.3 million and $71.0 million for the nine months ended September 30, 2016 and 2015, respectively.

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.

26

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

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

Offsetting of Financial Assets and Derivative Assets

	As of September 30, 2016
	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			Net Amount
	(in millions)
Description: Derivatives	$	62.6	$	—	$	62.6	$	(29.9	)	$	32.7

	As of December 31, 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	$	163.6	$	—	$	163.6	$	(41.5	)	$	122.1

⁽¹⁾ Includes $12.6 million of cash collateral held at December 31, 2015.

Offsetting of Financial Liabilities and Derivative Liabilities

	As of September 30, 2016
	Gross Amount of Recognized Liabilities			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		Net Amount
	(in millions)
Description: Derivatives	$	(334.1	)	$	—	$	(334.1	)	$	29.9	$	(304.2	)

	As of December 31, 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	$	(221.5	)	$	—	$	(221.5	)	$	41.5	$	(180.0	)

⁽¹⁾ Includes $12.6 million of cash collateral held at December 31, 2015.

Inputs to Fair Value Derivative Instruments

The following table sets forth by level within the fair value hierarchy of our net financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2016 and December 31, 2015. 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.

27

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

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

	September 30, 2016										December 31, 2015
	Level 1		Level 2			Level 3		Total			Level 1		Level 2			Level 3		Total
	(in millions)
Interest rate contracts	$	—	$	(289.3	)	$	—	$	(289.3	)	$	—	$	(157.5	)	$	—	$	(157.5	)
Commodity contracts:
Financial		—		(0.7	)		0.1		(0.6	)		—		8.4			8.9		17.3
Physical		—		—			1.3		1.3			—		—			0.6		0.6
Commodity options		—		—			17.1		17.1			—		—			94.3		94.3
	$	—		(290.0	)	$	18.5	$	(271.5	)	$	—	$	(149.1	)	$	103.8	$	(45.3	)
Cash collateral									—										(12.6	)
Total								$	(271.5	)								$	(57.9	)

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 measure the fair value of our Level 3 derivative instruments 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 and power) are forward commodity prices. The significant unobservable inputs used in determining the fair value measurement of options are price and volatility. Forward commodity price in isolation has a direct relationship to the fair value of a commodity contract in a long position and an inverse relationship to a commodity contract in a short position. Volatility has a direct relationship to the fair value of an option contract. 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 has an inverse relationship to the fair value of our derivative contracts.

28

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, 2016(2)			Valuation Technique		Unobservable Input		Range(1)
Contract Type								Lowest			Highest			Weighted Average			Units
	(in millions)
Commodity Contracts – Financial
Natural Gas	$	1.3			Market Approach		Forward Gas Price		2.65			3.59			3.08			MMBtu
NGLs		(1.2	)		Market Approach		Forward NGL Price		0.22			1.12			0.51			Gal
Commodity Contracts – Physical
Natural Gas		0.1			Market Approach		Forward Gas Price		2.66			3.58			2.92			MMBtu
Crude Oil		(1.4	)		Market Approach		Forward Crude Price		38.45			49.58			46.32			Bbl
NGLs		2.6			Market Approach		Forward NGL Price		0.22			1.48			0.57			Gal
Commodity Options
Natural Gas, Crude and NGLs		17.1			Option Model		Option Volatility		27	%		97	%		45	%
Total Fair Value	$	18.5

⁽¹⁾ Prices are in dollars per Millions of British Thermal Units, or MMBtu, for natural gas; dollars per gallon, or Gal, for NGLs; and dollars per barrel, or Bbl, for crude oil.

⁽²⁾ Fair values include credit valuation adjustment losses of approximately $0.1 million.

Quantitative Information about Level 3 Fair Value Measurements

	Fair Value at December 31, 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 Natural Gas Price		2.27			3.07			2.64			MMBtu
NGLs		8.6			Market Approach		Forward NGL Price		0.16			0.93			0.41			Gal
Commodity Contracts – Physical
Natural Gas		(2.5	)		Market Approach		Forward Natural Gas Price		2.08			3.44			2.33			MMBtu
Crude Oil		—			Market Approach		Forward Crude Oil Price		26.50			38.41			37.29			Bbl
NGLs		3.1			Market Approach		Forward NGL Price		0.16			1.20			0.40			Gal
Commodity Options
Natural Gas, Crude Oil and NGLs		94.3			Option Model		Option Volatility		13	%		74	%		36	%
Total Fair Value	$	103.8

⁽¹⁾ Prices are in dollars per MMBtu for natural gas, Gal for NGLs and Bbl for crude oil.

⁽²⁾ Fair values include credit valuation adjustment losses of approximately $0.3 million.

29

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

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

Level 3 Fair Value Reconciliation

The table below provides a reconciliation of changes in the fair value of our Level 3 financial assets and liabilities measured on a recurring basis from January 1, 2016 to September 30, 2016. No transfers of assets between any of the Levels occurred during the period.

	Commodity Financial Contracts			Commodity Physical Contracts			Commodity Options			Total
	(in millions)
Beginning balance as of January 1, 2016	$	8.9		$	0.6		$	94.3		$	103.8
Transfer in (out) of Level 3(1)		—			—			—			—
Gains or losses included in earnings:
Reported in Commodity sales		—			(15.5	)		—			(15.5	)
Reported in Commodity costs		(0.5	)		21.1			(21.9	)		(1.3	)
Gains or losses included in other comprehensive income:
Purchases, issuances, sales and settlements:
Purchases		—			—			—			—
Sales		—			—			0.7			0.7
Settlements(2)		(8.3	)		(4.9	)		(56.0	)		(69.2	)
Ending balance as September 30, 2016	$	0.1		$	1.3		$	17.1		$	18.5
Amounts reported in Commodity sales	$	—		$	(1.8	)	$	—		$	(1.8	)
Amount of changes in net assets attributable to the change in derivative gains or losses related to assets and liabilities still held at the reporting date:
Reported in Commodity sales	$	—		$	(3.5	)	$	—		$	(3.5	)
Reported in Commodity costs	$	(0.9	)	$	4.6		$	(15.9	)	$	(12.2	)

⁽¹⁾ Our policy is to recognize transfers as of the last day of the reporting period.

⁽²⁾ Settlements represent the realized portion of forward contracts.

30

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

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

Fair Value Measurements of Commodity Derivatives

The following table provides summarized information about the fair values of expected cash flows of our outstanding commodity based swaps and physical contracts at September 30, 2016 and December 31, 2015.

	At September 30, 2016													At December 31, 2015
					Wtd. Average Price(2)				Fair Value(3)					Fair Value(3)
	Commodity		Notional(1)		Receive		Pay		Asset		Liability			Asset		Liability
									(in millions)
Portion of contracts maturing in 2016
Swaps
Receive variable/pay fixed		Natural Gas		16,287	$	2.86	$	3.48	$	—	$	—		$	—	$	—
		NGL		2,694,200	$	26.38	$	24.49	$	5.7	$	(0.6	)	$	0.2	$	(8.4	)
		Crude Oil		169,400	$	48.75	$	62.50	$	0.5	$	(2.8	)	$	—	$	(17.5	)
Receive fixed/pay variable		NGL		5,040,200	$	23.97	$	24.96	$	3.2	$	(8.2	)	$	18.3	$	(0.2	)
		Crude Oil		391,836	$	57.18	$	48.78	$	4.2	$	(0.9	)	$	25.4	$	—
Receive variable/pay variable		Natural Gas		5,708,000	$	3.05	$	3.01	$	0.3	$	(0.1	)	$	0.1	$	(0.1	)
Physical Contracts
Receive variable/pay fixed		NGL		1,127,893	$	25.14	$	23.43	$	2.0	$	(0.1	)	$	—	$	(0.2	)
		Crude Oil		—	$	—	$	—	$	—	$	—		$	—	$	(0.2	)
Receive fixed/pay variable		NGL		1,359,447	$	21.30	$	23.31	$	0.8	$	(3.6	)	$	1.9	$	(0.2	)
Receive variable/pay variable		Natural Gas		19,810,834	$	2.83	$	2.84	$	0.1	$	(0.3	)	$	—	$	(2.8	)
		NGL		3,794,987	$	23.37	$	23.07	$	1.7	$	(0.5	)	$	4.0	$	(2.4	)
		Crude Oil		383,298	$	44.16	$	47.84	$	0.3	$	(1.8	)	$	0.7	$	(0.5	)
Portion of contracts maturing in 2017
Swaps
Receive variable/pay fixed		Natural Gas		989,030	$	2.89	$	2.91	$	—	$	—		$	—	$	—
		NGL		2,417,500	$	22.03	$	21.62	$	2.7	$	(1.7	)	$	—	$	(4.5	)
		Crude Oil		638,750	$	51.66	$	64.29	$	0.2	$	(8.2	)	$	—	$	(10.9	)
Receive fixed/pay variable		NGL		3,090,000	$	22.70	$	23.70	$	1.2	$	(4.3	)	$	3.3	$	(0.1	)
		Crude Oil		866,510	$	59.89	$	51.66	$	8.2	$	(1.1	)	$	10.9	$	—
Receive variable/pay variable		Natural Gas		12,550,000	$	3.12	$	3.03	$	1.1	$	(0.1	)	$	0.5	$	(0.2	)
Physical Contracts
Receive variable/pay fixed		NGL		45,000	$	23.42	$	21.96	$	0.1	$	—		$	—	$	—
Receive fixed/pay variable		NGL		45,781	$	25.46	$	25.39	$	0.1	$	(0.1	)	$	—	$	—
Receive variable/pay variable		Natural Gas		11,843,834	$	3.08	$	3.06	$	0.2	$	—		$	0.1	$	—
		NGL		1,262,231	$	26.68	$	25.59	$	1.4	$	—		$	—	$	—
Portion of contracts maturing in 2018
Physical Contracts
Receive variable/pay variable		Natural Gas		2,193,804	$	2.93	$	2.90	$	0.1	$	—		$	0.1	$	—
		NGL		456,250	$	23.15	$	21.26	$	0.8	$	—		$	—	$	—
Portion of contracts maturing in 2019
Physical Contracts
Receive variable/pay variable		Natural Gas		2,199,798	$	2.86	$	2.83	$	0.1	$	—		$	0.1	$	—
Portion of contracts maturing in 2020
Physical Contracts
Receive variable/pay variable		Natural Gas		365,634	$	3.11	$	3.08	$	—	$	—		$	—	$	—

⁽¹⁾ Volumes of natural gas are measured in MMBtu, whereas volumes of NGLs and crude oil are measured in Bbl.

⁽²⁾ Weighted-average prices received and paid are in $/MMBtu for natural gas and $/Bbl for NGLs and crude oil.

⁽³⁾ The fair value is determined based on quoted market prices at September 30, 2016 and December 31, 2015, respectively, discounted using the swap rate for the respective periods to consider the time value of money. Fair values exclude credit valuation adjustment gains of approximately $0.1 million and $0.5 million at September 30, 2016 and December 31, 2015, respectively, as well as cash collateral received.

31

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

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

The following table provides summarized information about the fair values of expected cash flows of our outstanding commodity options at September 30, 2016 and December 31, 2015.

	At September 30, 2016													At December 31, 2015
	Commodity		Notional(1)		Strike Price(2)		Market Price(2)		Fair Value(3)					Fair Value(3)
									Asset		Liability			Asset		Liability
									(in millions)
Portion of option contracts maturing in 2016
Puts (purchased)		Natural Gas		414,000	$	3.75	$	3.00	$	0.3	$	—		$	2.1	$	—
		NGL		745,200	$	39.29	$	27.70	$	9.2	$	—		$	54.4	$	—
		Crude Oil		202,400	$	75.91	$	49.00	$	5.4	$	—		$	27.7	$	—
Calls (written)		Natural Gas		414,000	$	4.98	$	3.00	$	—	$	—		$	—	$	—
		NGL		745,200	$	45.09	$	27.70	$	—	$	(0.3	)	$	—	$	(0.3	)
		Crude Oil		202,400	$	86.68	$	49.00	$	—	$	—		$	—	$	—
Puts (written)		Natural Gas		414,000	$	3.75	$	3.00	$	—	$	(0.3	)	$	—	$	(2.1	)
		NGL		59,800	$	37.04	$	28.98	$	—	$	(0.6	)	$	—	$	(1.5	)
Calls (purchased)		Natural Gas		414,000	$	4.98	$	3.00	$	—	$	—		$	—	$	—
		NGL		59,800	$	42.09	$	28.98	$	—	$	—		$	—	$	—
Portion of option contracts maturing in 2017
Puts (purchased)		NGL		1,642,500	$	25.90	$	29.51	$	5.5	$	—		$	5.8	$	—
		Crude Oil		638,750	$	59.86	$	51.66	$	7.6	$	—		$	10.0	$	—
Calls (written)		NGL		1,642,500	$	30.06	$	29.51	$	—	$	(8.0	)	$	—	$	(0.8	)
		Crude Oil		638,750	$	68.19	$	51.66	$	—	$	(1.2	)	$	—	$	(0.6	)
Portion of option contracts maturing in 2018
Puts (purchased)		Crude Oil		91,250	$	42.00	$	53.58	$	0.3	$	—		$	—	$	—
Calls (written)		Crude Oil		91,250	$	51.75	$	53.58	$	—	$	(0.8	)	$	—	$	—

⁽¹⁾ Volumes of natural gas are measured in MMBtu, whereas volumes of NGLs and crude oil are measured in Bbl.

⁽²⁾ Strike and market prices are in $/MMBtu for natural gas and in $/Bbl for NGLs and crude oil.

⁽³⁾ The fair value is determined based on quoted market prices at September 30, 2016 and December 31, 2015, respectively, discounted using the swap rate for the respective periods to consider the time value of money. Fair values exclude credit valuation adjustment losses of approximately $0.4 million at December 31, 2015 as well as cash collateral received.

32

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

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

Fair Value Measurements of Interest Rate Derivatives

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

	Accounting Treatment		Notional		Average Fixed Rate(1)			Fair Value(2) at
Date of Maturity & Contract Type								September 30, 2016			December 31, 2015
			(dollars in millions)
Contracts maturing in 2017
Interest Rate Swaps – Pay Fixed		Cash Flow Hedge	$	500		2.21	%	$	(2.0	)	$	(7.0	)
Contracts maturing in 2018
Interest Rate Swaps – Pay Fixed		Cash Flow Hedge	$	810		2.24	%	$	(11.2	)	$	(6.6	)
Contracts maturing in 2019
Interest Rate Swaps – Pay Fixed		Cash Flow Hedge	$	620		2.96	%	$	(11.1	)	$	(6.0	)
Contracts settling prior to maturity
2016 – Pre-issuance Hedges		Cash Flow Hedge	$	500		4.21	%	$	(127.0	)	$	(80.4	)
2017 – Pre-issuance Hedges		Cash Flow Hedge	$	500		3.69	%	$	(96.8	)	$	(49.2	)
2018 – Pre-issuance Hedges		Cash Flow Hedge	$	350		3.08	%	$	(44.3	)	$	(12.2	)

⁽¹⁾ Interest rate derivative contracts are based on the one-month or three-month London Interbank Offered Rate, or LIBOR.

⁽²⁾ The fair value is determined from quoted market prices at September 30, 2016 and December 31, 2015, respectively, discounted using the swap rate for the respective periods to consider the time value of money. Fair values exclude credit valuation adjustment gains of approximately $3.1 million and $3.9 million at September 30, 2016 and December 31, 2015, respectively.

13. INCOME TAXES

We are not a taxable entity for United States federal income tax purposes or for the majority of states that impose an income tax. Taxes on our net income generally are borne by our unitholders through the allocation of taxable income. Our income tax expense results from the enactment of franchise tax laws by the State of Texas that apply to entities organized as partnerships, and which is based upon many but not all items included in net income.

We compute our income tax expense by applying a Texas state franchise tax rate to modified gross margin. Our Texas state franchise tax rate was 0.4% for the nine months ended September 30, 2016 and 2015.

At September 30, 2016 and December 31, 2015, we included a current income tax payable of $1.8 million and $1.1 million, respectively, in “Property and other taxes payable” on our consolidated statements of financial position. In addition, at September 30, 2016 and December 31, 2015, we included a deferred income tax payable of $22.5 million and $20.9 million, respectively, in “Other long-term liabilities,” on our consolidated statements of financial position to reflect the tax associated with the difference between the net basis in assets and liabilities for financial and state tax reporting.

14. SEGMENT INFORMATION

Our business is divided into operating segments, defined as components of the enterprise, about which financial information is available and evaluated regularly by our Chief Operating Decision Maker, collectively comprised of our senior management, in deciding how resources are allocated and performance is assessed.

Each of our reportable segments is a business unit that offers different services and products that are managed separately, because each business segment requires different operating strategies. We have segregated our business activities into two distinct operating segments:

• Liquids; and

• Natural Gas.

33

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

14. SEGMENT INFORMATION  – (continued)

The following tables present certain financial information relating to our business segments and corporate activities:

	For the three months ended September 30, 2016
	Liquids			Natural Gas			Corporate(1)			Total
	(in millions)
Operating revenues:(2)
Commodity sales	$	—		$	442.0		$	—		$	442.0
Transportation and other services		634.6			44.0			—			678.6
		634.6			486.0			—			1,120.6
Operating expenses:
Commodity costs		—			404.0			—			404.0
Environmental costs, net of recoveries		(8.7	)		—			—			(8.7	)
Operating and administrative		149.7			71.7			3.2			224.6
Power		74.3			—			—			74.3
Asset impairment		756.7			—			—			756.7
Depreciation and amortization		109.4			39.2			—			148.6
		1,081.4			514.9			3.2			1,599.5
Operating loss		(446.8	)		(28.9	)		(3.2	)		(478.9	)
Interest expense, net		—			—			(112.3	)		(112.3	)
Allowance for equity used during construction		—			—			10.1			10.1
Other income		—			8.3	(3)		0.4			8.7
Loss before income tax expense		(446.8	)		(20.6	)		(105.0	)		(572.4	)
Income tax expense		—			—			(2.2	)		(2.2	)
Net loss		(446.8	)		(20.6	)		(107.2	)		(574.6	)
Less: Net income (loss) attributable to:
Noncontrolling interest		—			—			(191.9	)		(191.9	)
Series 1 preferred unit distributions		—			—			22.5			22.5
Accretion of discount on Series 1 preferred units		—			—			1.2			1.2
Net income (loss) attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P.	$	(446.8	)	$	(20.6	)	$	61.0		$	(406.4	)

⁽¹⁾ Corporate consists of interest expense, allowance for equity used during construction, noncontrolling interest and other costs such as income taxes, which are not allocated to the business segments.

⁽²⁾ There were no intersegment revenues for the three months ended September 30, 2016.

⁽³⁾ Other income for our Natural Gas segment includes our equity investment in the Texas Express NGL system.

34

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

14. SEGMENT INFORMATION  – (continued)

	For the three months ended September 30, 2015
	Liquids		Natural Gas			Corporate(1)			Total
	(in millions)
Operating revenues:(2)
Commodity sales	$	—	$	609.9		$	—		$	609.9
Transportation and other services		606.7		51.1			—			657.8
		606.7		661.0			—			1,267.7
Operating expenses:
Commodity costs		—		522.7			—			522.7
Environmental costs, net of recoveries		1.1		—			—			1.1
Operating and administrative		183.2		94.1			3.3			280.6
Power		71.6		—			—			71.6
Depreciation and amortization		97.7		39.2			—			136.9
		353.6		656.0			3.3			1,012.9
Operating income (loss)		253.1		5.0			(3.3	)		254.8
Interest expense, net		—		—			(88.2	)		(88.2	)
Allowance for equity used during construction		—		—			13.7			13.7
Other income (loss)		—		8.9	(3)		(0.1	)		8.8
Income (loss) before income tax expense		253.1		13.9			(77.9	)		189.1
Income tax expense		—		—			(4.6	)		(4.6	)
Net income (loss)		253.1		13.9			(82.5	)		184.5
Less: Net income attributable to:
Noncontrolling interest		—		—			77.8			77.8
Series 1 preferred unit distributions		—		—			22.5			22.5
Accretion of discount on Series 1 preferred units		—		—			2.1			2.1
Net income (loss) attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P.	$	253.1	$	13.9		$	(184.9	)	$	82.1

⁽¹⁾ Corporate consists of interest expense, allowance for equity used during construction, noncontrolling interest and other costs such as income taxes, which are not allocated to the business segments.

⁽²⁾ There were no intersegment revenues for the three months ended September 30, 2015.

⁽³⁾ Other income for our Natural Gas segment includes our equity investment in the Texas Express NGL system.

35

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

14. SEGMENT INFORMATION  – (continued)

	As of and for the nine months ended September 30, 2016
	Liquids		Natural Gas			Corporate(1)			Total
	(in millions)
Operating revenues:(2)
Commodity sales	$	—	$	1,205.8		$	—		$	1,205.8
Transportation and other services		1,885.6		139.7			—			2,025.3
		1,885.6		1,345.5			—			3,231.1
Operating expenses:
Commodity costs		—		1,111.1			—			1,111.1
Environmental costs, net of recoveries		8.3		—			—			8.3
Operating and administrative		418.6		224.0			9.4			652.0
Power		206.8		—			—			206.8
Asset impairment		757.1		10.6			—			767.7
Depreciation and amortization		315.7		118.7			—			434.4
		1,706.5		1,464.4			9.4			3,180.3
Operating income (loss)		179.1		(118.9	)		(9.4	)		50.8
Interest expense, net		—		—			(326.7	)		(326.7	)
Allowance for equity used during construction		—		—			35.7			35.7
Other income		—		22.0	(3)		0.9			22.9
Income (loss) before income tax expense		179.1		(96.9	)		(299.5	)		(217.3	)
Income tax expense		—		—			(7.2	)		(7.2	)
Net income (loss)		179.1		(96.9	)		(306.7	)		(224.5	)
Less: Net income (loss) attributable to:
Noncontrolling interest		—		—			(52.8	)		(52.8	)
Series 1 preferred unit distributions		—		—			67.5			67.5
Accretion of discount on Series 1 preferred units		—		—			3.5			3.5
Net income (loss) attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P.	$	179.1	$	(96.9	)	$	(324.9	)	$	(242.7	)
Total assets	$	13,104.9	$	4,931.5	(4)	$	63.6		$	18,100.0
Capital expenditures (excluding acquisitions)	$	655.4	$	40.1		$	1.1		$	696.6

⁽¹⁾ Corporate consists of interest expense, allowance for equity used during construction, noncontrolling interest and other costs such as income taxes, which are not allocated to the business segments.

⁽²⁾ There were no intersegment revenues for the nine months ended September 30, 2016.

⁽³⁾ Other income for our Natural Gas segment includes our equity investment in the Texas Express NGL system.

⁽⁴⁾ Total assets for our Natural Gas segment includes $359.6 million for our equity investment in the Texas Express NGL system.

36

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

14. SEGMENT INFORMATION  – (continued)

	As of and for the nine months ended September 30, 2015
	Liquids		Natural Gas			Corporate(1)			Total
	(in millions)
Operating revenues:(2)
Commodity sales	$	—	$	2,163.7		$	—		$	2,163.7
Transportation and other services		1,694.8		150.9			—			1,845.7
		1,694.8		2,314.6			—			4,009.4
Operating expenses:
Commodity costs		—		1,972.4			—			1,972.4
Environmental costs, net of recoveries		1.1		—			—			1.1
Operating and administrative		429.9		264.1			10.9			704.9
Power		192.4		—			—			192.4
Goodwill impairment		—		246.7			—			246.7
Asset impairment		—		12.3			—			12.3
Depreciation and amortization		276.5		118.3			—			394.8
		899.9		2,613.8			10.9			3,524.6
Operating income (loss)		794.9		(299.2	)		(10.9	)		484.8
Interest expense, net		—		—			(214.5	)		(214.5	)
Allowance for equity used during construction		—		—			54.0			54.0
Other income		—		20.5	(3)		0.2			20.7
Income (loss) before income tax expense		794.9		(278.7	)		(171.2	)		345.0
Income tax expense		—		—			(3.2	)		(3.2	)
Net income (loss)		794.9		(278.7	)		(174.4	)		341.8
Less: Net income attributable to:
Noncontrolling interest		—		—			139.1			139.1
Series 1 preferred unit distributions		—		—			67.5			67.5
Accretion of discount on Series 1 preferred units		—		—			10.1			10.1
Net income (loss) attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P.	$	794.9	$	(278.7	)	$	(391.1	)	$	125.1
Total assets	$	13,059.0	$	5,177.5	(4)	$	152.1		$	18,388.6
Capital expenditures (excluding acquisitions)	$	1,485.4	$	143.8		$	3.5		$	1,632.7

⁽¹⁾ Corporate consists of interest expense, allowance for equity used during construction, noncontrolling interest and other costs such as income taxes, which are not allocated to the business segments.

⁽²⁾ There were no intersegment revenues for the nine months ended September 30, 2015.

⁽³⁾ Other income for our Natural Gas segment includes our equity investment in the Texas Express NGL system.

⁽⁴⁾ Total assets for our Natural Gas segment includes $373.7 million for our equity investment in the Texas Express NGL system.

37

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

15. SUPPLEMENTAL CASH FLOWS INFORMATION

In the “Cash used in investing activities” section of the consolidated statements of cash flows, we exclude changes that did not affect cash. The following is a reconciliation of cash used for additions to property, plant and equipment to total capital expenditures (excluding “Investment in joint venture”):

	For the nine months ended September 30,
	2016		2015
	(in millions)
Total capital expenditures (excluding “Investment in joint venture”)	$	696.6	$	1,632.7
(Increase) decrease in construction payables		194.5		(76.5	)
Cash used for additions to property, plant and equipment	$	891.1	$	1,556.2

16. REGULATORY MATTERS

Regulatory Accounting

Due to over or under recovery adjustments made in accordance with the Federal Energy Regulatory Commission, or FERC, authoritative guidance and our cost-of-service recovery model, we recognize assets and liabilities for regulatory purposes. The assets and liabilities that we recognize for regulatory purposes are recorded on a net basis in “Other current assets” or “Accounts payable and other,” respectively, on our consolidated statements of financial position. These regulatory assets and liabilities are amortized on a straight-line basis over a one-year recovery period. Our over and under recovery revenue adjustments and net regulatory asset amortization for the three and nine months ended September 30, 2016 and 2015 are as follows:

	For the three months ended September 30,						For the nine months ended September 30,
	2016			2015			2016			2015
	(in millions)
Net regulatory asset balance at beginning of period	$	29.3		$	2.0		$	29.9		$	6.0
Current period under recovery revenue adjustments		6.4			24.0			20.0			24.5
Amortization of prior year regulatory asset		(7.9	)		(0.8	)		(22.1	)		(5.3	)
Net regulatory asset balance at end of period	$	27.8		$	25.2		$	27.8		$	25.2

Other Contractual Obligations

Qualifying Volumes

We have certain contractual obligations with our customers in which a portion of the revenue earned on volumes above certain predetermined shipment levels, or qualifying volumes, are returned to the shippers through future rate adjustments. At September 30, 2016 and December 31, 2015 we had no qualifying volume liabilities related to the original Southern Access and Alberta Clipper agreements on our consolidated statements of financial position.

We amortize the liability on a straight-line basis as an adjustment to revenue in the following year, reflecting the related rate adjustment. There was no amortization for qualifying volume liabilities for the three and nine months ended September 30, 2016 and 2015.

Alberta Clipper Pipeline Property Taxes

A portion of the rates we charge our customers includes an estimate for annual property taxes. If the estimated property tax we collect from our customers is higher or lower than the actual property tax imposed, we are contractually obligated to refund to our customers or entitled to collect from our customers 50% of the property tax over or under recovery, respectively. At September 30, 2016 and December 31, 2015, we had $0.4 million and $0.8 million, respectively, in property tax under recovery assets related to our Alberta Clipper Pipeline on our consolidated statements of financial position.

During 2015 and 2014, we incurred liabilities related to contractual obligations with our customers on the Alberta Clipper Pipeline related to property taxes. As a result, in 2015 and 2014, we recorded a liability for the

38

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

16. REGULATORY MATTERS  – (continued)

contractual amounts due back to our shippers with the corresponding amount as a reduction to revenue. We amortized the liability on a straight-line basis as an adjustment to revenue in the following year, reflecting the related rate adjustment. For the three and nine months ended September 30, 2016, we amortized through revenue $0.3 million and $0.5 million of property tax under recovery assets, respectively, on our consolidated statements of income with a corresponding amount reducing the contractual obligation on our consolidated statements of financial position. For the three and nine months ended September 30, 2015, we amortized through revenue $1.1 million and $4.0 million of property tax over recovery liabilities, respectively, on our consolidated statements of income with a corresponding amount reducing the contractual obligation on our consolidated statements of financial position.

Allowance for Equity Used During Construction

We are permitted to capitalize and recover costs for rate-making purposes that include an allowance for equity costs during construction, referred to as AEDC. In connection with construction of the Eastern Access Projects, Line 3 Replacement and Mainline Expansion Projects, we recorded $10.1 million and $35.7 million of “Allowance for equity used during construction” on our consolidated statements of income for the three and nine months ended September 30, 2016, respectively, and a corresponding amount of $35.7 million in “Property, plant and equipment, net” on our consolidated statement of financial position at September 30, 2016. We recorded $13.7 million and $54.0 million of “Allowance for equity used during construction” on our consolidated statements of income for the three and nine months ended September 30, 2015, respectively, with a corresponding amount of $54.0 million in “Property, plant and equipment” on our consolidated statement of financial position at September 30, 2015.

17. RECENT ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED

Revenues from Contracts with Customers

Since May 2014, the Financial Accounting Standards Board, or FASB, has issued ASU Nos. 2014-09, 2015-14, 2016-08, 2016-10 and 2016-12 which outline a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific guidance. The accounting updates are effective for annual and interim periods beginning on or after December 15, 2017, and may be applied on either a full or modified retrospective basis. We are currently evaluating our revenue contracts and determining the impacts that the new pronouncement will have on our consolidated financial statements and disclosures. We are also currently evaluating which transition approach we will apply.

Leases

In February 2016, the FASB issued ASU No. 2016-02, which requires lessees to recognize a right-of-use asset and a lease liability on the balance sheet for practically all leases (other than leases that are less than 12 months). The pronouncement continues to require lessees to distinguish between operating and financing, formerly known as capital leases, and lessors to distinguish between sales-type, direct financing, and operating leases for income statement purposes. This accounting update is effective for annual periods, and for interim periods within those annual periods, beginning after December 15, 2018. Early adoption is permitted, and entities are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach with certain optional practical expedients. We are currently evaluating the impact that this pronouncement will have on our consolidated financial statements.

18. SUBSEQUENT EVENTS

Distribution to Partners

On October 28, 2016, the board of directors of Enbridge Management declared a distribution payable to our partners on November 14, 2016. The distribution will be paid to unitholders of record as of November 7, 2016 of our available cash of $263.7 million at September 30, 2016, or $0.5830 per limited partner unit. Of this distribution, $216.1 million will be paid in cash, $46.6 million will be distributed in i-units to our i-unitholder, Enbridge Management, and due to the i-unit distribution, $1.0 million will be retained from our General Partner from amounts otherwise distributable to it in respect of its general partner interest and limited partner interest to maintain its 2% general partner interest.

39

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

18. SUBSEQUENT EVENTS  – (continued)

Distribution to Series EA Interests

On October 28, 2016, 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 a holder of the Series EA interests, declared a distribution payable to the holders of the Series EA general and limited partner interests. The OLP will pay $64.7 million to the noncontrolling interest in the Series EA, while $21.6 million will be paid to us.

Distribution to Series ME Interests

On October 28, 2016, 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 a holder of the Series ME interests, declared a distribution payable to the holders of the Series ME general and limited partner interests. The OLP will pay $44.3 million to the noncontrolling interest in the Series ME, while $14.8 million will be paid to us.

Distribution from MEP

On October 27, 2016, the board of directors of Midcoast Holdings, L.L.C., the general partner of MEP, declared a cash distribution payable to their partners on November 14, 2016. The distribution will be paid to unitholders of record as of November 7, 2016, of MEP’s available cash of $16.5 million at September 30, 2016, or $0.3575 per limited partner unit. MEP will pay $7.6 million to their public Class A common unitholders, while $8.9 million in the aggregate will be paid to us with respect to our Class A common units, our subordinated units, and to Midcoast Holdings, L.L.C. with respect to its general partner interest.

Midcoast Operating Distribution

On October 27, 2016, the general partner of Midcoast Operating declared a cash distribution by Midcoast Operating payable on November 14, 2016 to its partners of record as of November 7, 2016. Midcoast Operating will pay $14.4 million to us and $26.0 million to MEP.

During any quarter until the quarter ending December 31, 2017, if MEP’s quarterly declared distribution exceeds its distributable cash, as that term is defined in Midcoast Operating’s limited partnership agreement, we receive a decreased quarterly distribution from Midcoast Operating, and MEP receives a corresponding increase to its quarterly distribution in the amount that MEP’s declared distribution exceeds its distributable cash. Midcoast Operating’s adjustment of our distribution will be limited by our pro rata share of the Midcoast Operating quarterly cash distribution and a maximum of $0.005 per unit quarterly distribution increase by MEP. There is no requirement for MEP to compensate us for these adjusted distributions, except for settling our capital accounts with Midcoast Operating in a liquidation scenario. For the three and nine months ended September 30, 2016, our quarterly distribution from Midcoast Operating was reduced by $5.1 million and $8.2 million, respectively.

40

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations is based on and should be read in conjunction with our consolidated financial statements and the accompanying notes included in Item 1. Financial Statements of this report and in conjunction with the audited consolidated financial statements and accompanying footnotes in our Annual Report on Form 10-K for the year ended December 31, 2015, as filed with the Securities and Exchange Commission, or the SEC, on February 17, 2016.

RESULTS OF OPERATIONS — OVERVIEW

We provide services to our customers and returns for our unitholders primarily through the following activities:

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

• Gathering, treating, processing and transportation of natural gas and natural gas liquids, or NGLs, through pipelines and related facilities, along with supply, transportation and sales services, including purchasing and selling natural gas and NGLs.

We conduct our business through two business segments: Liquids and Natural Gas. Our Liquids segment includes the operations of our Lakehead, Mid-Continent and North Dakota systems. These systems largely consist of FERC regulated interstate crude oil and liquid petroleum pipelines, gathering systems and storage facilities. The Lakehead system, together with the Enbridge system in Canada, forms the longest liquid petroleum pipeline system in the world. Our Liquids systems generate revenues primarily from charging shippers a rate per barrel to gather, transport and store crude oil and liquid petroleum.

Our Natural Gas segment includes natural gas and NGL gathering and transportation pipeline systems, natural gas processing and treating facilities, condensate stabilizers and an NGL fractionation facility. Moreover, our Natural Gas segment also provides supply, transmission, storage and sales services to producers and wholesale customers on our natural gas gathering, transmission and customer pipelines, as well as other interconnected pipeline systems. Revenues for our Natural Gas segment are determined primarily by the volumes of natural gas gathered, compressed, treated, processed, transported and sold through our systems; the volumes of NGLs sold; and the level of natural gas, NGLs and condensate prices. In addition, we also provide marketing services of natural gas and NGLs to wholesale customers. Segment gross margin is derived from the compensation we receive from customers in the form of fees or commodities we receive for providing services in addition to the proceeds we receive for sales of natural gas, NGLs and condensate to affiliates and third-parties.

The following table reflects our operating income (loss) by business segment and corporate charges for the three and nine months ended September 30, 2016 and 2015.

	For the three months ended September 30,						For the nine months ended September 30,
	2016			2015			2016			2015
	(in millions)
Operating income (loss)
Liquids	$	(446.8	)	$	253.1		$	179.1		$	794.9
Natural Gas		(28.9	)		5.0			(118.9	)		(299.2	)
Corporate, operating and administrative		(3.2	)		(3.3	)		(9.4	)		(10.9	)
Total operating income (loss)		(478.9	)		254.8			50.8			484.8
Interest expense		(112.3	)		(88.2	)		(326.7	)		(214.5	)
Allowance for equity used during construction		10.1			13.7			35.7			54.0
Other income		8.7			8.8			22.9			20.7
Income (loss) before income tax expense		(572.4	)		189.1			(217.3	)		345.0
Income tax expense		(2.2	)		(4.6	)		(7.2	)		(3.2	)
Net income (loss)		(574.6	)		184.5			(224.5	)		341.8
Less: Net income (loss) attributable to:
Noncontrolling interest income (loss)		(191.9	)		77.8			(52.8	)		139.1
Series 1 preferred unit distributions		22.5			22.5			67.5			67.5
Accretion of discount on Series 1 preferred units		1.2			2.1			3.5			10.1
Net income (loss) attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P.	$	(406.4	)	$	82.1		$	(242.7	)	$	125.1

41

Highlights

Liquids

Our Liquids segment operating income decreased $699.9 million and $615.8 million for the three and nine months ended September 30, 2016, respectively, as compared to the same periods in 2015, primarily as a result of an impairment loss of $756.7 million on the Sandpiper Project that was recognized during the three and nine months ended September 30, 2016. The decrease in operating income is partially offset by the additional assets placed in service and an increase in volumes on our systems. In 2015, $1.6 billion of additional assets were placed into service on our Lakehead system, including portions of the Eastern Access, Mainline Expansion projects, and other projects. Average daily volumes delivered on our liquids systems increased 188,000 and 290,000 Bpd, for the three and nine months ended September 30, 2016, respectively, when compared to the same periods in 2015 due to increased capacity from the expansions mentioned above.

Natural Gas

Our Natural Gas segment operating results decreased $33.9 million and operating loss decreased $180.3 million for the three and nine months ended September 30, 2016, respectively, as compared to the same periods in 2015. Operating loss for the three and nine months ended September 30, 2016 increased as a result of the commodity price environment for natural gas, NGLs, condensate and crude oil which continues to impact production volumes. The average daily volumes of our major systems decreased by approximately 296,000 and 291,000 MMBtu/d for the three and nine months ended September 30, 2016, respectively. Further, during the nine months ended September 30, 2015, our Natural Gas segment recognized a $246.7 million goodwill impairment charge. No similar goodwill impairment charge was recognized in the same period of 2016.

Derivative Transactions and Hedging Activities

Contractual arrangements in our Liquids, Natural Gas, and Corporate segments expose us to market risks associated with changes in (1) commodity prices where we receive crude oil, natural gas or NGLs in return for the services we provide or where we purchase natural gas or NGLs and (2) interest rates on our variable rate debt. Our unhedged commodity position is fully exposed to fluctuations in commodity prices, which can be significant during periods of price volatility. 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 commodity prices and interest rates, as well as to reduce variability in our cash flows. Based on our risk management policies, all of our derivative financial instruments are employed in connection with an underlying asset, liability and/or forecasted transaction and are not entered into with the objective of speculating on commodity prices or interest rates. Derivative financial instruments that do not receive hedge accounting under the provisions of authoritative accounting guidance create volatility in our earnings that can be significant. However, these fluctuations in earnings do not affect our cash flow. Cash flow is only affected when we settle the derivative instrument.

We record all derivative instruments in our consolidated financial statements at fair market value pursuant to the requirements of applicable authoritative accounting guidance. We record changes in the fair value of our derivative financial instruments that do not receive hedge accounting in our consolidated statements of income as follows:

• Liquids segment commodity-based derivatives — ”Transportation and other services”

• Natural Gas segment commodity-based derivatives — ”Commodity sales” and “Commodity costs”

• Corporate interest rate derivatives — ”Interest expense”

42

The changes in fair value of our derivatives are also presented as a reconciling item on our consolidated statements of cash flows. The following table presents the net changes in fair value associated with our derivative financial instruments:

	For the three months ended September 30,						For the nine months ended September 30,
	2016			2015			2016			2015
	(in millions)
Liquids segment:
Non-qualified hedges	$	(0.2	)	$	1.1		$	(7.0	)	$	(11.1	)
Natural Gas segment:
Hedge ineffectiveness		—			(0.1	)		—			(4.1	)
Non-qualified hedges		(14.6	)		6.3			(87.5	)		(49.4	)
Commodity derivative fair value net gains (losses)		(14.8	)		7.3			(94.5	)		(64.6	)
Corporate:
Interest rate hedge ineffectiveness		—			(7.8	)		(3.4	)		24.6
Derivative fair value net losses	$	(14.8	)	$	(0.5	)	$	(97.9	)	$	(40.0	)

RESULTS OF OPERATIONS — BY SEGMENT

Liquids

The following tables set forth the operating results and statistics of our Liquids segment assets for the periods presented:

	For the three months ended September 30,					For the nine months ended September 30,
	2016			2015		2016		2015
	(in millions)
Operating Results:
Operating revenue	$	634.6		$	606.7	$	1,885.6	$	1,694.8
Operating expenses:
Environmental costs, net of recoveries		(8.7	)		1.1		8.3		1.1
Operating and administrative		149.7			183.2		418.6		429.9
Power		74.3			71.6		206.8		192.4
Depreciation and amortization		109.4			97.7		315.7		276.5
Asset impairment		756.7			—		757.1		—
Total operating expenses		1,081.4			353.6		1,706.5		899.9
Operating income (loss)	$	(446.8	)	$	253.1	$	179.1	$	794.9
Operating Statistics
Lakehead system:
United States(1)		1,909			1,905		1,957		1,869
Canada(1)		586			433		601		423
Total Lakehead system delivery volumes(1)		2,495			2,338		2,558		2,292
Barrel miles (billions)		178			164		536		471
Average haul (miles)		774			764		765		753
Mid-Continent system delivery volumes(1)		217			216		200		212
North Dakota system:
Trunkline(1)		363			331		382		344
Gathering(1)		—			2		—		2
Total North Dakota system delivery volumes(1)		363			333		382		346
Total Liquids segment delivery volumes(1)		3,075			2,887		3,140		2,850

⁽¹⁾ Average barrels per day in thousands.

43

Three months ended September 30, 2016, compared with the three months ended September 30, 2015

Operating results of our Liquids segment for the three months ended September 30, 2016, decreased $699.9 million, as compared to the same period in 2015, primarily due to a $756.7 million impairment loss on the Sandpiper Project and $5.9 million in related project costs. There were no asset impairments for the three months ended September 30, 2015. For further details, see Future Prospects Updates for Liquids — Recent Developments — Sandpiper Project.

Operating revenues of our Liquids segment increased $27.9 million for the three months ended September 30, 2016, as compared to the same period in 2015. Operating revenue on the Lakehead system increased $33.3 million for the three months ended September 30, 2016, as compared to the same period in 2015, primarily due to an increase of $38.7 million from increased surcharge revenue for projects subject to regulatory accounting. This increase is a result of placing $1.6 billion of additional assets into service on the Lakehead system in 2015. These additional assets placed into service included components of the Eastern Access, Mainline Expansion, and other expansion projects. These amounts were partially offset by a $9.9 million decrease in rates due to greater qualifying volume credits related to Lakehead toll revenues.

The Lakehead system experienced a period over period increase of 157,000 Bpd in average daily delivery volumes, which resulted in a $16.0 million increase in operating revenues period over period. Increased volumes on the Lakehead system were a result of additional system capacity from the aforementioned assets that were placed into service and increased downstream demand from the completion of certain Enbridge Light Oil Market Access Program projects that expanded access to markets in the Midwest and Eastern Canada for growing volumes of light oil production.

Operating revenue on the North Dakota system decreased $8.1 million for the three months ended September 30, 2016, as compared to the same period in 2015, which was primarily due to lower revenues from Berthold rail as a result of expired contracts and the expiration of surcharges resulting in lower rates. Operating revenues on the North Dakota system decreased as certain surcharge rates subject to an annual adjustment were decreased effective April 1, 2016. Offsetting these lower revenues, the North Dakota system experienced an increase of 30,000 Bpd in average daily delivery volumes, which resulted in an increase of $1.8 million in operating revenues. Increased volumes on the North Dakota system were a result of increased downstream demand from the completion of certain Enbridge Light Oil Market Access Program projects and by volumes shifting from other higher cost alternatives such as transportation by rail.

Environmental costs, net of recoveries, decreased $9.8 million for the three months ended September 30, 2016, as compared to the same period in 2015, due to $10.0 million in insurance recoveries associated with the Line 6A crude oil release.

The operating and administrative expenses of our Liquids segment decreased $33.5 million for the three months ended September 30, 2016, as compared to the same period in 2015, primarily due to a decrease of $47.2 million in pipeline integrity costs. The decrease in pipeline integrity costs relates to $51.4 million for the three months ended September 30, 2015 for the hydrostatic test on Line 2B. There were no such costs for the three months ended. The cost decreases were partially offset by $5.9 million in Sandpiper Project related costs, as described above.

The increase in depreciation expense of $11.7 million for the three months ended September 30, 2016, when compared to the same period in 2015, is directly attributable to additional assets placed into service, primarily on the projects discussed above.

Nine months ended September 30, 2016, compared with the nine months ended September 30, 2015

Operating income of our Liquids segment for the nine months ended September 30, 2016, decreased $615.8 million, as compared to the same period in 2015, primarily as a result of the $756.7 million impairment charge for the Sandpiper project as discussed above.

Operating revenues of our Liquids segment increased $190.8 million for the nine months ended September 30, 2016, as compared to the same period in 2015. Operating revenue on the Lakehead system increased $207.9 million for the nine months ended September 30, 2016, as compared to the same period in 2015 primarily due to an increase of $171.4 million from increased surcharge revenue on projects subject to regulatory accounting, as described above. These amounts were partially offset by a $59.2 million decrease in rates due to greater qualifying volume credits related to Lakehead toll revenues.

44

The Lakehead system experienced a period over period increase of 266,000 Bpd in average daily delivery volumes, which resulted in a $77.7 million increase in operating revenues period over period. Increased volumes on the Lakehead system were a result of additional system capacity from the assets that were placed into service, as mentioned above, and increased downstream demand from the completion of certain Enbridge Light Oil Market Access Program projects that expanded access to markets in the Midwest and Eastern Canada for growing volumes of light oil production. In addition, operating revenue on the Lakehead system increased $12.8 million for the nine months ended September 30, 2016, due to higher average rates, as compared to the same period in 2015.

The increase in operating income on the Lakehead system was offset by an approximate $21 million decrease due to the impact of extreme wildfires in northeastern Alberta during the nine months ended September 30, 2016, as compared to the same period in 2015. The impact of the wildfires during the first week of May 2016 in northeastern Alberta hindered throughput in the second quarter of 2016 as certain upstream facilities were temporarily shut down resulting in disruption of service on the Lakehead System. The reduced system deliveries decreased operating revenue by approximately $30 million and power costs by approximately $9 million for the nine months ended September 30, 2016. Oil sands production substantially came back online by the end of June 2016. As a result, throughput on the Lakehead system has strengthened, and overall system utilization is expected to remain strong through the end of the year.

Operating revenue on the North Dakota system decreased $21.6 million for the nine months ended September 30, 2016, as compared to the same period in 2015, primarily due to lower average rates and lower rail revenues. North Dakota system operating revenues decreased $12.3 million due to lower average rates as discussed above. In addition, operating revenues on the Berthold rail facility decreased $18.7 million. Offsetting these decreases were increases in operating revenues of $7.7 million from an increase of 36,000 Bpd in average daily delivery volumes. Increased volumes on the North Dakota system were also a result of increased downstream demand from the completion of certain Enbridge Light Oil Market Access Program projects and by volumes shifting from other higher cost alternatives such as transportation by rail.

Environmental costs, net of recoveries, increased $7.2 million for the nine months ended September 30, 2016, when compared with the same period in 2015. This increase is primarily related to a $15.0 million increased cost accrual for estimated fines and penalties associated with the Line 6B crude oil release, partially offset by $10.0 million in insurance recoveries associated with the Line 6A crude oil release.

The decrease of $11.3 million in operating and administrative expenses period over period was primarily due to a decrease of $45.1 million in pipeline integrity costs. The decrease in pipeline integrity costs relates to $53.3 million for the nine months ended September 30, 2015 for the hydrostatic test on Line 2B. There were no such costs for the nine months ended September 30, 2016. This decrease was offset by an increase of $25.1 million of property taxes. This cost increase primarily resulted from the additional assets placed into service as discussed above. The decrease was also partially offset by $5.9 million in Sandpiper Project related costs as described above.

Power costs increased $14.4 million for the nine months ended September 30, 2016, when compared to the same period in 2015, primarily as a result of an increase in volumes on our systems.

The increase in depreciation expense of $39.2 million for the nine months ended September 30, 2016, when compared to the same period in 2015, is directly attributable to additional assets placed into service.

Future Prospects Update for Liquids

We currently have a multi-billion dollar growth program underway, with projects coming into service in early 2019, in addition to options to increase our economic interest in projects that are jointly funded by Enbridge and us. Furthermore, our ultimate parent, Enbridge, recently announced a merger with Spectra Energy Corp. Enbridge has indicated that as part of the integration of the two companies, its U.S. sponsored vehicles, including us, will be reviewed in context of the combined enterprise. In addition, under the merger agreement, Enbridge has agreed that it and its subsidiaries, including us, will conduct their businesses in the ordinary course prior to completing the merger transaction, subject to certain specified exceptions or the consent of Spectra Energy Corp. Thus, while we continue to progress our evaluation of opportunities to strengthen our business, the long-term strategic path and execution of any such strategy, for us and our subsidiaries may be impacted by Enbridge’s enterprise-wide post-merger evaluation.

45

Recent Developments

  Bakken Pipeline System

On August 2, 2016, we announced that we had entered into an agreement with MPC to form a new joint venture, which in turn has entered into an agreement to acquire from an affiliate of Energy Transfer Partners, L.P. and Sunoco Logistics Partners L.P., a 49% equity interest in the holding company that owns 75% of the Bakken Pipeline System. Under this arrangement, we and MPC would indirectly hold 75% and 25%, respectively, of the joint venture’s 49% interest in the holding company of Bakken Pipeline. The purchase price of our effective 27.6% interest in the Bakken Pipeline is $1.5 billion. In September 2016, we announced that we have negotiated a tentative joint funding arrangement with our General Partner, whereby 75% of the $1.5 billion investment is expected to be funded by the General Partner. The remaining 25% of the investment is expected to be funded by the issuance of a new class of limited partner units to the General Partner. Closing of the transaction is subject to a number of customary conditions, not all of which have been met at this time.

The Bakken Pipeline System, which consists of the Dakota Access Pipeline, or DAPL, and the Energy Transfer Crude Oil Pipeline, or ETCO, projects, will transport crude oil from the Bakken formation in North Dakota to markets in eastern PADD II and the U.S. Gulf Coast. DAPL consists of 1,172 miles of 30-inch pipeline from the Bakken/Three Forks production area in North Dakota to Patoka, Illinois. It is expected to initially deliver in excess of 470,000 Bpd of crude oil and has the potential to be expanded to 570,000 Bpd. ETCO consists of 62 miles of new 30-inch diameter pipe, 686 miles of converted 30-inch diameter pipe, and 40 miles of converted 24-inch diameter pipe from Patoka, Illinois to Nederland, Texas.

  Sandpiper Project

On September 1, 2016, we announced that we applied for the withdrawal of regulatory applications for the Sandpiper Project pending with the MNPUC because we concluded that the project should be delayed until such time as crude oil production in North Dakota recovers sufficiently to support development of new pipeline capacity. Based on updated projections, we expect that this pipeline capacity will not likely be needed until beyond our current five-year planning horizon. On October 28, 2016 the MNPUC approved our application to withdraw the regulatory applications without conditions.

In connection with the above announcement and other factors, we evaluated the Sandpiper Project for impairment and determined that the project was impaired. In the third quarter of 2016, we recorded an asset impairment of $762.6 million, including related project costs. Of the total amount, $269.6 million was attributable to noncontrolling interest with respect to MPC’s ownership interests, and $493.0 million was attributable to our general and limited partner ownership interests. For further details, see Item 1. Financial Statements, Note 6. Property, Plant and Equipment.

The Sandpiper Project would have expanded and extended the North Dakota feeder system by 225,000 Bpd to a total of 580,000 Bpd. The proposed expansion involved construction of an approximate 600-mile pipeline from Beaver Lodge Station near Tioga, North Dakota to the Superior, Wisconsin mainline system terminal. The new line would have twinned the existing 210,000 Bpd North Dakota system mainline, which now terminates at Clearbrook Terminal in Minnesota, adding 250,000 Bpd of capacity on the twin line between Tioga and Berthold, North Dakota and 225,000 Bpd of capacity on the twin line between Berthold and Clearbrook both with new 24-inch diameter pipelines, in addition to adding 375,000 Bpd between Clearbrook and Superior with a 30-inch diameter pipeline.

Impact of Commodity Price Declines

Volatility in commodity prices can impact production volumes in the oil sands region of Western Canada and the Bakken region of North Dakota, our two primary crude oil supply basins.

The relatively high costs and large up-front capital investments required by oil sands projects involve significant assumptions around short-term and long-term crude oil fundamentals, including world supply and demand, North American supply and demand, and price outlook, among many other factors. As oil sands production is long-term in nature, the long-term outlook is significant to a producer’s investment decision. In the near-term, the current pricing environment is not expected to impact projected growth from the oil sands region.

We expect that the current crude oil price downturn may result in deferral of some oil sands projects, particularly if the current pricing environment continues throughout 2016 and into 2017. However, we expect that projects already under construction will be finished and enter production. In addition, current production volumes from the oil sands are unlikely to decrease absent an operational upset at any of the oil sands operations.

46

Accordingly, we do not anticipate significant changes in our short-term crude oil volume outlook. Our long-term growth in volumes and additional infrastructure expansion will depend on long-term fundamentals. During this period of uncertainty, we believe our pipeline systems are positioned to capture incremental pipeline capacity needs with lower cost, smaller scale expansions of our large Lakehead, North Dakota and Mid-Continent pipeline systems.

Tight sands oil production in any basin in North America will be comparatively more sensitive to the short-term changes in commodity prices due to the production profile associated with tight sands oil wells. Accordingly, we expect a reduction in the growth rate for North American tight sands and shale oil. We believe that rail will be the source of transportation most directly impacted by any declines in production due to its comparatively higher cost relative to pipeline transportation.

Financial impacts to our pipeline systems, in the event the rate of growth were to slow or volumes were to decline, is muted by our cost-of-service agreements, toll structures and demand to transport crude oil from existing production. We do not believe that the decline in crude oil prices will impact our liquids segment meaningfully in the short-term. However, a long-term decline in crude oil prices could have a more significant impact on future production and our rate of growth.

Expansion Projects

The table and discussion below summarize our commercially secured projects for the Liquids segment, which have been recently placed into service or will be placed into service in future periods:

Projects	Total Estimated Capital Costs		Expected In-Service Date		Funding
	(in millions)
Line 3 Replacement Program(1)	$	2,600		Early 2019		EEP(2)
Eastern Access Projects:
Line 6B Expansion		320		Complete		Joint(3)
U.S. Mainline Expansions:
Line 61 (Additional tankage)		380		Complete		Joint(4)
Line 61 (1,200,000 Bpd capacity)(5)		435		Early 2019		Joint	(4)

⁽¹⁾ As discussed under Line 3 Replacement Program below, the expected cost and in-service date of this project are under review by us in light of the schedule for regulatory review and approval communicated by the MNPUC on October 28, 2016.

⁽²⁾ A special committee of independent directors of the Board of Enbridge Management has been established to consider a joint funding agreement with Enbridge.

⁽³⁾ Jointly funded 25% by us and 75% by our General Partner under the Eastern Access Joint Funding agreement. Estimated capital costs are presented at 100% before our General Partner’s contributions.

⁽⁴⁾ Jointly funded 25% by us and 75% by our General Partner under the Mainline Expansion Joint Funding agreement. Estimated capital costs are presented at 100% before our General Partner’s contributions.

⁽⁵⁾ Estimated in-service date will be adjusted to coincide with the in-service date of the Line 3 Replacement Program and the impact of cost to be reviewed. In 2015, we completed the expansion of pipeline capacity to 950,000 Bpd.

Line 3 Replacement Program

In 2014, we and Enbridge jointly announced that shipper support was received to replace portions of the existing 1,031-mile Line 3 pipeline on the Canadian Mainline/Lakehead system between Hardisty, Alberta, Canada and Superior, Wisconsin. Our portion of the Line 3 Replacement Program, referred to as the US L3R Program, includes replacing 358 miles from the U.S./Canadian border at Neche, North Dakota to Superior, Wisconsin. While the L3R Program will not provide an increase in the overall capacity of the mainline system, it will support the safety and operational reliability of the system, enhance flexibility and allow us and Enbridge to optimize throughput on the mainline system from Western Canada into Superior, Wisconsin.

We are in the process of obtaining the appropriate permits for constructing the US L3R Program in Minnesota. The project requires both a Certificate of Need, or Certificate, and an approval of the pipeline’s route, or Route Permit, from the MNPUC. The MNPUC found both the Certificate and Route Permit applications for the US L3R Program through Minnesota to be complete. The MNPUC had sent the Certificate docket to the Administrative Law Judge, or ALJ, for a pre-hearing meeting to establish a schedule. With respect to the Route Permit, the Minnesota Department of Commerce held public scoping meetings in August 2015.

47

On February 1, 2016, the MNPUC issued a written order, or the US L3R Order, joining the Line 3 Certificate and Route Permit dockets and requiring the Department of Commerce, or DOC, to prepare a final Environmental Impact Statement, or EIS, before the Certificate and Route Permit processes commence, and sent the cases to the Office of Administrative Hearings, or OAH, with direction to restart the process. On February 5, 2016, we filed a Petition for Reconsideration of the requirement to provide a final EIS ahead of the commencement of the Certificate and Route Permit proceedings noted in the US L3R Order. At a hearing held on March 24, 2016 the MNPUC denied the Petition for Reconsideration.

With the issuance of the Environmental Assessment Worksheet, or EAW, on April 11, 2016 the MNPUC commenced the EIS process. Consultation regarding the EAW, which defines the scope of the EIS, commenced with a series of public meetings in communities in Minnesota on April 25, 2016, which concluded on May 13, 2016. The DOC addressed the comments received on the draft EIS scope and issued its scoping recommendations to the MNPUC on September 22, 2016.

Three external parties filed motions requesting that the scoping process be re-opened or that a comment period be established because of the issuance of the Consent Decree settling the Line 6B pipeline crude oil release in Marshall, Michigan and the withdrawal of regulatory applications pending with the MNPUC with respect to the Sandpiper Project discussed above. We filed a reply challenging the need to re-open the scoping process indicating that neither of these events warrants further extension of time. The motions filed by the external parties were considered and denied by the MNPUC at a hearing held on October 28, 2016.

At the hearing on October 28, 2016, the MNPUC also confirmed the scope of the EIS and the schedule for the remainder of the regulatory approval process for the US L3R Program in Minnesota. The MNPUC’s decision will be confirmed in a written order expected to be issued by the MNPUC shortly. We are currently evaluating the impact of the decision on the cost and in-service date of this project. It is possible, under the schedule approved by the MNPUC, that the in-service date could be delayed, at least until later in 2019. The assessment of the impact of the decision is ongoing and we will review the written order when issued and seek to further clarify the impact on the overall project schedule at that time.

A special committee of independent directors of the board of Enbridge Management has been established to consider a proposal from our General Partner, on behalf of Enbridge, that would establish joint funding arrangements for the US L3R Program by creating an additional jointly owned series of partnership interests in Enbridge Energy, Limited Partnership, or OLP, similar to the series established for Eastern Access and Mainline Expansion.

We will recover our costs based on our existing Facilities Surcharge Mechanism, or FSM, with the initial term being 15 years. For purposes of the toll surcharge, the agreement specifies a 30 year recovery of the capital based on a cost-of-service methodology.

Light Oil Market Access Program

We and Enbridge have invested in a Light Oil Market Access Program to expand access to markets for growing volumes of light oil production. This program responds to significant developments with respect to supply of light oil from U.S. north central formations and western Canada, as well as refinery demand for light oil in the U.S. Midwest and eastern Canada. The Light Oil Market Access Program includes several projects that will further expand capacity on our U.S. mainline system, upsize the Eastern Access Projects, enhance Enbridge’s Canadian mainline terminal capacity and provide additional access to U.S. Midwestern refineries.

  Eastern Access Projects

The Eastern Access Projects included a series of crude oil pipeline expansion projects providing increased access to refineries in the U.S. Upper Midwest and the Canadian provinces of Ontario and Quebec for light crude oil produced in western Canada and the United States. The majority of the Eastern Access Projects were completed between 2013 and 2015. The remaining project was an expansion project for Line 6B to increase capacity from 500,000 Bpd to 570,000 Bpd and included: pump station modifications at Griffith, Niles and Mendon; additional modifications at the Griffith and Stockbridge terminals; and breakout tankage at Stockbridge. The expansion was placed into service in June 2016 at an approximate cost of $320 million.

48

We will operate the Eastern Access Projects on a cost-of-service basis. The Eastern Access Projects were funded 75% by our General Partner and 25% by us under the Eastern Access Joint Funding Agreement. We will have the option to increase our economic interest by up to 15% at cost through the June 2017 anniversary of the in service date. In July of 2015, we entered into an agreement with the General Partner in which the General Partner agreed to temporarily forego its Series EA cash distributions through the quarter ended March 31, 2016 in exchange for a reduction in the General Partner’s capital funding contribution requirements to the Eastern Access projects, which were offset against its foregone cash distributions. Pursuant to the terms of this arrangement, the Partnership may have higher contribution costs through the end of 2016 and may be required to forego a portion of its distributions beginning with the first quarter of 2017 until such time as the General Partner’s foregone cash distributions are recouped through either capital funding contributions or the Partnership’s foregone cash distributions. For further details, see Amendment of OLP Limited Partnership Agreement under Item 1. Financial Statements, Note 10. Related Party Transactions.

  U.S. Mainline Expansion

The U.S. Mainline Expansion Projects includes a series of crude oil pipeline expansion projects for our mainline pipeline system between Neche, North Dakota, and Flanagan, Illinois. These projects include the expansion of our existing 36-inch diameter Alberta Clipper pipeline, or Line 67 and our existing 42-inch diameter Southern Access pipeline, or Line 61, and the construction of Line 78, a twin of the Spearhead North pipeline, or Line 62. The expansion on Line 67 and construction of Line 78 were completed during 2015.

The Line 67 pipeline expansion remains subject to the receipt of an amendment to the current Presidential border crossing permit to allow for operation of the Line 67 pipeline at its currently planned operating capacity of 800,000 Bpd. The timing of the receipt of the amendment to the Presidential border crossing permit to allow for increased flow on the Line 67 pipeline across the border cannot be determined at this time. A number of temporary system optimization actions have been undertaken to substantially mitigate any impact on throughput associated with any delays in obtaining this amendment.

The Line 61 expansion, between Superior, Wisconsin and Flanagan, Illinois requires only the addition of pumping horsepower with no pipeline construction. In 2015, we completed the expansion of pipeline capacity to 950,000 Bpd. The additional tankage which cost approximately $380 million was completed in the third quarter of 2016. The remaining work includes an expansion phase to increase the pipeline capacity to 1,200,000 Bpd at an expected cost of approximately $435 million. In conjunction with shippers, a decision was made to delay the in-service date of this remaining expansion phase to 2019 to align more closely with the anticipated in-service date for the US L3R Program.

We will operate the U.S. Mainline Expansions projects on a cost-of-service basis. These projects are jointly funded 75% by our General Partner and 25% by us under the Mainline Expansion Joint Funding Agreement, which parallels the Eastern Access Joint Funding Agreement. We have the option to increase our economic interest held up to 15% at cost. In July of 2015, we entered into an agreement with the General Partner in which the General Partner agreed to temporarily forego its Series ME cash distributions through the quarter ended March 31, 2016, in exchange for a reduction in the General Partner’s capital funding contribution requirements to the Mainline Expansion projects, which were offset against its foregone cash distributions. Pursuant to the terms of this arrangement, the Partnership may have higher contribution costs through the end of 2016 and may be required to forego a portion of its distributions beginning with the first quarter of 2017 until such time as the General Partner’s foregone cash distributions are recouped through either capital funding contributions or the Partnership’s foregone cash distributions. For further details, see Amendment of OLP Limited Partnership Agreement under Item 1. Financial Statements, Note 10. Related Party Transactions.

49

Natural Gas

The following tables set forth the operating results of our Natural Gas segment and approximate average daily volumes of natural gas throughput and NGLs produced on our major systems for the periods presented.

	For the three months ended September 30,					For the nine months ended September 30,
	2016			2015		2016			2015
	(in millions)
Operating revenues	$	486.0		$	661.0	$	1,345.5		$	2,314.6
Commodity costs		404.0			522.7		1,111.1			1,972.4
Segment gross margin		82.0			138.3		234.4			342.2
Operating and administrative		71.7			94.1		224.0			264.1
Goodwill impairment		—			—		—			246.7
Asset impairment		—			—		10.6			12.3
Depreciation and amortization		39.2			39.2		118.7			118.3
Operating expenses		110.9			133.3		353.3			641.4
Operating income (loss)		(28.9	)		5.0		(118.9	)		(299.2	)
Other income		8.3			8.9		22.0			20.5
Net income (loss)	$	(20.6	)	$	13.9	$	(96.9	)	$	(278.7	)
Operating Statistics (MMBtu/d)
East Texas		894,000			966,000		924,000			981,000
Anadarko		606,000			760,000		632,000			794,000
North Texas		192,000			262,000		202,000			274,000
Total		1,692,000			1,988,000		1,758,000			2,049,000
NGL Production (Bpd)		67,588			85,343		70,932			82,498

Three months ended September 30, 2016, compared with the three months ended September 30, 2015

The Natural Gas segment recorded an operating loss of $28.9 million for the three months ended September 30, 2016, as compared to operating income of $5.0 million during the same period in 2015. The decrease of $33.9 million was primarily due to a decrease of $56.3 million in segment gross margin for the three months ended September 30, 2016, as compared to the same period in 2015. These decreases were partially offset by decreases in operating and administrative expenses of $22.4 million period over period, as described below. Decreases in “Operating revenues” and “Commodity costs” for the three months ended September 30, 2016, as compared to the same period in 2015, are primarily due to decreases in commodity prices and the resulting decrease in volumes from reduced drilling activities.

Segment gross margin decreased by $56.3 million, in part due to increased non-cash mark-to-market losses. The Natural Gas segment recognized non-cash, mark-to-market losses of $14.6 million for the three months ended September 30, 2016, as compared to gains of $6.2 million for the same period in 2015. The $20.8 million decrease is primarily related to increased commodity prices of condensate and NGLs period over period, partially offset by the gains from the reversal of previously recognized unrealized market-to-market losses as the underlying transactions were settled.

Segment gross margin decreased by approximately $13.5 million for the three months ended September 30, 2016, as compared to the same period in 2015, due to reduced natural gas throughput. The average daily volumes of our major systems for the three months ended September 30, 2016, decreased by 296,000 MMBtu/d, or 15%, as compared to the same period in 2015. The average NGL production for the three months ended September 30, 2016, decreased by 17,755 Bpd, or 21%, as compared to the same period in 2015. The decreases in volumes were primarily attributable to the continued low commodity price environment for natural gas, condensate and NGLs, which resulted in reductions in drilling activity from producers in the areas we operate.

Segment gross margin decreased $12.5 million for the three months ended September 30, 2016, as compared with the same period in 2015 due to a decline in storage margins as a result of the sale of liquids product inventory at lower prevailing market prices relative to the cost of product inventory.

50

Operating and administrative costs decreased $22.4 million for the three months ended September 30, 2016, as compared to the same period in 2015, primarily due to workforce reductions and other cost reduction efforts, including decreases in repairs and maintenance, property taxes, and contract labor.

Nine months ended September 30, 2016, compared with the nine months ended September 30, 2015

The operating loss of our Natural Gas segment for the nine months ended September 30, 2016, decreased $180.3 million, as compared to the same period in 2015, primarily as a result of a reduction in goodwill impairment charge. During the nine months ended September 30, 2015, the Natural Gas segment recognized a goodwill impairment charge of $246.7 million. No similar charge was recorded during the same period in 2016. The effects of the lack of impairment charge were offset by lower segment gross margin in the 2016 period, as discussed below. Decreases in “Operating revenues” and “Commodity costs” for the nine months ended September 30, 2016, as compared to the same period in 2015, are due to the reasons discussed above.

Segment gross margin decreased $107.8 million for the nine months ended September 30, 2016, as compared to the same period in 2015, in part due to increased non-cash, mark-to-market losses. Non-cash, mark-to-market losses increased $34.0 million for the nine months ended September 30, 2016, as compared to the same period in 2015. This change primarily related to losses due to the increased commodity prices of condensate and NGLs period over period, partially offset by the gains from the reversal of previously recognized unrealized mark-to-market losses as the underlying transactions were settled.

Segment gross margin decreased by approximately $32.1 million for the nine months ended September 30, 2016, as compared to the same period in 2015, due to reduced natural gas throughput. The average daily volumes of our major systems decreased by approximately 291,000 MMBtu/d, or 14%, for the nine months ended September 30, 2016, as compared to the same period in 2015. The average NGL production for the nine months ended September 30, 2016, decreased 11,566 Bpd, or 14%, as compared to the same period in 2015. The decreases in volumes were primarily attributable to the continued low commodity price environment for natural gas, condensate and NGLs, which resulted in reductions in drilling activity by producers in the areas we operate.

Segment gross margin decreased $13.7 million for the nine months ended September 30, 2016, as compared to the same period in 2015, due to decreased margins from lower commodity prices, net of hedges, related to contracts where we were paid in commodities for our services.

Segment gross margin decreased $12.2 million for the nine months ended September 30, 2016, as compared to the same period in 2015, due to a decrease in storage margins as a result of the sale of liquids product inventory at lower prevailing market prices relative to the cost of product inventory.

Segment gross margin also decreased $10.6 million for the nine months ended September 30, 2016, as compared to the same period in 2015, due to a decrease in processing margins primarily driven by lower commodity prices along with decline in NGL volumes and associated keep whole volumes in the Anadarko and East Texas regions.

Operating and administrative costs decreased $40.1 million for the nine months ended September 30, 2016, as compared to the same period in 2015, primarily due to workforce reductions and other cost reduction efforts, as discussed above. Operating and administrative costs also decreased due to gains of $5.6 million recorded during the first quarter of 2016 to recognize return of escrow funds and a reversal of a contingent liability related to an acquisition. For further details regarding these amounts, refer to Item 1. Financial Statements, Note 3. Acquisitions.

Future Prospects for Natural Gas

Demand for our midstream services primarily depends upon the supply of natural gas and associated natural gas from crude oil development and the drilling rate for new wells. Demand for these services depends on overall economic conditions and commodity prices. Commodity prices for natural gas, NGLs, condensate, and crude oil continue to remain low. The depressed commodity price environment is the most significant factor for reduced drilling activity and low volumes in the basins in which we operate. Due to the commodity price environment, we expect drilling activity to remain low and as a result, we expect to see continued low volumes on our systems in 2016, and beyond. In addition, we also expect our average NGL transportation commitments on the Texas Express system to increase from 29,000 Bpd in 2016 to 75,000 Bpd in 2017.

We have a hedging program in place to assist in mitigating our direct commodity price risk. We have hedged over 90% and 60% of our direct forecasted commodity cash flow exposure for 2016 and 2017, respectively. Our condensate and NGL hedge prices for 2017 are approximately 20% and on average 30% lower than 2016,

51

respectively. See Liquidity and Capital Resources — Derivative Activities below. Despite our hedging program, we still bear indirect commodity price exposure as lower drilling activity impacts the volumes on our systems as well as direct commodity price exposure for unhedged commodity positions. We expect this indirect impact on our volumes to fluctuate depending on future price movements.

We have sought to expand our natural gas gathering and processing services by: (1) capturing opportunities within our footprint, (2) expanding outside of our existing footprint through strategic acquisitions, (3) providing an array of services for both natural gas and NGLs in combination with core asset optimization, and (4) capitalizing on new market opportunities by diversifying geographically and by commodity composition. However, in light of the low commodity price environment, we have been evaluating opportunities to strengthen our natural gas business. As part of this evaluation, in addition to, or as alternatives to, possible expansion strategies for our natural gas gathering and processing services discussed above, we are exploring strategic alternatives for our investments in each of Midcoast Operating and MEP. We have been working with MEP to explore and evaluate a broad range of strategic alternatives to address these challenges within our Natural Gas business. These additional various strategic alternatives may include, but are not necessarily limited to: asset sales; mergers, joint ventures, reorganizations or recapitalizations; and further reductions in operating and capital expenditures for the Natural Gas business. The evaluation process is ongoing, and no decision on any particular strategic alternative has been reached. Enbridge has indicated that as part of the integration resulting from the Spectra merger, its U.S. sponsored vehicles, which includes MEP, will be reviewed in context of the combined enterprise. In addition, as discussed more fully above with respect to future prospects for the liquids segment, the interim operating covenants that Enbridge agreed to as part of its merger agreement with Spectra Energy Corp. are also applicable to MEP and its subsidiaries. Thus, while we continue to progress our strategic evaluation of MEP, it is possible that the evaluation and potential execution of any such strategy could be affected by the merger and extend into 2017.

Corporate

Our corporate results consist of interest expense, allowance for equity used during construction, noncontrolling interest and other costs such as income taxes, which are not allocated to the business segments.

	For the three months ended September 30,						For the nine months ended September 30,
	2016			2015			2016			2015
	(in millions)
Operating Results:
Operating and administrative expenses	$	3.2		$	3.3		$	9.4		$	10.9
Operating loss		(3.2	)		(3.3	)		(9.4	)		(10.9	)
Interest expense, net		(112.3	)		(88.2	)		(326.7	)		(214.5	)
Allowance for equity used during construction		10.1			13.7			35.7			54.0
Other income (expense)		0.4			(0.1	)		0.9			0.2
Loss before income tax expense		(105.0	)		(77.9	)		(299.5	)		(171.2	)
Income tax expense		(2.2	)		(4.6	)		(7.2	)		(3.2	)
Net loss	$	(107.2	)	$	(82.5	)	$	(306.7	)	$	(174.4	)

Three months ended September 30, 2016, compared with three months ended September 30, 2015

The $24.7 million increase in our segment net loss for the three months ended September 30, 2016, as compared to the same period in 2015, was primarily attributable to an increase in interest expense.

The $24.1 million increase in interest expense was primarily due to an increase in our average outstanding debt balance during the three months ended September 30, 2016, which includes $1.6 billion of senior unsecured notes that were issued in October 2015.

Nine months ended September 30, 2016, compared with nine months ended September 30, 2015

The $132.3 million increase in our segment net loss for the nine months ended September 30, 2016, as compared to the same period in 2015, was mainly attributable to an increase in interest expense of $112.2 million, period over period. The increase is due to an increase in our average outstanding debt balance during the nine months ended September 30, 2016, which includes $1.6 billion of senior unsecured notes that were issued in October 2015. In addition, charges to interest expense from ineffectiveness on hedging instruments decreased $27.9 million, as compared to the same period in 2015.

52

Further, allowance for equity used during construction, or AEDC, decreased $18.3 million for the nine months ended September 30, 2016, when compared to the same period in 2015, as a result of a reduction in outstanding capital projects in which AEDC is being recognized.

LIQUIDITY AND CAPITAL RESOURCES

General

Our primary operating cash requirements consist of normal operating expenses, maintenance capital expenditures, funding requirements associated with environmental costs, distributions to our partners and payments associated with our risk management activities. We expect to fund our current and future short-term cash requirements for these items from our operating cash flows supplemented as necessary by issuances of commercial paper and borrowings under our Credit Facilities. Margin requirements associated with our derivative transactions are generally supported by letters of credit issued under our Credit Facilities.

Our current business strategy includes developing and expanding our existing business through organic growth and targeted acquisitions, in addition to the strategies, and subject to the short-term limitations, discussed above under Future Prospects for Liquids and Future Prospects for Natural Gas. We expect to initially fund our long-term cash requirements for expansion projects and acquisitions, as well as retire our maturing and callable debt, first from operating cash flows and then from issuances of commercial paper and borrowings on our Credit Facilities. We expect to obtain permanent financing as needed through the issuance of additional equity and debt securities, which we will use to repay amounts initially drawn to fund these activities, although there can be no assurance that such financings will be available on favorable terms, if at all.

We are evaluating opportunities to strengthen our business in light of the low commodity price environment, which is impacting the performance of our natural gas gathering and processing assets. As part of this process, we are exploring and evaluating strategic alternatives for our investments in each of Midcoast Operating and MEP, as discussed above under Future Prospects for Natural Gas, which may include, but are not limited to: asset sales; mergers, joint ventures, reorganizations or recapitalizations; and further reductions in operating and capital expenditures. It may also include selling additional interests in Midcoast Operating to MEP to raise capital over the course of the next several years. Although we are evaluating these opportunities, there is no assurance that any transactions will be pursued or effected.

In the past, when we had attractive growth opportunities in excess of our own capital raising capabilities, our General Partner provided supplementary funding, or participated directly in projects, to enable us to undertake such opportunities. If in the future we have attractive growth opportunities that exceed capital raising capabilities, we could seek similar arrangements from our General Partner, but there can be no assurance that this funding can be obtained.

Available Liquidity

Our primary source of short-term liquidity is provided by our $1.5 billion commercial paper program, which is supported by our $2.0 billion multi-year unsecured revolving credit facility, which we refer to as the Credit Facility, and our $625.0 million credit agreement, which we refer to as the 364-Day Credit Facility. We refer to the 364-Day Credit Facility and the Credit Facility as our Credit Facilities. We access our commercial paper program primarily to provide temporary financing for our operating activities, capital expenditures and acquisitions when the interest rates available to us for commercial paper are more favorable than the rates available under our Credit Facilities. At September 30, 2016, we had approximately $1,172.2 million in available credit under the terms of our Credit Facilities. For a description of our commercial paper program and our Credit Facilities, refer to Item 1. Financial Statements, Note 8. Debt.

On July 26, 2016, we entered into an unsecured revolving 364-day credit agreement with EUS. 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, $750.0 million. For further details, refer to Item 1. Financial Statements, Note 11. Related Party Transactions.

As of September 30, 2016, although we had a working capital deficit of approximately $1.0 billion, we had approximately $1.6 billion of consolidated liquidity to meet our ongoing operational, investing and financing needs as described above, as well as the funding requirements associated with the environmental remediation costs resulting from the crude oil release on Line 6B.

53

The following table, sets forth the consolidated liquidity available to us at September 30, 2016.

	EEP		MEP		Total
	(in millions)
Cash and cash equivalents	$	40.9	$	—	$	40.9
Total commitments under EEP’s Credit Facilities		2,625.0		—		2,625.0
Total commitments under the EUS 364-day Credit Facility		750.0		—		750.0
Total commitments under MEP’s Credit Agreement		—		810.0		810.0
Less: Amounts outstanding under EEP’s Credit Facilities		1,660.0		—		1,660.0
Amounts outstanding under MEP’s Credit Agreement		—		450.0		450.0
Principal amount of commercial paper outstanding		292.6		—		292.6
Letters of credit outstanding		250.2		—		250.2
Total	$	1,213.1	$	360.0	$	1,573.1

Capital Resources

Equity and Debt Securities

Execution of our growth strategy and completion of our planned construction projects contemplate our accessing the public and private equity and credit markets to obtain the capital necessary to fund these activities. We have issued a balanced combination of debt and equity securities to fund our expansion projects and acquisitions. Our internal growth projects and targeted acquisitions will require additional permanent capital and require us to bear the cost of constructing and acquiring assets before we begin to realize a return on them. From time to time, if the capital markets are constrained, our ability and willingness to complete future debt and equity offerings may be limited, which in turn, could affect our ability to execute our growth strategy or complete our planned construction projects. The timing of any future debt and equity offerings will depend on various factors, including prevailing market conditions, interest rates, our financial condition and our credit rating at the time.

From time to time, we may seek to satisfy liquidity needs through the issuance of registered debt or equity securities. We have a current shelf registration statement on Form S-3 that allows us to issue an unlimited amount of equity and debt securities in underwritten public offerings.

MEP Credit Agreement

MEP, Midcoast Operating, and their material subsidiaries are party to a senior revolving credit facility, which we refer to as the MEP Credit Agreement, which permits aggregate borrowings of up to $810.0 million, at any one time outstanding. 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 at the lenders’ discretion, two of which we have utilized. The MEP Credit Agreement’s current maturity date is September 30, 2018; however, $140.0 million of commitments expire on the original maturity date of November 13, 2016, and an additional $25.0 million of commitments expire on September 30, 2017.

The MEP Credit Agreement requires compliance with two financial covenants. They are not permitted to allow their ratio of consolidated funded debt to pro forma earnings before interest, taxes, depreciation and amortization, or EBITDA, as of the end of any applicable four-quarter period, to exceed 5.00 to 1.00, or 5.50 to 1.00 during acquisition periods. MEP must also maintain (on a consolidated basis), as of the end of each applicable four-quarter period, a ratio of pro forma EBITDA to consolidated interest expense for such four-quarter period then ended of at least 2.50 to 1.00.

At September 30, 2016, MEP was in compliance with the terms of their financial covenants in the MEP Credit Agreement and we expect MEP to remain in compliance throughout the remainder of 2016. Due to the low commodity price environment and the potential implications on MEP’s results of operations, it is possible that MEP may not be able to meet the total leverage ratio financial covenant at some point during the term of the agreement without further action on its part. If this were to occur, MEP would seek a waiver from its lenders, seek additional capital contributions, pursue refinancing of the amounts outstanding under the MEP Credit Agreement or seek to take other action to prevent a default under the MEP Credit Agreement, although there is no assurance that MEP could obtain any such necessary preventative actions. Failure to comply with one or both of the financial covenants may result in the occurrence of an event of default under the MEP Credit Agreement, which would result in a cross-default under the note purchase agreement relating to MEP’s senior notes. If an event of default were to occur, the lenders could, among other things, terminate their commitments under the MEP Credit Agreement, demand

54

immediate payment of all amounts borrowed by MEP and Midcoast Operating, trigger the springing liens, and require adequate security or collateral for all outstanding letters of credit outstanding under the facility. In addition, MEP and Midcoast Operating are restricted under the MEP Credit Agreement from making distributions to us in certain circumstances involving certain defaults under that agreement or any event of default under that agreement. Furthermore, a default under the MEP Credit Agreement or Purchase Agreement would limit our ability to receive payment of amounts that may be owed to us under the Financial Support Agreement. Any inability of MEP or Midcoast Operating to make distributions, or of Midcoast Operating to repay its indebtedness to us, could reduce our cash flows and affect our results of operations. See Item 1A. Risk Factors — Risks Related to Our Business in our Annual Report on Form 10-K for fiscal year ended December 31, 2015. In addition, as discussed above under Future Prospects for Natural Gas, as part of an evaluation of opportunities to strengthen our natural gas business in light of the low commodity price environment, we are exploring and evaluating a broad range of strategic alternatives for our investments in each of MEP and Midcoast Operating.

MEP Senior Notes

MEP has $400.0 million of notes consisting of three tranches of senior notes: $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, and commenced on March 31, 2015.

The Notes were issued pursuant to a Note Purchase Agreement, or the Purchase Agreement, between MEP and the purchasers named therein. The Notes and all other obligations under the Purchase Agreement are unconditionally guaranteed by each of MEP’s domestic material subsidiaries pursuant to a guaranty agreement. Until such time as MEP obtain an investment grade rating from either Moody’s or S&P and upon certain trigger events, MEP and the guarantors will grant liens in their assets (subject to certain excluded assets) to secure the obligations under the Notes. There are currently no liens associated with the Notes.

The Purchase Agreement also requires compliance with two financial covenants. MEP must not permit the ratio of consolidated funded debt to pro forma Earnings Before Interest, Taxes, Depreciation and Amortization, or EBITDA (the total leverage ratio), as of the end of any applicable four quarter period, to exceed 5.00 to 1.00, or 5.50 to 1.00 during acquisition periods. MEP also must maintain, on a consolidated basis, as of the end of each applicable four-quarter period, a ratio of pro forma EBITDA to consolidated interest expense for such four quarter period then ended of at least 2.50 to 1.00.

At September 30, 2016, MEP was in compliance with the terms of their financial covenants under the Notes and the related purchase agreement and we expect MEP to remain in compliance throughout the remainder of 2016. Due to the low commodity price environment and the potential implications on MEP’s results of operations, it is possible that MEP may not be able to meet the total leverage ratio financial covenant at some point during the term of the agreement without further action on its part. If this were to occur, MEP would seek a waiver from the note holders, seek additional capital contributions, pursue refinancing of the amounts outstanding under the Notes or seek to take other action to prevent a default under the Purchase Agreement and the Notes, although there is no assurance that MEP could obtain any such necessary preventative actions. Any failure to comply with one or both of the financial covenants could result in an event of default under the Purchase Agreement and the Notes and result in a cross-default under the MEP Credit Agreement. If an event of default were to occur, the note holders could, among other things, demand immediate payment of the Notes and trigger the springing liens. In addition, as discussed above, MEP and Midcoast Operating are restricted from making distributions to us in certain circumstances involving certain defaults under that agreement or any event of default under that agreement. Furthermore, a default under the MEP Credit Agreement or Purchase Agreement would limit our ability to receive payment of amounts that may be owed to us under the Financial Support Agreement. Any inability of MEP or Midcoast Operating to make distributions, or of Midcoast Operating to repay its indebtedness to us, could reduce our cash flows and affect our results of operations.

Joint Funding Arrangements

In order to obtain capital, we have explored, and may continue to explore, numerous options, including joint funding arrangements.

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 ended March 31, 2016. The General Partner’s

55

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. We do not expect to have reduced cash distributions in 2017.

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 the Eastern Access 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. 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%.

Our General Partner made equity contributions totaling $7.2 million and $119.3 million to the OLP for the nine months ended September 30, 2016 and 2015, respectively, to fund its equity portion of the construction costs associated with the Eastern Access Projects.

Joint Funding Arrangement for the U.S. Mainline Expansion

The OLP also has a series of partnership interests, which we refer to as the ME interests. The ME interests were created to finance the Mainline Expansion 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. 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 $58.5 million and $552.9 million to the OLP for the nine months ended September 30, 2016 and 2015, respectively, to fund its equity portion of the construction costs associated with the Mainline Expansion Projects.

Sale of Accounts Receivable

We and certain of our subsidiaries are parties to a receivables purchase arrangement, which we refer to as the Receivables Agreement, with an indirect, wholly-owned subsidiary of Enbridge. Pursuant to the Receivables Agreement, the Enbridge subsidiary will purchase on a monthly basis, for cash, current accounts receivables and accrued receivables, or the receivables, of certain of our subsidiaries and certain subsidiaries of MEP that are participating sellers under the Receivables Agreement, up to an aggregate monthly maximum of $450.0 million, net of receivables that have not been collected. The Receivables Agreement was amended in June 2016 to extend the termination date of the agreement to December 31, 2019.

For the nine months ended September 30, 2016, we sold and derecognized $2,485.0 million of receivables to an indirect, wholly-owned subsidiary of Enbridge, and we received cash proceeds of $2,483.9 million. As of September 30, 2016, outstanding receivables of $277.2 million, which had been sold and derecognized, had not been collected on behalf of the Enbridge subsidiary.

For further details regarding the Receivables Agreement, refer to Item 1. Financial Statements, Note. 10. Related Party Transactions.

Cash Requirements

Capital Spending

We categorize our capital expenditures as either maintenance capital or expansion capital expenditures. Maintenance capital expenditures are those expenditures that are necessary to maintain the service capability of our existing assets and include the replacement of system components and equipment which are worn, obsolete or completing its useful life. We also include in maintenance capital expenditures a portion of our expenditures for

56

connecting natural gas wells, or well-connects, to our natural gas gathering systems. Expenditure levels will increase as pipelines age and require higher levels of inspection, maintenance and capital replacement. We also anticipate that maintenance capital will increase due to the growth of our pipeline systems and the aging of portions of these systems. Maintenance capital expenditures are expected to be funded by operating cash flows.

Expansion capital expenditures include our capital expansion projects and other projects that improve the service capability of our existing assets, extend asset useful lives, increase capacities from existing levels, reduce costs or enhance revenues and enable us to respond to governmental regulations and developing industry standards. We anticipate funding expansion capital expenditures temporarily through borrowing under the terms of our Credit Facility, with permanent debt and equity funding being obtained when appropriate.

We maintain a comprehensive integrity management program for our pipeline systems, which relies on the latest technologies that include internal pipeline inspection tools. These internal pipeline inspection tools identify internal and external corrosion, dents, cracking, stress corrosion cracking and combinations of these conditions. We regularly assess the integrity of our pipelines utilizing the latest generations of metal loss, caliper and crack detection internal pipeline inspection tools. We also conduct hydrostatic testing to determine the integrity of our pipeline systems. Accordingly, we incur substantial expenditures each year for our integrity management programs. We expect to incur continuing annual capital and operating expenditures for pipeline integrity measures to ensure both regulatory compliance and to maintain the overall integrity of our pipeline systems. Under our capitalization policy, expenditures that replace major components of property or extend the useful lives of existing assets are capital in nature, while expenditures to inspect and test our pipelines are usually considered operating expenses.

We incurred capital expenditures of approximately $0.7 billion for the nine months ended September 30, 2016, including $46.1 million of maintenance capital expenditures. Of those capital expenditures, $79.2 million was financed by contributions from our General Partner and MPC via joint funding arrangements. At September 30, 2016, we had approximately $0.4 billion in outstanding purchase commitments attributable to capital projects for the construction of assets that will be recorded as property, plant and equipment in the future.

Acquisitions

We continue to assess ways to generate value for our unitholders, including reviewing opportunities that may lead to acquisitions or other strategic transactions, some of which may be material. We evaluate opportunities against operational, strategic and financial benchmarks before pursuing them. We expect to obtain the funds needed to make acquisitions through a combination of cash flows from operating activities, borrowings under our Credit Facilities, joint funding arrangements and the issuance of additional debt and equity securities. All acquisitions are considered in the context of the practical financing constraints presented by the capital markets.

Forecasted Expenditures

We estimate our capital expenditures based upon our strategic operating and growth plans, which are also dependent upon our ability to produce or otherwise obtain the financing necessary to accomplish our growth objectives. Due to the completion of major projects, and lower-than-anticipated spending on the Sandpiper and Line 3 Replacement projects in 2016, we expect our expansion capital expenditures to be significantly lower in 2016 than in recent years. The following table sets forth our estimated maintenance and expansion capital expenditures, net of joint funding, of $0.7 billion for the year ending December 31, 2016. We expect to receive funding of approximately $0.3 billion from our General Partner based on our joint funding arrangement for the Eastern Access Projects and Mainline Expansion Projects. Furthermore, we expect to receive funding of approximately $30.0 million from MPC based on our joint funding arrangement for the Sandpiper Project. Although we anticipate making these expenditures in 2016, these estimates may change due to factors beyond our control, including weather-related issues, construction timing, regulatory permitting, changes in supplier prices or poor economic conditions, which may adversely affect our ability to access the capital markets. Additionally, our estimates may also change as a result of decisions made at a later date to revise the scope of a project or undertake a particular capital program or an acquisition of assets.

57

	Total Forecasted Expenditures(1)
	(in millions)
Liquids Projects
Eastern Access Projects	$	200
U.S. Mainline Expansions		200
Sandpiper(2)		75
Line 3 Replacement		100
Liquids Integrity Program		180
Expansion Capital		190
Maintenance Capital Expenditures		55
		1,000
Less joint funding from:
General Partner(3)		300
Third parties		30
Liquids Total	$	670
Natural Gas Projects
Expansion Capital	$	30
Maintenance Capital Expenditures		30
		60
Less joint funding from:
MEP		30
Natural Gas Total	$	30
TOTAL	$	700

⁽¹⁾ Amounts do not include forecasted Allowance for Funds Used During Construction, or AFUDC.

⁽²⁾ Amounts represent costs capitalized before the Sandpiper Project was impaired. As discussed above under Future Prospects for Liquids — Recent Developments — Sandpiper Project, during the three months ended September 30, 2016, we recorded an asset impairment of $762.6 million, including related project costs on the Sandpiper Project, as we believe that this pipeline capacity will no longer be needed until beyond our five-year planning horizon.

⁽³⁾ Joint funding by the General Partner is based on its respective economic interests in the Eastern Access Projects and U.S. Mainline Expansions, and does not take into account the temporary adjustment to contributions and distributions pursuant to the amendment of the OLP limited partnership agreement, as described above.

Environmental

Lakehead Line 6B Crude Oil Release

During the nine months ended September 30, 2016, our cash flows were affected by the approximate $17.3 million we paid for the environmental remediation, restoration and cleanup activities resulting from the crude oil release that occurred in 2010 on Line 6B of our Lakehead system.

In March 2013, we and Enbridge filed a lawsuit against the insurers of our remaining $145.0 million 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 during the third quarter 2013 and have since amended our lawsuit, such that it now includes only one carrier. While we believe that our claims for the remaining $103.0 million are covered under the policy, there can be no assurance that we will prevail in this lawsuit. Of the remaining $103.0 million coverage limit, $85.0 million is the subject matter of a lawsuit Enbridge filed against one particular insurer and the remaining $18.0 million is awaiting resolution of arbitration, which is scheduled to begin in the fourth quarter of 2016. While we believe that those costs are eligible for recovery, there can be no assurance we will prevail in the arbitration. For more information regarding cost estimates and fines and penalties, refer to Item 1. Financial Statements, Note 11. Commitments and Contingencies.

Derivative Activities

We record all derivative financial instruments at fair market value in our consolidated statements of financial position. Price assumptions we use to value our non-qualifying derivative financial instruments can affect net income for each period. We use published market price information where available, or quotations from OTC

58

market makers to find executable bids and offers. We may also use these inputs with internally developed methodologies that result in our best estimate of fair value. The valuations also reflect the potential impact of liquidating our position in an orderly manner over a reasonable period of time under present market conditions, including credit risk of our counterparties. The amounts reported in our consolidated financial statements change quarterly as these valuations are revised to reflect actual results, changes in market conditions or other factors, many of which are beyond our control.

The following table provides summarized information about the timing and expected settlement amounts of our outstanding commodity derivative financial instruments based upon the market values at September 30, 2016 for each of the indicated calendar years:

	Notional(1)		2016			2017			2018			2019		2020 & Thereafter		Total(2)
	(in millions)
Swaps:
Natural gas		19,263,317	$	0.2		$	1.0		$	—		$	—		—	$	1.2
NGL		13,241,900		0.1			(2.1	)		—			—		—		(2.0	)
Crude Oil		2,066,496		1.0			(0.9	)		—			—		—		0.1
Options:
Natural gas – puts purchased		414,000		0.3			—			—			—		—		0.3
Natural gas – puts written		414,000		(0.3	)		—			—			—		—		(0.3	)
Natural gas – calls purchased		414,000		—			—			—			—		—		—
Natural gas – calls written		414,000		—			—			—			—		—		—
NGL – puts purchased		2,387,700		9.2			5.5			—			—		—		14.7
NGL – puts written		59,800		(0.6	)		—			—			—		—		(0.6	)
NGL – calls purchased		59,800		—			—			—			—		—		—
NGL – calls written		2,387,700		(0.3	)		(8.0	)		—			—		—		(8.3	)
Crude Oil – puts purchased		932,400		5.4			7.6			0.3			—		—		13.3
Crude Oil – calls written		932,400		—			(1.2	)		(0.8	)		—		—		(2.0	)
Forward contracts:
Natural gas		36,413,904		(0.2	)		0.2			0.1			0.1		—		0.2
NGL		8,091,589		0.3			1.5			0.8			—		—		2.6
Crude Oil		383,298		(1.5	)		—			—			—		—		(1.5	)
Totals			$	13.6		$	3.6		$	0.4		$	0.1	$	—	$	17.7

⁽¹⁾ Notional amounts for natural gas are recorded in MMBtu, whereas NGLs and crude oil are recorded in Bbl.

⁽²⁾ Fair values exclude credit valuation adjustment gains of approximately $0.1 million at September 30, 2016.

The following table provides summarized information about the timing and estimated settlement amounts of our outstanding interest rate derivatives calculated based on implied forward rates in the yield curve at September 30, 2016 for each of the indicated calendar years:

	Notional		2016			2017			2018			2019			2020		Total(1)
	(in millions)
Interest Rate Derivatives
Interest Rate Swaps:
Floating to Fixed	$	1,930	$	(0.3	)	$	(11.3	)	$	(10.0	)	$	(2.7	)	$	—	$	(24.3	)
Pre-issuance hedges	$	1,350		(127.0	)		(96.8	)		(44.3	)		—			—		(268.1	)
			$	(127.3	)	$	(108.1	)	$	(54.3	)	$	(2.7	)	$	—	$	(292.4	)

⁽¹⁾ Fair values exclude credit valuation adjustment gains of approximately $3.1 million at September 30, 2016.

59

Cash Flow Analysis

The following table summarizes the changes in cash flows by operating, investing and financing for each of the periods indicated:

	For the nine months ended September 30,						Variance 2016 vs. 2015 Increase (Decrease)
	2016			2015
	(in millions)
Total cash provided by (used in):
Operating activities	$	961.1		$	1,054.3		$	(93.2	)
Investing activities		(849.6	)		(1,566.5	)		716.9
Financing activities		(218.7	)		424.8			(643.5	)
Net decrease in cash and cash equivalents		(107.2	)		(87.4	)		(19.8	)
Cash and cash equivalents at beginning of year		148.1			197.9			(49.8	)
Cash and cash equivalents at end of period	$	40.9		$	110.5		$	(69.6	)

Changes in our working capital accounts are shown in the following table and discussed below:

	For the nine months ended September 30,						Variance 2016 vs. 2015
	2016			2015
	(in millions)
Changes in operating assets and liabilities, net of acquisitions:
Receivables, trade and other	$	15.0		$	36.2		$	(21.2	)
Due from General Partner and affiliates		(43.7	)		(28.1	)		(15.6	)
Accrued receivables		30.8			216.2			(185.4	)
Inventory		(32.0	)		0.5			(32.5	)
Current and long-term other assets		(22.6	)		(33.6	)		11.0
Due to General Partner and affiliates		20.2			80.5			(60.3	)
Accounts payable and other		(84.8	)		(11.5	)		(73.3	)
Environmental liabilities		(15.1	)		(34.5	)		19.4
Accrued purchases		(8.0	)		(175.1	)		167.1
Interest payable		20.3			0.3			20.0
Property and other taxes payable		(1.8	)		2.7			(4.5	)
Net change in working capital accounts	$	(121.7	)	$	53.6		$	(175.3	)

Operating Activities

Net cash provided by our operating activities decreased $93.2 million for the nine months ended September 30, 2016, compared to the same period in 2015, primarily due to decreased cash inflows from net changes in operating assets and liabilities, partially offset by increased cash from net income after non-cash adjustments. Increased cash from net income after non-cash adjustments totaled $82.1 million and was primarily due to increased volumes and rates on our liquids systems from new systems placed into service and offset by decreased volumes on our natural gas systems from lower drilling activity, as described in the Results of Operations — by Segment discussion. Decreased cash inflows from net changes in operating assets and liabilities include:

• Decreased cash from net balances due to and due from the General Partner and its affiliates of $75.9 million resulting from timing differences on amounts due from and due to the General Partner and its affiliates;

• Decreased cash from changes in accounts payable and other of $73.3 million, primarily as a result of timing differences in cash payments; and

• Decreased cash from net changes in accrued purchases and accrued receivables of $18.3 million, primarily resulting from lower commodity prices and volumes.

60

Investing Activities

Net cash used in our investing activities during the nine months ended September 30, 2016 decreased by $716.9 million compared to the same period in 2015 primarily due to decreased spending on capital projects.

Financing Activities

Net cash provided by our financing activities decreased $643.5 million for the nine months ended September 30, 2016 compared to the same period in 2015 primarily due to the following:

• Decrease in cash provided by contributions from noncontrolling interest of $661.4 million due to a reduction in cash requirements for capital projects and the temporary reductions of contributions from our General Partner on the Series EA and ME interests as discussed above under Amendment of OLP Limited Partnership Agreement;

• Decreased net proceeds from our unit issuances of $294.8 million, which occurred in March 2015, while we had no unit issuances in 2016; and

• Increased distributions to our limited partners of $28.2 million.

These decreases in net cash provided by our financing activities were partially offset by the following:

• Decreased repayments of $306.0 million to the General Partner in January 2015, primarily due to the A1 loan in January 2015, while we had no such repayments in 2016; and

• Decreased distributions to noncontrolling interest of $53.5 million due to foregone cash distributions to our General Partner on the Series EA and ME interests as discussed above under Amendment of OLP Limited Partnership Agreement.

REGULATORY MATTERS

FERC Transportation Tariffs

Under current policy, the FERC permits interstate pipelines that are subject to cost of service regulation to include an income tax allowance when calculating their regulated rates. On July 1, 2016, the U.S. Court of Appeals for the District of Columbia Circuit issued a decision that calls into question a FERC policy permitting regulated companies organized as pass-through entities for income tax purposes to include an allowance for income taxes in their rates. The court has remanded the case to the FERC to provide a basis for its decision on income tax allowances for partnership pipelines. At this time, there is not enough information available to us to determine whether the level of income tax allowance included in our regulated rates will change, and if so, by how much.

Lakehead System

Effective April 1, 2016, FERC tariff No. 43.20.0 adjusted rates to update the Facilities Surcharge Mechanism, or FSM. The FSM allows recovery of costs associated with particular shipper-approved projects through an incremental cost-of-service based surcharge that is layered on top of the base index rates. The FSM surcharge reflects our projected costs for these shipper-approved projects for 2016 and an adjustment for the difference between estimated and actual costs and throughput for the prior year. The surcharge is applicable to all volumes entering our system from the effective date of the tariff, which we recognize as revenue when the barrels are delivered, typically a period of approximately 30 days from the date shipped.

This tariff filing increased our transportation rate for heavy crude oil movements from the Canadian border to the Chicago, Illinois area by approximately $0.17 per barrel, to approximately $2.61 per barrel. The tariff filing also increased our transportation rate for light crude oil movements from the Canadian border to the Chicago, Illinois area by approximately $0.14 per barrel, to approximately $2.16 per barrel. These increases were primarily the result of an adjustment for the difference between estimated and actual costs and throughput for 2015, coupled with an increase in forecasted capital additions for 2016.

On May 31, 2016, we filed FERC tariff No. 43.21.0 with an effective date of July 1, 2016 for our Lakehead system. We decreased rates in compliance with the indexed rate ceilings allowed by the FERC, which incorporates the multiplier of 0.979865 issued by the FERC on May 19, 2016 in Docket No. RM93-11-000.

North Dakota System

Effective April 1, 2016, FERC tariff No. 3.18.0 adjusted rates, including an updated calculation of the Phase 5 Looping and Phase 6 Mainline surcharges. These surcharges are cost-of-service based surcharges that are adjusted

61

each year to actual costs and volumes and are not subject to the FERC indexing methodology. This filing decreased our average transportation rates for all crude oil movements on our North Dakota system with a destination of Clearbrook, Minnesota by an average of approximately $0.06, to an average of approximately $1.77 per barrel. The Phase 5 Looping surcharge increased primarily due to a decrease in forecasted throughput, and the Phase 6 Mainline surcharge decreased in order to return prior period over recoveries to shippers. Both of these surcharges expire at the end of 2016 and any differences in recoveries will be cash settled with the shippers in 2017.

Effective July 1, 2016, FERC Tariff No. 3.19.0 established new delivery points at Grenora, North Dakota and Little Muddy, North Dakota with rates from Reserve, Montana and Grenora, North Dakota (pump-over) to Grenora, Merchant Storage, North Dakota and from Little Muddy, North Dakota (pump-over) to Little Muddy, Merchant Storage, North Dakota.

Also effective July 1, 2016, FERC Tariff No. 3.20.0 decreased rates in compliance with the indexed rate ceilings allowed by the FERC, which incorporates the multiplier of 0.979865 issued by the FERC on May 19, 2016 in Docket No. RM93-11-000.

Additionally, under the Transportation Services Agreement, or TSA, this tariff adjusted the operating cost charge component of the committed trunkline rates to Berthold, North Dakota to the actual operating costs and throughput volumes for 2015 and the forecasted operating costs and throughput for 2016. Lastly, this tariff discounted the terminal charge for gathering or truck unloading at Little Muddy, North Dakota from the established 2016 ceiling rate of $0.2227 to $0.01 per barrel.

Bakken System

Effective July 1, 2016, FERC Tariff No. 2.3.0 decreased rates in compliance with the indexed rate ceilings allowed by the FERC, which incorporates the multiplier of 0.979865 issued by the FERC on May 19, 2016, in Docket No. RM93-11-000.

Also effective July 1, 2016, FERC tariff No. 3.5.0 adjusted rates in accordance with the TSA that was included in the Petition for Declaratory Order filed on August 26, 2010 in Docket No. OR10-19-000. Additionally, as per the TSA, this tariff adjusted the operating cost charge component of the committed international joint rates to Cromer, Manitoba to the actual operating costs and throughput volumes for 2015 and the forecasted operating costs and throughput for 2016.

Ozark System

Effective December 1, 2015, our Ozark system filed FERC Tariff 48.6.0 to increase its rate from $0.6759 to $0.8403. This filing was made to allow for recovery of costs related to the capital expenditures required to maintain the integrity of the pipeline. As a result of this filing, our Ozark system was not eligible to adjust its rate effective July 1, 2016, in compliance with indexed rate ceilings allowed by the FERC.

SUBSEQUENT EVENTS

Distribution to Partners

On October 28, 2016, the board of directors of Enbridge Management declared a distribution payable to our partners on November 14, 2016. The distribution will be paid to unitholders of record as of November 7, 2016 of our available cash of $263.7 million at September 30, 2016, or $0.5830 per limited partner unit. Of this distribution, $216.1 million will be paid in cash, $46.6 million will be distributed in i-units to our i-unitholder, Enbridge Management, and due to the i-unit distribution, $1.0 million will be retained from our General Partner from amounts otherwise distributable to it in respect of its general partner interest and limited partner interest to maintain its 2% general partner interest.

Distribution to Series EA Interests

On October 28, 2016, 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 a holder of the Series EA interests, declared a distribution payable to the holders of the Series EA general and limited partner interests. The OLP will pay $64.7 million to the noncontrolling interest in the Series EA, while $21.6 million will be paid to us.

62

Distribution to Series ME Interests

On October 28, 2016, 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 a holder of the Series ME interests, declared a distribution payable to the holders of the Series ME general and limited partner interests. The OLP will pay $44.3 million to the noncontrolling interest in the Series ME, while $14.8 million will be paid to us.

Distribution from MEP

On October 27, 2016, the board of directors of Midcoast Holdings, L.L.C., the general partner of MEP, declared a cash distribution payable to their partners on November 14, 2016. The distribution will be paid to unitholders of record as of November 7, 2016, of MEP’s available cash of $16.5 million at September 30, 2016, or $0.3575 per limited partner unit. MEP will pay $7.6 million to their public Class A common unitholders, while $8.9 million in the aggregate will be paid to us with respect to our Class A common units, our subordinated units, and to Midcoast Holdings, L.L.C. with respect to its general partner interest.

Midcoast Operating Distribution

On October 27, 2016, the general partner of Midcoast Operating declared a cash distribution by Midcoast Operating payable on November 14, 2016 to its partners of record as of November 7, 2016. Midcoast Operating will pay $14.4 million to us and $26.0 million to MEP.

During any quarter until the quarter ending December 31, 2017, if MEP’s quarterly declared distribution exceeds its distributable cash, as that term is defined in Midcoast Operating’s limited partnership agreement, we receive a decreased quarterly distribution from Midcoast Operating, and MEP receives a corresponding increase to its quarterly distribution in the amount that MEP’s declared distribution exceeds its distributable cash. Midcoast Operating’s adjustment of our distribution will be limited by our pro rata share of the Midcoast Operating quarterly cash distribution and a maximum of $0.005 per unit quarterly distribution increase by MEP. There is no requirement for MEP to compensate us for these adjusted distributions, except for settling our capital accounts with Midcoast Operating in a liquidation scenario. For the three and nine months ended September 30, 2016, our quarterly distribution from Midcoast Operating was reduced by $5.1 million and $8.2 million, respectively.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The following should be read in conjunction with the information presented in our Annual Report on Form 10-K for the fiscal year ended December 31, 2015, filed on February 17, 2016, in addition to information presented in Items 1 and 2 of this Quarterly Report on Form 10-Q. There have been no material changes to that information other than as presented below.

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 NGLs and condensate sales and the corresponding cost of natural gas 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 (i.e., 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 of our cash flows. Based on our risk management policies, all of our derivative financial instruments are employed in connection with an underlying asset, liability and/or forecasted transaction and are not entered into with the objective of speculating on interest rates or commodity prices.

63

Interest Rate Derivatives

The table below provides information about our derivative financial instruments that we use to hedge the interest payments on our variable rate debt obligations that are sensitive to changes in interest rates and to lock in the interest rate on anticipated issuances of debt in the future. For interest rate swaps, the table presents notional amounts, the rates charged on the underlying notional amounts and weighted-average interest rates paid by expected maturity dates. Notional amounts are used to calculate the contractual payments to be exchanged under the contract. Weighted-average variable rates are based on implied forward rates in the yield curve at September 30, 2016.

	Accounting Treatment		Notional		Average Fixed Rate(1)			Fair Value(2) at
Date of Maturity & Contract Type								September 30, 2016			December 31, 2015
			(dollars in millions)
Contracts maturing in 2017
Interest Rate Swaps – Pay Fixed		Cash Flow Hedge	$	500		2.21	%	$	(2.0	)	$	(7.0	)
Contracts maturing in 2018
Interest Rate Swaps – Pay Fixed		Cash Flow Hedge	$	810		2.24	%	$	(11.2	)	$	(6.6	)
Contracts maturing in 2019
Interest Rate Swaps – Pay Fixed		Cash Flow Hedge	$	620		2.96	%	$	(11.1	)	$	(6.0	)
Contracts settling prior to maturity
2016 – Pre-issuance Hedges		Cash Flow Hedge	$	500		4.21	%	$	(127.0	)	$	(80.4	)
2017 – Pre-issuance Hedges		Cash Flow Hedge	$	500		3.69	%	$	(96.8	)	$	(49.2	)
2018 – Pre-issuance Hedges		Cash Flow Hedge	$	350		3.08	%	$	(44.3	)	$	(12.2	)

⁽¹⁾ Interest rate derivative contracts are based on the one-month or three-month London Interbank Offered Rate, or LIBOR.

⁽²⁾ The fair value is determined from quoted market prices at September 30, 2016 and December 31, 2015, respectively, discounted using the swap rate for the respective periods to consider the time value of money. Fair values exclude credit valuation adjustment gains of approximately $3.1 million and $3.9 million at September 30, 2016 and December 31, 2015, respectively.

64

Fair Value Measurements of Commodity Derivatives

The following table provides summarized information about the fair values of expected cash flows of our outstanding commodity based swaps and physical contracts at September 30, 2016 and December 31, 2015.

	At September 30, 2016													At December 31, 2015
					Wtd. Average Price(2)				Fair Value(3)					Fair Value(3)
	Commodity		Notional(1)		Receive		Pay		Asset		Liability			Asset		Liability
									(in millions)
Portion of contracts maturing in 2016
Swaps
Receive variable/pay fixed		Natural Gas		16,287	$	2.86	$	3.48	$	—	$	—		$	—	$	—
		NGL		2,694,200	$	26.38	$	24.49	$	5.7	$	(0.6	)	$	0.2	$	(8.4	)
		Crude Oil		169,400	$	48.75	$	62.50	$	0.5	$	(2.8	)	$	—	$	(17.5	)
Receive fixed/pay variable		NGL		5,040,200	$	23.97	$	24.96	$	3.2	$	(8.2	)	$	18.3	$	(0.2	)
		Crude Oil		391,836	$	57.18	$	48.78	$	4.2	$	(0.9	)	$	25.4	$	—
Receive variable/pay variable		Natural Gas		5,708,000	$	3.05	$	3.01	$	0.3	$	(0.1	)	$	0.1	$	(0.1	)
Physical Contracts
Receive variable/pay fixed		NGL		1,127,893	$	25.14	$	23.43	$	2.0	$	(0.1	)	$	—	$	(0.2	)
		Crude Oil		—	$	—	$	—	$	—	$	—		$	—	$	(0.2	)
Receive fixed/pay variable		NGL		1,359,447	$	21.30	$	23.31	$	0.8	$	(3.6	)	$	1.9	$	(0.2	)
Receive variable/pay variable		Natural Gas		19,810,834	$	2.83	$	2.84	$	0.1	$	(0.3	)	$	—	$	(2.8	)
		NGL		3,794,987	$	23.37	$	23.07	$	1.7	$	(0.5	)	$	4.0	$	(2.4	)
		Crude Oil		383,298	$	44.16	$	47.84	$	0.3	$	(1.8	)	$	0.7	$	(0.5	)
Portion of contracts maturing in 2017
Swaps
Receive variable/pay fixed		Natural Gas		989,030	$	2.89	$	2.91	$	—	$	—		$	—	$	—
		NGL		2,417,500	$	22.03	$	21.62	$	2.7	$	(1.7	)	$	—	$	(4.5	)
		Crude Oil		638,750	$	51.66	$	64.29	$	0.2	$	(8.2	)	$	—	$	(10.9	)
Receive fixed/pay variable		NGL		3,090,000	$	22.70	$	23.70	$	1.2	$	(4.3	)	$	3.3	$	(0.1	)
		Crude Oil		866,510	$	59.89	$	51.66	$	8.2	$	(1.1	)	$	10.9	$	—
Receive variable/pay variable		Natural Gas		12,550,000	$	3.12	$	3.03	$	1.1	$	(0.1	)	$	0.5	$	(0.2	)
Physical Contracts
Receive variable/pay fixed		NGL		45,000	$	23.42	$	21.96	$	0.1	$	—		$	—	$	—
Receive fixed/pay variable		NGL		45,781	$	25.46	$	25.39	$	0.1	$	(0.1	)	$	—	$	—
Receive variable/pay variable		Natural Gas		11,843,834	$	3.08	$	3.06	$	0.2	$	—		$	0.1	$	—
		NGL		1,262,231	$	26.68	$	25.59	$	1.4	$	—		$	—	$	—
Portion of contracts maturing in 2018
Physical Contracts
Receive variable/pay variable		Natural Gas		2,193,804	$	2.93	$	2.90	$	0.1	$	—		$	0.1	$	—
		NGL		456,250	$	23.15	$	21.26	$	0.8	$	—		$	—	$	—
Portion of contracts maturing in 2019
Physical Contracts
Receive variable/pay variable		Natural Gas		2,199,798	$	2.86	$	2.83	$	0.1	$	—		$	0.1	$	—
Portion of contracts maturing in 2020
Physical Contracts
Receive variable/pay variable		Natural Gas		365,634	$	3.11	$	3.08	$	—	$	—		$	—	$	—

⁽¹⁾ Volumes of natural gas are measured in MMBtu, whereas volumes of NGLs and crude oil are measured in Bbl.

⁽²⁾ Weighted-average prices received and paid are in $/MMBtu for natural gas and $/Bbl for NGLs and crude oil.

⁽³⁾ The fair value is determined based on quoted market prices at September 30, 2016 and December 31, 2015, respectively, discounted using the swap rate for the respective periods to consider the time value of money. Fair values exclude credit valuation adjustment gains of approximately $0.1 million and $0.5 million at September 30, 2016 and December 31, 2015, respectively, as well as cash collateral received.

65

The following table provides summarized information about the fair values of expected cash flows of our outstanding commodity options at September 30, 2016 and December 31, 2015.

	At September 30, 2016													At December 31, 2015
	Commodity		Notional(1)		Strike Price(2)		Market Price(2)		Fair Value(3)					Fair Value(3)
									Asset		Liability			Asset		Liability
									(in millions)
Portion of option contracts maturing in 2016
Puts (purchased)		Natural Gas		414,000	$	3.75	$	3.00	$	0.3	$	—		$	2.1	$	—
		NGL		745,200	$	39.29	$	27.70	$	9.2	$	—		$	54.4	$	—
		Crude Oil		202,400	$	75.91	$	49.00	$	5.4	$	—		$	27.7	$	—
Calls (written)		Natural Gas		414,000	$	4.98	$	3.00	$	—	$	—		$	—	$	—
		NGL		745,200	$	45.09	$	27.70	$	—	$	(0.3	)	$	—	$	(0.3	)
		Crude Oil		202,400	$	86.68	$	49.00	$	—	$	—		$	—	$	—
Puts (written)		Natural Gas		414,000	$	3.75	$	3.00	$	—	$	(0.3	)	$	—	$	(2.1	)
		NGL		59,800	$	37.04	$	28.98	$	—	$	(0.6	)	$	—	$	(1.5	)
Calls (purchased)		Natural Gas		414,000	$	4.98	$	3.00	$	—	$	—		$	—	$	—
		NGL		59,800	$	42.09	$	28.98	$	—	$	—		$	—	$	—
Portion of option contracts maturing in 2017
Puts (purchased)		NGL		1,642,500	$	25.90	$	29.51	$	5.5	$	—		$	5.8	$	—
		Crude Oil		638,750	$	59.86	$	51.66	$	7.6	$	—		$	10.0	$	—
Calls (written)		NGL		1,642,500	$	30.06	$	29.51	$	—	$	(8.0	)	$	—	$	(0.8	)
		Crude Oil		638,750	$	68.19	$	51.66	$	—	$	(1.2	)	$	—	$	(0.6	)
Portion of option contracts maturing in 2018
Puts (purchased)		Crude Oil		91,250	$	42.00	$	53.58	$	0.3	$	—		$	—	$	—
Calls (written)		Crude Oil		91,250	$	51.75	$	53.58	$	—	$	(0.8	)	$	—	$	—

⁽¹⁾ Volumes of natural gas are measured in MMBtu, whereas volumes of NGLs and crude oil are measured in Bbl.

⁽²⁾ Strike and market prices are in $/MMBtu for natural gas and in $/Bbl for NGLs and crude oil.

⁽³⁾ The fair value is determined based on quoted market prices at September 30, 2016 and December 31, 2015, respectively, discounted using the swap rate for the respective periods to consider the time value of money. Fair values exclude credit valuation adjustment losses of approximately $0.4 million at December 31, 2015 as well as cash collateral received.

Our credit exposure for OTC derivatives is directly with our counterparty and continues until the maturity or termination of the contract. When appropriate, valuations are adjusted for various factors such as credit and liquidity considerations. The table below summarizes our derivatives balances by counterparty credit quality (any negative amounts represent our net obligations to pay the counterparty).

	September 30, 2016			December 31, 2015
	(in millions)
Counterparty Credit Quality(1)
AA(2)		(99.1	)		(12.4	)
A		(109.1	)		(10.5	)
Lower than A		(63.3	)		(35.0	)
	$	(271.5	)	$	(57.9	)

⁽¹⁾ As determined by nationally-recognized statistical ratings organizations.

⁽²⁾ Includes $12.6 million held of cash collateral at December 31, 2015.

Item 4. Controls and Procedures

We and Enbridge maintain systems of disclosure controls and procedures designed to provide reasonable assurance that we are able to record, process, summarize and report the information required to be disclosed in the reports that we file or submit under the Securities Exchange Act of 1934, as amended, or the Exchange Act, within the time periods specified in the rules and forms of the Securities and Exchange Commission, and that such information is accumulated and communicated to our management, including our principal executive and principal financial officers, as appropriate, to allow timely decisions regarding required disclosure. Our management, with the participation of our principal executive and principal financial officers, has evaluated the effectiveness of our disclosure controls and procedures as of September 30, 2016. Based upon that evaluation, our principal executive and principal financial officers concluded that our disclosure controls and procedures are effective at the reasonable

66

assurance level. In conducting this assessment, our management relied on similar evaluations conducted by employees of Enbridge affiliates who provide certain treasury, accounting and other services on our behalf.

There have been no changes in internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting during the three months ended September 30, 2016.

PART II — OTHER INFORMATION

Item 1. Legal Proceedings

Refer to Part I, Item 1. Financial Statements, Note 11. Commitments and Contingencies, which is incorporated herein by reference.

Item 1A. Risk Factors

The risk factor presented below updates and should be considered in addition to our risk factors previously disclosed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2015, filed with the SEC on February 17, 2016.

Changes in, or challenges to, our rates could have a material adverse effect on our financial condition and results of operations.

The rates charged by several of our pipeline systems are regulated by the FERC or state regulatory agencies, or both. If one of these regulatory agencies, on its own initiative or due to challenges by third parties, were to lower our tariff rates, the profitability of our pipeline businesses would suffer.

Under current policy, the FERC permits interstate pipelines that are subject to cost of service regulation to include an income tax allowance when calculating their regulated rates. The FERC’s income tax allowance policy has been the subject of challenge, and we cannot predict whether the FERC or a reviewing court will alter the existing policy. For example, on July 1, 2016, the U.S. Court of Appeals for the District of Columbia Circuit issued a decision that calls into question a decade of FERC policy and precedent permitting regulated companies organized as pass-through entities for income tax purposes to include an allowance for income taxes in their rates. The court has remanded the case to the FERC to allow it to have an opportunity to provide a reasoned basis for its decision on income tax allowances for partnership pipelines. If the FERC’s policy were to change and if the FERC were to disallow a substantial portion of our pipelines’ income tax allowance, our regulated rates, and therefore our revenues and ability to make quarterly cash distributions to our unitholders, could be adversely affected.

If we were permitted to raise our tariff rates for a particular pipeline, there might be significant delay between the time the tariff rate increase is approved and the time that the rate increase actually goes into effect, which if delayed could further reduce our cash flow. Furthermore, competition from other pipeline systems may prevent us from raising our tariff rates even if regulatory agencies permit us to do so. The regulatory agencies that regulate our systems periodically implement new rules, regulations and terms and conditions of services subject to their jurisdiction. New initiatives or orders may adversely affect the rates charged for our services.

We believe that the rates we charge for transportation services on our interstate common carrier oil and open access natural gas pipelines are just and reasonable under the ICA and NGA, respectively. However, because the rates that we charge are subject to review upon an appropriately supported protest or complaint, or a regulator’s own initiative, we cannot predict what rates we will be allowed to charge in the future for service on our interstate common carrier oil and open access natural gas pipelines. Furthermore, because rates charged for transportation services must be competitive with those charged by other transporters, the rates set forth in our tariffs will be determined based on competitive factors in addition to regulatory considerations.

Item 6. Exhibits

Reference is made to the “Index of Exhibits” following the signature page, which we hereby incorporate into this Item.

67

SIGNATURES

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

	Enbridge Energy Partners, L.P. (Registrant)
	By: Enbridge Energy Management, L.L.C. as delegate of Enbridge Energy Company, Inc. as General Partner
Date: October 31, 2016	By: /s/ Mark A. Maki Mark A. Maki President and Principal Executive Officer
Date: October 31, 2016	By: /s/ Stephen J. Neyland Stephen J. Neyland Vice President — Finance (Principal Financial Officer)

68

Index of Exhibits

Each exhibit identified below is filed as a part of this Quarterly Report on Form 10-Q. Exhibits included in this filing are designated by an asterisk; all exhibits not so designated are incorporated by reference to a prior filing as indicated.

Exhibit Number	Description
10.1*	Limited Liability Company Agreement of MarEn Bakken Company LLC dated as of August 2, 2016.
10.2*	Membership Interest Purchase Agreement dated as of August 2, 2016 by and between Bakken Holdings Company LLC and MarEn Bakken Company LLC.
10.3*	New Lender Joinder Agreement, dated July 28, 2016 by and among Enbridge Energy Partners, L.P., The Huntington National Bank, Bank of America, N.A., as administrative agent, swing line lender and letter of credit issuer, and Royal Bank of Canada, as letter of credit issuer.
10.4	Credit Agreement dated as of June 26, 2016, by and among Enbridge Energy Partners, L.P. and Enbridge (U.S.) Inc. (incorporated by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q, filed on July 29, 2016).
31.1*	Certification of Principal Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification of Principal Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*	Certification of Principal Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*	Certification of Principal Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*	XBRL Instance Document.
101.SCH*	XBRL Taxonomy Extension Schema Document.
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF*	XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB*	XBRL Taxonomy Extension Label Linkbase Document.
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase Document.

69

XML

Document And Entity Information - shares	9 Months Ended
	Sep. 30, 2016	Oct. 28, 2016
Document Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2016
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q3
Entity Registrant Name	ENBRIDGE ENERGY MANAGEMENT L L C
Entity Central Index Key	0001173911
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Trading Symbol	EEQ
Entity Common Stock, Shares Outstanding		79,995,975

XML

STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Equity loss from investment in Enbridge Energy Partners, L.P. (Note 1)		$ (1.9)	$ (117.3)	$ (120.0)	$ (192.3)
Loss before income tax benefit (expense)		(1.9)	(117.3)	(120.0)	(192.3)
Income tax benefit (expense) (Note 3)	[1]	0.6	(160.5)	1.2	(132.8)
Net loss		$ (1.3)	$ (277.8)	$ (118.8)	$ (325.1)
Net loss per share, (basic and diluted) (in dollars per shares)		$ (0.02)	$ (3.91)	$ (1.54)	$ (4.65)
Weighted average shares outstanding (in shares)		79.1	71.7	76.9	69.9

[1] Amortization of accumulated other comprehensive income into earnings is recorded before tax to recognize the related tax benefit. Recognition of the tax benefit in earnings does not impact the balance of the deferred tax asset and associated full valuation allowance, which were previously recorded when the losses were reflected in Other Comprehensive Income.

XML

STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Net loss	$ (1.3)	$ (277.8)	$ (118.8)	$ (325.1)
Equity in other comprehensive income (loss) of Enbridge Energy Partners, L.P., net of tax expense (benefit) of $0.6 million, $(10.0) million, $1.2 million and $(14.4) million, respectively	1.3	(16.5)	(13.7)	(24.1)
Comprehensive loss	$ 0.0	$ (294.3)	$ (132.5)	$ (349.2)

XML

STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Other comprehensive income (loss), tax benefit	$ 0.6	$ (10.0)	$ 1.2	$ (14.4)

XML

STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Cash provided by operating activities:
Net loss	$ (118.8)	$ (325.1)
Adjustments to reconcile net loss to net cash in operating activities:
Equity loss from investment in Enbridge Energy Partners, L.P.	120.0	192.3
Changes in operating assets and liabilities:
Due from affiliates	0.0	0.2
Due to affiliates	0.0	(0.1)
Deferred income taxes	(1.2)	132.8
Net cash provided by operating activities	0.0	0.1
Cash used in investing activities:
Net cash used in investing activities	0.0	0.0
Cash provided by financing activities:
Net cash provided by financing activities	0.0	0.0
Net increase in cash and cash equivalents	0.0	0.1
Cash and cash equivalents at beginning of year	0.8	0.7
Cash and cash equivalents at end of period	$ 0.8	$ 0.8

XML

STATEMENTS OF FINANCIAL POSITION - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
ASSETS
Cash	$ 0.8	$ 0.8
Investment in Enbridge Energy Partners, L.P. (Note 2)	0.0	132.5
Assets, Total	0.8	133.3
LIABILITIES AND SHAREHOLDERS' EQUITY
Commitments and contingencies
Shareholders' equity (Note 2)
Voting shares - unlimited authorized; 6.03 and 5.53 issued and outstanding at September 30, 2016 and December 31, 2015, respectively	0.0	0.0
Listed shares - unlimited authorized; 79,995,975 and 73,285,734 issued and outstanding at September 30, 2016 and December 31, 2015, respectively	1,576.3	1,443.8
Accumulated deficit	(1,517.7)	(1,266.4)
Accumulated other comprehensive loss	(57.8)	(44.1)
Total liabilities and stockholders' equity	$ 0.8	$ 133.3

XML

STATEMENTS OF FINANCIAL POSITION (Parenthetical) - shares	Sep. 30, 2016	Dec. 31, 2015
Voting Shares [Member]
Issued (in shares)	6.03	5.53
Outstanding (in shares)	6.03	5.53
Listed Shares [Member]
Issued (in shares)	79,995,975	73,285,734
Outstanding (in shares)	79,995,975	73,285,734

XML

BASIS OF PRESENTATION

9 Months Ended

Sep. 30, 2016

Organization, Consolidation and Presentation of Financial Statements [Abstract]

BASIS OF PRESENTATION

1. BASIS OF PRESENTATION

We are a limited partner of Enbridge Energy Partners, L.P., which we refer to as the Partnership, through our ownership of i-units, a special class of the Partnership’s limited partner interests. Under a delegation of control agreement among us, the Partnership and its general partner, Enbridge Energy Company, Inc., referred to as the General Partner, we manage the Partnership’s business and affairs. The General Partner is an indirect, wholly-owned subsidiary of Enbridge Inc., an energy company based in Calgary, Alberta, Canada that we refer to herein as Enbridge.

We have prepared the accompanying unaudited interim financial statements in accordance with generally accepted accounting principles in the United States of America, or GAAP, for interim financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. Accordingly, they do not include all the information and footnotes required by GAAP for complete financial statements. In the opinion of management, they contain all adjustments, consisting only of normal recurring adjustments, which management considers necessary to present fairly our financial position at September 30, 2016, our results of operations for the three and nine months ended September 30, 2016 and 2015 and our cash flows for the nine months ended September 30, 2016 and 2015. We derived our statements of financial position as of December 31, 2015 from the audited financial statements included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2015. Our results of operations for the three and nine months ended September 30, 2016 and 2015 should not be taken as indicative of the results to be expected for the full year.

The unaudited interim financial statements should be read in conjunction with our financial statements and notes thereto presented in our Annual Report on Form 10-K for the fiscal year ended December 31, 2015. Our results of operations, financial position and cash flows are dependent on the results of operations, financial position and cash flows of the Partnership. As a result, these unaudited interim financial statements should also be read in conjunction with the Partnership’s audited consolidated financial statements and notes thereto presented in its Annual Report on Form 10-K for the fiscal year ended December 31, 2015, as well as the Partnership’s unaudited interim consolidated financial statements presented in its Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2016.

Variable Interest Entities

On January 1, 2016, we adopted Accounting Standards Update No. 2015-02, which amended consolidation guidance to, among other things, eliminate the specialized consolidation model and guidance for limited partnerships, including the presumption that the general partner should consolidate a limited partnership. As a result, we have determined that the Partnership, which historically has not been consolidated by us under this presumption as we are not the general partner, is a variable interest entity, or VIE. Further, we determined that we are not the primary beneficiary of the Partnership. While the amended guidance did not impact our conclusion that the Partnership should not be consolidated, because the Partnership is now considered a VIE, additional disclosures are necessary. We have applied this amended guidance retrospectively to our disclosures.

Upon inception of a contractual agreement, we perform an assessment to determine whether the arrangement contains a variable interest in a legal entity and whether that legal entity is a VIE. We assess all aspects of our interests in an entity and use judgment when determining if we are the primary beneficiary. The primary beneficiary has both the power to direct the activities of the VIE that most significantly impact the entity’s economic performance and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. Other qualitative factors that are considered include decision-making responsibilities, the VIE capital structure, risk and rewards sharing, contractual agreements with the VIE, voting rights and level of involvement of other parties. A reassessment of the primary beneficiary conclusion is conducted when there are changes in the facts and circumstances related to a VIE.

As discussed above, we are a limited partner of the Partnership, through our ownership of i-units, a special class of the Partnership’s limited partner interests. At September 30, 2016, we owned approximately 16.3% of the Partnership through our ownership of the i-units. Further, under a delegation of control agreement among us, the Partnership and the General Partner, we manage the Partnership’s business and affairs. However, the General Partner has the ultimate responsibility to direct the activities that most significantly impact the Partnership’s economic performance. Further, the General Partner has the power to direct the activities that most significantly impact our economic performance through its 100% ownership interest in our voting shares. As a result, we have determined that we are not the primary beneficiary of the Partnership.

Partnership Incentive and Other Distributions

The General Partner receives distributions from the Partnership through a wholly-owned subsidiary’s ownership of Incentive Distribution Units, or IDUs, on the portion of cash distributions that exceed certain target thresholds on a per unit basis under the Seventh Amended and Restated Agreement of the Limited Partnership of the Partnership dated as of January 2, 2015, as amended, or the Partnership Agreement. The IDUs entitle the holder thereof to receive 23% of the incremental cash distributions paid by the Partnership in excess of $0.5435 per unit per quarter on its Class A and Class B common units, collectively, the common units, the i-units we own, the Class D Units, and the Class E Units.

In addition, the General Partner receives distributions from the Partnership through its ownership of Preferred Units, Class D units, and Class E units. The Preferred Units are entitled to annual distributions of 7.50% of the issue price, payable quarterly. Class D and Class E units entitle the holders thereof to receive quarterly distributions equal to the amount derived by multiplying the number of Class D and Class E units outstanding by the distribution rate on the Partnership’s common units and i-units.

Distributions to holders of the IDUs, Preferred Units, Class D units, and Class E units reduce the amount of income that is allocated to the Partnership’s remaining limited partners: (1) Class A common units, (2) Class B common units, and (3) i-units on a pro-rata basis based on our ownership interest in the Partnership. Thus, our “Equity income (loss) from the investment in Enbridge Energy Partners, L.P.” on our statements of income reflects our pro-rata share of these allocations every quarter.

The Partnership Agreement does not permit capital deficits to accumulate in the capital account of any limited partner and thus requires that such capital account deficits brought to zero, or “cured,” by additional allocations from the positive capital accounts of the common units, i-units, and General Partner, generally on a pro-rata basis. Our equity income from the Partnership is adjusted for our pro-rata share of such reallocations. Until we discontinued equity accounting for our investment in the Partnership on March 31, 2016, our equity earnings were reduced by $121.3 million, for our pro-rata share of the allocation needed to cure the capital account deficits of the Class A and Class B common units.

During the first quarter of 2016, our share of losses in the Partnership, driven primarily from curing losses, exceeded the carrying amount of our investment in the Partnership. As a result, we ceased recognition of our equity interest in the earnings of the Partnership when the carrying amount of our investment was reduced to zero and will no longer provide for additional losses as we are not obligated to provide further financial support to the Partnership. Further, our accumulated other comprehensive income is comprised of our historical interest in the Partnership’s other comprehensive income, which is based primarily on the effective mark-to-market changes in the Partnership’s underlying cash flow hedge contracts. We will amortize into earnings the remaining accumulated other comprehensive loss on a straight-line basis over the remaining term of the Partnership’s underlying hedge contracts.

XML

SHAREHOLDERS' EQUITY

9 Months Ended

Sep. 30, 2016

Stockholders' Equity Note [Abstract]

SHAREHOLDERS’ EQUITY

2. SHAREHOLDERS’ EQUITY

The following table presents significant changes in Shareholders’ equity during the nine months ended September 30, 2016 and 2015.

	For the nine months ended
	September 30,
	2016		2015
	(in millions)
Listed Shares:
Beginning balance	$	1,443.8	$	1,358.0
Capital account adjustments		—		(75.6)
Share distributions		132.5		119.5
Ending balance	$	1,576.3	$	1,401.9
Accumulated deficit:
Beginning balance	$	(1,266.4)	$	(592.7)
Net loss		(118.8)		(325.1)
Share distributions		(132.5)		(119.5)
Ending balance	$	(1,517.7)	$	(1,037.3)
Accumulated other comprehensive loss:
Beginning balance	$	(44.1)	$	(23.7)
Equity in other comprehensive income of the Partnership		(13.7)		(24.1)
Ending balance	$	(57.8)	$	(47.8)
Total Shareholders’ equity	$	0.8	$	316.8

Share Distributions

The following table sets forth the details regarding our share distributions, as approved by our board of directors, for the nine months ended September 30, 2016:

Distribution Declaration Date	Record Date	Distribution Payment Date	Distribution per Unit of the Partnership		Average Closing Price of the Listed Shares		Additional i-units Owned	Listed Shares Distributed to Public	Shares Distributed to General Partner
			(in millions, except per unit and per share amounts)
July 28, 2016	August 5, 2016	August 12, 2016	$	0.5830	$	22.84	1,991,304	1,758,587	232,717
April 29, 2016	May 6, 2016	May 13, 2016	$	0.5830	$	21.14	2,093,257	1,848,626	244,631
January 29, 2016	February 5, 2016	February 12, 2016	$	0.5830	$	16.27	2,625,681	2,318,827	306,854

We had non-cash operating activities in the form of i-units distributed to us by the Partnership and corresponding non-cash financing activities in the form of share distributions to our shareholders in the amounts of $132.5 million and $119.5 million during the nine months ended September 30, 2016 and 2015, respectively.

XML

INCOME TAXES

9 Months Ended

Sep. 30, 2016

Income Tax Disclosure [Abstract]

INCOME TAXES

3. INCOME TAXES

The terms of the i-units provide that the units owned by us will not be allocated income, gain, loss or deductions of the Partnership for tax purposes until such time that we dispose of our investment in the Partnership. As a result, actual realization of any long-term deferred income tax asset or liability would only occur upon liquidation of our investment in the Partnership.

Based on the estimates of our future operating income included in our forecasts, including curing impacts, we have concluded that it is not more likely than not that our deferred tax assets will be realized. As a result, we continue to maintain a full valuation allowance on those tax assets as of September 30, 2016.

The effective income tax rates for the three and nine months ended September 30, 2016 and 2015 are presented in the following table.

	For the three months						For the nine months
	ended September 30,						ended September 30,
	2016			2015			2016			2015
	(unaudited; in millions except for tax rate amounts)
Loss before income tax benefit	$	(1.9)		$	(117.3)		$	(120.0)		$	(192.3)
Income tax benefit (expense)		0.6			44.2			44.3			71.9
Tax Rate change		(3.7)			0.3			(3.7)			0.3
Valuation allowance		3.7			(205.0)			(39.4)			(205.0)
Total income tax benefit (expense)(1)	$	0.6		$	(160.5)		$	1.2		$	(132.8)
Effective income tax rate		31.6	%		(136.8)	%		1.0	%		(69.1)	%

⁽¹⁾ Amortization of accumulated other comprehensive income into earnings is recorded before tax to recognize the related tax benefit. Recognition of the tax benefit in earnings does not impact the balance of the deferred tax asset and associated full valuation allowance, which were previously recorded when the losses were reflected in Other Comprehensive Income.

XML

SUMMARIZED FINANCIAL INFORMATION FOR ENBRIDGE ENERGY PARTNERS, L.P.

9 Months Ended

Sep. 30, 2016

Equity Method Investment, Summarized Financial Information [Abstract]

SUMMARIZED FINANCIAL INFORMATION FOR ENBRIDGE ENERGY PARTNERS, L.P.

4. SUMMARIZED FINANCIAL INFORMATION FOR ENBRIDGE ENERGY PARTNERS, L.P.

	For the three months				For the nine months
	ended September 30,				ended September 30,
	2016		2015		2016		2015
	(in millions)
Operating revenue	$	1,120.6	$	1,267.7	$	3,231.1	$	4,009.4
Operating expenses		1,599.5		1,012.9		3,180.3		3,524.6
Operating income (loss)	$	(478.9)	$	254.8	$	50.8	$	484.8
Net income (loss)	$	(574.6)	$	184.5	$	(224.5)	$	341.8
Less: Net income (loss) attributable to:
Noncontrolling interest		(191.9)		77.8		(52.8)		139.1
Series 1 preferred unit distributions		22.5		22.5		67.5		67.5
Accretion of discount on Series 1 Preferred Units		1.2		2.1		3.5		10.1
Net income (loss) attributable to Enbridge Energy Partners, L.P.	$	(406.4)	$	82.1	$	(242.7)	$	125.1
Less: Net income attributable to the General Partner(1)		46.2		56.0		158.1		162.5
Net income (loss) attributable to common units and i-units(2)	$	(452.6)	$	26.1	$	(400.8)	$	(37.4)

⁽¹⁾ Net income attributable to the General Partner includes net income attributable to the general partner interest as well as to Class D units, Class E units, and IDUs.

⁽²⁾ The Partnership allocates its net income among the holders of Preferred Units, the General Partner and limited partners first using preferred unit distributions and then the two-class method in accordance with applicable authoritative accounting guidance. Under the two-class method, the Partnership allocates its net income, after noncontrolling interest and preferred unit distributions, to the General Partner and its limited partners, including us, according to the distribution formula for available cash as set forth in the Partnership Agreement.

We owned approximately 16.3% and 14.8% of the Partnership at September 30, 2016 and 2015, respectively.

XML

SUBSEQUENT EVENTS

9 Months Ended

Sep. 30, 2016

Subsequent Events [Abstract]

SUBSEQUENT EVENTS

5. SUBSEQUENT EVENTS

Share Distribution

On October 28, 2016, our board of directors declared a share distribution payable on November 14, 2016, to shareholders of record as of November 7, 2016, based on the $0.5830 per limited partner unit distribution declared by the Partnership. The Partnership’s distribution increases the number of i-units that we own. The amount of this increase is calculated by dividing the cash amount distributed by the Partnership per common unit by the average closing price of one of our Listed Shares on the New York Stock Exchange for the 10 trading day period immediately preceding the ex-dividend date for our shares, multiplied by the number of shares outstanding on the record date. We distribute additional Listed Shares to our shareholders and additional voting shares to the General Partner in respect of these additional i-units.

XML

SHAREHOLDERS' EQUITY (Tables)

9 Months Ended

Sep. 30, 2016

Stockholders' Equity Note [Abstract]

Schedule of Changes in Shareholders' Equity

The following table presents significant changes in Shareholders’ equity during the nine months ended September 30, 2016 and 2015.

	For the nine months ended
	September 30,
	2016		2015
	(in millions)
Listed Shares:
Beginning balance	$	1,443.8	$	1,358.0
Capital account adjustments		—		(75.6)
Share distributions		132.5		119.5
Ending balance	$	1,576.3	$	1,401.9
Accumulated deficit:
Beginning balance	$	(1,266.4)	$	(592.7)
Net loss		(118.8)		(325.1)
Share distributions		(132.5)		(119.5)
Ending balance	$	(1,517.7)	$	(1,037.3)
Accumulated other comprehensive loss:
Beginning balance	$	(44.1)	$	(23.7)
Equity in other comprehensive income of the Partnership		(13.7)		(24.1)
Ending balance	$	(57.8)	$	(47.8)
Total Shareholders’ equity	$	0.8	$	316.8

Schedule of Share Distribution

The following table sets forth the details regarding our share distributions, as approved by our board of directors, for the nine months ended September 30, 2016:

Distribution Declaration Date	Record Date	Distribution Payment Date	Distribution per Unit of the Partnership		Average Closing Price of the Listed Shares		Additional i-units Owned	Listed Shares Distributed to Public	Shares Distributed to General Partner
			(in millions, except per unit and per share amounts)
July 28, 2016	August 5, 2016	August 12, 2016	$	0.5830	$	22.84	1,991,304	1,758,587	232,717
April 29, 2016	May 6, 2016	May 13, 2016	$	0.5830	$	21.14	2,093,257	1,848,626	244,631
January 29, 2016	February 5, 2016	February 12, 2016	$	0.5830	$	16.27	2,625,681	2,318,827	306,854

XML

INCOME TAXES (Tables)

9 Months Ended

Sep. 30, 2016

Income Tax Disclosure [Abstract]

Schedule of Effective Income Tax Rate Reconciliation

The effective income tax rates for the three and nine months ended September 30, 2016 and 2015 are presented in the following table.

	For the three months						For the nine months
	ended September 30,						ended September 30,
	2016			2015			2016			2015
	(unaudited; in millions except for tax rate amounts)
Loss before income tax benefit	$	(1.9)		$	(117.3)		$	(120.0)		$	(192.3)
Income tax benefit (expense)		0.6			44.2			44.3			71.9
Tax Rate change		(3.7)			0.3			(3.7)			0.3
Valuation allowance		3.7			(205.0)			(39.4)			(205.0)
Total income tax benefit (expense)(1)	$	0.6		$	(160.5)		$	1.2		$	(132.8)
Effective income tax rate		31.6	%		(136.8)	%		1.0	%		(69.1)	%

⁽¹⁾ Amortization of accumulated other comprehensive income into earnings is recorded before tax to recognize the related tax benefit. Recognition of the tax benefit in earnings does not impact the balance of the deferred tax asset and associated full valuation allowance, which were previously recorded when the losses were reflected in Other Comprehensive Income.

XML

SUMMARIZED FINANCIAL INFORMATION FOR ENBRIDGE ENERGY PARTNERS, L.P. (Tables)

9 Months Ended

Sep. 30, 2016

Equity Method Investment, Summarized Financial Information [Abstract]

Schedule of Summarized Financial Information for the Partnership

	For the three months				For the nine months
	ended September 30,				ended September 30,
	2016		2015		2016		2015
	(in millions)
Operating revenue	$	1,120.6	$	1,267.7	$	3,231.1	$	4,009.4
Operating expenses		1,599.5		1,012.9		3,180.3		3,524.6
Operating income (loss)	$	(478.9)	$	254.8	$	50.8	$	484.8
Net income (loss)	$	(574.6)	$	184.5	$	(224.5)	$	341.8
Less: Net income (loss) attributable to:
Noncontrolling interest		(191.9)		77.8		(52.8)		139.1
Series 1 preferred unit distributions		22.5		22.5		67.5		67.5
Accretion of discount on Series 1 Preferred Units		1.2		2.1		3.5		10.1
Net income (loss) attributable to Enbridge Energy Partners, L.P.	$	(406.4)	$	82.1	$	(242.7)	$	125.1
Less: Net income attributable to the General Partner(1)		46.2		56.0		158.1		162.5
Net income (loss) attributable to common units and i-units(2)	$	(452.6)	$	26.1	$	(400.8)	$	(37.4)

⁽¹⁾ Net income attributable to the General Partner includes net income attributable to the general partner interest as well as to Class D units, Class E units, and IDUs.

⁽²⁾ The Partnership allocates its net income among the holders of Preferred Units, the General Partner and limited partners first using preferred unit distributions and then the two-class method in accordance with applicable authoritative accounting guidance. Under the two-class method, the Partnership allocates its net income, after noncontrolling interest and preferred unit distributions, to the General Partner and its limited partners, including us, according to the distribution formula for available cash as set forth in the Partnership Agreement.

XML

BASIS OF PRESENTATION (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended	9 Months Ended
	Mar. 31, 2016	Sep. 30, 2016	Sep. 30, 2015
Preferred Unit distribution rate (as a percentage)		7.50%
General Partner [Member] | Variable Interest Entity, Not Primary Beneficiary [Member]
Ownership percentage of voting shares outstanding		100.00%
First Target Distribution [Member]
Minimum portion of quarterly distribution per unit (in dollars per share)		$ 0.5435
Percentage of incremental distributions (as a percentage)		23.00%
Enbridge Energy Partners LP [Member]
Percentage of ownership in Partnership		16.30%	14.80%
Enbridge Energy Partners LP [Member] | Common Units (A and B) [Member]
Capital account adjustments	$ 121.3
I-Units [Member] | Variable Interest Entity, Not Primary Beneficiary [Member]
Percentage of ownership in Partnership		16.30%

XML

SHAREHOLDERS' EQUITY (Schedule of Changes in Shareholders' Equity) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Net loss	$ (1.3)	$ (277.8)	$ (118.8)	$ (325.1)
Equity in other comprehensive income of the Partnership	1.3	(16.5)	(13.7)	(24.1)
Ending balance	0.8	316.8	0.8	316.8
Accumulated Deficit [Member]
Beginning balance			(1,266.4)	(592.7)
Net loss			(118.8)	(325.1)
Share distributions			(132.5)	(119.5)
Ending balance	(1,517.7)	(1,037.3)	(1,517.7)	(1,037.3)
Accumulated Other Comprehensive Loss [Member]
Beginning balance			(44.1)	(23.7)
Equity in other comprehensive income of the Partnership			(13.7)	(24.1)
Ending balance	(57.8)	(47.8)	(57.8)	(47.8)
Listed Shares [Member]
Beginning balance			1,443.8	1,358.0
Capital account adjustments			0.0	(75.6)
Share distributions			132.5	119.5
Ending balance	$ 1,576.3	$ 1,401.9	$ 1,576.3	$ 1,401.9

XML

SHAREHOLDERS' EQUITY (Schedule of Share Distributions) (Details) - USD ($) $ / shares in Units, $ in Millions	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Distributions [Line Items]
Non-cash financing activities	$ 132.5	$ 119.5
First Quarter Distribution [Member]
Distributions [Line Items]
Distribution Declaration Date	Jan. 29, 2016
Record Date	Feb. 05, 2016
Distribution Payment Date	Feb. 12, 2016
Distribution per Unit of the Partnership (in dollars per share)	$ 0.5830
Additional i-units owned (in shares)	2,625,681
First Quarter Distribution [Member] | Public [Member]
Distributions [Line Items]
Additional i-units owned (in shares)	2,318,827
First Quarter Distribution [Member] | General Partner of Enbridge Energy Partners LP [Member]
Distributions [Line Items]
Additional i-units owned (in shares)	306,854
First Quarter Distribution [Member] | Weighted Average [Member]
Distributions [Line Items]
Closing Price of the Listed Shares (in dollars per share)	$ 16.27
Second Quarter Distribution [Member]
Distributions [Line Items]
Distribution Declaration Date	Apr. 29, 2016
Record Date	May 06, 2016
Distribution Payment Date	May 13, 2016
Distribution per Unit of the Partnership (in dollars per share)	$ 0.5830
Additional i-units owned (in shares)	2,093,257
Second Quarter Distribution [Member] | Public [Member]
Distributions [Line Items]
Additional i-units owned (in shares)	1,848,626
Second Quarter Distribution [Member] | General Partner of Enbridge Energy Partners LP [Member]
Distributions [Line Items]
Additional i-units owned (in shares)	244,631
Second Quarter Distribution [Member] | Weighted Average [Member]
Distributions [Line Items]
Closing Price of the Listed Shares (in dollars per share)	$ 21.14
Third Quarter Distribution [Member]
Distributions [Line Items]
Distribution Declaration Date	Jul. 28, 2016
Record Date	Aug. 05, 2016
Distribution Payment Date	Aug. 12, 2016
Distribution per Unit of the Partnership (in dollars per share)	$ 0.5830
Additional i-units owned (in shares)	1,991,304
Third Quarter Distribution [Member] | Public [Member]
Distributions [Line Items]
Additional i-units owned (in shares)	1,758,587
Third Quarter Distribution [Member] | General Partner of Enbridge Energy Partners LP [Member]
Distributions [Line Items]
Additional i-units owned (in shares)	232,717
Third Quarter Distribution [Member] | Weighted Average [Member]
Distributions [Line Items]
Closing Price of the Listed Shares (in dollars per share)	$ 22.84

XML

INCOME TAXES (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Effective income tax rates we used in computing the income tax provisions:
Loss before income tax benefit		$ (1.9)	$ (117.3)	$ (120.0)	$ (192.3)
Income tax benefit (expense)		0.6	44.2	44.3	71.9
Tax Rate change		(3.7)	0.3	(3.7)	0.3
Valuation allowance		3.7	(205.0)	(39.4)	(205.0)
Total income tax benefit (expense)	[1]	$ 0.6	$ (160.5)	$ 1.2	$ (132.8)
Effective income tax rate		31.60%	(136.80%)	1.00%	(69.10%)

[1] Amortization of accumulated other comprehensive income into earnings is recorded before tax to recognize the related tax benefit. Recognition of the tax benefit in earnings does not impact the balance of the deferred tax asset and associated full valuation allowance, which were previously recorded when the losses were reflected in Other Comprehensive Income.

XML

SUMMARIZED FINANCIAL INFORMATION FOR ENBRIDGE ENERGY PARTNERS, L.P. (Details) - Enbridge Energy Partners LP [Member] - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Operating revenue		$ 1,120.6	$ 1,267.7	$ 3,231.1	$ 4,009.4
Operating expenses		1,599.5	1,012.9	3,180.3	3,524.6
Operating income (loss)		(478.9)	254.8	50.8	484.8
Net income (loss)		(574.6)	184.5	(224.5)	341.8
Less: Net income (loss) attributable to Noncontrolling interest		(191.9)	77.8	(52.8)	139.1
Less: Net income (loss) attributable to Series 1 preferred unit distributions		22.5	22.5	67.5	67.5
Less: Net income attributable to Accretion of discount on Series 1 Preferred Units		1.2	2.1	3.5	10.1
Net income (loss) attributable to Enbridge Energy Partners, L.P.		(406.4)	82.1	(242.7)	125.1
Less: Net income attributable to the General Partner	[1]	46.2	56.0	158.1	162.5
Net income (loss) attributable to common units and i-units	[2]	$ (452.6)	$ 26.1	$ (400.8)	$ (37.4)
Percentage of ownership in Partnership		16.30%	14.80%	16.30%	14.80%

[1] Net income attributable to the General Partner includes net income attributable to the general partner interest as well as to Class D units, Class E units, and IDUs.

[2] The Partnership allocates its net income among the holders of Preferred Units, the General Partner and limited partners first using preferred unit distributions and then the two-class method in accordance with applicable authoritative accounting guidance. Under the two-class method, the Partnership allocates its net income, after noncontrolling interest and preferred unit distributions, to the General Partner and its limited partners, including us, according to the distribution formula for available cash as set forth in the Partnership Agreement.

XML

SUBSEQUENT EVENTS (Details) - Subsequent Event [Member]	1 Months Ended
	Oct. 28, 2016 $ / shares
Subsequent Event [Line Items]
Distribution Declaration Date	Oct. 28, 2016
Distribution Payment Date	Nov. 14, 2016
Record Date	Nov. 07, 2016
Distribution per Unit of the Partnership (in dollars per share)	$ 0.5830
Number of trading days	10 days