Enbridge Energy Partners 10-K 16 Feb 18 2017 FY Annual report Financial data

Document And Entity Information

Document And Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2017	Feb. 13, 2018	Jun. 30, 2017
Document And Entity Information [Abstract]
Entity Registrant Name	ENBRIDGE ENERGY PARTNERS LP
Trading Symbol	EEP
Entity Central Index Key	880,285
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-K
Document Period End Date	Dec. 31, 2017
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Common Stock, Shares Outstanding		326,517,110
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 5,223,268,544

CONSOLIDATED STATEMENTS OF INCO

CONSOLIDATED STATEMENTS OF INCOME - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating revenues:
Revenues	$ 2,428	$ 2,516	$ 2,303
Operating expenses:
Power	290	277	260
Depreciation and amortization	442	427	378
Gain on sale of assets	(74)	0	0
Asset impairment	0	757	63
Total operating expenses	1,307	2,035	1,339
Operating income	1,121	481	964
Interest expense, net	(525)	(413)	(292)
Allowance for equity used during construction	47	46	70
Other income	57	1	0
Income before income taxes	700	115	742
Income tax benefit (expense)	8	1	(3)
Net income (loss) from continuing operations	708	116	739
Loss from discontinued operations, net of tax	(57)	(157)	(285)
Net income (loss)	651	(41)	454
Net income attributable to noncontrolling interests	(369)	(26)	(221)
Series 1 preferred unit distributions	(29)	(90)	(90)
Accretion of discount on Series 1 preferred units	(8)	(5)	(11)
Net income (loss) - controlling interests	245	(162)	132
Net income (loss) attributable to common units and i-units:
Income (loss) from continuing operations	237	(268)	119
Loss from discontinued operations	(37)	(109)	(204)
Net income (loss) attributable to common units and i-units	$ 200	$ (377)	$ (85)
Net income (loss) per common unit and i-unit (basic and diluted):
Income (loss) from continuing operations (in dollars per share)	$ 0.60	$ (0.77)	$ 0.35
Loss from discontinued operations (in dollars per share)	(0.10)	(0.31)	(0.60)
Net income per common unit and i-unit (in dollars per share)	$ 0.50	$ (1.08)	$ (0.25)
Weighted average common units and i-units outstanding (basic and diluted) (in shares)	400	348	339
Distributions paid per limited partner unit (in dollars per share)	$ 1.633	$ 2.332	$ 2.306
Third Party [Member]
Operating revenues:
Revenues	$ 2,316	$ 2,409	$ 2,173
Operating expenses:
Operating and administrative	355	283	344
Affiliated Entity [Member]
Operating revenues:
Revenues	112	107	130
Operating expenses:
Operating and administrative	$ 294	$ 291	$ 294

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ 651	$ (41)	$ 454
Other comprehensive income (loss), net of tax
Change in cash flow hedges	(68)	(8)	(186)
Reclassification to earnings on cash flow hedges	208	39	22
Other comprehensive income (loss), net of tax	140	31	(164)
Comprehensive income (loss)	791	(10)	290
Comprehensive income attributable to noncontrolling interests	(369)	(26)	(221)
Series 1 preferred unit distributions	(29)	(90)	(90)
Accretion of discount on Series 1 preferred units	(8)	(5)	(11)
Other comprehensive loss allocated to noncontrolling interest	0	0	6
Comprehensive income (loss) attributable to common units and i-units	$ 385	$ (131)	$ (26)

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating activities:
Net income from continuing operations		$ 708	$ 116	$ 739
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		442	427	378
Changes in unrealized (gain) loss on derivative instruments, net		(47)	16	(83)
Environmental costs, net of recoveries		14	10	6
Distributions from investments in joint venture		52	0	0
Equity earnings from investments in joint venture		(52)	0	0
Gain on sale of assets		(74)	0	0
Allowance for equity used during construction		(47)	(46)	(70)
Amortization of debt issuance and hedging costs		37	40	17
Asset impairment		0	757	63
Other		(4)	(1)	21
Settlement of interest rate derivatives		0	0	(238)
Changes in operating assets and liabilities		(358)	(130)	(9)
Net cash provided by operating activities		671	1,189	824
Net cash (used in) provided by discontinued operations		(171)	227	207
Investing activities:
Capital expenditures		(606)	(1,024)	(1,926)
Changes in restricted cash		13	3	37
Proceeds from the sale of assets		329	0	0
Proceeds from the sale of Midcoast assets		1,310	0	0
Investments in joint venture		(1,598)	0	0
Distributions from investments in joint ventures in excess of cumulative earnings		32	0	0
Asset acquisitions		0	0	(41)
Other		(4)	(9)	1
Net cash used in investing activities		(524)	(1,030)	(1,929)
Net cash used in discontinued operations		(14)	(37)	(197)
Financing activities:
Redemption of Series 1 preferred units		(1,200)	0	0
Payment of Series 1 preferred unit dividends		(357)	0	0
Net proceeds from Class A issuances		1,225	0	295
Distributions to partners		(605)	(798)	(771)
Repayments to General Partner and affiliates		(1,640)	0	(306)
Repayments of Debt		0	(300)	0
Borrowings from General Partner and affiliates		1,500	750	0
Net (repayments) borrowings under credit facilities		(1,115)	155	(50)
Net commercial paper borrowings (repayments)		910	66	(286)
Acquisition of noncontrolling interest in subsidiary		(360)	0	0
Sale of noncontrolling interest in subsidiary		450	0	0
Contributions from noncontrolling interests		1,485	99	822
Distributions to noncontrolling interest		(504)	(159)	(242)
Proceeds from issuance of debt, net of discounts		0	0	1,600
Debt issuance costs		0	0	(25)
Other		(2)	(1)	0
Net cash provided by (used in) financing activities		(213)	(188)	1,037
Net cash (used in) provided by discontinued operations		229	(201)	8
Net decrease in cash and cash equivalents		(66)	(29)	(68)
Cash disposed as part of the Midcoast sale		(51)	0	0
Cash and cash equivalents at beginning of year - continuing operations		101	130	198
Cash and cash equivalents at beginning of year - discontinued operations		7	18	0
Cash and cash equivalents at end of year - continuing operations		35	101	130
Cash and cash equivalents at end of year - discontinued operations		0	7	18
Supplementary cash flow information
Interest paid	[1]	543	371	350
Property, plant and equipment non-cash accruals	[1]	$ 79	$ 100	$ 311
[1]	No income taxes were paid for the year ending December 31, 2017, 2016, and 2015.

CONSOLIDATED STATEMENTS OF FINA

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Current assets:
Cash and cash equivalents	$ 35	$ 101
Restricted cash	0	14
Receivables, trade and other	65	6
Due from General Partner and affiliates	101	88
Accrued receivables	105	19
Other current assets	24	34
Current assets related to discontinued operations	0	139
Assets, Current, Total	330	401
Property, plant and equipment, net	12,896	12,608
Equity investment in joint venture	1,565	0
Other assets, net	37	119
Assets held for sale	0	207
Non-current assets related to discontinued operations	0	4,775
Total assets	14,828	18,110
Current liabilities:
Accounts payable and other	173	348
Due to General Partner and affiliates	48	175
Interest payable	85	90
Environmental liabilities	23	100
Property and other taxes payable	106	89
Current portion of long-term debt	500	0
Current liabilities related to discontinued operations	0	300
Liabilities, Current, Total	935	1,102
Long-term debt	6,366	7,066
Loans from General Partner and affiliate	610	750
Due to General Partner and affiliates	0	328
Other long-term liabilities	178	197
Non-current liabilities related to discontinued operations	0	844
Liabilities, Total	8,089	10,287
Commitments and contingencies
Partners’ capital:
Series 1 preferred units (48,000,000 authorized and issued at December 31, 2016)	0	1,192
General Partner	68	(667)
Accumulated other comprehensive loss	(199)	(339)
Total Enbridge Energy Partners, L.P. partners’ capital	1,770	3,977
Noncontrolling interests	4,969	3,846
Total Partners’ capital	6,739	7,823
Total Liabilities and Partners' capital	14,828	18,110
Class D Units [Member]
Partners’ capital:
Common units	0	2,518
Class E Unit
Partners’ capital:
Common units	774	778
Class A Common Units [Member]
Partners’ capital:
Common units	860	0
Class B Common Units [Member]
Partners’ capital:
Common units	0	0
i-Units
Partners’ capital:
Common units	0	0
Class F Units [Member]
Partners’ capital:
Common units	267	0
Incentive Distribution Units
Partners’ capital:
Common units	0	495
Continuing Operations [Member]
Current assets:
Total assets		13,196
Partners’ capital:
Noncontrolling interests	4,969	3,543
Discontinued Operations [Member]
Partners’ capital:
Noncontrolling interests	$ 0	$ 303

CONSOLIDATED STATEMENTS OF FIN6

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION (Parenthetical) - shares	Dec. 31, 2017	Dec. 31, 2016
Preferred units, authorized (in shares)	48,000,000	48,000,000
Preferred units, issued (in shares)	48,000,000	48,000,000
Class D Units [Member]
Common units, authorized (in shares)	66,100,000	66,100,000
Common units, issued (in shares)	66,100,000	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)	89,798,818	81,857,168
Common units, issued (in shares)	89,798,818	81,857,168
Class F Units [Member]
Common units, authorized (in shares)	1,000	1,000
Common units, issued (in shares)	1,000	1,000
Incentive Distribution Units
Common units, authorized (in shares)	1,000	1,000
Common units, issued (in shares)	1,000	1,000

CONSOLIDATED STATEMENTS OF PART

CONSOLIDATED STATEMENTS OF PARTNERS CAPITAL - USD ($) $ in Millions	Total	Accumulated Other Comprehensive Income (Loss)	General Partner [Member]	Series 1 Preferred units	Class D Unit	Class E Unit	Class A Common Units	Class B Common Unit	i-Units	Class F Common Units	Incentive Distribution Units
Beginning balance at Dec. 31, 2014		$ (206)	$ 198	$ 1,176	$ 2,517	$ 0	$ 236	$ 0	$ 713	$ 0	$ 493
Redemption of preferred units				0
Net income	$ 132		(32)	90	153	42	311	18	(380)	0	19
Distribution payable	(339)		(17)	(90)	(152)	(32)	(600)	(18)		0	(17)
Noncontrolling interest, increase from sale of parent equity interest	0		0
Accretion of discount on preferred units	11			11
Waiver			0		0						0
Issuance of Units			0			768	289			0
Issuances of units			6
Allocation of distributions to General and limited partner			0
Allocation of fair value	(404)		(8)				(236)		(120)
Sale of noncontrolling interest in subsidiary	0		0				0	0	0
Other							0
Net realized gains (losses) on changes in fair value of derivative financial instruments reclassified to earnings		22
Unrealized net gain (loss) on derivative financial instruments		(186)
Ending balance at Dec. 31, 2015		(370)	147	1,187	2,518	778	0	0	213	0	495
Beginning balance at Dec. 31, 2014	3,609
Noncontrolling interest
Capital contributions	863		0
Acquisition of noncontrolling interest in subsidiary	0
Net income (loss)	221
Other comprehensive income (loss), net of tax	(6)
Ending balance at Dec. 31, 2015	3,944
Noncontrolling interest
Total partners’ capital at end of year	8,912
Redemption of preferred units				0
Net income	(162)		(797)	90	154	42	612	18	(213)	0	21
Distribution payable	(242)		(17)	(90)	(154)	(42)	(612)	(18)		0	(21)
Noncontrolling interest, increase from sale of parent equity interest	0		0
Accretion of discount on preferred units	5			5
Waiver			0		0						0
Issuance of Units			0			0	0			0
Issuances of units			0
Allocation of distributions to General and limited partner			0
Allocation of fair value	0		0				0		0
Sale of noncontrolling interest in subsidiary	0		0				0	0	0
Other			790				0
Net realized gains (losses) on changes in fair value of derivative financial instruments reclassified to earnings		39
Unrealized net gain (loss) on derivative financial instruments		(8)
Ending balance at Dec. 31, 2016	3,977	(339)	(667)	1,192	2,518	778	0	0	0	0	495
Noncontrolling interest
Capital contributions	118		0
Acquisition of noncontrolling interest in subsidiary	0
Net income (loss)	26
Other comprehensive income (loss), net of tax	0
Ending balance at Dec. 31, 2016	3,846
Noncontrolling interest
Total partners’ capital at end of year	7,823
Redemption of preferred units				(1,200)
Net income	245		76	29	0	25	126	12	(9)	15	0
Distribution payable	(504)		(12)	(29)	(39)	(29)	(496)	(13)		(11)	(5)
Noncontrolling interest, increase from sale of parent equity interest	411		1
Accretion of discount on preferred units	8			8
Waiver			2,969		(2,479)						(490)
Issuance of Units			(263)			0	1,200			263
Issuances of units			24
Allocation of distributions to General and limited partner			(1)
Allocation of fair value	0		0				0		0
Sale of noncontrolling interest in subsidiary	(297)		(2,127)				29	1	9
Other			71				1
Net realized gains (losses) on changes in fair value of derivative financial instruments reclassified to earnings		208
Unrealized net gain (loss) on derivative financial instruments		(68)
Ending balance at Dec. 31, 2017	1,770	$ (199)	68	$ 0	$ 0	$ 774	$ 860	$ 0	$ 0	$ 267	$ 0
Noncontrolling interest
Capital contributions	1,504		$ 68
Acquisition of noncontrolling interest in subsidiary	(360)
Net income (loss)	369
Other comprehensive income (loss), net of tax	0
Ending balance at Dec. 31, 2017	4,969
Noncontrolling interest
Total partners’ capital at end of year	$ 6,739

BUSINESS OVERVIEW

BUSINESS OVERVIEW	12 Months Ended
	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
BUSINESS OVERVIEW	1. BUSINESS OVERVIEW General Business Description We, together with our consolidated subsidiaries, are a publicly-traded Delaware limited partnership. We are a geographically and operationally diversified organization that provides crude oil and liquid petroleum gathering, transportation and storage services. We hold our assets in a series of limited liability companies and limited partnerships that we own either directly or indirectly. Our Class A common units are traded on the NYSE, under the symbol “EEP.” We were formed in 1991 by our General Partner, which is an indirect, wholly-owned subsidiary of Enbridge. We own and operate the crude oil and liquid petroleum transportation assets of the OLP, which owns the United States portion of a crude oil and liquid petroleum pipeline system extending from western Canada through the upper and lower Great Lakes region of the United States to eastern Canada. Midcoast Energy Partners, L.P. On April 27, 2017, MEP completed its merger with our General Partner under the terms of the Merger Agreement previously announced on January 26, 2017. Our General Partner acquired for cash, subject to terms and conditions thereof, all of the outstanding publicly held Class A common units of MEP at a price of $8 per common unit for an aggregate transaction value of $170 million . The public interest acquired by our General Partner represented an approximate 25% effective interest in our natural gas gathering and processing business. MEP ceased to be a publicly traded entity. 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 7 - Dispositions and Discontinued Operations . Enbridge Energy Management, L.L.C. Enbridge Management is a Delaware limited liability company that was formed in May 2002. Our General Partner, through its direct ownership of the voting shares of Enbridge Management, elects all of its directors. Enbridge Management’s listed shares are traded on the NYSE under the symbol “EEQ.” Enbridge Management owns all of a special class of our limited partner interests that we refer to as i-units and derives all of its earnings from its investment in us. Enbridge Management’s principal activity is managing our business and affairs pursuant to a delegation of control agreement among our General Partner, Enbridge Management and us. The delegation of control agreement provides that Enbridge Management will not amend or propose to amend our partnership agreement, allow a merger or consolidation involving us, allow a sale or exchange of all or substantially all of our assets or dissolve or liquidate us without the approval of our General Partner. In accordance with its limited liability company agreement, Enbridge Management’s activities are restricted to being our limited partner and managing our business and affairs. Enbridge Inc. Enbridge is the indirect parent of our General Partner, and its common shares are publicly traded on the NYSE in the United States and the Toronto Stock Exchange (TSX), in Canada under the symbol “ENB.” Enbridge is an energy transportation and distribution company, with a focus on crude oil and liquids pipelines, natural gas pipelines and natural gas distribution. At December 31, 2017 and 2016 , Enbridge and its consolidated subsidiaries held an effective 34.6% and 41.7% outstanding ownership interest in us, respectively, through its ownership in Enbridge Management and our General Partner. SEGMENTS AND TRANSACTIONS As noted above, On June 28, 2017, we completed the Midcoast sale which resulted in the discontinuation of the natural gas business and the elimination of our Natural Gas segment. As a result, we conduct our business through one operating segment: Liquids Liquids Our Liquids segment includes the Lakehead System, Mid-Continent Systems and Bakken Assets. Our Lakehead System consists of a series of interstate common carrier crude oil and liquid petroleum pipelines that are regulated by the FERC, and storage assets, all of which are located in the Great Lakes and Midwest regions of the United States. Our Lakehead System, together with the Enbridge system in Canada owned by Enbridge, forms the longest liquid petroleum pipeline in the world. The Lakehead System, consists of approximately 4,212 miles of pipe and 74 pump stations, has been in operation for more than 60 years and is the primary transporter of crude oil and liquid petroleum from western Canada to the United States. The Lakehead System primarily serves all the major refining centers in the Great Lakes and Midwest regions of the United States and the province of Ontario, Canada. Our Bakken Assets which contain our North Dakota crude oil system is approximately 660 miles long, has 12 pump stations, multiple delivery points and storage facilities. The North Dakota System connects directly into the Lakehead System in the state of Minnesota. Our Mid-Continent System consists of approximately 20 million barrels of storage capacity, which serve refineries in the United States Mid-Continent region from Cushing, Oklahoma. The remainder of our business operation is presented as "Other," and consists of unallocated corporate costs.

SUMMARY OF SIGNIFICANT ACCOUNTI

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES	2. SIGNIFICANT ACCOUNTING POLICIES Basis of Presentation and Use of Estimates These consolidated financial statements are prepared in accordance with U.S. GAAP. The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities in the consolidated financial statements. We regularly evaluate these estimates utilizing historical experience, consultation with experts and other methods we consider reasonable in the circumstances. Nevertheless, actual results may differ significantly from these estimates. We record the effect of any revisions to these estimates in our consolidated financial statements in the period in which the facts that give rise to the revision become known. Amounts are stated in United States dollars unless otherwise noted. Principles of Consolidation The consolidated financial statements include our accounts and accounts of our subsidiaries and VIEs for which we are the primary beneficiary. Upon inception of a contractual agreement, we perform an assessment to determine whether the arrangement contains a variable interest in a legal entity and whether that legal entity is a VIE. Where we conclude we are the primary beneficiary of a VIE, we consolidate the accounts of that VIE. We assess all aspects of our interests in an entity and use judgment when determining if we are the primary beneficiary. The primary beneficiary has both the power to direct the activities of the VIE that most significantly impact the entity’s economic performance and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. Other qualitative factors that are considered include decision-making responsibilities, the VIE capital structure, risk and rewards sharing, contractual agreements with the VIE, voting rights and level of involvement of other parties. A reassessment of the primary beneficiary conclusion is conducted when there are changes in the facts and circumstances related to a VIE. All significant intercompany accounts and transactions are eliminated upon consolidation. Ownership interests in subsidiaries represented by other parties that do not control the entity are presented in the consolidated financial statements as activities and balances attributable to NCI. Investments and entities over which we exercise significant influence are accounted for using the equity method. Regulation Our interstate liquids pipelines are subject to regulation by FERC and various state authorities. Regulatory bodies exercise statutory authority over matters such as construction, rates and ratemaking and agreements with customers. For example, the recovery of construction, operating and other costs associated with portions of our Lakehead System are subject to the authoritative accounting provisions applicable to regulated operations. To recognize the economic effects of the actions of the regulator, the timing of recognition of certain revenues and expenses in these operations may differ from that otherwise expected under U.S. GAAP for non rate-regulated entities. Under our cost-of-service recovery model, the difference between forecast used to calculate the tolls and actual results causes an over or under recovery in any given year that is deferred through a revenue adjustment and is returned to or recovered from shippers through future rate adjustments in the following year. Due to these over or under recovery adjustments made in accordance with the FERC’s authoritative guidance, 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. The net regulatory asset or liability balance is comprised of the cumulative over and under recovery adjustments made during the prior calendar year, less any amortizations and the cumulative over and under recovery adjustments made during current calendar year to date. We track regulatory assets and liabilities by vintage and our regulatory assets and liabilities are amortized on a straight-line basis over a one-year recovery period. Accordingly, amortization for a net regulatory asset or liability arising from over and under recovery adjustments related to any given calendar year does not begin until January of the following year. Allowance for Funds Used During Construction AFUDC is included in the cost of property, plant and equipment and is depreciated over future periods as part of the total cost of the related asset. AFUDC includes both an interest component and, if approved by the regulator, a cost of equity component, which are both capitalized based on rates set out in a regulatory agreement. In the absence of rate regulation, we would capitalize interest using a capitalization rate based on our cost of borrowing, whereas the capitalized equity component, the corresponding earnings during the construction phase and the subsequent depreciation would not be recognized. Revenue Recognition and the Estimation of Revenues We generally do not own the crude oil and liquid petroleum that we transport or store and therefore, we do not assume significant direct commodity price risk. Revenues are primarily derived from three sources: interstate transportation of crude oil and liquid petroleum under tariffs regulated by the FERC, ship-or-pay agreements and contract storage revenues related to our crude oil storage assets. The tariffs established for our interstate pipelines specify the amounts to be paid by shippers for transportation services we provide between receipt and delivery locations and the general terms and conditions of transportation services on the respective pipeline systems. We recognize revenue upon delivery of products to our customers, when pricing is determinable and collectability is reasonably assured. We recognize contract storage revenues based on contractual terms under which customers pay for the option to use available storage capacity and/or a fee based on storage volumes. We recognize revenues as storage services are rendered, when pricing is determinable and collectability is reasonably assured. Revenues are all recorded in “Transportation and other services” and “Transportation and other services — affiliate” on our consolidated statements of income. Estimation of Revenue In order to permit the timely preparation of our consolidated financial statements, we estimate our current month revenue and commodity costs. We generally cannot compile actual billing information nor obtain actual vendor invoices within a timeframe that would permit the recording of this actual data before our preparation of the consolidated financial statements. As a result, we record an estimate each month for our operating revenues based on the best available volume and price data for crude oil delivered and received, along with an adjustment of the prior month’s estimate to equal the prior month’s actual data. As a result, there is one month of estimated data recorded in our operating revenues and commodity costs for each of the years ended December 31, 2017 , 2016 and 2015 . We believe that the assumptions underlying these estimates are not significantly different from the actual amounts due to the routine nature of these estimates and the stability of our processes. Derivative Financial Instruments We use derivative financial instruments (i.e., futures, forwards, swaps, options and other financial instruments with similar characteristics) to manage our exposure to changes in commodity prices and interest rates. We record all derivative financial instruments at fair market value in our consolidated statements of financial position. For those instruments that qualify for hedge accounting, the accounting treatment is dependent on the intended use and designation of each instrument. We record changes in the fair value of our derivative financial instruments that are not designated for hedge accounting in our consolidated statements of income as follows: • Commodity-based derivatives — “Transportation and other services” • Interest rate derivatives — “Interest expense, net” Qualified Hedges We may use cash flow hedges to manage our exposure to changes in commodity prices and interest rates. To qualify for cash flow hedge accounting treatment, very specific requirements must be met in terms of hedge structure, hedge objective and hedge documentation. At inception, we formally document the relationship between the hedging instrument and the hedged item, the risk management objective and the method used for assessing and testing correlation and hedge effectiveness. We also assess, both at the inception of the hedge and on an on-going basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows of the hedged item. Furthermore, we regularly assess the creditworthiness of our counterparties to manage against the risk of default. If we determine that a derivative is no longer highly effective as a hedge, we discontinue hedge accounting prospectively by including changes in the fair value of the derivative in current earnings. The effective portion of the change in fair value of a cash flow hedge is recorded in other comprehensive income (loss) and is reclassified into earnings when the hedge item impacts earnings. Any ineffective portion of a cash flow hedge’s change in fair value is recognized each period in earnings. Gains and losses deferred in AOCI related to cash flow hedges for which hedge accounting has been discontinued remain in AOCI until the underlying physical transaction occurs unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two month period of time thereafter. Although we retain the ability to designate commodity hedges for cash flow hedge accounting, as of December 31, 2017 , we have no commodity hedges designated as cash flow hedges. Non-Qualified Hedges We have derivative financial instruments associated with our commodity activities where the hedge structure does not meet the requirements to apply hedge accounting. As a result, these derivative financial instruments do not qualify for hedge accounting and are referred to as non-qualifying. These non-qualifying derivative financial instruments are marked-to-market each period with the change in fair value, representing unrealized gains and losses, included in “Transportation and other services” in our consolidated statements of income. These mark-to-market adjustments produce a degree of earnings volatility that can often be significant from period to period, but have no cash flow impact relative to changes in market prices. The cash flow impact occurs when the underlying physical transaction takes place in the future and the associated financial instrument contract settlement is made. Although we retain the ability to designate commodity hedges for cash flow accounting, as of December 31, 2017 , we have no remaining commodity hedges that are designated. As such, all commodity hedges are marked-to-market with the changes in fair value recorded in earnings each period. Designated interest rate derivative financial instruments continue to be reported in AOCI. Fair Value Measurements We apply the authoritative accounting provisions for measuring fair value to our derivative instruments and disclosures associated with our outstanding commodity activities. Fair value is defined as the expected price we would receive to sell an asset or pay to transfer a liability in an orderly transaction with market participants at the measurement date. We employ a hierarchy which prioritizes the inputs we use to measure recurring fair value into three distinct categories based upon whether such inputs are observable in active markets or unobservable. We classify assets and liabilities in their entirety based on the lowest level of input that is significant to the fair value measurement. Our methodology for categorizing assets and liabilities that are measured at fair value pursuant to this hierarchy gives the highest priority to unadjusted quoted prices in active markets and the lowest level to unobservable inputs as outlined below: • Level 1 — We include in this category the fair value of assets and liabilities that we measure based on unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. We consider active markets as those in which transactions for the assets or liabilities occur with sufficient frequency and volume to provide pricing information on an ongoing basis. The fair value of our assets and liabilities included in this category consists primarily of exchange-traded derivative instruments. • Level 2 — We include in this category 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: (a) quoted prices for assets and liabilities; (b) time value; (c) volatility factors; and (d) 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. • Level 3 — We include in this category the fair value of assets and liabilities that we measure based on prices or valuation techniques that require inputs which are both significant to the fair value measurement and less observable from objective sources (i.e., values supported by lesser volumes of market activity). We may also use these inputs with internally developed methodologies that result in our best estimate of the fair value. Level 3 assets and liabilities primarily include derivative instruments for which we do not have sufficient corroborating market evidence, such as binding broker quotes, to support classifying the asset or liability as Level 2. Additionally, Level 3 valuations may utilize modeled pricing inputs to derive forward valuations, which may include some or all of the following inputs: non-binding broker quotes, time value, volatility, correlation and extrapolation methods. We record all derivative financial instruments in our consolidated financial statements at fair market value, which we adjust on a recurring basis each period for changes in the fair market value and refer to as marking to market, or mark-to-market. The fair market value of these derivative financial instruments reflects the estimated amounts that we would pay to transfer a liability or receive to sell an asset in an orderly transaction with market participants to terminate or close the contracts at the reporting date, taking into account the current unrealized losses or gains on open contracts. We apply a mid-market pricing convention, which we refer to as the “market approach,” to value substantially all of our derivative instruments. Our assets are adjusted for the non-performance risk of our counterparties using their current credit default swap spread rates. Likewise, in the case of our liabilities, our nonperformance risk is considered in the valuation and is also adjusted using a credit adjustment model incorporating inputs such as credit default swap rates, bond spreads, and default probabilities. Our credit exposure for OTC derivatives is directly with our counterparty and continues until the maturity or termination of the contracts. As appropriate, valuations are adjusted for various factors such as credit and liquidity considerations. Actively traded external market quotes, data from pricing services and published indices are also used to value our derivative instruments. We may use these inputs along with internally developed methodologies that result in our best estimates of fair value. Transaction Costs Transaction costs are incremental costs directly related to the acquisition of a financial asset or the issuance of a financial liability. We incur transaction costs primarily from the issuance of debt and accounts for these costs as a deduction from Long-term debt on the Statements of Financial Position. These costs are amortized using the effective interest rate method over the term of the related debt instrument and are recorded in Interest expense. Equity Investments Equity investments over which we exercise significant influence, but do not have controlling financial interests, are accounted for using the equity method. Equity investments are initially measured at cost and are adjusted for our proportionate share of undistributed equity earnings or loss. Equity investments are increased for contributions made to and decreased for distributions received from the investees. To the extent an equity investee undertakes activities necessary to commence its planned principal operations; we capitalize interest costs associated with its investment during such period. Income Taxes We are not a taxable entity for United States federal income tax purposes or for the majority of states that impose an income tax. Taxes on our net income generally are borne by our unitholders through the allocation of taxable income. Our income tax expense results from the enactment of franchise tax laws by the State of Texas that apply to entities organized as partnerships. This tax is computed on our modified gross margin and we have determined the tax to be an income tax as set forth in authoritative accounting literature. We recognize deferred income tax assets and liabilities for temporary differences between the relevant basis of our assets and liabilities for financial reporting and tax purposes. We record the impact of changes in tax legislation on deferred income tax liabilities and assets in the period the legislation is enacted. We recognize the tax effects of any uncertain tax positions as the largest amount that will more likely than not be realized upon ultimate settlement with a taxing authority having full knowledge of the position and all relevant facts. We recognize accrued interest income related to unrecognized tax benefits in interest income when the related unrecognized tax benefits are recognized. Net income for financial statement purposes may differ significantly from taxable income of unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under our partnership agreement. The aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined because information regarding each partner’s tax attributes in us is not available. Cash and Cash Equivalents Cash equivalents are defined as all highly marketable securities with original maturities of three months or less when purchased. The carrying value of cash and cash equivalents approximates fair value because of the short term to maturity of these investments. Restricted Cash Cash and cash equivalents that are restricted as to withdrawal or usage, in accordance with specific commercial arrangements, are presented as “Restricted cash” on our consolidated statements of financial position. Oil Measurement Adjustments Oil measurement adjustments occur as part of the normal operations associated with our liquid petroleum operations. The three types of oil measurement adjustments that routinely occur on our systems include: • Physical, which result from evaporation, shrinkage, differences in measurement (including sediment and water measurement) between receipt and delivery locations and other operational conditions; • Degradation, resulting from mixing at the interface within our pipeline systems or terminal and storage facilities between higher quality light crude oil and lower quality heavy crude oil in pipelines; and • Revaluation, which are a function of crude oil prices, the level of our carriers’ inventory and the inventory positions of customers. Quantifying oil measurement adjustments are difficult because: (i) physical measurements of volumes are not practical, as products continuously move through our pipelines, which are primarily located underground; (ii) the extensive length of our pipeline systems; and (iii) the numerous grades and types of crude oil products we carry. We utilize engineering-based models and operational assumptions to estimate product volumes in our systems and associated oil measurement adjustments. Material changes in our assumptions may result in revisions to our oil measurement estimates in the period determined. Oil measurement adjustments are included within the “Operating and administrative” line item of our consolidated statements of income. Property, Plant and Equipment We record property, plant and equipment at historical cost. We capitalize expenditures in excess of a minimum rule, which have a useful life greater than one year for: (i) assets purchased or constructed; (ii) existing assets that are replaced, improved or the useful lives have been extended; or (iii) all land, regardless of cost. Maintenance and repair costs, including any planned major maintenance activities, are expensed as incurred. Expenditures for project development are capitalized if they are expected to have a future benefit. During construction, we capitalize direct costs, such as labor and materials, and other costs, such as direct overhead and interest at our weighted average cost of debt. We depreciate property, plant and equipment on a straight-line basis over the lesser of its estimated useful life or the estimated remaining lives of the crude oil production in the basins the assets serve. Upon disposition of distinct assets, we recognize any gains or losses in our consolidated statements of income. For largely homogeneous groups of assets with comparable useful lives, we record depreciation using the group method of depreciation whereby similar assets are grouped and depreciated as a group. Under this method, when group assets are retired or otherwise disposed of, gains and losses are not reflected in our consolidated statements of income but are recorded as an adjustment to accumulated depreciation. Impairment We evaluate the recoverability of our long-lived assets when events or circumstances such as economic obsolescence, the business climate, legal and other factors indicate we may not recover the carrying amount of the assets. We evaluate the asset for recoverability by estimating the undiscounted future cash flows expected to be derived from operating the asset as a going concern. If the carrying amount of the asset exceeds the sum of the undiscounted future cash flows, we recognize an impairment loss in the amount of the excess carrying amount of the asset over its fair value. Asset Retirement Obligations Legal obligations exist for a minority of our right-of-way agreements due to requirements or landowner options that compel us to remove the pipe at final abandonment. Sufficient data exists with certain pipeline systems to reasonably estimate the cost of abandoning or retiring a pipeline system. However, in some cases, there is insufficient information to reasonably determine the timing and/or method of settlement for estimating the fair value of the asset retirement obligation. In these cases, the asset retirement obligation cost is considered indeterminate because there is no data or information that can be derived from past practice, industry practice, our intentions, or the estimated economic life of the asset. Useful lives of most pipeline systems are primarily derived from available supply resources and ultimate consumption of those resources by end users. Variables can affect the remaining lives of the assets which preclude us from making a reasonable estimate of the asset retirement obligation. Indeterminate asset retirement obligation costs will be recognized in the period in which sufficient information exists to allow us to reasonably estimate potential settlement dates and methods. We record a liability for the fair value of asset retirement obligations and conditional asset retirement obligations that we can reasonably estimate, on a discounted basis. We collectively refer to asset retirement obligations and conditional asset retirement obligations as ARO. Typically, we record an ARO at the time the assets are installed or acquired, if a reasonable estimate of fair value can be made. In connection with establishing an ARO, we capitalize the costs as part of the carrying value of the related assets. We recognize an ongoing expense for the interest component of the liability as part of depreciation expense resulting from changes in the value of the ARO due to the passage of time. We depreciate the initial capitalized costs over the useful lives of the related assets. We extinguish the liabilities for an ARO when assets are taken out of service or otherwise abandoned. Commitments, Contingencies and Environmental Liabilities We expense or capitalize, as appropriate, expenditures for ongoing compliance with environmental regulations that relate to past or current operations. We expense amounts we incur for remediation of existing environmental contamination caused by past operations that do not benefit future periods by preventing or eliminating future contamination. We record liabilities for environmental matters when assessments indicate that remediation efforts are probable, and the costs can be reasonably estimated. Estimates of environmental liabilities are based on currently available facts, existing technology and presently enacted laws and regulations taking into consideration the likely effects of inflation and other factors. These amounts also consider prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by government organizations. Our estimates are subject to revision in future periods based on actual costs or new information and are included in “Environmental liabilities” and “Other long-term liabilities” in our consolidated statements of financial position at their undiscounted amounts. We always have the potential of incurring additional costs in connection with environmental liabilities due to variations in any or all of the categories described above, including modified or revised requirements from regulatory agencies, in addition to fines and penalties, as well as expenditures associated with litigation and settlement of claims. We evaluate recoveries from insurance coverage separately from the liability and, when recovery is probable, we record and report an asset separately from the associated liability in our consolidated financial statements. We recognize liabilities for other commitments and contingencies when, after fully analyzing the available information, we determine it is either probable that an asset has been impaired, or that a liability has been incurred and the amount of impairment or loss can be reasonably estimated. When a range of probable loss can be estimated, we accrue the most likely amount, or if no amount is more likely than another, we accrue the minimum of the range of probable loss. We expense legal costs associated with loss contingencies as such costs are incurred.

CHANGES IN ACCOUNTING POLICY

CHANGES IN ACCOUNTING POLICY	12 Months Ended
	Dec. 31, 2017
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
CHANGES IN ACCOUNTING POLICY	3. CHANGES IN ACCOUNTING POLICY Adoption of New Standards Clarifying the Definition of a Business in an Acquisition Effective January 1, 2017, we early adopted Accounting Standards Update (ASU) 2017-01 on a prospective basis. The new standard was issued with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (disposals) of assets or businesses. The adoption of the pronouncement did not have a material impact on our consolidated financial statements. Accounting for Intra-Entity Asset Transfers Effective January 1, 2017, we early adopted ASU 2016-16 on a modified retrospective basis. The new standard was issued with the intent of improving the accounting for the income tax consequences of intra-entity asset transfers other than inventory. Under the new guidance, an entity should recognize the income tax consequences of an intra-entity transfer of an asset, other than inventory, when the transfer occurs. The adoption of the pronouncement did not have a material impact on our consolidated financial statements. Simplifying the Embedded Derivatives Analysis for Debt Instruments Effective January 1, 2017, we adopted ASU 2016-06 on a modified retrospective basis. The new guidance simplifies the embedded derivative analysis for debt instruments containing contingent call or put options. The adoption of the pronouncement did not have a material impact on our consolidated financial statements. Future Accounting Policy Changes Improvements to Accounting for Hedging Activities ASU 2017-12 was issued in August 2017 with the objective of better aligning a company’s risk management activities and the resulting hedge accounting reflected in the financial statements. The accounting update allows cash flow hedging of contractually specified components in financial and non-financial items. Under the new guidance, hedge ineffectiveness is no longer required to be measured and hedging instruments’ fair value changes will be recorded in the same income statement line as the hedged item. The ASU also allows the initial quantitative hedge effectiveness assessment to be performed at any time before the end of the quarter in which the hedge is designated. After initial quantitative testing is performed, an ongoing qualitative effectiveness assessment is permitted. The accounting update is effective January 1, 2019 and is to be applied on a modified retrospective basis. We are currently assessing the impact of the new standard on the consolidated financial statements. Simplifying Cash Flow Classification ASU 2016-15 was issued in August 2016 with the intent of reducing diversity in practice of how certain cash receipts and cash payments are classified in the Consolidated Statement of Cash Flows. The new guidance addresses eight specific presentation issues. The accounting update is effective January 1, 2018 and will be applied on a retrospective basis. We assessed each of the eight specific presentation issues and the adoption of this ASU does not have a material impact on our consolidated financial statements. Accounting for Credit Losses ASU 2016-13 was issued in June 2016 with the intent of providing financial statement users with more useful information about the expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity at each reporting date. Current treatment uses the incurred loss methodology for recognizing credit losses that delays the recognition until it is probable a loss has been incurred. The accounting update adds a new impairment model, known as the current expected credit loss model, which is based on expected losses rather than incurred losses. Under the new guidance, an entity recognizes as an allowance its estimate of expected credit losses, which the Financial Accounting Standards Board believes will result in more timely recognition of such losses. We are currently assessing the impact of the new standard on our consolidated financial statements. The accounting update is effective January 1, 2020. Recognition of Leases ASU 2016-02 was issued in February 2016 with the intent to increase transparency and comparability among organizations. It requires lessees of operating lease arrangements to recognize lease assets and lease liabilities on the statement of financial position and disclose additional key information about lease agreements. The accounting update also replaces the current definition of a lease and requires that an arrangement be recognized as a lease when a customer has the right to obtain substantially all of the economic benefits from the use of an asset, as well as the right to direct the use of the asset. We are currently gathering a complete inventory of our lease contracts in order to assess the impact of the new standard on our consolidated financial statements. The accounting update is effective January 1, 2019 and will be applied using a modified retrospective approach. Recognition and Measurement of Financial Assets and Liabilities ASU 2016-01 was issued in January 2016 with the intent to address certain aspects of recognition, measurement, presentation and disclosure of financial assets and liabilities. Investments in equity securities, excluding equity method and consolidated investments, are no longer classified as trading or available-for-sale securities. All investments in equity securities with readily determinable fair values are classified as investments at fair value through net income. Investments in equity securities without readily determinable fair values are measured using the fair value measurement alternative and are recorded at cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for an identical or similar investment of the same issuer. Investments in equity securities measured using the fair value measurement alternative are reviewed for indicators of impairment each reporting period. Fair value of financial instruments for disclosure purposes is measured using exit price. The accounting update is effective January 1, 2018 and will be applied on a prospective basis. We do not expect the adoption of this accounting update to have a material impact on our consolidated financial statements. Revenue 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. It also requires the use of more estimates and judgments than the present standards in addition to additional disclosures .The new standard is effective January 1, 2018. The new 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 decided to adopt the new standard using the modified retrospective method. We have reviewed our revenue contracts in order to evaluate the effect of the new standard on its revenue recognition practices. Based on this assessment, the application of the standard will result in the following changes to our financial statements and revenue recognition methods: • Estimates of variable consideration which will be required under the new standard as well as the allocation of the transaction price for certain revenue contracts may result in changes to the pattern or timing of revenue recognition for those contracts. • Certain payments received from customers to offset the cost of constructing assets required to provide services to those customers, referred to as CIACs were previously recorded as reductions of property, plant and equipment regardless of whether the amounts were imposed by regulation or negotiated. Under the new standard, negotiated CIACs are deemed to be advance payments for services and must be recognized when those future services are provided. Negotiated CIACs will be accounted for as deferred revenue and recognized over the term of the associated revenue contract. After conducting this assessment, we determined that any necessary adjustments to our partners' capital account as of January 1, 2018 would be immaterial. We have also developed and tested processes to generate the disclosures which will be required under the new standard commencing in first quarter of 2018.

NET INCOME PER LIMITED PARTNER

NET INCOME PER LIMITED PARTNER UNIT	12 Months Ended
	Dec. 31, 2017
Earnings Per Share [Abstract]
NET INCOME PER LIMITED PARTNER UNIT	4. NET INCOME PER LIMITED PARTNER UNIT We allocate our net income to our Class E units equal to the distributions that they receive. We also allocate any earnings in excess of distributions to our General Partner and limited partners owning Class A and B common units and i-units utilizing the distribution formula for available cash specified in our partnership agreement. We allocate any distributions in excess of earnings for the period to our General Partner and limited partners owning Class A and B common units and i-units based on their sharing of losses of 2% and 98% , respectively, as set forth in our partnership agreement. Prior to April 27, 2017, we allocated distributions to the General Partner and limited partners based upon the distribution rates and percentages set forth in the following table: Distribution Targets Portion of Quarterly Distribution Per Unit Percentage Distributed to General Partner and IDUs (1) Percentage Distributed to Limited partners Minimum Quarterly Distribution Up to $0.5435 2% 98% First Target Distribution > $0.5435 25% 75% ____________ (1) For distributions in excess of the Minimum Quarterly Distribution, this percentage includes both the General Partner’s distributions of 2% and the distribution to the Incentive Distribution Unit holder, a wholly-owned subsidiary of our General Partner. Equity Restructuring Transaction On April 27, 2017, a wholly-owned subsidiary of our General Partner irrevocably waived all of its rights associated with its 66 million Class D units and its 1,000 IDUs in exchange for the issuance of 1,000 Class F units. The irrevocable 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 Distribution Per Unit Percentage Distributed to General Partner and Class F Units (1) Percentage Distributed to Limited Partners 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 distribution in excess of the Minimum Quarterly Distribution, this percentage includes both the General Partner's distribution of 2% and the distribution to the Class F units. Alberta Clipper Drop Down On January 2, 2015, we completed a transaction to acquire from our General Partner the remaining 66.7% interest in the United States portion of the Alberta Clipper Pipeline. The consideration consisted of issuance to the General Partner of 18,114,975 units of a new class of limited partner interests designated as Class E units. We determined basic and diluted net income (loss) per common unit and i-unit as follows: For the year ended December 31, 2017 2016 2015 (in millions, except per unit amounts) Continuing operations: $ 708 $ 116 $ 739 Net income Less: Net income attributable to: Noncontrolling interest 388 72 297 Series 1 preferred unit distributions 29 90 90 Accretion of discount on Series 1 preferred units 8 5 11 Net income (loss) attributable to general and limited partner interests in Enbridge Energy Partners, L.P. - continuing operations 283 (51 ) 341 Distributions: Incentive distributions (1) (15 ) (21 ) (19 ) Distributed earnings attributed to our General Partner (13 ) (21 ) (21 ) Distributed earnings attributed to Class D and Class E units (1) (25 ) (196 ) (195 ) Total distributed earnings to our General Partner, Class D, Class E units Class F units and IDUs (53 ) (238 ) (235 ) Total distributed earnings attributed to our common units and i-units (589 ) (814 ) (791 ) Total distributed earnings (642 ) (1,052 ) (1,026 ) Overdistributed earnings $ (359 ) $ (1,103 ) $ (685 ) Discontinued operations: Net loss $ (57 ) $ (157 ) $ (285 ) Less: Net loss attributable to: Noncontrolling interest (19 ) (46 ) (76 ) Net loss attributable to general and limited partner interests in Enbridge Energy Partners, L.P. - discontinued operations $ (38 ) $ (111 ) $ (209 ) Weighted average common units and i-units outstanding 400 348 339 Basic and diluted earnings per unit: Distributed earnings per common unit and i-unit - continuing operations (2) 1.48 2.34 2.33 Overdistributed earnings per common unit and i-unit (3) (0.88 ) (3.11 ) (1.98 ) Net income (loss) per common unit and i-unit (basic and diluted) - continuing operations (4) 0.60 (0.77 ) 0.35 Net loss per common unit and i-unit (basic and diluted) - discontinued operations (4) (0.10 ) (0.31 ) (0.60 ) Net income (loss) per common unit and i-unit (basic and diluted) 0.50 (1.08 ) (0.25 ) ____________ (1) For the year ended December 31, 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 units and IDUs; for the years ended December 31, 2016 and 2015 , 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-unit’s 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 years ended December 31, 2017 , 2016 and 2015 , 43,201,310 anti-dilutive Preferred Units, 66,100,000 anti-dilutive Class D units and 18,114,975 anti-dilutive Class E units were excluded from the if-converted method of calculating diluted earnings per unit.

SEGMENT INFORMATION

SEGMENT INFORMATION	12 Months Ended
	Dec. 31, 2017
Segment Reporting [Abstract]
SEGMENT INFORMATION	5. SEGMENT INFORMATION Effective December 31, 2017, we revised our segment-level profit measure to earnings before interest, income taxes and depreciation and amortization from the previous measure of operating income (loss). The presentation of the prior year's tables has been revised in order to align with the current presentation. Our business has one operating segment, defined as a component of the enterprise, about which financial information is available and evaluated regularly by our Chief Operating Decision Maker, collectively comprised of our senior management, in deciding how resources are allocated and performance is assessed. Our reportable segment is a business unit that offers services and products and are managed based on our operating strategy. We have segregated our business activity in one operating segment: Liquids. The remainder of our business operations is presented as "Other" and consists of certain unallocated corporate costs. As of and for the year ended December 31, 2017 Total Revenues (1) Segment EBITDA/Consolidated Earnings Before Income Taxes Capital and Investment Expenditures Total Assets (in millions) Liquids $ 2,428 $ 1,674 $ 586 $ 14,819 Total reportable segment 2,428 1,674 586 14,819 Other (7 ) 9 Depreciation and amortization (442 ) Interest expense, net (525 ) Earnings before income tax expense 700 Income tax benefit 8 Net income from continuing operations 708 Net loss from discontinued operations (2) (57 ) Total consolidated $ 2,428 $ 651 $ 586 $ 14,828 ____________ (1) There were no intersegment revenues for the year ended December 31, 2017 . (2) The operating results of our disposed 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 7 - Dispositions and Discontinued Operations . As of and for the year ended December 31, 2016 Total Revenues (1) Segment EBITDA/Consolidated Earnings Before Income Taxes Capital and Investment Expenditures Total Assets (3) (in millions) Liquids $ 2,516 $ 964 $ 797 $ 13,031 Total reportable segment 2,516 964 797 13,031 Other (9 ) 165 Depreciation and amortization (427 ) Interest expense, net (413 ) Earnings before income tax expense 115 Income tax benefit 1 Net income from continuing operations 116 Net loss from discontinued operations (2) (157 ) Total consolidated $ 2,516 $ (41 ) $ 797 $ 13,196 ____________ (1) There were no intersegment revenues for the year ended December 31, 2016 . (2) The operating results of our disposed 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 7 - Dispositions and Discontinued Operations . (3) Comparative information excludes assets from discontinued operations. For further information refer to Note 7 - Dispositions and Discontinued Operations . As of and for the year ended December 31, 2015 Total Revenues (1) Segment EBITDA/Consolidated Earnings Before Income Taxes Capital and Investment Expenditures (in millions) Liquids $ 2,303 $ 1,441 $ 1,976 Total reportable segment 2,303 1,441 1,976 Other (29 ) Depreciation and amortization (378 ) Interest expense, net (292 ) Earnings before income tax expense 742 Income tax expense (3 ) Net income from continuing operations 739 Net loss from discontinued operations (2) (285 ) Total consolidated $ 2,303 $ 454 $ 1,976 ____________ (1) There were no intersegment revenues for the year ended December 31, 2015 . (2) The operating results of our disposed 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 7 - Dispositions and Discontinued Operations Substantially all of our consolidated revenues are earned in the United States and derived from a wide customer base. For the year ended December 31, 2017 , we had two non-affiliated customers that accounted for $392 million and $239 million , or 16.9% and 10.3% of our third-party revenues. For the years ended December 31, 2016 and 2015 , our largest non-affiliated customer accounted for $257 million and $338 million , or 10.7% and 15.6% of our third-party revenues, respectively. No other customers accounted for 10% or more of our third-party revenues during the years ended December 31, 2016 and 2015 .

REGULATORY MATTERS

REGULATORY MATTERS	12 Months Ended
	Dec. 31, 2017
Regulatory Assets and Liabilities Disclosure [Abstract]
REGULATORY MATTERS	6. REGULATORY MATTERS Financial Statement Effects Our over and under recovery revenue adjustments and net regulatory asset amortization for the years ended December 31, 2017 , 2016 , and 2015 are as follows: For the year ended December 31, 2017 2016 2015 (in millions) Net regulatory asset balance at beginning of year $ 12 $ 30 $ 6 Current year under recovery adjustments 3 12 30 Amortization of prior year regulatory asset (12 ) (30 ) (6 ) Net regulatory asset balance at end of year $ 3 $ 12 $ 30 Other Contractual Obligations Alberta Clipper Pipeline Property Taxes A portion of the rates we charge our customers includes an estimate for annual property taxes. If the estimated property tax we collect from our customers is higher or lower than the actual property tax imposed, we are contractually obligated to refund to our customers or entitled to collect from our customers 50% of the property tax over or under recovery, respectively and amortize the asset or liability on a straight line basis as an adjustment to revenue in the following year. Allowance for Equity Used During Construction We are permitted to capitalize and recover costs for rate-making purposes that include AEDC. In connection with construction of the Eastern Access, Mainline Expansion and Line 3 Replacement projects, we recorded $47 million , $46 million , and $70 million of AEDC on our consolidated statements of income at December 31, 2017 , 2016 and 2015 , respectively, with corresponding amounts to “Property, plant and equipment, net” on our consolidated statements of financial position for the respective periods. Tax Reform On December 22, 2017, United States legislation referred to as the "Tax Cuts and Jobs Act" (The TCJA) was signed into law. The TCJA includes a reduction in the corporate federal income tax rate from 35% to 21% . This tax rate change is expected to cause us to reduce the income tax allowance component of the tolls in its FERC regulated cost-of-service based Facility Surcharge Mechanism (FSM) projects. Impacts of tax reform will be realized in the first quarter of 2018 and will be reflected in Lakehead’s FSM toll filing for rates effective April 1, 2018. The TCJA had no material impact on our net regulatory asset balance at December 31, 2017 .

DISPOSITIONS AND DISCONTINUED O

DISPOSITIONS AND DISCONTINUED OPERATIONS	12 Months Ended
	Dec. 31, 2017
Discontinued Operations and Disposal Groups [Abstract]
DISPOSITIONS AND DISCONTINUED OPERATIONS	7. DISPOSITIONS AND DISCONTINUED OPERATIONS Dispositions For the year ended December 31, 2017 , we sold unnecessary pipe related to the Sandpiper Project for cash proceeds of approximately $112 million . A gain on disposal of $63 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 $220 million , including reimbursement costs. A gain on disposal of $11 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 $2.3 billion , which included cash consideration of $1.3 billion and outstanding indebtedness at MEP of $953 million . This sale included our 48.4% limited partnership interest in Midcoast Operating, our 51.9% limited partnership interest in MEP, and our 100% interest in Midcoast Holdings, L.L.C., MEP’s general partner. We recorded no gain or loss on the sale as this transaction was between entities under common control of Enbridge. The carrying value of the net assets sold was $4.3 billion . As a result of the transaction, partners’ capital decreased by $2.1 billion , all of which was allocated to the General Partner’s capital account. NCI in MEP of $297 million was eliminated. The following table presents the operating results from discontinued operations of our Midcoast gas gathering and processing business, which have been segregated from our continuing operations in our consolidated statements of income: For the year ended December 31, 2017 2016 2015 Operating revenues: Commodity sales $ 1,094 $ 1,786 $ 2,647 Transportation and other services 67 180 196 1,161 1,966 2,843 Operating expenses: Commodity costs 1,010 1,660 2,373 Operating and administrative 134 294 355 Depreciation and amortization 74 154 158 Asset impairment — 11 12 Goodwill impairment — — 227 1,218 2,119 3,125 Operating loss (57 ) (153 ) (282 ) Interest expense, net (18 ) (33 ) (30 ) Other income 19 31 29 Loss before income taxes (56 ) (155 ) (283 ) Income tax expense (1 ) (2 ) (2 ) Net loss from discontinued operations, net of tax $ (57 ) $ (157 ) $ (285 ) The following table presents the major classes of assets and liabilities for discontinued operations of our Midcoast gas gathering and processing business as presented in the consolidated statement of financial position: December 31, 2016 (in millions) Current assets related to discontinued operations: Cash and cash equivalents $ 7 Restricted cash 11 Receivables, trade and other, net of allowance for doubtful accounts 9 Due from General Partner and affiliates 2 Accrued receivables 21 Inventory 28 Other current assets 61 $ 139 Non-current assets related to discontinued operations: Property, plant and equipment, net $ 4,114 Equity investment in joint venture 361 Intangible assets, net 252 Other assets, net 48 $ 4,775 December 31, 2016 (in millions) Current liabilities related to discontinued operations: Accounts payable and other $ 67 Due to General Partner and affiliates 39 Accrued purchases 172 Property and other taxes payable 17 Interest payable 5 $ 300 Non-current liabilities related to discontinued operations: Long-term debt $ 818 Other long-term liabilities 26 $ 844

OTHER CURRENT ASSETS

OTHER CURRENT ASSETS	12 Months Ended
	Dec. 31, 2017
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
OTHER CURRENT ASSETS	8. OTHER CURRENT ASSETS December 31, 2017 2016 (in millions) Regulatory assets $ 3 $ 12 Prepaid expenses and other 15 16 Inventory 2 3 Other 4 3 Total other current assets $ 24 $ 34

PROPERTY, PLANT AND EQUIPMENT

PROPERTY, PLANT AND EQUIPMENT	12 Months Ended
	Dec. 31, 2017
Property, Plant and Equipment [Abstract]
PROPERTY, PLANT AND EQUIPMENT	9. PROPERTY, PLANT AND EQUIPMENT Weighted Average Depreciation Rate December 31, 2017 2016 (in millions) Land — $ 78 $ 79 Rights-of-way 2.92% 477 473 Pipelines 2.76% 8,731 8,571 Pumping equipment, buildings and tanks 3.16% 5,144 4,866 Vehicles, office furniture and equipment 3.35% 167 148 Construction in progress 1,109 864 Total property, plant and equipment 15,706 15,001 Accumulated depreciation (2,810 ) (2,393 ) Property, plant and equipment, net $ 12,896 $ 12,608 Depreciation expense for the years ended December 31, 2017 , 2016 , and 2015 , was $421 million , $408 million , and $366 million , respectively. On March 1, 2017, we completed the sale of the Ozark Pipeline system to a subsidiary of MPLX LP, refer to Note 7 - Dispositions and Discontinued Operations for further details. At December 31, 2016, the assets had a carrying value of $207 million , which was reclassified from "Property, plant and equipment, net" to "Assets held for sale" on our consolidated statements of financial position and measured at the lower of the carrying value or fair value less costs to sell, which did not result in a fair value adjustment. We ceased recognizing depreciation expense on these assets upon reclassification. On September 1, 2016, we announced that we applied for the withdrawal of regulatory applications pending with the MNPUC for the Sandpiper Project, included in our Liquids segment. In connection with this announcement and other factors, we evaluated the project for impairment. As a result of the analysis, we recognized an impairment loss of $757 million for the year ended December 31, 2016. Of that amount, $267 million was attributable to NCI. The estimated remaining fair value of $55 million of the Sandpiper Project was based on the estimated price that would be received to sell unnecessary pipe, land and other related equipment in its current condition, considering the current market conditions for sale of these assets. The valuation considered a range of potential selling prices from various alternatives that could be used to dispose of these assets. The estimated fair value, excluding $3 million in land, was reclassified to “Other assets, net.” During 2017, we disposed of substantially all of the remaining assets. Refer to Note 7 - Dispositions and Discontinued Operations for further details regarding the sale of unnecessary pipe related to the Sandpiper Project. During the year ended December 31, 2015, due to contracts that would not be renewed after 2016, we recorded an impairment loss of $63 million to write-off the remaining carrying value of our Berthold rail facility.

VARIABLE INTEREST ENTITIES

VARIABLE INTEREST ENTITIES	12 Months Ended
	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
VARIABLE INTEREST ENTITIES	10. VARIABLE INTEREST ENTITIES Consolidated Variable Interest Entities Enbridge Energy, Limited Partnership OLP is a Delaware limited partnership that has established several series of partnership interests. As of December 31, 2017 , we owned, directly or indirectly, 100% of the general partner interests in each series of OLP, as well as 100% of the Series LH and Series AC limited partner interests in OLP. In addition, including our ownership of the general partner interests, we directly and indirectly owned 40% , 25% and 1% of the Series EA, Series ME and Series L3R interests in OLP. Our General Partner owns the remaining 60% , 75% and 99% interests in Series EA, Series ME and Series L3R interests in OLP. We are the primary beneficiary of OLP because (i) through our ownership of the general partner interests in each of the OLP’s series and our limited partner interests in each series, we have the power to direct the activities that most significantly impact OLP’s economic performance; and (ii) we have the obligation to absorb losses and the right to receive residual returns that potentially could be significant to OLP. In addition, we are the entity within the related party group that is most closely associated with OLP. As of December 31, 2017 and 2016 , our consolidated statements of financial position include total assets of $11,676 million and $11,387 million , respectively, and total liabilities of $633 million and $760 million , respectively, related to OLP. Only the assets of OLP can be used to settle OLP’s obligations. We currently do not have any obligation to provide financial support to OLP, although from time to time, we may provide certain indemnities and guarantees for payment of specified liabilities to third parties in the event that OLP becomes in default under contracts with those third parties. North Dakota Pipeline Company, L.L.C. North Dakota Pipeline Company, L.L.C.(NDPC), is a Delaware limited liability company. As of December 31, 2017 , we directly owned 100% of the Class A units and 62.5% of the Class B units in NDPC. Williston Basin Pipeline LLC (Williston), an affiliate of MPC, owns the remaining 37.5% of Class B units in NDPC, which were used to fund the Sandpiper Project. We are the primary beneficiary of NDPC because (i) through our 100% ownership in NDPC’s Class A units and majority ownership in its Class B units, we have the power to direct the activities that most significantly impact NDPC’s economic performance; and (ii) we have the obligation to absorb losses and the right to receive residual returns that potentially could be significant to NDPC. As of December 31, 2017 and 2016 , our consolidated statements of financial position include total assets of $1,004 million and $1,045 million , respectively, and total liabilities of $41 million and $53 million , respectively, related to NDPC. Only the assets of NDPC can be used to settle NDPC’s obligations. We currently do not have any obligation to provide financial support to NDPC, although from time to time we may provide certain indemnities and guarantees for payment of specified liabilities to third parties in the event that NDPC becomes in default under contracts with those third parties. Enbridge Holdings (DakTex) L.L.C. On April 27, 2017, we finalized the 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. For more information regarding our equity investment, refer to Note 11 - Equity Investments in Joint Ventures . DakTex is considered a variable interest entity 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. As of December 31, 2017 , our consolidated statements of financial position include total assets of 1,547 million . DakTex does no t have any liabilities. Its sole asset is its investment in MarEn. The following table includes assets to be used to settle liabilities of our consolidated VIEs and liabilities of our consolidated VIEs for which creditors do not have recourse to our general credit as the primary beneficiary. These assets and liabilities are included in our consolidated statements of financial position. December 31, 2017 2016 (in millions) ASSETS Cash and cash equivalents $ 35 $ 37 Receivables, trade and other 62 2 Due from General Partner and affiliates 90 74 Accrued receivables 101 17 Other current assets 22 33 Property, plant and equipment, net 12,333 12,153 Equity investment in joint venture 1,547 — Other assets, net 37 116 LIABILITIES Accounts payable and other 147 168 Due to General Partner and affiliates 37 102 Interest payable 4 4 Environmental liabilities 23 100 Property and other taxes payable 102 87 Current portion of long-term debt 100 — Long-term debt 100 199 Other long-term liabilities $ 161 $ 153

EQUITY INVESTMENTS IN JOINT VEN

EQUITY INVESTMENTS IN JOINT VENTURES	12 Months Ended
	Dec. 31, 2017
Equity Method Investments and Joint Ventures [Abstract]
EQUITY INVESTMENTS IN JOINT VENTURES	11. EQUITY INVESTMENTS IN JOINT VENTURES The following table presents our equity investment in a joint venture with MPC and ownership interest in MarEn. Ownership Interest December 31, 2017 2016 (in millions) MarEn Bakken Company LLC 75 % $ 1,565 $ — On February 15, 2017, our joint venture with MCP, MarEn, closed its acquisition of an interest in the Bakken Pipeline System with Bakken Holdings Company LLC, and affiliate of Energy Transfer Partners, L.P. and Sunoco Logistics Partners L.P., to acquire a 49% equity interest in BPI, which 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 in to service on June 1 2017, which consists of DAPL and ETCOP. It connects the Bakken formation in North Dakota to markets in eastern PADD II and the United States Gulf Coast. For further details regarding out funding arrangement, refer to Note 20 - Related Party Transactions . We account for our investment in MarEn under the equity method of accounting. For the year ended December 31, 2017, we recognized $52 million in "Other income" in our consolidated statements of income representing our equity earnings for this investment, net of amortization of the excess of the purchase price over the underlying net book value (basis difference). Our equity investment includes basis difference of the investees' assets at the purchase date, which is comprised of $14 million in goodwill and $931 million in amortizable assets included within the Liquids segment. For the year ended December 31, 2017 , we amortized $23 million , which was recorded as a reduction to equity earnings. Our 75% aggregate investment in and earnings from MarEn is presented in "Equity investment in joint venture" on our consolidated statements financial position and "Other income" on our consolidated statements of income, respectively. The joint venture is included in our Liquids segment. The following tables present summarized balance sheet information as at December 31, 2017 and summarized income statement information for the year ended December 31, 2017. December 31, 2017 (in millions) Non-current assets $ 2,062 Total equity $ 2,062 December 31, 2017 (in millions) Income from equity investment $ 99 Amortization of basis difference (30 ) Net income $ 69

ACCOUNTS PAYABLE AND OTHER

ACCOUNTS PAYABLE AND OTHER	12 Months Ended
	Dec. 31, 2017
Payables and Accruals [Abstract]
ACCOUNTS PAYABLE AND OTHER	12. ACCOUNTS PAYABLE AND OTHER December 31, 2017 2016 (in millions) Short-term portion of derivative liabilities $ 9 $ 146 Accounts payable 74 78 Accrued liabilities 62 55 Contractor holdbacks 9 44 Deferred credits 13 14 Other current liabilities 2 6 Accrued purchases 4 5 Total accounts payable and other $ 173 $ 348

DEBT

DEBT	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
DEBT	13. DEBT The following table presents the primary components of our outstanding indebtedness with third parties and the interest rates associated with each component as of December 31, 2017 and 2016 , before the effect of our interest rate hedging activities. Our indebtedness with related parties is discussed in Note 20 - Related Party Transactions . December 31, 2017 2016 (in millions) EEP debt obligations: Commercial Paper (1) $ 1,303 $ 393 Credit Facilities due 2018 – 2022 (2) 150 1,265 6.500% senior notes due April 2018 400 400 9.875% senior notes due March 2019 500 500 5.200% senior notes due March 2020 500 500 4.375% senior notes due October 2020 500 500 4.200% senior notes due September 2021 600 600 5.875% senior notes due October 2025 500 500 5.950% senior notes due June 2033 200 200 6.300% senior notes due December 2034 100 100 7.500% senior notes due April 2038 400 400 5.500% senior notes due September 2040 550 550 7.375% senior notes due October 2045 600 600 Fixed to floating rate junior subordinated notes due 2067 (3) 400 400 OLP debt obligations: 7.000% senior notes due October 2018 100 100 7.125% senior notes due October 2028 100 100 Total debt 6,903 7,108 Unamortized discount (6 ) (6 ) Current portion of long-term debt (500 ) — Unamortized debt issuance costs (31 ) (36 ) Long-term debt $ 6,366 $ 7,066 ____________ (1) Individual issuances of commercial paper generally mature in 90 days or less, but are supported by our Credit Facilities and are therefore considered long-term debt as we have the ability and intent to refinance these long-term. The weighted average interest rate was 2.276% . (2) The interest rate was 2.744% (3) Effective October 1, 2017, the Junior Note bore interest at a variable rate equal to three months LIBOR for the related interest period increased by 3.798% . For the three months ended December 31, 2017 , the LIBOR rate was 1.335% . Commercial Paper Our commercial paper program provides for the issuance of up to an aggregate principal amount $1.5 billion of commercial paper and is supported by the availability of long-term committed credit facilities and therefore have been classified as long-term debt for the years ended December 31, 2017 and 2016, respectively, Credit Facilities The following table provides details of our committed Credit Facilities at December 31, 2017 : Maturity (1) Total Facilities Draws (2) (3) (4) Available (in millions) Enbridge Energy Partners, L.P. 2018 – 2022 $ 2,625 $ 1,453 $ 1,172 ____________ (1) Includes $175 million and $185 million of commitments that expire in 2018 and 2020, respectively. (2) Includes facility draws, letters of credit and commercial paper issuances that are back-stopped by the credit facility and excludes our credit agreement with EUS (the EUS 364-day Credit Facility.) (3) Under our commercial paper program, we had net borrowings of approximately $0.9 billion as of December 31, 2017 , which includes gross borrowings of $12.9 billion and gross repayments of $12.0 billion (4) Under our Credit Facilities, we had net repayments of approximately $1.1 billion as of December 31, 2017 , which includes gross borrowings of $1.9 billion and gross repayments of $3.0 billion At December 31, 2017, we had approximately $2.6 billion of committed bank Credit Facilities, which we use to fund our general activities and working capital needs. In addition to the committed bank credit facilities noted above, we maintain a $175 million uncommitted letter of credit facility. For the year ended December 31, 2017 and 2016 , $174 million and $71 million , respectively, were unutilized under this arrangement. Senior Notes Our senior notes represent unsecured obligations that rank equally in right of payment with all of our existing and future unsecured and unsubordinated indebtedness. Our senior notes have varying maturities and terms and are structurally subordinated to all existing and future indebtedness and other liabilities, including trade payables of our subsidiaries and the $200 million of senior notes issued by the OLP. The borrowings under our senior notes are non-recourse to our General Partner and Enbridge Management. We either pay or accrue interest semi-annually on our senior notes. The OLP has $200 million of senior notes outstanding representing unsecured obligations that are structurally senior to our senior notes, which we refer to as the OLP Notes. The OLP Notes consist of $100 million of 7.000% senior notes due in 2018 and $100 million of 7.125% senior notes due 2028. All of the OLP Notes pay interest semi-annually. The OLP Notes do not contain any covenants restricting the OLP from issuing additional indebtedness. The OLP Notes are subject to make-whole redemption rights and were issued under an indenture (the OLP Indenture) containing certain covenants that restrict our ability, with certain exceptions, to sell, convey, transfer, lease or otherwise dispose of all or substantially all of our assets, except in accordance with the OLP Indenture. We were in compliance with these covenants at December 31, 2017 . On October 6, 2015, we closed a public offering of $1.6 billion of senior unsecured notes, comprised of $ 500 million aggregate principal amount of notes due October 15, 2020 , $500 million aggregate principal amount of senior notes due October 15, 2025 and $600 million aggregate principal amount of notes due October 15, 2045 for net proceeds of approximately $1.6 billion after deducting underwriting discounts and commissions and offering expenses. In connection with the offering, we paid $315 million to settle certain pre-issuance hedges. Of that amount, a loss of $76 million was recognized in interest expense from ineffectiveness. The remaining loss of $238 million recorded in AOCI will be amortized as interest expense over a period of eight to ten years. As the pre-issuance hedge was designed to hedge the interest rate risk associated with the new debt, we have elected to classify the $238 million effective portion of the cash settlement, along with the $76 million of ineffectiveness included in interest expense, as “Net cash provided by operating activities” in the consolidated statement of cash flows. Junior Subordinated Notes The $400 million in principal amount of our fixed to floating rate, junior subordinated notes due 2067 (the Junior Notes) represent our unsecured obligations that are subordinate in right of payment to all of our existing and future senior indebtedness. Prior to October 1, 2017, the Junior Notes bore interest at a fixed annual rate of 8.05% , exclusive of any discounts or interest rate hedging activities, payable semi-annually in arrears on April 1 and October 1 of each year. Effective October 1, 2017, the Junior Notes bear interest at a variable rate equal to the three month LIBOR for the related interest period increased by 3.798% , payable quarterly in arrears on January 1, April 1, July 1 and October 1 of each year beginning January 1, 2018. We may elect to defer interest payments on the Junior Notes for up to ten consecutive years on one or more occasions, but not beyond the final repayment date. Until paid, any interest we elect to defer will bear interest at the prevailing interest rate, compounded quarterly. Post October 31, 2017, we may redeem the Junior Notes in whole at any time, or in part at a redemption price equal to the principal amount plus accrued and unpaid interest on the Junior Notes. Our right to optionally redeem the Junior Notes is also limited by our obligation to repay the Junior Notes on the scheduled maturity date which is limited by the Replacement Capital Covenants (Replacement Capital Covenants), which limits the types of financing sources we can use to redeem the Junior Notes in the same manner as to repay the Junior Notes, as outlined above. The Junior Notes do not restrict our ability to incur additional indebtedness. However, with limited exceptions, during any period we elect to defer interest payments on the Junior Notes, we cannot make cash distribution payments or liquidate any of our equity securities, nor can we or our subsidiaries make any principal and interest payments for any debt that ranks equally with or junior to the Junior Notes. Debt Covenants The Credit Facilities and the EUS 364-day Credit Facility contain, among other affirmative and negative covenants, certain financial covenants. A failure to comply with these covenants could result in an event of default under the Credit Facilities, which would prohibit us from declaring or making distributions to our unitholders and would permit acceleration of, and termination of our access to, our indebtedness under the Credit Facilities and the EUS 364-day Credit Facility, and may cause acceleration of our outstanding senior notes. Although we expect to be able to comply with these covenants under each of our Credit Facilities and the EUS 364-day Credit Facility, there can be no assurance that in the future we will be able to do so or that our lenders will be willing to waive such non-compliance or further amend such covenants. As of December 31, 2017 , we were in compliance with the terms of all of our financial covenants under the Credit Facilities and the EUS 364-day Credit Facility. Interest Cost Our interest cost for the years ended December 31, 2017 , 2016 and 2015 is comprised of the following: For the year ended December 31, 2017 2016 2015 (in millions) Term notes (1) $ 531 $ 428 $ 307 Commercial paper and credit facility draws 38 33 24 Less: Interest capitalized (44 ) (48 ) (39 ) Interest expense, net $ 525 $ 413 $ 292 ____________ (1) For the year ended December 31, 2017, interest expense includes reclassification of $168 million loss related to the termination of long-term interest rate swaps as not highly probable to issue long-term debt.

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS	12 Months Ended
	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
ASSET RETIREMENT OBLIGATIONS	14. ASSET RETIREMENT OBLIGATIONS Our AROs relate mostly to the retirement of our crude oil and liquid petroleum pipelines and storage facilities. A reconciliation of movements to our ARO liabilities is as follows: December 31, 2017 2016 (in millions) Balance at beginning of year $ 98 $ 100 Revisions in estimates 3 (1 ) Accretion expense 5 1 Liabilities settled — (2 ) Balance at end of year $ 106 $ 98 ARO liabilities of $2 million and $104 million are included in "Accounts payable and other" and "Other long-term liabilities," respectively, on our consolidated statements of financial position.

NONCONTROLLING INTERESTS

NONCONTROLLING INTERESTS	12 Months Ended
	Dec. 31, 2017
Noncontrolling Interest [Abstract]
NONCONTROLLING INTERESTS	15. NONCONTROLLING INTERESTS The following tables present additional information regarding NCI as presented on our consolidated statements of financial position and net income (loss) attributable to NCI as presented on our consolidated statements of income: December 31, 2017 2016 (in millions) Eastern Access Interests (1) $ 1,465 $ 1,892 U.S. Mainline Expansion Interests (1) 1,643 1,621 North Dakota Pipeline Company Interests (2) 15 30 Line 3 Replacement Interests (1) 686 — Enbridge Holdings (DakTex) L.L.C. Interests (3) 1,160 — Total $ 4,969 $ 3,543 ____________ (1) Represents the NCI in the OLP arising from the joint funding arrangements with our General Partner and its affiliate to finance certain expansion projects on our Lakehead System, which we refer to as the Eastern Access Project, Mainline Expansion Project and U.S. Line 3 Replacement Program. (2) Represents the NCI in NDPC arising from our agreement with Williston, an affiliate of MPC. (3) Represents the NCI in DakTex arising from the joint funding arrangement with our General Partner to finance our investment in the Bakken Pipeline System through our equity investment in MarEn. For the year ended December 31, 2017 2016 2015 (in millions) Alberta Clipper Interests $ — $ — $ (1 ) Eastern Access Interests 152 205 190 U.S. Mainline Expansion Interests 147 138 108 North Dakota Pipeline Company Interests (1) 21 (271 ) — Line 3 Replacement Interests 29 — — Enbridge Holdings (DakTex) L.L.C. Interests 39 — — Midcoast Energy Partners, L.P. - Discontinued Operations (19 ) (46 ) (76 ) Total $ 369 $ 26 $ 221 ____________ (1) Inclusive of impairment on the Sandpiper Project attributable to NCI for the year ending December 31, 2016 . For further details, see Note 9 - Property, Plant and Equipment . On June 28, 2017, we completed the Midcoast sale to our General Partner, reducing our NCI in MEP to nil upon the closing of the sale. For further details refer to Note 7 - Dispositions and Discontinued Operations . 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% . NCI represent our General Partner’s 75% interest. For further details refer to Note 20 - Related Party Transactions . On January 26, 2017, we entered into a joint funding arrangement with our General Partner for the 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 million and was recorded as an increase to NCI. The $40 million difference between the cash received and the carrying amount was recorded as an increase to the capital accounts of our common units, i-units, and General Partner interest on a pro-rated basis. For further details, refer to Note 20 - 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 NCI by approximately $360 million . We and our General Partner own 40% and 60% of the partnership interest in Series EA of the OLP, which we refer to as the EA interest, respectively. For further details, refer to Note 20 - Related Party Transactions .

PARTNERS' CAPITAL

PARTNERS' CAPITAL	12 Months Ended
	Dec. 31, 2017
Partners' Capital Notes [Abstract]
PARTNERS’ CAPITAL	16. PARTNERS' CAPITAL Our authorized share capital consists of an unlimited number of common shares with no par value. 2017 Series 1 preferred units Class D units Class E units Class F units Class A common units Class B common units i-units Incentive distribution units Balance at beginning of year 48,000,000 66,100,000 18,114,975 — 262,208,428 7,825,500 81,857,168 1,000 Waiver of units (48,000,000 ) (66,100,000 ) — — — — — (1,000 ) Issuances — — — 1,000 64,308,682 — — — Distributions — — — — — — 7,941,650 — Balance at end of year — — 18,114,975 1,000 326,517,110 7,825,500 89,798,818 — 2016 Balance at beginning of year 48,000,000 66,100,000 18,114,975 — 262,208,428 7,825,500 73,285,739 1,000 Distributions — — — — — — 8,571,429 — Balance at end of year 48,000,000 66,100,000 18,114,975 — 262,208,428 7,825,500 81,857,168 1,000 2015 Balance at beginning of year 48,000,000 66,100,000 — — 254,208,428 7,825,500 68,305,187 1,000 Issuances — — 18,114,975 — 8,000,000 — — — Distributions — — — — — — 4,980,552 — Balance at end of year 48,000,000 66,100,000 18,114,975 — 262,208,428 7,825,500 73,285,739 1,000 Our capital accounts are comprised of a 2% general partner interest and 98% limited partner interests. Our limited partner interests at December 31, 2017 , include Class E units, Class F units, Class A and Class B common units, and i-units. We refer to our Class A and Class B common units collectively as common units. Our limited partners have limited rights of ownership as provided for under our partnership agreement and, as discussed below, the right to participate in our distributions. Our General Partner manages our operations, subject to a delegation of control agreement with Enbridge Management, and participates in our distributions. Issuance of Class A Units On April 27, 2017, we funded the redemption of the Series 1 Preferred Units through the issuance of 64 million Class A common units to our General Partner at a price of $18.66 per Class A common unit. The Class A common units were recognized 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. The following table presents the net proceeds from our Class A common unit issuances for the year ended December 31, 2017 and 2015 . There were no issuances of Class A common units for the years ended December 31, 2016 . Issuance Date Number of Class A common unit Issued Offering Price per Class A common units Net Proceeds to the Partnership (1) General Partner Contribution (2) Net Proceeds Including General Partner Contribution (in millions, except units and per unit amounts) April, 2017 64,308,682 $ 18.66 $ 1,200 $ 24 $ 1,224 March, 2015 8,000,000 $ 36.70 $ 289 $ 6 $ 295 (1) Net of underwriters’ fees and discounts, commissions and issuance expenses. (2) Contributions made by the General Partner to maintain its 2% general partner interest. The proceeds from the April 2017 issuance were used to redeem in full our $1.2 billion of outstanding Series 1 Preferred Units held by our General Partner. The proceeds from the March 2015 offering were used to fund a portion of our capital expansion projects and for general partnership purposes. 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 $9 million was recorded against the capital balance of the General Partner. Additionally, we repaid $357 million in deferred distributions on the Series 1 Preferred Units owed to our General Partner upon the closing of the Midcoast sale. 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 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 units and IDUs by a wholly-owned subsidiary of our General Partner represents an extinguishment, resulting in a de-recognition of the Class D units and IDUs at their carrying value. The Class F units were recorded at their fair value of $263 million and the difference between the fair value of the Class F units and the de-recognized Class D units and IDUs 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. Alberta Clipper Drop Down On January 2, 2015, we completed a transaction (the Drop Down) pursuant to which we acquired the remaining 66.7% interest in the United States segment of the Alberta Clipper Pipeline from our General Partner. The consideration consisted of approximately 18,114,975 Class E units representing limited partner interests issued to the General Partner. The Class E units were issued at a notional value of $38.31 per unit, determined based on a trailing five -day volume weighted average of our Class A common units as of the date we entered into a contribution agreement with our General Partner outlining the terms of the Drop Down and repaid outstanding borrowings of $306 million to the General Partner. The Class E units are entitled to the same distributions as Class A common units held by the public and are convertible into Class A common units on a one-for-one basis at the General Partner’s option. The Class E units are redeemable at our option after 30 years, if not earlier converted by the General Partner. The Class E units have a liquidation preference equal to their notional value at December 23, 2014 of $38.31 per unit, which is also the liquidation value of the units. If the aggregate EBITDA attributable to the Series AC interest in the OLP for calendar years 2015 and 2016 is less than $266 million , then 1,305,142 of the Class E units were to be cancelled by us. Aggregate EBITDA exceeded the threshold, and therefore no Class E units were cancelled. In addition, during each taxable year during the period from January 1, 2015 through December 31, 2037 in which a majority of the Class E units issued on the closing date of the Drop Down remain outstanding, holders of Class A common units and Class B common units will be specially allocated items of gross income that would otherwise be allocated to holders of Class E units, to the extent that such an amount of gross income exists, in an annual amount equal to $40 million . The annual amount of such allocation will be reduced to $20 million for each taxable year beginning after December 31, 2037. We recorded the Drop Down as an equity transaction. No loss on the acquisition of the remaining ownership interests in Alberta Clipper was recognized in our consolidated statement of income or comprehensive income. We reduced the carrying value of the related NCI in Alberta Clipper of $404 million to zero . In addition, we recorded the Class E units at their fair value of $768 million . We determined the fair value of the Class E units using a market approach based upon the closing price of the Class A common units as of January 2, 2015, adjusted for differences in specific rights such as the liquidation preference granted to the Class E units and other economic factors that would affect the fair value of the Class E units. The difference of $364 million between the fair value of the Class E units and the carrying value of the NCI in Alberta Clipper was recorded as a reduction to the carrying amounts of the capital accounts of the Class A and Class B common units, the i-units and the General Partner interest on a pro-rated basis. The recording of this transaction reduced the carrying values of the Class A and Class B common units below zero. Our partnership agreement requires that such capital account deficits are brought back to zero, or “cured,” by additional allocations from the capital accounts of the i-units and General Partner interest on a pro-rated basis. As a result the i-units’ and General Partner interest’s capital balances were reduced by $47 million and $1 million , respectively, to cure the deficit balances in the Class A and Class B common units. This initial curing did not impact earnings allocated to either the i-units or the General Partner interest. Class B common units All of our outstanding Class B common units are held by our General Partner and have rights similar to our Class A common units, except with respect to certain allocations of taxable income. Class B common units are not publicly traded. i-units The i-units are a separate class of our limited partner interests, all of which are owned by Enbridge Management and are not publicly traded. Enbridge Management, as the owner of our i-units, votes together with the holders of the common units as a single class. However, the i-units vote separately as a class on the following matters: • Any proposed action that would cause us to be treated as a corporation for United States federal income tax purposes; • Amendments to our partnership agreement that would have a material adverse effect on the holder of our i-units, unless, under our partnership agreement, the amendment could be made by our General Partner without a vote of holders of any class of units; • The removal of our General Partner and the election of a successor general partner; and • The transfer by our General Partner of its general partner interest to a non-affiliated person that requires a vote of holders of units under our partnership agreement and the admission of that person as a general partner. In all cases, Enbridge Management will vote or refrain from voting its i-units in the same manner that owners of Enbridge Management’s listed shares vote or refrain from voting their listed shares. Furthermore, under the terms of our partnership agreement, we agree that we will not, except in liquidation, make a distribution on an i-unit other than in additional i-units or a security that has in all material respects the same rights and privileges as the i-units. Curing Our limited partnership agreement does not permit capital deficits to accumulate in the capital accounts of any limited partner and thus requires that such capital account deficits be “cured” by additional allocations from the positive capital accounts of the common units, i-units, and our General Partner, generally on a pro-rated basis. For the year ended December 31, 2017 , the carrying amounts for the capital accounts of the Class B common units were reduced below zero due to distributions to limited partners in excess of earnings and were subsequently cured. Class A units and i-units had positive capital balances and therefore, as outlined in the partnership agreement, we allocated earnings of $71 million to our General Partner to recover previous curing allocations made by the General Partner. For the year ended December 31, 2016 , the carrying amounts for the capital accounts of the Class A and Class B common units were reduced below zero due to distributions to limited partners in excess of earnings attributable to such limited partners. As a result, the capital balance of the i-units and our General partner interests were reduced by $126 million and $790 million , respectively, to cure the applicable deficit balance. Distributions Our partnership agreement requires us to distribute 100% of our “available cash”, which is generally defined in our partnership agreement as the sum of all cash receipts plus reductions in cash reserves established in prior quarters less cash disbursements and additions to cash reserves in that calendar quarter. Enbridge Management, as delegate of our General Partner under the delegation of control agreement, computes the amount of our “available cash.” Typically, our General Partner and owners of our common units will receive distributions in cash. We also retain reserves to provide for the proper conduct of our business, to stabilize distributions to our unitholders and our General Partner and, as necessary, to comply with the terms of our agreements or obligations (including any reserves required under debt instruments for future principal and interest payments and for future capital expenditures). We make distributions to our partners no later than 45 days following the end of each calendar quarter in accordance with their respective percentage interests. Our General Partner is granted discretion by our partnership agreement, which discretion has been delegated to Enbridge Management, subject to the approval of our General Partner in certain cases, to establish, maintain and adjust reserves for future operating expenses, debt service, maintenance capital expenditures, and distributions for the next four quarters. These reserves are not restricted by magnitude, but only by type of future cash requirements with which they can be associated. When Enbridge Management determines our quarterly distributions, it considers current and expected reserve needs along with current and expected cash flows to identify the appropriate sustainable distribution level. Distributions of our available cash are generally made 98% to holders of our limited partner units and 2% to our General Partner. However, distributions are subject to the payment of incentive distributions to our General Partner to the extent that certain target levels of distributions to the unitholders are achieved. Effective April 27, 2017, the wholly-owned subsidiary of our General Partner irrevocable waived all of its rights associated with its 66 million Class D units and 1,000 IDUs, in exchange for the issuance of 1,000 Class F units. Refer to Note 4 - Net Income Per Limited Partner Unit for further details regarding our distributions. As set forth in our partnership agreement, cash distributions declared on our i-units will be paid by a distribution of additional i-units such that the cash is retained and used in our operations and to finance a portion of our capital expansion projects. Enbridge Management, as holder of the i-units, does not receive distributions in cash. Instead, each time that we make a cash distribution in respect to our General Partner interest, Class A common units, Class B common units and Class E units, the number of i-units owned by Enbridge Management and the percentage of our total units owned by Enbridge Management will increase automatically under the provisions of our partnership agreement with the result that the number of i-units owned by Enbridge Management will equal the number of Enbridge Management’s listed and voting shares that are then outstanding. The amount of this increase in i-units is determined by dividing the cash amount distributed per common unit by the average price of one of Enbridge Management’s listed shares on the NYSE for the 10 trading day period immediately preceding the ex-dividend date for Enbridge Management’s shares multiplied by the number of shares outstanding on the record date. The cash equivalent amount of the additional i-units is treated as if it had actually been distributed for purposes of determining the distributions to be made to our General Partner. Distribution to Partners' The following table sets forth our distributions, as approved by the board of directors of Enbridge Management, during the years ended December 31, 2017 , 2016 and 2015 . Distribution Declaration Date Record Date Distribution Payment Date Distribution per Unit Cash Available for Distribution Amount of Distribution of i-units to i-unit Holders (1) Retained from General Partner (2) Distribution of Cash (in millions, except per unit amounts) 2017 October 27 November 7 November 14 $ 0.350 $ 161 $ 30 $ 1 $ 130 July 28 August 7 August 14 $ 0.350 160 29 1 130 April 27 May 8 May 15 $ 0.350 160 30 1 129 January 26 February 7 February 14 $ 0.583 265 48 1 216 $ 746 $ 137 $ 4 $ 605 2016 October 28 November 7 November 14 $ 0.583 $ 264 $ 47 $ 1 $ 216 July 28 August 5 August 12 $ 0.583 262 45 1 216 April 29 May 6 May 13 $ 0.583 261 44 1 216 January 29 February 5 February 12 $ 0.583 260 43 1 216 $ 1,047 $ 179 $ 4 $ 864 2015 October 30 November 6 November 13 $ 0.583 $ 259 $ 41 $ 1 $ 217 July 30 August 7 August 14 $ 0.583 258 41 1 $ 216 April 30 May 8 May 15 $ 0.570 250 40 1 $ 209 January 29 February 6 February 13 $ 0.570 234 39 1 $ 194 $ 1,001 $ 161 $ 4 $ 836 ____________ (1) We issued 7,941,650 , 8,571,429 and 4,980,552 i-units to Enbridge Management, L.L.C., the sole owner of our i-units, during 2017 , 2016 and 2015 , respectively, in lieu of cash distributions. (2) We retained an amount equal to 2% of the i-unit distribution from our General Partner to maintain its 2% general partner interest in us.

DERIVATIVE FINANCIAL INSTRUMENT

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES	12 Months Ended
	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES	17. DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES Our net income and cash flows are subject to volatility stemming from changes in interest rates on our variable rate debt obligations and fluctuations in commodity prices of crude oil. 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 interest rate risk exposure results from changes in interest rates on our variable rate debt. 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: December 31, 2017 2016 (in millions) Accounts payable and other (9 ) (146 ) Other long-term liabilities (2 ) (21 ) $ (11 ) $ (167 ) The changes in the 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. The table below summarizes our derivative balances by counterparty credit quality (any negative amounts represent our net obligations to pay the counterparty). December 31, 2017 2016 (in millions) Counterparty Credit Quality (1) AA $ (4 ) $ (79 ) A (7 ) (59 ) Lower than A — (29 ) $ (11 ) $ (167 ) ____________ (1) As determined by nationally-recognized statistical ratings organizations. When credit thresholds are met pursuant to the terms of our 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 December 31, 2017 and 2016 , we did not have any cash collateral. Cash collateral is classified as “Restricted cash” in our consolidated statements of financial position. We provided no letters of credit relating to our liability exposure pursuant to margin threshold in effect at December 31, 2017 . We provided letters of credit totaling $120 million at December 31, 2016 , 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 S&P 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 December 31, 2017 we would have been required to provide additional letters of credit in the amount of $12 million related to our positions. At December 31, 2017 and 2016 , we had credit concentrations in the following industry sectors, as presented below: December 31, 2017 2016 (in millions) United States financial institutions and investment banking entities $ (7 ) $ (122 ) Non-United States financial institutions (4 ) (45 ) $ (11 ) $ (167 ) 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 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 December 31, Fair Value at December 31, Financial Position Location 2017 2016 2017 2016 (in millions) Derivatives designated as hedging instruments: (1) Interest rate contracts Accounts payable and other $ — $ — $ (5 ) $ (144 ) Interest rate contracts Other long-term liabilities — — (1 ) (21 ) — — (6 ) (165 ) Derivatives not designated as hedging instruments: Commodity contracts Accounts payable and other — — (4 ) $ (2 ) Commodity contracts Other long-term liabilities — — (1 ) — — — (5 ) (2 ) Total derivative instruments $ — $ — $ (11 ) $ (167 ) ____________ (1) Includes items currently designated as hedging instruments. Excludes the portion of de-designated hedges which may have a component remaining in AOCI. Accumulated Other Comprehensive Income We record the change in fair value of our effective cash flow hedges in AOCI until the derivative financial instruments are settled, at which time they are reclassified to earnings. As of December 31, 2017 and 2016 , we included in AOCI unrecognized losses of approximately $192 million and $223 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 year ended December 31, 2017 and 2016 . We estimate that approximately $36 million , representing unrealized net losses from our cash flow hedging activities based on pricing and positions at December 31, 2017 , will be reclassified from AOCI to earnings during the next 12 months. Effect of Derivative Instruments on the Consolidated Statements of Income and Accumulated Other Comprehensive Income Derivatives in Cash Flow Hedging Relationships Amount of Gain (Loss) Recognized in AOCI on Derivative (Effective Portion) Location of Gain (Loss) Reclassified from AOCI to Earnings (Effective Portion) Amount of Gain (Loss) Reclassified from AOCI to Earnings (Effective Portion) (1) Location of Gain (Loss) Recognized in Earnings on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing) (1) Amount of Gain (Loss) Recognized in Earnings on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing) (2) (in millions) For the year ended December 31, 2017 Interest rate contracts $ 109 Interest expense $ (208 ) Interest expense $ 50 Total $ 109 $ (208 ) $ 50 For the year ended December 31, 2016 Interest rate contracts $ (1 ) Interest expense $ (39 ) Interest expense $ (7 ) Total $ (1 ) $ (39 ) $ (7 ) For the year ended December 31, 2015 Interest rate contracts $ 87 Interest expense $ (22 ) Interest expense $ 99 Total $ 87 $ (22 ) $ 99 ____________ (1) Includes reclassification of $168 million loss related to the termination of long-term interest rate swaps as not highly probable to issue long-term debt. (2) 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 Cash Flow Hedges 2017 2016 (in millions) Balance at January 1 $ (339 ) $ (370 ) Other comprehensive income before reclassifications (68 ) (8 ) Amounts reclassified from AOCI (1)(2) 208 39 Net other comprehensive income 140 31 Balance at December 31 $ (199 ) $ (339 ) ____________ (1) For additional details on the amounts reclassified from AOCI, reference the Reclassifications from Accumulated Other Comprehensive Income table below. (2) Includes reclassification of $168 million loss related to the termination of long-term interest rate swaps as not highly probable to issue long-term debt. Reclassifications from Accumulated Other Comprehensive Income For the year ended December 31, 2017 2016 2015 (in millions) Losses on cash flow hedges: Interest Rate Contracts (1) $ 208 $ 39 $ 22 Total Reclassifications from AOCI $ 208 $ 39 $ 22 ____________ (1) Loss reported within “Interest expense, net” in the consolidated statements of income. Effect of Derivative Instruments on Consolidated Statements of Income Derivatives Not Designated as Hedging Instruments Location of Gain (Loss) Recognized in Earnings December 31, 2017 2016 2015 Amount of Gain (Loss) Recognized in Earnings (1)(2) (in millions) Commodity contracts Transportation and other services (3) $ (3 ) $ (3 ) $ 11 Total $ (3 ) $ (3 ) $ 11 ____________ (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 nil , $6 million , and $27 million for the years ended December 31, 2017 , 2016 and 2015 , respectively. We record the fair market value of our derivative financial and physical instruments in the consolidated statements of financial position as current and long-term assets or liabilities on a gross basis. However, the terms of the ISDA®, which govern our financial contracts and our other master netting agreements, allow the parties to elect in respect of all transactions under the agreement, in the event of a default and upon notice to the defaulting party, for the non-defaulting party to set-off all settlement payments, collateral held and any other obligations (whether or not then due), which the non-defaulting party owes to the defaulting party. The effect of the rights of set-off are outlined below. Offsetting of Financial Liabilities and Derivative Liabilities As of December 31, 2017 Gross Amount of Recognized Liabilities Gross Amount Offset in the Statement of Financial Position Net Amount of Liabilities Presented in the Statement of Financial Position Gross Amount Not Offset in the Statement of Financial Position Net Amount (in millions) Description: Derivatives $ (11 ) $ — $ (11 ) $ — $ (11 ) As of December 31, 2016 Gross Amount of Recognized Liabilities Gross Amount Offset in the Statement of Financial Position Net Amount of Liabilities Presented in the Statement of Financial Position Gross Amount Not Offset in the Statement of Financial Position Net Amount (in millions) Description: Derivatives $ (167 ) $ — $ (167 ) $ — $ (167 ) Inputs to Fair Value Derivative Instruments The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2017 and 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 ended December 31, 2017 and 2016 , we did not have any Level 3 derivative instruments. December 31, 2017 December 31, 2016 Level 2 Level 2 (in millions) Interest rate contracts $ (6 ) $ (165 ) Commodity contracts: Financial (5 ) (2 ) $ (11 ) $ (167 ) 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 The following table provides summarized information about the fair values of expected cash flows of our outstanding commodity based swaps and physical contracts at December 31, 2017 and 2016 . At December 31, 2017 At December 31, 2016 Wtd. Average Price (2) Fair Value (3) Fair Value (3) Commodity Notional (1) Receive Pay Asset Liability Asset Liability Portion of contracts matured in 2017 Swaps: Receive fixed/pay variable Crude Oil 123,832 $ 51.91 $ 51.98 $ — $ — $ — $ (2 ) Portion of contracts maturing in 2018 Swaps: Receive fixed/pay variable Crude Oil 498,955 $ 50.71 $ 59.31 $ — $ (4 ) $ — $ — Portion of contracts maturing in 2019 Swaps: Receive fixed/pay variable Crude Oil 353,685 $ 55.22 $ 55.86 $ — $ (1 ) $ — $ — ____________ (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 December 31, 2017 and 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 December 31, 2017 and 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. The following table provides information about our current interest rate derivatives for the specified periods. Date of Maturity & Contract Type Accounting Treatment Notional Average Fixed Rate (1) Fair Value (2) at December 31, 2017 December 31, 2016 (in millions) Contracts matured in 2017 Interest Rate Swaps – Pay Fixed Cash Flow Hedge $ 500 2.21 % $ — $ (1 ) Contracts maturing in 2018 Interest Rate Swaps – Pay Fixed Cash Flow Hedge $ 810 2.24 % $ — $ (9 ) Contracts maturing in 2019 Interest Rate Swaps – Pay Fixed Cash Flow Hedge $ 620 2.96 % $ (6 ) $ (7 ) Contracts settled prior to maturity 2017 - Pre-issuance Hedges Cash Flow Hedge $ 1,000 4.07 % $ — $ (136 ) 2018 - Pre-issuance Hedges Cash Flow Hedge $ 350 3.08 % $ — $ (13 ) ____________ (1) Interest rate derivative contracts are based on the one-month or three-month LIBOR. (2) The fair value is determined from quoted market prices at December 31, 2017 and 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 nil and $1 million at December 31, 2017 and 2016 , respectively. Fair Value Measurements of Other Financial Instruments 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 December 31, 2017 and 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 $5.8 billion and $6.1 billion at December 31, 2017 and 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.

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
INCOME TAXES	18. INCOME TAXES We compute our income tax expense by applying a Texas state franchise tax rate to modified gross margin. Subsequent to the Midcoast sale, we are no longer subject to the Texas Margin Tax since all of our Texas activity was a result of owning these assets. For the years ended December 31, 2017 , 2016 and 2015 , our Texas state franchise tax rate was 0.4% . Our income tax expense is summarized below: For the year ended December 31, 2017 2016 2015 (in millions) Current state $ (5 ) $ 3 $ 4 Deferred state (3 ) (4 ) (1 ) Total income tax (benefit) expense $ (8 ) $ (1 ) $ 3 Our effective tax rate is calculated by dividing the income tax expense by the pretax net book income or loss. The income base for calculating our income tax expense is modified gross margin for Texas rather than pretax net book income or loss. As a result, this difference is the only reconciling item between the statutory and effective income tax rate. Our effective tax rate is as follows: For the year ended December 31, 2017 2016 2015 (in millions) Income before income tax $ 700 $ 115 $ 742 State income tax (benefit) expense $ (8 ) $ (1 ) $ 3 Effective income tax rate (1.1 )% (0.9 )% 0.4 % Accounting for Uncertainty in Income Taxes The following is a reconciliation of our beginning and ending balance of unrecognized tax benefits in millions: December 31, 2017 2016 2015 (in millions) Unrecognized tax benefits at January 1 $ 39 $ 37 $ 33 Additions for tax positions taken in current period 1 2 4 Lapses of statute of limitations (6 ) — — Unrecognized tax benefits at December 31 $ 34 $ 39 $ 37 As of December 31, 2017 , 2016 and 2015 , the entire balance of unrecognized tax benefits would favorably affect our effective tax rate in future periods if recognized. It is reasonably possible that our liability for unrecognized tax benefits will no t change during the next twelve months. We also recognized interest accrued related to unrecognized tax benefits and penalties as income tax expense. As of December 31, 2017 , we accrued penalties of $1 million and interest of $1 million . As of December 31, 2016 , we accrued penalties of $2 million and interest of $1 million . Furthermore, we recognize accrued interest income related to unrecognized tax benefits in interest income when the related unrecognized tax benefits are recognized. As such, at December 31, 2017 and 2016 , $1 million and $1 million of accrued interest income, respectively, has not been included in the balance of unrecognized tax benefits. Our tax years are generally open to examination by the IRS and state revenue authorities for calendar years ended December 31, 2017, 2016 and 2015. US TAX REFORM On December 22, 2017, United States legislation referred to as the "Tax Cuts and Jobs Act" (the TCJA) was signed into law. Substantially all of the provisions of the TCJA are effective for taxable years beginning after December 31, 2017. The TCJA includes significant changes to the Internal Revenue Code of 1986 (as amended, the Code), including amendments which significantly change the taxation of individual and business entities. The most significant change included in the TCJA is a reduction in the corporate federal income tax rate from 35% to 21%. Changes in the Code from the TCJA did not have a material impact on our financial statements in 2017.

CHANGES IN OPERATING ASSETS AND

CHANGES IN OPERATING ASSETS AND LIABILITIES	12 Months Ended
	Dec. 31, 2017
Supplemental Cash Flow Information [Abstract]
CHANGES IN OPERATING ASSETS AND LIABILITIES	19. CHANGES IN OPERATING ASSETS AND LIABILITIES Changes in our working capital accounts are shown in the following table: For the year ended December 31, 2017 2016 2015 (in millions) Receivables, trade and other (59 ) 6 18 Due from General Partner and affiliates (26 ) (42 ) (31 ) Accrued receivables (86 ) 3 9 Inventory 1 — 10 Current and long-term other assets 47 8 (40 ) Due to General Partner and affiliates (127 ) (14 ) 28 Accounts payable and other (26 ) (76 ) 5 Environmental liabilities (91 ) (19 ) (44 ) Accrued purchases (2 ) 3 2 Interest payable (5 ) (4 ) 24 Current income tax payable 1 (2 ) — Property and other taxes payable 15 7 10 Changes in operating assets and liabilities (358 ) (130 ) (9 )

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS	12 Months Ended
	Dec. 31, 2017
Related Party Transactions [Abstract]
RELATED PARTY TRANSACTIONS	20. 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 $17 million and $28 million for the year ended December 31, 2017 and 2016 , respectively, that we recorded as additions to “Property, plant and equipment, net” on our consolidated statements of financial position. Service Agreements Our General Partner, Enbridge Management, Enbridge and affiliates of Enbridge provide managerial, administrative, operational and director services to us pursuant to service agreements and we reimburse them for the costs of those services. Through an operational services agreement among Enbridge and Enbridge Operational Services, Inc., whom we refer to as the Canadian service provider, and us, we are charged for the services of Enbridge employees resident in Canada. Through a general and administrative services agreement among us, our General Partner, Enbridge Management and Enbridge Employee Services, Inc.(EES), we are charged for the services of employees resident in the United States. The charges related to these service agreements are included in “Operating and administrative — affiliate” expenses on our consolidated statements of income. Operational Services Agreement We are charged an amount by the Canadian service providers for services we are provided under the operational services agreement. The amount we are charged is established as part of the annual budget and agreed upon by us and the Canadian service providers. The amount we are charged is computed based on an estimate of the pro-rated reimbursement of each Canadian service provider’s estimated annual departmental costs, net of amounts charged to other affiliates and amounts identifiable as costs of that Canadian service provider. The total amount we reimbursed the Canadian service providers pursuant to the operational services agreement for the years ended December 31, 2017 , 2016 and 2015 , was $133 million , $106 million , $131 million , respectively. General and Administrative Services Agreement We, Enbridge Management and our General Partner receive services from EES under the general and administrative services agreement. Under this agreement, EES provides services to us, Enbridge Management and our General Partner and charges each recipient for services, on a monthly basis, the actual costs that it incurs for those services. Our General Partner and Enbridge Management may request that EES provide special additional general services for which each, as appropriate, agrees to pay costs and expenses incurred by EES in connection with providing the special additional general services. The total amount reimbursed by us for services received pursuant to the general and administrative services agreement for the years ended December 31, 2017 , 2016 and 2015 , was $201 million , $229 million , $216 million , respectively. Enbridge Pipelines (FSP) LLC Cushing Terminal Transfer In August 2017, Enbridge Pipelines (FSP) L.L.C., (FSP), a wholly-owned subsidiary of our General Partner, completed an asset transfer of a capital project which involved modification and upgrades to the existing Cushing terminal facilities that are owned by our subsidiary, Enbridge Storage (Cushing) L.L.C. The transfer of assets was accounted for as a transaction between entities under common control as both FSP and we are related through common ownership by the General Partner. The assets were transferred at cost of $68 million and were recognized as a capital contribution from our General Partner. 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 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 year ended December 31, 2017 and 2016 , we sold and derecognized receivables of $473 million and $1,773 million , respectively to an indirect, wholly-owned subsidiary of Enbridge and received cash proceeds of $472 million and $1,772 million , 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 year ended December 31, 2017 , 2016 , and 2015 the expense stemming from the discount on the receivables sold was not material. As of December 31, 2017 , we had no remaining derecognized receivables that had not been collected on behalf of the Enbridge subsidiary. As of December 31, 2016 , we had $156 million of receivables, which had been sold and derecognized that had not been collected on behalf of the Enbridge subsidiary. Lease and Storage Services Agreement We have an agreement with Illinois Extension Pipeline Company, L.L.C.(IEPC) an equity method investment of our General Partner, pursuant to which IEPC built two storage tanks at our storage facility in Flanagan, Illinois. We lease the tanks from IEPC and operate them. IEPC will pay us operating fees for the operation of the tanks. For the year ended December 31, 2017, IEPC paid no operating fees to us. General Partner Equity Transactions Our General Partner owns an effective 2% general partner interest in us. The cash distributions we make to our General Partner exclude an amount equal to 2% of the i-units, which we retain from the General Partner to maintain its 2% general partner interest in us. Our General Partner’s outstanding ownership interests on us at December 31, 2017 and 2016 , and the total distributions we paid to the General Partner for the years ending December 31, 2017 , 2016 and 2015 were as follows: General Partner’s Ownership Interests Cash Distributions Paid to General Partner (in units) (percentage) (1) (in millions) Type of Unit 2017 2016 2017 2016 2017 2016 2015 Series 1 preferred units (2) — 48,000,000 — % 9.7 % $ — $ — $ — Class D units — 66,100,000 — % 13.3 % $ 39 $ 154 $ 152 Class E units 18,114,975 18,114,975 4.0 % 3.7 % $ 29 $ 42 $ 32 Class A common units 110,827,018 46,518,336 24.6 % 9.4 % $ 143 $ 109 $ 107 Class B common units 7,825,500 7,825,500 1.7 % 1.6 % $ 13 $ 18 $ 18 Class F units 1,000 — — % — % $ 11 $ — $ — IDUs — 1,000 — % — % $ 5 $ 21 $ 17 General Partner interest — — 2.0 % 2.0 % $ 12 $ 17 $ 17 Enbridge Management shares (Listed and Voting) (3) 10,494,464 9,566,358 2.3 % 2.0 % $ — $ — $ — Total 147,262,957 196,126,169 34.6 % 41.7 % 252 361 343 ____________ (1) Represents the General Partners' interest in our total outstanding units. (2) For each of the years ended December 31, 2017 , 2016 and 2015 , total distributions of $29 million , $90 million and $90 million were accrued for the series 1 preferred units in the consolidated statements of financial position. (3) For the years ended December 31, 2017 , 2016 , and 2015 , we made total non-cash distributions of $16 million , $21 million , and $19 million , respectively, to the Listed and Voting Shares of Enbridge Management owned by the General Partner. Financing 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 $1.5 billion , for the purpose of funding our investment in the Bakken Pipeline System. On April 27, 2017, we re-paid the facility in full and terminated the EUS Credit Agreement. 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, $750 million . As of December 31, 2017 , we had $610 million outstanding under this facility, excluding any accrued interest to date. Joint Funding Arrangement for Bakken Pipeline On April 27, 2017, we finalized the 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 June 1, 2017 in-service date of the Bakken Pipeline System. As part of the transaction, DakTex distributed approximately $1.1 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 the EUS Credit Agreement). We terminated the EUS Credit Agreement subsequent to the repayment. 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 United States portion at book value at any time up to four years after the project goes into service. Our General Partner paid $450 million for its 99% interest in the project, 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 million and was recorded as an increase to NCI. The $40 million difference between the cash received and the carrying amount was recorded as an increase to the capital accounts of our common units, i-units, and General Partner interest on a pro-rated basis. Our General Partner made equity contributions totaling $247 million to the OLP for the twelve months ended December 31, 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 (the EA interests). The EA interests were created to finance the Eastern Access Projects to increase access to refineries in the United States 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, thereby increasing our ownership interest from 25% to 40% and reducing the interest of our General Partner from 75% to 60% , respectively. The exercise of our option occurred at book value of approximately $360 million and reduced NCI by approximately $360 million . The Eastern Access Project was placed into service in June 2016. Our General Partner made equity contributions totaling $13 million , $14 million and $119 million to the OLP for the years ended December 31, 2017 , 2016 and 2015 , respectively to fund its equity portion of the construction costs associated with the Eastern Access Projects. Joint Funding Arrangement for U.S. Mainline Expansion Projects The OLP has a series of partnership interests referred 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 made equity contributions totaling $41 million , $90 million and $673 million to the OLP for the years ended December 31, 2017 , 2016 and 2015 , respectively, to fund its equity portion of the construction costs associated with the U.S. Mainline Expansion Projects. During December 2015, the OLP made equity distributions of $72 million to our General Partner, representing return of capital for excess capital funds contributed by our General Partner to the U.S. Mainline Expansion Projects. This is included in “Distributions to noncontrolling interest” presented in our statement of cash flows. Distributions Distribution to Series AC Interests There were no distributions paid by the OLP during the years ended December 31, 2017 and December 31, 2016 with respect to the Series AC Units. The following table presents the distributions paid by the OLP during the years ended December 31, 2015, to our General Partner and its affiliate, representing the noncontrolling interest in the Series AC, and to us, as the holders of the Series AC general and limited partner interests. The distributions were declared by the board of directors of Enbridge Management, acting on behalf of Enbridge Pipelines (Lakehead) L.L.C., the managing general partner of the OLP and the Series AC interests. Pursuant to the OLP’s partnership agreement, the final ownership distribution for the Series AC interests was distributed to Series AC partners of record as of the last day of the fourth quarter of 2014. Distribution Declaration Date Distribution Payment Date Amount Paid to Partnership Amount Paid to the noncontrolling interest Total Series AC Distribution (in millions) 2015 January 29 February 13 $ 14 $ 27 $ 41 Amendment of OLP Limited Partnership Agreement On July 30, 2015, the partners amended and restated the limited partnership agreement of the OLP pursuant to which our General Partner temporarily did not receive Series EA and ME (the Series) distributions from the quarter ended June 30, 2015, through the quarter ended March 31, 2016. The General Partner's capital funding contribution requirements for each of those two Series, commencing in August 2015, were reduced by the amount of its foregone cash distributions from the respective Series, until the earlier of December 31, 2016 and the date aggregate reductions in capital contributions for such Series are equal to the foregone cash distributions from such Series. As of December 31, 2016, capital contributions offsets foregone cash distributions. Distribution to Series EA Interests The following table presents distributions paid by the OLP during the years ended December 31, 2017 , 2016 and 2015 , to our General Partner and its affiliate, representing the noncontrolling interest in the Series EA, and to us, as the holders of the Series EA general and limited partner interests. The distributions were declared by the board of directors of Enbridge Management, acting on behalf of Enbridge Pipelines (Lakehead), L.L.C., the managing general partner of the OLP and the Series EA interests . Distribution Declaration Date Distribution Payment Date Amount Paid to EEP Amount Paid to the noncontrolling interest Total Series EA Distribution (in millions) 2017 October 25 November 14 $ 35 $ 51 $ 86 July 28 August 14 33 50 83 April 27 May 15 29 62 91 January 26 February 14 23 69 92 $ 120 $ 232 $ 352 2016 October 28 November 14 $ 22 $ 65 $ 87 July 28 August 12 21 63 84 April 29 May 13 79 — 79 January 29 February 12 79 — 79 $ 201 $ 128 $ 329 2015 October 30 November 13 $ 76 $ — $ 76 July 30 August 14 76 — 76 April 30 May 15 18 52 70 January 29 February 13 22 67 89 $ 192 $ 119 $ 311 Distribution to Series ME Interests The following table presents distributions paid by the OLP during the years ended December 31, 2017 , 2016 and 2015 , to our General Partner and its affiliate, representing the noncontrolling interest in the Series ME, and to us, as the holders of the Series ME general and limited partner interests. The distributions were declared by the board of directors of Enbridge Management, acting on behalf of Enbridge Pipelines (Lakehead), L.L.C., the managing general partner of the OLP and the Series ME interests. Distribution Declaration Date Distribution Payment Date Amount Paid to EEP Amount Paid to the noncontrolling interest Total Series ME Distribution (in millions) 2017 October 25 November 14 $ 15 $ 44 $ 59 July 28 August 14 14 41 55 April 27 May 15 13 38 51 January 26 February 14 14 43 57 $ 56 $ 166 $ 222 2016 October 28 November 14 $ 15 $ 44 $ 59 July 28 August 12 13 40 53 April 29 May 13 43 — 43 January 29 February 12 41 — 41 $ 112 $ 84 $ 196 2015 October 30 November 13 $ 32 $ — $ 32 July 30 August 14 20 — 20 April 30 May 15 1 5 6 January 29 February 13 2 5 7 $ 55 $ 10 $ 65 Distribution from DakTex The following table presents distributions paid by DakTex during the year ended December 31, 2017 , to our General Partner and its affiliates, representing NCI in Class A units of DakTex, and to us, as the holders of the remaining Class A units of DakTex. Distribution Declaration Date Distribution Payment Date Amount Paid to EEP Amount Paid to the noncontrolling interest Total DakTex Distribution (in millions) 2017 December 19 December 28 $ 11 $ 32 $ 43 September 25 September 29 10 31 41 $ 21 $ 63 $ 84 We along with our General Partner made capital contributions of $440 million to DakTex for the year ended December 31, 2017. Equity income for the year ended December 31, 2017, was $52 million , of which 75% is attributable to our General Partner and recorded as part of NCI. Distribution from MEP The following table presents distributions paid by MEP during the years ended December 31, 2017 , 2016 and 2015 , to its public Class A common unitholders, representing the noncontrolling interest in MEP, and to us for our ownership of Class A common units. Distribution Declaration Date Distribution Payment Date Amount Paid to EEP Amount Paid to the noncontrolling interest Total MEP Distribution (in millions) 2017 January 26 February 14 $ 9 $ 8 $ 17 $ 9 $ 8 $ 17 2016 October 27 November 14 $ 9 $ 8 $ 17 July 27 August 12 9 7 16 April 28 May 13 9 8 17 January 28 February 12 9 7 16 $ 36 $ 30 $ 66 2015 October 29 November 13 $ 9 $ 8 $ 17 July 29 August 14 9 7 16 April 29 May 15 9 7 16 January 28 February 13 8 8 16 $ 35 $ 30 $ 65

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	21. COMMITMENTS AND CONTINGENCIES Future Minimum Commitments At December 31, 2017 , we had our commitments that have remaining non-cancelable terms in excess of one year as detailed below: Payments due by Period 2018 2019 2020 2021 2022 Thereafter Total (in millions) Annual debt maturities (1) $ 500 $ 500 $ 1,000 $ 600 $ 1,453 $ 2,850 $ 6,903 Interest obligations (2) 324 280 243 208 183 3,414 $ 4,652 Purchase commitments (3) 255 — — — — — $ 255 Power commitments (4) 26 25 24 10 10 257 $ 352 Operating leases 3 3 2 1 1 — $ 10 Right-of-way 2 2 2 2 2 36 $ 46 Product purchase obligations (5) 32 16 15 8 — — $ 71 Other long-term liabilities (6) — — 1 1 1 6 $ 9 Total $ 1,142 $ 826 $ 1,287 $ 830 $ 1,650 $ 6,563 $ 12,298 (1) Represents scheduled future maturities of our consolidated third-party debt principal obligations excluding any discounts. We have the ability under certain debt facilities to repay the obligations prior to scheduled maturities. Therefore, the actual timing of future cash repayments could be materially different than presented above. For information regarding our consolidated debt obligations, see Item 8. Financial Statements and Supplementary Data — Note 13 - Debt . (2) Estimated cash payments for third-party interest exclude adjustments for derivative agreements and cash payments for interest on variable-rate debt. We borrow and repay at varying amounts and interest rates. For more information on our debt obligations, see Item 8. Financial Statements and Supplementary Data — Note 13 - Debt . (3) Represents commitments to purchase materials, primarily pipe from third-party suppliers in connection with our growth projects. (4) Represents commitments to purchase power, included certain power commitments with obligations that are dependent on variable components. For these commitments, we only included the determinable portion of our commitment based on the contracted usage requirement and the current applicable contract rate. (5) Represents long-term product purchase commitments to purchase drag reducing agents. (6) Includes noncurrent portion of capital leases. We are unable to estimate deferred income taxes (see Note 18 - Income Taxes ) since cash payments for income taxes are determined primarily by taxable income for each discrete fiscal year. We are also unable to estimate asset retirement obligations (see Note 14 - Asset Retirement Obligations ), environmental liabilities (see Note 21 - Commitments and Contingencies ) and hedges payable (see Note 17 - Derivative Financial Instruments and Hedging Activities ) due to the uncertainty as to the amount and, or, timing of when cash payments will be required. Environmental Liabilities We are subject to federal and state laws and regulations relating to the protection of the environment. These laws and regulations can change from time to time, imposing new obligations on us. Environmental risk is inherent to liquid hydrocarbon pipeline operations, and we are, at times, subject to environmental remediation at various contaminated sites. We manage this environmental risk through environmental policies and practices to minimize any impact our operations may have on the environment. To the extent that we are unable to recover payment for environmental liabilities from insurance or other potentially responsible parties, we will be responsible for payment of liabilities arising from environmental incidents associated with the operating activities of our liquids businesses. Our General Partner has agreed to indemnify us from and against any costs relating to environmental liabilities associated with the Lakehead System assets prior to the transfer of these assets to us in 1991. This excludes any liabilities resulting from a change in laws after such transfer. We continue to voluntarily investigate past leak sites on our systems for the purpose of assessing whether any remediation is required in light of current regulations. As of December 31, 2017 and 2016 , our consolidated statements of financial position included $23 million and $100 million , respectively, in “Environmental liabilities,” and $51 million for both years in “Other long-term liabilities,” that we have accrued for costs we have recognized primarily to address remediation of contaminated sites, asbestos containing materials, management of hazardous waste material disposal, outstanding air quality measures for certain of our liquids and natural gas assets and penalties we have been or expect to be assessed. Lakehead Line 6B Crude Oil Releases 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. On March 14, 2013, we received an order from the EPA (the Order) that required additional containment and active recovery of submerged oil relating to the Line 6B crude oil release. In February 2015, the EPA acknowledged our completion of the Order. In November 2014, regulatory authority was transferred from the EPA to the Michigan Department of Environmental Quality (MDEQ). The MDEQ has oversight over submerged oil reassessment, sheen management and sediment trap monitoring and maintenance activities, through a Kalamazoo River Residual Oil Monitoring and Maintenance Work Plan. In May 2015, Enbridge reached a settlement with the MDEQ and the Michigan Attorney General’s offices regarding the Line 6B crude oil release. As stipulated in the settlement, Enbridge agrees to: (i) provide at least 300 acres of wetland through restoration, creation, or banked wetland credits, to remain as wetland in perpetuity, (ii) pay $5.0 million as mitigation for impacts to the banks, bottomlands, and flow of Talmadge Creek and the Kalamazoo River for the purpose of enhancing the Kalamazoo River watershed and restoring stream flows in the River, (iii) continue to reimburse the State of Michigan for costs arising from oversight of Enbridge activities since the release, and (iv) continue monitoring, restoration and invasive species control within state-regulated wetlands affected by the release and associated response activities. The timing of these activities is based upon the work plans approved by the State of Michigan. As of December 31, 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 December 31, 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 Line 6B Fines and Penalties section below. Our assumptions include, where applicable, estimates of the expected number of days the associated services will be required and rates that we have obtained from contracts negotiated for the respective service and equipment providers. As we receive invoices for the actual personnel, equipment and services, our estimates will continue to be further refined. Our estimates also consider currently available facts, existing technology and presently enacted laws and regulations. These amounts also consider our and other companies’ prior experience remediating contaminated sites and data released by government organizations. Despite the efforts we have made to ensure the reasonableness of our estimates, changes to the recorded amounts associated with this release are possible as more reliable information becomes available. We continue to have the potential of incurring additional costs in connection with this crude oil release due to variations in any or all of the categories described above, including modified or revised requirements from regulatory agencies, in addition to fines and penalties as well as expenditures associated with litigation and settlement of claims. The 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: December 31, 2017 (in millions) Response personnel and equipment $ 547 Environmental consultants 224 Professional, regulatory, fines and penalties and other 444 Total $ 1,215 For the years ended December 31, 2017 , 2016 and 2015 , we made payments of $76 million , $21 million and $37 million , respectively, for costs associated with the Line 6B crude oil release. For the years ended December 31, 2017 and 2016 , we had a remaining estimated liability of $62 million and $139 million , respectively. We did not recognize any insurance recoveries for the years ended December 31, 2017 , 2016 and 2015 . Fines and Penalties At December 31, 2017 , our total estimated costs related to the Line 6B crude oil release include $69 million in paid fines and penalties, which includes fines and penalties paid to the United States Department of Justice (DOJ) as discussed below. Consent Decree On May 23, 2017, the United States District Court for the Western District of Michigan, Southern Division (the District Court), approved our signed settlement agreement with the EPA and the DOJ regarding a consent decree to resolve liability for the Lines 6B crude oil release reported on July 26, 2010, as well as a release of approximately 6,427 barrels of oil from Line 6A near Romeoville, Illinois, on September 9, 2010 (the Consent Decree). On June 15, 2017, Enbridge made a total payment of $68 million as required by the Consent Decree, which reflects a $61 million civil penalty for the Line 6B release, a $1 million civil penalty for the Line 6A release, and $6 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. The Consent Decree contains a variety of injunctive measures, including, but not limited to, enhancements to our comprehensive in-line inspection (ILI)-based spill prevention program; enhanced measures to protect the Straits of Mackinac; improved leak detection requirements; installation of new valves to control product loss in the event of an incident; continued enhancement of control room operations; and improved spill response capabilities. Collectively, these measures build on continuous improvements we have implemented since 2010 to our leak detection program, control center operations, and emergency response program. We estimate the total cost of these measures to be approximately $110 million , most of which is already incorporated into existing long-term capital investment and operational expense planning and guidance. Compliance with the terms of the Consent Decree is not expected to materially impact our overall financial performance. Insurance We are included in the comprehensive insurance program maintained by Enbridge for its subsidiaries. This program includes insurance coverage in types and amounts and with terms and conditions that are generally consistent with coverage considered customary for our industry. In the unlikely event multiple insurable incidents occur which exceed coverage limits 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 million for pollution liability for Enbridge and its affiliates. Including our remediation spending through December 31, 2017 , costs related to Line 6B exceeded the limits of the coverage available under these insurance policies. Through December 31, 2017 , we have recorded total insurance recoveries of $547 million for the Line 6B crude oil release, out of the $650 million aggregate limit. In March 2013, we and Enbridge filed a lawsuit against the insurers of $145 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 million from the other remaining insurers and amended our lawsuit such that it included only one insurer. Of the remaining $103 million coverage limit, $85 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 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 will not 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 discovery in relation to a unitholder derivative action, with trial scheduled in the fourth 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 initiated investigations into the Line 6B crude oil release. As at December 31, 2017, there are no claims pending against us in United States state courts in connection with the July 2010 Line 6B crude oil release. 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. Oil and Gas in Custody Our Liquids assets transport crude oil owned by our customers for a fee. The volume of liquid hydrocarbons in our pipeline systems at any one time varies from approximately 27 million to 63 million barrels, virtually all of which is owned by our customers. Under the terms of our tariffs, losses of crude oil from identifiable incidents not resulting from our direct negligence may be apportioned among our customers. Rights-of-Way As part of our pipeline construction process, we must obtain certain rights-of-way from landowners whose property the pipeline will cross. Rights-of-way that we buy are capitalized as part of “Property, plant and equipment, net” in our consolidated statements of financial position. Rights-of-way that we lease are expensed. We have recorded expenses of $2 million for the leased right-of-way agreements for each of the three years ended December 31, 2017 , 2016 and 2015 . Purchase Commitment and Lease expense The purchases made under purchase commitments, power commitments, product purchase obligations and transportation/service contract obligations for the years ended December 31, 2017 , 2016 and 2015 totaled $341 million , $947 million and $260 million , respectively. Our consolidated operating expenses include lease and rental expense amounts of $7 million , $8 million and $8 million during the years ended December 31, 2017 , 2016 and 2015 , respectively.

QUARTERLY FINANCIAL DATA (Unaud

QUARTERLY FINANCIAL DATA (Unaudited)	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Data [Abstract]
QUARTERLY FINANCIAL DATA (Unaudited)	22. QUARTERLY FINANCIAL DATA (UNAUDITED) First Second Third Fourth Total (in millions, except per unit amounts) 2017 Quarters Operating revenue $ 605 $ 597 $ 616 $ 610 $ 2,428 Operating income 269 312 266 274 1,121 Income from continuing operations 179 232 196 101 708 Loss from discontinued operations, net of tax (22 ) (35 ) — — (57 ) Net income 157 197 196 101 651 Net income (loss) attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P. - continuing operations 79 117 93 (6 ) 283 Net income (loss) attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P. - discontinued operations (14 ) (24 ) — — (38 ) Net income (loss) per common unit and i-unit (basic and diluted): Income (loss) from continuing operations 0.19 0.27 0.19 (0.05 ) 0.60 Loss from discontinued operations (0.04 ) (0.06 ) — — (0.10 ) Net income (loss) per common unit and i-unit $ 0.15 $ 0.21 $ 0.19 $ (0.05 ) $ 0.50 2016 Quarters Operating revenue $ 630 $ 621 $ 635 $ 630 $ 2,516 Operating income (loss) (1) 296 323 (449 ) 311 481 Income from continuing operations 203 241 (544 ) 216 116 Loss from discontinued operations, net of tax (30 ) (63 ) (31 ) (33 ) (157 ) Net income (loss) 173 178 (575 ) 183 (41 ) Net income (loss) attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P. - continuing operations 101 130 (385 ) 103 (51 ) Net income (loss) attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P. - discontinued operations (21 ) (46 ) (22 ) (22 ) (111 ) Net income (loss) per common unit and i-unit (basic and diluted): Income (loss) from continuing operations 0.13 0.21 (1.25 ) 0.14 (0.77 ) Loss from discontinued operations (0.06 ) (0.13 ) (0.06 ) (0.06 ) (0.31 ) Net income (loss) per common unit and i-unit $ 0.07 $ 0.08 $ (1.31 ) $ 0.08 $ (1.08 ) ____________ (1) Third quarter 2016 operating expenses were impacted by an asset impairment of $757 million . For more information, refer to Note 9 - Property, Plant and Equipment .

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS	12 Months Ended
	Dec. 31, 2017
Subsequent Events [Abstract]
SUBSEQUENT EVENTS	23. SUBSEQUENT EVENTS Distribution to Partners On January 31, 2018 , the board of directors of Enbridge Management declared a distribution payable to our partners on February 14, 2018 . The distribution was paid to unitholders of record as of February 7, 2018 and consisted of our available cash of $162 million at December 31, 2017 , or $0.35 per limited partner unit. Of this distribution, $130 million was paid in cash, $31 million was distributed in i-units to our i-unitholder, Enbridge Management, and due to the i-unit distribution, $1 million was 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 January 31, 2018 , the board of directors of Enbridge Management, acting on behalf of Enbridge Pipelines (Lakehead) L.L.C., the managing general partner of the OLP and a holder of the Series EA interests, declared a distribution payable to the holders of the Series EA general and limited partner interests. The OLP paid $50 million to the noncontrolling interest in the Series EA, while $34 million was paid to us. Distribution to Series ME Interests On January 31, 2018 , the board of directors of Enbridge Management, acting on behalf of Enbridge Pipelines (Lakehead) L.L.C., the managing general partner of the OLP and a holder of the Series ME interests, declared a distribution payable to the holders of the Series ME general and limited partner interests. The OLP paid $44 million to the noncontrolling interest in the Series ME, while $15 million was paid to us.

SUMMARY OF SIGNIFICANT ACCOUN31

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Basis of Presentation and Use of Estimates	Basis of Presentation and Use of Estimates These consolidated financial statements are prepared in accordance with U.S. GAAP. The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities in the consolidated financial statements. We regularly evaluate these estimates utilizing historical experience, consultation with experts and other methods we consider reasonable in the circumstances. Nevertheless, actual results may differ significantly from these estimates. We record the effect of any revisions to these estimates in our consolidated financial statements in the period in which the facts that give rise to the revision become known. Amounts are stated in United States dollars unless otherwise noted.
Principles of Consolidation	Principles of Consolidation The consolidated financial statements include our accounts and accounts of our subsidiaries and VIEs for which we are the primary beneficiary. Upon inception of a contractual agreement, we perform an assessment to determine whether the arrangement contains a variable interest in a legal entity and whether that legal entity is a VIE. Where we conclude we are the primary beneficiary of a VIE, we consolidate the accounts of that VIE. We assess all aspects of our interests in an entity and use judgment when determining if we are the primary beneficiary. The primary beneficiary has both the power to direct the activities of the VIE that most significantly impact the entity’s economic performance and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. Other qualitative factors that are considered include decision-making responsibilities, the VIE capital structure, risk and rewards sharing, contractual agreements with the VIE, voting rights and level of involvement of other parties. A reassessment of the primary beneficiary conclusion is conducted when there are changes in the facts and circumstances related to a VIE. All significant intercompany accounts and transactions are eliminated upon consolidation. Ownership interests in subsidiaries represented by other parties that do not control the entity are presented in the consolidated financial statements as activities and balances attributable to NCI. Investments and entities over which we exercise significant influence are accounted for using the equity method.
Accounting for Regulated Operations	Regulation Our interstate liquids pipelines are subject to regulation by FERC and various state authorities. Regulatory bodies exercise statutory authority over matters such as construction, rates and ratemaking and agreements with customers. For example, the recovery of construction, operating and other costs associated with portions of our Lakehead System are subject to the authoritative accounting provisions applicable to regulated operations. To recognize the economic effects of the actions of the regulator, the timing of recognition of certain revenues and expenses in these operations may differ from that otherwise expected under U.S. GAAP for non rate-regulated entities. Under our cost-of-service recovery model, the difference between forecast used to calculate the tolls and actual results causes an over or under recovery in any given year that is deferred through a revenue adjustment and is returned to or recovered from shippers through future rate adjustments in the following year. Due to these over or under recovery adjustments made in accordance with the FERC’s authoritative guidance, 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. The net regulatory asset or liability balance is comprised of the cumulative over and under recovery adjustments made during the prior calendar year, less any amortizations and the cumulative over and under recovery adjustments made during current calendar year to date. We track regulatory assets and liabilities by vintage and our regulatory assets and liabilities are amortized on a straight-line basis over a one-year recovery period. Accordingly, amortization for a net regulatory asset or liability arising from over and under recovery adjustments related to any given calendar year does not begin until January of the following year. Allowance for Funds Used During Construction AFUDC is included in the cost of property, plant and equipment and is depreciated over future periods as part of the total cost of the related asset. AFUDC includes both an interest component and, if approved by the regulator, a cost of equity component, which are both capitalized based on rates set out in a regulatory agreement. In the absence of rate regulation, we would capitalize interest using a capitalization rate based on our cost of borrowing, whereas the capitalized equity component, the corresponding earnings during the construction phase and the subsequent depreciation would not be recognized.
Revenue Recognition and the Estimation of Revenues	Revenue Recognition and the Estimation of Revenues We generally do not own the crude oil and liquid petroleum that we transport or store and therefore, we do not assume significant direct commodity price risk. Revenues are primarily derived from three sources: interstate transportation of crude oil and liquid petroleum under tariffs regulated by the FERC, ship-or-pay agreements and contract storage revenues related to our crude oil storage assets. The tariffs established for our interstate pipelines specify the amounts to be paid by shippers for transportation services we provide between receipt and delivery locations and the general terms and conditions of transportation services on the respective pipeline systems. We recognize revenue upon delivery of products to our customers, when pricing is determinable and collectability is reasonably assured. We recognize contract storage revenues based on contractual terms under which customers pay for the option to use available storage capacity and/or a fee based on storage volumes. We recognize revenues as storage services are rendered, when pricing is determinable and collectability is reasonably assured. Revenues are all recorded in “Transportation and other services” and “Transportation and other services — affiliate” on our consolidated statements of income. Estimation of Revenue In order to permit the timely preparation of our consolidated financial statements, we estimate our current month revenue and commodity costs. We generally cannot compile actual billing information nor obtain actual vendor invoices within a timeframe that would permit the recording of this actual data before our preparation of the consolidated financial statements. As a result, we record an estimate each month for our operating revenues based on the best available volume and price data for crude oil delivered and received, along with an adjustment of the prior month’s estimate to equal the prior month’s actual data. As a result, there is one month of estimated data recorded in our operating revenues and commodity costs for each of the years ended December 31, 2017 , 2016 and 2015 . We believe that the assumptions underlying these estimates are not significantly different from the actual amounts due to the routine nature of these estimates and the stability of our processes.
Derivative Financial Instruments	Derivative Financial Instruments We use derivative financial instruments (i.e., futures, forwards, swaps, options and other financial instruments with similar characteristics) to manage our exposure to changes in commodity prices and interest rates. We record all derivative financial instruments at fair market value in our consolidated statements of financial position. For those instruments that qualify for hedge accounting, the accounting treatment is dependent on the intended use and designation of each instrument. We record changes in the fair value of our derivative financial instruments that are not designated for hedge accounting in our consolidated statements of income as follows: • Commodity-based derivatives — “Transportation and other services” • Interest rate derivatives — “Interest expense, net” Qualified Hedges We may use cash flow hedges to manage our exposure to changes in commodity prices and interest rates. To qualify for cash flow hedge accounting treatment, very specific requirements must be met in terms of hedge structure, hedge objective and hedge documentation. At inception, we formally document the relationship between the hedging instrument and the hedged item, the risk management objective and the method used for assessing and testing correlation and hedge effectiveness. We also assess, both at the inception of the hedge and on an on-going basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows of the hedged item. Furthermore, we regularly assess the creditworthiness of our counterparties to manage against the risk of default. If we determine that a derivative is no longer highly effective as a hedge, we discontinue hedge accounting prospectively by including changes in the fair value of the derivative in current earnings. The effective portion of the change in fair value of a cash flow hedge is recorded in other comprehensive income (loss) and is reclassified into earnings when the hedge item impacts earnings. Any ineffective portion of a cash flow hedge’s change in fair value is recognized each period in earnings. Gains and losses deferred in AOCI related to cash flow hedges for which hedge accounting has been discontinued remain in AOCI until the underlying physical transaction occurs unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two month period of time thereafter. Although we retain the ability to designate commodity hedges for cash flow hedge accounting, as of December 31, 2017 , we have no commodity hedges designated as cash flow hedges. Non-Qualified Hedges We have derivative financial instruments associated with our commodity activities where the hedge structure does not meet the requirements to apply hedge accounting. As a result, these derivative financial instruments do not qualify for hedge accounting and are referred to as non-qualifying. These non-qualifying derivative financial instruments are marked-to-market each period with the change in fair value, representing unrealized gains and losses, included in “Transportation and other services” in our consolidated statements of income. These mark-to-market adjustments produce a degree of earnings volatility that can often be significant from period to period, but have no cash flow impact relative to changes in market prices. The cash flow impact occurs when the underlying physical transaction takes place in the future and the associated financial instrument contract settlement is made. Although we retain the ability to designate commodity hedges for cash flow accounting, as of December 31, 2017 , we have no remaining commodity hedges that are designated. As such, all commodity hedges are marked-to-market with the changes in fair value recorded in earnings each period. Designated interest rate derivative financial instruments continue to be reported in AOCI.
Fair Value Measurements	Fair Value Measurements We apply the authoritative accounting provisions for measuring fair value to our derivative instruments and disclosures associated with our outstanding commodity activities. Fair value is defined as the expected price we would receive to sell an asset or pay to transfer a liability in an orderly transaction with market participants at the measurement date. We employ a hierarchy which prioritizes the inputs we use to measure recurring fair value into three distinct categories based upon whether such inputs are observable in active markets or unobservable. We classify assets and liabilities in their entirety based on the lowest level of input that is significant to the fair value measurement. Our methodology for categorizing assets and liabilities that are measured at fair value pursuant to this hierarchy gives the highest priority to unadjusted quoted prices in active markets and the lowest level to unobservable inputs as outlined below: • Level 1 — We include in this category the fair value of assets and liabilities that we measure based on unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. We consider active markets as those in which transactions for the assets or liabilities occur with sufficient frequency and volume to provide pricing information on an ongoing basis. The fair value of our assets and liabilities included in this category consists primarily of exchange-traded derivative instruments. • Level 2 — We include in this category 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: (a) quoted prices for assets and liabilities; (b) time value; (c) volatility factors; and (d) 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. • Level 3 — We include in this category the fair value of assets and liabilities that we measure based on prices or valuation techniques that require inputs which are both significant to the fair value measurement and less observable from objective sources (i.e., values supported by lesser volumes of market activity). We may also use these inputs with internally developed methodologies that result in our best estimate of the fair value. Level 3 assets and liabilities primarily include derivative instruments for which we do not have sufficient corroborating market evidence, such as binding broker quotes, to support classifying the asset or liability as Level 2. Additionally, Level 3 valuations may utilize modeled pricing inputs to derive forward valuations, which may include some or all of the following inputs: non-binding broker quotes, time value, volatility, correlation and extrapolation methods. We record all derivative financial instruments in our consolidated financial statements at fair market value, which we adjust on a recurring basis each period for changes in the fair market value and refer to as marking to market, or mark-to-market. The fair market value of these derivative financial instruments reflects the estimated amounts that we would pay to transfer a liability or receive to sell an asset in an orderly transaction with market participants to terminate or close the contracts at the reporting date, taking into account the current unrealized losses or gains on open contracts. We apply a mid-market pricing convention, which we refer to as the “market approach,” to value substantially all of our derivative instruments. Our assets are adjusted for the non-performance risk of our counterparties using their current credit default swap spread rates. Likewise, in the case of our liabilities, our nonperformance risk is considered in the valuation and is also adjusted using a credit adjustment model incorporating inputs such as credit default swap rates, bond spreads, and default probabilities. Our credit exposure for OTC derivatives is directly with our counterparty and continues until the maturity or termination of the contracts. As appropriate, valuations are adjusted for various factors such as credit and liquidity considerations. Actively traded external market quotes, data from pricing services and published indices are also used to value our derivative instruments. We may use these inputs along with internally developed methodologies that result in our best estimates of fair value.
Income Taxes	Income Taxes We are not a taxable entity for United States federal income tax purposes or for the majority of states that impose an income tax. Taxes on our net income generally are borne by our unitholders through the allocation of taxable income. Our income tax expense results from the enactment of franchise tax laws by the State of Texas that apply to entities organized as partnerships. This tax is computed on our modified gross margin and we have determined the tax to be an income tax as set forth in authoritative accounting literature. We recognize deferred income tax assets and liabilities for temporary differences between the relevant basis of our assets and liabilities for financial reporting and tax purposes. We record the impact of changes in tax legislation on deferred income tax liabilities and assets in the period the legislation is enacted. We recognize the tax effects of any uncertain tax positions as the largest amount that will more likely than not be realized upon ultimate settlement with a taxing authority having full knowledge of the position and all relevant facts. We recognize accrued interest income related to unrecognized tax benefits in interest income when the related unrecognized tax benefits are recognized. Net income for financial statement purposes may differ significantly from taxable income of unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities and the taxable income allocation requirements under our partnership agreement. The aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined because information regarding each partner’s tax attributes in us is not available.
Cash and Cash Equivalents	Cash and Cash Equivalents Cash equivalents are defined as all highly marketable securities with original maturities of three months or less when purchased. The carrying value of cash and cash equivalents approximates fair value because of the short term to maturity of these investments.
Restricted Cash	Restricted Cash Cash and cash equivalents that are restricted as to withdrawal or usage, in accordance with specific commercial arrangements, are presented as “Restricted cash” on our consolidated statements of financial position.
Oil Measurement Adjustments	Oil Measurement Adjustments Oil measurement adjustments occur as part of the normal operations associated with our liquid petroleum operations. The three types of oil measurement adjustments that routinely occur on our systems include: • Physical, which result from evaporation, shrinkage, differences in measurement (including sediment and water measurement) between receipt and delivery locations and other operational conditions; • Degradation, resulting from mixing at the interface within our pipeline systems or terminal and storage facilities between higher quality light crude oil and lower quality heavy crude oil in pipelines; and • Revaluation, which are a function of crude oil prices, the level of our carriers’ inventory and the inventory positions of customers. Quantifying oil measurement adjustments are difficult because: (i) physical measurements of volumes are not practical, as products continuously move through our pipelines, which are primarily located underground; (ii) the extensive length of our pipeline systems; and (iii) the numerous grades and types of crude oil products we carry. We utilize engineering-based models and operational assumptions to estimate product volumes in our systems and associated oil measurement adjustments. Material changes in our assumptions may result in revisions to our oil measurement estimates in the period determined. Oil measurement adjustments are included within the “Operating and administrative” line item of our consolidated statements of income.
Property, Plant and Equipment	Property, Plant and Equipment We record property, plant and equipment at historical cost. We capitalize expenditures in excess of a minimum rule, which have a useful life greater than one year for: (i) assets purchased or constructed; (ii) existing assets that are replaced, improved or the useful lives have been extended; or (iii) all land, regardless of cost. Maintenance and repair costs, including any planned major maintenance activities, are expensed as incurred. Expenditures for project development are capitalized if they are expected to have a future benefit. During construction, we capitalize direct costs, such as labor and materials, and other costs, such as direct overhead and interest at our weighted average cost of debt. We depreciate property, plant and equipment on a straight-line basis over the lesser of its estimated useful life or the estimated remaining lives of the crude oil production in the basins the assets serve. Upon disposition of distinct assets, we recognize any gains or losses in our consolidated statements of income. For largely homogeneous groups of assets with comparable useful lives, we record depreciation using the group method of depreciation whereby similar assets are grouped and depreciated as a group. Under this method, when group assets are retired or otherwise disposed of, gains and losses are not reflected in our consolidated statements of income but are recorded as an adjustment to accumulated depreciation.
Impairment	Impairment We evaluate the recoverability of our long-lived assets when events or circumstances such as economic obsolescence, the business climate, legal and other factors indicate we may not recover the carrying amount of the assets. We evaluate the asset for recoverability by estimating the undiscounted future cash flows expected to be derived from operating the asset as a going concern. If the carrying amount of the asset exceeds the sum of the undiscounted future cash flows, we recognize an impairment loss in the amount of the excess carrying amount of the asset over its fair value.
Asset Retirement Obligations	Asset Retirement Obligations Legal obligations exist for a minority of our right-of-way agreements due to requirements or landowner options that compel us to remove the pipe at final abandonment. Sufficient data exists with certain pipeline systems to reasonably estimate the cost of abandoning or retiring a pipeline system. However, in some cases, there is insufficient information to reasonably determine the timing and/or method of settlement for estimating the fair value of the asset retirement obligation. In these cases, the asset retirement obligation cost is considered indeterminate because there is no data or information that can be derived from past practice, industry practice, our intentions, or the estimated economic life of the asset. Useful lives of most pipeline systems are primarily derived from available supply resources and ultimate consumption of those resources by end users. Variables can affect the remaining lives of the assets which preclude us from making a reasonable estimate of the asset retirement obligation. Indeterminate asset retirement obligation costs will be recognized in the period in which sufficient information exists to allow us to reasonably estimate potential settlement dates and methods. We record a liability for the fair value of asset retirement obligations and conditional asset retirement obligations that we can reasonably estimate, on a discounted basis. We collectively refer to asset retirement obligations and conditional asset retirement obligations as ARO. Typically, we record an ARO at the time the assets are installed or acquired, if a reasonable estimate of fair value can be made. In connection with establishing an ARO, we capitalize the costs as part of the carrying value of the related assets. We recognize an ongoing expense for the interest component of the liability as part of depreciation expense resulting from changes in the value of the ARO due to the passage of time. We depreciate the initial capitalized costs over the useful lives of the related assets. We extinguish the liabilities for an ARO when assets are taken out of service or otherwise abandoned.
Commitments, Contingencies and Environmental Liabilities	Commitments, Contingencies and Environmental Liabilities We expense or capitalize, as appropriate, expenditures for ongoing compliance with environmental regulations that relate to past or current operations. We expense amounts we incur for remediation of existing environmental contamination caused by past operations that do not benefit future periods by preventing or eliminating future contamination. We record liabilities for environmental matters when assessments indicate that remediation efforts are probable, and the costs can be reasonably estimated. Estimates of environmental liabilities are based on currently available facts, existing technology and presently enacted laws and regulations taking into consideration the likely effects of inflation and other factors. These amounts also consider prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by government organizations. Our estimates are subject to revision in future periods based on actual costs or new information and are included in “Environmental liabilities” and “Other long-term liabilities” in our consolidated statements of financial position at their undiscounted amounts. We always have the potential of incurring additional costs in connection with environmental liabilities due to variations in any or all of the categories described above, including modified or revised requirements from regulatory agencies, in addition to fines and penalties, as well as expenditures associated with litigation and settlement of claims. We evaluate recoveries from insurance coverage separately from the liability and, when recovery is probable, we record and report an asset separately from the associated liability in our consolidated financial statements. We recognize liabilities for other commitments and contingencies when, after fully analyzing the available information, we determine it is either probable that an asset has been impaired, or that a liability has been incurred and the amount of impairment or loss can be reasonably estimated. When a range of probable loss can be estimated, we accrue the most likely amount, or if no amount is more likely than another, we accrue the minimum of the range of probable loss. We expense legal costs associated with loss contingencies as such costs are incurred.

NET INCOME PER LIMITED PARTNE32

NET INCOME PER LIMITED PARTNER UNIT (Tables)	12 Months Ended
	Dec. 31, 2017
Earnings Per Share [Abstract]
Schedule of Formula for Distributing Available Cash	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 Distribution Per Unit Percentage Distributed to General Partner and Class F Units (1) Percentage Distributed to Limited Partners 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 distribution in excess of the Minimum Quarterly Distribution, this percentage includes both the General Partner's distribution of 2% and the distribution to the Class F units. Prior to April 27, 2017, we allocated distributions to the General Partner and limited partners based upon the distribution rates and percentages set forth in the following table: Distribution Targets Portion of Quarterly Distribution Per Unit Percentage Distributed to General Partner and IDUs (1) Percentage Distributed to Limited partners Minimum Quarterly Distribution Up to $0.5435 2% 98% First Target Distribution > $0.5435 25% 75% ____________ (1) For distributions in excess of the Minimum Quarterly Distribution, this percentage includes both the General Partner’s distributions of 2% and the distribution to the Incentive Distribution Unit holder, a wholly-owned subsidiary of our General Partner.
Basic and Diluted Net Income Per Limited Partner Unit	We determined basic and diluted net income (loss) per common unit and i-unit as follows: For the year ended December 31, 2017 2016 2015 (in millions, except per unit amounts) Continuing operations: $ 708 $ 116 $ 739 Net income Less: Net income attributable to: Noncontrolling interest 388 72 297 Series 1 preferred unit distributions 29 90 90 Accretion of discount on Series 1 preferred units 8 5 11 Net income (loss) attributable to general and limited partner interests in Enbridge Energy Partners, L.P. - continuing operations 283 (51 ) 341 Distributions: Incentive distributions (1) (15 ) (21 ) (19 ) Distributed earnings attributed to our General Partner (13 ) (21 ) (21 ) Distributed earnings attributed to Class D and Class E units (1) (25 ) (196 ) (195 ) Total distributed earnings to our General Partner, Class D, Class E units Class F units and IDUs (53 ) (238 ) (235 ) Total distributed earnings attributed to our common units and i-units (589 ) (814 ) (791 ) Total distributed earnings (642 ) (1,052 ) (1,026 ) Overdistributed earnings $ (359 ) $ (1,103 ) $ (685 ) Discontinued operations: Net loss $ (57 ) $ (157 ) $ (285 ) Less: Net loss attributable to: Noncontrolling interest (19 ) (46 ) (76 ) Net loss attributable to general and limited partner interests in Enbridge Energy Partners, L.P. - discontinued operations $ (38 ) $ (111 ) $ (209 ) Weighted average common units and i-units outstanding 400 348 339 Basic and diluted earnings per unit: Distributed earnings per common unit and i-unit - continuing operations (2) 1.48 2.34 2.33 Overdistributed earnings per common unit and i-unit (3) (0.88 ) (3.11 ) (1.98 ) Net income (loss) per common unit and i-unit (basic and diluted) - continuing operations (4) 0.60 (0.77 ) 0.35 Net loss per common unit and i-unit (basic and diluted) - discontinued operations (4) (0.10 ) (0.31 ) (0.60 ) Net income (loss) per common unit and i-unit (basic and diluted) 0.50 (1.08 ) (0.25 ) ____________ (1) For the year ended December 31, 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 units and IDUs; for the years ended December 31, 2016 and 2015 , 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-unit’s 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 years ended December 31, 2017 , 2016 and 2015 , 43,201,310 anti-dilutive Preferred Units, 66,100,000 anti-dilutive Class D units and 18,114,975 anti-dilutive Class E units were excluded from the if-converted method of calculating diluted earnings per unit.

SEGMENT INFORMATION (Tables)

SEGMENT INFORMATION (Tables)	12 Months Ended
	Dec. 31, 2017
Segment Reporting [Abstract]
Schedule of Segment Reporting Information, By Segment	As of and for the year ended December 31, 2017 Total Revenues (1) Segment EBITDA/Consolidated Earnings Before Income Taxes Capital and Investment Expenditures Total Assets (in millions) Liquids $ 2,428 $ 1,674 $ 586 $ 14,819 Total reportable segment 2,428 1,674 586 14,819 Other (7 ) 9 Depreciation and amortization (442 ) Interest expense, net (525 ) Earnings before income tax expense 700 Income tax benefit 8 Net income from continuing operations 708 Net loss from discontinued operations (2) (57 ) Total consolidated $ 2,428 $ 651 $ 586 $ 14,828 ____________ (1) There were no intersegment revenues for the year ended December 31, 2017 . (2) The operating results of our disposed 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 7 - Dispositions and Discontinued Operations . As of and for the year ended December 31, 2016 Total Revenues (1) Segment EBITDA/Consolidated Earnings Before Income Taxes Capital and Investment Expenditures Total Assets (3) (in millions) Liquids $ 2,516 $ 964 $ 797 $ 13,031 Total reportable segment 2,516 964 797 13,031 Other (9 ) 165 Depreciation and amortization (427 ) Interest expense, net (413 ) Earnings before income tax expense 115 Income tax benefit 1 Net income from continuing operations 116 Net loss from discontinued operations (2) (157 ) Total consolidated $ 2,516 $ (41 ) $ 797 $ 13,196 ____________ (1) There were no intersegment revenues for the year ended December 31, 2016 . (2) The operating results of our disposed 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 7 - Dispositions and Discontinued Operations . (3) Comparative information excludes assets from discontinued operations. For further information refer to Note 7 - Dispositions and Discontinued Operations . As of and for the year ended December 31, 2015 Total Revenues (1) Segment EBITDA/Consolidated Earnings Before Income Taxes Capital and Investment Expenditures (in millions) Liquids $ 2,303 $ 1,441 $ 1,976 Total reportable segment 2,303 1,441 1,976 Other (29 ) Depreciation and amortization (378 ) Interest expense, net (292 ) Earnings before income tax expense 742 Income tax expense (3 ) Net income from continuing operations 739 Net loss from discontinued operations (2) (285 ) Total consolidated $ 2,303 $ 454 $ 1,976 ____________ (1) There were no intersegment revenues for the year ended December 31, 2015 . (2) The operating results of our disposed 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 7 - Dispositions and Discontinued Operations

REGULATORY MATTERS (Tables)

REGULATORY MATTERS (Tables)	12 Months Ended
	Dec. 31, 2017
Regulatory Assets and Liabilities Disclosure [Abstract]
Schedule of Changes in Net Regulatory Asset Balance	Our over and under recovery revenue adjustments and net regulatory asset amortization for the years ended December 31, 2017 , 2016 , and 2015 are as follows: For the year ended December 31, 2017 2016 2015 (in millions) Net regulatory asset balance at beginning of year $ 12 $ 30 $ 6 Current year under recovery adjustments 3 12 30 Amortization of prior year regulatory asset (12 ) (30 ) (6 ) Net regulatory asset balance at end of year $ 3 $ 12 $ 30

DISPOSITIONS AND DISCONTINUED35

DISPOSITIONS AND DISCONTINUED OPERATIONS (Tables)	12 Months Ended
	Dec. 31, 2017
Discontinued Operations and Disposal Groups [Abstract]
Disposal Groups, Including Discontinued Operations	The following table presents the operating results from discontinued operations of our Midcoast gas gathering and processing business, which have been segregated from our continuing operations in our consolidated statements of income: For the year ended December 31, 2017 2016 2015 Operating revenues: Commodity sales $ 1,094 $ 1,786 $ 2,647 Transportation and other services 67 180 196 1,161 1,966 2,843 Operating expenses: Commodity costs 1,010 1,660 2,373 Operating and administrative 134 294 355 Depreciation and amortization 74 154 158 Asset impairment — 11 12 Goodwill impairment — — 227 1,218 2,119 3,125 Operating loss (57 ) (153 ) (282 ) Interest expense, net (18 ) (33 ) (30 ) Other income 19 31 29 Loss before income taxes (56 ) (155 ) (283 ) Income tax expense (1 ) (2 ) (2 ) Net loss from discontinued operations, net of tax $ (57 ) $ (157 ) $ (285 ) The following table presents the major classes of assets and liabilities for discontinued operations of our Midcoast gas gathering and processing business as presented in the consolidated statement of financial position: December 31, 2016 (in millions) Current assets related to discontinued operations: Cash and cash equivalents $ 7 Restricted cash 11 Receivables, trade and other, net of allowance for doubtful accounts 9 Due from General Partner and affiliates 2 Accrued receivables 21 Inventory 28 Other current assets 61 $ 139 Non-current assets related to discontinued operations: Property, plant and equipment, net $ 4,114 Equity investment in joint venture 361 Intangible assets, net 252 Other assets, net 48 $ 4,775 December 31, 2016 (in millions) Current liabilities related to discontinued operations: Accounts payable and other $ 67 Due to General Partner and affiliates 39 Accrued purchases 172 Property and other taxes payable 17 Interest payable 5 $ 300 Non-current liabilities related to discontinued operations: Long-term debt $ 818 Other long-term liabilities 26 $ 844

OTHER CURRENT ASSETS (Tables)

OTHER CURRENT ASSETS (Tables)	12 Months Ended
	Dec. 31, 2017
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Schedule of Other Current Assets	December 31, 2017 2016 (in millions) Regulatory assets $ 3 $ 12 Prepaid expenses and other 15 16 Inventory 2 3 Other 4 3 Total other current assets $ 24 $ 34

PROPERTY, PLANT AND EQUIPMENT (

PROPERTY, PLANT AND EQUIPMENT (Tables)	12 Months Ended
	Dec. 31, 2017
Property, Plant and Equipment [Abstract]
Schedule of Property, Plant and Equipment	Weighted Average Depreciation Rate December 31, 2017 2016 (in millions) Land — $ 78 $ 79 Rights-of-way 2.92% 477 473 Pipelines 2.76% 8,731 8,571 Pumping equipment, buildings and tanks 3.16% 5,144 4,866 Vehicles, office furniture and equipment 3.35% 167 148 Construction in progress 1,109 864 Total property, plant and equipment 15,706 15,001 Accumulated depreciation (2,810 ) (2,393 ) Property, plant and equipment, net $ 12,896 $ 12,608

VARIABLE INTEREST ENTITIES (Tab

VARIABLE INTEREST ENTITIES (Tables)	12 Months Ended
	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Schedule of Variable Interest Entities	The following table includes assets to be used to settle liabilities of our consolidated VIEs and liabilities of our consolidated VIEs for which creditors do not have recourse to our general credit as the primary beneficiary. These assets and liabilities are included in our consolidated statements of financial position. December 31, 2017 2016 (in millions) ASSETS Cash and cash equivalents $ 35 $ 37 Receivables, trade and other 62 2 Due from General Partner and affiliates 90 74 Accrued receivables 101 17 Other current assets 22 33 Property, plant and equipment, net 12,333 12,153 Equity investment in joint venture 1,547 — Other assets, net 37 116 LIABILITIES Accounts payable and other 147 168 Due to General Partner and affiliates 37 102 Interest payable 4 4 Environmental liabilities 23 100 Property and other taxes payable 102 87 Current portion of long-term debt 100 — Long-term debt 100 199 Other long-term liabilities $ 161 $ 153

EQUITY INVESTMENTS IN JOINT V39

EQUITY INVESTMENTS IN JOINT VENTURES (Tables)	12 Months Ended
	Dec. 31, 2017
Equity Method Investments and Joint Ventures [Abstract]
Equity Method Investments	The following table presents our equity investment in a joint venture with MPC and ownership interest in MarEn. Ownership Interest December 31, 2017 2016 (in millions) MarEn Bakken Company LLC 75 % $ 1,565 $ — The following tables present summarized balance sheet information as at December 31, 2017 and summarized income statement information for the year ended December 31, 2017. December 31, 2017 (in millions) Non-current assets $ 2,062 Total equity $ 2,062 December 31, 2017 (in millions) Income from equity investment $ 99 Amortization of basis difference (30 ) Net income $ 69

ACCOUNTS PAYABLE AND OTHER (Tab

ACCOUNTS PAYABLE AND OTHER (Tables)	12 Months Ended
	Dec. 31, 2017
Payables and Accruals [Abstract]
Schedule of Accounts Payable and Other	December 31, 2017 2016 (in millions) Short-term portion of derivative liabilities $ 9 $ 146 Accounts payable 74 78 Accrued liabilities 62 55 Contractor holdbacks 9 44 Deferred credits 13 14 Other current liabilities 2 6 Accrued purchases 4 5 Total accounts payable and other $ 173 $ 348

DEBT (Tables)

DEBT (Tables)	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Schedule of Debt Obligations	The following table presents the primary components of our outstanding indebtedness with third parties and the interest rates associated with each component as of December 31, 2017 and 2016 , before the effect of our interest rate hedging activities. Our indebtedness with related parties is discussed in Note 20 - Related Party Transactions . December 31, 2017 2016 (in millions) EEP debt obligations: Commercial Paper (1) $ 1,303 $ 393 Credit Facilities due 2018 – 2022 (2) 150 1,265 6.500% senior notes due April 2018 400 400 9.875% senior notes due March 2019 500 500 5.200% senior notes due March 2020 500 500 4.375% senior notes due October 2020 500 500 4.200% senior notes due September 2021 600 600 5.875% senior notes due October 2025 500 500 5.950% senior notes due June 2033 200 200 6.300% senior notes due December 2034 100 100 7.500% senior notes due April 2038 400 400 5.500% senior notes due September 2040 550 550 7.375% senior notes due October 2045 600 600 Fixed to floating rate junior subordinated notes due 2067 (3) 400 400 OLP debt obligations: 7.000% senior notes due October 2018 100 100 7.125% senior notes due October 2028 100 100 Total debt 6,903 7,108 Unamortized discount (6 ) (6 ) Current portion of long-term debt (500 ) — Unamortized debt issuance costs (31 ) (36 ) Long-term debt $ 6,366 $ 7,066 ____________ (1) Individual issuances of commercial paper generally mature in 90 days or less, but are supported by our Credit Facilities and are therefore considered long-term debt as we have the ability and intent to refinance these long-term. The weighted average interest rate was 2.276% . (2) The interest rate was 2.744% (3) Effective October 1, 2017, the Junior Note bore interest at a variable rate equal to three months LIBOR for the related interest period increased by 3.798% . For the three months ended December 31, 2017 , the LIBOR rate was 1.335% .
Schedule of Interest Costs	Our interest cost for the years ended December 31, 2017 , 2016 and 2015 is comprised of the following: For the year ended December 31, 2017 2016 2015 (in millions) Term notes (1) $ 531 $ 428 $ 307 Commercial paper and credit facility draws 38 33 24 Less: Interest capitalized (44 ) (48 ) (39 ) Interest expense, net $ 525 $ 413 $ 292 ____________ (1) For the year ended December 31, 2017, interest expense includes reclassification of $168 million loss related to the termination of long-term interest rate swaps as not highly probable to issue long-term debt.
Schedule of Line of Credit Facilities	The following table provides details of our committed Credit Facilities at December 31, 2017 : Maturity (1) Total Facilities Draws (2) (3) (4) Available (in millions) Enbridge Energy Partners, L.P. 2018 – 2022 $ 2,625 $ 1,453 $ 1,172 ____________ (1) Includes $175 million and $185 million of commitments that expire in 2018 and 2020, respectively. (2) Includes facility draws, letters of credit and commercial paper issuances that are back-stopped by the credit facility and excludes our credit agreement with EUS (the EUS 364-day Credit Facility.) (3) Under our commercial paper program, we had net borrowings of approximately $0.9 billion as of December 31, 2017 , which includes gross borrowings of $12.9 billion and gross repayments of $12.0 billion (4) Under our Credit Facilities, we had net repayments of approximately $1.1 billion as of December 31, 2017 , which includes gross borrowings of $1.9 billion and gross repayments of $3.0 billion

ASSET RETIREMENT OBLIGATIONS (T

ASSET RETIREMENT OBLIGATIONS (Tables)	12 Months Ended
	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Asset Retirement Obligations	A reconciliation of movements to our ARO liabilities is as follows: December 31, 2017 2016 (in millions) Balance at beginning of year $ 98 $ 100 Revisions in estimates 3 (1 ) Accretion expense 5 1 Liabilities settled — (2 ) Balance at end of year $ 106 $ 98

NONCONTROLLING INTERESTS (Table

NONCONTROLLING INTERESTS (Tables)	12 Months Ended
	Dec. 31, 2017
Noncontrolling Interest [Abstract]
Schedule of Non Controlling Interest	The following tables present additional information regarding NCI as presented on our consolidated statements of financial position and net income (loss) attributable to NCI as presented on our consolidated statements of income: December 31, 2017 2016 (in millions) Eastern Access Interests (1) $ 1,465 $ 1,892 U.S. Mainline Expansion Interests (1) 1,643 1,621 North Dakota Pipeline Company Interests (2) 15 30 Line 3 Replacement Interests (1) 686 — Enbridge Holdings (DakTex) L.L.C. Interests (3) 1,160 — Total $ 4,969 $ 3,543 ____________ (1) Represents the NCI in the OLP arising from the joint funding arrangements with our General Partner and its affiliate to finance certain expansion projects on our Lakehead System, which we refer to as the Eastern Access Project, Mainline Expansion Project and U.S. Line 3 Replacement Program. (2) Represents the NCI in NDPC arising from our agreement with Williston, an affiliate of MPC. (3) Represents the NCI in DakTex arising from the joint funding arrangement with our General Partner to finance our investment in the Bakken Pipeline System through our equity investment in MarEn.
Schedule Of Net Income Or Loss Attributable To Noncontrolling Interest	For the year ended December 31, 2017 2016 2015 (in millions) Alberta Clipper Interests $ — $ — $ (1 ) Eastern Access Interests 152 205 190 U.S. Mainline Expansion Interests 147 138 108 North Dakota Pipeline Company Interests (1) 21 (271 ) — Line 3 Replacement Interests 29 — — Enbridge Holdings (DakTex) L.L.C. Interests 39 — — Midcoast Energy Partners, L.P. - Discontinued Operations (19 ) (46 ) (76 ) Total $ 369 $ 26 $ 221 ____________ (1) Inclusive of impairment on the Sandpiper Project attributable to NCI for the year ending December 31, 2016 . For further details, see Note 9 - Property, Plant and Equipment .

PARTNERS' CAPITAL (Tables)

PARTNERS' CAPITAL (Tables)	12 Months Ended
	Dec. 31, 2017
Partners' Capital Notes [Abstract]
Schedule of Capital Units	2017 Series 1 preferred units Class D units Class E units Class F units Class A common units Class B common units i-units Incentive distribution units Balance at beginning of year 48,000,000 66,100,000 18,114,975 — 262,208,428 7,825,500 81,857,168 1,000 Waiver of units (48,000,000 ) (66,100,000 ) — — — — — (1,000 ) Issuances — — — 1,000 64,308,682 — — — Distributions — — — — — — 7,941,650 — Balance at end of year — — 18,114,975 1,000 326,517,110 7,825,500 89,798,818 — 2016 Balance at beginning of year 48,000,000 66,100,000 18,114,975 — 262,208,428 7,825,500 73,285,739 1,000 Distributions — — — — — — 8,571,429 — Balance at end of year 48,000,000 66,100,000 18,114,975 — 262,208,428 7,825,500 81,857,168 1,000 2015 Balance at beginning of year 48,000,000 66,100,000 — — 254,208,428 7,825,500 68,305,187 1,000 Issuances — — 18,114,975 — 8,000,000 — — — Distributions — — — — — — 4,980,552 — Balance at end of year 48,000,000 66,100,000 18,114,975 — 262,208,428 7,825,500 73,285,739 1,000
Schedule of Net Proceeds from Class A Common Units through Equity Offerings	The following table presents the net proceeds from our Class A common unit issuances for the year ended December 31, 2017 and 2015 . There were no issuances of Class A common units for the years ended December 31, 2016 . Issuance Date Number of Class A common unit Issued Offering Price per Class A common units Net Proceeds to the Partnership (1) General Partner Contribution (2) Net Proceeds Including General Partner Contribution (in millions, except units and per unit amounts) April, 2017 64,308,682 $ 18.66 $ 1,200 $ 24 $ 1,224 March, 2015 8,000,000 $ 36.70 $ 289 $ 6 $ 295 (1) Net of underwriters’ fees and discounts, commissions and issuance expenses. (2) Contributions made by the General Partner to maintain its 2% general partner interest.
Schedule of Distributions	The following table sets forth our distributions, as approved by the board of directors of Enbridge Management, during the years ended December 31, 2017 , 2016 and 2015 . Distribution Declaration Date Record Date Distribution Payment Date Distribution per Unit Cash Available for Distribution Amount of Distribution of i-units to i-unit Holders (1) Retained from General Partner (2) Distribution of Cash (in millions, except per unit amounts) 2017 October 27 November 7 November 14 $ 0.350 $ 161 $ 30 $ 1 $ 130 July 28 August 7 August 14 $ 0.350 160 29 1 130 April 27 May 8 May 15 $ 0.350 160 30 1 129 January 26 February 7 February 14 $ 0.583 265 48 1 216 $ 746 $ 137 $ 4 $ 605 2016 October 28 November 7 November 14 $ 0.583 $ 264 $ 47 $ 1 $ 216 July 28 August 5 August 12 $ 0.583 262 45 1 216 April 29 May 6 May 13 $ 0.583 261 44 1 216 January 29 February 5 February 12 $ 0.583 260 43 1 216 $ 1,047 $ 179 $ 4 $ 864 2015 October 30 November 6 November 13 $ 0.583 $ 259 $ 41 $ 1 $ 217 July 30 August 7 August 14 $ 0.583 258 41 1 $ 216 April 30 May 8 May 15 $ 0.570 250 40 1 $ 209 January 29 February 6 February 13 $ 0.570 234 39 1 $ 194 $ 1,001 $ 161 $ 4 $ 836 ____________ (1) We issued 7,941,650 , 8,571,429 and 4,980,552 i-units to Enbridge Management, L.L.C., the sole owner of our i-units, during 2017 , 2016 and 2015 , respectively, in lieu of cash distributions. (2) We retained an amount equal to 2% of the i-unit distribution from our General Partner to maintain its 2% general partner interest in us.

DERIVATIVE FINANCIAL INSTRUME45

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Tables)	12 Months Ended
	Dec. 31, 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: December 31, 2017 2016 (in millions) Accounts payable and other (9 ) (146 ) Other long-term liabilities (2 ) (21 ) $ (11 ) $ (167 )
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). December 31, 2017 2016 (in millions) Counterparty Credit Quality (1) AA $ (4 ) $ (79 ) A (7 ) (59 ) Lower than A — (29 ) $ (11 ) $ (167 ) ____________ (1) As determined by nationally-recognized statistical ratings organizations.
Schedule of Credit Concentrations in Industry Sectors	At December 31, 2017 and 2016 , we had credit concentrations in the following industry sectors, as presented below: December 31, 2017 2016 (in millions) United States financial institutions and investment banking entities $ (7 ) $ (122 ) Non-United States financial institutions (4 ) (45 ) $ (11 ) $ (167 )
Effect of Derivative Instruments on the Consolidated Statements of Financial Position	Asset Derivatives Liability Derivatives Fair Value at December 31, Fair Value at December 31, Financial Position Location 2017 2016 2017 2016 (in millions) Derivatives designated as hedging instruments: (1) Interest rate contracts Accounts payable and other $ — $ — $ (5 ) $ (144 ) Interest rate contracts Other long-term liabilities — — (1 ) (21 ) — — (6 ) (165 ) Derivatives not designated as hedging instruments: Commodity contracts Accounts payable and other — — (4 ) $ (2 ) Commodity contracts Other long-term liabilities — — (1 ) — — — (5 ) (2 ) Total derivative instruments $ — $ — $ (11 ) $ (167 ) ____________ (1) Includes items currently designated as hedging instruments. Excludes the portion of de-designated hedges which may have a component remaining in AOCI.
Effect of Derivative Instruments on the Consolidated Statements of Income and Accumulated Other Comprehensive Income	Derivatives in Cash Flow Hedging Relationships Amount of Gain (Loss) Recognized in AOCI on Derivative (Effective Portion) Location of Gain (Loss) Reclassified from AOCI to Earnings (Effective Portion) Amount of Gain (Loss) Reclassified from AOCI to Earnings (Effective Portion) (1) Location of Gain (Loss) Recognized in Earnings on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing) (1) Amount of Gain (Loss) Recognized in Earnings on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing) (2) (in millions) For the year ended December 31, 2017 Interest rate contracts $ 109 Interest expense $ (208 ) Interest expense $ 50 Total $ 109 $ (208 ) $ 50 For the year ended December 31, 2016 Interest rate contracts $ (1 ) Interest expense $ (39 ) Interest expense $ (7 ) Total $ (1 ) $ (39 ) $ (7 ) For the year ended December 31, 2015 Interest rate contracts $ 87 Interest expense $ (22 ) Interest expense $ 99 Total $ 87 $ (22 ) $ 99 ____________ (1) Includes reclassification of $168 million loss related to the termination of long-term interest rate swaps as not highly probable to issue long-term debt. (2) Includes only the ineffective portion of derivatives that are designated as hedging instruments and does not include net gains or losses associated with derivatives that do not qualify for hedge accounting treatment.
Components of Accumulated Other Comprehensive Income/(Loss)	Cash Flow Hedges 2017 2016 (in millions) Balance at January 1 $ (339 ) $ (370 ) Other comprehensive income before reclassifications (68 ) (8 ) Amounts reclassified from AOCI (1)(2) 208 39 Net other comprehensive income 140 31 Balance at December 31 $ (199 ) $ (339 ) ____________ (1) For additional details on the amounts reclassified from AOCI, reference the Reclassifications from Accumulated Other Comprehensive Income table below. (2) Includes reclassification of $168 million loss related to the termination of long-term interest rate swaps as not highly probable to issue long-term debt.
Reclassifications from Accumulated Other Comprehensive Income	For the year ended December 31, 2017 2016 2015 (in millions) Losses on cash flow hedges: Interest Rate Contracts (1) $ 208 $ 39 $ 22 Total Reclassifications from AOCI $ 208 $ 39 $ 22 ____________ (1) Loss reported within “Interest expense, net” in the consolidated statements of income.
Effect of Derivative Instruments on Consolidated Statements of Income	Derivatives Not Designated as Hedging Instruments Location of Gain (Loss) Recognized in Earnings December 31, 2017 2016 2015 Amount of Gain (Loss) Recognized in Earnings (1)(2) (in millions) Commodity contracts Transportation and other services (3) $ (3 ) $ (3 ) $ 11 Total $ (3 ) $ (3 ) $ 11 ____________ (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 nil , $6 million , and $27 million for the years ended December 31, 2017 , 2016 and 2015 , respectively.
Offsetting of Financial Liabilities and Derivative Liabilities	As of December 31, 2017 Gross Amount of Recognized Liabilities Gross Amount Offset in the Statement of Financial Position Net Amount of Liabilities Presented in the Statement of Financial Position Gross Amount Not Offset in the Statement of Financial Position Net Amount (in millions) Description: Derivatives $ (11 ) $ — $ (11 ) $ — $ (11 ) As of December 31, 2016 Gross Amount of Recognized Liabilities Gross Amount Offset in the Statement of Financial Position Net Amount of Liabilities Presented in the Statement of Financial Position Gross Amount Not Offset in the Statement of Financial Position Net Amount (in millions) Description: Derivatives $ (167 ) $ — $ (167 ) $ — $ (167 )
Table Setting Forth By Level Within The Fair Value Hierarchy Financial Assets And Liabilities	December 31, 2017 December 31, 2016 Level 2 Level 2 (in millions) Interest rate contracts $ (6 ) $ (165 ) Commodity contracts: Financial (5 ) (2 ) $ (11 ) $ (167 )
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 and physical contracts at December 31, 2017 and 2016 . At December 31, 2017 At December 31, 2016 Wtd. Average Price (2) Fair Value (3) Fair Value (3) Commodity Notional (1) Receive Pay Asset Liability Asset Liability Portion of contracts matured in 2017 Swaps: Receive fixed/pay variable Crude Oil 123,832 $ 51.91 $ 51.98 $ — $ — $ — $ (2 ) Portion of contracts maturing in 2018 Swaps: Receive fixed/pay variable Crude Oil 498,955 $ 50.71 $ 59.31 $ — $ (4 ) $ — $ — Portion of contracts maturing in 2019 Swaps: Receive fixed/pay variable Crude Oil 353,685 $ 55.22 $ 55.86 $ — $ (1 ) $ — $ — ____________ (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 December 31, 2017 and 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 December 31, 2017 and 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. Date of Maturity & Contract Type Accounting Treatment Notional Average Fixed Rate (1) Fair Value (2) at December 31, 2017 December 31, 2016 (in millions) Contracts matured in 2017 Interest Rate Swaps – Pay Fixed Cash Flow Hedge $ 500 2.21 % $ — $ (1 ) Contracts maturing in 2018 Interest Rate Swaps – Pay Fixed Cash Flow Hedge $ 810 2.24 % $ — $ (9 ) Contracts maturing in 2019 Interest Rate Swaps – Pay Fixed Cash Flow Hedge $ 620 2.96 % $ (6 ) $ (7 ) Contracts settled prior to maturity 2017 - Pre-issuance Hedges Cash Flow Hedge $ 1,000 4.07 % $ — $ (136 ) 2018 - Pre-issuance Hedges Cash Flow Hedge $ 350 3.08 % $ — $ (13 ) ____________ (1) Interest rate derivative contracts are based on the one-month or three-month LIBOR. (2) The fair value is determined from quoted market prices at December 31, 2017 and 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 nil and $1 million at December 31, 2017 and 2016 , respectively.

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Schedule of Income Tax Expense	Our income tax expense is summarized below: For the year ended December 31, 2017 2016 2015 (in millions) Current state $ (5 ) $ 3 $ 4 Deferred state (3 ) (4 ) (1 ) Total income tax (benefit) expense $ (8 ) $ (1 ) $ 3
Effective Income Tax Rate Reconciliation	Our effective tax rate is as follows: For the year ended December 31, 2017 2016 2015 (in millions) Income before income tax $ 700 $ 115 $ 742 State income tax (benefit) expense $ (8 ) $ (1 ) $ 3 Effective income tax rate (1.1 )% (0.9 )% 0.4 %
Unrecognized Tax Schedule	The following is a reconciliation of our beginning and ending balance of unrecognized tax benefits in millions: December 31, 2017 2016 2015 (in millions) Unrecognized tax benefits at January 1 $ 39 $ 37 $ 33 Additions for tax positions taken in current period 1 2 4 Lapses of statute of limitations (6 ) — — Unrecognized tax benefits at December 31 $ 34 $ 39 $ 37

CHANGES IN OPERATIG ASSETS AND

CHANGES IN OPERATIG ASSETS AND LIABILITIES (Tables)	12 Months Ended
	Dec. 31, 2017
Supplemental Cash Flow Information [Abstract]
Schedule of Change in Working Capital	Changes in our working capital accounts are shown in the following table: For the year ended December 31, 2017 2016 2015 (in millions) Receivables, trade and other (59 ) 6 18 Due from General Partner and affiliates (26 ) (42 ) (31 ) Accrued receivables (86 ) 3 9 Inventory 1 — 10 Current and long-term other assets 47 8 (40 ) Due to General Partner and affiliates (127 ) (14 ) 28 Accounts payable and other (26 ) (76 ) 5 Environmental liabilities (91 ) (19 ) (44 ) Accrued purchases (2 ) 3 2 Interest payable (5 ) (4 ) 24 Current income tax payable 1 (2 ) — Property and other taxes payable 15 7 10 Changes in operating assets and liabilities (358 ) (130 ) (9 )

RELATED PARTY TRANSACTIONS (Tab

RELATED PARTY TRANSACTIONS (Tables)	12 Months Ended
	Dec. 31, 2017
Related Party Transactions [Abstract]
Schedule of Incentive Distributions Made to Managing Members or General Partners by Distribution	Our General Partner’s outstanding ownership interests on us at December 31, 2017 and 2016 , and the total distributions we paid to the General Partner for the years ending December 31, 2017 , 2016 and 2015 were as follows: General Partner’s Ownership Interests Cash Distributions Paid to General Partner (in units) (percentage) (1) (in millions) Type of Unit 2017 2016 2017 2016 2017 2016 2015 Series 1 preferred units (2) — 48,000,000 — % 9.7 % $ — $ — $ — Class D units — 66,100,000 — % 13.3 % $ 39 $ 154 $ 152 Class E units 18,114,975 18,114,975 4.0 % 3.7 % $ 29 $ 42 $ 32 Class A common units 110,827,018 46,518,336 24.6 % 9.4 % $ 143 $ 109 $ 107 Class B common units 7,825,500 7,825,500 1.7 % 1.6 % $ 13 $ 18 $ 18 Class F units 1,000 — — % — % $ 11 $ — $ — IDUs — 1,000 — % — % $ 5 $ 21 $ 17 General Partner interest — — 2.0 % 2.0 % $ 12 $ 17 $ 17 Enbridge Management shares (Listed and Voting) (3) 10,494,464 9,566,358 2.3 % 2.0 % $ — $ — $ — Total 147,262,957 196,126,169 34.6 % 41.7 % 252 361 343 ____________ (1) Represents the General Partners' interest in our total outstanding units. (2) For each of the years ended December 31, 2017 , 2016 and 2015 , total distributions of $29 million , $90 million and $90 million were accrued for the series 1 preferred units in the consolidated statements of financial position. (3) For the years ended December 31, 2017 , 2016 , and 2015 , we made total non-cash distributions of $16 million , $21 million , and $19 million , respectively, to the Listed and Voting Shares of Enbridge Management owned by the General Partner.
Schedule of Distributions	The following table presents distributions paid by the OLP during the years ended December 31, 2017 , 2016 and 2015 , to our General Partner and its affiliate, representing the noncontrolling interest in the Series EA, and to us, as the holders of the Series EA general and limited partner interests. The distributions were declared by the board of directors of Enbridge Management, acting on behalf of Enbridge Pipelines (Lakehead), L.L.C., the managing general partner of the OLP and the Series EA interests . Distribution Declaration Date Distribution Payment Date Amount Paid to EEP Amount Paid to the noncontrolling interest Total Series EA Distribution (in millions) 2017 October 25 November 14 $ 35 $ 51 $ 86 July 28 August 14 33 50 83 April 27 May 15 29 62 91 January 26 February 14 23 69 92 $ 120 $ 232 $ 352 2016 October 28 November 14 $ 22 $ 65 $ 87 July 28 August 12 21 63 84 April 29 May 13 79 — 79 January 29 February 12 79 — 79 $ 201 $ 128 $ 329 2015 October 30 November 13 $ 76 $ — $ 76 July 30 August 14 76 — 76 April 30 May 15 18 52 70 January 29 February 13 22 67 89 $ 192 $ 119 $ 311 The following table presents the distributions paid by the OLP during the years ended December 31, 2015, to our General Partner and its affiliate, representing the noncontrolling interest in the Series AC, and to us, as the holders of the Series AC general and limited partner interests. The distributions were declared by the board of directors of Enbridge Management, acting on behalf of Enbridge Pipelines (Lakehead) L.L.C., the managing general partner of the OLP and the Series AC interests. Pursuant to the OLP’s partnership agreement, the final ownership distribution for the Series AC interests was distributed to Series AC partners of record as of the last day of the fourth quarter of 2014. Distribution Declaration Date Distribution Payment Date Amount Paid to Partnership Amount Paid to the noncontrolling interest Total Series AC Distribution (in millions) 2015 January 29 February 13 $ 14 $ 27 $ 41 The following table presents distributions paid by DakTex during the year ended December 31, 2017 , to our General Partner and its affiliates, representing NCI in Class A units of DakTex, and to us, as the holders of the remaining Class A units of DakTex. Distribution Declaration Date Distribution Payment Date Amount Paid to EEP Amount Paid to the noncontrolling interest Total DakTex Distribution (in millions) 2017 December 19 December 28 $ 11 $ 32 $ 43 September 25 September 29 10 31 41 $ 21 $ 63 $ 84 The following table presents distributions paid by MEP during the years ended December 31, 2017 , 2016 and 2015 , to its public Class A common unitholders, representing the noncontrolling interest in MEP, and to us for our ownership of Class A common units. Distribution Declaration Date Distribution Payment Date Amount Paid to EEP Amount Paid to the noncontrolling interest Total MEP Distribution (in millions) 2017 January 26 February 14 $ 9 $ 8 $ 17 $ 9 $ 8 $ 17 2016 October 27 November 14 $ 9 $ 8 $ 17 July 27 August 12 9 7 16 April 28 May 13 9 8 17 January 28 February 12 9 7 16 $ 36 $ 30 $ 66 2015 October 29 November 13 $ 9 $ 8 $ 17 July 29 August 14 9 7 16 April 29 May 15 9 7 16 January 28 February 13 8 8 16 $ 35 $ 30 $ 65 The following table presents distributions paid by the OLP during the years ended December 31, 2017 , 2016 and 2015 , to our General Partner and its affiliate, representing the noncontrolling interest in the Series ME, and to us, as the holders of the Series ME general and limited partner interests. The distributions were declared by the board of directors of Enbridge Management, acting on behalf of Enbridge Pipelines (Lakehead), L.L.C., the managing general partner of the OLP and the Series ME interests. Distribution Declaration Date Distribution Payment Date Amount Paid to EEP Amount Paid to the noncontrolling interest Total Series ME Distribution (in millions) 2017 October 25 November 14 $ 15 $ 44 $ 59 July 28 August 14 14 41 55 April 27 May 15 13 38 51 January 26 February 14 14 43 57 $ 56 $ 166 $ 222 2016 October 28 November 14 $ 15 $ 44 $ 59 July 28 August 12 13 40 53 April 29 May 13 43 — 43 January 29 February 12 41 — 41 $ 112 $ 84 $ 196 2015 October 30 November 13 $ 32 $ — $ 32 July 30 August 14 20 — 20 April 30 May 15 1 5 6 January 29 February 13 2 5 7 $ 55 $ 10 $ 65

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Tables)	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Schedule of Future Minimum Commitments	At December 31, 2017 , we had our commitments that have remaining non-cancelable terms in excess of one year as detailed below: Payments due by Period 2018 2019 2020 2021 2022 Thereafter Total (in millions) Annual debt maturities (1) $ 500 $ 500 $ 1,000 $ 600 $ 1,453 $ 2,850 $ 6,903 Interest obligations (2) 324 280 243 208 183 3,414 $ 4,652 Purchase commitments (3) 255 — — — — — $ 255 Power commitments (4) 26 25 24 10 10 257 $ 352 Operating leases 3 3 2 1 1 — $ 10 Right-of-way 2 2 2 2 2 36 $ 46 Product purchase obligations (5) 32 16 15 8 — — $ 71 Other long-term liabilities (6) — — 1 1 1 6 $ 9 Total $ 1,142 $ 826 $ 1,287 $ 830 $ 1,650 $ 6,563 $ 12,298 (1) Represents scheduled future maturities of our consolidated third-party debt principal obligations excluding any discounts. We have the ability under certain debt facilities to repay the obligations prior to scheduled maturities. Therefore, the actual timing of future cash repayments could be materially different than presented above. For information regarding our consolidated debt obligations, see Item 8. Financial Statements and Supplementary Data — Note 13 - Debt . (2) Estimated cash payments for third-party interest exclude adjustments for derivative agreements and cash payments for interest on variable-rate debt. We borrow and repay at varying amounts and interest rates. For more information on our debt obligations, see Item 8. Financial Statements and Supplementary Data — Note 13 - Debt . (3) Represents commitments to purchase materials, primarily pipe from third-party suppliers in connection with our growth projects. (4) Represents commitments to purchase power, included certain power commitments with obligations that are dependent on variable components. For these commitments, we only included the determinable portion of our commitment based on the contracted usage requirement and the current applicable contract rate. (5) Represents long-term product purchase commitments to purchase drag reducing agents. (6) Includes noncurrent portion of capital leases. We are unable to estimate deferred income taxes (see Note 18 - Income Taxes ) since cash payments for income taxes are determined primarily by taxable income for each discrete fiscal year. We are also unable to estimate asset retirement obligations (see Note 14 - Asset Retirement Obligations ), environmental liabilities (see Note 21 - Commitments and Contingencies ) and hedges payable (see Note 17 - Derivative Financial Instruments and Hedging Activities ) due to the uncertainty as to the amount and, or, timing of when cash payments will be required.
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: December 31, 2017 (in millions) Response personnel and equipment $ 547 Environmental consultants 224 Professional, regulatory, fines and penalties and other 444 Total $ 1,215

QUARTERLY FINANCIAL DATA (Una50

QUARTERLY FINANCIAL DATA (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Data [Abstract]
Schedule of Quarterly Financial Data	First Second Third Fourth Total (in millions, except per unit amounts) 2017 Quarters Operating revenue $ 605 $ 597 $ 616 $ 610 $ 2,428 Operating income 269 312 266 274 1,121 Income from continuing operations 179 232 196 101 708 Loss from discontinued operations, net of tax (22 ) (35 ) — — (57 ) Net income 157 197 196 101 651 Net income (loss) attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P. - continuing operations 79 117 93 (6 ) 283 Net income (loss) attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P. - discontinued operations (14 ) (24 ) — — (38 ) Net income (loss) per common unit and i-unit (basic and diluted): Income (loss) from continuing operations 0.19 0.27 0.19 (0.05 ) 0.60 Loss from discontinued operations (0.04 ) (0.06 ) — — (0.10 ) Net income (loss) per common unit and i-unit $ 0.15 $ 0.21 $ 0.19 $ (0.05 ) $ 0.50 2016 Quarters Operating revenue $ 630 $ 621 $ 635 $ 630 $ 2,516 Operating income (loss) (1) 296 323 (449 ) 311 481 Income from continuing operations 203 241 (544 ) 216 116 Loss from discontinued operations, net of tax (30 ) (63 ) (31 ) (33 ) (157 ) Net income (loss) 173 178 (575 ) 183 (41 ) Net income (loss) attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P. - continuing operations 101 130 (385 ) 103 (51 ) Net income (loss) attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P. - discontinued operations (21 ) (46 ) (22 ) (22 ) (111 ) Net income (loss) per common unit and i-unit (basic and diluted): Income (loss) from continuing operations 0.13 0.21 (1.25 ) 0.14 (0.77 ) Loss from discontinued operations (0.06 ) (0.13 ) (0.06 ) (0.06 ) (0.31 ) Net income (loss) per common unit and i-unit $ 0.07 $ 0.08 $ (1.31 ) $ 0.08 $ (1.08 ) ____________ (1) Third quarter 2016 operating expenses were impacted by an asset impairment of $757 million . For more information, refer to Note 9 - Property, Plant and Equipment .

BUSINESS OVERVIEW (Details)

BUSINESS OVERVIEW (Details) $ / shares in Units, bbl in Millions, $ in Millions	1 Months Ended	12 Months Ended
	Jan. 26, 2017USD ($)$ / shares	Dec. 31, 2017operating_segmentpump_stationMilesbbl	Dec. 31, 2016
Number of reporting segments (in segments) | operating_segment		1
Enbridge Inc. [Member]
Per share price of acquisition (in dollars per share) | $ / shares	$ 8
Transaction value of acquisition | $	$ 170
Percentage of interest acquired (in percentage)	25.00%
Ownership interest in affiliate of Partnership (in percentage)		34.60%	41.70%
Lakehead System [Member]
Length of pipeline (in miles) | Miles		4,212
Number of pump stations (in stations) | pump_station		74
Period of operation		60 years
North Dakota System [Member]
Length of pipeline (in miles) | Miles		660
Number of pump stations (in stations) | pump_station		12
Mid Continent System [Member]
Crude oil capacity (in barrels) | bbl		20

SUMMARY OF SIGNIFICANT ACCOUN52

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Details)	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Additional period thereafter related to gains and losses deferred in AOCI	2 months

NET INCOME PER LIMITED PARTNE53

NET INCOME PER LIMITED PARTNER UNIT (Narrative) (Details) - shares	Apr. 27, 2017	Apr. 27, 2017	Apr. 27, 2017	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Jan. 02, 2015
Class D Units [Member]
Waiver of units	66,000,000				(66,100,000)
Anti-dilutive Preferred Units excluded (in shares)					66,100,000	66,100,000	66,100,000
Class E Units [Member]
Anti-dilutive Preferred Units excluded (in shares)					18,114,975	18,114,975	18,114,975
Alberta Clipper Pipeline [Member]
Percentage of interest acquired (in percentage)								66.70%
Incentive Distribution Units
Waiver of units		1,000
Common Class F [Member]
Number of units issued in transaction (in shares)		1,000
Minimum Quarterly Distribution [Member]
Percentage Distributed to General Partner (in percentage)			2.00%	2.00%	2.00%
Percentage Distributed to Limited Partners (in percentage)			98.00%	98.00%	98.00%

NET INCOME PER LIMITED PARTNE54

NET INCOME PER LIMITED PARTNER UNIT (Formula for Distributing Available Cash in Partnership Agreement) (Details) - $ / shares	3 Months Ended		4 Months Ended	8 Months Ended	12 Months Ended
	Dec. 31, 2015	Jun. 30, 2015	Apr. 27, 2017	Dec. 31, 2017	Dec. 31, 2017
Portion of Quarterly Distribution Per Unit, minimum (in dollars per share)	$ 0.5435
General Partners Capital Account Distribution Rate					2.00%
Minimum Quarterly Distribution [Member]
Portion of Quarterly Distribution Per Unit, maximum (in dollars per share)		$ 0.295			$ 0.5435
Percentage distributed to General Partner and IDUs (in percentage)			2.00%	2.00%	2.00%
Percentage Distributed to Limited Partners (in percentage)			98.00%	98.00%	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 and IDUs (in percentage)			25.00%	15.00%
Percentage Distributed to Limited Partners (in percentage)			75.00%	85.00%
Over Second Target Distribution [Member]
Portion of Quarterly Distribution Per Unit, minimum (in dollars per share)		$ 0.35
Percentage distributed to General Partner and IDUs (in percentage)				25.00%
Percentage Distributed to Limited Partners (in percentage)				75.00%

NET INCOME PER LIMITED PARTNE55

NET INCOME PER LIMITED PARTNER UNIT (Basic and Diluted Net Income Per Limited Partner Unit) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								4 Months Ended	8 Months Ended	12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Apr. 27, 2017	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Continuing operations:	$ 101	$ 196	$ 232	$ 179	$ 216	$ (544)	$ 241	$ 203			$ 708	$ 116	$ 739
Less: Net income attributable to:
Noncontrolling interest											388	72	297
Series 1 preferred unit distributions											29	90	90
Accretion of discount on Series 1 preferred units											8	5	11
Net income (loss) attributable to general and limited partner interests in Enbridge Energy Partners, L.P. - continuing operations	(6)	93	117	79	103	(385)	130	101			283	(51)	341
Distributions:
Incentive distributions											(15)	(21)	(19)
Total distributed earnings to our General Partner, Class D, Class E units Class F units and IDUs											(53)	(238)	(235)
Total distributed earnings attributed to our common units and i-units											(589)	(814)	(791)
Total distributed earnings											(642)	(1,052)	(1,026)
Overdistributed earnings											(359)	(1,103)	(685)
Discontinued operations:
Loss from discontinued operations, net of tax	0	0	(35)	(22)	(33)	(31)	(63)	(30)			(57)	(157)	(285)
Noncontrolling interest											(19)	(46)	(76)
Net loss attributable to general and limited partner interests in Enbridge Energy Partners, L.P. - discontinued operations	$ 0	$ 0	$ (24)	$ (14)	$ (22)	$ (22)	$ (46)	$ (21)			$ (38)	$ (111)	$ (209)
Weighted average common units and i-units outstanding											400	348	339
Basic and diluted earnings per unit:
Distributed earnings per common unit and i-unit (in dollars per share)											$ 1.48	$ 2.34	$ 2.33
Overdistributed Earnings Per Limited Partnership Unit Outstanding											(0.88)	(3.11)	(1.98)
Income (Loss) from Continuing Operations, Per Outstanding Limited Partnership and General Partnership Unit, Basic and Diluted, Net of Tax											0.60	(0.77)	0.35
Loss from discontinued operations (in dollars per share)	$ 0	$ 0	$ (0.06)	$ (0.04)	$ (0.06)	$ (0.06)	$ (0.13)	$ (0.06)			(0.10)	(0.31)	(0.60)
Net income (loss) per common unit and i-unit (basic and diluted) (in dollars per share)											$ 0.50	$ (1.08)	$ (0.25)
Preferred Stock [Member]
Basic and diluted earnings per unit:
Anti-dilutive Preferred Units excluded (in shares)											43,201,310	43,201,310	43,201,310
General Partner [Member]
Distributions:
Distributed earnings attributed to our General Partner											$ (13)	$ (21)	$ (21)
Class D and Class E Units [Member]
Distributions:
Total distributed earnings to our General Partner, Class D, Class E units Class F units and IDUs											$ (25)	$ (196)	$ (195)
Minimum Quarterly Distribution [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Percentage Distributed to Limited Partners (in percentage)									98.00%	98.00%	98.00%
Class D Units [Member]
Basic and diluted earnings per unit:
Anti-dilutive Preferred Units excluded (in shares)											66,100,000	66,100,000	66,100,000
Class E Units [Member]
Basic and diluted earnings per unit:
Anti-dilutive Preferred Units excluded (in shares)											18,114,975	18,114,975	18,114,975

SEGMENT INFORMATION (Details)

SEGMENT INFORMATION (Details) - USD ($)	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Segment Reporting Information [Line Items]
Revenues	$ 610,000,000	$ 616,000,000	$ 597,000,000	$ 605,000,000	$ 630,000,000	$ 635,000,000	$ 621,000,000	$ 630,000,000	$ 2,428,000,000	$ 2,516,000,000	$ 2,303,000,000
Other									57,000,000	1,000,000	0
Depreciation and amortization									(442,000,000)	(427,000,000)	(378,000,000)
Interest expense, net									(525,000,000)	(413,000,000)	(292,000,000)
Income before income taxes									700,000,000	115,000,000	742,000,000
Income tax benefit									8,000,000	1,000,000	(3,000,000)
Net income from continuing operations	101,000,000	196,000,000	232,000,000	179,000,000	216,000,000	(544,000,000)	241,000,000	203,000,000	708,000,000	116,000,000	739,000,000
Net loss from discontinued operations	0	0	(35,000,000)	(22,000,000)	(33,000,000)	(31,000,000)	(63,000,000)	(30,000,000)	(57,000,000)	(157,000,000)	(285,000,000)
Net income (loss)	101,000,000	$ 196,000,000	$ 197,000,000	$ 157,000,000	183,000,000	$ (575,000,000)	$ 178,000,000	$ 173,000,000	651,000,000	(41,000,000)	454,000,000
Total Assets	14,828,000,000				18,110,000,000				14,828,000,000	18,110,000,000
Operating Segments [Member]
Segment Reporting Information [Line Items]
Revenues									2,428,000,000	2,516,000,000	2,303,000,000
Total consolidated									1,674,000,000	964,000,000	1,441,000,000
Depreciation and amortization									(442,000,000)	(427,000,000)	(378,000,000)
Interest expense, net									(525,000,000)	(413,000,000)	(292,000,000)
Income before income taxes									700,000,000	115,000,000	742,000,000
Income tax benefit									8,000,000	1,000,000	(3,000,000)
Net income (loss)									651,000,000	(41,000,000)	454,000,000
Capital and Investment Expenditures									586,000,000	797,000,000	1,976,000,000
Total Assets	14,819,000,000				13,031,000,000				14,819,000,000	13,031,000,000
Operating Segments [Member] | Liquids [Member]
Segment Reporting Information [Line Items]
Revenues									2,428,000,000	2,516,000,000	2,303,000,000
Total consolidated									1,674,000,000	964,000,000	1,441,000,000
Capital and Investment Expenditures									586,000,000	797,000,000	1,976,000,000
Total Assets	14,819,000,000				13,031,000,000				14,819,000,000	13,031,000,000
Other [Member]
Segment Reporting Information [Line Items]
Revenues									0	0	0
Other									(7,000,000)	(9,000,000)	(29,000,000)
Capital and Investment Expenditures									586,000,000	797,000,000	$ 1,976,000,000
Total Assets	$ 9,000,000				165,000,000				$ 9,000,000	165,000,000
Continuing Operations [Member]
Segment Reporting Information [Line Items]
Total Assets					$ 13,196,000,000					$ 13,196,000,000

SEGMENT INFORMATION (Narrative)

SEGMENT INFORMATION (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Segment Reporting Information [Line Items]
Revenues	$ 610	$ 616	$ 597	$ 605	$ 630	$ 635	$ 621	$ 630	$ 2,428	$ 2,516	$ 2,303
Customer Concentration Risk [Member]
Segment Reporting Information [Line Items]
Revenues										$ 257	$ 338
Concentration risk, percentage										10.70%	15.60%
Customer One [Member]
Segment Reporting Information [Line Items]
Revenues									$ 392
Customer One [Member] | Customer Concentration Risk [Member]
Segment Reporting Information [Line Items]
Concentration risk, percentage									16.90%
Customer Two [Member]
Segment Reporting Information [Line Items]
Revenues									$ 239
Customer Two [Member] | Customer Concentration Risk [Member]
Segment Reporting Information [Line Items]
Concentration risk, percentage									10.30%

REGULATORY MATTERS (Details)

REGULATORY MATTERS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Allowance for equity used during construction	$ 47	$ 46	$ 70
Regulatory Assets and Liabilities [Roll Forward]
Net regulatory asset balance at beginning of period	12	30	6
Current year under recovery adjustments	3	12	30
Amortization of prior year regulatory asset	(12)	(30)	(6)
Net regulatory asset balance at end of period	$ 3	$ 12	$ 30
Alberta Clipper Pipeline [Member]
Obligation to refund overcollection to customers (in percentage)	50.00%

DISPOSITIONS AND DISCONTINUED59

DISPOSITIONS AND DISCONTINUED OPERATIONS (Narrative) (Details) - USD ($) $ in Millions	1 Months Ended		12 Months Ended
	Jun. 28, 2017	Mar. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Proceeds from sale of property, plant, and equipment		$ 220	$ 112
Gain (loss) on disposition of assets			74	$ 0	$ 0
Discontinued Operations, Disposed of by Sale [Member]
Increase (decrease) in partners' capital	$ 2,100
Discontinued Operations, Disposed of by Sale [Member] | General Partners [Member]
Proceeds from divestiture of businesses	2,300
Discontinued Operations, Disposed of by Sale [Member] | Midcoast Energy Partners L.P. [Member]
Consideration transferred	1,300
Aggregate indebtedness	$ 953
Equity method investment, ownership percentage	51.90%
Asset held for sale at carrying value	$ 4,300
Noncontrolling interest in limited partnerships	$ 297
Discontinued Operations, Disposed of by Sale [Member] | Midcoast Operating L.P. [Member]
Equity method investment, ownership percentage	48.40%
Discontinued Operations, Disposed of by Sale [Member] | Midcoast Holding LLC [Member]
Noncontrolling interest, ownership percentage by parent (in percent)	100.00%
Sandpiper Project [Member] | Liquids [Member]
Gain (loss) on disposition of assets			63
Ozark Pipeline System [Member] | Liquids [Member]
Gain (loss) on disposition of assets			$ 11

DISPOSITIONS AND DISCONTINUED60

DISPOSITIONS AND DISCONTINUED OPERATIONS (Consolidated Statements of Income) (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating expenses:
Net loss from discontinued operations	$ 0	$ 0	$ (35)	$ (22)	$ (33)	$ (31)	$ (63)	$ (30)	$ (57)	$ (157)	$ (285)
Discontinued Operations, Disposed of by Sale [Member]
Operating revenues:
Operating revenues									1,161	1,966	2,843
Transportation and other services									67	180	196
Operating expenses:
Commodity costs									1,010	1,660	2,373
Operating and administrative									134	294	355
Depreciation and amortization									74	154	158
Asset impairment									0	11	12
Goodwill impairment									0	0	227
Operating expenses, Total									1,218	2,119	3,125
Operating loss									(57)	(153)	(282)
Interest expense, net									(18)	(33)	(30)
Other income									19	31	29
Loss before income taxes									(56)	(155)	(283)
Income tax expense									(1)	(2)	(2)
Net loss from discontinued operations									(57)	(157)	(285)
Discontinued Operations, Disposed of by Sale [Member] | Commodity sales - affiliate [Member]
Operating revenues:
Operating revenues									$ 1,094	$ 1,786	$ 2,647

DISPOSITIONS AND DISCONTINUED61

DISPOSITIONS AND DISCONTINUED OPERATIONS (Consolidated Statements of Financial Position) (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Current assets related to discontinued operations:
Current assets related to discontinued operations, Total	$ 0	$ 139
Non-current assets related to discontinued operations:
Non-current assets related to discontinued operations, Total	0	4,775
Current liabilities related to discontinued operations:
Current liabilities related to discontinued operations, Total	0	300
Non-current liabilities related to discontinued operations:
Non-current liabilities related to discontinued operations, Total	$ 0	844
Discontinued Operations, Disposed of by Sale [Member]
Current assets related to discontinued operations:
Cash and cash equivalents		7
Restricted cash		11
Receivables, trade and other, net of allowance for doubtful accounts		9
Due from General Partner and affiliates		2
Accrued receivables		21
Inventory		28
Other current assets		61
Current assets related to discontinued operations, Total		139
Non-current assets related to discontinued operations:
Property, plant and equipment, net		4,114
Equity investment in joint venture		361
Intangible assets, net		252
Other assets, net		48
Non-current assets related to discontinued operations, Total		4,775
Current liabilities related to discontinued operations:
Accounts payable and other		67
Due to General Partner and affiliates		39
Accrued purchases		172
Property and other taxes payable		17
Interest payable		5
Current liabilities related to discontinued operations, Total		300
Non-current liabilities related to discontinued operations:
Long-term debt		818
Other long-term liabilities		26
Non-current liabilities related to discontinued operations, Total		$ 844

OTHER CURRENT ASSETS (Details)

OTHER CURRENT ASSETS (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]
Regulatory assets	$ 3	$ 12
Prepaid expenses and other	15	16
Inventory	2	3
Other	4	3
Total other current assets	$ 24	$ 34

PROPERTY, PLANT AND EQUIPMENT63

PROPERTY, PLANT AND EQUIPMENT (Schedule of Property, Plant and Equipment) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Property, Plant and Equipment [Line Items]
Total property, plant and equipment	$ 15,706	$ 15,001
Accumulated depreciation	(2,810)	(2,393)
Property, plant and equipment, net	12,896	12,608
Land [Member]
Property, Plant and Equipment [Line Items]
Total property, plant and equipment	$ 78	79
Right-of-way [Member]
Property, Plant and Equipment [Line Items]
Depreciation rate	2.92%
Total property, plant and equipment	$ 477	473
Pipelines [Member]
Property, Plant and Equipment [Line Items]
Depreciation rate	2.76%
Total property, plant and equipment	$ 8,731	8,571
Pumping Equipment, Buildings and Tanks [Member]
Property, Plant and Equipment [Line Items]
Depreciation rate	3.16%
Total property, plant and equipment	$ 5,144	4,866
Vehicles, Office Furniture and Equipment [Member]
Property, Plant and Equipment [Line Items]
Depreciation rate	3.35%
Total property, plant and equipment	$ 167	148
Construction in Progress [Member]
Property, Plant and Equipment [Line Items]
Total property, plant and equipment	$ 1,109	$ 864

PROPERTY, PLANT AND EQUIPMENT64

PROPERTY, PLANT AND EQUIPMENT (Narrative) (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Sep. 30, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Sep. 01, 2016
Property, Plant and Equipment [Line Items]
Depreciation		$ 421	$ 408	$ 366
Assets held-for-sale, not part of disposal group, other		207
Asset impairment charges	$ 757
Non-cash impairment loss		0	$ 757	63
Sandpiper Project [Member]
Property, Plant and Equipment [Line Items]
Asset impairment charges		757
Fair value of assets held for sale					$ 55
Sandpiper Project [Member] | Noncontrolling Interest [Member]
Property, Plant and Equipment [Line Items]
Asset impairment charges		267
Berthhold Rail Facility [Member]
Property, Plant and Equipment [Line Items]
Non-cash impairment loss				$ 63
Land [Member] | Sandpiper Project [Member]
Property, Plant and Equipment [Line Items]
Fair value of assets held for sale		$ 3

VARIABLE INTEREST ENTITIES (Nar

VARIABLE INTEREST ENTITIES (Narrative) (Details) - USD ($) $ in Millions	Apr. 27, 2017	Dec. 31, 2017	Dec. 31, 2016
Enbridge Energy Limited Partnership [Member] | Variable Interest Entity, Primary Beneficiary [Member]
Variable Interest Entity [Line Items]
Ownership interest (in percentage)	25.00%
VIE assets		$ 11,676	$ 11,387
VIE liabilities		$ 633	760
Enbridge Energy Limited Partnership [Member] | General Partner [Member]
Variable Interest Entity [Line Items]
Ownership interest (in percentage)	75.00%
Enbridge Energy Limited Partnership [Member] | Capital Unit, Class A [Member] | Variable Interest Entity, Primary Beneficiary [Member]
Variable Interest Entity [Line Items]
Ownership interest (in percentage)		100.00%
North Dakota Pipeline Company [Member] | Variable Interest Entity, Primary Beneficiary [Member]
Variable Interest Entity [Line Items]
VIE assets		$ 1,004	1,045
VIE liabilities		$ 41	$ 53
North Dakota Pipeline Company [Member] | Capital Unit, Class A [Member] | Variable Interest Entity, Primary Beneficiary [Member]
Variable Interest Entity [Line Items]
Ownership interest (in percentage)		100.00%
North Dakota Pipeline Company [Member] | Capital Unit, Class B [Member] | Variable Interest Entity, Primary Beneficiary [Member]
Variable Interest Entity [Line Items]
Ownership interest (in percentage)		62.50%
North Dakota Pipeline Company [Member] | Capital Unit, Class B [Member] | Williston Basin Pipeline LLC [Member]
Variable Interest Entity [Line Items]
Ownership interest (in percentage)		37.50%
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		$ 1,547
Series Lakehead and Series AC [Member] | Enbridge Energy Limited Partnership [Member] | General And Limited Partner Interest [Member] | Variable Interest Entity, Primary Beneficiary [Member]
Variable Interest Entity [Line Items]
Ownership interest (in percentage)		100.00%
Series EA [Member] | Enbridge Energy Limited Partnership [Member] | General And Limited Partner Interest [Member] | Variable Interest Entity, Primary Beneficiary [Member]
Variable Interest Entity [Line Items]
Ownership interest (in percentage)		40.00%
Series EA [Member] | Enbridge Energy Limited Partnership [Member] | General Partner [Member]
Variable Interest Entity [Line Items]
Ownership interest (in percentage)		60.00%
Series ME [Member] | Enbridge Energy Limited Partnership [Member] | General And Limited Partner Interest [Member] | Variable Interest Entity, Primary Beneficiary [Member]
Variable Interest Entity [Line Items]
Ownership interest (in percentage)		25.00%
Series ME [Member] | Enbridge Energy Limited Partnership [Member] | General Partner [Member]
Variable Interest Entity [Line Items]
Ownership interest (in percentage)		75.00%
Series L3R [Member] | Enbridge Energy Limited Partnership [Member] | General And Limited Partner Interest [Member] | Variable Interest Entity, Primary Beneficiary [Member]
Variable Interest Entity [Line Items]
Ownership interest (in percentage)		1.00%
Series L3R [Member] | Enbridge Energy Limited Partnership [Member] | General Partner [Member]
Variable Interest Entity [Line Items]
Ownership interest (in percentage)		99.00%

VARIABLE INTEREST ENTITIES (VIE

VARIABLE INTEREST ENTITIES (VIE Assets and Liabilities) (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
ASSETS
Cash and cash equivalents	$ 35	$ 101
Receivables, trade and other	65	6
Due from General Partner and affiliates	101	88
Accrued receivables	105	19
Other current assets	24	34
Property, plant and equipment, net	12,896	12,608
Equity investment in joint venture	1,565	0
Other assets, net	37	119
LIABILITIES
Accounts payable and other	173	348
Due to General Partner and affiliates	48	175
Interest payable	85	90
Environmental liabilities	23	100
Property and other taxes payable	106	89
Long-term debt	6,366	7,066
Other long-term liabilities	178	197
Variable Interest Entity, Primary Beneficiary [Member]
ASSETS
Cash and cash equivalents	35	37
Receivables, trade and other	62	2
Due from General Partner and affiliates	90	74
Accrued receivables	101	17
Other current assets	22	33
Property, plant and equipment, net	12,333	12,153
Equity investment in joint venture	1,547	0
Other assets, net	37	116
LIABILITIES
Accounts payable and other	147	168
Due to General Partner and affiliates	37	102
Interest payable	4	4
Environmental liabilities	23	100
Property and other taxes payable	102	87
Current portion of long-term debt	100	0
Long-term debt	100	199
Other long-term liabilities	$ 161	$ 153

EQUITY INVESTMENTS IN JOINT V67

EQUITY INVESTMENTS IN JOINT VENTURES (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Equity investment in joint venture	$ 1,565	$ 0
MarEn Bakken Company LLC [Member]
Ownership interest in joint venture (in percentage)	75.00%
Equity investment in joint venture	$ 1,565	$ 0

EQUITY INVESTMENTS IN JOINT V68

EQUITY INVESTMENTS IN JOINT VENTURES (Narrative) (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Feb. 15, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Number of joint ventures		$ 52	$ 0	$ 0
Reduction to equity earnings		$ (23)
MarEn Bakken Company LLC [Member]
Ownership in Midcoast Operating (in percentage)	25.00%
Ownership interest in joint venture (in percentage)		75.00%
Bakken Pipeline System [Member]
Percentage of interest acquired (in percentage)	49.00%
Noncontrolling interest, ownership percentage by parent (in percent)	75.00%
Ownership in Midcoast Operating (in percentage)	27.60%
Consideration transferred	$ 1,500
Goodwill	14
Business combination, finite-lived intangibles	$ 931
MarEn Bakken Company LLC [Member]
Percentage of interest acquired (in percentage)	49.00%

EQUITY INVESTMENTS IN JOINT V69

EQUITY INVESTMENTS IN JOINT VENTURES (Financial Statement Information) (Details) - MarEn Bakken Company LLC [Member] $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)
Schedule of Equity Method Investments [Line Items]
Non-current assets	$ 2,062
Total equity	2,062
Equity Method Investment, Summarized Financial Information, Income Statement [Abstract]
Income from equity investment	99
Amortization of basis difference	(30)
Net income	$ 69

ACCOUNTS PAYABLE AND OTHER (Det

ACCOUNTS PAYABLE AND OTHER (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Payables and Accruals [Abstract]
Short-term portion of derivative liabilities	$ 9	$ 146
Accounts payable	74	78
Accrued liabilities	62	55
Contractor holdbacks	9	44
Deferred credits	13	14
Other current liabilities	2	6
Accrued purchases	4	5
Total accounts payable and other	$ 173	$ 348

DEBT (Debt Obligations) (Detail

DEBT (Debt Obligations) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Total principal amount of debt obligations	$ 6,903	$ 7,108
Unamortized discount	(6)	(6)
Current maturities of long-term debt	(500)	0
Unamortized debt issuance costs	(31)	(36)
Total long term debt	$ 6,366	7,066
6.500% Senior Notes due April 2018 [Member]
Debt Instrument [Line Items]
Interest Rate (in percentage)	6.50%
9.875% Senior Notes due March 2019 [Member]
Debt Instrument [Line Items]
Interest Rate (in percentage)	9.875%
5.200% Senior Notes due March 2020 [Member]
Debt Instrument [Line Items]
Interest Rate (in percentage)	5.20%
Senior Notes due October 2020 [Member]
Debt Instrument [Line Items]
Interest Rate (in percentage)	4.375%
4.200% Senior Notes due September 2021 [Member]
Debt Instrument [Line Items]
Interest Rate (in percentage)	4.20%
5.875% Senior Notes due October 2025 [Member]
Debt Instrument [Line Items]
Interest Rate (in percentage)	5.875%
5.950% Senior Notes due June 2033 [Member]
Debt Instrument [Line Items]
Interest Rate (in percentage)	5.95%
6.300% Senior Notes due December 2034 [Member]
Debt Instrument [Line Items]
Interest Rate (in percentage)	6.30%
7.500% Senior Notes due April 2038 [Member]
Debt Instrument [Line Items]
Interest Rate (in percentage)	7.50%
5.500% Senior Notes due September 2040 [Member]
Debt Instrument [Line Items]
Interest Rate (in percentage)	5.50%
7.375% Senior Notes due October 2045 [Member]
Debt Instrument [Line Items]
Interest Rate (in percentage)	7.375%
7.000% Senior Notes due October 2018 [Member]
Debt Instrument [Line Items]
Interest Rate (in percentage)	7.00%
7.125% Senior Notes due October 2028 [Member]
Debt Instrument [Line Items]
Interest Rate (in percentage)	7.125%
Commercial Paper [Member]
Debt Instrument [Line Items]
Total principal amount of debt obligations	$ 1,303	393
Debt, Weighted Average Interest Rate	2.276%
Credit Facilities [Member]
Debt Instrument [Line Items]
Total principal amount of debt obligations	$ 150	1,265
Interest Rate (in percentage)	2.744%
Senior Notes [Member]
Debt Instrument [Line Items]
Total principal amount of debt obligations	$ 200
Senior Notes [Member] | 6.500% Senior Notes due April 2018 [Member]
Debt Instrument [Line Items]
Total principal amount of debt obligations	400	400
Senior Notes [Member] | 9.875% Senior Notes due March 2019 [Member]
Debt Instrument [Line Items]
Total principal amount of debt obligations	500	500
Senior Notes [Member] | 5.200% Senior Notes due March 2020 [Member]
Debt Instrument [Line Items]
Total principal amount of debt obligations	500	500
Senior Notes [Member] | Senior Notes due October 2020 [Member]
Debt Instrument [Line Items]
Total principal amount of debt obligations	500	500
Senior Notes [Member] | 4.200% Senior Notes due September 2021 [Member]
Debt Instrument [Line Items]
Total principal amount of debt obligations	600	600
Senior Notes [Member] | 5.875% Senior Notes due October 2025 [Member]
Debt Instrument [Line Items]
Total principal amount of debt obligations	500	500
Senior Notes [Member] | 5.950% Senior Notes due June 2033 [Member]
Debt Instrument [Line Items]
Total principal amount of debt obligations	200	200
Senior Notes [Member] | 6.300% Senior Notes due December 2034 [Member]
Debt Instrument [Line Items]
Total principal amount of debt obligations	100	100
Senior Notes [Member] | 7.500% Senior Notes due April 2038 [Member]
Debt Instrument [Line Items]
Total principal amount of debt obligations	400	400
Senior Notes [Member] | 5.500% Senior Notes due September 2040 [Member]
Debt Instrument [Line Items]
Total principal amount of debt obligations	550	550
Senior Notes [Member] | 7.375% Senior Notes due October 2045 [Member]
Debt Instrument [Line Items]
Total principal amount of debt obligations	600	600
Senior Notes [Member] | 7.000% Senior Notes due October 2018 [Member]
Debt Instrument [Line Items]
Total principal amount of debt obligations	100	100
Senior Notes [Member] | 7.125% Senior Notes due October 2028 [Member]
Debt Instrument [Line Items]
Total principal amount of debt obligations		100
Junior Subordinated Notes [Member]
Debt Instrument [Line Items]
Total principal amount of debt obligations	$ 400	$ 400
Interest Rate (in percentage)	8.05%
Interest rate, increase (decrease)	3.798%
London Interbank Offered Rate (LIBOR) [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Effective Percentage	1.335%

DEBT (Narrative) (Details)

DEBT (Narrative) (Details) - USD ($)	Oct. 06, 2015	Dec. 31, 2017	Dec. 31, 2016
Line of Credit Facility [Line Items]
Proceeds from issuance of commercial paper		$ 1,500,000,000
Long-term debt, gross		6,903,000,000	$ 7,108,000,000
Senior Notes [Member]
Line of Credit Facility [Line Items]
Long-term debt, gross		200,000,000
Senior unsecured notes issued, value	$ 1,600,000,000
Proceeds from issuance of unsecured debt	1,600,000,000
Accumulated other comprehensive income amortized as interest expense	238,000,000
Payments of debt issuance costs	315,000,000
Senior Notes [Member] | 7.000% Senior Notes due October 2018 [Member]
Line of Credit Facility [Line Items]
Long-term debt, gross		$ 100,000,000
Interest Rate (in percentage)		7.00%
Senior Notes [Member] | 7.125% Senior Notes due October 2028 [Member]
Line of Credit Facility [Line Items]
Long-term debt, gross		$ 100,000,000
Interest Rate (in percentage)		7.125%
Senior Notes [Member] | Senior Notes due October 2020 [Member]
Line of Credit Facility [Line Items]
Long-term debt, gross	500,000,000
Junior Subordinated Debt [Member]
Line of Credit Facility [Line Items]
Long-term debt, gross		$ 400,000,000	400,000,000
Interest Rate (in percentage)		8.05%
Interest rate, increase (decrease)		3.798%
Senior Notes Due October 2045 [Member] | Senior Notes [Member]
Line of Credit Facility [Line Items]
Long-term debt, gross	600,000,000
Committed Credit Facility [Member]
Line of Credit Facility [Line Items]
Line of credit facility expiring in year one		$ 175,000,000
Line of credit facility expiring in year three		185,000,000
Maximum borrowing capacity of line of credit		2,600,000,000
Uncommitted Demand Credit Facilities [Member]
Line of Credit Facility [Line Items]
Maximum borrowing capacity of line of credit		175,000,000
Total unutilized commitments at December 31, 2016		$ 174,000,000	$ 71,000,000
Interest Expense [Member] | Senior Notes [Member]
Line of Credit Facility [Line Items]
Accumulated other comprehensive income amortized as interest expense	76,000,000
Payments of debt issuance costs	$ 76,000,000

DEBT (Credit Facility) (Details

DEBT (Credit Facility) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Line of Credit Facility [Line Items]
Net (repayments) borrowings under credit facilities	$ (1,115,000,000)	$ 155,000,000	$ (50,000,000)
Committed Credit Facility [Member]
Line of Credit Facility [Line Items]
Line of credit facility expiring in year one	175,000,000
Maximum borrowing capacity of line of credit	2,600,000,000
Line of credit facility expiring in year three	185,000,000
Three Hundred Sixty Four Day Credit Facility [Member]
Line of Credit Facility [Line Items]
Proceeds from lines of credit	1,900,000,000
Repayments of lines of credit	3,000,000,000
Net (repayments) borrowings under credit facilities	1,100,000,000
Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Maximum borrowing capacity of line of credit	2,625,000,000
Proceeds from lines of credit	1,453,000,000
Available borrowing capacity	1,172,000,000
Commercial Paper [Member]
Line of Credit Facility [Line Items]
Proceeds from lines of credit	12,900,000,000
Repayments of lines of credit	12,000,000,000
Net (repayments) borrowings under credit facilities	$ 900,000,000

DEBT (Interest Cost) (Details)

DEBT (Interest Cost) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Interest Cost
Less: Interest capitalized	$ (44)	$ (48)	$ (39)
Interest expense, net	525	413	292
Senior Notes [Member]
Interest Cost
Interest cost incurred	531	428	307
Commercial Paper [Member]
Interest Cost
Interest cost incurred	38	$ 33	$ 24
Restatement Adjustment [Member] | Senior Notes [Member]
Interest Cost
Interest cost incurred	$ 168

ASSET RETIREMENT OBLIGATIONS (D

ASSET RETIREMENT OBLIGATIONS (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at beginning of year	$ 98	$ 100
Revisions in estimates	3	(1)
Accretion expense	5	1
Liabilities settled	0	(2)
Balance at end of year	106	$ 98
Accounts Payable and Other [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at end of year	2
Other Long-Term Liabilities [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Balance at end of year	$ 104

NONCONTROLLING INTERESTS (Narra

NONCONTROLLING INTERESTS (Narrative) (Details) - USD ($) $ in Millions	Apr. 27, 2017	Jan. 26, 2017	Sep. 30, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Jan. 27, 2017
Proceeds from noncontrolling interests				$ 1,485	$ 99	$ 822
Noncontrolling interest, increase from sale of parent equity interest				411	0	0
Decrease from redemptions or purchase of interests		$ 360
Line 3 Replacement [Member]
Joint funding arrangement, parent, percentage		99.00%
Joint funding arrangement, funding percentage		1.00%
Noncontrolling interest, increase from sale of parent equity interest		$ 411
Decrease from redemptions or purchase of interests		$ 40
General Partner [Member]
Proceeds from noncontrolling interests	$ 1,140
Joint funding arrangement, funding percentage		99.00%					99.00%
Noncontrolling interest, increase from sale of parent equity interest				$ 1	$ 0	$ 0
Enbridge Holdings LLC [Member] | General Partner [Member]
Ownership interest in joint venture (in percentage)	75.00%
Noncontrolling interest, ownership percentage by parent (in percent)	25.00%
Eastern Access project [Member]
Noncontrolling interest, ownership percentage by parent (in percent)			60.00%
Decrease from redemptions or purchase of interests		$ 360
Ownership interest in affiliate of partnership			40.00%
Joint funding arrangement, additional acquisition percentage		15.00%

NONCONTROLLING INTERESTS (Conso

NONCONTROLLING INTERESTS (Consolidated statements of financial position) (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Noncontrolling interests	$ 4,969	$ 3,846	$ 3,944	$ 3,609
Eastern Access Interests [Member]
Noncontrolling interests	1,465	1,892
US Mainline Expansion Interests [Member]
Noncontrolling interests	1,643	1,621
North Dakota Pipeline Company Interests [Member]
Noncontrolling interests	15	30
Line 3 Replacement Interests [Member]
Noncontrolling interests	686	0
Enbridge Holdings DakTex LLC Interests [Member]
Noncontrolling interests	1,160	0
Continuing Operations [Member]
Noncontrolling interests	$ 4,969	$ 3,543

NONCONTROLLING INTERESTS (Compo

NONCONTROLLING INTERESTS (Components of net income (loss) attributable to noncontrolling interests) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Noncontrolling Interest [Line Items]
Net income attributable to noncontrolling interests	$ 369	$ 26	$ 221
Alberta Clipper Interests [Member]
Noncontrolling Interest [Line Items]
Net income attributable to noncontrolling interests	0	0	(1)
Eastern Access Interest [Member]
Noncontrolling Interest [Line Items]
Net income attributable to noncontrolling interests	152	205	190
US Mainline Expansion Interests [Member]
Noncontrolling Interest [Line Items]
Net income attributable to noncontrolling interests	147	138	108
North Dakota Pipeline Company Interests [Member]
Noncontrolling Interest [Line Items]
Net income attributable to noncontrolling interests	21	(271)	0
Line 3 Replacement Interests [Member]
Noncontrolling Interest [Line Items]
Net income attributable to noncontrolling interests	29	0	0
Enbridge Holdings DakTex LLC Interests [Member]
Noncontrolling Interest [Line Items]
Net income attributable to noncontrolling interests	39	0	0
Midcoast Energy Partners, L.P. [Member]
Noncontrolling Interest [Line Items]
Net income attributable to noncontrolling interests	$ (19)	$ (46)	$ (76)

PARTNERS' CAPITAL (Schedule of

PARTNERS' CAPITAL (Schedule of Equity Interests) (Details) - USD ($)	Apr. 27, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Class D Units [Member]
Balance at beginning of year		$ 66,100,000	$ 66,100,000	$ 66,100,000
Waiver of units	66,000,000	(66,100,000)
Balance at end of year		$ 0	66,100,000	66,100,000
Class E Units [Member]
Balance at beginning of year		18,114,975	18,114,975	$ 0
Issuances				18,114,975
Balance at end of year		18,114,975	18,114,975	$ 18,114,975
Class F Units [Member]
Balance at beginning of year		$ 0	0	0
Issuances		1,000
Balance at end of year		$ 1,000	0	0
Class A Common Units [Member]
Balance at beginning of year		$ 262,208,428	262,208,428	$ 254,208,428
Issuances		64,308,682		8,000,000
Balance at end of year		$ 326,517,110	262,208,428	$ 262,208,428
Class B Common Units [Member]
Balance at beginning of year		7,825,500	7,825,500	7,825,500
Balance at end of year		7,825,500	7,825,500	7,825,500
i-Units [Member]
Balance at beginning of year		$ 81,857,168	$ 73,285,739	$ 68,305,187
Distributions		7,941,650.04850395	8,571,429	4,980,552
Balance at end of year		$ 89,798,818	$ 81,857,168	$ 73,285,739
Incentive Distribution Units
Balance at beginning of year		$ 1,000	1,000	1,000
Waiver of units		(1,000)
Balance at end of year		$ 0	1,000	1,000
Series1 Preferred Stock [Member]
Balance at beginning of year		$ 48,000,000	48,000,000	48,000,000
Waiver of units		(48,000,000)
Balance at end of year		$ 0	$ 48,000,000	$ 48,000,000

PARTNERS' CAPITAL (Schedule o80

PARTNERS' CAPITAL (Schedule of Class A Common Unit Equity Issuances) (Details) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended	12 Months Ended
	Jan. 27, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
General Partner [Member]
Net Proceeds to the Partnership (in dollars)		$ 24	$ 0	$ 6
General Partner Contribution	$ 450
Master limited partnership ownership interest (in percentage)		34.60%	41.70%
Class A Common Units [Member] | General Partner [Member]
Master limited partnership ownership interest (in percentage)		24.60%	9.40%
Second Quarter Distribution [Member]
Net Proceeds Including General Partner Contribution		$ 1,224
Second Quarter Distribution [Member] | General Partner [Member]
General Partner Contribution		$ 24
Second Quarter Distribution [Member] | Class A Common Units [Member]
Number of Class A common units Issued (in shares)		64,308,682
Offering Price per Class A common unit (in dollars per share)		$ 18.66
Net Proceeds to the Partnership (in dollars)		$ 1,200
First Quarter Distribution [Member]
Net Proceeds Including General Partner Contribution				295
First Quarter Distribution [Member] | General Partner [Member]
General Partner Contribution				$ 6,000
First Quarter Distribution [Member] | Class A Common Units [Member]
Number of Class A common units Issued (in shares)				8,000,000
Offering Price per Class A common unit (in dollars per share)				$ 36.70
Net Proceeds to the Partnership (in dollars)				$ 289
General Partner interest [Member]
Master limited partnership ownership interest (in percentage)		2.00%
General Partner interest [Member] | General Partner [Member]
Master limited partnership ownership interest (in percentage)		2.00%	2.00%

PARTNERS' CAPITAL (Narrative) (

PARTNERS' CAPITAL (Narrative) (Details) - USD ($) $ / shares in Units, $ in Millions	Apr. 27, 2017	Jan. 02, 2015	Dec. 24, 2014	Apr. 27, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Unamortized Beneficial Conversion Feature Discount	$ 9			$ 9
Increase In General Partners' Capital Account				$ 2,700
Repayment of debt					$ 1,640	$ 0	$ 306
Trading window used in determination of dividends					10 days
Limited Partner [Member]
Master limited partnership ownership interest (in percentage)					98.00%
General Partner [Member]
Master limited partnership ownership interest (in percentage)					34.60%	41.70%
Stock Issued During Period, Value, New Issues					$ (263)	$ 0	0
General Partner Distributions					13	21	$ 21
Allocations from capital accounts		$ 1			$ 71	$ 790
Alberta Clipper Pipeline [Member]
Percentage of interest acquired (in percentage)		66.70%
Repayment of debt		$ 306
Carrying value of noncontrolling interest		404
Difference between fair value of consideration and carrying value of noncontrolling interest		$ 364
Class D Units [Member]
Waiver of units	66,000,000				(66,100,000)
Maximum preference in liquidation (in percentage)					100.00%
Class D Units [Member] | General Partner [Member]
Master limited partnership ownership interest (in percentage)					0.00%	13.30%
Incentive Distribution Units
Distribution period					5 days
Class E Units [Member]
Number of units issued (in shares)							18,114,975
Notional value (in dollars per share)		$ 38.31	$ 38.31
Redemption term					30 years
Earnings threshold determining cancellation of units					$ 266
Number of partnership units potentially cancellable (in shares)					1,305,142
Amount of gross income threshold resulting in special allocations					$ 40
Amount of gross income threshold resulting in special allocations, secondary period					$ 20
Class E Units [Member] | General Partner [Member]
Master limited partnership ownership interest (in percentage)					4.00%	3.70%
Class E Units [Member] | Alberta Clipper Pipeline [Member]
Number of units issued (in shares)		18,114,975
Fair value of equity transferred		$ 768
Common Class A [Member]
Offering Price per Class A common unit (in dollars per share)	$ 18.66			$ 18.66
Fair value Per Share	$ 18.57			$ 18.57
Stock Issued During Period, Value, New Issues				$ 1,200
Series One Preferred Unit [Member]
Stock redeemed or called during period, value	$ 1,200			1,200
General Partner Distributions				$ 357
Common Class F [Member]
Common units, issued (in shares)	1,000			1,000
Limited Partners' Contributed Capital	$ 263			$ 263
Incentive Distribution Units
Waiver of units				1,000
Common units, issued (in shares)					1,000	1,000
Class D Units [Member]
Waiver of units	66,000,000				66,000,000
Common units, issued (in shares)					66,100,000	66,100,000
i-Units [Member]
Common units, issued (in shares)					89,798,818	81,857,168
Allocations from capital accounts		$ 47				$ 126
General Partner interest [Member]
Master limited partnership ownership interest (in percentage)					2.00%
General Partner interest [Member] | General Partner [Member]
Master limited partnership ownership interest (in percentage)					2.00%	2.00%
General Partner [Member] | Common Class A [Member]
Stock Issued During Period, Shares, New Issues				64,000,000

PARTNERS' CAPITAL (Distribution

PARTNERS' CAPITAL (Distribution to Partners) (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Distribution per Unit	$ 1.633	$ 2.332	$ 2.306
Cash available for distribution	$ 746	$ 1,047	$ 1,001
Amount of distribution	589	814	791
Cash distribution made to member or limited partner	605	864	836
i-Units [Member]
Amount of distribution	$ 137	$ 179	$ 161
Distributions	7,941,650.04850395	8,571,429	4,980,552
General Partner [Member]
Cash distribution made to member or limited partner	$ 4	$ 4	$ 4
First Quarter Distribution [Member]
Distribution per Unit	$ 0.583	$ 0.583	$ 0.570
Cash available for distribution	$ 265	$ 260	$ 234
Cash distribution made to member or limited partner	216	216	194
First Quarter Distribution [Member] | i-Units [Member]
Amount of distribution	48	43	39
First Quarter Distribution [Member] | General Partner [Member]
Cash distribution made to member or limited partner	$ 1	$ 1	$ 1
Second Quarter Distribution [Member]
Distribution per Unit	$ 0.350	$ 0.583	$ 0.570
Cash available for distribution	$ 160	$ 261	$ 250
Cash distribution made to member or limited partner	129	216	209
Second Quarter Distribution [Member] | i-Units [Member]
Amount of distribution	30	44	40
Second Quarter Distribution [Member] | General Partner [Member]
Cash distribution made to member or limited partner	$ 1	$ 1	$ 1
Third Quarter Distribution [Member]
Distribution per Unit	$ 0.350	$ 0.583	$ 0.583
Cash available for distribution	$ 160	$ 262	$ 258
Cash distribution made to member or limited partner	130	216	216
Third Quarter Distribution [Member] | i-Units [Member]
Amount of distribution	29	45	41
Third Quarter Distribution [Member] | General Partner [Member]
Cash distribution made to member or limited partner	$ 1	$ 1	$ 1
Fourth Quarter Distribution [Member]
Distribution per Unit	$ 0.350	$ 0.583	$ 0.583
Cash available for distribution	$ 161	$ 264	$ 259
Cash distribution made to member or limited partner	130	216	217
Fourth Quarter Distribution [Member] | i-Units [Member]
Amount of distribution	30	47	41
Fourth Quarter Distribution [Member] | General Partner [Member]
Cash distribution made to member or limited partner	$ 1	$ 1	$ 1
General Partner interest [Member]
Master limited partnership ownership interest (in percentage)	2.00%
General Partner interest [Member] | i-Units [Member]
Master limited partnership ownership interest (in percentage)	2.00%

DERIVATIVE FINANCIAL INSTRUME83

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Derivative Instruments in Statement of Financial Position) (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Derivatives, Fair Value [Line Items]
Net Total	$ (11)	$ (167)
Accounts Payable and Other [Member]
Derivatives, Fair Value [Line Items]
Net Total	(9)	(146)
Other Long-term Liabilities [Member]
Derivatives, Fair Value [Line Items]
Net Total	$ (2)	$ (21)

DERIVATIVE FINANCIAL INSTRUME84

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Derivative Balances by Counterparty Credit Quality) (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Derivative [Line Items]
Net Total	$ (11)	$ (167)
AA Rating [Member]
Derivative [Line Items]
Net Total	(4)	(79)
A Rating [Member]
Derivative [Line Items]
Net Total	(7)	(59)
Lower than A [Member]
Derivative [Line Items]
Net Total	$ 0	$ (29)

DERIVATIVE FINANCIAL INSTRUME85

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Credit Concentrations in Industry Sectors) (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Net Total	$ (11)	$ (167)
United States Financial Institutions And Investment Banking Entities [Member]
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Credit concentrations	(7)	(122)
Non-United States financial institutions [Member]
Fair Value, Concentration of Risk, Financial Statement Captions [Line Items]
Credit concentrations	$ (4)	$ (45)

DERIVATIVE FINANCIAL INSTRUME86

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Effect of Derivative Instruments on Consolidated Statements of Financial Position) (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Derivatives, Fair Value [Line Items]
Asset Derivatives	$ 0	$ 0
Liability Derivatives	(11)	(167)
Derivatives Designated as Hedging Instruments [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	0	0
Liability Derivatives	(6)	(165)
Derivatives Designated as Hedging Instruments [Member] | Accounts Payable and Other [Member] | Interest Rate Contracts [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	0	0
Liability Derivatives	(5)	(144)
Derivatives Designated as Hedging Instruments [Member] | Other Long-term Liabilities [Member] | Interest Rate Contracts [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	0	0
Liability Derivatives	(1)	(21)
Derivatives Not Designated as Hedging Instruments [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	0	0
Liability Derivatives	(5)	(2)
Derivatives Not Designated as Hedging Instruments [Member] | Accounts Payable and Other [Member] | Commodity Contracts [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	0	0
Liability Derivatives	(4)	(2)
Derivatives Not Designated as Hedging Instruments [Member] | Other Long-term Liabilities [Member] | Commodity Contracts [Member]
Derivatives, Fair Value [Line Items]
Asset Derivatives	0	0
Liability Derivatives	$ (1)	$ 0

DERIVATIVE FINANCIAL INSTRUME87

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Effect of Derivative Instruments on Consolidated Statements of Income and AOCI) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in AOCI on Derivative (Effective Portion)	$ 109	$ (1)	$ 87
Amount of Gain (Loss) Reclassified from AOCI to Earnings (Effective Portion)	(208)	(39)	(22)
Amount of Gain (Loss) Recognized in Earnings on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)	50	(7)	99
Interest Rate Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Recognized in AOCI on Derivative (Effective Portion)	109	(1)	87
Interest Rate Swap [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Reclassified from AOCI to Earnings (Effective Portion)	168
Interest Expense [Member] | Interest Rate Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain (Loss) Reclassified from AOCI to Earnings (Effective Portion)	(208)	(39)	(22)
Amount of Gain (Loss) Recognized in Earnings on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)	50	(7)	99
Senior Notes [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Interest Costs Incurred	531	$ 428	$ 307
Restatement Adjustment [Member] | Senior Notes [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Interest Costs Incurred	$ 168

DERIVATIVE FINANCIAL INSTRUME88

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Components of Accumulated Other Comprehensive Income) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Balance at January 1	$ (339)
Other comprehensive income (loss), net of tax	140	$ 31	$ (164)
Balance at December 31		(339)
Amount of Gain (Loss) Reclassified from AOCI to Earnings (Effective Portion)	(208)	(39)	(22)
Cash Flow Hedge [Member]
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Balance at January 1	(339)	(370)
Other comprehensive income before reclassifications	(68)	(8)
Amounts reclassified from AOCI	208	39
Other comprehensive income (loss), net of tax	140	31
Balance at December 31	(199)	$ (339)	$ (370)
Interest Rate Swap [Member]
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Amount of Gain (Loss) Reclassified from AOCI to Earnings (Effective Portion)	$ 168

DERIVATIVE FINANCIAL INSTRUME89

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Reclassifications from Accumulated Other Comprehensive Income) (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Interest expense, net									$ 525	$ 413	$ 292
Net income (loss)	$ 101	$ 196	$ 197	$ 157	$ 183	$ (575)	$ 178	$ 173	651	(41)	454
Reclassification out of AOCI [Member] | Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Net income (loss)									208	39	22
Interest Rate Contract [Member] | Reclassification out of AOCI [Member] | Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Interest expense, net									$ 208	$ 39	$ 22

DERIVATIVE FINANCIAL INSTRUME90

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Effect of Derivative Instruments on Consolidated Statements of Income) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Transportation And Other Services Revenue [Member] | Commodity Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain on Settlement of Derivative Instruments	$ 0	$ 6	$ 27
Derivatives Not Designated As Hedging Instruments [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Amount of Gain or (Loss) Recognized in Earnings	(3)	(3)	11
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	$ (3)	$ (3)	$ 11

DERIVATIVE FINANCIAL INSTRUME91

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Offsetting of Financial Liabilities and Derivative Liabilities) (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Derivatives
Gross Amount of Recognized Liabilities	$ (11)	$ (167)
Gross Amount Offset in the Statement of Financial Position	0	0
Net Amount of Liabilities Presented in the Statement of Financial Position	(11)	(167)
Gross Amount Not Offset in the Statement of Financial Position	0	0
Net Amount	$ (11)	$ (167)

DERIVATIVE FINANCIAL INSTRUME92

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Level with in Fair Value Hierarchy, Financial Assets and Liabilities) (Details) - Level 2 [Member] - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments	$ (11)	$ (167)
Interest Rate Contracts [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments	(6)	(165)
Commodity Contracts - Financial [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative instruments	$ (5)	$ (2)

DERIVATIVE FINANCIAL INSTRUME93

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Fair Values of Expected Cash Flows of Commodity Based Swaps and Physical Contracts) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)$ / Barrel-bblbbl	Dec. 31, 2016USD ($)
Fair Value
Asset	$ 0	$ 0
Liability	$ (11)	(167)
Swaps - Portion of Contracts Maturing in 2017 - Receive Fixed/Pay Variable - Crude Oil [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	123,832
Fair Value
Asset	$ 0	0
Liability	$ 0	(2)
Swaps - Portion of Contracts Maturing in 2017 - Receive Fixed/Pay Variable - Crude Oil [Member] | Receive [Member]
Derivative [Line Items]
Wtd. Average Price | $ / Barrel-bbl	51.91
Swaps - Portion of Contracts Maturing in 2017 - Receive Fixed/Pay Variable - Crude Oil [Member] | Pay [Member]
Derivative [Line Items]
Wtd. Average Price | $ / Barrel-bbl	51.98
Commodity Swap Crude Oil Maturing In 2018 Receive Fixed Pay Variable [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	498,955
Fair Value
Asset	$ 0	0
Liability	$ (4)	0
Commodity Swap Crude Oil Maturing In 2018 Receive Fixed Pay Variable [Member] | Receive [Member]
Derivative [Line Items]
Wtd. Average Price | $ / Barrel-bbl	50.71
Commodity Swap Crude Oil Maturing In 2018 Receive Fixed Pay Variable [Member] | Pay [Member]
Derivative [Line Items]
Wtd. Average Price | $ / Barrel-bbl	59.31
Commodity Swap Crude Oil Maturing In 2019 Receive Fixed Pay Variable [Member]
Derivative [Line Items]
Notional (Bbl) | bbl	353,685
Fair Value
Asset	$ 0	0
Liability	$ (1)	$ 0
Commodity Swap Crude Oil Maturing In 2019 Receive Fixed Pay Variable [Member] | Receive [Member]
Derivative [Line Items]
Wtd. Average Price | $ / Barrel-bbl	55.22
Commodity Swap Crude Oil Maturing In 2019 Receive Fixed Pay Variable [Member] | Pay [Member]
Derivative [Line Items]
Wtd. Average Price | $ / Barrel-bbl	55.86

DERIVATIVE FINANCIAL INSTRUME94

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Interest Rate Derivatives) (Details) - Interest Rate Swap [Member] - Derivatives in Cash Flow Hedging Relationships [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Derivative [Line Items]
Credit Valuation Adjustments	$ 0	$ 1
Contracts Maturing In 2017 [Member]
Derivative [Line Items]
Notional	$ 500
Average Fixed Rate (in percentage)	2.21%
Fair Value	$ 0	(1)
Contracts Maturing In 2018 [Member]
Derivative [Line Items]
Notional	$ 810
Average Fixed Rate (in percentage)	2.24%
Fair Value	$ 0	(9)
Contracts Maturing In 2019 [Member]
Derivative [Line Items]
Notional	$ 620
Average Fixed Rate (in percentage)	2.96%
Fair Value	$ (6)	(7)
Contracts Settling Prior to Maturity - 2017 Pre Issuance Hedges [Member]
Derivative [Line Items]
Notional	$ 1,000
Average Fixed Rate (in percentage)	4.07%
Fair Value	$ 0	(136)
Contracts Settling Prior to Maturity - 2018 Pre Issuance Hedges [Member]
Derivative [Line Items]
Notional	$ 350
Average Fixed Rate (in percentage)	3.08%
Fair Value	$ 0	$ (13)

DERIVATIVE FINANCIAL INSTRUME95

DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Letters of credit provided on derivatives	$ 0	$ 120,000,000
Derivative instruments income statement location of gain loss reclassified from accumulated other comprehensive income	192,000,000	223,000,000
Cash flow hedge gain (loss) to be reclassified within twelve months	(36,000,000)
Expected value of cash collateral or letters of credit if credit rating is downgraded	12,000,000
Interest expense	525,000,000	413,000,000	$ 292,000,000
Loans receivable with fixed rates of interest	$ 5,800,000,000	$ 6,100,000,000

INCOME TAXES (Details)

INCOME TAXES (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income tax expense:
Current state	$ (5)	$ 3	$ 4
Deferred state	(3)	(4)	(1)
Total income tax expense	(8)	(1)	3
A reconciliation of the income tax expense with amounts determined by applying the statutory U.S. federal income tax rate to income before income tax expense:
Income before income tax	700	115	742
Income tax benefit	$ (8)	$ (1)	$ 3
Effective income tax rate	(1.10%)	(0.90%)	0.40%
Accounting for Uncertainty in Income Taxes:
Unrecognized tax benefits at January 1	$ 39	$ 37	$ 33
Additions for tax positions taken in current period	1	2	4
Lapses of statute of limitations	(6)	0	0
Unrecognized tax benefits at December 31	34	39	$ 37
Unrecognized tax benefits, possible estimate change	0
Penalties accrued	1	2
Interest accrued	1	1
Accrued interest income not included in balance of unrecognized tax benefits	$ 1	$ 1
Texas State Income Tax Rate [Member]
Accounting for Uncertainty in Income Taxes:
State franchise tax rate (in percentage)	0.40%	0.40%	0.40%

CHANGES IN OPERATIG ASSETS AN97

CHANGES IN OPERATIG ASSETS AND LIABILITIES (Schedule of Change in Working Capital) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Changes in operating assets and liabilities, net of acquisitions:
Receivables, trade and other	$ (59)	$ 6	$ 18
Due from General Partner and affiliates	(26)	(42)	(31)
Accrued receivables	(86)	3	9
Inventory	1	0	10
Current and long-term other assets	47	8	(40)
Due to General Partner and affiliates	(127)	(14)	28
Accounts payable and other	(26)	(76)	5
Environmental liabilities	(91)	(19)	(44)
Accrued purchases	(2)	3	2
Interest payable	(5)	(4)	24
Current income tax payable	1	(2)	0
Property and other taxes payable	15	7	10
Changes in operating assets and liabilities	$ (358)	$ (130)	$ (9)

RELATED PARTY TRANSACTIONS (Joi

RELATED PARTY TRANSACTIONS (Joint Funding Arrangement Discussions) (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Aug. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Construction Project Work Force Cost Transactions [Member]
Related party expenses		$ 17	$ 28
Operation Services Transactions [Member]
Related party expenses		133	106	$ 131
General And Administrative Services Transactions [Member]
Related party expenses		$ 201	$ 229	$ 216
Enbridge Pipelines LLC [Member]
General Partner Contribution	$ 68

RELATED PARTY TRANSACTIONS (Sal

RELATED PARTY TRANSACTIONS (Sale of AR) (Details) - USD ($)	Apr. 27, 2017	Dec. 31, 2017	Dec. 31, 2016
Proceed From Termination of Receivables Agreement	$ 5,000,000
Net value of receivables sold		$ 473,000,000	$ 1,773,000,000
Proceeds from Sale of Receivables		472,000,000	1,772,000,000
Restricted cash		0	14,000,000
Sale of Accounts Receivable to Affiliate [Member]
Restricted cash		$ 0	$ 156,000,000

RELATED PARTY TRANSACTIONS (Sch

RELATED PARTY TRANSACTIONS (Schedule of General Partner Equity Transactions) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
General Partner [Member]
Master limited partnership ownership interest (in percentage)	34.60%	41.70%
General Partner's ownership Interests (in units)	147,262,957	196,126,169
Cash distributions paid to general partner	$ 252	$ 361	$ 343
Total Cash Distribution Paid	$ 29	$ 90	90
Series 1 Preferred units [Member] | General Partner [Member]
Master limited partnership ownership interest (in percentage)	0.00%	9.70%
General Partner's ownership Interests (in units)	0	48,000,000
Cash distributions paid to general partner	$ 0	$ 0	0
General Partner interest [Member]
Master limited partnership ownership interest (in percentage)	2.00%
General Partner interest [Member] | General Partner [Member]
Master limited partnership ownership interest (in percentage)	2.00%	2.00%
General Partner's ownership Interests (in units)	0	0
Cash distributions paid to general partner	$ 12	$ 17	17
i-Units [Member]
Master limited partnership ownership interest (in percentage)	2.00%
Class D Units [Member] | General Partner [Member]
Master limited partnership ownership interest (in percentage)	0.00%	13.30%
General Partner's ownership Interests (in units)	0	66,100,000
Cash distributions paid to general partner	$ 39	$ 154	152
Class E Units [Member] | General Partner [Member]
Master limited partnership ownership interest (in percentage)	4.00%	3.70%
General Partner's ownership Interests (in units)	18,114,975	18,114,975
Cash distributions paid to general partner	$ 29	$ 42	32
Class A Common Units [Member] | General Partner [Member]
Master limited partnership ownership interest (in percentage)	24.60%	9.40%
General Partner's ownership Interests (in units)	110,827,018	46,518,336
Cash distributions paid to general partner	$ 143	$ 109	107
Class B Common Units [Member] | General Partner [Member]
Master limited partnership ownership interest (in percentage)	1.70%	1.60%
General Partner's ownership Interests (in units)	7,825,500	7,825,500
Cash distributions paid to general partner	$ 13	$ 18	18
Class F Units [Member] | General Partner [Member]
Master limited partnership ownership interest (in percentage)	0.00%	0.00%
General Partner's ownership Interests (in units)	1,000	0
Cash distributions paid to general partner	$ 11	$ 0	0
i-Units [Member] | General Partner [Member]
Master limited partnership ownership interest (in percentage)	0.00%	0.00%
General Partner's ownership Interests (in units)	0	1,000
Cash distributions paid to general partner	$ 5	$ 21	17
Enbridge Management shares [Member] | General Partner [Member]
Master limited partnership ownership interest (in percentage)	2.30%	2.00%
General Partner's ownership Interests (in units)	10,494,463.531729	9,566,358
Cash distributions paid to general partner	$ 0	$ 0	0
Non Cash Distribution Paid	$ 16	$ 21	$ 19

RELATED PARTY TRANSACTIONS (Fin

RELATED PARTY TRANSACTIONS (Financing Transactions with Affiliates) (Details) - USD ($)	Apr. 27, 2017	Jan. 02, 2015	Apr. 27, 2017	Feb. 15, 2017	Jan. 27, 2017	Jan. 26, 2017	Sep. 30, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Related Party Transaction [Line Items]
Interest expense								$ 525,000,000	$ 413,000,000	$ 292,000,000
Property, plant and equipment, net								12,896,000,000	12,608,000,000
Contributions from noncontrolling interests								$ 1,485,000,000	99,000,000	822,000,000
US Mainline Expansion Interests [Member]
Related Party Transaction [Line Items]
Noncontrolling interest, ownership percentage by parent (in percent)								75.00%
Additional acquisition percentages						15.00%
Contributions from noncontrolling interests								$ 41,000,000	90,000,000	673,000,000
Ownership interest in affiliate of Partnership (in percentage)								25.00%
Cash distributions declared										72,000,000
Bakken Pipeline Systems [Member]
Related Party Transaction [Line Items]
Noncontrolling interest, ownership percentage by parent (in percent)	75.00%		75.00%
Ownership interest in affiliate of partnership			25.00%
Additional acquisitions percentages			20.00%
General Partner Contribution								$ 440,000,000
Line 3 Replacement [Member]
Related Party Transaction [Line Items]
Fair value of equity transferred		$ 411,000,000
Interest expense								40,000,000
Eastern Access Pipeline [Member]
Related Party Transaction [Line Items]
Additional acquisition percentages						15.00%
Master limited partnership ownership interest (in percentage)						25.00%	40.00%
Managing member or general partner, ownership interest						75.00%	60.00%
Parent ownership interest, changes, purchase of interest by parent						$ 360,000,000
Contributions from noncontrolling interests								$ 13,000,000	$ 14,000,000	$ 119,000,000
EUS Credit Agreement [Member]
Related Party Transaction [Line Items]
Repayments of lines of credit				$ 1,500,000,000
Enbridge Inc., Credit Agreement [Member]
Related Party Transaction [Line Items]
Term of debt instrument								364 days
Maximum borrowing capacity of line of credit								$ 750,000,000
Fair value of amount outstanding								$ 610,000,000
General Partner [Member]
Related Party Transaction [Line Items]
Proceeds from related party debt			$ 1,100,000,000
Joint funding arrangement, funding percentage					99.00%	99.00%
General Partner Contribution					$ 450,000,000
Master limited partnership ownership interest (in percentage)								34.60%	41.70%
Contributions from noncontrolling interests	$ 1,140,000,000
General Partner [Member] | Enbridge Inc., Credit Agreement [Member]
Related Party Transaction [Line Items]
Proceeds from related party debt								$ 400,000,000
Enbridge Management shares [Member]
Related Party Transaction [Line Items]
Joint funding arrangement, funding percentage					1.00%
Enbridge Management shares [Member] | General Partner [Member]
Related Party Transaction [Line Items]
Master limited partnership ownership interest (in percentage)								2.30%	2.00%
Class E Units [Member] | General Partner [Member]
Related Party Transaction [Line Items]
Master limited partnership ownership interest (in percentage)								4.00%	3.70%
Line 3 Replacement [Member]
Related Party Transaction [Line Items]
Joint funding arrangement, funding percentage						1.00%
Option to increase general partnership interest percentage						40.00%
General Partner Contribution								$ 247,000,000
Eastern Access Pipeline [Member]
Related Party Transaction [Line Items]
Property, plant and equipment, net						$ 360,000,000

RELATED PARTY TRANSACTIONS (Dis

RELATED PARTY TRANSACTIONS (Distributions by Affiliates) (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Feb. 13, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Total amount of distribution paid		$ 605	$ 864	$ 836
First Quarter Distribution [Member]
Total amount of distribution paid		216	216	194
Second Quarter Distribution [Member]
Total amount of distribution paid		129	216	209
Third Quarter Distribution [Member]
Total amount of distribution paid		130	216	216
Fourth Quarter Distribution [Member]
Total amount of distribution paid		130	216	217
Alberta Clipper Pipeline [Member] | First Quarter Distribution [Member]
Amount paid to parent	$ 14
Amount paid to the noncontrolling interest	27
Total amount of distribution paid	$ 41
Eastern Access Pipeline [Member]
Amount paid to parent		120	201	192
Amount paid to the noncontrolling interest		232	128	119
Total amount of distribution paid		352	329	311
Eastern Access Pipeline [Member] | First Quarter Distribution [Member]
Amount paid to parent		23	79	22
Amount paid to the noncontrolling interest		69	0	67
Total amount of distribution paid		92	79	89
Eastern Access Pipeline [Member] | Second Quarter Distribution [Member]
Amount paid to parent		29	79	18
Amount paid to the noncontrolling interest		62	0	52
Total amount of distribution paid		91	79	70
Eastern Access Pipeline [Member] | Third Quarter Distribution [Member]
Amount paid to parent		33	21	76
Amount paid to the noncontrolling interest		50	63	0
Total amount of distribution paid		83	84	76
Eastern Access Pipeline [Member] | Fourth Quarter Distribution [Member]
Amount paid to parent		35	22	76
Amount paid to the noncontrolling interest		51	65	0
Total amount of distribution paid		86	87	76
US Mainline Expansion Interests [Member]
Amount paid to parent		56	112	55
Amount paid to the noncontrolling interest		166	84	10
Total amount of distribution paid		222	196	65
US Mainline Expansion Interests [Member] | First Quarter Distribution [Member]
Amount paid to parent		14	41	2
Amount paid to the noncontrolling interest		43	0	5
Total amount of distribution paid		57	41	7
US Mainline Expansion Interests [Member] | Second Quarter Distribution [Member]
Amount paid to parent		13	43	1
Amount paid to the noncontrolling interest		38	0	5
Total amount of distribution paid		51	43	6
US Mainline Expansion Interests [Member] | Third Quarter Distribution [Member]
Amount paid to parent		14	13	20
Amount paid to the noncontrolling interest		41	40	0
Total amount of distribution paid		55	53	20
US Mainline Expansion Interests [Member] | Fourth Quarter Distribution [Member]
Amount paid to parent		15	15	32
Amount paid to the noncontrolling interest		44	44	0
Total amount of distribution paid		59	59	32
Enbridge Holdings DakTex LLC Interests [Member]
Amount paid to parent		21
Amount paid to the noncontrolling interest		63
Total amount of distribution paid		84
Enbridge Holdings DakTex LLC Interests [Member] | Third Quarter Distribution [Member]
Amount paid to parent		10
Amount paid to the noncontrolling interest		31
Total amount of distribution paid		41
Enbridge Holdings DakTex LLC Interests [Member] | Fourth Quarter Distribution [Member]
Amount paid to parent		11
Amount paid to the noncontrolling interest		32
Total amount of distribution paid		43
Midcoast Energy Partners [Member]
Amount paid to parent		9	36	35
Amount paid to the noncontrolling interest		8	30	30
Total amount of distribution paid		17	66	65
Midcoast Energy Partners [Member] | First Quarter Distribution [Member]
Amount paid to parent		9	9	8
Amount paid to the noncontrolling interest		8	7	8
Total amount of distribution paid		$ 17	16	16
Midcoast Energy Partners [Member] | Second Quarter Distribution [Member]
Amount paid to parent			9	9
Amount paid to the noncontrolling interest			8	7
Total amount of distribution paid			17	16
Midcoast Energy Partners [Member] | Third Quarter Distribution [Member]
Amount paid to parent			9	9
Amount paid to the noncontrolling interest			7	7
Total amount of distribution paid			16	16
Midcoast Energy Partners [Member] | Fourth Quarter Distribution [Member]
Amount paid to parent			9	9
Amount paid to the noncontrolling interest			8	8
Total amount of distribution paid			$ 17	$ 17

RELATED PARTY TRANSACTIONS (103

RELATED PARTY TRANSACTIONS (Distributions) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Apr. 27, 2017
Related Party Transaction [Line Items]
Proceeds from noncontrolling interests	$ 1,485	$ 99	$ 822
Equity earnings from investments in joint venture	(52)	0	0
US Mainline Expansion Interests [Member]
Related Party Transaction [Line Items]
Proceeds from noncontrolling interests	$ 41	$ 90	$ 673
Noncontrolling interest, ownership percentage by parent (in percent)	75.00%
Bakken Pipeline Systems [Member]
Related Party Transaction [Line Items]
General Partner Contribution	$ 440
Noncontrolling interest, ownership percentage by parent (in percent)				75.00%

COMMITMENTS AND CONTINGENCIE104

COMMITMENTS AND CONTINGENCIES (Commitments and Other Disclosures) (Details) $ in Millions	Dec. 31, 2017USD ($)
Total Future Minimum Commitments
2,018	$ 1,142
2,019	826
2,020	1,287
2,021	830
2,022	1,650
Thereafter	6,563
Total	12,298
Annual Debt Maturities [Member]
Total Future Minimum Commitments
2,018	500
2,019	500
2,020	1,000
2,021	600
2,022	1,453
Thereafter	2,850
Total	6,903
Interest Obligation [Member]
Total Future Minimum Commitments
2,018	324
2,019	280
2,020	243
2,021	208
2,022	183
Thereafter	3,414
Total	4,652
Purchase Commitment [Member]
Total Future Minimum Commitments
2,018	255
2,019	0
2,020	0
2,021	0
2,022	0
Thereafter	0
Total	255
Power Commitments [Member]
Total Future Minimum Commitments
2,018	26
2,019	25
2,020	24
2,021	10
2,022	10
Thereafter	257
Total	352
Product Purchase Obligation [Member]
Total Future Minimum Commitments
2,018	32
2,019	16
2,020	15
2,021	8
2,022	0
Thereafter	0
Total	71
Other Long-Term Liabilities [Member]
Total Future Minimum Commitments
2,018	0
2,019	0
2,020	1
2,021	1
2,022	1
Thereafter	6
Total	9
Operating leases [Member]
Total Future Minimum Commitments
2,018	3
2,019	3
2,020	2
2,021	1
2,022	1
Thereafter	0
Total	10
Right-of-way [Member]
Total Future Minimum Commitments
2,018	2
2,019	2
2,020	2
2,021	2
2,022	2
Thereafter	36
Total	$ 46

COMMITMENTS AND CONTINGENCIE105

COMMITMENTS AND CONTINGENCIES (Narrative) (Details) $ in Millions	Jun. 15, 2017USD ($)	May 31, 2015USD ($)a	Dec. 31, 2017USD ($)bbl	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Mar. 31, 2015USD ($)	Mar. 31, 2013USD ($)	Jul. 26, 2010Milesbbl
Site Contingency [Line Items]
Remaining liabilities			$ 23	$ 100
Accrual for environmental loss contingencies			51	51
Estimated total loss of crude oil release			1,215
Government fines and penalties	$ 68
Aggregate insurance coverage limit			650
Insurance recoveries, since inception			547
Remaining aggregate insurance coverage							$ 145
Remaining expected insurance recoveries			$ 103			$ 85
Natural gas volumes in custody (in barrels) | bbl			27,000,000
Natural gas volumes in custody (in barrels) | bbl			63,000,000
Rent expense			$ 7	8	$ 8
Purchase obligation			341	947	260
Rights Of Way [Member]
Site Contingency [Line Items]
Rent expense			2	2	2
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
Civil Penalties [Member]
Site Contingency [Line Items]
Government fines and penalties	61
Line 6A Crude Oil Release [Member]
Site Contingency [Line Items]
Government fines and penalties	1
Past Removal Costs and Interest [Member]
Site Contingency [Line Items]
Government fines and penalties	$ 6
Consent Decree [Member]
Site Contingency [Line Items]
Accrual for environmental loss contingencies			110
Line Six Marshall Leak [Member]
Site Contingency [Line Items]
Remaining liabilities			62	139
Crude oil released (in barrels) | bbl								20,000
Area impacted by crude oil release | Miles								38
Costs paid associated with crude oil release			76	$ 21	$ 37
Estimated total loss of crude oil release			1,200
Government fines and penalties			$ 69
Line Six Marshall Leak [Member] | May 2015 Settlement [Member]
Site Contingency [Line Items]
Area of remediation site (in acres) | a		300
Costs paid associated with crude oil release		$ 5

COMMITMENTS AND CONTINGENCIE106

COMMITMENTS AND CONTINGENCIES (Cumulative Estimated Loss) (Details) $ in Millions	Dec. 31, 2017USD ($)
Site Contingency [Line Items]
Response personnel and equipment	$ 1,215
Response Personnel and Equipment [Member]
Site Contingency [Line Items]
Response personnel and equipment	547
Environmental Consultants [Member]
Site Contingency [Line Items]
Response personnel and equipment	224
Professional, Regulatory, Fines and Penalties and Other [Member]
Site Contingency [Line Items]
Response personnel and equipment	$ 444

QUARTERLY FINANCIAL DATA (Un107

QUARTERLY FINANCIAL DATA (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Quarterly Financial Data [Abstract]
Operating revenue	$ 610	$ 616	$ 597	$ 605	$ 630	$ 635	$ 621	$ 630	$ 2,428	$ 2,516	$ 2,303
Operating income (loss)	274	266	312	269	311	(449)	323	296	1,121	481	964
Continuing operations:	101	196	232	179	216	(544)	241	203	708	116	739
Net loss from discontinued operations	0	0	(35)	(22)	(33)	(31)	(63)	(30)	(57)	(157)	(285)
Net income (loss)	101	196	197	157	183	(575)	178	173	651	(41)	454
Income (Loss) from Continuing Operations, Net of Tax, Attributable to Parent	(6)	93	117	79	103	(385)	130	101	283	(51)	341
Net loss attributable to general and limited partner interests in Enbridge Energy Partners, L.P. - discontinued operations	$ 0	$ 0	$ (24)	$ (14)	$ (22)	$ (22)	$ (46)	$ (21)	$ (38)	$ (111)	$ (209)
Net income (loss) per common unit and i-unit (basic and diluted):
Income (loss) from continuing operations (in dollars per share)	$ (0.05)	$ 0.19	$ 0.27	$ 0.19	$ 0.14	$ (1.25)	$ 0.21	$ 0.13	$ 0.60	$ (0.77)	$ 0.35
Loss from discontinued operations (in dollars per share)	0	0	(0.06)	(0.04)	(0.06)	(0.06)	(0.13)	(0.06)	(0.10)	(0.31)	(0.60)
Net income per common unit and i-unit (in dollars per share)	$ (0.05)	$ 0.19	$ 0.21	$ 0.15	$ 0.08	$ (1.31)	$ 0.08	$ 0.07	$ 0.50	$ (1.08)	$ (0.25)

QUARTERLY FINANCIAL DATA (Narra

QUARTERLY FINANCIAL DATA (Narrative) (Details) $ in Millions	3 Months Ended
	Sep. 30, 2016USD ($)
Quarterly Financial Data [Abstract]
Asset impairment	$ 757

SUBSEQUENT EVENTS (Details)

SUBSEQUENT EVENTS (Details) - USD ($) $ / shares in Units, $ in Millions	Jan. 31, 2018	Mar. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Subsequent Event [Line Items]
Cash available for distribution			$ 746	$ 1,047	$ 1,001
Distributions paid per limited partner unit (in dollars per share)			$ 1.633	$ 2.332	$ 2.306
Total amount of distribution paid			$ 605	$ 864	$ 836
Amount of distribution			589	814	791
i-Units [Member]
Subsequent Event [Line Items]
Amount of distribution			137	179	161
Subsequent Event [Member]
Subsequent Event [Line Items]
Total amount of distribution paid	$ 130
Subsequent Event [Member] | i-Units [Member]
Subsequent Event [Line Items]
Amount of distribution	31
Amount paid to parent	$ 1
Master limited partnership ownership interest (in percentage)	2.00%
Series EA Interests [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Amount paid to parent	$ 50
Amount paid to the noncontrolling interest	34
Series ME Interests [Member]
Subsequent Event [Line Items]
Total amount of distribution paid			222	196	65
Amount paid to parent			56	112	55
Amount paid to the noncontrolling interest			166	84	10
Series ME Interests [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Amount paid to parent	44
Amount paid to the noncontrolling interest	$ 15
First Quarter Distribution [Member]
Subsequent Event [Line Items]
Cash available for distribution			$ 265	$ 260	$ 234
Distributions paid per limited partner unit (in dollars per share)			$ 0.583	$ 0.583	$ 0.570
Total amount of distribution paid			$ 216	$ 216	$ 194
First Quarter Distribution [Member] | i-Units [Member]
Subsequent Event [Line Items]
Amount of distribution			48	43	39
First Quarter Distribution [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Cash available for distribution		$ 162
Distributions paid per limited partner unit (in dollars per share)		$ 0.35
First Quarter Distribution [Member] | Series ME Interests [Member]
Subsequent Event [Line Items]
Total amount of distribution paid			57	41	7
Amount paid to parent			14	41	2
Amount paid to the noncontrolling interest			$ 43	$ 0	$ 5