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 ~~June~~September 30, 2018



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.)

5400 Westheimer Court

Houston, Texas 77056

(Address of Principal Executive Offices) (Zip Code)

(713) 627-5400

(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, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer x Accelerated filer o Non-accelerated filer o ~~(Do not check if a smaller reporting company)~~ Smaller reporting company o Emerging growth company o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. 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 326,517,110 Class A common units outstanding as of October 30, 2018.

TABLE OF CONTENTS

ENBRIDGE ENERGY PARTNERS, L.P.

TABLE OF CONTENTS

	PART I — FINANCIAL INFORMATION
Item 1.	Financial Statements
	Consolidated Statements of Income for the three and six months ended June 30, 2018 and 2017	1
	Consolidated Statements of Income for the three and nine months ended September 30, 2018 and 2017	1
	Consolidated Statements of Comprehensive Income for the three and six months ended June 30, 2018 and 2017	2
	Consolidated Statements of Comprehensive Income for the three and nine months ended September 30, 2018 and 2017	2
	Consolidated Statements of Cash Flows for the six months ended June 30, 2018 and 2017	3
	Consolidated Statements of Cash Flows for the nine months ended September 30, 2018 and 2017	3
	Consolidated Statements of Financial Position as of June 30, 2018 and December 31, 2017	4
	Consolidated Statements of Financial Position as of September 30, 2018 and December 31, 2017	4
	Consolidated Statements of Partners’ Capital for the six months ended June 30, 2018 and 2017	5
	Consolidated Statements of Partners’ Capital for the nine months ended September 30, 2018 and 2017	5
	Notes to the Consolidated Financial Statements	7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	1920
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	2829
Item 4.	Controls and Procedures	2829
	PART II — OTHER INFORMATION
Item 1.	Legal Proceedings	3031
Item 1A.	Risk Factors	3032
Item 6.	Exhibits	3133
Signatures		3233

In this report, unless the context requires otherwise, references to “we,” “us,” “our,” 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, within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934, including with respect to the transactions contemplated by the Agreement and Plan of Merger, dated September 17, 2018, by and among Enbridge Energy Partners, L.P., Enbridge Energy Company, Inc., Enbridge Energy Management, L.L.C., Enbridge Inc., Enbridge (U.S.) Inc., Winter Acquisition Sub II, LLC, and, solely for the purposes of Articles I, II and XI, Enbridge US Holdings Inc. (the Proposed Merger). All statements other than statements of historical fact contained in this Quarterly Report on Form 10-Q are forward-looking statements, including, without limitation, statements regarding the consummation of the Proposed Merger, including the timing and expected effects thereof, 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) the ~~negotiation~~risk ~~and~~that ~~execution,~~Enbridge ~~and~~may ~~the~~be ~~terms~~unable ~~and~~to ~~conditions~~obtain governmental, ofunitholder ~~definitive~~and ~~agreements~~regulatory ~~relating~~approvals torequired ~~Enbridge's~~for ~~offer~~the toProposed Merger, whereby Enbridge will acquire all of our outstanding public Class A common units ~~not~~or ~~currently~~required ~~beneficially~~governmental, ~~owned~~unitholder byand ~~Enbridge~~regulatory approvals may delay the Proposed Merger or result in the imposition of conditions that could cause the parties to abandon the Proposed Merger; (2) the risk that a condition to closing of the Proposed ~~Transaction~~Merger may not be satisfied; (3) the timing to complete the Proposed Merger; (4) the ability to realize expected cost savings, benefits and any other synergies from the ~~timing~~Proposed Merger and ~~ability~~the proposed simplification of Enbridge's overall corporate structure may not be fully realized or usmay take longer to ~~enter~~realize ~~into~~than expected; (5) disruption from the Proposed Merger may make it more difficult to maintain relationships with customers, employees or ~~consummate~~suppliers; ~~such~~(6) ~~agreements~~the impact and outcome of pending and future litigation, including litigation, if any, relating to the Proposed Merger; (27) the effectiveness of the various actions we have taken resulting from our strategic review process; (38) changes in the demand for, the supply of, forecast data for, and price trends related to crude oil and liquid petroleum, including the rate of development of the Alberta Oil Sands; (49) our ability to successfully complete and finance expansion projects; (510) the effects of competition, in particular, by other pipeline systems; (611) shut-downs or cutbacks at our facilities or refineries, petrochemical plants, utilities or other businesses for which we transport products or to whom we sell products; (712) hazards and operating risks that may not be covered fully by insurance; (813) any fines, penalties and injunctive relief assessed in connection with any crude oil release; (914) state or federal legislative and regulatory initiatives or actions that affect cost and investment recovery or that have an effect on rate structure, or other changes in or challenges to our tariff rates; (1015) 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 (1116) permitting at federal, state and local levels or renewals of rights of way.

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Forward-looking statements regarding sponsor support transactions or sales of assets (to Enbridge or otherwise) are further qualified by the fact that Enbridge is under no obligation to provide additional sponsor support and neither Enbridge nor any third party is under any obligation to offer to buy or sell us assets, and we are under no obligation to buy or sell any such assets. As a result, we do not know when or if any such transactions will occur. Any statements regarding sponsor expectations or intentions are based on information communicated to us by Enbridge, but there can be no assurance that these expectations or intentions will not change in the future.

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, 2017 and in any Quarterly Report on Form 10-Q filed thereafter, which is available to the public over the Internet at the United States Securities and Exchange Commission's (the SEC) website (www.sec.gov) and at our website (www.enbridgepartners.com).

iii

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PART I — FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ENBRIDGE ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF INCOME

(unaudited; in millions, except per unit amounts)



	Three months ended September 30,						Nine months ended September 30,
	2018			2017			2018			2017
Operating revenues:
Transportation and other services	$	527		$	596		$	1,586		$	1,745
Transportation and other services - affiliates	33			20			103			72
Total operating revenues (Note 3)	560			616			1,689			1,817
Operating expenses:
Environmental costs, net of recoveries	4			1			(18		)	15
Operating and administrative	62			77			198			239
Operating and administrative - affiliates	64			85			195			235
Power	83			81			235			221
Depreciation and amortization	111			112			330			329
Impairment of long-lived asset (Note 6)	1			—			37			—
Gain on sale of assets (Note 6)	(22		)	(6		)	(22		)	(68		)
Total operating expenses	303			350			955			971
Operating income	257			266			734			846
Interest expense, net	102			104			307			306
Allowance for equity used during construction	16			12			48			33
Income from equity investment in joint venture (Note 7)	37			22			93			28
Other income (expense)	—			—			(1		)	5
Income from continuing operations before income taxes	208			196			567			606
Income tax benefit (expense)	(1		)	—			(1		)	1
Income from continuing operations	207			196			566			607
Loss from discontinued operations, net of taxes (Note 6)	—			—			—			(57		)
Net income	207			196			566			550
Noncontrolling interests (Note 10)	(103		)	(103		)	(293		)	(262		)
Series 1 Preferred unit distributions	—			—			—			(29		)
Accretion of discount on Series 1 Preferred units	—			—			—			(8		)
Net income - controlling interests	$	104		$	93		$	273		$	251
Net income allocable to common units and i-units:
Income from continuing operations	$	92		$	82		$	237		$	254
Loss from discontinued operations (Note 4)	—			—			—			(38		)
Net income allocable to common units and i-units	$	92		$	82		$	237		$	216
Net income per common unit and i-unit (basic and diluted):
Income from continuing operations (Note 4)	$	0.21		$	0.19		$	0.55		$	0.65
Loss from discontinued operations (Note 4)	—			—			—			(0.10		)
Net income per common unit and i-unit (Note 4)	$	0.21		$	0.19		$	0.55		$	0.55
Weighted average common units and i-units outstanding (basic and diluted)	431			421			428			392
Cash Distributions paid per limited partner unit	$	0.350		$	0.350		$	1.050		$	1.283

	Three months ended June 30,						Six months ended June 30,
	2018			2017			2018			2017
Operating revenues:
Transportation and other services	$	500		$	569		$	1,059		$	1,149
Transportation and other services - affiliate	37			27			70			52
Total operating revenues (Note 3)	537			596			1,129			1,201
Operating expenses:
Environmental costs, net of recoveries	(23		)	4			(22		)	14
Operating and administrative	67			84			136			162
Operating and administrative - affiliate	68			74			131			150
Power	75			66			152			140
Depreciation and amortization	109			108			219			217
Impairment of long-lived asset (Note 6)	1			—			36			—
Gain on sale of assets (Note 6)	—			(51		)	—			(62		)
Total operating expenses	297			285			652			621
Operating income	240			311			477			580
Interest expense, net	101			103			205			202
Allowance for equity used during construction	16			11			32			21
Income from equity investment in joint venture (Note 7)	33			6			56			6
Other income (expense)	(1		)	5			(1		)	5
Income from continuing operations before income taxes	187			230			359			410
Income tax benefit	—			2			—			1
Income from continuing operations	187			232			359			411
Loss from discontinued operations, net of taxes (Note 6)	—			(35		)	—			(57		)
Net income	187			197			359			354
Noncontrolling interests (Note 9)	(92		)	(91		)	(190		)	(159		)
Series 1 preferred unit distributions	—			(6		)	—			(29		)
Accretion of discount on Series 1 preferred units	—			(7		)	—			(8		)
Net income - controlling interests	$	95		$	93		$	169		$	158
Net income allocable to common units and i-units:
Income from continuing operations	$	83		$	105		$	145		$	172
Loss from discontinued operations (Note 4)	—			(24		)	—			(38		)
Net income allocable to common units and i-units	$	83		$	81		$	145		$	134
Net income per common unit and i-unit (basic and diluted):
Income from continuing operations (Note 4)	$	0.19		$	0.27		$	0.34		$	0.46
Loss from discontinued operations (Note 4)	—			(0.06		)	—			(0.10		)
Net income per common unit and i-unit (Note 4)	$	0.19		$	0.21		$	0.34		$	0.36
Weighted average common units and i-units outstanding (basic and diluted)	428			400			427			377
Cash Distributions paid per limited partner unit	$	0.350		$	0.350		$	0.700		$	0.933

_____________________

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

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ENBRIDGE ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(unaudited; in millions)

	Three months ended June 30,						Six months ended June 30,
	Three months ended September 30,						Nine months ended September 30,
	2018			2017			2018			2017
Net income	$	~~187~~207		$	~~197~~196		$	~~359~~566		$	~~354~~550
Other comprehensive income, net of tax
Change in cash flow hedges	—			(194		)	—			(2125		)
Reclassification to income on cash flow hedges	8			10			2028			2131
Other comprehensive income (loss), net of tax	8			(9		)	20			—
Other comprehensive income, net of tax	8			6			28			6
Comprehensive income	~~195~~215			~~188~~202			~~379~~594			~~354~~556
Comprehensive income attributable to noncontrolling interests	(92103		)	(91103		)	(~~190~~293		)	(~~159~~262		)
Series 1 preferred unit distributions	—			(6		)	—			(29		)
Series 1 Preferred unit distributions	—			—			—			(29		)
Accretion of discount on Series 1 preferred units	—			(7		)	—			(8		)
Accretion of discount on Series 1 Preferred units	—			—			—			(8		)
Comprehensive income attributable to common units and i-units	$	~~103~~112		$	8499		$	~~189~~301		$	~~158~~257

_____________________

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

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ENBRIDGE ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited; in millions)

	Six months ended June 30,
	Nine months ended September 30,
	2018			2017
Operating activities:
Income from continuing operations	$	~~359~~566		$	~~411~~607
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	~~219~~330			~~217~~329
Changes in unrealized (gain) loss on derivative instruments, net	7			(1		)
Changes in unrealized loss on derivative instruments, net	8			1
Environmental costs, net of recoveries	(2223		)	1415
Distributions from equity investment in joint venture	5693			—28
Income from equity investment in joint venture (Note 7)	(5693		)	(628		)
Gain on sale of assets (Note 6)	—(22		)	(6268		)
Allowance for equity used during construction	(3248		)	(2133		)
Amortization of debt issuance and hedging costs	1727			1927
Impairment of long-lived asset (Note 6)	3637			—
Other	1			(2—		)
Changes in operating assets and liabilities	3162			(~~354~~319		)
Net cash provided by operating activities	~~616~~938			~~215~~559
Net cash used in discontinued operations	—			(171		)
Investing activities:
Capital expenditures	(~~333~~467		)	(~~229~~418		)
Proceeds from the sale of assets	—			314
Proceeds from the sale of assets (Note 6)	15			319
Proceeds from the sale of Midcoast assets (Note 6)	—			1,310
Equity investment in joint venture	(49		)	(1,~~557~~577		)
Distributions from equity investment in joint venture in excess of cumulative earnings	4057			—12
Other	—			(3		)
Net cash used in investing activities	(~~297~~404		)	(~~165~~357		)
Net cash used in discontinued operations	—			(25		)
Financing activities:
Redemption of Series 1 Preferred Units (Note 10)	—			(1,200		)
Redemption of Series 1 Preferred units (Note 11)	—			(1,200		)
Payment of Series 1 Preferred Unit dividends (Note 10)	—			(357		)
Payment of Series 1 Preferred unit dividends (Note 11)	—			(357		)
Net proceeds from Class A common unit issuances (Note 10)	—			1,225
Net proceeds from Class A common unit issuances (Note 11)	—			1,225
Distributions to partners	(~~260~~390		)	(~~346~~475		)
Repayments to General Partner and affiliates	(157		)	(1,~~829~~706		)
Borrowings from General Partner and affiliates	297			1,500
Net borrowings (repayments) under credit facilities (Note 8)	~~175~~238			(~~865~~1,065		)
Net commercial paper borrowings (Note 8)	9119			~~676~~686
Repayment of long-term debt (Note 8)	(400		)	—
Acquisition of noncontrolling interest in subsidiary (Note 11)	—			(360		)
Acquisition of noncontrolling interest in subsidiary (Note 12)	—			(360		)
Sale of noncontrolling interest in subsidiary (Note 11)	—			450
Sale of noncontrolling interest in subsidiary (Note 12)	—			450
Contributions from noncontrolling interests	~~165~~205			1,~~285~~390
Distributions to noncontrolling interests	(~~254~~364		)	(~~219~~376		)
Other	(2		)	(1		)
Net cash used in financing activities	(~~345~~554		)	(41289		)
Net cash provided by discontinued operations	—			229
Net increase (decrease) in cash and cash equivalents and restricted cash - continuing operations	(26		)	9
Net decrease in cash and cash equivalents and restricted cash - continuing operations	(20		)	(87		)
Net increase in cash and cash equivalents and restricted cash - discontinued operations	—			33
Cash disposed as part of the Midcoast sale	—			(51		)
Cash and cash equivalents and restricted cash at beginning of year - continuing operations	35			115
Cash and cash equivalents and restricted cash at beginning of year - discontinued operations	—			18
Cash and cash equivalents and restricted cash at end of period - continuing operations	$	915		$	~~124~~28
Cash and cash equivalents and restricted cash at end of period - discontinued operations	$	—		$	—

_____________________

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

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ENBRIDGE ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

(unaudited; in millions, except number of Class F units)

	June 30, 2018			December 31, 2017
	September 30, 2018			December 31, 2017
ASSETS
Current assets:
Cash and cash equivalents	$	915		$	35
Receivables, trade and other	5276			65
Due from General Partner and affiliates	~~107~~84			101
Accrued receivables	9187			105
Other current assets	3024			24
	289			330
	286			330
Property, plant and equipment, net	1213,~~978~~104			12,896
Equity investment in joint venture (Note 7)	1,~~530~~517			1,565
Other assets, net	3843			37
Total assets	$	14,~~835~~950		$	14,828
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities:
Accounts payable and other	$	~~188~~224		$	173
Due to General Partner and affiliates	5134			48
Interest payable	8188			85
Environmental liabilities	1716			23
Property and other taxes payable	8783			106
Current portion of long-term debt	600			500
	1,024			935
	1,045			935
Long-term debt	6,~~133~~126			6,366
Loans from General Partner and affiliate	750			610
Other long-term liabilities	~~158~~244			178
	8,065			8,089
	8,165			8,089
Commitments and contingencies (Note 12)
Commitments and contingencies (Note 13)
Partners’ capital:
Class E units (18.1 authorized and issued at June 30, 2018 and December 31, 2017, respectively)	774			774
Class E units (18.1 authorized and issued at September 30, 2018 and December 31, 2017, respectively)	774			774
Class A common units (326.5 outstanding at June 30, 2018 and December 31, 2017, respectively)	614			860
Class A common units (326.5 outstanding at September 30, 2018 and December 31, 2017, respectively)	491			860
Class B common units (7.8 authorized and issued at June 30, 2018 and December 31, 2017, respectively)	—			—
Class B common units (7.8 authorized and issued at September 30, 2018 and December 31, 2017, respectively)	—			—
i-units (95.5 and 89.8 authorized and issued at June 30, 2018 and December 31, 2017, respectively)	—			—
i-units (98.6 and 89.8 authorized and issued at September 30, 2018 and December 31, 2017, respectively)	—			—
Class F units (1,000 authorized and issued at June 30, 2018 and December 31, 2017, respectively)	267			267
Class F units (1,000 authorized and issued at September 30, 2018 and December 31, 2017, respectively)	267			267
General Partner	~~224~~321			68
Accumulated other comprehensive loss	(~~179~~171		)	(199		)
Total Enbridge Energy Partners, L.P. partners’ capital	1,~~700~~682			1,770
Noncontrolling interests	5,~~070~~103			4,969
Total Partners’ capital	6,~~770~~785			6,739
Total Liabilities and Partners’ capital	$	14,~~835~~950		$	14,828

_____________________

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

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ENBRIDGE ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

(unaudited; in millions)

	Six months ended June 30,
	Nine months ended September 30,
	2018			2017
Series 1 Preferred units:
Beginning balance	$	—		$	1,192
Redemption of preferred units (Note 10)	—			(1,200		)
Redemption of preferred units (Note 11)	—			(1,200		)
Net income	—			29
Distribution payable	—			(29		)
Accretion of discount on preferred units	—			8
Ending balance	—			—
Class D units:
Beginning balance	—			2,518
Waiver of Class D units (Note 10)	—			(2,479		)
Waiver of Class D units (Note 11)	—			(2,479		)
Distributions	—			(39		)
Ending balance	—			—
Class E units:
Beginning balance	774			778
Net income	1319			1319
Distributions	(1319		)	(1723		)
Ending balance	774			774
Class A common units:
Beginning balance	860			—
Net income (loss)	(19		)	150
Net income	(26		)	141
Issuance of Class A units (Note 10)	—			1,200
Issuance of Class A units (Note 11)	—			1,200
Distributions	(~~229~~343		)	(~~267~~381		)
Sale of noncontrolling interest in subsidiary (Note 11)	—			29
Sale of noncontrolling interest in subsidiary (Note 12)	—			29
Other	2			—
Ending balance	491			989
Ending balance	614			1,112
Class B common units:
Net income	68			69
Sale of noncontrolling interest in subsidiary (Note 11)	—			1
Sale of noncontrolling interest in subsidiary (Note 12)	—			1
Distributions	(68		)	(710		)
Ending balance	—			—
i-units:
Net loss	—			(9		)
Sale of noncontrolling interest in subsidiary (Note 11)	—			9
Sale of noncontrolling interest in subsidiary (Note 12)	—			9
Ending balance	—			—
Class F units:
Beginning balance	267			—
Issuance of Class F units (Note 10)	—			263
Issuance of Class F units (Note 11)	—			263
Net income	811			711
Distributions	(811		)	(37		)
Ending balance	267			267

_____________________

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

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ENBRIDGE ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL - (continued)

(unaudited; millions of dollars)

	Six months ended June 30,
	Nine months ended September 30,
	2018			2017
Incentive distribution units:
Beginning balance	—			495
Waiver of incentive distribution units (Note 10)	—			(490		)
Waiver of incentive distribution units (Note 11)	—			(490		)
Distributions	—			(5		)
Ending balance	—			—
General Partner:
Beginning balance	68			(667		)
Net income (loss)	161			(9		)
Net income	261			80
Waiver of Class D units and incentive distribution units (Note 10)	—			2,969
Waiver of Class D units and incentive distribution units (Note 11)	—			2,969
Issuance of Class F units (Note 10)	—			(263		)
Issuance of Class F units (Note 11)	—			(263		)
Contributions	—			2592
Sale of Midcoast assets (Note 6)	—			(2,127		)
Distributions	(58		)	(79		)
Sale of noncontrolling interest in subsidiary (Note 11)	—			1
Sale of noncontrolling interest in subsidiary (Note 12)	—			1
Ending balance	~~224~~321			~~(78~~76		)
Accumulated other comprehensive loss:
Beginning balance	(199		)	(339		)
Changes in fair value of derivative financial instruments recognized in other comprehensive income	—			(2125		)
Changes in fair value of derivative financial instruments reclassified to income	2028			2131
Ending balance	(~~179~~171		)	(~~339~~333		)
Noncontrolling interests:
Beginning balance	4,969			3,846
Capital contributions	~~165~~205			1,~~305~~410
Sale of noncontrolling interest in subsidiary (Note 11)	—			411
Sale of noncontrolling interest in subsidiary (Note 12)	—			411
Acquisition of noncontrolling interest in subsidiary (Note 11)	—			(360		)
Acquisition of noncontrolling interest in subsidiary (Note 12)	—			(360		)
Sale of Midcoast assets (Note 6)	—			(297		)
Net income	~~190~~293			~~159~~262
Distributions to noncontrolling interests	(~~254~~364		)	(~~219~~376		)
Ending balance	5,~~070~~103			4,~~845~~896
Total Partners’ Capital at end of period	$	6,~~770~~785		$	6,~~581~~669

_____________________

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

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ENBRIDGE ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

1. GENERAL

The terms “we,” “our,” “us” and “Enbridge Energy Partners” as used in this report refer collectively to Enbridge Energy Partners, L.P. and its subsidiaries unless the context suggests otherwise. Those terms are used for convenience only and are not intended as a precise description of any separate legal entity within Enbridge Energy Partners.

Nature of Operations

We, together with our consolidated subsidiaries, provide crude oil and liquid petroleum gathering, transportation and storage services. In June 2017, we sold all of our ownership interest in our Midcoast gas gathering and processing business to our General Partner (the Midcoast Sale), which is an indirect wholly-owned subsidiary of Enbridge Inc. (Enbridge) The sale of this ownership interest represented a strategic shift in our business and met the criteria for classification as discontinued operations, which resulted in the results of operations, cash flows and financial position of our natural gas business for the prior periods being reflected as discontinued operations. For further information refer to Note 6 - Asset Held for Sale, Dispositions and Discontinued Operations.

Basis of Presentation

The accompanying unaudited interim consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (U.S. GAAP), for interim consolidated financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. They do not include all the information and notes required by U.S. GAAP for annual consolidated financial statements and should therefore be read in conjunction with our annual consolidated financial statements and notes presented in our Annual Report on Form 10-K for the year ended December 31, 2017. In the opinion of management, the interim consolidated financial statements contain all adjustments, consisting only of normal recurring adjustments, necessary to present fairly our financial position, results of operations and cash flows for the interim periods reported. These interim consolidated financial statements follow the same significant accounting policies as those included in our annual consolidated financial statements for the year ended December 31, 2017, except for the adoption of new standards.

Our operations and earnings for interim periods can be affected by seasonal fluctuations in the supply of and the demand for crude oil, as well as other factors such as the timing and completion of our construction projects, the effect of environmental costs and related insurance recoveries on our Lakehead System, the impact of forward commodity prices and differentials on derivative financial instruments that are accounted for at fair value and may not be indicative of annual results.

2. CHANGES IN ACCOUNTING POLICIES

Adoption of New Standards

Clarifying Guidance on Derecognition and Partial Sales of Nonfinancial Assets

Effective January 1, 2018, we adopted Accounting Standards Update (ASU) 2017-05 on a modified retrospective basis. The new standard clarifies the scope provisions of nonfinancial assets and how to allocate consideration to each distinct asset upon sale or partial sale and amends the guidance for derecognition of a distinct nonfinancial asset in partial sale transactions so that an in-scope partial sale results in the recognition of a full gain or loss. The adoption of this accounting update did not have a material impact on our consolidated financial statements.

Clarifying the Presentation of Restricted Cash in the Statement of Cash Flows

Effective January 1, 2018, we adopted ASU 2016-18 on a retrospective basis. The new standard clarifies guidance on the classification and presentation of changes in restricted cash and restricted cash equivalents within the statement of cash flows. The amendments require that changes in restricted cash and restricted cash equivalents be included within cash and cash equivalents when reconciling the opening and closing period amounts shown on the statement of cash flows. For current and comparative periods, we amended the presentation in our consolidated statements of cash flows to include restricted cash and restricted cash equivalents with cash and cash equivalents.

Simplifying Cash Flow Classification

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Simplifying Cash Flow Classification

Effective January 1, 2018, we adopted ASU 2016-15 on a retrospective basis. The new standard reduces diversity in practice of how certain cash receipts and cash payments are classified in the statements of cash flows. The new guidance addresses eight specific presentation issues. We assessed each of the eight specific presentation issues and the adoption of this ASU did not have a material impact on our consolidated financial statements.

Revenues from Contracts with Customers

Effective January 1, 2018, we adopted ASU 2014-09 on a modified retrospective basis to contracts that were not yet completed at the date of initial application. The new standard was issued with the intent of significantly enhancing consistency and comparability of revenue recognition practices across entities and industries. The new standard establishes a single, principles-based five-step model to be applied to all contracts with customers and introduces new and enhanced disclosure requirements. It also requires the use of more estimates and judgments, as well as additional disclosures. The adoption of this new standard did not have a material impact on our consolidated financial statements, see Note 3 - Revenue for further details.

Future Accounting Policy Changes

Amended Guidance on Cloud Computing Arrangements

In August 2018, ASU 2018-15 was issued to provide guidance on the accounting for implementation costs incurred in a cloud computing arrangement (CCA) that is a service contract. The amendment aligns the accounting for costs incurred to implement a CCA that is a service arrangement with the guidance on capitalizing costs associated with developing or obtaining internal-use software. Additionally ASU 2018-15 specifies that an entity would apply Accounting Standard Codification (ASC) 350-40 to determine which implementation costs related to a hosting arrangement that is a service contract should be capitalized and which should be expensed. Furthermore, the amendments in the update require capitalized costs be amortized on a straight-line basis generally over the term of the arrangement and presented in the same income statement line as fees paid for the hosting service. The new standard also requires that the balance sheet presentation of capitalized implementation costs to be the same as that of the prepayment of fees related to the hosting arrangement, as well as similar consistency in classifications from a cash flow statement perspective. ASU 2018-15 is effective January 1, 2020 and early adoption is permitted. We are currently assessing the impact of the new standard on our consolidated financial statements.

Disclosure Effectiveness

In August 2018, the Financial Accounting Standards Board issued amendments as a part of its disclosure framework project aimed to improve the effectiveness of disclosures in the notes to financial statements.

ASU 2018-13 was issued to modify the disclosure requirements in ASC 820, Fair Value Measurement. The amendments in ASU 2018-13 eliminate and modify some disclosures, while also adding new disclosures for fair value measurements. This update is effective January 1, 2020; however, entities are permitted to early adopt the eliminated or modified disclosures. We are currently assessing the impact of the new standard on our consolidated financial statements.

Improvements to Accounting for Hedging Activities

ASU 2017-12 was issued in August 2017 with the objective of better aligning an organization's risk management activities and the resulting hedge accounting reflected in the financial statements. The amendments allow cash flow hedging of contractually specified components in financial and non-financial items. Under the new guidance, hedge ineffectiveness is no longer required to be measured and hedging instruments’ fair value changes will be recorded in the same income statement line as the hedged item. The ASU also allows the initial quantitative hedge effectiveness assessment to be performed at any time before the end of the quarter in which the hedge is designated. After initial quantitative testing is performed, an ongoing qualitative effectiveness assessment is permitted. The accounting update is effective January 1, 2019, with early adoption permitted and is to be applied on a modified retrospective basis. We are currently assessing the impact of the new standard on the consolidated financial statements.

Accounting for Credit Losses

ASU 2016-13 was issued in June 2016 with the intent of providing financial statement users with more useful information about the expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity at each reporting date. Current treatment uses the incurred loss methodology for recognizing credit losses that delays the recognition until it is probable a loss has been incurred. The accounting update adds a new impairment model, known as the current expected credit loss model, which is based on expected losses rather than incurred losses. Under the new guidance, an entity will recognize as an allowance its estimate of expected credit losses, which the Financial Accounting Standards Board believes will result in more timely recognition of such losses. ~~The accounting update is effective January 1, 2020. We are currently assessing the impact of the new standard on our consolidated financial statements.~~

Recognition of Leases

ASU 2016-02 was issued in February 2016 with the intent to increase transparency and comparability among organizations. It requires lessees of operating lease arrangements to recognize lease assets and lease liabilities on the statement of financial position and disclose additional key information about lease agreements. The accounting update also replaces the current definition of a lease and requires that an arrangement be recognized as a lease when a customer has the right to obtain substantially all of the economic benefits from the use of an asset, as well as the right to direct the use of the asset. We will adopt the new standard on January 1, 2019 and we intend to apply the transition practical expedients offered in connection with this update. The election to apply the package of practical expedients allows an entity to not apply the new lease standard to the prior year comparative periods in the year of adoption. Application of the package of practical expedients permits entities not to reassess whether any expired or existing contracts contain leases, their lease classification, as well as any related initial direct costs.

Further, ASU 2018-01 was issued in January 2018 to address stakeholder concerns about the costs and complexity of complying with the transition provisions of the new lease requirements as they relate to land easements. The amendments provide an optional transition practical expedient to not evaluate existing or expired land easements that were not previously accounted for as leases under existing guidance. We intend to elect this practical expedient in connection with the adoption of the new lease requirements.

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~~statements~~The ofaccounting ~~financial~~update ~~position~~is ~~for~~effective ~~operating~~January ~~leases~~1, 2020. We ~~continue~~are tocurrently ~~assess~~assessing the ~~necessary~~impact ~~changes~~of ~~to accounting and business processes in order to implement~~ the ~~recognition~~new ~~and~~standard ~~disclosure~~on ~~requirements~~our ofconsolidated ~~the~~financial ~~new lease standard~~statements.

Recognition of Leases

ASU 2016-02 was issued in February 2016 with the intent to increase transparency and comparability among organizations. It requires lessees of operating lease arrangements to recognize lease assets and lease liabilities on the statement of financial position and disclose additional key information about lease agreements. The accounting update also replaces the current definition of a lease and requires that an arrangement be recognized as a lease when a customer has the right to obtain substantially all of the economic benefits from the use of an asset, as well as the right to direct the use of the asset. We will adopt the new standard on January 1, 2019 and we intend to apply the transition practical expedients offered in connection with this update. The election to apply the package of practical expedients allows an entity to not apply the new lease standard to the prior year comparative periods in the year of adoption. Application of the package of practical expedients also permits entities not to reassess a) whether any expired or existing contracts contain leases in accordance with the new guidance, b) lease classifications, and c) whether initial direct costs capitalized under ASC 840 continue to meet the definition of initial direct costs under the new guidance.

In July 2018, ASU 2018-11 was issued to address additional stakeholder concerns regarding the unanticipated costs and complexities associated with the modified retrospective transition method as well as the requirement for lessors to separate components of a contract. Under the new guidance, entities are provided with an additional transition method which allows entities to apply the new standard at the date of adoption and to elect not to recast comparative periods presented. This amendment also provides a practical expedient which allows lessors to combine associated lease and nonlease components within a contract when certain conditions are met. We intend to adopt the new transition option in connection with the adoption of the new lease requirements; however, we continue to evaluate the lessor practical expedient to combine lease and nonlease components.

We have substantially completed the process of identifying existing lease contracts and are currently performing detailed evaluations of our leases under the new accounting requirements. We believe the most significant change to our financial statements will be the recognition of lease liabilities and right-of-use assets in our consolidated statements of financial position for operating leases. We continue to assess the necessary changes to accounting and business processes in order to implement the recognition and disclosure requirements of the new lease standard.

3. REVENUE

Revenues from Contracts with Customers

Major Products and Services

	Three months ended June 30,			Six months ended June 30,
	Three months ended September 30,			Nine months ended September 30,
	2018			2018
	(in millions)
Operating revenues:
Transportation	$	~~519~~543		$	1,~~090~~633
Storage and other	2521			4970
Total revenues from contracts with customers	~~544~~564			1,~~139~~703
Other	(74		)	(1014		)
Total revenues	$	~~537~~560		$	1,~~129~~689

	Three months ended June 30,		Six months ended June 30, 2018
	2018		2018
	(in millions)
Revenues from products and services transferred over time - crude oil pipeline transportation and storage	$	544	$	1,139

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Recognition and Measurement of Revenue



	Three months ended September 30,		Nine months ended September 30, 2018
	2018		2018
	(in millions)
Revenues from products and services transferred over time - crude oil pipeline transportation and storage	$	564	$	1,703

Payment terms

Payments are received monthly from customers under long-term transportation contracts.

Contract balances

Contract assets represent the amount of revenue which has been recognized in advance of payments received for performance obligations we have fulfilled (or partially fulfilled) and prior to the point in time at which our right to the payment is unconditional. Amounts included in contract assets are transferred to accounts receivable when our right to the consideration becomes unconditional.

Contract liabilities represent payments received for performance obligations which have not been fulfilled. Contract liabilities primarily relate to make-up rights.

We had Receivables balances of $255 million and $~~217~~218 million at January 1, 2018 and ~~June~~ September 30, 2018, respectively. At ~~June~~ September 30, 2018, we had no material contract assets and $43 million in contract liabilities.

Revenues to be Recognized from Unfulfilled Performance Obligations

Total revenues from performance obligations expected to be fulfilled in future periods is $~~567~~537 million, of which $6232 million and $128 million are expected to be recognized during the remaining ~~six~~three months ending December 31, 2018 and for the year ended December 31, 2019, respectively.

Certain revenues such as flow-through operating costs charged to shippers are recognized at the amount for which we have the right to invoice our customers. Those revenues are not included in the amounts for revenues to be recognized in the future from unfulfilled performance obligations above. Variable consideration is excluded from the amounts above due to the uncertainty of the associated consideration, which is generally resolved when actual volumes and prices are determined. Additionally, the effect of escalation on certain tolls which are contractually escalated for inflation has not been reflected in the amounts above as it is not possible to reliably estimate future inflation rates. Finally, revenues from contracts with customers which have an original expected duration of one year or less are excluded from the amounts above.

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Significant Judgments made in Recognizing Revenues

Judgment is required in estimating variable consideration for volumetric transportation and sales contracts. We estimate variable consideration for these contracts as the most likely amount based on actual volumes transported and delivered when those quantities are determined at the conclusion of each month using metered volumes and actual average monthly index prices for commodity sales contracts.

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4. NET INCOME PER LIMITED PARTNER UNIT

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

	Three months ended June 30,						Six months ended June 30,
	Three months ended September 30,						Nine months ended September 30,
	2018			2017			2018			2017
	(in millions, except per unit amounts)
Continuing operations:
Net income	$	~~187~~207		$	~~232~~196		$	~~359~~566		$	~~411~~607
Noncontrolling interests	(92103		)	(~~102~~103		)	(~~190~~293		)	(~~178~~281		)
Series 1 preferred unit distributions	—			(6		)	—			(29		)
Series 1 Preferred unit distributions	—			—			—			(29		)
Accretion of discount on Series 1 preferred units	—			(7		)	—			(8		)
Accretion of discount on Series 1 Preferred units	—			—			—			(8		)
Net income - continuing operations	95104			~~117~~93			~~169~~273			~~196~~289
Distributions:
Incentive distributions to Class F units	(4		)	(4		)	(811		)	(812		)
Distributed earnings attributed to our General Partner	(3		)	(3		)	(610		)	(69		)
Distributed earnings attributed to Class E units	(6		)	(6		)	(1319		)	(1319		)
Total distributed earnings to our General Partner, Class E and Class F units	(13		)	(13		)	(2740		)	(2740		)
Total distributed earnings attributed to our common units and i-units	(~~151~~152		)	(~~147~~148		)	(~~300~~451		)	(~~293~~441		)
Total distributed earnings	(~~164~~165		)	(~~160~~161		)	(~~327~~491		)	(~~320~~481		)
Overdistributed earnings	$	(6961	)	$	(4368	)	$	(~~158~~218	)	$	(~~124~~192	)
Discontinued operations:
Net loss	$	—		$	~~(35~~—	)	$	—		$	(57	)
Noncontrolling interest	—			11—			—			19
Net loss – discontinued operations	$	—		$	(24	)	$	—		$	(38	)
Net loss - discontinued operations	$	—		$	—		$	—		$	(38	)
Weighted average common units and i-units outstanding	~~428~~431			~~400~~421			~~427~~428			~~377~~392
Basic and diluted earnings per unit:
Distributed earnings per common unit and i-unit - continuing operations(1)	$	0.35		$	0.3735		$	01.7005		$	01.7813
Overdistributed earnings per common unit and i-unit(2)	(0.1614		)	(0.1016		)	(0.3650		)	(0.3248		)
Net income per common unit and i-unit (basic and diluted) - continuing operations(3)	0.1921			0.2719			0.3455			0.4665
Net loss per common unit and i-unit (basic and diluted) - discontinued operations(3)	—			~~(0.06~~—		)	—			(0.10		)
Net income per common unit and i-unit (basic and diluted)	$	0.1921		$	0.2119		$	0.3455		$	0.3655

_____________________


(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 ~~six~~nine months ended ~~June~~September 30, 2018, 18.1 million anti-dilutive Class E units were excluded from the if-converted method of calculating diluted earnings per share. For the three months ended ~~June~~September 30, 2017, 18.1 million anti-dilutive Class E units were excluded from the if-converted method of calculating diluted earnings per share. For the ~~six~~nine months ended ~~June~~September 30, 2017, 43.2 million anti-dilutive Preferred units and 18.1 million anti-dilutive Class E units were excluded from the if-converted method of calculating diluted earnings per unit and 66.1 million of Class D units were excluded from the if-converted method of calculating diluted earnings per unit as the General Partner irrevocably waived all of its rights associated with the Class D units effective April 27, 2017.

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5. REGULATORY MATTERS

Regulatory Accounting

Our over and under recovery revenue adjustments and net regulatory asset amortization are as follows:

	Three months ended June 30,						Six months ended June 30,
	Three months ended September 30,						Nine months ended September 30,
	2018			2017			2018			2017
	(in millions)
Net regulatory (liability) asset balance at beginning of period	$	(1134	)	$	(3424	)	$	3		$	12
Prior period true-up	—			—			4			(5		)
Current period (over) under recovery revenue adjustments	(2113		)	1229			(3750		)	~~(27~~2		)
Amortization of prior year regulatory asset	(2		)	(21		)	(46		)	(45		)
Net regulatory liability balance at end of period	$	(34	)	$	(24	)	$	(34	)	$	(24	)
Net regulatory (liability) asset balance at end of period	$	(49	)	$	4		$	(49	)	$	4

6. ASSET HELD FOR SALE, DISPOSITIONS AND DISCONTINUED OPERATIONS

Asset Held for Sale

~~During~~In the first quarter of 2018, we satisfied the conditions as set out in our agreements for the sale of our Line 10 crude oil pipeline, a component of our Lakehead System. Line 10 originates near Hamilton, Ontario and terminates at West Seneca, New York. We own the United States portion of Line 10, while a subsidiary of the indirect parent of our General Partner, Enbridge ~~Inc., (Enbridge)~~ owns the Canadian portion.

We expect to close the sale of Line 10 within one year, subject to regulatory approval and certain closing conditions. As such, during the first quarter of 2018, we classified our portion of Line 10 assets as held for sale and measured them at the lower of their carrying value or fair value less costs to sell, which resulted in a loss of $3637 million included within “Impairment of long-lived asset” on our consolidated statements of income for the ~~six~~nine months ended ~~June~~ September 30, 2018. The remaining held for sale assets and liabilities were not material.

Dispositions

~~During~~In ~~the~~July ~~second~~2018, ~~quarter~~we ofentered ~~2017,~~into wean ~~sold~~agreement to sell to a third party unnecessary ~~pipe~~materials related to the Sandpiper Project for cash proceeds of approximately $9830 million, of which we received approximately $15 million during the three months ended September 30, 2018 with the remaining balance being held in an escrow account as of September 30, 2018. AThe remaining balance will be released from escrow once the purchaser takes possession of all the purchased materials. Under the terms of the agreement, title was transferred to the purchaser in late September 2018 when payment of the remaining balance was deposited in the escrow account. As a result, we recorded a gain on disposition of $5122 million ~~was~~net of selling costs, included in "Gain on sale of assets" on our consolidated statements of income.

During the nine months ended September 30, 2017, we sold unnecessary pipe related to the Sandpiper Project for cash proceeds of approximately $103 million. A gain on disposition of $57 million was included in "Gain on sale of assets" on our consolidated statements of income.

In March 2017, we completed the sale of the Ozark Pipeline to a subsidiary of MPLX LP for cash proceeds of approximately $220 million, including reimbursement costs. A gain on disposition of $11 million was included in “Gain on sale of assets” on our consolidated statements of income.

Discontinued Operations

Sale of Natural Gas Business

In June 2017, we completed the sale of all of our ownership interest in our Midcoast gas gathering and processing business to our General Partner for $2.3 billion, which included cash consideration of $1.3 billion and outstanding indebtedness at Midcoast Energy Partners, L.P. (MEP) of $953 million. This sale included our 48.4% limited partnership interest in Midcoast Operating, L.P., our 51.9% limited partnership interest in MEP, and our 100% interest in Midcoast Holdings, L.L.C., MEP’s general partner. We recorded no gain or loss on the sale as this transaction was between entities under common control of Enbridge. The carrying value of the net assets sold was $4.3 billion. As a result of the transaction, partners’ capital decreased by $2.1 billion, all of which was allocated to the General Partner’s capital account. Noncontrolling interest (NCI) in MEP of $297 million was eliminated.

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the transaction, partners’ capital decreased by $2.1 billion, all of which was allocated to the General Partner’s capital account. Noncontrolling interest (NCI) in MEP of $297 million was eliminated.

The following table presents the operating results from discontinued operations of our Midcoast gas gathering and processing business, which have been segregated from our continuing operations in our consolidated statements of income:

	Three months ended June 30,			Six months ended June 30,
	Nine months ended September 30,
	2017			~~2017~~
	(in millions)
Operating revenues	$	~~587~~1,161		$	~~1,161~~
Operating expenses:
Commodity costs	~~523~~1,011			~~1,011~~
Operating and administrative	63133			~~133~~
Depreciation and amortization	3774			74
	623			1,218
	1,218
Operating loss	(3657		)	~~(57~~		)
Interest expense, net	917			17
Other income	1018			18
Loss before income taxes	(3556		)	~~(56~~		)
Income tax expense	—(1		)	(1		)
Loss from discontinued operations, net of taxes	$	(3557	)	$	~~(57~~	)

7. EQUITY INVESTMENT IN JOINT VENTURE

The following table presents our equity investment in a joint venture and ownership interest in MarEn Bakken Company LLC (MarEn).

	OwnershipInterest	~~June~~September 30, 2018	December 31, 2017
		(in millions)
MarEn Bakken Company LLC	75%	$1,~~530~~517	$1,565

In February 2017, our joint venture with Marathon Petroleum Corporation (MPC), MarEn, closed its acquisition to acquire a 49% interest in Bakken Pipeline Investments LLC (BPI). BPI owns 75% of the Dakota Access Pipeline (DAPL) and the Energy Transfer Crude Oil Pipeline (ETCOP), collectively the Bakken Pipeline System. The Bakken Pipeline System was placed into service June 1, 2017. Our investment subsidiary, Enbridge Holdings (DakTex) L.L.C. (DakTex) and MPC indirectly hold 75% and 25% interests, respectively, of MarEn. The purchase of DakTex's effective 27.6% interest in the Bakken Pipeline System was $1.5 billion and funded through a bridge loan from Enbridge (U.S.) Inc., (EUS) an affiliate of our General Partner and was re-paid and terminated on April 27, 2017, as a result of the finalization by our Board of Directors of a joint funding arrangement with our General Partner. This arrangement resulted in DakTex now being owned 75% by our General Partner and 25% by us. Refer to Note 1112 - Related Party Transactions for further details on our joint funding arrangements.

We account for our investment in MarEn under the equity method of accounting. For the three and ~~six~~nine months ended ~~June~~September 30, 2018, we recognized $3337 million and $5693 million, respectively, and $622 million and $28 million for the ~~six~~three and nine months ended ~~June~~September 30, 2017, respectively, in “Income from equity investment in joint venture" in our consolidated statements of income representing our equity earnings for this investment, net of amortization of the excess of the purchase price over the underlying net book value (basis difference).

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ENBRIDGE ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

Our equity investment includes basis difference of the investees’ assets at the purchase date, which is comprised of $14 million in goodwill and $931 million in amortizable assets. We amortized $9 million and $1928 million, ~~respectively,~~ for the three and ~~six~~nine months ended ~~June~~September 30, 2018, respectively and $310 million and $13 million for the ~~six~~three and nine months ~~June~~ended September 30, 2017, respectively, which was recorded as a reduction to equity earnings.

8. DEBT

Credit Facilities

	MaturityDates(1)	Total Facilities(2)	Draws(3)	Available
	(in millions)
Enbridge Energy Partners, L.P.	2019 – 2022	$2,~~625~~450	$1,~~719~~710	$~~906~~740

_______________________

(1) Includes $~~175 million and $~~185 million of commitments that expire in ~~2018~~2020. ~~and~~$175 ~~2020~~million of commitments expired on September 26, ~~respectively~~2018.

(2) Includes our $21.08 billion multi-year revolving credit facility (Credit Facility) and our $625 million credit agreement (364-Day Credit Facility), together (the Credit Facilities).


(3)	Includes facility draws, letters of credit and commercial paper issuances that are back-stopped by the credit facility and excludes our unsecured revolving 364-day credit agreement with EUS (the EUS 364-day Credit Facility).

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 the availability of long-term committed credit facilities, and therefore is classified as long-term debt as of ~~June~~September 30, 2018 and December 31, 2017, respectively.

In addition to the committed credit facilities noted in the above table, we also have $175 million available under an uncommitted letters of credit arrangement, of which $~~172~~171 million and $174 million were unutilized as of ~~June~~September 30, 2018 and December 31, 2017, respectively.

Our Credit Facilities, had net borrowings of approximately $175 million as of June 30, 2018, which includes gross borrowings of $1,117 million and gross repayments of $942 million.

Under our commercial paper program, we had net borrowings of approximately $91 million as of June 30, 2018, which includes gross borrowings of $10.9 billion and gross repayments of $10.8 billion.

On April 15, 2018, our 6.5% senior notes of $400 million matured, and were subsequently paid on April 16, 2018.

On June 29, 2018, we extended the termination date attributable to our 364-Day Credit Facility to December 31, 2018, which has a term out option that could extend maturity of any outstanding borrowings to December 31, 2019. The size of the facility remains at $625 million and is through a syndicate of third party lenders.

Debt Covenants

We and our consolidated subsidiaries were in compliance with the terms of our financial covenants under our consolidated debt agreements as of ~~June~~September 30, 2018.

Fair Value of Debt Obligations

The carrying amounts of our outstanding commercial paper, borrowings under our Credit Facilities, and the EUS 364-day Credit Facility approximate their fair values 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 EUS 364-day Credit Facility are included with our long-term debt obligations above 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 $5.21 billion and $5.8 billion as of ~~June~~September 30, 2018 and December 31, 2017, 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.

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~~markets~~TABLE inOF 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.CONTENTS

9. ~~NONCONTROLLING~~ASSET ~~INTERESTS~~RETIREMENT OBLIGATIONS

Our AROs relate mostly to the retirement of our crude oil and liquid petroleum pipelines and storage facilities.

A reconciliation of movements to our ARO liabilities is as follows:



	September 30,
	2018			2017

	(in millions)
Balance at beginning of year	$	106		$	98
Liabilities incurred	87			—
Accretion expense	4			5
Liabilities settled	(5		)	—
Revision in estimate	—			3
Balance at end of year	$	192		$	106

ARO liabilities of $192 million are included in "Other long-term liabilities" on our consolidated statements of financial position.

10. NONCONTROLLING INTERESTS

The following table presents income attributable to our noncontrolling interests as outlined below:

	Three months ended June 30,					Six months ended June 30,
	Three months ended September 30,					Nine months ended September 30,
	2018		2017			2018		2017
	(in millions)
Eastern Access	$	27	$	37		$	6188	$	77114
U.S. Mainline Expansion	2728		3639			6290		69108
North Dakota Pipeline Company	—9		183			—9		1619
U.S. Line 3 Replacement Program	1311		68			2536		1119
Enbridge Holdings (DakTex) L.L.C.	2528		516			4270		521
Midcoast Energy Partners, L.P. – discontinued operations	—		(11		)	—		(19		)
Midcoast Energy Partners, L.P. - discontinued operations	—		—			—		(19		)
Total	$	92103	$	91103		$	~~190~~293	$	~~159~~262

1011. PARTNERS' CAPITAL

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-rated basis. For the ~~six~~nine months ended ~~June~~September 30, 2018, the carrying amounts for the capital accounts of the Class B common units were reduced below zero due to distributions to limited partners in excess of earnings and were subsequently cured. Class A common units and i-units had positive capital balances and therefore, as outlined in the partnership agreement, we allocated earnings of $~~158~~255 million to our General Partner to recover previous curing allocations made by the General Partner.

Redemption of Series 1 Preferred Units

In April 2017, we redeemed all of our outstanding Series 1 Preferred ~~Units~~units held by our General Partner at face value of $1.2 billion in cash. The remaining unamortized beneficial conversion feature discount of $9 million was recorded against the capital balance of the General Partner. Additionally, we repaid $357 million in deferred distributions on the Series 1 Preferred ~~Units~~units owed to our General Partner upon the closing of the Midcoast sale.

Issuance of Class A Units

In April 2017, we funded the redemption of the Series 1 Preferred ~~Units~~units through the issuance of 64.3 million Class A common units to our General Partner at a price of $18.66 per Class A common unit. The Class A common units were ~~recognized at fair value. The fair value of the Class A common units was $18.57 per unit, resulting in a $1.2 billion increase to the Class A common units capital account.~~

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recognized at fair value. The fair value of the Class A common units was $18.57 per unit, resulting in a $1.2 billion increase to the Class A common units capital account.

Simplification of Incentive Distributions

In April 2017, a wholly-owned subsidiary of our General Partner irrevocably waived all of its rights associated with its 66.1 million Class D units and 1,000 incentive distribution units (IDU), in exchange for the issuance of 1,000 Class F units. The waiver represented an extinguishment, resulting in a derecognition of the Class D units and IDUs at their respective carrying values. The Class F units were recorded at their fair value using the income approach on the basis of discounted cash flow from expected quarterly distributions of $263 million with the difference between the fair value of the Class F units and the carrying value of the Class D units and IDUs being recorded as an increase of $2.7 billion to our General Partner's capital accounts.

1112. RELATED PARTY TRANSACTIONS

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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~~affiliates” on our consolidated statements of income.

Enbridge and its affiliates allocated direct workforce costs to us for our construction projects of $58 million and $17 million as of ~~June~~September 30, 2018 and December 31, 2017, respectively, which we recorded as additions to “Property, plant and equipment, net” on our consolidated statements of financial position.

Affiliate Revenues

We record operating revenues for storage, transportation and terminalling services we provide to affiliates, which are presented in “Transportation and other services - ~~affiliate~~affiliates” on our consolidated statements of income.

Financial Transactions with Affiliates

EUS 364-day Credit Facility

We are party to 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, $750 million. ~~As of June 30, 2018, we had $750 million outstanding under this facility, excluding any accrued interest to date.~~

On July 24, 2018, we entered into an agreement with EUS whereby the termination date was extended to July 23, 2019. The terms of our agreement with EUS remain unchanged. At that time, we may elect to convert any outstanding loans to term loans, which would mature on July 23, 2020.

As of September 30, 2018, we had $750 million outstanding under this facility, excluding any accrued interest to date.

Joint Funding Arrangement for Bakken Pipeline System

We have a joint funding arrangement with our General Partner which established ownership in the Class A units of DakTex, the entity through which we and our General Partner own our interest in MarEn. Our General Partner owns a 75% interest and we own a 25% interest in DakTex, with an option for us to increase our interest by 20% at a price equal to net book value, at any time during the five years subsequent to the June 1, 2017 in-service date of the Bakken Pipeline System.

Our General Partner made contributions to DakTex totaling $4 million and $14 million, respectively, for the six months ended June 30, 2018 and 2017, respectively. During the second quarter of 2017 we received distributions from DakTex in the amount of $1.1 billion. The funds received, along with additional borrowing under the EUS 364-day Credit Facility, were used to repay a bridge loan from EUS which was subsequently terminated. 16

~~Equity~~TABLE ~~income~~OF for the three and six months ended June 30, 2018, was $33 million and $56 million, respectively and $6 million for the six months ended June 30, 2017, of which 75% is attributable to our General Partner and recorded as part of NCI. CONTENTS

Our General Partner made contributions to DakTex totaling $7 million and $30 million, respectively, for the nine months ended September 30, 2018 and 2017, respectively. During the second quarter of 2017 we received distributions from DakTex in the amount of $1.1 billion. The funds received, along with additional borrowing under the EUS 364-day Credit Facility, were used to repay a bridge loan from EUS which was subsequently terminated.

Income from equity investment in joint venture for the three and nine months ended September 30, 2018, was $37 million and $93 million, respectively and $22 million and $28 million, respectively, for the three and nine months ended September 30, 2017, of which 75% is attributable to our General Partner and recorded as part of NCI.

Joint Funding Arrangement for U.S. Line 3 Replacement Program

We have a joint funding arrangement with our General Partner for the U.S. Line 3 Replacement Program (U.S. L3R Program). Under the terms of the arrangement, our General Partner funds 99% and we fund 1% of the capital cost of the U.S. L3R Program. We have an option to increase our interest in the U.S. L3R Program assets up to 40% in the U.S. portion at book value at any time up to four years after the project goes into service. Our General Partner paid $450 million for its 99% interest in the project in January 2017, including our share of the construction costs and other incremental amounts. The carrying amount of our General Partner's 99% interest in the project was recorded as an increase to noncontrolling interest. The $40 million difference between the cash received and the carrying amount was recorded as an increase to the capital accounts of our common units, i-units, and General Partner interest on a pro-rated basis.

15Our General Partner made contributions to Enbridge Energy, Limited Partnership (OLP) totaling $189 million and $185 million for the nine months ended September 30, 2018 and 2017, respectively, to fund its portion of the construction costs associated with the U.S. L3R Program.

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Our General Partner made contributions to Enbridge Energy, Limited Partnership (OLP) totaling $155 million and $100 million for the six months ended June 30, 2018 and 2017, respectively, to fund its portion of the construction costs associated with the U.S. L3R Program.

Joint Funding Arrangement for Eastern Access Projects

We have a joint funding arrangement with our General Partner that established the Series EA interests in the OLP (the EA interest), which were created to finance the Eastern Access Project 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.

In January 2017, we exercised our option under the Eastern Access joint funding arrangement to acquire an additional 15% interest in the Eastern Access Project, thereby increasing our ownership interest from 25% to 40% and reducing the interest of our General Partner from 75% to 60%. The exercise of our option occurred at book value of approximately $360 million and reduced noncontrolling interests by approximately $360 million. The Eastern Access Project was placed into service in June 2016.

Our General Partner made contributions to the OLP totaling $1 million and $69 million for the ~~six~~nine months ended ~~June~~September 30, 2018 and 2017, respectively, to fund its portion of the construction costs associated with the Eastern Access Project.

Joint Funding Arrangement for U.S. Mainline Expansion Projects

The OLP also has a series of partnership interests (the ME interests) which 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 we own 25% of the ME interests, with an option for us to increase our ownership interest by an additional 15% at cost, under the Mainline Expansion joint funding arrangement.

Our General Partner made contributions to the OLP totaling $58 million and $2627 million for the ~~six~~nine months ended ~~June~~September 30, 2018 and 2017, respectively, to fund its portion of the construction costs associated with the Mainline Expansion Projects.

Distributions

Distributions from Enbridge Holdings (DakTex) L.L.C.

The following table presents distributions paid by DakTex during the six months ended June 30, 2018, to our General Partner and its affiliate, representing the noncontrolling interest in Class A units of DakTex, and to us, as the holders of the remaining Class A units of DakTex.17

DistributionDeclaration Date	DistributionPayment Date	Amount Paid toEEP		Amount Paid tononcontrolling Interest		Total DakTexDistribution
		(in millions)
June 28, 2018	June 28, 2018	$	11	$	35	$	46
April 6, 2018	April 6, 2018	12		38		50
		$	23	$	73	$	96

Distributions to Series EA Interests

The following table presents distributions paid by the OLP during the six months ended June 30, 2018, 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 partner interests and certain limited partner interests.

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DistributionDeclaration Date	DistributionPayment Date	Amount Paid toEEP		Amount Paid tononcontrolling Interest		Total Series EADistribution
		(in millions)
April 27, 2018	May 15, 2018	$	32	$	47	$	79
January 31, 2018	February 14, 2018	34		50		84
		$	66	$	97	$	163

The following table presents distributions paid by DakTex during the nine months ended September 30, 2018, to our General Partner and its affiliate, representing the noncontrolling interest in Class A units of DakTex, and to us, as the holders of the remaining Class A units of DakTex.



Distribution Declaration Date	Distribution Payment Date	Amount Paid to EEP		Amount Paid to noncontrolling Interest		Total DakTex Distribution
		(in millions)
September 27, 2018	September 27, 2018	$	13	$	41	$	54
June 28, 2018	June 28, 2018	$	11	$	35	$	46
April 6, 2018	April 6, 2018	12		38		50
		$	36	$	114	$	150

Distributions to Series EA Interests

The following table presents distributions paid by the OLP during the nine months ended September 30, 2018, 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 partner interests and certain limited partner interests.



Distribution Declaration Date	Distribution Payment Date	Amount Paid to EEP		Amount Paid to noncontrolling Interest		Total Series EA Distribution
		(in millions)
July 25, 2018	August 14, 2018	$	26	$	38	$	64
April 27, 2018	May 15, 2018	32		47		79
January 31, 2018	February 14, 2018	34		50		84
		$	92	$	135	$	227

Distributions to Series ME Interests

The following table presents distributions paid by the OLP during the ~~six~~nine months ended ~~June~~September 30, 2018, 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 partner and certain limited partner interests.

DistributionDeclaration Date	DistributionPayment Date	Amount Paid toEEP		Amount Paid tononcontrollingInterest		Total Series MEDistribution
		(in millions)
April 27, 2018	May 15, 2018	$	13	$	40	$	53
July 25, 2018	August 14, 2018	$	11	$	31	$	42
April 27, 2018	May 15, 2018	13		40		53
January 31, 2018	February 14, 2018	15		44		59
		$	2839	$	84115	$	~~112~~154

1213. COMMITMENTS AND CONTINGENCIES

Environmental Liabilities

We are subject to federal and state laws and regulations relating to the protection of the environment. These laws and regulations can change from time to time, imposing new obligations on us. Environmental risk is inherent to liquid hydrocarbon pipeline operations, and we are, at times, subject to environmental remediation at various contaminated sites. We manage this environmental risk through 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 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 June 30, 2018 and December 31, 2017, our consolidated statements of financial position included $17 million and $23 million, respectively, in “Environmental liabilities,” and $26 million and $51 million, respectively, in “Other long-term liabilities,” that we have accrued for costs to address remediation of contaminated sites, asbestos containing materials, management of hazardous waste material disposal, outstanding air quality measures for certain of our liquids assets and penalties we have been or expect to be assessed. On May 31, 2018, we received a No Further Action letter from the Michigan Department of Environmental Quality and subsequently reduced our Line 6B environmental accrual by $28 million. 18

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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, 2018 and December 31, 2017, our consolidated statements of financial position included $16 million and $23 million, respectively, in “Environmental liabilities,” and $25 million and $51 million, respectively, in “Other long-term liabilities,” that we have accrued for costs to address remediation of contaminated sites, asbestos containing materials, management of hazardous waste material disposal, outstanding air quality measures for certain of our liquids assets and penalties we have been or expect to be assessed. On May 31, 2018, we received a No Further Action letter from the Michigan Department of Environmental Quality and subsequently reduced our Line 6B environmental accrual by $28 million.

Legal and Regulatory Proceedings

We are subject to various legal and regulatory actions and proceedings that arise in the normal course of business, including interventions in regulatory proceedings and challenges to regulatory approvals and permits by special interest groups. Some of these proceedings are covered, in whole or in part, by insurance.

~~We are in discovery in relation to a unitholder class and derivative action, with trial scheduled in the second quarter of 2019~~14. ASUBSEQUENT ~~motion~~EVENTS to dismiss the entirety of the action is pending. An estimate of reasonably possible losses, if any, associated with causes of action cannot be made until all of the facts, circumstances and legal theories relating to such claims and the defenses are fully disclosed and analyzed. We have not established any reserves relating to this

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action. We believe the action is without merit and expect to vigorously defend against it. We believe an unfavorable outcome to be more than remote but less than probable.

13. SUBSEQUENT EVENTS

Distribution to Partners

On ~~July~~October 2524, 2018, the board of directors of Enbridge Management declared a distribution payable to our partners on ~~August~~November 14, 2018. The distribution will be paid to unitholders of record as of ~~August~~November 7, 2018 of our available cash of $~~164~~165 million at ~~June~~September 30, 2018, or $0.35 per limited partner unit. Of this distribution, $130 million will be paid in cash, $3334 million will be distributed in i-units to our i-unitholder, Enbridge Management, and due to the i-unit distribution, $1 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 ~~July~~October 2524, 2018, the managing general partner 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 $3840 million to the noncontrolling interest in the Series EA, while $2627 million will be paid to us.

Distribution to Series ME Interests

On ~~July~~October 2524, 2018, the managing general partner 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 $3133 million to the noncontrolling interest in the Series ME, while $11 million will be paid to us.

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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, 2017, as filed with the Securities and Exchange Commission (SEC) on February 16, 2018.

RECENT DEVELOPMENTS

PROPOSED MERGER

On September 18, 2018, we announced our entry into a definitive agreement (the Merger Agreement) with respect to the Proposed Merger pursuant to which an indirect wholly-owned subsidiary of Enbridge will be merged with and into us with us surviving as an indirect wholly-owned subsidiary of Enbridge. Under the terms of the Merger Agreement, at the effective time of the Proposed Merger, Enbridge will acquire all of our outstanding Class A common units not currently beneficially owned by Enbridge in an all stock-for-unit transaction at a ratio of 0.3350 common shares of Enbridge per Class A common unit (the Agreed Exchange Ratio), in a taxable transaction to our common unitholders. The Agreed Exchange Ratio represents an approximate 8.7% increase to the exchange ratio of 0.3083 common shares of Enbridge per Class A common unit that was initially offered by Enbridge on May 17, 2018. The Proposed Merger is part of Enbridge's sponsored vehicle restructuring initiative to simplify its corporate structure.

The completion of the Proposed Merger is subject to certain customary closing conditions, including the (i) affirmative vote of (a) at least 66 2/3% of our outstanding limited partner units entitled to vote on such matter and (b) a majority of our outstanding Class A common units (other than Class A common units held by Enbridge and its affiliates) and the outstanding i-units held by Enbridge Management (other than i-units voted at the direction of Enbridge and its affiliates) entitled to vote on such matter as of the close of business on November 5, 2018, the record date for determining the unitholders entitled to vote on the Proposed Merger, voting as a single class (clauses (a) and (b), collectively, the Unitholder Approval), (ii) the Enbridge common stock issuable in connection with the Proposed Merger having been approved for listing on the New York Stock Exchange (NYSE) and the Toronto Stock Exchange, subject to official notice of issuance, (iii) Enbridge's registration statement on Form S-4 having become effective under the Securities Act of 1933, as amended (the Securities Act). (iv) expiration or termination of any waiting period (and any extension thereof) applicable to the Proposed Merger under the Hart-Scott Rodino Antitrust Improvements Act of 1976, and (v) the absence of any governmental order prohibiting the consummation of the Proposed Merger or the other transactions contemplated thereby. The obligation of each party to the Merger Agreement to consummate the Proposed Merger is also conditioned upon the accuracy of the representations and warranties of the other parties as of the date of the Merger Agreement and as of the closing (subject to customary materiality qualifiers), the performance by the other parties of all obligations under the Merger Agreement at or prior to closing and receipt of an officer’s certificate evidencing the satisfaction of the foregoing.

As a result of the completion of the Proposed Merger, our common units will no longer be publicly traded. All of our outstanding debt is expected to remain outstanding. Subject to the satisfaction or waiver of certain conditions, including the Unitholder Approval, the Proposed Merger is targeted to close in fourth quarter of 2018.

MINNESOTA PUBLIC UTILITIES COMMISSION APPROVAL OF U.S. LINE 3 REPLACEMENT PROGRAM

On June 28, 2018, the Minnesota Public Utilities Commission (MNPUC) approved the issuance of Certificate of Need (Certificate) and pipeline route (Route Permit) for construction of the U.S. L3R Program in Minnesota. The Route Permit adopted our preferred route, with minor modifications and subject to certain conditions. For further details refer to Growth Projects - Regulatory Matters - U.S. L3R Program.

ENBRIDGE INC. OFFER TO ACQUIRE PUBLICLY OWNED CLASS A COMMON UNITS

On May 18, 2018, we announced that we received a non-binding offer from Enbridge, the indirect parent of our General Partner, together with a wholly-owned subsidiary of Enbridge to acquire all of our outstanding Class A common units not currently beneficially owned by Enbridge (the Proposed Transaction). Under the terms of the Proposed Transaction, our public Class A common unitholders would receive 0.3083 common shares of Enbridge per Class A common unit.

The board of directors of Enbridge Energy Management, L.L.C., (EEQ) as the delegate of our General Partner, has established a special committee of independent directors to review and consider the Proposed Transaction. Any definitive agreement is subject to applicable board and unitholder approvals by 66 2/3% of our outstanding units and is expected to contain customary closing conditions, including standard regulatory notifications and approvals.

The Proposed Transaction is part of Enbridge's sponsored vehicle initiative to simplify its corporate structure. On May 17, 2018, Enbridge announced separate all-share proposals to the respective boards of directors of Enbridge's other sponsored vehicles, including Spectra Energy Partners, LP (SEP), Enbridge Income Fund Holdings Inc. (ENF), and EEQ to acquire, in separate combination transactions, all of the outstanding equity securities of those sponsored vehicles not beneficially owned by Enbridge.

U.S. TAX REFORM

On December 22, 2017, United States legislation referred to as the Tax Cuts and Jobs Act (TCJA) was signed into law. The most significant change included in the TCJA iswas a reduction in the corporate federal income tax rate from 35% to 21% (U.S. Tax Reform). This rate change resulted in a reduction attributable to the income tax component of ~~the tolls in our Federal Energy Regulatory Commission (FERC) regulated cost of service based Lakehead Facility Surcharge Mechanism (FSM) projects.~~

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the tolls in our Federal Energy Regulatory Commission (FERC) regulated cost of service based Lakehead Facility Surcharge Mechanism (FSM) projects.

REVISED FERC POLICY ON TREATMENT OF INCOME TAXES

On March 15, 2018, the FERC changed its long-standing policy on the treatment of income tax amounts included in the rates of pipelines and other entities subject to cost of service rate regulation within a Master Limited Partnership (MLP). The FERC revised a policy in place since 2005 to no longer permit entities organized as MLPs to recover an income tax allowance in their cost of service rates. The 2018 financial impact of this action combined with the U.S. Tax Reform is expected to reduce revenues by approximately $180 million. The announcement of the Revised Policy Statement was accompanied by a Notice of Inquiry seeking comment on how FERC should address changes related to Accumulated Deferred Income Taxes (ADIT) and bonus depreciation. We are organized as an MLP and certain of the rates applicable to our expansion projects are tolled annually on a cost of service basis, via the FSM. These FERC announcements have adversely affected MLPs generally, including us.

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We filed comments to request clarification, reconsideration and rehearing of FERC’s Revised Policy Statement in April and filed comments in response to the Notice of Inquiry in May. On April 27, 2018, the FERC issued a tolling order for the purpose of affording it additional time for consideration of matters raised on rehearing.

On July 18, 2018, the FERC issued an Order that: (i) dismissed all requests for rehearing of its March 15, 2018, revised policy statement and explained that its revised policy statement does not establish a binding rule, but is instead an expression of general policy that the Commission intends to follow in the future; and (ii) provides guidance that if an MLP or other tax pass-through pipeline eliminates its income tax allowance from its cost of service pursuant to FERC’s Revised Policy Statement, then ADIT will similarly be removed from its cost of service and MLP pipelines may also eliminate previously-accumulated sums in ADIT ~~instead of flowing ADIT balances back to ratepayers~~. As a statement of general policy, the FERC will consider alternative application of its tax allowance and ADIT policy on a case-by-case basis.

We continue to assess the financial impact of the July 18, 2018, announcement but expect it would increase 2018 revenues by $40 million with the assumption the guidance is retroactive to March 2018. Pending greater clarification from the FERC on the application of its new policy, assessing the near-term and long-term implications of the policy is challenging. We have provided our best estimate of the implications to 2018, which includes a $40 million positive impact from the proposed ADIT change and the $180 million negative impact from the tax changes noted above.

RESULTS OF OPERATIONS - OVERVIEW

We provide services to our customers and returns for our unitholders through our liquids business, which consists of interstate pipeline transportation and storage of crude oil and liquid petroleum. Our liquids business is conducted through three systems: Lakehead System, Mid-Continent System and Bakken Assets. 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 Canadian portion of the liquid petroleum mainline system (Enbridge System), 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.

In June 2017 our General Partner acquired all of our ownership interests in our Midcoast gas gathering and processing business through the acquisition of all of our 48.4% interest in Midcoast Operating, all of our ownership interests in Midcoast Holdings, L.L.C., and all of our limited partnership interests in MEP.

The results of our Midcoast gas gathering and processing business are included in “Loss from discontinued operations” in our consolidated statements of income.

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The following table reflects our results of operations for the three and ~~six~~nine months ended ~~June~~September 30, 2018 and 2017:

	Three months ended June 30,						Six months ended June 30,
	Three months ended September 30,						Nine months ended September 30,
	2018			2017			2018			2017
	(in millions)
Operating revenues	$	~~537~~560		$	~~596~~616		$	1,~~129~~689		$	1,~~201~~817
Operating expenses:
Environmental costs, net of recoveries	~~(23~~4		)	41			(2218		)	1415
Operating and administrative	6762			8477			~~136~~198			~~162~~239
Operating and administrative - affiliate	68			74			131			150
Operating and administrative - affiliates	64			85			195			235
Power	7583			6681			~~152~~235			~~140~~221
Depreciation and amortization	~~109~~111			~~108~~112			~~219~~330			~~217~~329
Impairment of long-lived asset	1			—			3637			—
Gain on sale of assets	—(22		)	(516		)	—(22		)	(6268		)
	297			285			652			621
	303			350			955			971
Operating income	~~240~~257			~~311~~266			~~477~~734			~~580~~846
Interest expense, net	~~101~~102			~~103~~104			~~205~~307			~~202~~306
Allowance for equity used during construction	16			1112			3248			2133
Income from equity investment in joint venture	3337			622			5693			628
Other income (expense)	(1—		)	5—			(1		)	5
Income from continuing operations before income taxes	~~187~~208			~~230~~196			~~359~~567			~~410~~606
Income tax benefit	—			2			—			1
Income tax benefit (expense)	(1		)	—			(1		)	1
Income from continuing operations	~~187~~207			~~232~~196			~~359~~566			~~411~~607
Loss from discontinued operations, net of taxes	—			~~(35~~—		)	—			(57		)
Net income	~~187~~207			~~197~~196			~~359~~566			~~354~~550
Noncontrolling interests	(92103		)	(91103		)	(~~190~~293		)	(~~159~~262		)
Series 1 preferred unit distributions	—			(6		)	—			(29		)
Series 1 Preferred unit distributions	—			—			—			(29		)
Accretion of discount on Series 1 preferred units	—			(7		)	—			(8		)
Accretion of discount on Series 1 Preferred units	—			—			—			(8		)
Net income - controlling interests	$	95104		$	93		$	~~169~~273		$	~~158~~251

THREE MONTHS ENDED ~~JUNE~~SEPTEMBER 30, 2018 COMPARED TO THREE MONTHS ENDED ~~JUNE~~SEPTEMBER 30, 2017

Operating Revenues

The $5956 million decrease was mainly driven by:

• Lower Lakehead System revenues driven by the regulatory impact of the U.S. Tax Reform ~~of approximately $20 million~~ and the change in FERC income tax policy which no longer permits recovery of an income tax allowance in cost of service rates ~~of approximately $33 million, partially offset by an increase in operating revenue due to increased flow-through of recoverable power costs attributable to higher throughput~~.

Operating Expenses

The $12 million increase was mainly driven by:

• Absence of a $51 million gain on disposition from the sale of unnecessary pipe related to the Sandpiper Project in 2017;

• Higher operating expenses on our Cushing Storage Terminal within our Mid-Continent System driven by higher scheduled facilities integrity work; and

• Higher flow-through power costs resulting from higher throughput on the Lakehead System.

partially offset by:

• ~~Lower~~An ~~Lakehead~~increase ~~System~~in operating ~~expenses~~revenue ~~driven~~due byto ~~the~~increased ~~timing~~flow-through of ~~operating~~recoverable ~~expenses;~~power costs attributable to higher throughput and an increase in the index toll effective July 1, 2018.

•Operating ~~The reduction of our environmental accrual in relation to Line 6B of approximately $28 million.~~Expenses

21The $47 million decrease was mainly driven by:

~~TABLE~~• OFLower ~~CONTENTS~~Lakehead System operating expenses driven by higher oil measurement gains and the timing of operating expenses; and


•	A higher gain on the disposition from the sale of unnecessary materials related to the Sandpiper Project.

Income from equity investment in joint venture

The $2715 million increase was driven by ~~a full quarter of equity earnings from our interest in the Bakken Pipeline System, which was placed into service on June 1, 2017.~~:

~~Loss~~• Higher volumes on the Bakken Pipeline System resulting in higher earnings from ~~discontinued~~our ~~operations,~~investment ~~net~~in ofthe ~~taxes~~Bakken Pipeline System.

The $35 million improvement was driven by the sale of our Midcoast gas gathering and processing business in June 2017, to our General Partner, resulting in the absence of losses in the second quarter of 2018. 22

~~SIX~~TABLE ~~MONTHS~~OF ~~ENDED JUNE 30, 2018 COMPARED TO SIX MONTHS ENDED JUNE 30, 2017~~ CONTENTS

NINE MONTHS ENDED SEPTEMBER 30, 2018 COMPARED TO NINE MONTHS ENDED SEPTEMBER 30, 2017

Operating Revenues

The $72128 million decrease was mainly driven by:

• Lower Lakehead System revenues driven by the change in FERC income tax policy of approximately $65 million and the regulatory impact from the U.S. Tax Reform of approximately $60 million; and


•	Lower operating revenues from our Mid-Continent System as a result of the sale of the Ozark Pipeline in March 2017.

partially offset by:

• Higher operating revenue due to increased flow-through of recoverable power costs resulting from higher throughput on the Lakehead System.; and


•	An increase in the Lakehead System index toll effective July 1, 2018.

Operating Expenses

The $3116 million ~~increase~~decrease was mainly driven by:

• An impairment charge of $3637 million in 2018 related to our Line 10 crude oil pipeline, a component of the Lakehead System. The impairment charge results from the classification of Line 10 as held for sale and the subsequent measurement at the lower of carrying value and fair value less cost to sell; and


•	Higher flow-through power costs resulting from higher throughput on the Lakehead System.

partially offset by:

• Lower Lakehead System operating expenses driven by higher oil measurement gains and the timing of operating expenses;

• ~~Lower~~A ~~operating expenses from our Mid-Continent System primarily due to~~ lower ~~environmental~~gain ~~costs~~on ~~resulting~~disposition from ~~$10~~the ~~million~~sale inof ~~environmental~~unnecessary ~~remediation~~materials ~~costs~~ related to ~~a release on~~ the ~~Ozark~~Sandpiper ~~Pipeline in January 2017~~Project; and

• ~~Reduction~~A ofreduction ~~our~~in net environmental ~~accrual~~accruals inpredominately ~~relation~~attributable to Line 6B ~~of approximately $28 million; and~~.

• Absence of a $51 million gain on disposition from the sale of unnecessary pipe related to the Sandpiper Project in 2017.

Income from equity investment in joint venture

The $5065 million increase was driven by ~~equity earnings from our interest in the Bakken Pipeline System, which was placed into service on June 1, 2017.~~:

~~Loss~~• A full year of equity earnings from ~~discontinued~~our ~~operations~~interest in the Bakken Pipeline System, ~~net~~which ofwas ~~taxes~~placed into service on June 1, 2017; and

~~The~~• ~~$57~~Higher ~~million~~volumes ~~improvement~~on ~~was driven by~~ the ~~sale~~Bakken ofPipeline ~~our~~System ~~Midcoast~~resulting ~~gas gathering and processing business~~ in ~~June~~higher ~~2017~~earnings tofrom our ~~General~~investment ~~Partner, resulting~~ in the ~~absence~~Bakken ofPipeline ~~losses in the first and second quarters of 2018~~System.

Income attributable to noncontrolling interests

The $31 million increase was mainly driven by:


•	The sale of our interest in our Midcoast gas gathering and processing business resulting in the absence of losses attributable to NCI;


•	Equity earnings from our investment in the Bakken Pipeline System, which was placed into service on June 1, 2017, of which 75% of the earnings are attributable to NCI; and


•	The allocation of credits in relation to both the interest component and the cost of equity component of allowance for funds used during construction related to contributions made by our General Partner in relation to the U.S. L3R Program, of which 99% is attributable to NCI under the terms of our joint funding arrangement.

22partially offset by:


•	Lower income attributable to interests in Eastern Access and U.S. Mainline expansion, due to lower allocatable income as a result of the FERC income tax policy and U.S. Tax Reform.

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Series 1 Preferred Units Distribution

The $29 million decrease was driven by the April 2017 redemption of our outstanding Series 1 Preferred Units resulting in the absence of preferred distributions in the first and second quarter of 2018.

RESULTS OF OPERATIONS - LIQUIDS

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

	Three months ended June 30,						Six months ended June 30,
	Three months ended September 30,						Nine months ended September 30,
	2018			2017			2018			2017
	(in millions)
Operating Results:
Operating revenues	$	~~537~~560		$	~~596~~616		$	1,~~129~~689		$	1,~~201~~817
Operating expenses:
Environmental costs, net of recoveries	23(4		)	(41		)	2218			(1415		)
Operating and administrative	(~~129~~125		)	(~~154~~161		)	(~~258~~383		)	(~~304~~465		)
Power	(7583		)	(6681		)	(~~152~~235		)	(~~140~~221		)
Impairment of long-lived asset	(1		)	—			(3637		)	—
Gain on sale of assets	—22			516			—22			6268
Allowance for equity used during construction	16			1112			3248			2133
Income from equity investment in joint venture	3337			622			5693			628
EBITDA	$	~~404~~422		$	~~440~~413		$	~~793~~1,215		$	~~832~~1,245
Operating Statistics:
Lakehead System:
United States(1)	2,~~178~~073			1,~~986~~982			2,~~128~~109			2,~~021~~008
Canada(1)	~~599~~654			~~618~~638			~~643~~647			~~654~~649
Total Lakehead System delivery volumes(1)	2,~~777~~727			2,~~604~~620			2,~~771~~756			2,~~675~~657
Barrel miles (billions)	~~194~~196			~~183~~188			~~386~~582			~~375~~563
Average haul (miles)	~~769~~783			~~774~~782			~~770~~774			~~773~~776
Mid-Continent System delivery volumes(1)	—			—			—			4733
Bakken Assets:
North Dakota System to Clearbrook(1)	~~217~~220			219			~~216~~218			~~211~~214
Bakken System to Cromer(1)	6458			~~136~~84			5456			~~134~~116
Total Bakken Assets delivery volumes(1)	~~281~~278			~~355~~303			~~270~~274			~~345~~330
Total Liquids segment delivery volumes(1)	3,~~058~~005			2,~~959~~923			3,~~041~~030			3,~~067~~020

___________________________


(1)	Average Bpd in thousands.

THREE MONTHS ENDED ~~JUNE~~SEPTEMBER 30, 2018 COMPARED TO THREE MONTHS ENDED ~~JUNE~~SEPTEMBER 30, 2017

EBITDA ~~decreased~~increased by $369 million primarily due to the following items:

• ~~Lower~~Higher ~~Lakehead~~volumes ~~System~~on ~~EBITDA was driven by~~ the ~~regulatory~~Bakken ~~impact~~Pipeline ofSystem ~~the~~resulting ~~U.S.~~in ~~Tax~~higher ~~Reform~~earnings ~~and~~from ~~the~~our ~~FERC~~investment ~~income tax policy to no longer permit recovery of an income tax allowance~~ in ~~cost~~the ofBakken ~~service~~Pipeline ~~rates~~System;

• ~~Higher~~An ~~operating~~increase ~~expense~~in ~~driven by scheduled facilities integrity work on our Cushing Storage Terminals within~~ the ~~Mid-Continent~~Lakehead System ~~offsetting~~index ~~storage~~toll ~~revenues~~effective ~~and~~July ~~additional income earned from operating the Ozark Pipeline post sale, March~~ 1, ~~2017~~2018; ~~and~~

• ~~Absence~~Lower ofoperating aexpenses ~~$51 million gain~~ on ~~disposition~~the ~~from~~Lakehead ~~the~~System ~~sale~~due ofto ~~unnecessary~~higher ~~pipe~~oil ~~related~~measurement togains and the ~~Sandpiper~~timing ~~Project~~of inoperating ~~2017.~~expenses; and


•	A higher gain on the disposition from the sale of unnecessary materials related to the Sandpiper Project.

partially offset by:

23• Lower Lakehead System EBITDA driven by the regulatory impact of the U.S. Tax Reform and the FERC income tax policy to no longer permit recovery of an income tax allowance in cost of service rates.

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•NINE AMONTHS ~~full~~ENDED ~~quarter of equity earnings from our interest in the Bakken Pipeline System~~SEPTEMBER 30, ~~which~~2018 ~~was~~COMPARED ~~placed~~TO ~~into~~NINE ~~service~~MONTHS onENDED ~~June 1~~SEPTEMBER 30, 2017;

•EBITDA Adecreased ~~reduction~~by in$30 ~~net~~million ~~environmental~~primarily ~~accruals~~due ~~predominately attributable~~ to ~~Line~~the ~~6B;~~following ~~and~~items:

• Lower ~~operating~~Lakehead ~~expenses~~System onEBITDA driven by the ~~Lakehead~~change ~~System~~in ~~due~~FERC toincome ~~timing~~tax policy which no longer permits recovery of ~~when~~an ~~expenses~~income ~~are~~tax ~~incurred~~allowance in cost of service rates and a lower tax rate pursuant to U.S. Tax Reform;

~~SIX~~• ~~MONTHS~~An ~~ENDED~~impairment ~~JUNE 30,~~charge of $37 million in 2018 ~~COMPARED~~related TOto ~~SIX~~our ~~MONTHS~~Line ~~ENDED~~10 ~~JUNE 30~~crude oil pipeline, ~~2017~~a component of the Lakehead System, resulting from the classification as held for sale and the subsequent measurement at the lower of its carrying value or fair value less cost to sell;

~~EBITDA~~• ~~decreased~~Lower bytransportation ~~$39~~revenues ~~million primarily~~ due to the ~~following~~sale ~~items:~~of the Ozark Pipeline on March 1, 2017; and

• AnA ~~impairment~~lower ~~charge~~gain ofon ~~$36~~disposition ~~million in 2018 related to our Line 10 crude oil pipeline, a component of the Lakehead System, resulting~~ from the ~~classification as held for~~ sale ~~and~~of ~~the~~unnecessary ~~subsequent~~materials ~~measurement~~related atto the ~~lower~~Sandpiper ~~of its carrying value or fair value less cost to sell;~~Project.

• Lower Lakehead System EBITDA driven by the change in FERC income tax policy which no longer permits recovery of an income tax allowance in cost of service rates and a lower tax rate pursuant to U.S. Tax Reform; and

• Lower transportation revenues due to the sale of the Ozark Pipeline on March 1, 2017 and higher operating expenses driven by scheduled facilities integrity work on our Cushing Storage Terminals within the Mid-Continent System.

partially offset by:

• ~~Equity~~Higher ~~earnings~~volumes ~~from~~on ~~our interest in~~ the Bakken Pipeline System, ~~which~~resulting ~~was~~in ~~placed~~higher ~~into~~earnings ~~service~~from onour ~~June~~investment 1,in ~~2017~~the Bakken Pipeline System;

• ALower ~~reduction~~operating inexpenses ~~net~~on ~~environmental~~our ~~accruals~~Lakehead ~~predominately~~System ~~attributable~~due to ~~Line~~higher 6Boil measurement gains and the timing of operating expenses; and

• ~~Lower~~A ~~operating~~reduction ~~expenses~~in onnet ~~our~~environmental ~~Lakehead~~accruals ~~System~~predominately ~~due~~attributable to ~~timing;~~Line ~~and~~6B.

• Higher storage revenue at the Cushing Storage Terminal with the Mid-Continent System.

GROWTH PROJECTS - COMMERCIALLY SECURED PROJECTS

The following table summarizes the status of our commercially secured projects for the Liquids segment. Expenditures to date reflect total cumulative expenditures incurred from inception of the project to ~~June~~September 30, 2018.



	Ownership Interest	Estimated Capital Costs⁽¹⁾	Expenditures to Date⁽²⁾	Status	Expected In-Service Date
Lakehead System Mainline Expansion - Line 61⁽³⁾⁽⁴⁾	25%	$0.4 billion	$0.4 billion	Substantially complete	2H - 2019
U.S. Line 3 Replacement Program⁽⁵⁾	1%	$2.9 billion	$0.9 billion	Pre- construction⁽⁶⁾	2H - 2019

_____________________


(1)	These amounts are estimates and are subject to upward or downward adjustment based on various factors.

(2) Expenditures to date reflect total cumulative expenditures incurred from inception of the project up to ~~June~~September 30, 2018.


(3)	Jointly funded 25% by us and 75% by our General Partner under the Mainline Expansion joint funding arrangement. Estimated capital costs are presented at 100% before our General Partner’s contributions.


(4)	Estimated in-service date will be adjusted to coincide with the in-service date of the U.S. L3R Program.


(5)	Jointly funded 1% by us and 99% by our General Partner under the Line 3 Replacement joint funding arrangement. Estimated capital costs are presented at 100% before our General Partner's contributions.


(6)	Construction of the Wisconsin portion of the project is complete as noted below. The remaining portion of the project is in pre-construction status.

The following commercially secured growth projects are expected to be placed into service in 2019:

• U.S. L3R PROGRAM - The Wisconsin portion of the U.S. L3R Program is in service. For additional updates on the project, refer to Growth Projects -– Regulatory Matters -– U.S. L3R Program,

GROWTH PROJECTS - REGULATORY MATTERS

U.S. L3R PROGRAM

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We are in the process of obtaining the appropriate permits for constructing the U.S. L3R Program in Minnesota. The project requires both a Certificate and Route Permit from the MNPUC.

On June 28, 2018, the MNPUC approved the issuance of a Certificate and Route Permit that adopts our preferred route, with minor modifications and subject to certain conditions. AThe ~~written~~MNPUC ~~order~~issued ~~documenting~~its ~~the~~Certificate ~~MNPUC’s~~of ~~rulings~~Need inorder ~~the~~on ~~Certificate~~September ~~and~~5, 2018. The Route Permit ~~dockets~~was isissued ~~expected~~on byOctober ~~September~~26, 2018. Permits are also required from the United States Army Corps of Engineers (Army Corps), state agencies (including the Minnesota Department of Natural Resources and the Minnesota Pollution Control Agency) and local ~~governments~~government authorities in Minnesota. We anticipate ~~the receipt of all required permits in time to mobilize our contractors and commence construction activities during the first quarter of 2019.~~

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the receipt of all required permits in time to commence construction activities during the first quarter of 2019, and continue to anticipate an in-service date for the project in the second half of 2019.

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.

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.

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 $21.08 billion multi-year unsecured revolving credit facility (Credit Facility) and our $625 million credit agreement (364-Day Credit Facility) together providing approximately $2.65 billion of committed bank credit facilities. 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 ~~June~~September 30, 2018, we had approximately $~~906~~740 million in available credit under the terms of our Credit Facilities.

We are also party to a 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 million. At ~~June~~September 30, 2018, we had $750 million outstanding under the terms of the EUS 364-day Credit Facility.

For further details regarding our commercial paper program, our Credit Facilities, and the EUS 364-day Credit Facility, refer to Item 1. Financial Statements – Note 8 - Debt and Note 1112 - Related Party Transactions.

As of ~~June~~September 30, 2018, we had a working capital deficit of approximately $~~735~~759 million, which includes the current portion of long-term debt of $600 million. We had approximately $~~912~~751 million of consolidated liquidity, which we expect to be sufficient to meet our ongoing operational, investing and financing needs as described above.

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The following table sets forth the consolidated liquidity available to us at ~~June~~September 30, 2018.

	June 30, 2018
	September 30, 2018
	(in millions)
Cash and cash equivalents	$	915
Total capacity under the Credit Facilities	2,~~625~~450
Total capacity under the EUS 364-day Credit Facility	750
Less: Amounts outstanding under the Credit Facilities	~~325~~388
Amounts outstanding under the EUS 364-day Credit Facility	750
Principal amount of commercial paper outstanding	1,~~394~~322
Letters of credit outstanding	34
Total	$	~~912~~751

CAPITAL RESOURCES

Debt and Equity Securities

Execution of our growth strategy and completion of our planned construction projects contemplate accessing the capital markets to obtain the necessary funding for these activities. We have issued a balanced combination of debt and equity securities to fund our expansion projects and acquisitions. Our organic growth projects and targeted acquisitions will require additional permanent capital and may 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.

Our shelf registration statement on Form S-3, which allowed us to issue an unlimited amount of equity and debt securities in underwritten public offerings expired in February of 2018. Unless we seek and receive a waiver from the SEC, a new shelf registration statement would not be expected to be filed until August of 2018, at the earliest. The delay in filing a new shelf registration statement is due to the late filing of pro forma financial information after the sale of our Midcoast gas gathering and processing business to our General Partner. Until a new shelf registration statement on Form S-3 is filed with the SEC, any issuances of debt or equity securities in underwritten public offerings would utilize a different form of registration statement or we could seek to issue debt or equity securities in a private placement. On September 18, 2018, we announced the Proposed Merger with Enbridge and Enbridge's indirect wholly-owned subsidiary. The completion of the Proposed Merger will result in our Class A common units to no longer be publicly traded.

Joint Funding Arrangements

In order to obtain capital, we have explored, and may continue to explore, numerous options, including joint funding arrangements. For certain of our joint funding arrangements currently in place, we have an option to increase our ownership of certain assets. For further details regarding our existing joint funding arrangements, including the option periods and exercise price of certain options held by us, refer to Item 1. Financial Statements – Note 1112 - Related Party Transactions.

CASH REQUIREMENTS

Capital Spending

We incurred capital expenditures of approximately $~~305~~441 million for the ~~six~~nine months ended ~~June~~September 30, 2018, including $1320 million of maintenance capital expenditures. Of those capital expenditures, $~~161~~198 million were financed by contributions from our General Partner via joint funding arrangements. At ~~June~~September 30, 2018, we had approximately $~~231~~203 million 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.

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 strategy. We forecast total expenditures of approximately $780 million in 2018, inclusive of $40 million related to maintenance capital. We expect to fund $362 million and the remaining $418 million will be funded by our General Partner based on our joint funding arrangements for the U.S. L3R Program, Eastern Access Projects, and Mainline Expansion Projects.

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Although we anticipate making these expenditures in 2018, 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.

Distributions

The following table sets forth our distributions, as approved by the board of directors of Enbridge ~~Energy~~ Management during the ~~six~~nine months ended ~~June~~September 30, 2018.

Distribution Declaration Date	Record Date	DistributionPayment Date	Distributionper Unit		CashAvailable forDistribution		Amount ofDistributionof i-unitsto i-unitHolders		RetainedfromGeneralPartner(1)		Distributionof Cash
					(in millions, except per unit amounts)
July 25, 2018	August 7, 2018	August 14, 2018	$	0.35	$	164	$	33	$	1	$	130
April 27, 2018	May 8, 2018	May 15, 2018	$	0.35	$	163	$	32	$	1	$	130
January 31, 2018	February 7, 2018	February 14, 2018	$	0.35	$	162	$	31	$	1	$	130

_____________________


(1)	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.

Cash Flow Analysis

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

	Six months ended June 30,
	Nine months ended September 30,
	2018			2017
	(in millions)
Total cash provided by (used in):
Operating activities	$	~~616~~938		$	~~215~~559
Investing activities	(~~297~~404		)	(~~165~~357		)
Financing activities	(~~345~~554		)	(41289		)
Net increase (decrease) in cash and cash equivalents and restricted cash	(2620		)	9(87		)
Cash and cash equivalents and restricted cash at beginning of year	35			115
Cash and cash equivalents and restricted cash at end of period	$	915		$	~~124~~28

Operating Activities

Net cash provided by our operating activities increased $~~401~~379 million for the ~~six~~nine months ended ~~June~~September 30, 2018, compared to the same period in 2017, primarily due to ~~increased cash from net income after non-cash adjustments, as well as~~ greater cash inflows from net changes in operating assets and liabilities. ~~Increased cash from net income after non-cash adjustments totaled $16 million and was primarily due to lower operating expenses during the period, as described in Results of Operations - Liquids.~~

Cash inflows from net changes in operating assets and liabilities increased $~~385~~381 million. ~~The~~During ~~increase~~2017, iscash ~~primarily~~inflows ~~attributable~~from tochanges in operating assets and liabilities were lower as a result of the termination of the receivables purchase agreement between us and certain of our subsidiaries, inwhich impacted the ~~second~~timing ~~quarter~~ of ~~2017~~cash inflows from our receivables. Our 2018 cash inflows from changes in operating assets and liabilities were not impacted by these timing differences. Our operating assets and liabilities fluctuate in the normal course of business due to various factors, including timing of cash payments and receipts.

Investing Activities

Net cash used in our investing activities during the ~~six~~nine months ended ~~June~~September 30, 2018, increased by $~~132~~47 million compared to the same period in 2017, primarily due to increased capital expenditures of $~~104~~49 million, predominately attributable to construction on the Wisconsin portion of our U.S. L3R Program. This increase was partially offset by cash inflows of $40 million from distributions received from our investment in the Bakken Pipeline System, which are in excess of cumulative equity earnings. We received no such dividends during the six months ended June 30, 2017.

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Financing Activities

Net cash used in financing activities increased $~~304~~265 million for the ~~six~~nine months ended ~~June~~September 30, 2018 compared to the same period in 2017 primarily due to the following:


•	Repayments on long-term debt of $400 million;

• ~~Decreased~~Lower contributions from NCI of $1.12 billion as we received funds of $1.1 billion in the second quarter of 2017 from our General Partner, as a result of the finalization of the joint funding arrangement, which resulted in our investment in the Bakken Pipeline System to be 75% owned by our General Partner and 25% by us; and


•	The absence of cash inflows of $450 million received from the sale of our 99% interest in the U.S. L3R Project to our General Partner during the first quarter of 2017.

The increase in net cash used in our financing activities were partially offset by the following:

• Net borrowings on sources of short-term financing of $~~455~~636 million; and

• Net borrowings of $~~469~~346 million under the EUS 364-day Credit Facility;


•	The absence of cash used in the acquisition of an additional 15% interest in the Eastern Access Projects of $360 million during the first half of 2017;

• The absence of cash used in the payment on Series 1 Preferred ~~Unit~~unit dividends of $357 million during the first half of 2017; and

• Decrease in distribution to partners of $8685 million due to a reduction in our quarterly distribution from $0.583 per unit to $0.35 per unit in the first quarter of 2017.

LEGAL AND OTHER UPDATES

DAKOTA ACCESS PIPELINE

In February 2017, the Standing Rock Sioux Tribe and the Cheyenne River Sioux Tribe (the Tribes) filed motions with the United States District Court for the District of Columbia (the Court) contesting the validity of the process used by the Army Corps to permit DAPL. The plaintiffs requested the Court order the operator to shut down the pipeline until the appropriate regulatory process is completed.

On June 14, 2017, the Court ruled that the Army Corps did not sufficiently weigh the degree to which the project's effects would be highly controversial and the Army Corps failed to adequately consider the impact of an oil spill on the hunting and fishing rights of the Tribes and on environmental justice (the June 2017 Order). The Court ordered the Army Corps to reconsider those components of its environmental analysis. On October 11, 2017, the Court issued an order that allows DAPL to continue operating while the Army Corps completes the additional environmental review required by the June 2017 Order. The Court additionally ordered DAPL to implement certain interim measures pending the Army Corps' supplemental analysis. The Army Corps' ~~has~~issued ~~met~~its ~~with~~decision ~~all~~on ofAugust ~~the~~31, ~~Tribes~~2018 and ~~its~~found ~~review~~that ofno ~~appropriate~~supplemental ~~information~~environmental isanalysis ~~underway~~was required. The Army Corps' decision ~~on the supplemental analysis~~ is ~~expected~~under ~~during~~review ~~August~~by ~~2018~~the Tribes.

CHANGES IN ACCOUNTING POLICIES

For further details on the impacts of recently issued and future accounting standards on our financial condition and results of operations, refer to Item 1. Financial Statements – Note 2 - Changes in Accounting Policies.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our exposure to market risk is described in Item 7A of our Annual Report on Form 10-K, for the year ended December 31, 2017. We believe our exposure to market risk has not changed materially since then.

ITEM 4. CONTROLS AND PROCEDURES

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

28We 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

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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 (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 ~~June~~September 30, 2018. Based upon that evaluation, our principal executive and principal financial officers concluded that our disclosure controls and procedures are effective at the 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.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

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 ~~June~~September 30, 2018.

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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 the outcome of all these proceedings will not, individually or in the aggregate, have a material adverse effect on our financial condition. The disclosures included in Part I – Item 1. Financial Statements – Note 1213 - Commitments and Contingencies, address the matters required by this item and are incorporated herein by reference.

JUDY MESIROV v. ENBRIDGE ENERGY CO., INC. ET AL.

On July 20, 2015, plaintiff Peter Brinckerhoff (the Plaintiff), individually and as trustee of the Peter R. Brinckerhoff Trust, filed a Verified Class Action and Derivative Complaint in the Court of Chancery of the State of Delaware against our General Partner, Enbridge, Enbridge Management, Enbridge Pipelines (Alberta Clipper) L.L.C., the OLP, us, and the following individuals: Jeffrey A. Connelly, Rebecca B. Roberts, Dan A. Westbrook, J. Richard Bird, J. Herbert England, C. Gregory Harper, D. Guy Jarvis, Mark A. Maki, and John K. Whelen, (collectively, the Director Defendants). The initial Complaint asserted both class action claims on behalf of holders of our Class A Common Units, as well as derivative claims brought on behalf of us. The Plaintiff’s claims arose out of the January 2, 2015, repurchase by us of our General Partner’s 66.67% interest in the pipeline that runs from the Canadian international border near Neche, North Dakota to Superior, Wisconsin on our Lakehead System (Alberta Clipper Pipeline), known as the 2015 Transaction. First, the Plaintiff alleged that the 2015 Transaction improperly amended without Public Unitholder consent the Sixth Amended and Restated Agreement of Limited Partnership (the LPA) so as to allocate to the Public Unitholders gross income that should have been allocated to the General Partner (the Special Tax Allocation). Second, the Plaintiff alleged that we paid an unfair price for our General Partner’s 66.67% interest in the Alberta Clipper Pipeline such that the 2015 Transaction breached the LPA because it was not fair and reasonable to the Partnership. The initial Complaint asserted claims for breach of fiduciary duty, breach of the covenant of good faith and fair dealing, breach of residual fiduciary duties, tortious interference, aiding and abetting, and rescission and reformation.

On April 29, 2016, the Court of Chancery granted Enbridge’s and the Director Defendants’ motion to dismiss and dismissed the case in its entirety. On May 26, 2016 the Plaintiff appealed that dismissal to the Delaware Supreme Court. On March 20, 2017, the Delaware Supreme Court reversed in part and affirmed in part the ruling of the Court of Chancery. Specifically, the Delaware Supreme Court affirmed that the enactment of the Special Tax Allocation did not breach the LPA, but reversed on the question of whether the Plaintiff had adequately alleged that the price we paid in the 2015 Transaction, including the Special Tax Allocation component, was fair and reasonable to the Partnership. On November 15, 2017, Plaintiff filed a Verified Second Amended Complaint (the Second Amended Complaint). The Second Amended Complaint added Piper Jaffray & Co. as successor to Simmons & Company International (Simmons) as a direct Defendant. Simmons acted as the financial advisor to our Special Committee in the 2015 Transaction. The Second Amended Complaint also revised many of the allegations against Enbridge and the Director Defendants. On December 18, 2017, all Defendants except Simmons filed their brief in support of their motion to dismiss the Second Amended Complaint. On January 19, 2018, Simmons filed its brief in support of its motion to dismiss the Second Amended Complaint.

On February 28, 2018, Plaintiff filed a Motion for Leave to File a Verified Third Amended Complaint and a Motion to Intervene on behalf of a proposed new plaintiff, Judy Mesirov (subsequently amended). On March 23, 2018, Plaintiff filed a Verified Third Amended Complaint and a Motion for Voluntary Dismissal of Brinckerhoff. On April 3, 2018, all Defendants filed their briefs in support of their motions to dismiss the Third Amended Complaint. Plaintiff Brinckerhoff has now been dismissed as a named Plaintiff. Plaintiff Mesirov filed a Fourth Amended Complaint, which is substantially the same as the Third Amended Complaint except that it substitutes Judy Mesirov in place of Peter Brinckerhoff as the named Plaintiff. ~~The~~On ~~parties~~August ~~have~~29, ~~agreed~~2018, ~~that~~the aCourt ~~ruling~~granted onin ~~the~~part ~~motions~~and denied in part Defendants’ Motions to ~~dismiss~~Dismiss the Third (now Fourth) Amended Complaint. All ~~will~~direct beclaims ~~binding~~have asnow tobeen ~~the~~dismissed, ~~now-active~~and ~~Fourth~~only ~~Amended~~derivative ~~Complaint.~~claims ~~Oral~~for ~~argument~~breach onof ~~the~~contract ~~motions~~(including toequitable ~~dismiss~~remedies ~~was~~of ~~held~~rescission onor ~~May~~reformation) ~~30,~~against ~~2018.~~our ~~The~~General ~~parties~~Partner ~~are~~and ~~currently~~aiding and abetting a breach of contract against Simmons remain in ~~discovery~~the Fourth Amended Complaint. On September 28, ~~with~~2018, ~~trial~~Plaintiff ~~currently~~filed ~~scheduled~~a ~~for~~Fifth Amended Complaint, adding Enbridge and the ~~second~~Director ~~quarter~~Defendants ofas ~~2019~~defendants to the derivative claims.

On September 18, 2018, Enbridge announced that it (on behalf of itself and certain of its wholly owned U.S. subsidiaries) had entered into definitive merger agreements with us, under which Enbridge would, subject to certain

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approvals of unitholders and other conditions, acquire all of our outstanding Class A common units (other than those held by Enbridge and its wholly owned subsidiaries). If the Proposed Merger transaction closes and Enbridge acquires all of our outstanding Class A common units, Plaintiff will lose standing to continue her derivative claims on behalf of us, and Enbridge will become the owner of such derivative claims. Trial is currently scheduled for the second quarter of 2019.

ITEM 1A. RISK FACTORS

There have been no material changes to our risk factors previously disclosed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2017, filed with the SEC on February 16, 2018, except as described below.

30THE PROPOSED MERGER IS SUBJECT TO CONDITIONS, INCLUDING SOME CONDITIONS THAT MAY NOT BE SATISFIED ON A TIMELY BASIS, IF AT ALL. FAILURE TO COMPLETE THE PROPOSED MERGER, OR SIGNIFICANT DELAYS IN COMPLETING THE PROPOSED MERGER, COULD NEGATIVELY AFFECT OUR BUSINESS AND FINANCIAL RESULTS AND THE TRADING PRICES OF OUR CLASS A COMMON UNITS.

The completion of the Proposed Merger is not assured and is subject to risks, including the risk that the Unitholder Approval is not obtained. Further, the Proposed Merger may not be completed even if the Unitholder Approval is obtained. The Merger Agreement contains conditions, some of which are beyond our control, that, if not satisfied or waived, may prevent, delay or otherwise result in the Proposed Merger not occurring.

If the Proposed Merger is not completed, or if there are significant delays in completing the Proposed Merger, Enbridge's and our future business and financial results and the trading price of our Class A common units could be negatively affected, and each of the parties will be subject to several risks, including the following:


•	the parties may be liable for expenses to one another under the terms and conditions of the Merger Agreement; and


•	there may be negative reactions from the financial markets due to the fact that current prices of our Class A common units may reflect a market assumption that the Proposed Merger will be completed.

BECAUSE THE EXCHANGE RATIO IS FIXED AND BECAUSE THE MARKET PRICE OF ENBRIDGE COMMON SHARES WILL FLUCTUATE PRIOR TO THE COMPLETION OF THE PROPOSED MERGER, OUR UNITHOLDERS CANNOT BE SURE OF THE MARKET VALUE OF THE ENBRIDGE COMMON SHARES THEY WILL RECEIVE AS MERGER CONSIDERATION RELATIVE TO THE VALUE OF OUR CLASS A COMMON UNITS THEY EXCHANGE.

The market value of the consideration that our unitholders will receive in the Proposed Merger will depend on the trading price of Enbridge common shares at the closing of the Proposed Merger. The exchange ratio that determines the number of Enbridge common shares that our unitholders will received in the Proposed Merger is fixed at 0.3350 common shares of Enbridge per Class A common unit. This means that there is no mechanism contained in the Merger Agreement that would adjust the number of Enbridge common shares that our unitholders will receive based on any decreases or increases in the trading price of Enbridge common shares. Share or unit price changes may result from a variety of factors (many of which are beyond Enbridge’s and our control), including:


•	changes in Enbridge's or our business, operations and prospects;


•	changes in market assessments of Enbridge's or our business, operations and prospects;


•	changes in market assessments of the likelihood that the Proposed Merger will be completed;


•	interest rates, commodity prices, general market, industry and economic conditions and other factors generally affecting the price of Enbridge common shares or our common units; and


•	federal, state and local legislation, governmental regulation and legal developments in the businesses in which Enbridge and we operate.

If the price of Enbridge common shares at the closing of the Proposed Merger is less than the price of Enbridge common shares on the date that the Merger Agreement was signed, then the market value of the merger consideration will be less than contemplated at the time the Merger Agreement was signed.

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~~THERE~~WHEN ~~CAN~~OUR BECLASS NOA ~~ASSURANCE~~COMMON ~~THAT~~UNITHOLDERS RECEIVE THE ~~PROPOSED~~MERGER ~~TRANSACTION~~CONSIDERATION ~~BETWEEN~~DEPENDS ~~US,~~ON ~~ENBRIDGE~~THE ~~AND~~COMPLETION ~~ENBRIDGE~~DATE ~~(U.S.)~~OF ~~INC.~~THE ~~WILL~~PROPOSED ~~BE AGREED UPON~~MERGER, ~~APPROVED~~WHICH ~~AND~~IS ~~ULTIMATELY CONSUMMATED, AND THE TERMS OF ANY SUCH TRANSACTION MAY DIFFER MATERIALLY FROM THOSE ORIGINALLY PROPOSED BY ENBRIDGE~~UNCERTAIN.

OnCompleting ~~May~~the ~~17,~~Proposed ~~2018,~~Merger ~~Enbridge~~is ~~and~~subject ~~Enbridge~~to ~~(U.S.)~~several ~~Inc.~~conditions, ~~made~~not ~~a non-binding~~ all~~-share~~ ~~proposal to the board~~ of ~~directors~~which ofare ~~the~~controllable ~~delegate~~by ofus. ~~the~~Accordingly, ~~General Partner (~~the ~~Board),~~date toon ~~acquire,~~which ~~in a combination transaction, all of~~ our ~~outstanding~~unitholders ~~Class~~will Areceive ~~common~~merger ~~units~~consideration ~~not~~depends ~~beneficially~~on ~~owned~~the bycompletion ~~Enbridge.~~date ~~Under~~of the ~~original~~Proposed ~~proposal~~Merger, ~~our~~which ~~Class~~is Auncertain ~~common~~and ~~unitholders~~subject ~~would~~to ~~receive~~several ~~0.3083~~other ~~common~~closing ~~shares of Enbridge per Class A common unit~~conditions.

The Proposed Transaction is subject to negotiation. Any definitive agreement with respect to the Proposed Transaction is subject to approval by the Enbridge board of directors, the Board, General Partner and unitholder approvals. Such definitive agreement would be expected to contain customary closing conditions, including standard regulatory notifications and approvals.

As a result, we cannot predict whether the terms of the Proposed Transaction will be agreed upon by Enbridge and the Board’s special committee for recommendation to their respective boards of directors, and with respect to us, additionally to the General Partner, for approval of the transaction, or whether any such transactions would be approved by the requisite votes of our unitholders.

We also cannot predict the timing, final structure or other terms of any potential transaction, and the terms of any such transaction may differ materially from those originally proposed by Enbridge. Any decrease in the market prices of Enbridge’s common shares would result in a corresponding proportional decrease in the value of the Enbridge common shares our unitholders would receive in the event the Proposed Transaction was consummated on the terms proposed by Enbridge. Any changes in the market prices of Enbridge’s common shares or our Class A common units could affect whether the Proposed Transaction is ultimately approved, or if such approval is granted, the terms on which the Proposed Transaction is approved.

ITEM 6. EXHIBITS

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

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INDEX OF EXHIBITS

Each exhibit identified below is included as a part of this Quarterly Report. 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
2.1		Agreement and Plan of Merger, dated as of September 17, 2018, by and among Enbridge Energy Partners, L.P., Enbridge Energy Company, Inc., Enbridge Energy Management, L.L.C., Enbridge Inc., Enbridge (U.S.) Inc., Winter Acquisition Sub II, LLC, and solely for the purposes of Articles I, II and XI, Enbridge US Holdings Inc. (incorporated by reference to Exhibit 2.1 to our Current Report on Form 8-K, filed on September 19, 2018)
10.1		Third Amendment to Credit Agreement, dated as of July 24, 2018, by and among Enbridge Energy Partners, L.P. and Enbridge (U.S.) Inc. (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K, filed on July 26, 2018)
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.

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 the General Partner
Date: August 3, 2018	By:	/s/ Mark A. Maki
		Mark A. MakiPresident(Principal Executive Officer)
Date: August 3, 2018	By:	/s/ Christopher J. Johnston
		Christopher J. JohnstonVice President, Finance(Principal Financial Officer)

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	Enbridge Energy Partners, L.P. (Registrant)

	By:	Enbridge Energy Management, L.L.C. as delegate of the General Partner

Date: November 1, 2018	By:	/s/ Mark A. Maki
		Mark A. Maki President (Principal Executive Officer)

Date: November 1, 2018	By:	/s/ Christopher J. Johnston
		Christopher J. Johnston Vice President, Finance (Principal Financial Officer)

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