Enbridge Energy Partners 10-Q 3 Aug 17 2017 Q2 Quarterly report Financial data

Document And Entity Information

Document And Entity Information - shares	6 Months Ended
	Jun. 30, 2017	Jul. 28, 2017
Document Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2017
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	Q2
Entity Registrant Name	ENBRIDGE ENERGY PARTNERS LP
Entity Central Index Key	880,285
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Trading Symbol	EEP
Entity Common Stock, Shares Outstanding		326,517,110

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions		3 Months Ended				6 Months Ended
		Jun. 30, 2017		Jun. 30, 2016		Jun. 30, 2017		Jun. 30, 2016
Operating revenues:
Transportation and other services	[1]	$ 596.5	[2]	$ 621.3	[3]	$ 1,201.2	[4]	$ 1,251	[5]
Total operating revenues	[1]	596.5	[2]	621.3	[3]	1,201.2	[4]	1,251	[5]
Operating expenses:
Environmental costs, net of recoveries	[1]	3.5		0.1		13.8		17
Operating and administrative	[1]	158.3		134.1		311.4		276.4
Power	[1]	66.4		59.7		140.9		132.5
Depreciation and amortization	[1]	108.3		104.9		217.1		206.3
Gain on sale of assets (Note 6)		(51.5)		0		(62.1)	[1]	0
Operating Expenses		285		298.8		621.1		632.2
Operating income	[1]	311.5		322.5		580.1		618.8
Interest expense, net	[1]	(102.8)		(93.3)		(201.7)		(197.8)
Allowance for equity used during construction	[1]	10.7		13.3		21		25.6
Other income	[1]	11.4		0.2		11.4	[6]	0.4
Income from continuing operations before income tax	[1]	230.8	[6]	242.7		410.8		447
Income tax benefit (expense)	[1]	1.6		(2)		0.5		(3.6)
Income from continuing operations	[1]	232.4		240.7		411.3		443.4
Loss from discontinued operations, net of tax (Note 6)	[1]	(35.4)		(63)		(56.8)		(93.3)
Net income	[1]	197		177.7		354.5		350.1
Less: Net income attributable to:
Noncontrolling interests		90.6		70.3		158.9		139.1
Series 1 preferred unit distributions		6.5		22.5		29		45
Accretion of discount on Series 1 preferred units		7.3		1.2		8.5		2.3
Net income attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P.		92.6		83.7		158.1		163.7
Net income (loss) allocable to common units and i-units:
Income from continuing operations		104.9		73.7		172.1		118.8
Loss from discontinued operations		(24.2)		(46)		(38)		(67)
Net income allocable to common units and i-units		$ 80.7		$ 27.7		$ 134.1		$ 51.8
Net income (loss) per common unit and i-unit (basic and diluted):
Income from continuing operations		$ 0.27		$ 0.21		$ 0.46		$ 0.33
Loss from discontinued operations		(0.06)		(0.13)		(0.10)		(0.18)
Net income per common unit and i-unit		$ 0.21		$ 0.08		$ 0.36		$ 0.15
Weighted average common units and i-units outstanding (basic and diluted)		400.1		347.1		376.7		345.9
Distributions paid per limited partner unit		$ 0.350		$ 0.583		$ 0.933		$ 1.166
Third Party [Member]
Operating revenues:
Transportation and other services		$ 569.7		$ 591.5		$ 1,149.7		$ 1,198.6
Operating expenses:
Operating and administrative		84.3		62.6		161.7		124.5
Affiliated Entity [Member]
Operating revenues:
Transportation and other services		26.8		29.8		51.5		52.4
Operating expenses:
Operating and administrative		$ 74		$ 71.5		$ 149.7		$ 151.9
[1]	Certain costs that are not allocated to individual segments, including Other, interest expense, allowance for equity used during construction, and income taxes are included in the consolidated total.
[2]	There were no intersegment revenues for the three months ended June 30, 2017.
[3]	There were no intersegment revenues for the three months ended June 30, 2016.
[4]	There were no intersegment revenues for the six months ended June 30, 2017.
[5]	There were no intersegment revenues for the six months ended June 30, 2016.
[6]	Other income includes our equity income for our Liquids segment from our investment in the Bakken Pipeline System.

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Net income	[1]	$ 197	$ 177.7	$ 354.5	$ 350.1
Other comprehensive income (loss), net of tax
Change in unrealized loss on cash flow hedges		(19.4)	(51.5)	(20.3)	(139.1)
Reclassification to earnings of loss on cash flow hedges		10.4	9.8	20.7	19.8
Other comprehensive income (loss), net of tax		(9)	(41.7)	0.4	(119.3)
Comprehensive income		188	136	354.9	230.8
Less:
Comprehensive income attributable to noncontrolling interests		90.6	70.3	158.9	139.1
Net income attributable to Series 1 preferred unit distributions		6.5	22.5	29	45
Net income attributable to accretion of discount on Series 1 preferred units		7.3	1.2	8.5	2.3
Comprehensive income attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P.		$ 83.6	$ 42	$ 158.5	$ 44.4
[1]	Certain costs that are not allocated to individual segments, including Other, interest expense, allowance for equity used during construction, and income taxes are included in the consolidated total.

CONSOLIDATED STATEMENTS OF CHAN

CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS' CAPITAL - USD ($) $ in Millions	Total	Noncontrolling Interests [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	General Partner [Member]	Class F Units [Member]	Series 1 Preferred units [Member]	Class D Unit [Member]	Class E Unit [Member]	Class A Common Units [Member]	Class B Common Unit [Member]	I Units [Member]	Incentive Distribution Unit [Member]
Beginning balance at Dec. 31, 2015		$ 3,944.5	$ (370)	$ 147.4		$ 1,186.8	$ 2,517.6	$ 778.2			$ 212.6	$ 495
Redemption of preferred units (Note 11)						0
Net income	$ 163.7			(47.2)	$ 0	45	77.1	21.1	$ 305.7	$ 9.1	(212.6)	10.5
Accretion of discount on preferred units	2.3					2.3
Waiver of Class D units (Note 11)				0			0					0
Capital contributions		63.4
Sale of noncontrolling interest in subsidiary		0		0					0	0	0
Other									0
Acquisition of noncontrolling interest in subsidiary		0
Issuance of Class units (Note 11)				0	0				0
Contributions				0
Sale of Midcoast assets				0
Net income	139.1	139.1
Distributions		(15.2)		(8.6)	0	(45)	(77.1)	(21.1)	(305.7)	(9.1)		(10.4)
Changes in fair value of derivative financial instruments reclassified to earnings			19.8
Changes in fair value of derivative financial instruments recognized in other comprehensive loss	(139.1)		(139.1)
Sale of Midcoast assets		0
Ending balance at Jun. 30, 2016	8,714.1	4,131.8	(489.3)	91.6	0	1,189.1	2,517.6	778.2	0	0	0	495.1
Beginning balance at Dec. 31, 2016	7,822.5	3,846.1	(339.3)	(666.8)		1,191.5	2,517.6	778.2			0	495.2
Redemption of preferred units (Note 11)						(1,200)
Net income	158.1			(9.2)	7.4	29	0	12.7	149.7	6.4	(8.9)	0
Accretion of discount on preferred units	8.5					8.5
Waiver of Class D units (Note 11)				2,969			(2,479.1)					(489.9)
Capital contributions		1,305
Sale of noncontrolling interest in subsidiary		411		0.8					28.5	0.9	8.9
Other									0.7
Acquisition of noncontrolling interest in subsidiary		(360.3)
Issuance of Class units (Note 11)				(263)	263				1,200
Contributions				24.5
Sale of Midcoast assets				(2,126.5)
Net income	158.9	158.9
Distributions		(219)		(6.9)	(3.7)	(29)	(38.5)	(16.9)	(267.1)	(7.3)		(5.3)
Changes in fair value of derivative financial instruments reclassified to earnings			20.7
Changes in fair value of derivative financial instruments recognized in other comprehensive loss	(20.3)		(20.3)
Sale of Midcoast assets		(296.6)
Ending balance at Jun. 30, 2017	$ 6,580.6	$ 4,845.1	$ (338.9)	$ (78.1)	$ 266.7	$ 0	$ 0	$ 774	$ 1,111.8	$ 0	$ 0	$ 0

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions		6 Months Ended
		Jun. 30, 2017	Jun. 30, 2016
Operating activities:
Net income from continuing operations	[1]	$ 411.3	$ 443.4
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		217.1	206.3
Derivative fair value net (gains) losses		(0.8)	10.2
Environmental costs, net of recoveries		14.2	15.7
Equity earnings from investments in joint ventures		(6.4)	0
Gain on sale of assets		(62.1)	0
Allowance for equity used during construction	[1]	(21)	(25.6)
Amortization of debt issuance and hedging costs		18.6	20
Asset impairment		0	0.4
Other		(2.4)	5.4
Changes in operating assets and liabilities		(353.7)	(232.1)
Net cash provided by operating activities		214.8	443.7
Net cash (used in) provided by discontinued operations		(171.1)	102.8
Investing activities:
Capital expenditures		(228.9)	(637.9)
Changes in restricted cash		13.6	11.1
Proceeds from the sale of net assets		314	0
Proceeds from the sale of Midcoast assets		1,310	0
Investments in joint ventures		(1,556.7)	0
Other		(2.5)	(2.3)
Net cash used in investing activities		(150.5)	(629.1)
Net cash used in discontinued operations		(14)	(31)
Financing activities:
Redemption of Series 1 preferred units		(1,200)	0
Payment of Series 1 preferred unit dividends		(357.3)	0
Net proceeds from Class A unit issuances		1,224.5	0
Distributions to partners		(345.7)	(399)
Repayments to General Partner and affiliates		(1,829.4)	0
Borrowings from General Partner and affiliates		1,500	0
Net (repayments) borrowings under credit facilities		(865)	630
Net commercial paper borrowings (repayments)		675.7	(131.8)
Acquisition of noncontrolling interest in subsidiary		(360.3)	0
Sale of noncontrolling interest in subsidiary		450.1	0
Contributions from noncontrolling interests		1,285	81.9
Distributions to noncontrolling interests		(219)	0
Other		(0.5)	(0.8)
Net cash (used in) provided by financing activities		(41.9)	180.3
Net cash (used in) provided by discontinued operations		229	(81.7)
Net increase (decrease) in cash and cash equivalents		66.3	(15)
Cash disposed as part of the Midcoast sale		(51.3)	0
Cash and cash equivalents at beginning of year - continuing operations		101.3	130.1
Cash and cash equivalents at beginning of year - discontinued operations		7.4	18
Cash and cash equivalents at end of period		123.7	133.1
Cash and cash equivalents at end of period - continuing operations		123.7	125
Cash and cash equivalents at end of period - discontinued operations		$ 0	$ 8.1
[1]	Certain costs that are not allocated to individual segments, including Other, interest expense, allowance for equity used during construction, and income taxes are included in the consolidated total.

CONSOLIDATED STATEMENTS OF FINA

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION - USD ($) $ in Millions	Jun. 30, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 123.7	$ 101.3
Restricted cash	0	13.6
Receivables, trade and other	63.6	6
Due from General Partner and affiliates	98.6	88.4
Accrued receivables	94	18.8
Other current assets	41.3	34.3
Current assets related to discontinued operations	0	138.6
Assets, Current, Total	421.2	401
Property, plant and equipment, net	12,631.9	12,608.2
Equity investments in joint ventures	1,563.1	0
Other assets, net	51.2	118.8
Assets held for sale	0	206.8
Non-current assets related to discontinued operations	0	4,775.3
Total Assets	14,667.4	18,110.1	[1]
Current liabilities:
Accounts payable and other	353.1	347.7
Due to General Partner and affiliates	38.7	175.2
Interest payable	88.7	90.1
Environmental liabilities	23.6	99.8
Property and other taxes payable	77.4	89.6
Current portion of long-term debt	400	0
Current liabilities related to discontinued operations	0	299.8
Liabilities, Current	981.5	1,102.2
Long-term debt	6,479.3	7,065.9
Loans from General Partner and affiliate	420.6	750
Due to General Partner and affiliates	0	328.3
Other long-term liabilities	205.4	196.9
Non-current liabilities related to discontinued operations	0	844.3
Liabilities, Total	8,086.8	10,287.6
Commitments and contingencies
Partners’ capital:
Series 1 preferred units (48,000,000 authorized and issued at December 31, 2016)	0	1,191.5
General Partner	(78.1)	(666.8)
Accumulated other comprehensive loss	(338.9)	(339.3)
Total Enbridge Energy Partners, L.P. partners' capital	1,735.5	3,976.4
Noncontrolling interests	4,845.1	3,543.2
Total partners' capital	6,580.6	7,822.5
Total Liabilities and Partners' capital	14,667.4	18,110.1
Discontinued Operations [Member]
Partners’ capital:
Noncontrolling interests	0	302.9
Class D Units [Member]
Partners’ capital:
Common units	0	2,517.6
Class E Units [Member]
Partners’ capital:
Common units	774	778.2
Class A Common Units [Member]
Partners’ capital:
Common units	1,111.8	0
Class B Common Units [Member]
Partners’ capital:
Common units	0	0
i-Units [Member]
Partners’ capital:
Common units	0	0
Incentive Distribution Units [Member]
Partners’ capital:
Common units	0	495.2
Class F Units [Member]
Partners’ capital:
Common units	266.7	$ 0
Total partners' capital	$ 266.7
[1]	Comparative information excludes assets from discontinued operations. See Note 6 Dispositions and Discontinued Operations.

CONSOLIDATED STATEMENTS OF FIN7

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION (Parenthetical) - shares	Jun. 30, 2017	Dec. 31, 2016
Preferred units, authorized (in shares)		48,000,000
Preferred units, issued (in shares)		48,000,000
Class D Units [Member]
Common units, authorized (in shares)		66,100,000
Common units, issued (in shares)		66,100,000
Class E Units [Member]
Common units, authorized (in shares)	18,114,975	18,114,975
Common units, issued (in shares)	18,114,975	18,114,975
Class A Common Units [Member]
Common units, outstanding (in shares)	326,517,110	262,208,428
Class B Common Units [Member]
Common units, authorized (in shares)	7,825,500	7,825,500
Common units, issued (in shares)	7,825,500	7,825,500
i-Units [Member]
Common units, authorized (in shares)	85,620,914	81,857,168
Common units, issued (in shares)	85,620,914	81,857,168
Incentive Distribution Units [Member]
Common units, authorized (in shares)		1,000
Common units, issued (in shares)		1,000
Class F Units [Member]
Common units, authorized (in shares)	1,000
Common units, issued (in shares)	1,000

GENERAL

GENERAL	6 Months Ended
	Jun. 30, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
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. On June 28, 2017, we sold all of our ownership interest in our Midcoast gas gathering and processing business to our General Partner (the Midcoast sale). The sale of this ownership interest represents a strategic shift in our business and meets the criteria for classification as discontinued operations and as a result, the results of operations, cash flows and financial position of our natural gas business for the current and prior periods are reflected as discontinued operations. For further information refer to Note 6 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, 2016. 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, 2016, 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 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.

FUTURE ACCOUNTING POLICY CHANGE

FUTURE ACCOUNTING POLICY CHANGES	6 Months Ended
	Jun. 30, 2017
Accounting Policies [Abstract]
FUTURE ACCOUNTING POLICY CHANGES	2. FUTURE ACCOUNTING POLICY CHANGES 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 amendment adds a new impairment model, known as the current expected credit loss model that is based on expected losses rather than incurred losses. Under the new guidance, an entity recognizes as an allowance its estimate of expected credit losses, which the Financial Accounting Standards Board (FASB) believes will result in more timely recognition of such losses. We are currently assessing the impact of the new standard on our consolidated financial statements. The accounting update is effective for annual and interim periods beginning on or after December 15, 2019 and is to be applied using a modified retrospective approach. 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 consolidated statements 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 are currently assessing the impact of the new standard on our consolidated financial statements. The accounting update is effective for fiscal years beginning after December 15, 2018 and is to be applied using a modified retrospective approach. Revenues from Contracts with Customers ASU 2014-09 was issued in 2014 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. The standard is effective January 1, 2018. The new revenue standard permits either a full retrospective method of adoption with restatement of all prior periods presented, or a modified retrospective method with the cumulative effect of applying the new standard recognized as an adjustment to opening retained earnings in the period of adoption. We have tentatively decided to adopt the new revenue standard using the modified retrospective method. We have reviewed a sample of our revenue contracts in order to evaluate the effect of the new standard on our revenue recognition practices. Based on the our initial assessment, estimates of variable consideration which will be required under the new standard for certain contracts may result in changes to the pattern or timing of revenue recognition for those contracts. While we have not yet completed the assessment, we do not expect these changes to have a material impact on revenues or earnings (loss). We are currently developing processes to generate the disclosures required under the new standard.

NET INCOME PER LIMITED PARTNER

NET INCOME PER LIMITED PARTNER UNIT	6 Months Ended
	Jun. 30, 2017
Earnings Per Share [Abstract]
NET INCOME PER LIMITED PARTNER UNIT	3. NET INCOME PER LIMITED PARTNER UNIT Three months Six months 2017 2016 2017 2016 (in millions, except per unit amounts) Continuing operations: Net income $ 232.4 $ 240.7 $ 411.3 $ 443.4 Less: Net income attributable to: Noncontrolling interest 101.8 87.3 177.7 165.4 Series 1 preferred unit distributions 6.5 22.5 29.0 45.0 Accretion of discount on Series 1 preferred units 7.3 1.2 8.5 2.3 Net income attributable to general and limited partner interests in Enbridge Energy Partners, L.P. – continuing operations 116.8 129.7 196.1 230.7 Distributions: Incentive distributions (1) (3.7 ) (5.2 ) (7.4 ) (10.4 ) Distributed earnings attributed to our General Partner (3.2 ) (5.3 ) (6.4 ) (10.5 ) Distributed earnings attributed to Class D and Class E units (6.4 ) (49.1 ) (12.7 ) (98.2 ) Total distributed earnings to our General Partner, Class D and Class E units and IDUs (13.3 ) (59.6 ) (26.5 ) (119.1 ) Total distributed earnings attributed to our common units and i-units (146.9 ) (202.9 ) (293.3 ) (404.6 ) Total distributed earnings (160.2 ) (262.5 ) (319.8 ) (523.7 ) Overdistributed earnings $ (43.4 ) $ (132.8 ) $ (123.7 ) $ (293.0 ) Discontinued operations: Net loss $ (35.4 ) $ (63.0 ) $ (56.8 ) $ (93.3 ) Less: Net loss attributable to: Noncontrolling interest (11.2 ) (17.0 ) (18.8 ) (26.3 ) Net loss attributable to general and limited partner interests in Enbridge Energy Partners, L.P. – discontinued operations (24.2 ) (46.0 ) (38.0 ) (67.0 ) Weighted average common units and i-units outstanding 400.1 347.1 376.7 345.9 Three months Six months 2017 2016 2017 2016 (in millions, except per unit amounts) Basic and diluted earnings per unit: Distributed earnings per common unit and i-unit – continuing operations (2) $ 0.37 $ 0.58 $ 0.78 $ 1.17 Overdistributed earnings per common unit and i-unit (3) (0.10 ) (0.37 ) (0.32 ) (0.84 ) Net income per common unit and i-unit (basic and diluted) – continuing operations (4) $ 0.27 $ 0.21 $ 0.46 $ 0.33 Net loss per common unit and i-unit (basic and diluted) – discontinued operations (4) $ (0.06 ) $ (0.13 ) $ (0.10 ) $ (0.18 ) Net income per common unit and i-unit (basic and diluted) $ 0.21 $ 0.08 $ 0.36 $ 0.15 (1) For the three and six months ended June 30, 2017, Class D units and IDUs were not entitled to distributions as the wholly-owned subsidiary of our General Partner irrevocably waived its rights associated with the Class D and IDUs; for the three and six months ended June 30, 2017, incentive distributions were made to Class F units. For the three and six months ended June 30, 2016, incentive distributions were made to IDUs and Class D units. (2) 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. (3) 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. (4) For the three months ended June 30, 2017, there were no units excluded from the if-converted method of calculating diluted earnings per share. For the six months ended June 30, 2017 and the three and six months ended June 30, 2016, 43,201,310 anti-dilutive Preferred units and 18,114,975 anti-dilutive Class E units were excluded from the if-converted method of calculating diluted earnings per unit. For the six months ended June 30, 2017, 66,100,000 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. For the three and six months ended June 30, 2016, 66,100,000 anti-dilutive Class D units were excluded from the if-converted method of calculating diluted earnings per unit. Simplification of Incentive Distributions Distribution Targets Portion of Quarterly Percentage Distributed (1) Percentage Distributed Minimum Quarterly Distribution Up to $0.295 2 % 98 % First Target Distribution > $0.295 to $0.35 15 % 85 % Over First Target Distribution > $0.35 25 % 75 % (1) For distributions in excess of the Minimum Quarterly Distribution, this percentage includes both the General Partner’s distributions of 2% and the distribution to the Class F Units.

SEGMENT INFORMATION

SEGMENT INFORMATION	6 Months Ended
	Jun. 30, 2017
Segment Reporting [Abstract]
SEGMENT INFORMATION	4. SEGMENT INFORMATION Three months ended June 30, 2017 Liquids Natural Gas (1) Other Consolidated (2) (in millions) Operating revenues: (3) Transportation and other services $ 596.5 $ — $ — $ 596.5 596.5 — — 596.5 Operating expenses: Environmental costs, net of recoveries 3.5 — — 3.5 Operating and administrative 153.5 — 4.8 158.3 Power 66.4 — — 66.4 Depreciation and amortization 108.3 — — 108.3 Gain on sale of assets (51.5 ) — — (51.5 ) 280.2 — 4.8 285.0 Operating income (loss) $ 316.3 $ — $ (4.8 ) $ 311.5 Interest expense, net (102.8 ) Allowance for equity used during construction 10.7 Other income (4) 11.4 Income from continuing operations before income tax benefit 230.8 Income tax benefit 1.6 Income from continuing operations 232.4 Income (loss) from discontinued operations — (41.4 ) 6.0 (35.4 ) Net income $ 197.0 (1) The operating results of our Natural Gas segment are included in discontinued operations as a result of the Midcoast sale to our General Partner. For further information refer to Note 6 Dispositions and Discontinued Operations. (2) Certain costs that are not allocated to individual segments, including Other, interest expense, allowance for equity used during construction, and income taxes are included in the consolidated total. (3) There were no intersegment revenues for the three months ended June 30, 2017. (4) Other income includes our equity income for our Liquids segment from our investment in the Bakken Pipeline System. Three months ended June 30, 2016 Liquids Natural Gas (1) Other Consolidated (2) (in millions) Operating revenues: (3) Transportation and other services $ 621.3 $ — $ — 621.3 621.3 — — 621.3 Operating expenses: Environmental costs, net of recoveries 0.1 — — 0.1 Operating and administrative 132.1 — 2.0 134.1 Power 59.7 — — 59.7 Depreciation and amortization 104.9 — — 104.9 296.8 — 2.0 298.8 Operating income (loss) $ 324.5 $ — $ (2.0 ) $ 322.5 Interest expense, net (93.3 ) Allowance for equity used during construction 13.3 Other income 0.2 Income from continuing operations before income tax expense 242.7 Income tax expense (2.0 ) Income from continuing operations 240.7 Loss from discontinued operations — (53.5 ) (9.5 ) (63.0 ) Net income $ 177.7 (1) The operating results of our Natural Gas segment are included in discontinued operations as a result of the Midcoast sale to our General Partner. For further information refer to Note 6 Dispositions and Discontinued Operations. (2) Certain costs that are not allocated to individual segments, including Other, interest expense, allowance for equity used during construction, and income taxes are included in the consolidated total. (3) There were no intersegment revenues for the three months ended June 30, 2016. Six months ended June 30, 2017 Liquids Natural Gas (1) Other Consolidated (2) (in millions) Operating revenues: (3) Transportation and other services $ 1,201.2 $ — $ — $ 1,201.2 1,201.2 — — 1,201.2 Operating expenses: Environmental costs, net of recoveries 13.8 — — 13.8 Operating and administrative 304.0 — 7.4 311.4 Power 140.9 — — 140.9 Depreciation and amortization 217.1 — — 217.1 Gain on sale of asset (62.1 ) — — (62.1 ) 613.7 — 7.4 621.1 Operating income (loss) $ 587.5 $ — $ (7.4 ) $ 580.1 Interest expense, net (201.7 ) Allowance for equity used during construction 21.0 Other income (4) 11.4 Income from continuing operations before income tax benefit 410.8 Income tax benefit 0.5 Income from continuing operations 411.3 Loss from discontinued operations $ — $ (51.1 ) $ (5.7 ) $ (56.8 ) Net income $ 354.5 (1) The operating results of our Natural Gas segment are included in discontinued operations as a result of the Midcoast sale to our General Partner. For further information refer to Note 6 Dispositions and Discontinued Operations (2) Certain costs that are not allocated to individual segments, including Other, interest expense, allowance for equity used during construction, and income taxes are included in the consolidated total. (3) There were no intersegment revenues for the six months ended June 30, 2017. (4) Other income includes our equity income for our Liquids segment from our investment in the Bakken Pipeline System. Six months ended June 30, 2016 Liquids Natural Gas (1) Other Consolidated (2) (in millions) Operating revenues: (3) Transportation and other services $ 1,251.0 $ — $ — $ 1,251.0 1,251.0 — — 1,251.0 Operating expenses: Environmental costs, net of recoveries 17.0 — — 17.0 Operating and administrative 269.3 — 7.1 276.4 Power 132.5 — — 132.5 Depreciation and amortization 206.3 — — 206.3 625.1 — 7.1 632.2 Operating income (loss) $ 625.9 $ — $ (7.1 ) $ 618.8 Interest expense, net (197.8 ) Allowance for equity used during construction 25.6 Other income 0.4 Income from continuing operations before income tax expense 447.0 Income tax expense (3.6 ) Income from continuing operations 443.4 Loss from discontinued operations — (76.3 ) (17.0 ) (93.3 ) Net income $ 350.1 (1) The operating results of our Natural Gas segment are included in discontinued operations as a result of the Midcoast sale to our General Partner. For further information refer to Note 6 Dispositions and Discontinued Operations. (2) Certain costs that are not allocated to individual segments, including Other, interest expense, allowance for equity used during construction, and income taxes are included in the consolidated total. (3) There were no intersegment revenues for the six months ended June 30, 2016. Total Assets June 30, December 31, (1) Liquids $ 14,661.5 $ 13,030.5 Natural Gas — — Other 5.9 165.6 Total $ 14,667.4 $ 13,196.1 (1) Comparative information excludes assets from discontinued operations. See Note 6 Dispositions and Discontinued Operations.

REGULATORY MATTERS

REGULATORY MATTERS	6 Months Ended
	Jun. 30, 2017
Regulatory Assets and Liabilities Disclosure [Abstract]
REGULATORY MATTERS	5. REGULATORY MATTERS Regulatory Accounting Due to over or under recovery adjustments made in accordance with the Federal Energy Regulatory Commission (FERC), authoritative guidance and our cost-of-service recovery model, we recognize assets and liabilities for regulatory purposes. The assets and liabilities that we recognize for regulatory purposes are recorded on a net basis in “Other current assets” or “Accounts payable and other,” respectively, on our consolidated statements of financial position. These regulatory assets and liabilities are amortized on a straight-line basis over a one-year recovery period. Our over and under recovery revenue adjustments and net regulatory asset amortization for the three and six months ended June 30, 2017 and 2016 are as follows: Three months Six months 2017 2016 2017 2016 (in millions) Net regulatory asset (liability) balance at beginning of period $ (34.1 ) $ 31.2 $ 11.9 $ 29.9 Current period (over) under recovery revenue adjustments 12.0 5.9 (27.0 ) 13.6 Amortization of prior year regulatory asset (1.6 ) (7.8 ) (8.6 ) (14.2 ) Net regulatory asset (liability) balance at end of period $ (23.7 ) $ 29.3 $ (23.7 ) $ 29.3

DISPOSITIONS AND DISCONTINUED O

DISPOSITIONS AND DISCONTINUED OPERATIONS	6 Months Ended
	Jun. 30, 2017
Discontinued Operations and Disposal Groups [Abstract]
DISPOSITIONS AND DISCONTINUED OPERATIONS	6. DISPOSITIONS AND DISCONTINUED OPERATIONS Dispositions During the second quarter of 2017, we sold unnecessary pipe related to the Sandpiper project for cash proceeds of approximately $97.6 million. A gain on disposal of $51.5 million before tax was included in “Gain on sale of assets” on our consolidated statements of income. These assets were part of our Liquids segment. On March 1, 2017, we completed the sale of the Ozark Pipeline System to a subsidiary of MPLX LP for cash proceeds of approximately $219.6 million, including reimbursement costs. A gain on disposal of $10.6 million before tax was included in “Gain on sale of assets” on our consolidated statements of income. These assets were part of our Liquids segment. Discontinued Operations Sale of Natural Gas Business On June 28, 2017, we completed the sale of all of our ownership interest in our Midcoast gas gathering and processing business to our General Partner for $2.26 billion, which included cash consideration of $1.31 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 $4.29 billion. As a result of the transaction, partners’ capital decreased by $2.13 billion, all of which was allocated to the General Partner’s capital account. Noncontrolling interest in MEP of $296.6 million was eliminated. Three months Six months 2017 2016 2017 2016 Operating revenues: Commodity sales $ 559.3 $ 379.4 $ 1,085.0 $ 757.2 Commodity sales – affiliate 3.3 1.4 9.4 6.6 Transportation and other services 24.5 46.8 66.7 95.7 587.1 427.6 1,161.1 859.5 Operating expenses: Commodity costs 496.8 350.5 968.2 685.9 Commodity costs – affiliate 25.7 8.5 42.1 21.2 Operating and administrative 28.3 40.0 64.7 74.8 Operating and administrative – affiliate 35.0 38.9 68.7 76.8 Depreciation and amortization 37.1 40.0 74.5 79.5 Asset impairment — 10.6 — 10.6 622.9 488.5 1,218.2 948.8 Operating loss (35.8 ) (60.9 ) (57.1 ) (89.3 ) Interest expense, net (9.5 ) (8.1 ) (17.4 ) (16.5 ) Other income 10.4 6.5 18.6 13.9 Loss before income tax expense (34.9 ) (62.5 ) (55.9 ) (91.9 ) Income tax expense (0.5 ) (0.5 ) (0.9 ) (1.4 ) Net loss from discontinued operations $ (35.4 ) $ (63.0 ) $ (56.8 ) $ (93.3 ) December 31, Current assets related to discontinued operations: Cash and cash equivalents $ 7.4 Restricted cash 11.0 Receivables, trade and other, net of allowance for doubtful accounts 8.5 Due from General Partner and affiliates 2.1 Accrued receivables 20.8 Inventory 28.1 Other current assets 60.7 $ 138.6 Non-current assets related to discontinued operations: Property, plant and equipment, net $ 4,114.5 Equity investments in joint ventures 360.7 Intangible assets, net 251.8 Other assets, net 48.3 $ 4,775.3 December 31, Current liabilities related to discontinued operations: Accounts payable and other $ 66.9 Due to General Partner and affiliates 38.8 Environmental liabilities 0.1 Accrued purchases 171.8 Property and other taxes payable 17.2 Interest payable 5.0 $ 299.8 Non-current liabilities related to discontinued operations: Long-term debt $ 818.5 Other long-term liabilities 25.8 $ 844.3

VARIABLE INTEREST ENTITIES

VARIABLE INTEREST ENTITIES	6 Months Ended
	Jun. 30, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
VARIABLE INTEREST ENTITIES	7. VARIABLE INTEREST ENTITIES Enbridge Holdings (DakTex) L.L.C. On April 27, 2017, we finalized a joint funding arrangement with our General Partner with respect to our equity investment in the Bakken Pipeline System, held through our investment subsidiary, Enbridge Holdings (DakTex) L.L.C. (DakTex). DakTex is now owned 75% by our General Partner and 25% by us. DakTex owns a 75% equity interest in MarEn Bakken Company LLC (MarEn). For more information regarding our equity investment, refer to Note 8. Equity Investments in Joint Ventures DakTex is considered a variable interest entity (VIE) consolidated by us. We have authority as managing member to exclusively manage the business and affairs of DakTex, subject to certain protective voting rights and are subject to removal as managing member only upon certain fundamental changes. We are the primary beneficiary of Daktex because (i) as the managing partner we have the power to direct the activities of DakTex that most significantly impact its economic performance; and (ii) we have the obligation to absorb losses and the right to receive residual returns that potentially could be significant to DakTex. DakTex does not have any liabilities. Its sole asset is its investment in MarEn. At June 30, 2017, the carrying amount of DakTex’s investment in MarEn was $1,544.3 million.

EQUITY INVESTMENTS IN JOINT VEN

EQUITY INVESTMENTS IN JOINT VENTURES	6 Months Ended
	Jun. 30, 2017
Equity Method Investments and Joint Ventures [Abstract]
EQUITY INVESTMENTS IN JOINT VENTURES	8. EQUITY INVESTMENTS IN JOINT VENTURES Ownership June 30, December 31, (in millions) MarEn Bakken Company LLC 75.0 % $ 1,563.1 $ — On February 15, 2017, our joint venture with Marathon Petroleum Corporation (MPC), MarEn, closed its acquisition of the Bakken Pipeline System with Bakken Holdings Company LLC (Bakken Holdings), an affiliate of Energy Transfer Partners, L.P. and Sunoco Logistics Partners L.P., to acquire a 49% equity interest in Bakken Pipeline Investments LLC (BPI). BPI owns 75% of the Bakken Pipeline System. Under this arrangement, we and MPC indirectly hold 75% and 25%, respectively, of MarEn’s 49% interest in BPI. The purchase price of our effective 27.6% interest in the Bakken Pipeline System was $1.5 billion. The Bakken Pipeline System was placed into service on June 1, 2017, which consists of the Dakota Access Pipeline (DAPL) and the Energy Transfer Crude Oil Pipeline (ETCOP). It connects the prolific Bakken formation in North Dakota to markets in eastern Petroleum Administration for Defense Districts (PADD II) and the United States Gulf Coast, providing customers with access to premium markets at a competitive cost. For further details regarding our funding arrangement, refer to Note 14 Related Party Transactions We account for our investment in MarEn under the equity method of accounting. For the six months ended June 30, 2017, we recognized $6.4 million in “Other income” in our consolidated statements of income representing our equity earnings for this investment, net of amortization of the purchase price basis difference. Our equity investment includes the unamortized excess of the purchase price over the underlying net book value (basis difference), of the investees’ assets at the purchase date, which is comprised of $14.4 million in goodwill and $931.4 million in amortizable assets included within the Liquids segment. We amortized $2.9 million for the six months ended June 30, 2017, which was recorded as a reduction to equity earnings.

DEBT

DEBT	6 Months Ended
	Jun. 30, 2017
Debt Disclosure [Abstract]
DEBT	9. DEBT Maturity Total Facilities Draws (1) Available (in millions) Enbridge Energy Partners, L.P. 2019 – 2020 $ 2,625.0 $ 1,535.0 $ 1,090.0 (1) Includes facility draws, letters of credit and commercial paper issuances that are back-stopped by the credit facility and excludes the EUS 364-day Credit Facility In addition to the committed credit facilities noted in the above table, we also have a $175.0 million (December 31, 2016 — $175.0 million) of uncommitted letter of credit, of which $87.6 million (December 31, 2016 — $70.9 million) were unutilized as at June 30, 2017. Under our multi-year senior unsecured revolving credit facility and our 364-day revolving credit agreement, together referred to as the Credit Facilities, we had net repayments of approximately $865.0 million during the period ended June 30, 2017, which includes gross borrowings of $8.1 billion and gross repayments of $9.0 billion. Under our commercial paper program, we had net borrowings of approximately $675.7 million during the period ended June 30, 2017, which includes gross borrowings of $4.6 billion and gross repayments of $3.9 billion. Under our credit agreement with EUS, an affiliate of Enbridge and the owner of our General Partner, or the EUS 364-day Credit Facility, we had net repayments of approximately $329.4 million during the period ended June 30, 2017, which includes gross borrowings of $443.6 million and gross repayments of $773.0 million. On April 27, 2017, our Board of Directors finalized the joint funding arrangement with our General Partner with respect to our investment in the Bakken Pipeline System, held through our subsidiary, DakTex. As part of the transaction, DakTex distributed approximately $1.14 billion to us. We used these distribution proceeds plus additional borrowings of $0.4 billion from our existing EUS 364-day Credit Facility to repay the $1.5 billion outstanding under our unsecured revolving 364-day credit agreement with EUS (the EUS Credit Agreement). We terminated the EUS Credit Agreement subsequent to the repayment. For further information on distribution from our General Partner, refer to Note 14 Related Party Transactions On June 30, 2017, we extended our 364-day revolving credit facility termination date. The termination date was extended to June 29, 2018, which has a term out option that could extend maturity of outstanding borrowings to June 28, 2019, and capacity remains at $625 million. The 364-day Credit Facility is through a syndicate of third party lenders. As at June 30, 2017, commercial paper and credit facility draws, net of short-term borrowings and non-revolving credit facilities that mature within one year, of $1,468.7 million (December 31, 2016 — $1,657.6 million) are supported by the availability of long-term committed credit facilities and therefore have been classified as long-term debt. We have the ability and intent to refinance all of our commercial paper obligations on a long-term basis through borrowings under our Credit Facilities. Accordingly, such amounts have been classified as “Long-term debt” in our accompanying consolidated statements of financial position. At June 30, 2017, we had approximately $1,090.0 million of unutilized commitments under the terms of our Credit Facilities and the EUS 364-day Credit Facility. Debt Covenants We and our consolidated subsidiaries were in compliance with the terms of our financial covenants under our consolidated debt agreements as at June 30, 2017. On June 5, 2017, we entered into amendments with the lenders of each of our Credit Facilities and the EUS 364-day Credit Facility. These agreements eliminated certain covenants related to MEP and its subsidiaries and were effective June 28, 2017. 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 at June 30, 2017 and December 31, 2016, respectively, due to the short-term nature and frequent repricing of the amounts outstanding under these obligations. The fair value of our outstanding commercial paper and borrowings under our Credit Facilities and the 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 $6.2 billion and $6.5 billion at June 30, 2017 and December 31, 2016, 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.

NONCONTROLLING INTERESTS

NONCONTROLLING INTERESTS	6 Months Ended
	Jun. 30, 2017
Noncontrolling Interest [Abstract]
NONCONTROLLING INTERESTS	10. NONCONTROLLING INTERESTS Three months Six months 2017 2016 2017 2016 (in millions) Eastern Access Interests $ 36.8 $ 53.2 $ 76.3 $ 104.7 U.S. Mainline Expansion Interests 35.8 34.1 69.2 60.7 North Dakota Pipeline Company Interests 18.4 — 16.8 — Line 3 Replacement Interests 6.0 — 10.6 — Enbridge Holdings (DakTex) L.L.C. Interests 4.8 — 4.8 — Midcoast Energy Partners, L.P. – Discontinued Operations (11.2 ) (17.0 ) (18.8 ) (26.3 ) Total $ 90.6 $ 70.3 $ 158.9 $ 139.1 On April 27, 2017, we finalized the previously announced joint funding arrangement with our General Partner for our investment in the Bakken Pipeline System. Our equity investment in MarEn is held by our consolidated subsidiary, DakTex. Under the terms of the agreement, our General Partner contributed approximately $1.14 billion in exchange for Class A units in DakTex to obtain its 75% ownership interest while we retain the remaining 25%. Noncontrolling interests represent our General Partner’s 75% interest. For further details refer to Note 14 Related Party Transactions On June 28, 2017, we completed the Midcoast sale to our General Partner, reducing our noncontrolling interest in MEP to nil upon the closing of the sale. On January 26, 2017, we entered into a joint funding arrangement with our General Partner for the U.S. Line 3 Replacement Program (U.S. L3R Program). Under the term of the arrangement, our General Partner will fund 99% and we will fund 1% of the capital costs of the U.S. L3R Program. The carrying amount of our 99% interest in the project at the transaction date was $411.0 million and was recorded as an increase to noncontrolling interest. The $39.1 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-rata basis. For further details, refer to Note 14 Related Party Transactions On January 26, 2017, we exercised our option under the Eastern Access Project joint funding arrangement to acquire an additional 15% interest in the Eastern Access Project, at its book value of approximately $360 million, which is now in service. This transaction reduced noncontrolling interest by approximately $360 million. As of June 30, 2017, we and our General Partner owned 40% and 60% of the partnership interest in Series EA of Enbridge Energy, Limited Partnership (OLP), which we refer to as the EA interest, respectively. For further details, refer to Note 14 Related Party Transactions

PARTNERS' CAPITAL

PARTNERS' CAPITAL	6 Months Ended
	Jun. 30, 2017
Partners' Capital Notes [Abstract]
PARTNERS’ CAPITAL	11. PARTNERS’ CAPITAL Redemption of Series 1 Preferred Units On April 27, 2017, we redeemed all of our outstanding Series 1 Preferred Units held by our General Partner at face value of $1.2 billion in cash. The remaining unamortized beneficial conversion feature discount of $8.5 million was recorded against the capital balance of the General Partner. Additionally, we repaid $357.3 million in deferred distributions on the Series 1 Preferred Units owed to our General Partner upon the closing of the Midcoast sale. Issuance of Class A Units On April 27, 2017, we funded the redemption of the Series 1 Preferred Units through the issuance of 64,308,682 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 on April 27, 2017, at fair value. The fair value of the Class A common units was $18.57 per unit, the market closing price on April 27, 2017, resulting in a $1.2 billion increase to the Class A unit capital account. Simplification of Incentive Distributions On April 27, 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 IDUs, in exchange for the issuance of 1,000 Class F units. The waiving of the Class D and IDUs by a wholly-owned subsidiary of our General Partner represents an extinguishment, resulting in a de-recognition of the Class D and IDU’s at their carrying value. The Class F units were recorded at their fair value of $263.0 million and the difference between the fair value of the Class F units and the de-recognized Class D and IDU’s were recorded as an increase of $2.7 billion to our General Partner’s capital account. We determined the fair value of the Class F units using an income approach on the basis of discounted cash flows from expected quarterly distributions. The Class F units are entitled to (i) 13% of all distributions of available cash in excess of $0.295 per unit, but less than or equal to $0.35 per unit, and (ii) 23% of all distributions of available cash in excess of $0.35 per unit. Curing Our limited partnership agreement does not permit capital deficits to accumulate in the capital accounts of any limited partner and thus requires that such capital account deficits be “cured” by additional allocations from the positive capital accounts of the common units, i-units, and our General Partner, generally on a pro-rata basis. For the six months ended June 30, 2017, the carrying amounts for the capital accounts of the Class A and Class B common units were reduced below zero due to distributions to limited partners in excess of earnings attributable to such limited partners. As a result, the capital balances of the i-units and our General Partner interests were reduced by $39.9 million and $11.9 million, respectively, to cure the applicable deficit balances.

DERIVATIVE FINANCIAL INSTRUMENT

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES	6 Months Ended
	Jun. 30, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES	12. DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES As a result of the Midcoast sale, our net income and cash flows are no longer subject to volatility stemming from fluctuation in the prices of natural gas, NGLs, condensates and fractionation margins. Our net income and cash flows are subject to volatility stemming from changes in interest rates on our variable rate debt obligations and fluctuations in commodity prices of crude oil. Our interest rate risk exposure results from changes in interest rates on our variable rate debt and exists at the corporate level where our variable rate debt obligations are issued. Our exposure to commodity price risk exists within our Liquids segment. We use derivative financial instruments, such as futures, forwards, swaps, options and other financial instruments with similar characteristics, to manage the risks associated with market fluctuations in interest rates and commodity prices, as well as to reduce volatility in our cash flows. Based on our risk management policies, all of our derivative financial instruments, including those that are not designated for hedge accounting treatment, are employed in connection with an underlying asset, liability or forecasted transaction and are not entered into with the objective of speculating on interest rates or commodity prices. We have hedged a portion of our exposure to the variability in future cash flows associated with the risks discussed above in future periods in accordance with our risk management policies. Our derivative instruments that are designated for hedge accounting under authoritative guidance are classified as cash flow hedges. Derivative Positions Our derivative financial instruments are included at their fair values in the consolidated statements of financial position as follows: June 30, December 31, (in millions) Other current assets $ 1.2 $ — Accounts payable and other (159.0 ) (145.4 ) Other long-term liabilities (23.8 ) (21.3 ) $ (181.6 ) $ (166.7 ) The changes in the assets and liabilities associated with our derivatives are primarily attributable to the effects of new derivative transactions we have entered at prevailing market prices, settlement of maturing derivatives and the change in forward market prices of our remaining hedges. Our portfolio of derivative financial instruments is largely comprised of interest rate contracts and crude oil sales contracts. June 30, December 31, (in millions) Counterparty Credit Quality (1) AA $ (82.6 ) $ (79.2 ) A (63.6 ) (58.4 ) Lower than A (35.4 ) (29.1 ) $ (181.6 ) $ (166.7 ) (1) As determined by nationally-recognized statistical ratings organizations. As the net value of our derivative financial instruments has decreased in response to changes in forward commodity prices and interest rates, our outstanding financial exposure to third parties have increased. When credit thresholds are met pursuant to the terms of our International Swaps and Derivatives Association, Inc., or ISDA®, financial contracts, we have the right to require collateral from our counterparties. We include any cash collateral received or posted in the balances listed above. At June 30, 2017 and December 31, 2016, we did not have any cash collateral on our asset exposures. Cash collateral is classified as “Restricted cash” in our consolidated statements of financial position. We provided letters of credit totaling $152.5 million and $119.5 million relating to our liability exposures pursuant to the margin thresholds in effect at June 30, 2017 and December 31, 2016, respectively, under our ISDA® agreements. The ISDA® agreements and associated credit support, which govern our financial derivative transactions, contain no credit rating downgrade triggers that would accelerate the maturity dates of our outstanding transactions. A change in ratings is not an event of default under these instruments, and the maintenance of a specific minimum credit rating is not a condition to transacting under the ISDA® agreements. In the event of a credit downgrade, additional collateral may be required to be posted under the agreement if we are in a liability position to our counterparty, but the agreement will not automatically terminate and require immediate settlement of all future amounts due. The ISDA® agreements, in combination with our master netting agreements, and credit arrangements governing our interest rate and commodity swaps require that collateral be posted per tiered contractual thresholds based on the credit rating of each counterparty. We generally provide letters of credit to satisfy such collateral requirements under our ISDA® agreements. These agreements will require additional collateral postings of up to 100% on net liability positions in the event of a credit downgrade below investment grade. Automatic termination clauses which exist are related only to non-performance activities, such as the refusal to post collateral when contractually required to do so. When we are holding an asset position, our counterparties are likewise required to post collateral on their liability (our asset) exposures, also determined by tiered contractual collateral thresholds. Counterparty collateral may consist of cash or letters of credit, both of which must be fulfilled with immediately available funds. In the event that our credit ratings were to decline below the lowest level of investment grade, as determined by Standard & Poor’s and Moody’s, we would be required to provide additional amounts under our existing letters of credit to meet the requirements of our ISDA® agreements. For example, if our credit ratings had been below the lowest level of investment grade at June 30, 2017, we would have been required to provide additional letters of credit in the amount of $30.9 million related to our positions. June 30, December 31, (in millions) United States financial institutions and investment banking entities $ (131.3 ) $ (121.7 ) Non-United States financial institutions (50.3 ) (45.0 ) $ (181.6 ) $ (166.7 ) Gross derivative balances are presented below before the effects of collateral received or posted and without the effects of master netting arrangements. Both our assets and liabilities are adjusted for non-performance risk, which is statistically derived. This credit valuation adjustment model considers existing derivative asset and liability balances in conjunction with contractual netting and collateral arrangements, current market data such as credit default swap rates and bond spreads and probability of default assumptions to quantify an adjustment to fair value. For credit modeling purposes, collateral received is included in the calculation of our assets, while any collateral posted is excluded from the calculation of the credit adjustment. Our credit exposure for these over-the-counter, or OTC, derivatives is directly with our counterparty and continues until the maturity or termination of the contracts. Effect of Derivative Instruments on the Consolidated Statements of Financial Position Asset Derivatives Liability Derivatives Fair Value at Fair Value at Financial Position June 30, December 31, June 30, December 31, (in millions) Derivatives designated as hedging instruments: (1) Interest rate contracts Accounts payable and other $ — $ — $ (159.0 ) $ (144.0 ) Interest rate contracts Other long-term liabilities — — (23.8 ) (21.1 ) — — (182.8 ) (165.1 ) Derivatives not designated as hedging instruments: Commodity contracts Other current assets 1.2 — — — Commodity contracts Accounts payable and other — — — (1.4 ) Commodity contracts Other long-term liabilities — — — (0.2 ) 1.2 — — (1.6 ) Total derivative instruments $ 1.2 $ — $ (182.8 ) $ (166.7 ) (1) Includes items currently designated as hedging instruments. Excludes the portion of de-designated hedges which may have a component remaining in accumulated other comprehensive income, or AOCI. Accumulated Other Comprehensive Income We record the change in fair value of our highly effective cash flow hedges in AOCI until the derivative financial instruments are settled, at which time they are reclassified to earnings. As of June 30, 2017 and December 31, 2016, we included in AOCI unrecognized losses of approximately $207.9 million and $223.3 million, respectively, associated with derivative financial instruments that qualified for and were classified as cash flow hedges of forecasted transactions that were subsequently de-designated, settled, or terminated. These losses are reclassified to earnings over the periods during which the originally hedged forecasted transactions affect earnings. No commodity hedges were de-designated during the six months ended June 30, 2017 and 2016. We estimate that approximately $45.0 million, representing net losses from our cash flow hedging activities based on pricing and positions at June 30, 2017, will be reclassified from AOCI to earnings during the next 12 months. Derivatives in Cash Flow Amount of Gain Location of Gain Amount of Gain Location of Gain (Loss) (1) Amount of Gain (1) (in millions) Three months ended June 30, 2017 Interest rate contracts $ (17.6 ) Interest expense $ (10.4 ) Interest expense $ (1.6 ) Total $ (17.6 ) $ (10.4 ) $ (1.6 ) Three months ended June 30, 2016 Interest rate contracts $ (49.6 ) Interest expense $ (9.8 ) Interest expense $ (1.5 ) Total $ (49.6 ) $ (9.8 ) $ (1.5 ) Six months ended June 30, 2017 Interest rate contracts $ (15.8 ) Interest expense $ (20.7 ) Interest expense $ (1.9 ) Total $ (15.8 ) $ (20.7 ) $ (1.9 ) Six months ended June 30, 2016 Interest rate contracts $ (135.2 ) Interest expense $ (19.9 ) Interest expense $ (3.4 ) Commodity contracts — Commodity Costs 0.1 Commodity Costs — Total $ (135.2 ) $ (19.8 ) $ (3.4 ) (1) Includes only the ineffective portion of derivatives that are designated as hedging instruments and does not include net gains or losses associated with derivatives that do not qualify for hedge accounting treatment. Cash Flow Hedges 2017 2016 (in millions) Balance at January 1 $ (339.3 ) $ (370.0 ) Other comprehensive loss before reclassifications (20.3 ) (139.1 ) Amounts reclassified from AOCI (1) 20.7 19.8 Net other comprehensive income (loss) $ 0.4 $ (119.3 ) Balance at June 30 $ (338.9 ) $ (489.3 ) (1) For additional details on the amounts reclassified from AOCI, reference the Reclassifications from Accumulated Other Comprehensive Income Reclassifications from Accumulated Other Comprehensive Income Three months Six months 2017 2016 2017 2016 (in millions) Losses on cash flow hedges: Interest Rate Contracts (1) $ 10.4 $ 9.8 $ 20.7 $ 19.9 Total Reclassifications from AOCI $ 10.4 $ 9.8 $ 20.7 $ 19.9 (1) Loss reported within “Interest expense, net” in the consolidated statements of income Effect of Derivative Instruments on Consolidated Statements of Income Three months Six months 2017 2016 2017 2016 Derivatives Not Designated Location of Gain or (Loss) Amount of Gain or (Loss) (1) (2) Amount of Gain or (Loss) (1) (2) (in millions) Commodity contracts Transportation and other services (3) $ 1.4 $ (3.9 ) $ 3.1 $ (3.1 ) Total $ 1.4 $ (3.9 ) $ 3.1 $ (3.1 ) (1) Does not include settlements associated with derivative instruments that settle through physical delivery. (2) Includes only net gains or losses associated with those derivatives that do not receive hedge accounting treatment and does not include the ineffective portion of derivatives that are designated as hedging instruments. (3) Includes settlement gains of $0.4 million and $1.2 million for the three months ended June 30, 2017 and 2016, respectively, and settlement gains of $0.4 million and $3.7 million for the six months ended June 30, 2017 and 2016, respectively. We record the fair market value of our derivative financial and physical instruments in the consolidated statements of financial position as current and long-term assets or liabilities on a gross basis. However, the terms of the ISDA®, which govern our financial contracts and our other master netting agreements, allow the parties to elect in respect of all transactions under the agreement, in the event of a default and upon notice to the defaulting party, for the non-defaulting party to set-off all settlement payments, collateral held and any other obligations (whether or not then due), which the non-defaulting party owes to the defaulting party. The effect of the rights of set-off are outlined below. Offsetting of Financial Assets and Derivative Assets June 30, 2017 Gross Gross Net Amount Gross Amount Net Amount (in millions) Description: Derivatives $ 1.2 $ — $ 1.2 $ — $ 1.2 December 31, 2016 Gross Gross Net Amount Gross Amount Net Amount (in millions) Description: Derivatives $ — $ — $ — $ — $ — Offsetting of Financial Liabilities and Derivative Liabilities June 30, 2017 Gross Gross Amount Net Amount of Gross Amount Net Amount (in millions) Description: Derivatives $ (182.8 ) $ — $ (182.8 ) $ — $ (182.8 ) December 31, 2016 Gross Gross Amount Net Amount of Liabilities Gross Amount Net Amount (in millions) Description: Derivatives $ (166.7 ) $ — $ (166.7 ) $ — $ (166.7 ) Inputs to Fair Value Derivative Instruments June 30, 2017 December 31, 2016 Level 1 Level 2 Total Level 1 Level 2 Total (in millions) Interest rate contracts $ — $ (182.8 ) $ (182.8 ) $ — $ (165.1 ) $ (165.1 ) Commodity contracts: Financial — 1.2 1.2 — (1.6 ) (1.6 ) Total $ — $ (181.6 ) $ (181.6 ) $ — $ (166.7 ) $ (166.7 ) Qualitative Information about Level 2 Fair Value Measurements We categorize, as Level 2, the fair value of assets and liabilities that we measure with either directly or indirectly observable inputs as of the measurement date, where pricing inputs are other than quoted prices in active markets for the identical instrument. This category includes both OTC transactions valued using exchange traded pricing information in addition to assets and liabilities that we value using either models or other valuation methodologies derived from observable market data. These models are primarily industry-standard models that consider various inputs including: (i) quoted prices for assets and liabilities; (ii) time value; and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the assets and liabilities, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. Fair Value Measurements of Commodity Derivatives June 30, 2017 December 31, 2016 Commodity Notional (1) Wtd. Average Price (2) Fair Value (3) Fair Value (3) Receive Pay Asset Liability Asset Liability (in millions) Portion of contracts maturing in 2017 Swaps Receive fixed/pay variable Crude Oil 220,432 $ 52.14 $ 46.74 $ 1.2 $ — $ — $ (1.6 ) (1) Volumes of crude oil are measured in Bbl. (2) Weighted-average prices received and paid are in $/Bbl for crude oil. (3) The fair value is determined based on quoted market prices at June 30, 2017 and December 31, 2016, respectively, discounted using the swap rate for the respective periods to consider the time value of money. Fair values exclude credit valuation adjustment gains of nil at June 30, 2017 and December 31, 2016, as well as cash collateral received. Fair Value Measurements of Interest Rate Derivatives We enter into interest rate swaps, caps and derivative financial instruments with similar characteristics to manage the cash flow associated with future interest rate movements on our indebtedness. Average (1) Fair Value (2) Date of Maturity & Contract Type Accounting Treatment Notional June 30, December 31, (dollars in millions) Contracts maturing in 2017 Interest Rate Swaps – Pay Fixed Cash Flow Hedge $ 500 2.21 % $ — $ (0.3 ) Contracts maturing in 2018 Interest Rate Swaps – Pay Fixed Cash Flow Hedge $ 810 2.24 % $ (4.0 ) $ (9.4 ) Contracts maturing in 2019 Interest Rate Swaps – Pay Fixed Cash Flow Hedge $ 620 2.96 % $ (8.0 ) $ (7.3 ) Contracts settling prior to maturity 2017 – Pre-issuance Hedges Cash Flow Hedge $ 1,000 4.07 % $ (153.1 ) $ (136.2 ) 2018 – Pre-issuance Hedges Cash Flow Hedge $ 350 3.08 % $ (18.3 ) $ (13.1 ) (1) Interest rate derivative contracts are based on the one-month or three-month London Interbank Offered Rate, or LIBOR. (2) The fair value is determined from quoted market prices at June 30, 2017 and December 31, 2016, respectively, discounted using the swap rate for the respective periods to consider the time value of money. Fair values are presented in millions of dollars and exclude credit valuation adjustment gains of approximately $0.6 million and $1.2 million at June 30, 2017 and December 31, 2016, respectively.

SUPPLEMENTAL CASH FLOWS INFORMA

SUPPLEMENTAL CASH FLOWS INFORMATION	6 Months Ended
	Jun. 30, 2017
Supplemental Cash Flow Information [Abstract]
SUPPLEMENTAL CASH FLOWS INFORMATION	13. SUPPLEMENTAL CASH FLOWS INFORMATION Six months 2017 2016 (in millions) Total capital expenditures (excluding “Investments in joint ventures”) $ 207.3 $ 499.6 Decrease in construction payables 21.6 178.5 Cash used for additions to property, plant and equipment $ 228.9 $ 678.1

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS	6 Months Ended
	Jun. 30, 2017
Related Party Transactions [Abstract]
RELATED PARTY TRANSACTIONS	14. RELATED PARTY TRANSACTIONS Administrative and Workforce Related Services We do not directly employ any of the individuals responsible for managing or operating our business nor do we have any directors. Enbridge and its affiliates provide management and we obtain managerial, administrative, operational and workforce related services from our General Partner, Enbridge Management and affiliates of Enbridge pursuant to service agreements among our General Partner, Enbridge Management, affiliates of Enbridge, and us. Pursuant to these service agreements, we have agreed to reimburse our General Partner, Enbridge Management and affiliates of Enbridge, for the cost of managerial, administrative, operational and director services they provide to us. Where directly attributable, the cost of all compensation, benefits expenses and employer expenses for these employees are charged directly by Enbridge to the appropriate affiliate. Enbridge does not record any profit or margin for the administrative and operational services charged to us. The affiliate amounts incurred by us for services received pursuant to the services agreements are reflected in “Operating and administrative — affiliate” on our consolidated statements of income. Enbridge and its affiliates allocated direct workforce costs to us for our construction projects of $4.8 million as of June 30, 2017 and $28.4 million as of December 31, 2016, respectively, that we recorded as additions to “Property, plant and equipment, net” on our consolidated statements of financial position. Affiliate Revenues We record operating revenues in our Liquids segment for storage, transportation and terminalling services we provide to affiliates, which are presented in “Transportation and other services — affiliate” on our consolidated statements of income. Sale of Accounts Receivable We and certain of our subsidiaries were parties to a receivables purchase agreement (the Receivables Agreement), with an indirect, wholly-owned subsidiary of Enbridge. On April 27, 2017, we terminated our Receivables Agreement with the indirect, wholly-owned subsidiary of Enbridge in exchange for a one-time $5.0 million payment to us, which was recorded within “Other income” in our consolidated statements of income. As a result of the termination of the Receivables Agreement we discontinued the sale of our receivables balance. For the three months ended June 30, 2017, no receivables were sold and derecognized. We sold and derecognized receivables of $428.1 million for the three months ended June 30, 2016. For the six months ended June 30, 2017 and 2016, we sold and derecognized receivables of $458.0 million and $894.4 million, respectively, to an indirect, wholly-owned subsidiary of Enbridge. We received no cash proceeds for the three months ended June 30, 2017 and received $468.9 million for the six months ended June 30, 2017. We received cash proceeds of $427.9 million and $894.0 million for the three and six months ended June 30, 2016, respectively. Consideration for the receivables sold was equivalent to the carrying value of the receivables less a discount for credit risk. The difference between the carrying value of the receivables sold and the cash proceeds received was recognized in “Operating and administrative — affiliate” expense in our consolidated statements of income. For the three and six months ended June 30, 2017 and 2016, the expense stemming from the discount on the receivables sold was not material. As of June 30, 2017, we had no significant remaining derecognized receivables that had not been collected on behalf of the Enbridge subsidiary. As of December 31, 2016, we had $155.5 million of receivables, which had been sold and derecognized that had not been collected on behalf of the Enbridge subsidiary. Financial Transactions with Affiliates EUS Credit Agreement In connection with our investment in the Bakken Pipeline System, on February 15, 2017, we entered into the EUS Credit Agreement. The EUS Credit Agreement was a committed senior unsecured revolving credit facility that permitted aggregate borrowings of up to, at any one time outstanding for the purpose of funding our investment in the Bakken Pipeline System, $1.5 billion, (i) on a revolving basis for a 364-day period and (ii) for a 364-day term on a non-revolving basis following the expiration of the revolving period; provided that the EUS Credit Agreement would mature on the date any project financing was completed. Loans under the EUS Credit Agreement accrued interest based, at our election, on either the Eurocurrency rate or a base rate, in each case, plus an applicable margin. A facility fee accrued at the applicable margin rate, which is based on our non-credit-enhanced, senior unsecured long-term debt rating at the applicable time. On April 27, 2017, we re-paid the facility in full and terminated the EUS Credit Agreement. For further details refer to Note 9 Debt. EUS 364-day Credit Facility We are party to an unsecured revolving 364-day credit agreement (the EUS 364-day Credit Facility), with EUS. The EUS 364-day Credit Facility is a committed senior unsecured revolving credit facility that permits aggregate borrowings of up to, at any one time outstanding, $750 million, (i) on a revolving basis for a 364-day period and (ii) for a 364-day term on a non-revolving basis following the expiration of the revolving period. Loans under the EUS 364-day Credit Facility accrue interest, at our election, based on either the Eurocurrency rate or a base rate, in each case, plus an applicable margin. On July 25, 2017 we entered into an agreement with EUS whereby the termination date was extended to July 24, 2018. 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, 2019. As of June 30, 2017, we had $420.6 million outstanding under this facility, excluding any accrued interest to date. The commitment under the EUS 364-day Credit Facility may be permanently reduced by EUS, from time to time, by up to an amount equal to the net cash proceeds to us from the sale by us of debt or equity securities in a registered public offering. Distribution from MEP The following table presents distributions paid by MEP prior to its sale on June 28, 2017, representing the noncontrolling interest in MEP, and to us for our ownership of Class A common units. No distributions were made during the second quarter of 2017. Distribution Distribution Amount Paid to Amount Paid to Total MEP (in millions) January 26, 2017 February 14, 2017 $ 8.9 $ 7.6 $ 16.5 Joint Funding Arrangement for Bakken Pipeline On April 27, 2017, we finalized a joint funding arrangement with our General Partner with respect to our investment in the Bakken Pipeline System. Under the terms of the arrangement, our General Partner owns 75% and we own 25% of 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 in-service date of the Bakken Pipeline system. We received distributions from DakTex in the amount of $1.14 billion. The funds received were used to repay our borrowing, under the EUS Credit Agreement. Joint Funding Arrangement for Line 3 Replacement On January 26, 2017, our Board of Directors approved a joint funding arrangement with our General Partner for the U.S. L3R Program. Under the terms of the arrangement, our General Partner will fund 99% and we will 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 $450.1 million for its 99% interest in the project, including our share of the construction costs to date and other incremental amounts. The carrying amount of our 99% interest in the project at the transaction date was $411.0 million and was recorded as an increase to noncontrolling interest. The $39.1 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-rata basis. Our General Partner made equity contributions totaling $100.0 million to the OLP for the six months ended June 30, 2017, to fund its equity 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 the General Partner that established an additional series of partnership interests in the OLP, which we refer to as the EA interests. The EA interests 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. On January 26, 2017, we exercised our option under the Eastern Access joint funding arrangement to acquire an additional 15% interest in the Eastern Access Project, therefore increasing our ownership interest from 25% to 40% and reducing the interest of our General Partner form 75% to 60%, respectively. The exercise of our option occurred at book value of approximately $360 million and reduced noncontrolling interest by approximately $360 million. The Eastern Access Project was placed into service June 2016. Our General Partner made equity contributions totaling $5.6 million and $7.2 million to the OLP for the six months ended June 30, 2017 and 2016, respectively, to fund its equity portion of the construction costs associated with the Eastern Access Project. Distribution to Series EA Interests The following table presents distributions paid by the OLP during the six months ended June 30, 2017, 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 Distribution Amount Paid to Amount Paid to Total Series EA (in millions) April 27, 2017 May 15, 2017 $ 29.3 $ 62.0 $ 91.3 January 26, 2017 February 14, 2017 22.9 68.8 91.7 $ 52.2 $ 130.8 $ 183.0 Joint Funding Arrangement for U.S. Mainline Expansion Projects The OLP also has a series of partnership interests, which we refer to as the ME interests. The ME interests were created to finance the Mainline Expansion Projects to increase access to the markets of North Dakota and western Canada for light oil production on our Lakehead System between Neche, North Dakota and Superior, Wisconsin. Our General Partner owns 75% of the ME interests, and the projects are jointly funded by our General Partner at 75% and us at 25% 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 has made equity contributions totaling $26.0 million and $42.8 million to the OLP for the six months ended June 30, 2017 and 2016, respectively, to fund its equity portion of the construction costs associated with the Mainline Expansion Projects. Distribution to Series ME Interests The following table presents distributions paid by the OLP during the six months ended June 30, 2017, 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. Distribution Distribution Amount Paid to Amount Paid to Total Series ME (in millions) April 27, 2017 May 15, 2017 $ 12.7 $ 38.0 $ 50.7 January 26, 2017 February 14, 2017 14.2 42.7 56.9 $ 26.9 $ 80.7 $ 107.6

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	6 Months Ended
	Jun. 30, 2017
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	15. 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 and natural gas pipeline operations, and we are, at times, subject to environmental remediation at various contaminated sites. We manage this environmental risk through appropriate environmental policies and practices to minimize any impact our operations may have on the environment. To the extent that we are unable to recover payment for environmental liabilities from insurance or other potentially responsible parties, we will be responsible for payment of liabilities arising from environmental incidents associated with the operating activities of our liquids and natural gas businesses. Our General Partner has agreed to indemnify us from and against any costs relating to environmental liabilities associated with the Lakehead system assets prior to the transfer of these assets to us in 1991. This excludes any liabilities resulting from a change in laws after such transfer. We continue to voluntarily investigate past leak sites on our systems for the purpose of assessing whether any remediation is required in light of current regulations. As of June 30, 2017 and December 31, 2016, our consolidated statements of financial position included $23.6 million and $99.8 million, respectively, in “Environmental liabilities,” and $55.3 million and $50.8 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 and natural gas assets and penalties we have been or expect to be assessed. Lakehead Line 6B Crude Oil Release On July 26, 2010, a release of crude oil on Line 6B of our Lakehead system was reported near Marshall, Michigan. We estimate that approximately 20,000 barrels of crude oil were leaked at the site, a portion of which reached the Kalamazoo River via Talmadge Creek, a waterway that feeds the Kalamazoo River. The released crude oil affected approximately 38 miles of shoreline along the Talmadge Creek and Kalamazoo River waterways, including residential areas, businesses, farmland and marshland between Marshall and downstream of Battle Creek, Michigan. We continue to evaluate the need for additional remediation activities and are performing the necessary restoration and monitoring of the areas affected by the Line 6B crude oil release. All the initiatives we are undertaking in the monitoring and restoration phase are intended to restore the crude oil release area to the satisfaction of the appropriate regulatory authorities. As of June 30, 2017, our cumulative cost estimate for the Line 6B crude oil release remains at $1.2 billion. For purposes of estimating our expected losses associated with the Line 6B crude oil release, we have included those costs that we considered probable and that could be reasonably estimated at June 30, 2017. Our estimates exclude: (i) amounts we have capitalized, (ii) any claims associated with the release that may later become evident, (iii) amounts recoverable under insurance, and (iv) fines and penalties from other governmental agencies except as described in the Fines and Penalties (in millions) Response personnel and equipment $ 547.3 Environmental consultants 224.3 Professional, regulatory, fines and penalties and other 443.4 Total $ 1,215.0 For the six months ended June 30, 2017 and 2016, we made payments of $70.4 million and $12.9 million, respectively, for costs associated with the Line 6B crude oil release. As of June 30, 2017 and December 31, 2016, we had a remaining estimated liability of $67.9 million and $138.8 million, respectively. Line 6B Fines and Penalties At June 30, 2017, our total estimated costs related to the Line 6B crude oil release include $68.5 million in fines and penalties, which includes fines and penalties from the Department of Justice as discussed below. Consent Decree On May 23, 2017, the United States District Court for the Western District of Michigan, Southern Division (the Court), approved a Consent Decree (the Consent Decree), which is our signed settlement agreement with the United States Environmental Protection Agency (EPA) and the United States Department of Justice regarding Lines 6A and 6B crude oil releases, both of which occurred in 2010. On June 15, 2017, Enbridge made a total payment of $67.8 million as required by the Consent Decree, which reflects a $61.0 million civil penalty for the Line 6B release, a $1.0 million civil penalty for the Line 6A release, and $5.8 million for past removal costs and interest. In addition to the monetary fines and penalties, the Consent Decree calls for replacement of Line 3, which we initiated in 2014 and is currently under regulatory review in the State of Minnesota; refer to Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations Line 3 Replacement Program Insurance We are included in the comprehensive insurance program that is maintained by Enbridge for its subsidiaries and affiliates. On May 1 of each year, our insurance program is renewed and includes commercial liability insurance coverage that is consistent with coverage considered customary for our industry and includes coverage for environmental incidents such as those we have incurred for the crude oil release from Line 6B, excluding costs for fines and penalties. Enbridge, together with us and its other affiliates, are covered under comprehensive property and liability insurance programs under which we are insured through April 30, 2018, with a liability program aggregate limit of $940.0 million, which includes sudden and accidental pollution liability. In the unlikely event that multiple insurable incidents which in aggregate exceed coverage limits occur within the same insurance period, the total insurance coverage will be allocated among the Enbridge entities on an equitable basis based on an insurance allocation agreement we have entered into with Enbridge and other Enbridge subsidiaries. A majority of the costs incurred for the July 2010 Line 6B crude oil release, other than fines and penalties, are covered by the insurance policies that expired on April 30, 2011, which had an aggregate limit of $650.0 million for pollution liability for Enbridge and its affiliates. Including our remediation spending through June 30, 2017, costs related to Line 6B exceeded the limits of the coverage available under these insurance policies. Through June 30, 2017, we have recorded total insurance recoveries of $547.0 million for the Line 6B crude oil release, out of the $650.0 million aggregate limit. In March 2013, we and Enbridge filed a lawsuit against the insurers of $145.0 million of coverage, as one particular insurer disputed our recovery eligibility for costs related to our claim on the Line 6B crude oil release and the other remaining insurers asserted that their payment was predicated on the outcome of our recovery with that insurer. We received a partial recovery payment of $42.0 million from the other remaining insurers and amended our lawsuit such that it includes only one insurer. Of the remaining $103.0 million coverage limit, $85.0 million was the subject matter of a lawsuit Enbridge filed against one particular insurer described above. In March 2015, Enbridge reached agreement with that insurer to submit the $85.0 million claim to binding arbitration. On May 2, 2017, the arbitration panel issued a decision that was not favorable to Enbridge. As a result, we are unlikely to receive any additional insurance recoveries in connection with the Line 6B crude oil release. Legal and Regulatory Proceedings We are subject to various legal and regulatory actions and proceedings which 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 the early stages of discovery in relation to a unitholder derivative action, with trial scheduled in the second quarter of 2018. Accordingly, 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 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. A number of governmental agencies and regulators have initiated investigations into the Line 6B crude oil release. One action or claim is pending against us and our affiliates in state court in connection with the Line 6B crude oil release. Based on the current status of this case, we do not expect the outcome of this action to be material to our results of operations or financial condition. We have accrued a provision for future legal costs and probable losses associated with the Line 6B crude oil release as described above in this footnote.

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS	6 Months Ended
	Jun. 30, 2017
Subsequent Events [Abstract]
SUBSEQUENT EVENTS	16. SUBSEQUENT EVENTS Distribution to Partners On July 28, 2017, the board of directors of Enbridge Management declared a distribution payable to our partners on August 14, 2017. The distribution will be paid to unitholders of record as of August 7, 2017 of our available cash of $160.2 million at June 30, 2017, or $0.35 per limited partner unit. Of this distribution, $129.6 million will be paid in cash, $30.0 million will be distributed in i-units to our i-unitholder, Enbridge Management, and due to the i-unit distribution, $0.6 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 28, 2017, 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 $49.8 million to the noncontrolling interest in the Series EA, while $33.2 million will be paid to us. Distribution to Series ME Interests On July 28, 2017, 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 $41.3 million to the noncontrolling interest in the Series ME, while $13.8 million will be paid to us.

FUTURE ACCOUNTING POLICY CHAN24

FUTURE ACCOUNTING POLICY CHANGES (Policies)	6 Months Ended
	Jun. 30, 2017
Accounting Policies [Abstract]
Accounting for Credit Losses	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 amendment adds a new impairment model, known as the current expected credit loss model that is based on expected losses rather than incurred losses. Under the new guidance, an entity recognizes as an allowance its estimate of expected credit losses, which the Financial Accounting Standards Board (FASB) believes will result in more timely recognition of such losses. We are currently assessing the impact of the new standard on our consolidated financial statements. The accounting update is effective for annual and interim periods beginning on or after December 15, 2019 and is to be applied using a modified retrospective approach.
Recognition of Leases	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 consolidated statements 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 are currently assessing the impact of the new standard on our consolidated financial statements. The accounting update is effective for fiscal years beginning after December 15, 2018 and is to be applied using a modified retrospective approach.
Revenues from Contracts with Customers	Revenues from Contracts with Customers ASU 2014-09 was issued in 2014 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. The standard is effective January 1, 2018. The new revenue standard permits either a full retrospective method of adoption with restatement of all prior periods presented, or a modified retrospective method with the cumulative effect of applying the new standard recognized as an adjustment to opening retained earnings in the period of adoption. We have tentatively decided to adopt the new revenue standard using the modified retrospective method. We have reviewed a sample of our revenue contracts in order to evaluate the effect of the new standard on our revenue recognition practices. Based on the our initial assessment, estimates of variable consideration which will be required under the new standard for certain contracts may result in changes to the pattern or timing of revenue recognition for those contracts. While we have not yet completed the assessment, we do not expect these changes to have a material impact on revenues or earnings (loss). We are currently developing processes to generate the disclosures required under the new standard.

NET INCOME PER LIMITED PARTNE25

NET INCOME PER LIMITED PARTNER UNIT (Tables)	6 Months Ended
	Jun. 30, 2017
Earnings Per Share [Abstract]
Basic and Diluted Net Income Per Limited Partner Unit	We determined basic and diluted net income per limited partner unit as follows: Three months Six months 2017 2016 2017 2016 (in millions, except per unit amounts) Continuing operations: Net income $ 232.4 $ 240.7 $ 411.3 $ 443.4 Less: Net income attributable to: Noncontrolling interest 101.8 87.3 177.7 165.4 Series 1 preferred unit distributions 6.5 22.5 29.0 45.0 Accretion of discount on Series 1 preferred units 7.3 1.2 8.5 2.3 Net income attributable to general and limited partner interests in Enbridge Energy Partners, L.P. – continuing operations 116.8 129.7 196.1 230.7 Distributions: Incentive distributions (1) (3.7 ) (5.2 ) (7.4 ) (10.4 ) Distributed earnings attributed to our General Partner (3.2 ) (5.3 ) (6.4 ) (10.5 ) Distributed earnings attributed to Class D and Class E units (6.4 ) (49.1 ) (12.7 ) (98.2 ) Total distributed earnings to our General Partner, Class D and Class E units and IDUs (13.3 ) (59.6 ) (26.5 ) (119.1 ) Total distributed earnings attributed to our common units and i-units (146.9 ) (202.9 ) (293.3 ) (404.6 ) Total distributed earnings (160.2 ) (262.5 ) (319.8 ) (523.7 ) Overdistributed earnings $ (43.4 ) $ (132.8 ) $ (123.7 ) $ (293.0 ) Discontinued operations: Net loss $ (35.4 ) $ (63.0 ) $ (56.8 ) $ (93.3 ) Less: Net loss attributable to: Noncontrolling interest (11.2 ) (17.0 ) (18.8 ) (26.3 ) Net loss attributable to general and limited partner interests in Enbridge Energy Partners, L.P. – discontinued operations (24.2 ) (46.0 ) (38.0 ) (67.0 ) Weighted average common units and i-units outstanding 400.1 347.1 376.7 345.9 Three months Six months 2017 2016 2017 2016 (in millions, except per unit amounts) Basic and diluted earnings per unit: Distributed earnings per common unit and i-unit – continuing operations (2) $ 0.37 $ 0.58 $ 0.78 $ 1.17 Overdistributed earnings per common unit and i-unit (3) (0.10 ) (0.37 ) (0.32 ) (0.84 ) Net income per common unit and i-unit (basic and diluted) – continuing operations (4) $ 0.27 $ 0.21 $ 0.46 $ 0.33 Net loss per common unit and i-unit (basic and diluted) – discontinued operations (4) $ (0.06 ) $ (0.13 ) $ (0.10 ) $ (0.18 ) Net income per common unit and i-unit (basic and diluted) $ 0.21 $ 0.08 $ 0.36 $ 0.15 (1) For the three and six months ended June 30, 2017, Class D units and IDUs were not entitled to distributions as the wholly-owned subsidiary of our General Partner irrevocably waived its rights associated with the Class D and IDUs; for the three and six months ended June 30, 2017, incentive distributions were made to Class F units. For the three and six months ended June 30, 2016, incentive distributions were made to IDUs and Class D units. (2) 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. (3) 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. (4) For the three months ended June 30, 2017, there were no units excluded from the if-converted method of calculating diluted earnings per share. For the six months ended June 30, 2017 and the three and six months ended June 30, 2016, 43,201,310 anti-dilutive Preferred units and 18,114,975 anti-dilutive Class E units were excluded from the if-converted method of calculating diluted earnings per unit. For the six months ended June 30, 2017, 66,100,000 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. For the three and six months ended June 30, 2016, 66,100,000 anti-dilutive Class D units were excluded from the if-converted method of calculating diluted earnings per unit.
Schedule of Formula for Distributing Available Cash	On April 27, 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 its 1,000 incentive distribution units (IDUs) in exchange for the issuance of 1,000 Class F units. The irrevocable waiver (the Waiver) is effective with respect to distributions declared with a record date after April 27, 2017. The Class F units are entitled to receive an incentive distribution for amounts distributed in excess of the Minimum Quarterly Distribution as described in the following table: Distribution Targets Portion of Quarterly Percentage Distributed (1) Percentage Distributed Minimum Quarterly Distribution Up to $0.295 2 % 98 % First Target Distribution > $0.295 to $0.35 15 % 85 % Over First Target Distribution > $0.35 25 % 75 % (1) For distributions in excess of the Minimum Quarterly Distribution, this percentage includes both the General Partner’s distributions of 2% and the distribution to the Class F Units.

SEGMENT INFORMATION (Tables)

SEGMENT INFORMATION (Tables)	6 Months Ended
	Jun. 30, 2017
Segment Reporting [Abstract]
Schedule of Segment Reporting Information, By Segment	Three months ended June 30, 2017 Liquids Natural Gas (1) Other Consolidated (2) (in millions) Operating revenues: (3) Transportation and other services $ 596.5 $ — $ — $ 596.5 596.5 — — 596.5 Operating expenses: Environmental costs, net of recoveries 3.5 — — 3.5 Operating and administrative 153.5 — 4.8 158.3 Power 66.4 — — 66.4 Depreciation and amortization 108.3 — — 108.3 Gain on sale of assets (51.5 ) — — (51.5 ) 280.2 — 4.8 285.0 Operating income (loss) $ 316.3 $ — $ (4.8 ) $ 311.5 Interest expense, net (102.8 ) Allowance for equity used during construction 10.7 Other income (4) 11.4 Income from continuing operations before income tax benefit 230.8 Income tax benefit 1.6 Income from continuing operations 232.4 Income (loss) from discontinued operations — (41.4 ) 6.0 (35.4 ) Net income $ 197.0 (1) The operating results of our Natural Gas segment are included in discontinued operations as a result of the Midcoast sale to our General Partner. For further information refer to Note 6 Dispositions and Discontinued Operations. (2) Certain costs that are not allocated to individual segments, including Other, interest expense, allowance for equity used during construction, and income taxes are included in the consolidated total. (3) There were no intersegment revenues for the three months ended June 30, 2017. (4) Other income includes our equity income for our Liquids segment from our investment in the Bakken Pipeline System. Three months ended June 30, 2016 Liquids Natural Gas (1) Other Consolidated (2) (in millions) Operating revenues: (3) Transportation and other services $ 621.3 $ — $ — 621.3 621.3 — — 621.3 Operating expenses: Environmental costs, net of recoveries 0.1 — — 0.1 Operating and administrative 132.1 — 2.0 134.1 Power 59.7 — — 59.7 Depreciation and amortization 104.9 — — 104.9 296.8 — 2.0 298.8 Operating income (loss) $ 324.5 $ — $ (2.0 ) $ 322.5 Interest expense, net (93.3 ) Allowance for equity used during construction 13.3 Other income 0.2 Income from continuing operations before income tax expense 242.7 Income tax expense (2.0 ) Income from continuing operations 240.7 Loss from discontinued operations — (53.5 ) (9.5 ) (63.0 ) Net income $ 177.7 (1) The operating results of our Natural Gas segment are included in discontinued operations as a result of the Midcoast sale to our General Partner. For further information refer to Note 6 Dispositions and Discontinued Operations. (2) Certain costs that are not allocated to individual segments, including Other, interest expense, allowance for equity used during construction, and income taxes are included in the consolidated total. (3) There were no intersegment revenues for the three months ended June 30, 2016. Six months ended June 30, 2017 Liquids Natural Gas (1) Other Consolidated (2) (in millions) Operating revenues: (3) Transportation and other services $ 1,201.2 $ — $ — $ 1,201.2 1,201.2 — — 1,201.2 Operating expenses: Environmental costs, net of recoveries 13.8 — — 13.8 Operating and administrative 304.0 — 7.4 311.4 Power 140.9 — — 140.9 Depreciation and amortization 217.1 — — 217.1 Gain on sale of asset (62.1 ) — — (62.1 ) 613.7 — 7.4 621.1 Operating income (loss) $ 587.5 $ — $ (7.4 ) $ 580.1 Interest expense, net (201.7 ) Allowance for equity used during construction 21.0 Other income (4) 11.4 Income from continuing operations before income tax benefit 410.8 Income tax benefit 0.5 Income from continuing operations 411.3 Loss from discontinued operations $ — $ (51.1 ) $ (5.7 ) $ (56.8 ) Net income $ 354.5 (1) The operating results of our Natural Gas segment are included in discontinued operations as a result of the Midcoast sale to our General Partner. For further information refer to Note 6 Dispositions and Discontinued Operations (2) Certain costs that are not allocated to individual segments, including Other, interest expense, allowance for equity used during construction, and income taxes are included in the consolidated total. (3) There were no intersegment revenues for the six months ended June 30, 2017. (4) Other income includes our equity income for our Liquids segment from our investment in the Bakken Pipeline System. Six months ended June 30, 2016 Liquids Natural Gas (1) Other Consolidated (2) (in millions) Operating revenues: (3) Transportation and other services $ 1,251.0 $ — $ — $ 1,251.0 1,251.0 — — 1,251.0 Operating expenses: Environmental costs, net of recoveries 17.0 — — 17.0 Operating and administrative 269.3 — 7.1 276.4 Power 132.5 — — 132.5 Depreciation and amortization 206.3 — — 206.3 625.1 — 7.1 632.2 Operating income (loss) $ 625.9 $ — $ (7.1 ) $ 618.8 Interest expense, net (197.8 ) Allowance for equity used during construction 25.6 Other income 0.4 Income from continuing operations before income tax expense 447.0 Income tax expense (3.6 ) Income from continuing operations 443.4 Loss from discontinued operations — (76.3 ) (17.0 ) (93.3 ) Net income $ 350.1 (1) The operating results of our Natural Gas segment are included in discontinued operations as a result of the Midcoast sale to our General Partner. For further information refer to Note 6 Dispositions and Discontinued Operations. (2) Certain costs that are not allocated to individual segments, including Other, interest expense, allowance for equity used during construction, and income taxes are included in the consolidated total. (3) There were no intersegment revenues for the six months ended June 30, 2016. Total Assets June 30, December 31, (1) Liquids $ 14,661.5 $ 13,030.5 Natural Gas — — Other 5.9 165.6 Total $ 14,667.4 $ 13,196.1 (1) Comparative information excludes assets from discontinued operations. See Note 6 Dispositions and Discontinued Operations.

REGULATORY MATTERS (Tables)

REGULATORY MATTERS (Tables)	6 Months Ended
	Jun. 30, 2017
Regulatory Assets and Liabilities Disclosure [Abstract]
Schedule of Changes in Net Regulatory Asset Balance	Three months Six months 2017 2016 2017 2016 (in millions) Net regulatory asset (liability) balance at beginning of period $ (34.1 ) $ 31.2 $ 11.9 $ 29.9 Current period (over) under recovery revenue adjustments 12.0 5.9 (27.0 ) 13.6 Amortization of prior year regulatory asset (1.6 ) (7.8 ) (8.6 ) (14.2 ) Net regulatory asset (liability) balance at end of period $ (23.7 ) $ 29.3 $ (23.7 ) $ 29.3

DISPOSITIONS AND DISCONTINUED28

DISPOSITIONS AND DISCONTINUED OPERATIONS (Tables)	6 Months Ended
	Jun. 30, 2017
Discontinued Operations and Disposal Groups [Abstract]
Disposal Groups, Including Discontinued Operations	Three months Six months 2017 2016 2017 2016 Operating revenues: Commodity sales $ 559.3 $ 379.4 $ 1,085.0 $ 757.2 Commodity sales – affiliate 3.3 1.4 9.4 6.6 Transportation and other services 24.5 46.8 66.7 95.7 587.1 427.6 1,161.1 859.5 Operating expenses: Commodity costs 496.8 350.5 968.2 685.9 Commodity costs – affiliate 25.7 8.5 42.1 21.2 Operating and administrative 28.3 40.0 64.7 74.8 Operating and administrative – affiliate 35.0 38.9 68.7 76.8 Depreciation and amortization 37.1 40.0 74.5 79.5 Asset impairment — 10.6 — 10.6 622.9 488.5 1,218.2 948.8 Operating loss (35.8 ) (60.9 ) (57.1 ) (89.3 ) Interest expense, net (9.5 ) (8.1 ) (17.4 ) (16.5 ) Other income 10.4 6.5 18.6 13.9 Loss before income tax expense (34.9 ) (62.5 ) (55.9 ) (91.9 ) Income tax expense (0.5 ) (0.5 ) (0.9 ) (1.4 ) Net loss from discontinued operations $ (35.4 ) $ (63.0 ) $ (56.8 ) $ (93.3 ) December 31, Current assets related to discontinued operations: Cash and cash equivalents $ 7.4 Restricted cash 11.0 Receivables, trade and other, net of allowance for doubtful accounts 8.5 Due from General Partner and affiliates 2.1 Accrued receivables 20.8 Inventory 28.1 Other current assets 60.7 $ 138.6 Non-current assets related to discontinued operations: Property, plant and equipment, net $ 4,114.5 Equity investments in joint ventures 360.7 Intangible assets, net 251.8 Other assets, net 48.3 $ 4,775.3 December 31, Current liabilities related to discontinued operations: Accounts payable and other $ 66.9 Due to General Partner and affiliates 38.8 Environmental liabilities 0.1 Accrued purchases 171.8 Property and other taxes payable 17.2 Interest payable 5.0 $ 299.8 Non-current liabilities related to discontinued operations: Long-term debt $ 818.5 Other long-term liabilities 25.8 $ 844.3

EQUITY INVESTMENTS IN JOINT V29

EQUITY INVESTMENTS IN JOINT VENTURES (Tables)	6 Months Ended
	Jun. 30, 2017
Equity Method Investments and Joint Ventures [Abstract]
Equity Method Investments	Ownership June 30, December 31, (in millions) MarEn Bakken Company LLC 75.0 % $ 1,563.1 $ —

DEBT (Tables)

DEBT (Tables)	6 Months Ended
	Jun. 30, 2017
Debt Disclosure [Abstract]
Schedule of Line of Credit Facilities	Maturity Total Facilities Draws (1) Available (in millions) Enbridge Energy Partners, L.P. 2019 – 2020 $ 2,625.0 $ 1,535.0 $ 1,090.0 (1) Includes facility draws, letters of credit and commercial paper issuances that are back-stopped by the credit facility and excludes the EUS 364-day Credit Facility

NONCONTROLLING INTERESTS (Table

NONCONTROLLING INTERESTS (Tables)	6 Months Ended
	Jun. 30, 2017
Noncontrolling Interest [Abstract]
Schedule of Non Controlling Interest	Three months Six months 2017 2016 2017 2016 (in millions) Eastern Access Interests $ 36.8 $ 53.2 $ 76.3 $ 104.7 U.S. Mainline Expansion Interests 35.8 34.1 69.2 60.7 North Dakota Pipeline Company Interests 18.4 — 16.8 — Line 3 Replacement Interests 6.0 — 10.6 — Enbridge Holdings (DakTex) L.L.C. Interests 4.8 — 4.8 — Midcoast Energy Partners, L.P. – Discontinued Operations (11.2 ) (17.0 ) (18.8 ) (26.3 ) Total $ 90.6 $ 70.3 $ 158.9 $ 139.1

DERIVATIVE FINANCIAL INSTRUME32

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Tables)	6 Months Ended
	Jun. 30, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value	Our derivative financial instruments are included at their fair values in the consolidated statements of financial position as follows: June 30, December 31, (in millions) Other current assets $ 1.2 $ — Accounts payable and other (159.0 ) (145.4 ) Other long-term liabilities (23.8 ) (21.3 ) $ (181.6 ) $ (166.7 )
Schedule of Derivative Balances by Counter Party Credit Quality	The table below summarizes our derivative balances by counterparty credit quality (any negative amounts represent our net obligations to pay the counterparty). June 30, 2017 December 31, 2016 (in millions) Counterparty Credit Quality (1) AA $ (82.6 ) $ (79.2 ) A (63.6 ) (58.4 ) Lower than A (35.4 ) (29.1 ) $ (181.6 ) $ (166.7 ) (1) As determined by nationally-recognized statistical ratings organizations.
Schedule of Credit Concentrations in Industry Sectors	At June 30, 2017 and December 31, 2016, we had credit concentrations in the following industry sectors, as presented below: June 30, December 31, (in millions) United States financial institutions and investment banking entities $ (131.3 ) $ (121.7 ) Non-United States financial institutions (50.3 ) (45.0 ) $ (181.6 ) $ (166.7 )
Effect of Derivative Instruments on the Consolidated Statements of Financial Position	Asset Derivatives Liability Derivatives Fair Value at Fair Value at Financial Position June 30, December 31, June 30, December 31, (in millions) Derivatives designated as hedging instruments: (1) Interest rate contracts Accounts payable and other $ — $ — $ (159.0 ) $ (144.0 ) Interest rate contracts Other long-term liabilities — — (23.8 ) (21.1 ) — — (182.8 ) (165.1 ) Derivatives not designated as hedging instruments: Commodity contracts Other current assets 1.2 — — — Commodity contracts Accounts payable and other — — — (1.4 ) Commodity contracts Other long-term liabilities — — — (0.2 ) 1.2 — — (1.6 ) Total derivative instruments $ 1.2 $ — $ (182.8 ) $ (166.7 ) (1) Includes items currently designated as hedging instruments. Excludes the portion of de-designated hedges which may have a component remaining in accumulated other comprehensive income, or AOCI.
Effect of Derivative Instruments on the Consolidated Statements of Income and Accumulated Other Comprehensive Income	Derivatives in Cash Flow Amount of Gain Location of Gain Amount of Gain Location of Gain (Loss) (1) Amount of Gain (1) (in millions) Three months ended June 30, 2017 Interest rate contracts $ (17.6 ) Interest expense $ (10.4 ) Interest expense $ (1.6 ) Total $ (17.6 ) $ (10.4 ) $ (1.6 ) Three months ended June 30, 2016 Interest rate contracts $ (49.6 ) Interest expense $ (9.8 ) Interest expense $ (1.5 ) Total $ (49.6 ) $ (9.8 ) $ (1.5 ) Six months ended June 30, 2017 Interest rate contracts $ (15.8 ) Interest expense $ (20.7 ) Interest expense $ (1.9 ) Total $ (15.8 ) $ (20.7 ) $ (1.9 ) Six months ended June 30, 2016 Interest rate contracts $ (135.2 ) Interest expense $ (19.9 ) Interest expense $ (3.4 ) Commodity contracts — Commodity Costs 0.1 Commodity Costs — Total $ (135.2 ) $ (19.8 ) $ (3.4 ) (1) Includes only the ineffective portion of derivatives that are designated as hedging instruments and does not include net gains or losses associated with derivatives that do not qualify for hedge accounting treatment.
Components of Accumulated Other Comprehensive Income/(Loss)	Components of Accumulated Other Comprehensive Income/(Loss) Cash Flow Hedges 2017 2016 (in millions) Balance at January 1 $ (339.3 ) $ (370.0 ) Other comprehensive loss before reclassifications (20.3 ) (139.1 ) Amounts reclassified from AOCI (1) 20.7 19.8 Net other comprehensive income (loss) $ 0.4 $ (119.3 ) Balance at June 30 $ (338.9 ) $ (489.3 ) (1) For additional details on the amounts reclassified from AOCI, reference the Reclassifications from Accumulated Other Comprehensive Income
Reclassifications from Accumulated Other Comprehensive Income	Three months Six months 2017 2016 2017 2016 (in millions) Losses on cash flow hedges: Interest Rate Contracts (1) $ 10.4 $ 9.8 $ 20.7 $ 19.9 Total Reclassifications from AOCI $ 10.4 $ 9.8 $ 20.7 $ 19.9 (1) Loss reported within “Interest expense, net” in the consolidated statements of income
Effect of Derivative Instruments on Consolidated Statements of Income	Three months Six months 2017 2016 2017 2016 Derivatives Not Designated Location of Gain or (Loss) Amount of Gain or (Loss) (1) (2) Amount of Gain or (Loss) (1) (2) (in millions) Commodity contracts Transportation and other services (3) $ 1.4 $ (3.9 ) $ 3.1 $ (3.1 ) Total $ 1.4 $ (3.9 ) $ 3.1 $ (3.1 ) (1) Does not include settlements associated with derivative instruments that settle through physical delivery. (2) Includes only net gains or losses associated with those derivatives that do not receive hedge accounting treatment and does not include the ineffective portion of derivatives that are designated as hedging instruments. (3) Includes settlement gains of $0.4 million and $1.2 million for the three months ended June 30, 2017 and 2016, respectively, and settlement gains of $0.4 million and $3.7 million for the six months ended June 30, 2017 and 2016, respectively.
Offsetting of Financial Assets and Derivative Assets	June 30, 2017 Gross Gross Net Amount Gross Amount Net Amount (in millions) Description: Derivatives $ 1.2 $ — $ 1.2 $ — $ 1.2 December 31, 2016 Gross Gross Net Amount Gross Amount Net Amount (in millions) Description: Derivatives $ — $ — $ — $ — $ —
Offsetting of Financial Liabilities and Derivative Liabilities	June 30, 2017 Gross Gross Amount Net Amount of Gross Amount Net Amount (in millions) Description: Derivatives $ (182.8 ) $ — $ (182.8 ) $ — $ (182.8 ) December 31, 2016 Gross Gross Amount Net Amount of Liabilities Gross Amount Net Amount (in millions) Description: Derivatives $ (166.7 ) $ — $ (166.7 ) $ — $ (166.7 )
Table Setting Forth By Level Within The Fair Value Hierarchy Financial Assets And Liabilities	The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2017 and December 31, 2016. We classify financial assets and liabilities in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect our valuation of the financial assets and liabilities and their placement within the fair value hierarchy. For the periods ending June 30, 2017 and December 31, 2016, we did not have any Level 3 derivative instruments. June 30, 2017 December 31, 2016 Level 1 Level 2 Total Level 1 Level 2 Total (in millions) Interest rate contracts $ — $ (182.8 ) $ (182.8 ) $ — $ (165.1 ) $ (165.1 ) Commodity contracts: Financial — 1.2 1.2 — (1.6 ) (1.6 ) Total $ — $ (181.6 ) $ (181.6 ) $ — $ (166.7 ) $ (166.7 )
Schedule of Fair Values of Expected Cash Flows of Outstanding Commodity Based Swaps and Physical Contracts	The following table provides summarized information about the fair values of expected cash flows of our outstanding commodity based swaps at June 30, 2017 and December 31, 2016. June 30, 2017 December 31, 2016 Commodity Notional (1) Wtd. Average Price (2) Fair Value (3) Fair Value (3) Receive Pay Asset Liability Asset Liability (in millions) Portion of contracts maturing in 2017 Swaps Receive fixed/pay variable Crude Oil 220,432 $ 52.14 $ 46.74 $ 1.2 $ — $ — $ (1.6 ) (1) Volumes of crude oil are measured in Bbl. (2) Weighted-average prices received and paid are in $/Bbl for crude oil. (3) The fair value is determined based on quoted market prices at June 30, 2017 and December 31, 2016, respectively, discounted using the swap rate for the respective periods to consider the time value of money. Fair values exclude credit valuation adjustment gains of nil at June 30, 2017 and December 31, 2016, as well as cash collateral received.
Schedule of Current Interest Rate Derivatives	The following table provides information about our current interest rate derivatives for the specified periods. Average (1) Fair Value (2) Date of Maturity & Contract Type Accounting Treatment Notional June 30, December 31, (dollars in millions) Contracts maturing in 2017 Interest Rate Swaps – Pay Fixed Cash Flow Hedge $ 500 2.21 % $ — $ (0.3 ) Contracts maturing in 2018 Interest Rate Swaps – Pay Fixed Cash Flow Hedge $ 810 2.24 % $ (4.0 ) $ (9.4 ) Contracts maturing in 2019 Interest Rate Swaps – Pay Fixed Cash Flow Hedge $ 620 2.96 % $ (8.0 ) $ (7.3 ) Contracts settling prior to maturity 2017 – Pre-issuance Hedges Cash Flow Hedge $ 1,000 4.07 % $ (153.1 ) $ (136.2 ) 2018 – Pre-issuance Hedges Cash Flow Hedge $ 350 3.08 % $ (18.3 ) $ (13.1 ) (1) Interest rate derivative contracts are based on the one-month or three-month London Interbank Offered Rate, or LIBOR. (2) The fair value is determined from quoted market prices at June 30, 2017 and December 31, 2016, respectively, discounted using the swap rate for the respective periods to consider the time value of money. Fair values are presented in millions of dollars and exclude credit valuation adjustment gains of approximately $0.6 million and $1.2 million at June 30, 2017 and December 31, 2016, respectively.

SUPPLEMENTAL CASH FLOWS INFOR33

SUPPLEMENTAL CASH FLOWS INFORMATION (Tables)	6 Months Ended
	Jun. 30, 2017
Supplemental Cash Flow Information [Abstract]
Schedule of Supplemental Cash Flow Information	In the “Cash used in investing activities” section of the consolidated statements of cash flows, we exclude changes that do not affect cash. The following is a reconciliation of cash used for additions to property, plant and equipment to total capital expenditures (excluding “Investments in joint ventures”): Six months 2017 2016 (in millions) Total capital expenditures (excluding “Investments in joint ventures”) $ 207.3 $ 499.6 Decrease in construction payables 21.6 178.5 Cash used for additions to property, plant and equipment $ 228.9 $ 678.1

RELATED PARTY TRANSACTIONS (Tab

RELATED PARTY TRANSACTIONS (Tables)	6 Months Ended
	Jun. 30, 2017
Related Party Transactions [Abstract]
Schedule of Distributions	The following table presents distributions paid by MEP prior to its sale on June 28, 2017, representing the noncontrolling interest in MEP, and to us for our ownership of Class A common units. No distributions were made during the second quarter of 2017. Distribution Distribution Amount Paid to Amount Paid to Total MEP (in millions) January 26, 2017 February 14, 2017 $ 8.9 $ 7.6 $ 16.5 The following table presents distributions paid by the OLP during the six months ended June 30, 2017, 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 Distribution Amount Paid to Amount Paid to Total Series EA (in millions) April 27, 2017 May 15, 2017 $ 29.3 $ 62.0 $ 91.3 January 26, 2017 February 14, 2017 22.9 68.8 91.7 $ 52.2 $ 130.8 $ 183.0 The following table presents distributions paid by the OLP during the six months ended June 30, 2017, 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. Distribution Distribution Amount Paid to Amount Paid to Total Series ME (in millions) April 27, 2017 May 15, 2017 $ 12.7 $ 38.0 $ 50.7 January 26, 2017 February 14, 2017 14.2 42.7 56.9 $ 26.9 $ 80.7 $ 107.6

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Tables)	6 Months Ended
	Jun. 30, 2017
Commitments and Contingencies Disclosure [Abstract]
Material Components Underlying Estimated Loss For Cleanup, Remediation And Restoration	The components underlying our cumulative estimated loss for the cleanup, remediation and restoration associated with the Line 6B crude oil release, the majority of which have been paid, include the following: (in millions) Response personnel and equipment $ 547.3 Environmental consultants 224.3 Professional, regulatory, fines and penalties and other 443.4 Total $ 1,215.0

NET INCOME PER LIMITED PARTNE36

NET INCOME PER LIMITED PARTNER UNIT (Narrative) (Details) - shares	1 Months Ended	3 Months Ended		6 Months Ended
	Apr. 27, 2017	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
General Partners Capital Account Distribution Rate				2.00%
Preferred Stock [Member]
Anti-dilutive Preferred Units excluded (in shares)			43,201,310	43,201,310	43,201,310
Class E Units [Member]
Anti-dilutive Preferred Units excluded (in shares)			18,114,975	18,114,975	18,114,975
Class D Units [Member]
Anti-dilutive Preferred Units excluded (in shares)			66,100,000	66,100,000	66,100,000
Number of units waived (in shares)	66,100,000	66,100,000		66,100,000
Incentive Distribution Units [Member]
Number of units waived (in shares)	1,000	1,000		1,000
Class F Units [Member]
Number of units issued in transaction (in shares)	1,000	1,000		1,000

NET INCOME PER LIMITED PARTNE37

NET INCOME PER LIMITED PARTNER UNIT (Basic and Diluted Net Income Per Limited Partner Unit) (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Continuing operations:
Net income from continuing operations	[1]	$ 232.4	$ 240.7	$ 411.3	$ 443.4
Less: Net income attributable to: Noncontrolling interest		101.8	87.3	177.7	165.4
Series 1 preferred unit distributions		6.5	22.5	29	45
Accretion of discount on Series 1 preferred units		7.3	1.2	8.5	2.3
Net income attributable to general and limited partner interests in Enbridge Energy Partners, L.P. - continuing operations		116.8	129.7	196.1	230.7
Distributions:
Incentive distributions	[2]	(3.7)	(5.2)	(7.4)	(10.4)
Distributed earnings attributed to Class D and Class E units		(13.3)	(59.6)	(26.5)	(119.1)
Total distributed earnings attributed to our common units and i-units		(146.9)	(202.9)	(293.3)	(404.6)
Total distributed earnings		(160.2)	(262.5)	(319.8)	(523.7)
Overdistributed earnings		(43.4)	(132.8)	(123.7)	(293)
Discontinued operations:
Net loss	[1]	(35.4)	(63)	(56.8)	(93.3)
Less: Net loss attributable to Noncontrolling interest		(11.2)	(17)	(18.8)	(26.3)
Net loss attributable to general and limited partner interests in Enbridge Energy Partners, L.P. - discontinued operations		$ (24.2)	$ (46)	$ (38)	$ (67)
Weighted average common units and i-units outstanding		400.1	347.1	376.7	345.9
Basic and diluted earnings per unit:
Distributed earnings per common unit and i-unit - continuing operations	[3]	$ 0.37	$ 0.58	$ 0.78	$ 1.17
Overdistributed earnings per common unit and i-unit	[4]	(0.10)	(0.37)	(0.32)	(0.84)
Net income per common unit and i-unit (basic and diluted) - continuing operations	[5]	0.27	0.21	0.46	0.33
Net loss per common unit and i-unit (basic and diluted) - discontinued operations	[5]	(0.06)	(0.13)	(0.10)	(0.18)
Net income per common unit and i-unit (basic and diluted)		$ 0.21	$ 0.08	$ 0.36	$ 0.15
Class D and Class E Units [Member]
Distributions:
Distributed earnings attributed to Class D and Class E units		$ (6.4)	$ (49.1)	$ (12.7)	$ (98.2)
General Partner [Member]
Distributions:
Distributed earnings attributed to our General Partner		$ (3.2)	$ (5.3)	$ (6.4)	$ (10.5)
[1]	Certain costs that are not allocated to individual segments, including Other, interest expense, allowance for equity used during construction, and income taxes are included in the consolidated total.
[2]	For the three and six months ended June 30, 2017, Class D units and IDUs were not entitled to distributions as the wholly-owned subsidiary of our General Partner irrevocably waived its rights associated with the Class D and IDUs; for the three and six months ended June 30, 2017, incentive distributions were made to Class F units. For the three and six months ended June 30, 2016, incentive distributions were made to IDUs and Class D units.
[3]	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.
[4]	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.
[5]	For the three months ended June 30, 2017, there were no units excluded from the if-converted method of calculating diluted earnings per share. For the six months ended June 30, 2017 and the three and six months ended June 30, 2016, 43,201,310 anti-dilutive Preferred units and 18,114,975 anti-dilutive Class E units were excluded from the if-converted method of calculating diluted earnings per unit. For the six months ended June 30, 2017, 66,100,000 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. For the three and six months ended June 30, 2016, 66,100,000 anti-dilutive Class D units were excluded from the if-converted method of calculating diluted earnings per unit.

NET INCOME PER LIMITED PARTNE38

NET INCOME PER LIMITED PARTNER UNIT (Formula for Distributing Available Cash in Partnership Agreement) (Details)	1 Months Ended
	Apr. 27, 2017$ / shares
Minimum Quarterly Distribution [Member]
Portion of Quarterly Distribution Per Unit, maximum (in dollars per share)	$ 0.295
Percentage Distributed to General Partner (in percentage)	2.00%	[1]
Percentage Distributed to Limited Partners (in percentage)	98.00%
First Target Distribution [Member]
Portion of Quarterly Distribution Per Unit, maximum (in dollars per share)	$ 0.35
Portion of Quarterly Distribution Per Unit, minimum (in dollars per share)	$ 0.295
Percentage Distributed to General Partner (in percentage)	15.00%	[1]
Percentage Distributed to Limited Partners (in percentage)	85.00%
Over First Target Distribution [Member]
Portion of Quarterly Distribution Per Unit, maximum (in dollars per share)	$ 0.35
Percentage Distributed to General Partner (in percentage)	25.00%	[1]
Percentage Distributed to Limited Partners (in percentage)	75.00%
[1]	For distributions in excess of the Minimum Quarterly Distribution, this percentage includes both the General Partner’s distributions of 2% and the distribution to the Class F Units.

SEGMENT INFORMATION (Details)

SEGMENT INFORMATION (Details) - USD ($) $ in Millions		3 Months Ended				6 Months Ended
		Jun. 30, 2017		Jun. 30, 2016		Jun. 30, 2017		Jun. 30, 2016		Dec. 31, 2016	[7]
Operating revenues:
Transportation and other services	[1]	$ 596.5	[2]	$ 621.3	[3]	$ 1,201.2	[4]	$ 1,251	[5]
Total operating revenues	[1]	596.5	[2]	621.3	[3]	1,201.2	[4]	1,251	[5]
Operating expenses:
Environmental costs, net of recoveries	[1]	3.5		0.1		13.8		17
Operating and administrative	[1]	158.3		134.1		311.4		276.4
Power	[1]	66.4		59.7		140.9		132.5
Depreciation and amortization	[1]	108.3		104.9		217.1		206.3
Gain on sale of assets		51.5		0		62.1	[1]	0
Total costs and expenses	[1]	285		298.8		621.1		632.2
Operating income (loss)	[1]	311.5		322.5		580.1		618.8
Interest expense, net	[1]	(102.8)		(93.3)		(201.7)		(197.8)
Allowance for equity used during construction	[1]	10.7		13.3		21		25.6
Other income	[1]	11.4		0.2		11.4	[6]	0.4
Income from continuing operations before income tax expense benefit	[1]	230.8	[6]	242.7		410.8		447
Income tax expense benefit	[1]	1.6		(2)		0.5		(3.6)
Income from continuing operations	[1]	232.4		240.7		411.3		443.4
Income loss from discontinued operations	[1]	(35.4)		(63)		(56.8)		(93.3)
Net income	[1]	197		177.7		354.5		350.1
Less: Net income attributable to:
Assets		14,667.4				14,667.4				$ 18,110.1
Liquids [Member]
Operating revenues:
Transportation and other services		596.5	[2]	621.3	[3]	1,201.2	[4]	1,251	[5]
Total operating revenues		596.5	[2]	621.3	[3]	1,201.2	[4]	1,251	[5]
Operating expenses:
Environmental costs, net of recoveries		3.5		0.1		13.8		17
Operating and administrative		153.5		132.1		304		269.3
Power		66.4		59.7		140.9		132.5
Depreciation and amortization		108.3		104.9		217.1		206.3
Gain on sale of assets		(51.5)				(62.1)
Total costs and expenses		280.2		296.8		613.7		625.1
Operating income (loss)		316.3		324.5		587.5		625.9
Income loss from discontinued operations		0		0		0		0
Less: Net income attributable to:
Assets		14,661.5				14,661.5				13,030.5
Natural Gas [Member]
Operating revenues:
Transportation and other services	[8]	0	[2]	0	[3]	0	[4]	0	[5]
Total operating revenues	[8]	0	[2]	0	[3]	0	[4]	0	[5]
Operating expenses:
Environmental costs, net of recoveries	[8]	0		0		0		0
Operating and administrative	[8]	0		0		0		0
Power	[8]	0		0		0		0
Depreciation and amortization	[8]	0		0		0		0
Gain on sale of assets	[8]	0				0
Total costs and expenses	[8]	0		0		0		0
Operating income (loss)	[8]	0		0		0		0
Income loss from discontinued operations	[8]	(41.4)		(53.5)		(51.1)		(76.3)
Less: Net income attributable to:
Assets		0				0				0
Other [Member]
Operating revenues:
Transportation and other services		0	[2]	0	[3]	0	[4]	0	[5]
Total operating revenues		0	[2]	0	[3]	0	[4]	0	[5]
Operating expenses:
Environmental costs, net of recoveries		0		0		0		0
Operating and administrative		4.8		2		7.4		7.1
Power		0		0		0		0
Depreciation and amortization		0		0		0		0
Gain on sale of assets		0				0
Total costs and expenses		4.8		2		7.4		7.1
Operating income (loss)		(4.8)		(2)		(7.4)		(7.1)
Income loss from discontinued operations		6		$ (9.5)		(5.7)		$ (17)
Less: Net income attributable to:
Assets		$ 5.9				$ 5.9				$ 165.6
[1]	Certain costs that are not allocated to individual segments, including Other, interest expense, allowance for equity used during construction, and income taxes are included in the consolidated total.
[2]	There were no intersegment revenues for the three months ended June 30, 2017.
[3]	There were no intersegment revenues for the three months ended June 30, 2016.
[4]	There were no intersegment revenues for the six months ended June 30, 2017.
[5]	There were no intersegment revenues for the six months ended June 30, 2016.
[6]	Other income includes our equity income for our Liquids segment from our investment in the Bakken Pipeline System.
[7]	Comparative information excludes assets from discontinued operations. See Note 6 Dispositions and Discontinued Operations.
[8]	The operating results of our Natural Gas segment are included in discontinued operations as a result of the Midcoast sale to our General Partner. For further information refer to Note 6 Dispositions and Discontinued Operations.

REGULATORY MATTERS (Details)

REGULATORY MATTERS (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Net regulatory asset (liability) balance at beginning of period	$ (34.1)	$ 31.2	$ 11.9	$ 29.9
Current period (over) under recovery revenue adjustments	12	5.9	(27)	13.6
Amortization of prior year regulatory asset	(1.6)	(7.8)	(8.6)	(14.2)
Net regulatory asset (liability) balance at end of period	$ (23.7)	$ 29.3	$ (23.7)	$ 29.3

DISPOSITIONS AND DISCONTINUED41

DISPOSITIONS AND DISCONTINUED OPERATIONS (Narrative) (Details) - USD ($) $ in Millions	1 Months Ended		3 Months Ended		6 Months Ended
	Jun. 28, 2017	Mar. 31, 2017	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	[1]	Jun. 30, 2016
Gain (Loss) on Disposition of Assets			$ 51.5	$ 0	$ 62.1		$ 0
Proceeds from Sale of Property, Plant, and Equipment		$ 219.6	97.6
Increase (Decrease) in Partners' Capital	$ (2,130)
General Partners [Member]
Proceeds from Divestiture of Businesses	$ 2,260
Midcoast Operating L.P. [Member]
Equity Method Investment, Ownership Percentage	48.40%
Midcoast Holding LLC [Member]
Noncontrolling Interest, Ownership Percentage by Parent	100.00%
Midcoast Energy Partners L.P. [Member]
Business Combination, Consideration Transferred	$ 1,310
Aggregate Indebtedness	$ 953
Equity Method Investment, Ownership Percentage	51.90%
Asset Held For Sale At Carrying Value	$ 4,290
Noncontrolling Interest in Limited Partnerships	$ 296.6
General and Administrative Expense [Member]
Gain (Loss) on Disposition of Assets		$ 10.6	$ 51.5
[1]	Certain costs that are not allocated to individual segments, including Other, interest expense, allowance for equity used during construction, and income taxes are included in the consolidated total.

DISPOSITIONS AND DISCONTINUED42

DISPOSITIONS AND DISCONTINUED OPERATIONS (Consolidated Statements of Income) (Details) - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Operating revenues:
Operating revenues		$ 587.1	$ 427.6	$ 1,161.1	$ 859.5
Operating expenses:
Commodity costs		496.8	350.5	968.2	685.9
Operating and administrative		28.3	40	64.7	74.8
Depreciation and amortization		37.1	40	74.5	79.5
Asset impairment		0	10.6	0	10.6
Operating expenses, Total		622.9	488.5	1,218.2	948.8
Operating loss		(35.8)	(60.9)	(57.1)	(89.3)
Interest expense, net		(9.5)	(8.1)	(17.4)	(16.5)
Other income		10.4	6.5	18.6	13.9
Loss before income tax expense		(34.9)	(62.5)	(55.9)	(91.9)
Income tax expense		(0.5)	(0.5)	(0.9)	(1.4)
Net loss from discontinued operations	[1]	(35.4)	(63)	(56.8)	(93.3)
Commodity sales - nonaffiliate [Member]
Operating revenues:
Operating revenues		559.3	379.4	1,085	757.2
Commodity sales - affiliate [Member]
Operating revenues:
Operating revenues		3.3	1.4	9.4	6.6
Transportation and other services - nonaffiliate [Member]
Operating revenues:
Operating revenues		24.5	46.8	66.7	95.7
Commodity costs - affiliate [Member]
Operating expenses:
Commodity costs		25.7	8.5	42.1	21.2
Operating and administrative - affiliate [Member]
Operating expenses:
Operating and administrative		$ 35	$ 38.9	$ 68.7	$ 76.8
[1]	Certain costs that are not allocated to individual segments, including Other, interest expense, allowance for equity used during construction, and income taxes are included in the consolidated total.

DISPOSITIONS AND DISCONTINUED43

DISPOSITIONS AND DISCONTINUED OPERATIONS (Consolidated Statements of Financial Position) (Details) - USD ($) $ in Millions	Jun. 30, 2017	Dec. 31, 2016	Jun. 30, 2016	Dec. 31, 2015
Current assets related to discontinued operations:
Cash and cash equivalents	$ 0	$ 7.4	$ 8.1	$ 18
Restricted cash		11
Receivables, trade and other, net of allowance for doubtful accounts		8.5
Due from General Partner and affiliates		2.1
Accrued receivables		20.8
Inventory		28.1
Other current assets		60.7
Current assets related to discontinued operations, Total	0	138.6
Non-current assets related to discontinued operations:
Property, plant and equipment, net		4,114.5
Equity investments in joint ventures		360.7
Intangible assets, net		251.8
Other assets, net		48.3
Non-current assets related to discontinued operations, Total	0	4,775.3
Current liabilities related to discontinued operations:
Accounts payable and other		66.9
Due to General Partner and affiliates		38.8
Environmental liabilities		0.1
Accrued purchases		171.8
Property and other taxes payable		17.2
Interest payable		5
Current liabilities related to discontinued operations, Total	0	299.8
Non-current liabilities related to discontinued operations:
Long-term debt		818.5
Other long-term liabilities		25.8
Non-current liabilities related to discontinued operations, Total	$ 0	$ 844.3

VARIABLE INTEREST ENTITIES (Nar

VARIABLE INTEREST ENTITIES (Narrative) (Details) - USD ($) $ in Millions	1 Months Ended
	Apr. 27, 2017	Jun. 30, 2017
Enbridge Energy Limited Partnership [Member] | Variable Interest Entity, Primary Beneficiary [Member]
Variable Interest Entity [Line Items]
Ownership interest (in percentage)	25.00%
Enbridge Energy Limited Partnership [Member] | General Partner [Member]
Variable Interest Entity [Line Items]
Ownership interest (in percentage)	75.00%
MarEn Bakken Company LLC [Member] | Variable Interest Entity, Primary Beneficiary [Member]
Variable Interest Entity [Line Items]
Ownership interest (in percentage)	75.00%
Enbridge Holdings DakTex LLC [Member] | Variable Interest Entity, Primary Beneficiary [Member]
Variable Interest Entity [Line Items]
VIE assets		$ 1,544.3

EQUITY INVESTMENTS IN JOINT V45

EQUITY INVESTMENTS IN JOINT VENTURES (Narrative) (Details) - USD ($) $ in Millions	1 Months Ended	6 Months Ended
	Feb. 15, 2017	Jun. 30, 2017	Jun. 30, 2016
Reduction To Equity Earnings		$ 2.9
Income (Loss) from Equity Method Investments		$ 6.4	$ 0
Bakken Pipeline System [Member]
Noncontrolling Interest, Ownership Percentage by Parent	75.00%
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners	27.60%
Business Combination, Consideration Transferred	$ 1,500
Goodwill	14.4
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Finite-Lived Intangibles	$ 931.4
MarEn Bakken Company LLC [Member]
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners	25.00%

EQUITY INVESTMENTS IN JOINT V46

EQUITY INVESTMENTS IN JOINT VENTURES (Details) - USD ($) $ in Millions	Jun. 30, 2017	Dec. 31, 2016
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures	$ 1,563.1	$ 0
MarEn Bakken Company LLC [Member]
Equity Method Investment, Ownership Percentage	75.00%
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures	$ 1,563.1	$ 0

DEBT (Narrative) (Details)

DEBT (Narrative) (Details) - USD ($) $ in Millions	1 Months Ended	6 Months Ended
	Apr. 27, 2017	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016
Line of Credit Facility [Line Items]
Net borrowings under facilities		$ (865)	$ 630
Long-term Debt, Excluding Current Maturities		6,479.3		$ 7,065.9
Proceeds from Equity Method Investment, Distribution	$ 1,140
Fixed Rate Debt Obligations [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Fair Value Disclosure		6,200		6,500
Credit Facility [Member]
Line of Credit Facility [Line Items]
Net borrowings under facilities		865
Proceeds from Lines of Credit		8,100
Repayments of Lines of Credit		9,000
Line of Credit Facility, Remaining Borrowing Capacity		1,090
364-Day Credit Facility [Member]
Line of Credit Facility [Line Items]
Net borrowings under facilities		675.7
Proceeds from Lines of Credit	$ 400	4,600
Repayments of Lines of Credit		3,900
EUS 364-day Credit Facility [Member]
Line of Credit Facility [Line Items]
Net borrowings under facilities		329.4
Line of Credit Facility, Maximum Borrowing Capacity		$ 625
Line of Credit Facility, Expiration Date		Jun. 29, 2018
Proceeds from Lines of Credit		$ 443.6
Repayments of Lines of Credit		773
Commercial Paper And Revolvong Credit facility [Member]
Line of Credit Facility [Line Items]
Long-term Debt, Excluding Current Maturities		1,468.7		1,657.6
Uncommitted Demand Credit Facilities [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		175		175
Line of Credit Facility, Remaining Borrowing Capacity		$ 87.6		$ 70.9

DEBT (Credit Facility) (Details

DEBT (Credit Facility) (Details) - Enbridge Energy Partners, L.P. [Member] $ in Millions	6 Months Ended
	Jun. 30, 2017USD ($)
Total Facilities	$ 2,625
Draws	1,535	[1]
Available	$ 1,090
Maximum [Member]
Maturity Dates	2,020
Minimum [Member]
Maturity Dates	2,019
[1]	Includes facility draws, letters of credit and commercial paper issuances that are back-stopped by the credit facility and excludes the EUS 364-day Credit Facility

NONCONTROLLING INTERESTS (Narra

NONCONTROLLING INTERESTS (Narrative) (Details) - USD ($) $ in Millions	1 Months Ended		6 Months Ended
	Apr. 27, 2017	Jan. 26, 2017	Jun. 30, 2017	Jun. 30, 2016
Acquisition of noncontrolling interest in subsidiary		$ 360
Proceeds from Noncontrolling Interests			$ 1,285	$ 81.9
General Partner [Member]
Noncontrolling Interest, Increase from Sale of Parent Equity Interest			$ 0.8	$ 0
Proceeds from Noncontrolling Interests	$ 1,140
Enbridge Holdings LLC [Member] | General Partner [Member]
Equity Method Investment, Ownership Percentage	75.00%
Noncontrolling Interest, Ownership Percentage by Parent	25.00%
Eastern Access project [Member]
Joint Funding Arrangement, Additional Acquisition Percentage		15.00%
Noncontrolling Interest, Ownership Percentage by Parent			60.00%
Acquisition of noncontrolling interest in subsidiary		$ 360
Ownership Interest In Affiliate Of Partnership			40.00%
Line 3 Replacement [Member]
Joint Funding Arrangement, Funding Percentage		1.00%
Joint Funding Arrangement, Parent, Percentage		99.00%
Acquisition of noncontrolling interest in subsidiary		$ 39.1
Noncontrolling Interest, Increase from Sale of Parent Equity Interest		$ 411

NONCONTROLLING INTERESTS (Conso

NONCONTROLLING INTERESTS (Consolidated statements of financial position) (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Net income	$ 90.6	$ 70.3	$ 158.9	$ 139.1
Eastern Access Interests [Member]
Net income	36.8	53.2	76.3	104.7
U.S. Mainline Expansion Interests [Member]
Net income	35.8	34.1	69.2	60.7
North Dakota Pipeline Company Interests [Member]
Net income	18.4	0	16.8	0
Line 3 Replacement Interests [Member]
Net income	6	0	10.6	0
Enbridge Holdings DakTex LLC Interests [Member]
Net income	4.8	0	4.8	0
Midcoast Energy Partners, L.P. - Discontinued Operations [Member]
Net income	$ (11.2)	$ (17)	$ (18.8)	$ (26.3)

PARTNERS' CAPITAL (Narrative) (

PARTNERS' CAPITAL (Narrative) (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended	3 Months Ended	6 Months Ended
	Apr. 27, 2017	Jun. 30, 2017	Jun. 30, 2017	Dec. 31, 2016
Unamortized Beneficial Conversion Feature Discount	$ 8.5
Increase In General Partners' Capital Account	$ 2,700
Incentive Distributions Description		The Class F units are entitled to (i) 13% of all distributions of available cash in excess of $0.295 per unit, but less than or equal to $0.35 per unit, and (ii) 23% of all distributions of available cash in excess of $0.35 per unit.
General Partner [Member]
Allocations from capital accounts			$ 11.9
Incentive Distribution Units [Member]
Number of units waived (in shares)	1,000	1,000	1,000
Class D Units [Member]
Number of units waived (in shares)	66,100,000	66,100,000	66,100,000
I Units [Member]
Allocations from capital accounts			$ 39.9
Limited Partners' Capital Account, Units Issued		85,620,914	85,620,914	81,857,168
Series 1 Preferred units [Member]
Stock Redeemed or Called During Period, Value	$ 1,200
General Partner Distributions	$ 357.3
Common Class F [Member]
Limited Partners' Capital Account, Units Issued	1,000	1,000	1,000
Limited Partners' Contributed Capital	$ 263
Common Class A [Member]
Stock Issued During Period, Value, New Issues	$ 1,200
Shares Issued, Price Per Share	$ 18.66
Fair value Per Share	$ 18.57
Common Class A [Member] | General Partner [Member]
Stock Issued During Period, Shares, New Issues	64,308,682	64,308,682	64,308,682

DERIVATIVE FINANCIAL INSTRUME52

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Derivative Instruments in Statement of Financial Position) (Details) - USD ($) $ in Millions		Jun. 30, 2017	Dec. 31, 2016
Derivatives, Fair Value [Line Items]
Net Total	[1]	$ (181.6)	$ (166.7)
Other Current Assets [Member]
Derivatives, Fair Value [Line Items]
Net Total		1.2	0
Accounts Payable and Other [Member]
Derivatives, Fair Value [Line Items]
Net Total		(159)	(145.4)
Other Long-term Liabilities [Member]
Derivatives, Fair Value [Line Items]
Net Total		$ (23.8)	$ (21.3)
[1]	As determined by nationally-recognized statistical ratings organizations.

DERIVATIVE FINANCIAL INSTRUME53

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Derivative Balances by Counterparty Credit Quality) (Details) - USD ($) $ in Millions		Jun. 30, 2017	Dec. 31, 2016
Derivative [Line Items]
Net Total	[1]	$ (181.6)	$ (166.7)
AA Rating [Member]
Derivative [Line Items]
Net Total	[1]	(82.6)	(79.2)
A Rating [Member]
Derivative [Line Items]
Net Total	[1]	(63.6)	(58.4)
Lower than A [Member]
Derivative [Line Items]
Net Total	[1]	$ (35.4)	$ (29.1)
[1]	As determined by nationally-recognized statistical ratings organizations.

DERIVATIVE FINANCIAL INSTRUME54

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Credit Concentrations in Industry Sectors) (Details) - USD ($) $ in Millions		Jun. 30, 2017	Dec. 31, 2016
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Net Total	[1]	$ (181.6)	$ (166.7)
United States Financial Institutions And Investment Banking Entities [Member]
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Credit concentrations		(131.3)	(121.7)
Non-United States financial institutions [Member]
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Credit concentrations		$ (50.3)	$ (45)
[1]	As determined by nationally-recognized statistical ratings organizations.

DERIVATIVE FINANCIAL INSTRUME55

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Effect of Derivative Instruments on Consolidated Statements of Financial Position) (Details) - USD ($) $ in Millions		Jun. 30, 2017	Dec. 31, 2016
Derivatives, Fair Value [Line Items]
Asset Derivatives	[1]	$ 1.2	$ 0
Liability Derivatives	[1]	(182.8)	(166.7)
Derivatives Designated as Hedging Instruments [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	[1]	0	0
Liability Derivatives	[1]	(182.8)	(165.1)
Derivatives Designated as Hedging Instruments [Member] | Accounts Payable and Other [Member] | Interest Rate Contracts [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	[1]	0	0
Liability Derivatives	[1]	(159)	(144)
Derivatives Designated as Hedging Instruments [Member] | Other Long-term Liabilities [Member] | Interest Rate Contracts [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	[1]	0	0
Liability Derivatives	[1]	(23.8)	(21.1)
Derivatives Not Designated as Hedging Instruments [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	[1]	1.2	0
Liability Derivatives	[1]	0	(1.6)
Derivatives Not Designated as Hedging Instruments [Member] | Other Current Assets [Member] | Commodity Contracts [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	[1]	1.2	0
Liability Derivatives	[1]	0	0
Derivatives Not Designated as Hedging Instruments [Member] | Other Assets, Net [Member] | Commodity Contracts [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	[1]	0	0
Liability Derivatives	[1]	0	(1.4)
Derivatives Not Designated as Hedging Instruments [Member] | Accounts Payable and Other [Member] | Commodity Contracts [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	[1]	0	0
Liability Derivatives	[1]	$ 0	$ (0.2)
[1]	Includes items currently designated as hedging instruments. Excludes the portion of de-designated hedges which may have a component remaining in accumulated other comprehensive income, or AOCI.

DERIVATIVE FINANCIAL INSTRUME56

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Effect of Derivative Instruments on Consolidated Statements of Income and AOCI) (Details) - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in AOCI on Derivative (Effective Portion)		$ (17.6)	$ (49.6)	$ (15.8)	$ (135.2)
Amount of Gain (Loss) Reclassified from AOCI to Earnings (Effective Portion)		(10.4)	(9.8)	(20.7)	(19.8)
Amount of Gain (Loss) Recognized in Earnings on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)	[1]	(1.6)	(1.5)	(1.9)	(3.4)
Interest Expense [Member] | Interest Rate Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in AOCI on Derivative (Effective Portion)		(17.6)	(49.6)	(15.8)	(135.2)
Amount of Gain (Loss) Reclassified from AOCI to Earnings (Effective Portion)		(10.4)	(9.8)	(20.7)	(19.9)
Amount of Gain (Loss) Recognized in Earnings on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)	[1]	$ (1.6)	$ (1.5)	$ (1.9)	(3.4)
Cost of Sales [Member] | Commodity Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in AOCI on Derivative (Effective Portion)					0
Amount of Gain (Loss) Reclassified from AOCI to Earnings (Effective Portion)					0.1
Amount of Gain (Loss) Recognized in Earnings on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)	[1]				$ 0
[1]	Includes only the ineffective portion of derivatives that are designated as hedging instruments and does not include net gains or losses associated with derivatives that do not qualify for hedge accounting treatment.

DERIVATIVE FINANCIAL INSTRUME57

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Components of Accumulated Other Comprehensive Income) (Details) - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance				$ (339.3)
Net other comprehensive income (loss)		$ (9)	$ (41.7)	0.4	$ (119.3)
Ending Balance		(338.9)		(338.9)
Cash Flow Hedge [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning Balance				(339.3)	(370)
Other comprehensive loss before reclassifications				(20.3)	(139.1)
Amounts reclassified from AOCI	[1]			20.7	19.8
Net other comprehensive income (loss)				0.4	(119.3)
Ending Balance		$ (338.9)	$ (489.3)	$ (338.9)	$ (489.3)
[1]	For additional details on the amounts reclassified from AOCI, reference the Reclassifications from Accumulated Other Comprehensive Income table below.

DERIVATIVE FINANCIAL INSTRUME58

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Reclassifications from Accumulated Other Comprehensive Income) (Details) - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Interest Rate Contracts	[1]	$ 102.8	$ 93.3	$ 201.7	$ 197.8
Total Reclassifications from AOCI	[1]	197	177.7	354.5	350.1
Reclassification out of AOCI [Member] | Accumulated Net (Gain) Loss from Designated or Qualifying Cash Flow Hedges [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Total Reclassifications from AOCI		10.4	9.8	20.7	19.9
Interest Rate Contract [Member] | Reclassification out of AOCI [Member] | Accumulated Net (Gain) Loss from Designated or Qualifying Cash Flow Hedges [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Interest Rate Contracts	[2]	$ 10.4	$ 9.8	$ 20.7	$ 19.9
[1]	Certain costs that are not allocated to individual segments, including Other, interest expense, allowance for equity used during construction, and income taxes are included in the consolidated total.
[2]	Loss reported within “Interest expense, net” in the consolidated statements of income.

DERIVATIVE FINANCIAL INSTRUME59

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Effect of Derivative Instruments on Consolidated Statements of Income) (Details) - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Commodity Costs [Member] | Commodity Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain on Settlement of Derivative Instruments		$ 0.4	$ 1.2	$ 0.4	$ 3.7
Derivatives Not Designated As Hedging Instruments [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain or (Loss) Recognized in Earnings	[1],[2]	1.4	(3.9)	3.1	(3.1)
Derivatives Not Designated As Hedging Instruments [Member] | Transportation And Other Services Revenue [Member] | Commodity Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain or (Loss) Recognized in Earnings	[1],[2],[3]	$ 1.4	$ (3.9)	$ 3.1	$ (3.1)
[1]	Does not include settlements associated with derivative instruments that settle through physical delivery.
[2]	Includes only net gains or losses associated with those derivatives that do not receive hedge accounting treatment and does not include the ineffective portion of derivatives that are designated as hedging instruments.
[3]	Includes settlement gains of $0.4 million and $1.2 million for the three months ended June 30, 2017 and 2016, respectively and settlement gains of $0.4 million and $3.7 million for the six months ended June 30, 2017 and 2016, respectively.

DERIVATIVE FINANCIAL INSTRUME60

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Offsetting of Financial Assets and Derivative Assets) (Details) - USD ($) $ in Millions		Jun. 30, 2017	Dec. 31, 2016
Derivatives
Gross Amount of Recognized Assets	[1]	$ 1.2	$ 0
Gross Amount Offset in the Statement of Financial Position		0	0
Net Amount of Assets Presented in the Statement of Financial Position		1.2	0
Gross Amount Not Offset in the Statement of Financial Position		0	0
Net Amount		$ 1.2	$ 0
[1]	Includes items currently designated as hedging instruments. Excludes the portion of de-designated hedges which may have a component remaining in accumulated other comprehensive income, or AOCI.

DERIVATIVE FINANCIAL INSTRUME61

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Offsetting of Financial Liabilities and Derivative Liabilities) (Details) - USD ($) $ in Millions	Jun. 30, 2017	Dec. 31, 2016
Derivatives
Gross Amount of Recognized Liabilities	$ (182.8)	$ (166.7)
Gross Amount Offset in the Statement of Financial Position	0	0
Net Amount of Liabilities Presented in the Statement of Financial Position	(182.8)	(166.7)
Gross Amount Not Offset in the Statement of Financial Position	0	0
Net Amount	$ (182.8)	$ (166.7)

DERIVATIVE FINANCIAL INSTRUME62

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Inputs to Fair Value Derivative Instruments) (Details) - USD ($) $ in Millions		Jun. 30, 2017	Dec. 31, 2016
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total	[1]	$ (181.6)	$ (166.7)
Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total		0	0
Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total		(181.6)	(166.7)
Commodity Contracts - Financial [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Interest rate contracts		1.2	(1.6)
Commodity Contracts - Financial [Member] | Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Interest rate contracts		0	0
Commodity Contracts - Financial [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Interest rate contracts		1.2	(1.6)
Interest Rate Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Interest rate contracts		(182.8)	(165.1)
Interest Rate Contracts [Member] | Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Interest rate contracts		0	0
Interest Rate Contracts [Member] | Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Interest rate contracts		$ (182.8)	$ (165.1)
[1]	As determined by nationally-recognized statistical ratings organizations.

DERIVATIVE FINANCIAL INSTRUME63

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Fair Value Measurements of Commodity Derivatives) (Details) $ in Millions		6 Months Ended
		Jun. 30, 2017USD ($)$ / Barrel-bblbbl	Dec. 31, 2016USD ($)
Fair Value
Asset	[1]	$ 1.2	$ 0
Liability		(182.8)	(166.7)
Swaps - Portion of Contracts Maturing in 2017 - Receive Variable/Pay Fixed - Crude Oil [Member]
Fair Value
Asset	[2]	1.2	0
Liability	[2]	$ 0	$ (1.6)
Swaps - Portion of Contracts Maturing in 2017 - Receive Fixed/Pay Variable - Crude Oil [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	[3]	220,432
Swaps - Portion of Contracts Maturing in 2017 - Receive Fixed/Pay Variable - Crude Oil [Member] | Receive [Member]
Derivative [Line Items]
Wtd. Average Price | $ / Barrel-bbl	[4]	52.14
Swaps - Portion of Contracts Maturing in 2017 - Receive Fixed/Pay Variable - Crude Oil [Member] | Pay [Member]
Derivative [Line Items]
Wtd. Average Price | $ / Barrel-bbl	[4]	46.74
[1]	Includes items currently designated as hedging instruments. Excludes the portion of de-designated hedges which may have a component remaining in accumulated other comprehensive income, or AOCI.
[2]	The fair value is determined based on quoted market prices at June 30, 2017 and December 31, 2016, respectively, discounted using the swap rate for the respective periods to consider the time value of money. Fair values exclude credit valuation adjustment gains of nil at June 30, 2017 and December 31, 2016, as well as cash collateral received.
[3]	Volumes of crude oil are measured in Bbl.
[4]	Weighted-average prices received and paid are in $/Bbl for crude oil.

DERIVATIVE FINANCIAL INSTRUME64

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Interest Rate Derivatives) (Details) - Interest Rate Swap [Member] - Derivatives in Cash Flow Hedging Relationships [Member] - USD ($) $ in Millions		6 Months Ended	12 Months Ended
		Jun. 30, 2017	Dec. 31, 2016
Derivative [Line Items]
Credit Valuation Adjustments		$ 0.6	$ 1.2
Contracts Maturing In 2017 [Member]
Derivative [Line Items]
Notional		$ 500
Average Fixed Rate (in percentage)	[1]	2.21%
Fair Value	[2]	$ 0	(0.3)
Contracts Maturing In 2018 [Member]
Derivative [Line Items]
Notional		$ 810
Average Fixed Rate (in percentage)	[1]	2.24%
Fair Value	[2]	$ (4)	(9.4)
Contracts Maturing In 2019 [Member]
Derivative [Line Items]
Notional		$ 620
Average Fixed Rate (in percentage)	[1]	2.96%
Fair Value	[2]	$ (8)	(7.3)
Contracts Settling Prior to Maturity - 2017 Pre Issuance Hedges [Member]
Derivative [Line Items]
Notional		$ 1,000
Average Fixed Rate (in percentage)	[1]	4.07%
Fair Value	[2]	$ (153.1)	(136.2)
Contracts Settling Prior to Maturity - 2018 Pre Issuance Hedges [Member]
Derivative [Line Items]
Notional		$ 350
Average Fixed Rate (in percentage)	[1]	3.08%
Fair Value	[2]	$ (18.3)	$ (13.1)
[1]	Interest rate derivative contracts are based on the one-month or three-month London Interbank Offered Rate, or LIBOR.
[2]	The fair value is determined from quoted market prices at June 30, 2017 and December 31, 2016, respectively, discounted using the swap rate for the respective periods to consider the time value of money. Fair values are presented in millions of dollars and exclude credit valuation adjustment gains of approximately $0.6 million and $1.2 million at June 30, 2017 and December 31, 2016, respectively.

DERIVATIVE FINANCIAL INSTRUME65

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Narrative) (Details) - USD ($) $ in Millions	6 Months Ended		12 Months Ended
	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016
Derivative [Line Items]
Derivative instruments income statement location of gain loss reclassified from accumulated other comprehensive income	$ 207.9		$ 223.3
Cash flow hedge gain (loss) to be reclassified within three months	45	$ 45
Expected value of cash collateral or letters of credit if credit rating is downgraded	30.9
Letters of credit provided on derivatives	$ 152.5		$ 119.5

SUPPLEMENTAL CASH FLOWS INFOR66

SUPPLEMENTAL CASH FLOWS INFORMATION (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2017	Jun. 30, 2016
Total capital expenditures (excluding "Investments in joint ventures")	$ 207.3	$ 499.6
Decrease in construction payables	21.6	178.5
Cash used for additions to property, plant and equipment	$ 228.9	$ 678.1

RELATED PARTY TRANSACTIONS (Joi

RELATED PARTY TRANSACTIONS (Joint Funding Arrangement Discussions) (Details) - USD ($) $ in Millions	1 Months Ended	6 Months Ended
	Jan. 26, 2017	Jun. 30, 2017	Jun. 30, 2016
Proceeds from noncontrolling interests		$ 1,285	$ 81.9
Acquisition of noncontrolling interest in subsidiary		360
Line 3 Replacement [Member]
Acquisition of noncontrolling interest in subsidiary		39.1
Noncontrolling Interest, Increase from Sale of Parent Equity Interest	$ 411
Joint Funding Arrangement, Parent, Percentage	99.00%
Partners Capital Account, Contributions	$ 450.1
Option to increase general partnership interest percentage (in percentage)	40.00%
Contributions to noncontrolling interest		$ 100
Joint funding arrangement noncontrolling interest (in percentage)	1.00%
Eastern Access Pipeline [Member]
Additional Acquisition Percentages	15.00%
Acquisition of noncontrolling interest in subsidiary	$ 360
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest	25.00%	40.00%
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest	75.00%	60.00%
Contributions to noncontrolling interest		$ 5.6	7.2
US Mainline Expansion Interests [Member]
Noncontrolling Interest, Ownership Percentage by Parent		75.00%
Ownership interest in affiliate of Partnership (in percentage)		25.00%
Proceeds from noncontrolling interests		$ 26	$ 42.8
Additional Acquisition Percentages		15.00%

RELATED PARTY TRANSACTIONS (Sal

RELATED PARTY TRANSACTIONS (Sale of AR) (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended		6 Months Ended
	Apr. 27, 2017	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016	Dec. 31, 2016
Net value of receivables sold		$ 0	$ 428.1	$ 458	$ 894.4
Proceeds from Sale of Receivables			$ 427.9	$ 468.9	$ 894
Sold Receivables that have not been collected at the balance sheet date.						$ 155.5
Proceed From Termination of Receivables Agreement	$ 5

RELATED PARTY TRANSACTIONS (Dis

RELATED PARTY TRANSACTIONS (Distributions by Affiliates) (Details) - USD ($) $ in Millions	1 Months Ended		6 Months Ended
	May 15, 2017	Feb. 14, 2017	Jun. 30, 2017
Midcoast Energy Partners [Member] | First Quarter Distribution [Member]
Distribution declaration date			Jan. 26, 2017
Distribution payment date			Feb. 14, 2017
Amount paid to parent		$ 8.9
Amount paid to noncontrolling interest		7.6
Total amount of distribution paid		16.5
Series EA [Member]
Amount paid to parent			$ 52.2
Amount paid to noncontrolling interest			130.8
Total amount of distribution paid			$ 183
Series EA [Member] | First Quarter Distribution [Member]
Distribution declaration date			Jan. 26, 2017
Distribution payment date			Feb. 14, 2017
Amount paid to parent		22.9
Amount paid to noncontrolling interest		68.8
Total amount of distribution paid		91.7
Series EA [Member] | Second Quarter Distribution [Member]
Distribution declaration date			Apr. 27, 2017
Distribution payment date			May 15, 2017
Amount paid to parent	$ 29.3
Amount paid to noncontrolling interest	62
Total amount of distribution paid	91.3
U.S. Mainline Expansion Interests [Member]
Amount paid to parent			$ 26.9
Amount paid to noncontrolling interest			80.7
Total amount of distribution paid			$ 107.6
U.S. Mainline Expansion Interests [Member] | First Quarter Distribution [Member]
Distribution declaration date			Jan. 26, 2017
Distribution payment date			Feb. 14, 2017
Amount paid to parent		14.2
Amount paid to noncontrolling interest		42.7
Total amount of distribution paid		$ 56.9
U.S. Mainline Expansion Interests [Member] | Second Quarter Distribution [Member]
Distribution declaration date			Apr. 27, 2017
Distribution payment date			May 15, 2017
Amount paid to parent	12.7
Amount paid to noncontrolling interest	38
Total amount of distribution paid	$ 50.7

RELATED PARTY TRANSACTIONS (Nar

RELATED PARTY TRANSACTIONS (Narrative) (Details) - USD ($) $ in Millions	1 Months Ended		6 Months Ended	12 Months Ended
	Apr. 27, 2017	Feb. 15, 2017	Jun. 30, 2017	Dec. 31, 2016
Related Party Transaction [Line Items]
Long-term Line of Credit			$ 420.6
EUS Credit Agreement [Member]
Related Party Transaction [Line Items]
Repayments of Lines of Credit		$ 1,500
Bakken Pipeline Systems [Member]
Related Party Transaction [Line Items]
Noncontrolling Interest, Ownership Percentage by Parent	75.00%
Ownership Interest In Affiliate Of Partnership	25.00%
Additional Acquisitions Percentages	20.00%
General Partner [Member]
Related Party Transaction [Line Items]
Proceeds from Related Party Debt	$ 1,140
Enbridge Inc., Credit Agreement [Member]
Related Party Transaction [Line Items]
Term of debt instrument			364 days
Line of Credit Facility, Expiration Date			Jul. 23, 2019
Maximum borrowing capacity of line of credit			$ 750
Construction Project Work Force Cost Transactions [Member]
Related Party Transaction [Line Items]
Related party expenses			$ 4.8	$ 28.4

COMMITMENTS AND CONTINGENCIES71

COMMITMENTS AND CONTINGENCIES (Material Components Underlying Estimated Loss for Cleanup, Remediation and Restoration) (Details) $ in Millions	Jun. 30, 2017USD ($)
Estimated total loss of crude oil release	$ 1,215
Response Personnel and Equipment [Member]
Estimated total loss of crude oil release	547.3
Environmental Consultants [Member]
Estimated total loss of crude oil release	224.3
Professional, Regulatory, Fines and Penalties and Other [Member]
Estimated total loss of crude oil release	$ 443.4

COMMITMENTS AND CONTINGENCIES72

COMMITMENTS AND CONTINGENCIES (Narrative) (Details) $ in Millions	1 Months Ended	6 Months Ended
	Jun. 15, 2017USD ($)	Jun. 30, 2017USD ($)	Jun. 30, 2016USD ($)	Dec. 31, 2016USD ($)	Mar. 31, 2015USD ($)	Mar. 31, 2013USD ($)	Jul. 26, 2010Milesbbl
Site Contingency [Line Items]
Remaining liabilities		$ 23.6		$ 99.8
Accrual for environmental loss contingencies		55.3		50.8
Costs paid associated with crude oil release		70.4	$ 12.9
Government fines and penalties	$ 67.8
Aggregate insurance coverage limit		650
Insurance recoveries, since inception		547
Remaining aggregate insurance coverage						$ 145
Remaining expected insurance recoveries		103			$ 85
Estimated total loss of crude oil release		1,215
Disputes with Insurers for Which Partial Payment Was Received [Member]
Site Contingency [Line Items]
Insurance recoveries		42
Dispute with One Particular Insurer [Member]
Site Contingency [Line Items]
Remaining expected insurance recoveries		85
Liability Program [Member]
Site Contingency [Line Items]
Aggregate insurance coverage limit		940
Line 6A Crude Oil Release [Member]
Site Contingency [Line Items]
Government fines and penalties	1
Consent Decree [Member]
Site Contingency [Line Items]
Accrual for environmental loss contingencies	110
Civil Penalties [Member]
Site Contingency [Line Items]
Government fines and penalties	61
Past Removal Costs and Interest [Member]
Site Contingency [Line Items]
Government fines and penalties	$ 5.8
Line Six Marshall Leak [Member]
Site Contingency [Line Items]
Remaining liabilities		67.9		$ 138.8
Crude oil released (in barrels) | bbl							20,000
Area Impacted By Crude Oil Release | Miles							38
Government fines and penalties		68.5
Estimated total loss of crude oil release		$ 1,200

SUBSEQUENT EVENTS (Details)

SUBSEQUENT EVENTS (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended	3 Months Ended		6 Months Ended
	Jul. 28, 2017	Jun. 30, 2017	Jun. 30, 2016	Jun. 30, 2017	Jun. 30, 2016
Subsequent Event [Line Items]
Amount of distribution		$ 146.9	$ 202.9	$ 293.3	$ 404.6
Percentage of Distribution Retained				2.00%
Subsequent Event [Member]
Subsequent Event [Line Items]
Cash distributions paid per limited partner unit outstanding (in dollars per share)	$ 0.35
Cash Available for Distribution	$ 160.2
Distribution payment date	Aug. 14, 2017
Distribution record date	Aug. 7, 2017
Distribution declaration date	Jul. 28, 2017
Total amount of distribution paid	$ 129.6
Subsequent Event [Member] | I Units [Member]
Subsequent Event [Line Items]
Amount of distribution	30
Amount paid to parent	0.6
Series EA Interests [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Amount paid to parent	49.8
Amount paid to the noncontrolling interest	$ 33.2
Distribution declaration date	Jul. 28, 2017
Series ME Interests [Member]
Subsequent Event [Line Items]
Amount paid to parent				$ 26.9
Amount paid to the noncontrolling interest				80.7
Total amount of distribution paid				$ 107.6
Series ME Interests [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Amount paid to parent	$ 41.3
Amount paid to the noncontrolling interest	$ 13.8
Distribution declaration date	Jul. 28, 2017