Enbridge (ENB) 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. 09, 2018	Jun. 30, 2017
Document And Entity Information [Abstract]
Entity Registrant Name	ENBRIDGE INC
Trading Symbol	ENB
Entity Central Index Key	895,728
Document Type	10-K
Document Period End Date	Dec. 31, 2017
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		1,695,190,292
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	FY
Entity Public Float			$ 65,416,118,124

CONSOLIDATED STATEMENTS OF EARN

CONSOLIDATED STATEMENTS OF EARNINGS - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating revenues
Commodity sales	CAD 26,286	CAD 22,816	CAD 23,842
Gas distribution sales	4,215	2,486	3,096
Transportation and other services	13,877	9,258	6,856
Total operating revenues	44,378	34,560	33,794
Operating expenses
Commodity costs	26,065	22,409	22,949
Gas distribution costs	2,572	1,596	2,292
Operating and administrative	6,442	4,358	4,131
Depreciation and amortization	3,163	2,240	2,024
Impairment of long-lived assets (Note 7 and Note 10)	4,463	1,376	96
Impairment of goodwill (Note 7 and Note 15)	102	0	440
Total operating expenses	42,807	31,979	31,932
Operating income	1,571	2,581	1,862
Income from equity investments (Note 12)	1,102	428	475
Net foreign currency gain/(loss)	237	91	(884)
Gain on dispositions	16	848	94
Other	199	93	88
Interest expense (Note 17)	(2,556)	(1,590)	(1,624)
Earnings before income taxes	569	2,451	11
Income tax recovery/(expense) (Note 24)	2,697	(142)	(170)
Earnings/(loss)	3,266	2,309	(159)
(Earnings)/loss attributable to noncontrolling interests and redeemable noncontrolling interests	(407)	(240)	410
Earnings attributable to controlling interests	2,859	2,069	251
Preference share dividends	(330)	(293)	(288)
Earnings/(loss) attributable to common shareholders	CAD 2,529	CAD 1,776	CAD (37)
Earnings/(loss) per common share attributable to Enbridge Inc. common shareholders (in dollars per share)	CAD 1.66	CAD 1.95	CAD (0.04)
Diluted earnings/(loss) per common share attributable to Enbridge Inc. common shareholders (in dollars per share)	CAD 1.65	CAD 1.93	CAD (0.04)

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Statement of Comprehensive Income [Abstract]
Earnings/(loss)	CAD 3,266	CAD 2,309	CAD (159)
Other comprehensive income/(loss), net of tax
Change in unrealized gain/(loss) on cash flow hedges	(21)	(138)	198
Change in unrealized gain/(loss) on net investment hedges	490	166	(903)
Other comprehensive income/(loss) from equity investees	(27)	0	30
Reclassification to earnings of (gain)/loss on cash flow hedges	313	116	(559)
Reclassification to earnings of pension and other postretirement benefits amounts	19	17	21
Actuarial gain/(loss) on pension plans and other postretirement benefits	8	(34)	51
Foreign currency translation adjustments	(3,060)	(712)	3,347
Other comprehensive income/(loss), net of tax	(2,278)	(585)	2,185
Comprehensive income	988	1,724	2,026
Comprehensive (income)/loss attributable to noncontrolling interests and redeemable noncontrolling interests	(160)	(229)	292
Comprehensive income attributable to controlling interests	828	1,495	2,318
Preference share dividends	(330)	(293)	(288)
Comprehensive income/(loss) attributable to common shareholders	CAD 498	CAD 1,202	CAD 2,030

CONSOLIDATED STATEMENTS OF CHAN

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY - CAD CAD in Millions	Total	Preference shares	Common shares	Additional paid-in capital	Retained earnings/(deficit)	Accumulated other comprehensive income/(loss)	Reciprocal shareholding	Total Enbridge Inc. shareholders' equity	Noncontrolling Interest
Balance at Dec. 31, 2014		CAD 6,515	CAD 6,669	CAD 2,549	CAD 1,571	CAD (435)	CAD (83)		CAD 2,015
Increase (Decrease) in Stockholders' Equity
Shares issued		0	0
Common shares issued in Merger Transaction (Note 7)			0
Dividend Reinvestment and Share Purchase Plan			646
Stock-based compensation				35
Fair value of outstanding earned stock-based compensation from Merger Transaction (Note 7)				0
Exercised of stock options			76	(19)
Enbridge Energy Company, Inc. common control transaction				0					0
Drop down of interest to Enbridge Energy Partners, L.P.				218					(304)
Dilution gain/(loss) and other (Note 19)				518
Earnings attributable to controlling interests	CAD 251				251
Preference share dividends					(288)
Common share dividends declared					(1,596)
Dividends paid to reciprocal shareholder					22
Reversal of cumulative redemption value adjustment attributable to Enbridge Commercial Trust (Note 19)					541
Redemption value adjustment attributable to redeemable noncontrolling interests (Note 19)	359				(359)
Adjustment for the recognition of unutilized tax deductions for stock based compensation expense					0
Adjustment relating to equity method investment					0
Other					0
Other comprehensive income/(loss) attributable to common shareholders, net of tax						2,067
Issuance of treasury stock							0
Earnings/(loss) attributable to noncontrolling interests									(407)
Change in unrealized gain on cash flow hedges									161
Foreign currency translation adjustments									273
Reclassification to earnings of (gain)/loss on cash flow hedges									(319)
Other comprehensive income/(loss) attributable to noncontrolling interests, net of tax									115
Comprehensive income/(loss) attributable to noncontrolling interests									(292)
Noncontrolling interests resulting from Merger Transaction (Note 7)									0
Distributions									(680)
Contributions									615
Deconsolidation of Sabal Trail Transmission, LLC									0
Dilution gain/(loss)									(53)
Disposition of Olympic Pipeline									0
Other									(1)
Balance at Dec. 31, 2015	CAD 20,198	6,515	7,391	3,301	142	1,632	(83)	CAD 18,898	1,300
Increase (Decrease) in Stockholders' Equity
Dividends paid per common share	CAD 1.86
Shares issued		740	2,241
Common shares issued in Merger Transaction (Note 7)			0
Dividend Reinvestment and Share Purchase Plan			795
Stock-based compensation				41
Fair value of outstanding earned stock-based compensation from Merger Transaction (Note 7)				0
Exercised of stock options			65	(24)
Enbridge Energy Company, Inc. common control transaction				0					0
Drop down of interest to Enbridge Energy Partners, L.P.				0					0
Dilution gain/(loss) and other (Note 19)				81
Earnings attributable to controlling interests	CAD 2,069				2,069
Preference share dividends					(293)
Common share dividends declared					(1,945)
Dividends paid to reciprocal shareholder					26
Reversal of cumulative redemption value adjustment attributable to Enbridge Commercial Trust (Note 19)					0
Redemption value adjustment attributable to redeemable noncontrolling interests (Note 19)	686				(686)
Adjustment for the recognition of unutilized tax deductions for stock based compensation expense					0
Adjustment relating to equity method investment					(29)
Other					0
Other comprehensive income/(loss) attributable to common shareholders, net of tax						(574)
Issuance of treasury stock							(19)
Earnings/(loss) attributable to noncontrolling interests									(28)
Change in unrealized gain on cash flow hedges									4
Foreign currency translation adjustments									(44)
Reclassification to earnings of (gain)/loss on cash flow hedges									40
Other comprehensive income/(loss) attributable to noncontrolling interests, net of tax									0
Comprehensive income/(loss) attributable to noncontrolling interests									(28)
Noncontrolling interests resulting from Merger Transaction (Note 7)									0
Distributions									(720)
Contributions									28
Deconsolidation of Sabal Trail Transmission, LLC									0
Dilution gain/(loss)									0
Disposition of Olympic Pipeline									0
Other									(3)
Balance at Dec. 31, 2016	CAD 21,963	7,255	10,492	3,399	(716)	1,058	(102)	21,386	577
Increase (Decrease) in Stockholders' Equity
Dividends paid per common share	CAD 2.12
Shares issued		492	1,500
Common shares issued in Merger Transaction (Note 7)			37,429
Dividend Reinvestment and Share Purchase Plan			1,226
Stock-based compensation				82
Fair value of outstanding earned stock-based compensation from Merger Transaction (Note 7)				77
Exercised of stock options			90	(95)
Enbridge Energy Company, Inc. common control transaction				76					(343)
Drop down of interest to Enbridge Energy Partners, L.P.				0					0
Dilution gain/(loss) and other (Note 19)				(345)
Earnings attributable to controlling interests	CAD 2,859				2,859
Preference share dividends					(330)
Common share dividends declared					(4,702)
Dividends paid to reciprocal shareholder					30
Reversal of cumulative redemption value adjustment attributable to Enbridge Commercial Trust (Note 19)					0
Redemption value adjustment attributable to redeemable noncontrolling interests (Note 19)	(292)				292
Adjustment for the recognition of unutilized tax deductions for stock based compensation expense					41
Adjustment relating to equity method investment					0
Other					58
Other comprehensive income/(loss) attributable to common shareholders, net of tax						(2,031)
Issuance of treasury stock							0
Earnings/(loss) attributable to noncontrolling interests									232
Change in unrealized gain on cash flow hedges									15
Foreign currency translation adjustments									(431)
Reclassification to earnings of (gain)/loss on cash flow hedges									139
Other comprehensive income/(loss) attributable to noncontrolling interests, net of tax									(277)
Comprehensive income/(loss) attributable to noncontrolling interests									(45)
Noncontrolling interests resulting from Merger Transaction (Note 7)									8,955
Distributions									(839)
Contributions									832
Deconsolidation of Sabal Trail Transmission, LLC									(2,318)
Dilution gain/(loss)									832
Disposition of Olympic Pipeline									(24)
Other									(30)
Balance at Dec. 31, 2017	CAD 65,732	CAD 7,747	CAD 50,737	CAD 3,194	CAD (2,468)	CAD (973)	CAD (102)	CAD 58,135	CAD 7,597
Increase (Decrease) in Stockholders' Equity
Dividends paid per common share	CAD 2.41

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating activities
Earnings/(loss)	CAD 3,266	CAD 2,309	CAD (159)
Depreciation and amortization	3,163	2,240	2,024
Deferred income tax expense	(2,877)	43	7
Changes in unrealized (gain)/loss on derivative instruments, net (Note 23)	(1,242)	(509)	2,373
Earnings from equity investments	(1,102)	(656)	(483)
Distributions from equity investments	1,264	827	727
Impairment	4,565	1,620	536
(Gain)/loss on dispositions	(120)	(848)	(94)
Hedge ineffectiveness (Note 23)	(55)	61	(20)
Inventory revaluation allowance	56	245	410
Unrealized intercompany foreign exchange (gain)/loss	28	43	(131)
Other	50	198	69
Changes in environmental liabilities, net of recoveries	(98)	(4)	(43)
Changes in operating assets and liabilities (Note 26)	(314)	(358)	(645)
Net cash provided by operating activities	6,584	5,211	4,571
Investing activities
Capital expenditures	(8,287)	(5,128)	(7,273)
Joint venture financing	(25)	(1)	0
Long-term investments	(3,525)	(467)	(622)
Distributions from equity investments in excess of cumulative earnings	125	0	0
Restricted long-term investments	(54)	(46)	(49)
Additions to intangible assets	(789)	(127)	(101)
Purchases of held-to-maturity securities	(529)	0	0
Proceeds from sales and maturities of held-to-maturity securities	584	0	0
Purchase of available-for-sale securities	(136)	0	0
Proceeds from sales and maturities of available-for-sale securities	99	0	0
Acquisitions	0	(644)	(106)
Cash acquired in Merger Transaction (Note 7)	682	0	0
Proceeds from dispositions	628	1,379	146
Reimbursement of capital expenditures	212	0	0
Affiliate loans, net	(22)	(118)	59
Changes in restricted cash	35	(40)	13
Net cash used in investing activities	(11,002)	(5,192)	(7,933)
Financing activities
Net change in short-term borrowings (Note 2)	721	(248)	(487)
Net change in commercial paper and credit facility draws	(1,249)	(2,297)	1,507
Debenture and term note issues, net of issue costs	9,483	4,080	3,767
Debenture and term note repayments	(5,054)	(1,946)	(1,023)
Purchase of interest in consolidated subsidiary	(227)	0	0
Contributions from noncontrolling interests	832	28	615
Distributions to noncontrolling interests	(919)	(720)	(680)
Contributions from redeemable noncontrolling interests	1,178	591	670
Distributions to redeemable noncontrolling interests	(247)	(202)	(114)
Preference shares issued	489	737	0
Common shares issued	1,549	2,260	57
Preference share dividends	(330)	(293)	(288)
Common share dividends	(2,750)	(1,150)	(950)
Net cash provided by financing activities	3,476	840	3,074
Effect of translation of foreign denominated cash and cash equivalents	(72)	(19)	143
Net increase/(decrease) in cash and cash equivalents	(1,014)	840	(145)
Cash and cash equivalents at beginning of year	1,494	654	799
Cash and cash equivalents at end of year	480	1,494	654
Supplementary cash flow information
Cash paid for income taxes	172	194	80
Cash paid for interest, net of amount capitalized	2,668	1,820	1,835
Property, plant and equipment non-cash accruals	CAD 889	CAD 773	CAD 1,222

CONSOLIDATED STATEMENTS OF FINA

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION - CAD CAD in Millions	Dec. 31, 2017	Dec. 31, 2016
Current assets
Cash and cash equivalents (Note 2)	CAD 480	CAD 1,494
Restricted cash	107	68
Accounts receivable and other (Note 8)	7,053	4,978
Accounts receivable from affiliates	47	14
Inventory (Note 9)	1,528	1,233
Total Current assets	9,215	7,787
Property, plant and equipment, net (Note 10)	90,711	64,284
Long-term investments (Note 12)	16,644	6,836
Restricted investments, at fair value	267	90
Restricted long-term investments (Note 13)	267	90
Deferred amounts and other assets	6,442	3,391
Intangible assets, net (Note 14)	3,267	1,573
Goodwill (Note 15)	34,457	78
Deferred income taxes (Note 24)	1,090	1,170
Total assets	162,093	85,209
Current liabilities
Short-term borrowings (Note 17)	1,444	351
Accounts payable and other (Note 16)	9,478	7,295
Accounts payable to affiliates	157	122
Interest payable	634	333
Environmental liabilities	40	142
Current portion of long-term debt (Note 17)	2,871	4,100
Total Current liabilities	14,624	12,343
Long-term debt (Note 17)	60,865	36,494
Other long-term liabilities	7,510	4,981
Deferred income taxes (Note 24)	9,295	6,036
Total Liabilities	92,294	59,854
Commitments and contingencies (Note 28)
Redeemable noncontrolling interests (Note 19)	4,067	3,392
Share capital (Note 20)
Preference shares	7,747	7,255
Common shares (1,695 and 943 outstanding at December 31, 2017 and December 31,2016, respectively)	50,737	10,492
Additional paid-in capital	3,194	3,399
Deficit	(2,468)	(716)
Accumulated other comprehensive income/(loss) (Note 22)	(973)	1,058
Reciprocal shareholding	(102)	(102)
Total Enbridge Inc. shareholders’ equity	58,135	21,386
Noncontrolling interests (Note 19)	7,597	577
Total Equity	65,732	21,963
Total liabilities and equity	CAD 162,093	CAD 85,209

CONSOLIDATED STATEMENTS OF FIN7

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION (Parenthetical) - shares shares in Millions	Dec. 31, 2017	Dec. 31, 2016
Statement of Financial Position [Abstract]
Common shares, outstanding (in shares)	1,695	943

BUSINESS OVERVIEW

BUSINESS OVERVIEW	12 Months Ended
	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
BUSINESS OVERVIEW	BUSINESS OVERVIEW The terms “we,” “our,” “us” and “Enbridge” as used in this report refer collectively to Enbridge Inc. and its subsidiaries unless the context suggests otherwise. These terms are used for convenience only and are not intended as a precise description of any separate legal entity within Enbridge Inc. Enbridge is a publicly traded energy transportation and distribution company. We conduct our business through five business segments: Liquids Pipelines; Gas Transmission and Midstream; Gas Distribution; Green Power and Transmission; and Energy Services. These reporting segments are strategic business units established by senior management to facilitate the achievement of our long-term objectives, to aid in resource allocation decisions and to assess operational performance. LIQUIDS PIPELINES Liquids Pipelines consists of common carrier and contract pipelines that transport crude oil, natural gas liquids (NGL) and refined products and terminals in Canada and the United States, including Canadian Mainline, Lakehead Pipeline System (Lakehead System), Regional Oil Sands System, Mid-Continent and Gulf Coast, Southern Lights Pipeline, Express-Platte System, Bakken System, and Feeder Pipelines and Other. GAS TRANSMISSION AND MIDSTREAM Gas Transmission and Midstream, formerly referred to as Gas Pipelines and Processing, consists of investments in natural gas pipelines and gathering and processing facilities. Investments in natural gas pipelines include our interests in US Gas Transmission, Canadian Gas Transmission and Midstream, Alliance Pipeline, US Midstream and Other. Investments in natural gas processing include our interest in Aux Sable, a natural gas extraction and fractionation business located near the terminus of the Alliance Pipeline; Canadian Gas Transmission and Midstream assets located in northeast British Columbia and northwest Alberta; and DCP Midstream, LLC (DCP Midstream) assets located primarily in Texas and Oklahoma. GAS DISTRIBUTION Gas Distribution consists of our natural gas utility operations, the core of which are Enbridge Gas Distribution Inc. (EGD) and Union Gas Limited (Union Gas), which serves residential, commercial and industrial customers, primarily located in Ontario. This business segment also includes our investment in Noverco Inc. (Noverco) and Other Gas Distribution and Storage. GREEN POWER AND TRANSMISSION Green Power and Transmission consists of our investments in renewable energy assets and transmission facilities. Renewable energy assets consist of wind, solar, geothermal and waste heat recovery facilities and are located in Canada primarily in the provinces of Alberta, Ontario and Quebec and in the United States primarily in Colorado, Texas, Indiana and West Virginia. We also have assets under development located in Europe. ENERGY SERVICES The Energy Services businesses in Canada and the United States undertake physical commodity marketing activity and logistical services, oversee refinery supply services and manage our volume commitments on various pipeline systems. ELIMINATIONS AND OTHER In addition to the segments noted above, Eliminations and Other includes operating and administrative costs and foreign exchange costs which are not allocated to business segments. Also included in Eliminations and Other are new business development activities, general corporate investments and elimination of transactions between segments required to present financial performance and financial position on a consolidated basis. ACQUISITION OF SPECTRA ENERGY CORP On February 27, 2017, Enbridge and Spectra Energy Corp (Spectra Energy) combined in a stock-for-stock merger transaction (the Merger Transaction) for a purchase price of $37.5 billion . Under the terms of the Merger Transaction, Spectra Energy shareholders received 0.984 shares of Enbridge for each share of Spectra Energy common stock that they owned, giving us 100% ownership of Spectra Energy. Please refer to Note 7 - Acquisitions and Dispositions for further discussion of the transaction. CANADIAN RESTRUCTURING PLAN Effective September 1, 2015, under an agreement with Enbridge Income Fund (the Fund) and Enbridge Income Fund Holdings Inc. (ENF), Enbridge transferred its Canadian Liquids Pipelines business, held by Enbridge Pipelines Inc. (EPI) and Enbridge Pipelines (Athabasca) Inc. (EPAI), and certain Canadian renewable energy assets to the Fund Group (comprising the Fund, Enbridge Commercial Trust (ECT), Enbridge Income Partners LP (EIPLP) and the subsidiaries of EIPLP) for consideration valued at $30.4 billion plus incentive distribution and performance rights (the Canadian Restructuring Plan). The consideration that we received included $18.7 billion of units in the Fund Group, comprised of $3 billion of Fund units and $15.7 billion of equity units of EIPLP, in which the Fund has an interest. The Fund Group also assumed debt of EPI and EPAI of approximately $11.7 billion .

SUMMARY OF ACCOUNTING POLICIES

SUMMARY OF ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
SUMMARY OF ACCOUNTING POLICIES	SIGNIFICANT ACCOUNTING POLICIES These consolidated financial statements are prepared in accordance with generally accepted accounting principles in the United States of America (U.S. GAAP). Amounts are stated in Canadian dollars unless otherwise noted. As a Securities and Exchange Commission (SEC) registrant, we are permitted to use U.S. GAAP for purposes of meeting both our Canadian and United States continuous disclosure requirements. BASIS OF PRESENTATION AND USE OF ESTIMATES 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. Significant estimates and assumptions used in the preparation of the consolidated financial statements include, but are not limited to: carrying values of regulatory assets and liabilities (Note 6) ; purchase price allocations (Note 7) ; unbilled revenues; depreciation rates and carrying value of property, plant and equipment (Note 10) ; amortization rates of intangible assets (Note 14) ; measurement of goodwill (Note 15) ; fair value of asset retirement obligations (ARO) (Note 18) ; valuation of stock-based compensation (Note 21) ; fair value of financial instruments (Note 23) ; provisions for income taxes (Note 24) ; assumptions used to measure retirement and other postretirement benefit obligations (OPEB) (Note 25) ; commitments and contingencies (Note 28) ; and estimates of losses related to environmental remediation obligations (Note 28) . Actual results could differ from these estimates. Effective September 30, 2017 , we combined Cash and cash equivalents and amounts previously presented as Bank indebtedness where the corresponding bank accounts are subject to cash pooling arrangements. As at December 31, 2017 , $0.6 billion ( December 31, 2016 - $0.6 billion ) of Bank indebtedness has been combined within Cash and cash equivalents in our Consolidated Statements of Financial Position. Net cash provided by financing activities in the Consolidated Statements of Cash Flows for the years ended December 31, 2016 and 2015 have decreased by $0.3 billion and increased by $0.1 billion , respectively, to reflect this change. PRINCIPLES OF CONSOLIDATION The consolidated financial statements include our accounts and accounts of our subsidiaries and variable interest entities (VIEs) for which we are the primary beneficiary. A VIE is a legal entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support or is structured such that equity investors lack the ability to make significant decisions relating to the entity’s operations through voting rights or do not substantively participate in the gains and losses of the entity. 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. 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 entity that could potentially be significant to the VIE. Where we conclude that we are the primary beneficiary of a VIE, we will consolidate the accounts of that VIE. We assess all variable interests in the entity and use our judgment when determining if we are the primary beneficiary. 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. We assess the primary beneficiary determination for a VIE on an ongoing basis, as there are changes in the facts and circumstances related to a VIE. The consolidated financial statements also include the accounts of any limited partnerships where we represent the general partner and, based on all facts and circumstances, control such limited partnerships, unless the limited partner has substantive participating rights or substantive kick-out rights. For certain investments where we retain an undivided interest in assets and liabilities, we record our proportionate share of assets, liabilities, revenues and expenses. If an entity is determined to not be a VIE, the voting interest entity model will be applied. 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 noncontrolling interests and redeemable noncontrolling interests. Investments and entities over which we exercise significant influence are accounted for using the equity method. As a result of the Canadian Restructuring Plan, ECT, our subsidiary, determines its equity investment earnings from EIPLP using the Hypothetical Liquidation at Book Value (HLBV) method. ECT applies the HLBV method to its equity method investments where cash distributions, including both preference and residual distributions, are not based on the investor’s ownership percentages. Under the HLBV method, a calculation is prepared at each balance sheet date to determine the amount that ECT would receive if EIPLP were to liquidate all of its assets, as valued in accordance with U.S. GAAP, and distribute that cash to the investors. The difference between the calculated liquidation distribution amounts at the beginning and the end of the reporting period, after adjusting for capital contributions and distributions, is ECT’s share of the earnings or losses from the equity investment for the period. While ECT and EIPLP are both consolidated in these financial statements, the use of the HLBV method by ECT impacts the earnings attributable to redeemable noncontrolling interests reported on Enbridge’s Consolidated Statements of Earnings. We continue to recognize Redeemable noncontrolling interests on the Consolidated Statements of Financial Position at the maximum redemption value of the trust units held by third parties, which references the market price of ENF common shares. REGULATION Certain parts of our businesses are subject to regulation by various authorities including, but not limited to, the National Energy Board (NEB), the Federal Energy Regulatory Commission (FERC), the Alberta Energy Regulator, the New Brunswick Energy and Utilities Board (EUB), the Ontario Energy Board (OEB) and La Régie de l’Energie du Québec. Regulatory bodies exercise statutory authority over matters such as construction, rates and ratemaking and agreements with customers. 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. Regulatory assets represent amounts that are expected to be recovered from customers in future periods through rates. Regulatory liabilities represent amounts that are expected to be refunded to customers in future periods through rates or expected to be paid to cover future abandonment costs in relation to the NEB’s Land Matters Consultation Initiative (LMCI). Long-term regulatory assets are recorded in Deferred amounts and other assets and current regulatory assets are recorded in Accounts receivable and other. Long-term regulatory liabilities are included in Other long-term liabilities and current regulatory liabilities are recorded in Accounts payable and other. Regulatory assets are assessed for impairment if we identify an event indicative of possible impairment. The recognition of regulatory assets and liabilities is based on the actions, or expected future actions, of the regulator. To the extent that the regulator’s actions differ from our expectations, the timing and amount of recovery or settlement of regulatory balances could differ significantly from those recorded. In the absence of rate regulation, we would generally not recognize regulatory assets or liabilities and the earnings impact would be recorded in the period the expenses are incurred or revenues are earned. A regulatory asset or liability is recognized in respect of deferred income taxes when it is expected the amounts will be recovered or settled through future regulator-approved rates. 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 its cost of borrowing, whereas the capitalized equity component, the corresponding earnings during the construction phase and the subsequent depreciation would not be recognized. For certain regulated operations to which U.S. GAAP guidance for phase-in plans applies, negotiated depreciation rates recovered in transportation tolls may be less than the depreciation expense calculated in accordance with U.S. GAAP in early years of long-term contracts but recovered in future periods when tolls exceed depreciation. Depreciation expense on such assets is recorded in accordance with U.S. GAAP and no deferred regulatory asset is recorded (Note 6) . With the approval of the applicable regulator, EGD, Union Gas and certain distribution operations capitalize a percentage of specified operating costs. These operations are authorized to charge depreciation and earn a return on the net book value of such capitalized costs in future years. To the extent that the regulator’s actions differ from our expectations, the timing and amount of recovery or settlement of capitalized costs could differ significantly from those recorded. In the absence of rate regulation, a portion of such costs may be charged to current period earnings. REVENUE RECOGNITION For businesses that are not rate-regulated, revenues are recorded when products have been delivered or services have been performed, the amount of revenue can be reliably measured and collectability is reasonably assured. Customer credit worthiness is assessed prior to agreement signing, as well as throughout the contract duration. Certain revenues from liquids and gas pipeline businesses are recognized under the terms of committed delivery contracts rather than the cash tolls received. Long-term take-or-pay contracts, under which shippers are obligated to pay fixed amounts rateably over the contract period regardless of volumes shipped, may contain make-up rights. Make-up rights are earned by shippers when minimum volume commitments are not utilized during the period but under certain circumstances can be used to offset overages in future periods, subject to expiry periods. We recognize revenues associated with make-up rights at the earlier of when the make-up volume is shipped, the make-up right expires or when it is determined that the likelihood that the shipper will utilize the make-up right is remote. Certain offshore pipeline transportation contracts require Enbridge to provide transportation services for the life of the underlying producing fields. Under these arrangements, shippers pay Enbridge a fixed monthly toll for a defined period of time which may be shorter than the estimated reserve life of the underlying producing fields, resulting in a contract period which extends past the period of cash collection. Fixed monthly toll revenues are recognized ratably over the committed volume made available to shippers throughout the contract period, regardless of when cash is received. For the years ended December 31, 2017 , 2016 and 2015 , cash received net of revenue recognized for contracts under make-up rights and similar deferred revenue arrangements was $196 million , $249 million , and $61 million , respectively. For rate-regulated businesses, revenues are recognized in a manner that is consistent with the underlying agreements as approved by the regulators. Natural gas utilities revenues are recorded on the basis of regular meter readings and estimates of customer usage from the last meter reading to the end of the reporting period. Estimates are based on historical consumption patterns and heating degree days experienced. Heating degree days is a measure of coldness that is indicative of volumetric requirements for natural gas utilized for heating purposes in our distribution franchise area. Since July 1, 2011, Canadian Mainline (excluding Lines 8 and 9) earnings are governed by the Competitive Toll Settlement (CTS), under which revenues are recorded when services are performed. Effective on that date, we prospectively discontinued the application of rate-regulated accounting for those assets with the exception of flow-through income taxes covered by specific rate orders. For our energy marketing contracts, an estimate of revenues and commodity costs for the month of December is included in the Consolidated Statements of Earnings for each year based on the best available volume and price data for the commodity delivered and received. DERIVATIVE INSTRUMENTS AND HEDGING Non-qualifying Derivatives Non-qualifying derivative instruments are used primarily to economically hedge foreign exchange, interest rate and commodity price earnings exposure. Non-qualifying derivatives are measured at fair value with changes in fair value recognized in earnings in Transportation and other services revenues, Commodity costs, Operating and administrative expense, Other income/(expense) and Interest expense. Derivatives in Qualifying Hedging Relationships We use derivative financial instruments to manage our exposure to changes in commodity prices, foreign exchange rates, interest rates and certain compensation tied to our share price. Hedge accounting is optional and requires Enbridge to document the hedging relationship and test the hedging item’s effectiveness in offsetting changes in fair values or cash flows of the underlying hedged item on an ongoing basis. We present the earnings effects of hedging items with the hedged transaction. Derivatives in qualifying hedging relationships are categorized as cash flow hedges, fair value hedges or net investment hedges. Cash Flow Hedges We use cash flow hedges to manage our exposure to changes in commodity prices, foreign exchange rates, interest rates and certain compensation tied to our share price. The effective portion of the change in the fair value of a cash flow hedging instrument is recorded in Other comprehensive income/(loss) (OCI) and is reclassified to earnings when the hedged item impacts earnings. Any hedge ineffectiveness is recorded in current period earnings. If a derivative instrument designated as a cash flow hedge ceases to be effective or is terminated, hedge accounting is discontinued and the gain or loss at that date is deferred in OCI and recognized concurrently with the related transaction. If a hedged anticipated transaction is no longer probable, the gain or loss is recognized immediately in earnings. Subsequent gains and losses from derivative instruments for which hedge accounting has been discontinued are recognized in earnings in the period in which they occur. Fair Value Hedges We use fair value hedges to hedge the fair value of debt instruments. The change in the fair value of the hedging instrument is recorded in earnings with changes in the fair value of the hedged asset or liability that is designated as part of the hedging relationship. If a fair value hedge is discontinued or ceases to be effective, the hedged asset or liability, otherwise required to be carried at cost or amortized cost, ceases to be remeasured at fair value and the cumulative fair value adjustment to the carrying value of the hedged item is recognized in earnings over the remaining life of the hedged item. Net Investment Hedges Gains and losses arising from translation of net investment in foreign operations from their functional currencies to Enbridge’s Canadian dollar presentation currency are included in cumulative translation adjustments (CTA). We designate foreign currency derivatives and United States dollar denominated debt as hedges of net investments in United States dollar denominated foreign operations. As a result, the effective portion of the change in the fair value of the foreign currency derivatives as well as the translation of United States dollar denominated debt are reflected in OCI and any ineffectiveness is reflected in current period earnings. Amounts recognized previously in Accumulated other comprehensive income/(loss) (AOCI) are reclassified to earnings when there is a reduction of the hedged net investment resulting from disposal of a foreign operation. Classification of Derivatives We recognize the fair market value of derivative instruments on the Consolidated Statements of Financial Position as current and non-current assets or liabilities depending on the timing of the settlements and the resulting cash flows associated with the instruments. Fair value amounts related to cash flows occurring beyond one year are classified as non-current. Cash inflows and outflows related to derivative instruments are classified as Operating activities on the Consolidated Statements of Cash Flows. Balance Sheet Offset Assets and liabilities arising from derivative instruments may be offset in the Consolidated Statements of Financial Position when we have the legal right and intention to settle them on a net basis. 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 account 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. RESTRICTED LONG-TERM INVESTMENTS Long-term investments that are restricted as to withdrawal or usage, for the purposes of the NEB’s LMCI, are presented as Restricted long-term investments on the Consolidated Statements of Financial Position. OTHER INVESTMENTS Generally, we classify equity investments in entities over which we do not exercise significant influence and that do not trade on an actively quoted market as other investments carried at cost. Financial assets in this category are initially recorded at fair value with no subsequent re-measurement. Any investments which do trade on an active market are classified as available for sale investments measured at fair value through OCI. Dividends received from investments carried at cost are recognized in earnings when the right to receive payment is established. NONCONTROLLING INTERESTS Noncontrolling interests represent ownership interests attributable to third parties in certain consolidated subsidiaries, limited partnerships and VIEs. The portion of equity not owned by us in such entities is reflected as Noncontrolling interests within the equity section of the Consolidated Statements of Financial Position and, in the case of redeemable noncontrolling interests, within the mezzanine section of the Consolidated Statements of Financial Position between long-term liabilities and equity. The Fund’s noncontrolling interest holders have the option to redeem the Fund trust units for cash, subject to certain limitations. Redeemable noncontrolling interests are recognized at the maximum redemption value of the trust units held by third parties, which references the market price of ENF common shares. On a quarterly basis, changes in estimated redemption values are reflected as a charge or credit to retained earnings. The use of the HLBV method by ECT impacts the earnings attributable to redeemable noncontrolling interests reported on our Consolidated Statements of Earnings. INCOME TAXES Income taxes are accounted for using the liability method. Deferred income tax assets and liabilities are recorded based on temporary differences between the tax bases of assets and liabilities and their carrying values for accounting purposes. Deferred income tax assets and liabilities are measured using the tax rate that is expected to apply when the temporary differences reverse. For our regulated operations, a deferred income tax liability or asset is recognized with a corresponding regulatory asset or liability, respectively, to the extent taxes can be recovered through rates. Any interest and/or penalty incurred related to tax is reflected in Income taxes. FOREIGN CURRENCY TRANSACTIONS AND TRANSLATION Foreign currency transactions are those transactions whose terms are denominated in a currency other than the currency of the primary economic environment in which Enbridge or a reporting subsidiary operates, referred to as the functional currency. Transactions denominated in foreign currencies are translated into the functional currency using the exchange rate prevailing at the date of transaction. Monetary assets and liabilities denominated in foreign currencies are translated to the functional currency using the rate of exchange in effect at the balance sheet date. Exchange gains and losses resulting from translation of monetary assets and liabilities are included in the Consolidated Statements of Earnings in the period in which they arise. Gains and losses arising from translation of foreign operations’ functional currencies to our Canadian dollar presentation currency are included in the CTA component of AOCI and are recognized in earnings upon sale of the foreign operation. Asset and liability accounts are translated at the exchange rates in effect on the balance sheet date, while revenues and expenses are translated using monthly average exchange rates. CASH AND CASH EQUIVALENTS Cash and cash equivalents include short-term investments with a term to maturity of three months or less when purchased. 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 the Consolidated Statements of Financial Position. LOANS AND RECEIVABLES Affiliate long-term notes receivable are measured at amortized cost using the effective interest rate method, net of any impairment losses recognized. Accounts receivable and other are measured at cost. ALLOWANCE FOR DOUBTFUL ACCOUNTS Allowance for doubtful accounts is determined based on collection history. When we have determined that further collection efforts are unlikely to be successful, amounts charged to the allowance for doubtful accounts are applied against the impaired accounts receivable. NATURAL GAS IMBALANCES The Consolidated Statements of Financial Position include in-kind balances as a result of differences in gas volumes received and delivered for customers. Since settlement of certain imbalances is in-kind, changes in the balances do not have an effect on our Consolidated Statements of Earnings or Consolidated Statements of Cash Flows. Most natural gas volumes owed to or by us are valued at natural gas market index prices as at the balance sheet dates. INVENTORY Inventory is comprised of natural gas in storage held in EGD and Union Gas, and crude oil and natural gas held primarily by energy services businesses in the Energy Services segment. Natural gas in storage in EGD and Union Gas is recorded at the quarterly prices approved by the OEB in the determination of distribution rates. The actual price of gas purchased may differ from the OEB approved price. The difference between the approved price and the actual cost of the gas purchased is deferred as a liability for future refund or as an asset for collection as approved by the OEB. Other commodities inventory is recorded at the lower of cost, as determined on a weighted average basis, or market value. Upon disposition, other commodities inventory is recorded to Commodity costs on the Consolidated Statements of Earnings at the weighted average cost of inventory, including any adjustments recorded to reduce inventory to market value. PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment is recorded at historical cost. Expenditures for construction, expansion, major renewals and betterments are capitalized. Maintenance and repair costs are expensed as incurred. Expenditures for project development are capitalized if they are expected to have future benefit. We capitalize interest incurred during construction for non-rate-regulated assets. For rate-regulated assets, 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. Two primary methods of depreciation are utilized. For distinct assets, depreciation is generally provided on a straight-line basis over the estimated useful lives of the assets commencing when the asset is placed in service. For largely homogeneous groups of assets with comparable useful lives, the pool method of accounting for property, plant and equipment is followed whereby similar assets are grouped and depreciated as a pool. When group assets are retired or otherwise disposed of, gains and losses are generally not reflected in earnings but are booked as an adjustment to accumulated depreciation. DEFERRED AMOUNTS AND OTHER ASSETS Deferred amounts and other assets primarily include: costs which regulatory authorities have permitted, or are expected to permit, to be recovered through future rates including deferred income taxes; contractual receivables under the terms of long-term delivery contracts; and derivative financial instruments. INTANGIBLE ASSETS Intangible assets consist primarily of certain software costs, customer relationships and emission allowances. We capitalize costs incurred during the application development stage of internal use software projects . Customer relationships represent the underlying relationship from long-term agreements with customers that are capitalized upon acquisition. Emission allowances, which are recorded at their original cost, are purchased in order to meet greenhouse gas (GHG) compliance obligations. Intangible assets are generally amortized on a straight-line basis over their expected lives, commencing when the asset is available for use, with the exception of emission allowances, which are not amortized as they will be used to satisfy compliance obligations as they come due. GOODWILL Goodwill represents the excess of the purchase price over the fair value of net identifiable assets on acquisition of a business. The carrying value of goodwill, which is not amortized, is assessed for impairment annually, or more frequently if events or changes in circumstances arise that suggest the carrying value of goodwill may be impaired. We perform our annual review for impairment at the reporting unit level, which is identified by assessing whether the components of our operating segments constitute businesses for which discrete information is available, whether segment management regularly reviews the operating results of those components and whether the economic and regulatory characteristics are similar. We determined that our reporting units are equivalent to our reportable segments, with the exception of the gas transmission and gas midstream reportable segment which is divided at the component level into two reporting units. We have the option to first assess qualitative factors to determine whether it is necessary to perform the quantitative goodwill impairment test. The quantitative goodwill impairment test involves determining the fair value of our reporting units and comparing those values to the carrying value of each reporting unit. If the carrying value of a reporting unit, including allocated goodwill, exceeds its fair value, goodwill impairment is measured at the amount by which the reporting unit’s carrying value exceeds its fair value. This amount should not exceed the carrying amount of goodwill. IMPAIRMENT We review the carrying values of our long-lived assets as events or changes in circumstances warrant. If it is determined that the carrying value of an asset exceeds the undiscounted cash flows expected from the asset, we calculate fair value based on the discounted cash flows and write the assets down to the extent that the carrying value exceeds the fair value. With respect to investments in debt and equity securities, we assess at each balance sheet date whether there is objective evidence that a financial asset is impaired by completing a quantitative or qualitative analysis of factors impacting the investment. If there is objective evidence of impairment, we value the expected discounted cash flows using observable market inputs and determine whether the decline below carrying value is other than temporary. If the decline is determined to be other than temporary, an impairment charge is recorded in earnings with an offsetting reduction to the carrying value of the asset. With respect to other financial assets, we assess the assets for impairment when there is no longer reasonable assurance of timely collection. If evidence of impairment is noted, we reduce the value of the financial asset to its estimated realizable amount, determined using discounted expected future cash flows. ASSET RETIREMENT OBLIGATIONS ARO associated with the retirement of long-lived assets are measured at fair value and recognized as Accounts payable and other or Other long-term liabilities in the period in which they can be reasonably determined. The fair value approximates the cost a third party would charge to perform the tasks necessary to retire such assets and is recognized at the present value of expected future cash flows. AROs are added to the carrying value of the associated asset and depreciated over the asset’s useful life. The corresponding liability is accreted over time through charges to earnings and is reduced by actual costs of decommissioning and reclamation. Our estimates of retirement costs could change as a result of changes in cost estimates and regulatory requirements. RETIREMENT AND POSTRETIREMENT BENEFITS We maintain pension plans which provide defined benefit and defined contribution pension benefits. Defined benefit pension plan costs are determined using actuarial methods and are funded through contributions determined using the projected benefit method, which incorporates management’s best estimates of future salary levels, other cost escalations, retirement ages of employees and other actuarial factors including discount rates and mortality. We use mortality tables issued by the Society of Actuaries in the United States (revised in 2016) and the Canadian Institute of Actuaries tables (revised in 2014) to measure our benefit obligations of our United States pension plan (the United States Plan) and our Canadian pension plans (the Canadian Plans), respectively. We determine discount rates by reference to rates of high-quality long-term corporate bonds with maturities that approximate the timing of future payments we anticipate making under each of the respective plans. Pension cost is charged to earnings and includes: • Cost of pension plan benefits provided in exchange for employee services rendered during the year; • Interest cost of pension plan obligations; • Expected return on pension plan assets; • Amortization of the prior service costs and amendments on a straight-line basis over the expected average re

CHANGES IN ACCOUNTING POLICIES

CHANGES IN ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2017
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
CHANGES IN ACCOUNTING POLICIES	CHANGES IN ACCOUNTING POLICIES CHANGES IN ACCOUNTING POLICIES Goodwill We previously performed our annual goodwill impairment test on October 1 of each fiscal year. Beginning with the quarter ended December 31, 2017, we moved the annual goodwill impairment test from October 1 to April 1 to better align with the preparation and review of our business plan, which is used in the test. The change does not delay, accelerate or avoid an impairment charge. ADOPTION OF NEW STANDARDS Simplifying the Measurement of Goodwill Impairment Effective January 1, 2017, we early adopted Accounting Standards Update (ASU) 2017-04 and applied the standard on a prospective basis. Under the new guidance, goodwill impairment will now be the amount by which a reporting unit’s carrying value exceeds its fair value; this amount should not exceed the carrying amount of goodwill. We applied this standard as at December 31, 2017 in the measurement of the goodwill impairment relating to the gas midstream reporting unit (Note 15) . Clarifying the Definition of a Business in an Acquisition Effective January 1, 2017, we early adopted 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. This accounting update was applied to acquisitions and dispositions that occurred in the year. 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. Improvements to Employee Share-Based Payment Accounting Effective January 1, 2017, we adopted ASU 2016-09 and applied certain amendments on a modified retrospective basis with the remaining amendments applied on a prospective basis. The new standard was issued with the intent of simplifying and improving several aspects of accounting for share-based payment transactions including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. 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 Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income ASU 2018-02 was issued in February 2018 to address a specific consequence of the Tax Cuts and Jobs Act (TCJA). This accounting update allows a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from TCJA. The amendments eliminate the stranded tax effects that were created as a result of the reduction of historical U.S. federal corporate income tax rate to the newly enacted U.S. federal corporate income tax rate. The accounting update is effective January 1, 2019, with early adoption permitted, and is to be applied either in the period of adoption or retrospectively to each period in which the effect of the change in the U.S. federal corporate income tax rate in the TCJA is recognized. We are currently assessing the impact of the new standard on the consolidated financial statements. 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 our consolidated financial statements. Clarifying Guidance on the Application of Modification Accounting on Stock Compensation ASU 2017-09 was issued in May 2017 with the intent to clarify the scope of modification accounting and when it should be applied to a change to the terms or conditions of a share based payment award. Under the new guidance, modification accounting is required for all changes to share based payment awards, unless all of the following are met: 1) there is no change to the fair value of the award, 2) the vesting conditions have not changed, and 3) the classification of the award as an equity instrument or a debt instrument has not changed. 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. Amending the Amortization Period for Certain Callable Debt Securities Purchased at a Premium ASU 2017-08 was issued in March 2017 with the intent of shortening the amortization period to the earliest call date for certain callable debt securities held at a premium. The accounting update is effective January 1, 2019 and will be applied on a modified retrospective basis. We are currently assessing the impact of the new standard on our consolidated financial statements. Improving the Presentation of Net Periodic Benefit Cost related to Defined Benefit Plans ASU 2017-07 was issued in March 2017 primarily to improve the income statement presentation of the components of net periodic pension cost and net periodic postretirement benefit cost for an entity’s sponsored defined benefit pension and OPEB plans. In addition, only the service cost component of net benefit cost is eligible for capitalization. The accounting update is effective January 1, 2018 and will be applied on a retrospective basis for the statement of earnings presentation component and a prospective basis for the capitalization component. We do not expect the adoption of this accounting update to have a material impact on our consolidated financial statements. Clarifying Guidance on Derecognition and Partial Sales of Nonfinancial Assets ASU 2017-05 was issued in February 2017 with the intent of clarifying the scope of asset derecognition guidance and accounting for partial sales of nonfinancial assets. The ASU clarifies the scope provisions of nonfinancial assets and how to allocate consideration to each distinct asset, and amends the guidance for derecognition of a distinct nonfinancial asset in partial sale transactions. The accounting update is effective January 1, 2018 and will be applied on a modified retrospective basis. We do not expect the adoption of this accounting update to have a material impact on our consolidated financial statements. Clarifying the Presentation of Restricted Cash in the Statement of Cash Flows ASU 2016-18 was issued in November 2016 with the intent to clarify guidance on the classification and presentation of changes in restricted cash and restricted cash equivalents within the statement of cash flows. The accounting update requires that changes in restricted cash and restricted cash equivalents be included within cash and cash equivalents when reconciling the opening and closing period amounts shown on the statement of cash flows. We currently present the changes in restricted cash and restricted cash equivalents under investing activities in the Consolidated Statement of Cash Flows. The accounting update is effective January 1, 2018 and will be applied on a retrospective basis. We will amend the presentation in the Consolidated Statement of Cash Flows to include restricted cash and restricted cash equivalents with cash and cash equivalents and we will retrospectively reclassify all periods presented. 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 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 our revenue recognition practices. Based on our assessment to-date, the adoption of the new standard will have the following impact to our financial statements: • A change in presentation in the Gas Distribution business related to payments to customers under the earnings sharing mechanism which are currently shown as an expense in the Consolidated Statements of Earnings. Under the new standard, these payments will be reflected as a reduction of revenue. • Estimates of variable consideration, required under the new standard for certain Liquids Pipelines, Gas Transmission and Midstream and Green Power and Transmission revenue contracts as well as the allocation of the transaction price for certain Liquids Pipelines revenue contracts, may result in changes to the pattern or timing of revenue recognition for those contracts. • Non-cash consideration received in the form of a percentage of the products derived from processing natural gas in the Gas Transmission and Midstream business was previously accounted for as revenue when the commodity was sold to third parties. Under the new standard, the non-cash consideration will be accounted for as revenue when processing services are performed. The commodity will continue to be accounted for as revenue when it is subsequently sold to third parties. The impact of this change will be an increase in costs and revenues due to the recognition of this non-cash consideration. • Service fee revenue, from processing natural gas for certain contracts in the Gas Transmission and Midstream business whereby Enbridge purchases natural gas at the wellhead, then processes and subsequently sells the gas, was previously presented as revenue. Under the new standard, processing fees charged on natural gas purchased by Enbridge are presented as a reduction of commodity costs upon the transfer of control of the natural gas at the wellhead . • Revenue from certain contracts in the Gas Transmission and Midstream business that provide for Enbridge to process and sell customers’ natural gas and retain a percentage of the resulting processed natural gas and/or NGLs as payment for processing services rendered, commonly referred to as Percentage of Proceeds and Percentage of Liquids contracts, was previously presented on a gross basis whereby Enbridge recorded one hundred percent of the value of the natural gas and products sold as revenue, with the cost of the natural gas purchased recorded as commodity cost. Under the new standard only Enbridge’s share of the products retained and sold is presented as revenue and no commodity cost is recorded. • Certain payments received from customers to offset the cost of constructing assets required to provide services to those customers, referred to as Contributions in Aid of Construction (CIAC) 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 as revenue 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. Upon adoption, we will recognize the significant cumulative effect of initially applying the new standard as an increase in the opening balance of retained deficit of approximately $120 million, an increase in property, plant and equipment of $130 million and an increase in deferred revenue of $120 million, subject to final determination, as at January 1, 2018. The adoption of the new standard will also result in changes in classification between Revenue and Commodity costs as discussed above. We have also developed and tested processes to generate the disclosures which will be required under the new standard commencing in the first quarter of 2018.

SEGMENTED INFORMATION

SEGMENTED INFORMATION	12 Months Ended
	Dec. 31, 2017
Segment Reporting [Abstract]
SEGMENTED INFORMATION	SEGMENTED INFORMATION Effective December 31, 2017, we changed our segment-level profit measure to Earnings before interest, income taxes and depreciation and amortization from the previous measure of Earnings before interest and income taxes. We also renamed the Gas Pipelines and Processing segment to Gas Transmission and Midstream. The presentation of the prior years' tables has been revised in order to align with the current presentation. Segmented information for the years ended December 31, 2017 , 2016 and 2015 are as follows: Year ended December 31, 2017 Liquids Pipelines Gas Transmission and Midstream Gas Distribution Green Power and Transmission Energy Services Eliminations and Other Consolidated (millions of Canadian dollars) Revenues 8,913 7,067 4,992 534 23,282 (410 ) 44,378 Commodity and gas distribution costs (18 ) (2,834 ) (2,689 ) — (23,508 ) 412 (28,637 ) Operating and administrative (2,949 ) (1,756 ) (960 ) (163 ) (47 ) (567 ) (6,442 ) Impairment of long-lived assets — (4,463 ) — — — — (4,463 ) Impairment of goodwill — (102 ) — — — — (102 ) Income/(loss) from equity investments 416 653 23 6 8 (4 ) 1,102 Other income/(expense) 33 166 24 (5 ) 2 232 452 Earnings/(loss) before interest, income tax expense, and depreciation and amortization 6,395 (1,269 ) 1,390 372 (263 ) (337 ) 6,288 Depreciation and amortization (3,163 ) Interest expense (2,556 ) Income tax recovery 2,697 Earnings 3,266 Capital expenditures 1 2,799 4,016 1,177 321 1 108 8,422 Total assets 63,881 60,745 25,956 6,289 2,514 2,708 162,093 Year ended December 31, 2016 Liquids Pipelines Gas Transmission and Midstream Gas Distribution Green Power and Transmission Energy Services Eliminations and Other Consolidated (millions of Canadian dollars) Revenues 8,176 2,877 2,976 502 20,364 (335 ) 34,560 Commodity and gas distribution costs (12 ) (2,206 ) (1,653 ) 5 (20,473 ) 334 (24,005 ) Operating and administrative (2,908 ) (446 ) (553 ) (173 ) (63 ) (215 ) (4,358 ) Impairment of long-lived assets (1,365 ) (11 ) — — — — (1,376 ) Income/(loss) from equity investments 194 223 12 2 (3 ) — 428 Other income/(expense) 841 27 49 8 (8 ) 115 1,032 Earnings/(loss) before interest, income tax expense, and depreciation and amortization 4,926 464 831 344 (183 ) (101 ) 6,281 Depreciation and amortization (2,240 ) Interest expense (1,590 ) Income tax expense (142 ) Earnings 2,309 Capital expenditures 1 3,957 176 713 251 — 32 5,129 Total assets 52,007 11,182 10,132 5,571 1,951 4,366 85,209 Year ended December 31, 2015 Liquids Pipelines Gas Transmission and Midstream Gas Distribution Green Power and Transmission Energy Services Eliminations and Other Consolidated (millions of Canadian dollars) Revenues 5,589 3,803 3,609 498 20,842 (547 ) 33,794 Commodity and gas distribution costs (9 ) (3,002 ) (2,349 ) 4 (20,443 ) 558 (25,241 ) Operating and administrative (2,748 ) (506 ) (536 ) (143 ) (66 ) (132 ) (4,131 ) Impairment of long-lived assets (80 ) (16 ) — — — — (96 ) Impairment of goodwill — (440 ) — — — — (440 ) Income/(loss) from equity investments 296 200 (10 ) 2 (9 ) (4 ) 475 Other income/(expense) (15 ) 4 49 2 — (742 ) (702 ) Earnings/(loss) before interest, income tax expense, and depreciation and amortization 3,033 43 763 363 324 (867 ) 3,659 Depreciation and amortization (2,024 ) Interest expense (1,624 ) Income tax expense (170 ) Loss (159 ) Capital expenditures 1 5,884 385 858 68 — 80 7,275 1 Includes allowance for equity funds used during construction. The measurement basis for preparation of segmented information is consistent with the significant accounting policies (Note 2) . Our largest non-affiliated customer accounted for approximately 11.8% , 18.0% , and 21.8% of our third-party revenues for the years ended December 31, 2017, 2016 and 2015, respectively. A second customer accounted for approximately 10.4% of our third-party revenues for the year ended December 31, 2016. A third customer accounted for approximately 10.8% of our third-party revenues for the year ended December 31, 2015. Revenues from these three customers are primarily reported in the Energy Services segment. OUT-OF-PERIOD ADJUSTMENT Earnings attributable to common shareholders for the year ended December 31, 2015 were increased by an out-of-period adjustment of $71 million in respect of an overstatement of deferred income tax expense in 2013 and 2014. GEOGRAPHIC INFORMATION Revenues 1 Year ended December 31, 2017 2016 2015 (millions of Canadian dollars) Canada 18,076 12,470 11,087 United States 26,302 22,090 22,707 44,378 34,560 33,794 1 Revenues are based on the country of origin of the product or service sold. Property, Plant and Equipment 1 December 31, 2017 2016 (millions of Canadian dollars) Canada 46,025 32,008 United States 44,686 32,276 90,711 64,284 1 Amounts are based on the location where the assets are held.

EARNINGS PER COMMON SHARE

EARNINGS PER COMMON SHARE	12 Months Ended
	Dec. 31, 2017
Earnings Per Share [Abstract]
EARNINGS PER COMMON SHARE	EARNINGS PER COMMON SHARE BASIC Earnings per common share is calculated by dividing earnings attributable to common shareholders by the weighted average number of common shares outstanding. The weighted average number of common shares outstanding has been reduced by our pro-rata weighted average interest in our own common shares of 13 million as at December 31, 2017 and 2016 , and 12 million as at December 31, 2015 resulting from our reciprocal investment in Noverco. DILUTED The treasury stock method is used to determine the dilutive impact of stock options. This method assumes any proceeds from the exercise of stock options would be used to purchase common shares at the average market price during the period. Weighted average shares outstanding used to calculate basic and diluted earnings per share are as follows: December 31, 2017 2016 2015 (number of shares in millions) Weighted average shares outstanding 1,525 911 847 Effect of dilutive options 7 7 — Diluted weighted average shares outstanding 1,532 918 847 For the years ended December 31, 2017 , 2016 and 2015 , 14,271,615 , 10,803,672 and 36,005,043 , respectively, of anti-dilutive stock options with a weighted average exercise price of $56.71 , $52.92 and $40.26 , respectively, were excluded from the diluted earnings per common share calculation.

REGULATORY MATTERS

REGULATORY MATTERS	12 Months Ended
	Dec. 31, 2017
Regulated Operations [Abstract]
REGULATORY MATTERS	REGULATORY MATTERS GENERAL INFORMATION ON RATE REGULATION AND ITS ECONOMIC EFFECTS We record assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for non-regulated entities. See Note 2 for further discussion. A number of our businesses are subject to regulation by the NEB. We also collect and set aside funds to cover future pipeline abandonment costs for all NEB regulated pipelines as a result of the NEB’s regulatory requirements under LMCI (Note 13) . Amounts expected to be paid to cover future abandonment costs are recognized as long-term regulatory liabilities. Our significant regulated businesses and other related accounting impacts, are described below. Liquids Pipelines Canadian Mainline Canadian Mainline includes the Canadian portion of the mainline system and is subject to regulation by the NEB. Canadian Mainline tolls (excluding Lines 8 and 9) are currently governed by the 10 -year CTS, which establishes a Canadian Local Toll for all volumes shipped on the Canadian Mainline and an International Joint Tariff for all volumes shipped from western Canadian receipt points to delivery points on the Lakehead System and delivery points on the Canadian Mainline downstream of the Lakehead System. The CTS was negotiated with shippers in accordance with NEB guidelines, was approved by the NEB in June 2011 and took effect July 1, 2011. Under the CTS, a regulatory asset is recognized to offset deferred income taxes as a NEB rate order governing flow-through income tax treatment permits future recovery. No other material regulatory assets or liabilities are recognized under the terms of the CTS. Southern Lights Pipeline The United States portion of the Southern Lights Pipeline is regulated by the FERC and the Canadian portion of the Southern Lights Pipeline is regulated by the NEB. Shippers on the Southern Lights Pipeline are subject to long-term transportation contracts under a cost-of-service toll methodology. Toll adjustments are filed annually with the regulators. Tariffs provide for recovery of allowable operating and debt financing costs, plus a pre-determined after-tax rate of return on equity (ROE) of 10% . Southern Lights Pipeline tolls are based on a deemed 70% debt and 30% equity structure. Gas Transmission and Midstream British Columbia Pipeline and British Columbia Field Services Under the current NEB-authorized rate structure, income tax costs are recovered in tolls based on the current income tax payable and do not include accruals for deferred income tax. However, as income taxes become payable as a result of the reversal of timing differences that created the deferred income taxes, it is expected that transportation and field services tolls will be adjusted to recover these taxes. Since most of these timing differences are related to property, plant and equipment costs, this recovery is expected to occur over the life of those assets. Spectra Energy Partners, LP SEP's gas transmission and storage services are regulated by the FERC. Current rates are governed by the applicable FERC-approved natural gas tariff while fee-based gathering services are governed by the applicable state oil and gas commissions. For information related to regulatory assets acquired in the Merger Transaction for Union Gas, British Columbia (BC) Pipelines, BC Field Services and SEP, refer to Note 7 - Acquisitions and Dispositions . Gas Distribution Enbridge Gas Distribution Inc. EGD’s gas distribution operations are regulated by the OEB. Rates for the years ended December 31, 2017 and 2016 were set in accordance with parameters established by the customized incentive rate plan (IR Plan). The customized IR Plan, inclusive of the requested capital investment amounts and an incentive mechanism providing the opportunity to earn above the allowed ROE, was approved, with modifications, by the OEB in 2014. The approved customized IR Plan is for establishing rates for 2014 through 2018. As part of the customized IR Plan, the OEB approved the adoption of a new approach for determining net salvage percentages to be included within EGD’s approved depreciation rates, as compared with the traditional approach previously employed. The new approach results in lower net salvage percentages for EGD, and therefore lowers depreciation rates and future removal and site restoration reserves. The customized IR Plan also includes an earnings sharing mechanism, whereby any return over the allowed rate of return for a given year under the customized IR Plan will be shared equally with customers. Within annual rate proceedings for 2015 through 2018, the customized requires allowed revenues, and corresponding rates, to be updated annually for select items. EGD’s after-tax rate of return on common equity embedded in rates was 8.8% and 9.2% for the years ended December 31, 2017 and 2016 , respectively, based on a 36% deemed common equity component of capital for regulatory purposes, in both years. Union Gas Limited Union Gas is regulated by the OEB. Union Gas's distribution rates beginning January 1, 2014 are set under a five -year incentive regulation framework. The incentive regulation framework establishes new rates at the beginning of each year through the use of a pricing formula rather than through the examination of revenue and cost forecasts. The incentive regulation framework includes an earnings sharing mechanism that permits Union Gas to fully retain the return on common equity from utility operations up to 9.93% , share 50% of any earnings between 9.93% and 10.93% with customers, and share 90% of any earnings above 10.93% with customers. Union Gas's approved after-tax return on common equity is fixed at 8.93% for the five -year incentive regulation term. Enbridge Gas New Brunswick Inc. Enbridge Gas New Brunswick Inc. is regulated by the EUB. The current rates are set, as prescribed by legislation for 2018 and 2019. In 2020 all rates will be set by cost-of-service methodology. FINANCIAL STATEMENT EFFECTS Accounting for rate-regulated activities has resulted in the recognition of the following significant regulatory assets and liabilities: December 31, Recovery/Refund Period Ends 2017 2016 (millions of Canadian dollars) Regulatory assets/(liabilities) Liquids Pipelines Deferred income taxes Various 1,492 1,270 Tolling deferrals 2018 (34 ) (37 ) Recoverable income taxes Through 2030 46 51 Pipeline future abandonment costs 1 Various (141 ) (88 ) Gas Transmission and Midstream Deferred income taxes Various 717 — Regulatory liability related to income taxes 2 Various (1,078 ) — Other Various (16 ) — Gas Distribution Deferred income taxes Various 1,000 385 Purchased gas variance 3 Various 51 5 Pension plans and OPEB 4 Various 102 116 Constant dollar net salvage adjustment 2018 38 38 Future removal and site restoration reserves Various (1,066 ) (606 ) Site restoration clearance adjustment Various (31 ) (109 ) Other Various 31 (4 ) 1 Funds collected are included in Restricted long-term investments (Note 13) . 2 Relates to the establishment of a regulatory liability as a result of the United States tax reform legislation dated December 22, 2017. 3 Purchase gas variance is the difference between the actual cost and the approved cost of natural gas reflected in rates. EGD and Union Gas have been granted OEB approval to refund this balance to, or to collect this balance from, customers on a rolling 12-month basis via the Quarterly Rate Adjustment Mechanism process. 4 The balances are excluded from the rate base and do not earn an ROE. OTHER ITEMS AFFECTED BY RATE REGULATION Allowance for Funds Used During Construction and Other Capitalized Costs Under the pool method prescribed by certain regulators, it is not possible to identify the carrying value of the equity component of AFUDC or its effect on depreciation. Similarly, gains and losses on the retirement of certain specific fixed assets in any given year cannot be identified or quantified. Operating Cost Capitalization With the approval of regulators, certain operations capitalize a percentage of specified operating costs. These operations are authorized to charge depreciation and earn a return on the net book value of such capitalized costs in future years. In the absence of rate regulation, a portion of such operating costs would be charged to earnings in the year incurred. EGD entered into a services contract relating to asset management initiatives. The majority of the costs, primarily consulting fees, are being capitalized to gas mains in accordance with regulatory approval. As at December 31, 2017 and 2016 , the net book value of these costs included in gas mains in Property, plant and equipment, net was $118 million and $125 million , respectively. In the absence of rate regulation accounting, some of these costs would be charged to earnings in the year incurred.

ACQUISITIONS AND DISPOSITIONS

ACQUISITIONS AND DISPOSITIONS	12 Months Ended
	Dec. 31, 2017
Business Combinations [Abstract]
ACQUISITIONS AND DISPOSITIONS	ACQUISITIONS AND DISPOSITIONS ACQUISITIONS Spectra Energy Corp On February 27, 2017, Enbridge and Spectra Energy combined in the Merger Transaction for a purchase price of $37.5 billion . Under the terms of the Merger Transaction, Spectra Energy shareholders received 0.984 shares of Enbridge for each share of Spectra Energy common stock that they owned, giving us 100% ownership of Spectra Energy. Consideration offered to complete the Merger Transaction included 691 million common shares of Enbridge at US $41.34 per share, based on the February 24, 2017 closing price on the New York Stock Exchange (NYSE), for a total value of $37,429 million in common shares issued to Spectra Energy shareholders, plus approximately $3 million in cash in lieu of any fractional shares, and 3.5 million share options with a fair value of $77 million , that were exchanged for Spectra Energy’s outstanding stock compensation awards. Spectra Energy, through its subsidiaries and equity affiliates, owns and operates a large and diversified portfolio of complementary natural gas-related energy assets and is one of North America’s leading natural gas infrastructure companies. Spectra Energy also owns and operates a crude oil pipeline system that connects Canadian and United States producers to refineries in the United States Rocky Mountain and Midwest regions. The combination brings together two highly complementary platforms to create North America’s largest energy infrastructure company and meaningfully enhances customer optionality, positioning us for long-term growth opportunities, and strengthening our balance sheet. The Merger Transaction has been accounted for as a business combination under the acquisition method of accounting as prescribed by Accounting Standards Codification (ASC) 805 Business Combinations . The acquired tangible and intangible assets and assumed liabilities are recorded at their estimated fair values at the date of acquisition. The purchase price allocation has been completed as at December 31, 2017 , along with the allocation of goodwill to reporting units (Note 15) . Our reporting units are equivalent to our identified segments with the exception of the Gas Transmission and Midstream segment, which is composed of two reporting units: gas transmission and gas midstream. The following table summarizes the estimated fair values that were assigned to the net assets of Spectra Energy: February 27, 2017 (millions of Canadian dollars) Fair value of net assets acquired: Current assets (a) 2,432 Property, plant and equipment, net (b) 33,555 Restricted long-term investments 144 Long-term investments (c) 5,000 Deferred amounts and other assets (d) 2,390 Intangible assets, net (e) 1,288 Current liabilities (a) (3,982 ) Long-term debt (d) (21,444 ) Other long-term liabilities (1,983 ) Deferred income taxes (b) (7,670 ) Noncontrolling interests (f) (8,877 ) 853 Goodwill (g) 36,656 37,509 Purchase price: Common shares 37,429 Cash 3 Fair value of outstanding earned stock compensation awards recorded in Additional paid-in capital 77 37,509 a) Accounts receivable is comprised primarily of customer trade receivables and natural gas imbalances. As such, the fair value of accounts receivable approximates the net carrying value of $1,174 million . The gross amount due of $1,190 million , of which $16 million is not expected to be collected, is included in current assets. During the fourth quarter of 2017, we identified certain transactions that were not reflected in the purchase price equation. This resulted in a $67 million and $548 million increase in current assets and current liabilities, respectively, and a $481 million decrease in long-term debt. b) We have applied the valuation methodologies described in ASC 820 Fair Value Measurements and Disclosures , to value the property, plant and equipment purchased. The fair value of Spectra Energy’s rate-regulated property, plant and equipment was determined using a market participant perspective, which is their carrying amount. The fair value of the remaining non-regulated property, plant and equipment was determined primarily using variations of the income approach, which is based on the present value of the future after-tax cash flows attributable to each non-regulated asset. Some of the more significant assumptions inherent in the development of the values, from the perspective of a market participant, include, but are not limited to, the amount and timing of projected future cash flows (including revenue and profitability); the discount rate selected to measure the risks inherent in the future cash flows; the assessment of the asset’s life cycle; the competitive trends impacting the asset; and customer turnover. During the third quarter of 2017, Spectra Energy's right-of-way agreements were reclassified from intangible assets to property, plant and equipment to conform the presentation of these agreements with our accounting policy pertaining to rights-of-way. The purchase price allocation above reflects this reclassification, which amounted to $830 million as at February 27, 2017. There is no change in the amortization period for the right-of-way agreements as a result of this reclassification. During the fourth quarter of 2017, we finalized our fair value measurement of the BC Pipeline & Field Services businesses, which resulted in decreases to property, plant and equipment of $1,955 million and deferred income tax liabilities of $661 million as at February 27, 2017. c) Long-term investments represent Spectra Energy’s 50% equity investment in DCP Midstream, Gulfstream Natural Gas System, L.L.C., Nexus Gas Transmission, LLC (Nexus), Steckman Ridge LP, Islander East Pipeline Company, L.L.C., Southeast Supply Header L.L.C., and 20% equity interest in PennEast Pipeline Company LLC (PennEast). The fair value of these investments was determined using an income approach. d) Fair value of long-term debt was determined based on the current underlying Government of Canada and United States Treasury interest rates on the corresponding bonds, as well as an implied credit spread based on current market conditions and resulted in an increase in the book value of debt of $1.5 billion . The fair value adjustment to long-term debt related to rate-regulated entities of $629 million also results in a regulatory offset in Deferred amounts and other assets in the Consolidated Statements of Financial Position. During the fourth quarter of 2017, deferred amounts and other assets decreased by $530 million as at February 27, 2017 due to the finalization of BC Pipelines & Field Services' fair value measurement, as discussed under (b) above. During the fourth quarter of 2017, we identified certain transactions that were not reflected in the purchase price equation. This resulted in a $481 million decrease in long-term debt, as discussed under (a) above. e) Intangible assets primarily consist of customer relationships in the non-regulated business, which represent the underlying relationship from long-term agreements with customers that are capitalized upon acquisition, determined using the income approach. Intangible assets are amortized on a straight-line basis over their expected lives. During the third quarter of 2017, intangible assets decreased by $830 million as at February 27, 2017 due to a reclassification to property, plant and equipment, as discussed under (b) above. The fair value of intangible assets acquired through the Merger Transaction, by major classes is as follows: Weighted Average Fair As at February 27, 2017 Amortization Rate Value (millions of Canadian dollars) Customer relationships 1 3.7 % 739 Project agreement 2 4.0 % 105 Software 11.1 % 329 Other 4.2 % 115 1,288 1 Represents customer relationships in the non-regulated business, which were capitalized upon acquisition. 2 Represents a project agreement between SEP, NextEra Energy, Inc., Duke Energy Corporation (Duke Energy) and Williams Partners L.P. In accordance with the agreement, payments will be made, based on our proportional ownership interest in Sabal Trail Transmission, LLC (Sabal Trail), as certain milestones of the project are met. Amortization of the intangible asset began on July 3, 2017 , when Sabal Trail was placed into service (Note 12) . f) The fair value of Spectra Energy’s noncontrolling interests includes approximately 78.4 million SEP common units outstanding to the public, valued at the February 24, 2017 closing price of US $44.88 per common unit on the NYSE, and units held by third parties in Maritimes & Northeast Pipeline, L.L.C., Sabal Trail and Algonquin Gas Transmission, L.L.C., valued based on the underlying net assets of each reporting unit and preferred stock held by third parties in Union Gas and Westcoast Energy Inc. During the third quarter of 2017, we finalized our fair value measurement of Sabal Trail, which resulted in an increase to noncontrolling interests of $85 million as at February 27, 2017. g) We recorded $36.7 billion in goodwill, which is primarily related to expected synergies from the Merger Transaction. The goodwill balance recognized is not deductible for tax purposes. Factors that contributed to the goodwill include the opportunity to expand our natural gas pipelines segment, the potential for cost and supply chain optimization synergies, existing assembled assets and work force that cannot be duplicated at the same cost by a new entrant, franchise rights and other intangibles not separately identifiable because they are inextricably linked to the provision of regulated utility service and the enhanced scale and geographic diversity which provide greater optionality and platforms for future growth. During the third quarter of 2017, goodwill increased by $85 million as at February 27, 2017 due to the finalization of the fair value measurement of Sabal Trail as discussed under (f) above. During the fourth quarter of 2017, goodwill increased by $1,824 million as at February 27, 2017 due to the finalization of the fair value measurement of BC Pipelines & Field Services as discussed under (b) above. Acquisition-related expenses incurred to date were approximately $231 million . Costs incurred for the years ended December 31, 2017 and 2016 of $180 million and $51 million , respectively, are included in Operating and administrative expense in the Consolidated Statements of Earnings. Upon completion of the Merger Transaction, we began consolidating Spectra Energy. Since the closing date of February 27, 2017 through December 31, 2017, Spectra Energy has generated approximately $5,740 million in revenues and $2,574 million in earnings. Our supplemental pro forma consolidated financial information for the years ended December 31, 2017 and 2016, including the results of operations for Spectra Energy as if the Merger Transaction had been completed on January 1, 2016 are as follows: Year ended December 31, 2017 2016 (unaudited; millions of Canadian dollars) Revenues 45,669 40,934 Earnings attributable to common shareholders 1 2,902 2,820 1 Merger Transaction costs of $180 million (after-tax $131 million ) were excluded from earnings for the year ended December 31, 2017. Tupper Main and Tupper West On April 1, 2016, we acquired the Tupper Main and Tupper West gas plants and associated pipelines (the Tupper Plants) located in northeastern BC for cash consideration of $539 million . The purchase price for the Tupper Plants was equal to the fair value of identifiable net assets acquired and accordingly, we did not recognize any goodwill as part of the acquisition. Transaction costs incurred by us totaled approximately $1 million and are included in Operating and administrative expense in the Consolidated Statements of Earnings. The Tupper Plants are a part of our Gas Transmission and Midstream segment. Since the closing date through December 31, 2016, the Tupper Plants generated approximately $33 million in revenues and $22 million in earnings before interest and income taxes. If the acquisition had closed on January 1, 2016, the Consolidated Statements of Earnings for the year ended December 31, 2016 would have shown revenues of $44 million and earnings before interest and income taxes of $28 million . The final purchase price allocation was as follows: April 1, 2016 (millions of Canadian dollars) Fair value of net assets acquired: Property, plant and equipment 288 Intangible assets 251 539 Purchase price: Cash 539 OTHER ACQUISITIONS Chapman Ranch Wind Project On September 9, 2016, we acquired a 100% interest in the 249 megawatt (MW) Chapman Ranch Wind Project (Chapman Ranch) located in Texas for cash consideration of $65 million (US $50 million ), of which $62 million (US $48 million ) was allocated to property, plant and equipment and the balance allocated to Intangible assets. On November 2, 2016, we invested a further $40 million (US $30 million ) in Chapman Ranch, of which $23 million (US $17 million ) was related to Property, plant and equipment and the balance related to Intangible assets. There would have been no effect on our earnings if the transaction had occurred on January 1, 2016 as the project was under construction and had not generated revenues to date. Chapman Ranch is a part of our Green Power and Transmission segment. New Creek Wind Project In November 2015, we acquired a 100% interest in the 103 MW New Creek Wind Project (New Creek) for cash consideration of $48 million (US $36 million ), with $35 million (US $26 million ) of the purchase price allocated to Property, plant and equipment and the balance allocated to Intangible assets. New Creek was placed into service in December 2016 and is a part of our Green Power and Transmission segment. Midstream Business On February 27, 2015, Enbridge Energy Partners, L.P. (EEP) acquired, through its partially-owned subsidiary, Midcoast Energy Partners, L.P. (MEP), the midstream business of New Gulf Resources, LLC located in Texas for $106 million (US $85 million ) in cash and a contingent future payment of up to $21 million (US $17 million ). The acquisition consisted of a natural gas gathering system that is in operation and is a part of our Gas Transmission and Midstream segment. Of the purchase price, we allocated $69 million (US $55 million ) to Property, plant and equipment and the balance to Intangible assets. In 2016, we determined that the likelihood of making any future contingent payments was remote. ASSETS HELD FOR SALE US Midstream In November 2017, we announced that we have identified certain non-core assets that we plan to sell or monetize in 2018 as they do not meet our long-term strategy. As a result, we are in the process of selling certain assets within the United States Midstream business of our Gas Transmission and Midstream segment. As at December 31, 2017, we classified these assets as held for sale and measured them at the lower of their carrying value or fair value less costs to sell, which resulted in a loss of $4.4 billion ( $2.8 billion after-tax) and a related goodwill impairment of $102 million . Fair value less cost to sell was estimated using the discounted cash flow method, which was negatively impacted by prolonged decline in commodity prices and deteriorating business performance. This loss has been included within Impairment of long-lived assets and Impairment of goodwill, respectively, on the Consolidated Statements of Earnings for the year ended December 31, 2017. St. Lawrence Gas Company, Inc. In August 2017, we entered into an agreement to sell the issued and outstanding shares of St. Lawrence Gas Company, Inc. (St. Lawrence Gas) for cash proceeds of approximately $88 million (US $70 million ). Subject to regulatory approval and certain pre-closing conditions, the transaction is expected to close in 2018. As at December 31, 2017, St. Lawrence Gas, which is a part of our Gas Distribution segment, was classified as held for sale in the Consolidated Statements of Financial Position. The table below summarizes the presentation of net assets held for sale in our Consolidated Statements of Financial Position: December 31, 2017 2016 (millions of Canadian dollars) Accounts receivable and other (current assets held for sale) 424 — Deferred amounts and other assets (long-term assets held for sale) 1,190 278 Accounts payable and other (current liabilities held for sale) (315 ) — Net assets held for sale 1,299 278 DISPOSITIONS Olympic Pipeline On July 31, 2017, we completed the sale of our interest in Olympic Pipeline for cash proceeds of approximately $203 million (US $160 million ). A gain on disposal of $27 million (US $21 million ) before tax was included in Other income/(expense) in the Consolidated Statements of Earnings. This interest was a part of our Liquids Pipelines segment. Sandpiper Project During the year ended December 31, 2017, we sold unused pipe related to the Sandpiper Project (Sandpiper) for cash proceeds of approximately $148 million (US $111 million ). A gain on disposal of $83 million (US $63 million ) before tax was included in Operating and administrative expense in the Consolidated Statements of Earnings. These assets were a part of our Liquids Pipelines segment. Ozark Pipeline In 2016, we classified the Ozark Pipeline assets as held for sale. On March 1, 2017, we completed the sale of the Ozark Pipeline assets to a subsidiary of MPLX LP for cash proceeds of approximately $294 million (US $220 million ), including reimbursement of costs. A gain on disposal of $14 million (US $10 million ) before tax was included in Operating and administrative expense in the Consolidated Statements of Earnings. These assets were a part of our Liquids Pipelines segment. South Prairie Region On December 1, 2016, we completed the sale of the South Prairie Region assets for cash proceeds of approximately $1.1 billion . A gain on disposal of $850 million before tax was included in Other income/(expense) in the Consolidated Statements of Earnings. These assets were a part of our Liquids Pipelines segment. OTHER DISPOSITIONS In December 2016, we sold other miscellaneous non-core assets for cash proceeds of approximately $286 million . In August 2015, we sold our 77.8% controlling interest in the Frontier Pipeline Company, which holds pipeline assets located in the midwest United States, for gross proceeds of approximately $112 million (US $85 million ). A gain on disposal of $70 million (US $53 million ) before tax was included in Other income/(expense) in the Consolidated Statements of Earnings. This interest was a part of our Liquids Pipelines segment. In May 2015, the Fund sold certain of its crude oil pipeline system assets for gross proceeds of approximately $26 million . A gain on disposal of $22 million before tax was included in Other income/(expense) in the Consolidated Statements of Earnings. These assets were a part of our Liquids Pipelines segment.

ACCOUNTS RECEIVABLE AND OTHER

ACCOUNTS RECEIVABLE AND OTHER	12 Months Ended
	Dec. 31, 2017
Receivables [Abstract]
ACCOUNTS RECEIVABLE AND OTHER	ACCOUNTS RECEIVABLE AND OTHER December 31, 2017 2016 (millions of Canadian dollars) Trade receivables and unbilled revenues 1 5,325 3,814 Other 1,728 1,164 7,053 4,978 1 Net of allowance for doubtful accounts of $50 million and $46 million as at December 31, 2017 and 2016 , respectively. During 2017, in conjunction with its restructuring actions (Note 19) , EEP terminated a receivable purchase agreement with a special purpose entity wholly-owned by us.

INVENTORY

INVENTORY	12 Months Ended
	Dec. 31, 2017
Inventory Disclosure [Abstract]
INVENTORY	INVENTORY December 31, 2017 2016 (millions of Canadian dollars) Natural gas 695 594 Crude oil 744 634 Other commodities 89 5 1,528 1,233

PROPERTY, PLANT AND EQUIPMENT

PROPERTY, PLANT AND EQUIPMENT	12 Months Ended
	Dec. 31, 2017
Property, Plant and Equipment [Abstract]
PROPERTY, PLANT AND EQUIPMENT	PROPERTY, PLANT AND EQUIPMENT Weighted Average December 31, Depreciation Rate 2017 2016 (millions of Canadian dollars) Pipeline 2.5 % 47,720 34,474 Pumping equipment, buildings, tanks and other 2.9 % 16,610 15,554 Land and right-of-way 1 2.1 % 2,538 2,067 Gas mains, services and other 2.1 % 17,026 10,022 Compressors, meters and other operating equipment 2.1 % 5,774 4,014 Processing and treating plants 3.1 % 1,440 846 Storage 2.0 % 1,545 — Wind turbines, solar panels and other 3.3 % 4,804 4,259 Power transmission 2.2 % 365 378 Vehicles, office furniture, equipment and other buildings and improvements 6.5 % 390 315 Under construction — 7,601 6,966 Total property, plant and equipment 2 105,813 78,895 Total accumulated depreciation (15,102 ) (14,611 ) Property, plant and equipment, net 90,711 64,284 1 The measurement of weighted average depreciation rate excludes non-depreciable assets. 2 Certain assets were reclassified as held for sale as at December 31, 2017 (Note 7) . Depreciation expense for the years ended December 31, 2017 , 2016 and 2015 was $2.9 billion , $2.0 billion and $1.9 billion , respectively. IMPAIRMENT Northern Gateway Project On November 29, 2016, the Canadian Federal Government directed the NEB to dismiss our Northern Gateway Project application and the Certificates of Public Convenience and Necessity have been rescinded. In consultation with potential shippers and Aboriginal equity partners, we assessed this decision and concluded that the project cannot proceed as envisioned. After taking into consideration the amount recoverable from potential shippers on Northern Gateway Project, we recognized an impairment of $373 million ( $272 million after-tax), which is included in Impairment of property, plant and equipment in the Consolidated Statements of Earnings. This impairment loss is based on the full carrying value of the assets, which have an estimated fair value of nil, and are a part of our Liquids Pipelines segment. Sandpiper Project On September 1, 2016, we announced that EEP applied for the withdrawal of regulatory applications pending with the Minnesota Public Utilities Commission for Sandpiper. In connection with this announcement and other factors, we evaluated Sandpiper for impairment. As a result, we recognized an impairment loss of $992 million ( $81 million after-tax attributable to us) for the year ended December 31, 2016 , which is included in Impairment of property, plant and equipment in the Consolidated Statements of Earnings. Sandpiper is a part of our Liquids Pipelines segment. The estimated remaining fair value of Sandpiper was based on the estimated price that would be received to sell unused pipe, land and other related equipment in its current condition, considering the current market conditions for sale of these assets at the time. The valuation considered a range of potential selling prices from various alternatives that could be used to dispose of these assets. The estimated fair value, with the exception of $3 million in land, was reclassified into Deferred amounts and other assets in the Consolidated Statements of Financial Position as at December 31, 2016 . During 2017, we disposed of substantially all of the remaining Sandpiper assets (Note 7) . Other For the year ended December 31, 2016, we recorded impairment charges of $11 million related to EEP’s non-core trucking assets and related facilities, which are a part of our Gas Transmission and Midstream segment. For the year ended December 31, 2015, we recorded impairment charges of $96 million , of which $80 million related to EEP’s Berthold rail facility, included within the Liquids Pipelines segment, due to contracts that were not yet renewed beyond 2016. The remaining $16 million in impairment charges relate to EEP’s non-core Louisiana propylene pipeline asset, included within the Gas Transmission and Midstream segment, following finalization of a contract restructuring with a primary customer. Impairment charges were based on the amount by which the carrying values of the assets exceeded fair value, determined using expected discounted future cash flows, and such charges are included in Impairment of property, plant and equipment on the Consolidated Statements of Earnings.

VARIABLE INTEREST ENTITIES

VARIABLE INTEREST ENTITIES	12 Months Ended
	Dec. 31, 2017
Equity Method Investments and Joint Ventures [Abstract]
VARIABLE INTEREST ENTITIES	VARIABLE INTEREST ENTITIES CONSOLIDATED VARIABLE INTEREST ENTITIES Enbridge Energy Partners, L.P. EEP is a publicly-traded Delaware limited partnership and is considered a VIE as its limited partners do not have substantive kick-out rights or participating rights. Through our wholly-owned subsidiary, Enbridge Energy Company, Inc. (EECI), we have the power to direct EEP’s activities and have a significant impact on EEP’s economic performance. Along with an economic interest held through an indirect common interest and general partner interest through EECI, and through our 100% ownership of EECI, we are the primary beneficiary of EEP. As at December 31, 2017 and 2016 , our economic interest in EEP was 34.6% and 35.3% respectively. The public owns the remaining interests in EEP. Enbridge Income Fund The Fund is an unincorporated open-ended trust established by a trust indenture under the laws of the Province of Alberta and is considered a VIE by virtue of its capital structure. We are the primary beneficiary of the Fund through our combined 82.5% economic interest held indirectly through a common investment in ENF, a direct common interest in the Fund, a preferred unit investment in ECT, a direct common interest in Enbridge Income Partners GP Inc., and a direct common interest in EIPLP. As at December 31, 2016 , our combined economic interest was 86.9% . As at December 31, 2017 and 2016 , our direct common interest in the Fund was 29.4% and 43.2% , respectively. We also serve in the capacity of Manager of ENF and the Fund Group. Enbridge Commercial Trust We have the ability to appoint the majority of the trustees to ECT’s Board of Trustees, resulting in a lack of decision making ability for the holders of the common trust units of ECT. As a result, ECT is considered to be a VIE and although we do not have a common equity interest in ECT, we are considered to be the primary beneficiary of ECT. We also serve in the capacity of Manager of ECT, as part of the Fund Group. Enbridge Income Partners LP EIPLP, formed in 2002, is involved in the generation, transportation and storage of energy through interests in its Liquids Pipelines business, including the Canadian Mainline, the Regional Oil Sands System, a 50.0% interest in the Alliance Pipeline, which transports natural gas, and its renewable and alternative power generation facilities. EIPLP is a partnership between an indirect wholly-owned subsidiary of Enbridge and ECT. EIPLP is considered a VIE as its limited partners lack substantive kick-out rights and participating rights. Through a majority ownership of EIPLP’s General Partner, 100% ownership of Enbridge Management Services Inc. (a service provider for EIPLP), and 53.1% of direct common interest in EIPLP, we have the power to direct the activities that most significantly impact EIPLP’s economic performance and have the obligation to absorb losses and the right to receive residual returns that are potentially significant to EIPLP, making us the primary beneficiary of EIPLP. As at December 31, 2017 and 2016 , our economic interest in EIPLP was 73.5% and 79.1% , respectively. Green Power and Transmission Through various subsidiaries, we have a majority ownership interest in Magic Valley, Wildcat, Keechi Wind Project (Keechi), and New Creek wind farms. These wind farms are considered VIEs as they do not have sufficient equity at risk and are partially financed by tax equity investors. We are the primary beneficiary of these VIEs by virtue of our voting rights, our power to direct the activities that most significantly impact the economic performance of the wind farms, and our obligation to absorb losses. Enbridge Holdings (DakTex) L.L.C. Enbridge Holdings (DakTex) L.L.C. (DakTex) is owned 75% by a wholly-owned subsidiary of Enbridge and 25% by EEP, through which we have an effective 27.6% interest in the equity investment, Bakken Pipeline System (Note 12) . EEP is the primary beneficiary because it has the power to direct DakTex’s activities that most significantly impact its economic performance. We consolidate EEP and by extension also consolidate DakTex. Spectra Energy Partners, LP We acquired a 75% o wnership in SEP through the Merger Transaction. SEP is a natural gas and crude oil infrastructure master limited partnership and is considered a VIE as its limited partners do not have substantive kick-out rights or participating rights. We are the primary beneficiary of SEP because we have the power to direct SEP’s activities that most significantly impact its economic performance. Valley Crossing Pipeline, LLC Valley Crossing Pipeline, LLC (Valley Crossing), a wholly-owned subsidiary of Enbridge, is constructing a natural gas pipeline to transport natural gas within Texas. Valley Crossing is considered a VIE due to insufficient equity at risk to finance its activities. We are the primary beneficiary of Valley Crossing because we have the power to direct Valley Crossing’s activities that most significantly impact its economic performance. Other Limited Partnerships By virtue of a lack of substantive kick-out rights and participating rights, substantially all limited partnerships wholly-owned by us and/or our subsidiaries are considered VIEs. As these entities are 100% owned and directed by us with no third parties having the ability to direct any of the significant activities, we are considered the primary beneficiary. 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 the Consolidated Statements of Financial Position. December 31, 2017 2016 (millions of Canadian dollars) Assets Cash and cash equivalents 368 314 Accounts receivable and other 2,132 781 Accounts receivable from affiliates 3 3 Inventory 220 53 2,723 1,151 Property, plant and equipment, net 68,685 45,720 Long-term investments 6,258 954 Restricted long-term investments 206 83 Deferred amounts and other assets 2,921 2,227 Intangible assets, net 296 488 Goodwill 29 29 Deferred income taxes 145 231 81,263 50,883 Liabilities Short-term borrowings 485 — Accounts payable and other 2,859 1,446 Accounts payable to affiliates 131 105 Interest payable 312 204 Environmental liabilities 35 140 Current portion of long-term debt 2,129 342 5,951 2,237 Long-term debt 31,469 20,176 Other long-term liabilities 4,301 1,207 Deferred income taxes 3,010 1,753 44,731 25,373 Net assets before noncontrolling interests 36,532 25,510 We do not have an obligation to provide financial support to any of the consolidated VIEs, with the exception of EIPLP. We are required, when called on by ENF, to backstop equity funding required by EIPLP to undertake the growth program embedded in the assets it acquired in the Canadian Restructuring Plan. UNCONSOLIDATED VARIABLE INTEREST ENTITIES Sabal Trail Transmission, LLC SEP owns a 50% interest in Sabal Trail, a joint venture that operates a pipeline originating in Alabama that transports natural gas to Florida. On July 3, 2017, we discontinued the consolidation of Sabal Trail and accounted for our interest under the equity method. Sabal Trail is a VIE due to insufficient equity at risk to finance its activities. We are not the primary beneficiary because the power to direct Sabal Trail's activities that most significantly impact its economic performance is shared. Nexus Gas Transmission, LLC SEP owns a 50% equity investment in Nexus, a joint venture that is constructing a natural gas pipeline from Ohio to Michigan and continuing on to Ontario, Canada. Nexus is a VIE due to insufficient equity at risk to finance its activities. We are not the primary beneficiary because the power to direct Nexus’ activities that most significantly impact its economic performance is shared. PennEast Pipeline Company, LLC SEP owned a 10% equity investment in PennEast, which was increased to 20% in June 2017. PennEast is constructing a natural gas pipeline from northeastern Pennsylvania to New Jersey. PennEast is a VIE due to insufficient equity at risk to finance its activities. We are not the primary beneficiary since we do not have the power to direct PennEast’s activities that most significantly impact its economic performance. We currently hold several equity investments in limited partnerships that are assessed to be VIEs due to limited partners not having substantive kick-out rights or participating rights. We have determined that we do not have the power to direct the activities of the VIEs that most significantly impact the VIEs’ economic performance. Specifically, the power to direct the activities of a majority of these VIEs is shared amongst the partners. Each partner has representatives that make up an executive committee who makes significant decisions for the VIE and none of the partners may make major decisions unilaterally. The carrying amount of our interest in VIEs that are unconsolidated and our estimated maximum exposure to loss as at December 31, 2017 and 2016 is presented below. Carrying Amount of Investment Enbridge’s Maximum Exposure to December 31, 2017 in VIE Loss (millions of Canadian dollars) Aux Sable Liquid Products L.P. 1 300 361 Eolien Maritime France SAS 2 69 754 Hohe See Offshore Wind Project 3 763 2,484 Illinois Extension Pipeline Company, L.L.C. 4 686 686 Nexus Gas Transmission, LLC 5 834 1,678 PennEast Pipeline Company, LLC 5 69 345 Rampion Offshore Wind Limited 6 555 679 Sabal Trail Transmissions, LLC 5 2,355 2,529 Vector Pipeline L.P. 7 169 278 Other 4 21 21 5,821 9,815 Carrying Amount of Investment Enbridge’s Maximum Exposure to December 31, 2016 in VIE Loss (millions of Canadian dollars) Aux Sable Liquid Products L.P. 158 223 Eddystone Rail Company, LLC 8 19 25 Eolien Maritime France SAS 58 686 Illinois Extension Pipeline Company, L.L.C. 759 759 Rampion Offshore Wind Limited 345 457 Vector Pipeline L.P. 159 289 Other 17 17 1,515 2,456 1 At December 31, 2017 , the maximum exposure to loss includes a guarantee by us for our respective share of the VIE’s borrowing on a bank credit facility. 2 At December 31, 2017 , the maximum exposure to loss includes the portion of our parental guarantee that has been committed in project construction contracts in which we would be liable for in the event of default by the VIE and an outstanding affiliate loan receivable for $163 million held by us. 3 At December 31, 2017 , the maximum exposure to loss includes the portion of our parental guarantee that has been committed in project construction contracts in which we would be liable for in the event of default by the VIE. 4 At December 31, 2017 , the maximum exposure to loss is limited to our equity investment as these companies are in operation and self-sustaining. 5 At December 31, 2017 the maximum exposure to loss is limited to our equity investment and the remaining expected contributions for each joint venture. 6 At December 31, 2017 , the maximum exposure to loss includes the portion of our parental guarantee that has been committed in project construction contracts in which we would be liable for in the event of default by the VIE. 7 At December 31, 2017 the maximum exposure to loss includes the carrying value of an outstanding loan issued by us. 8 As at December 31, 2017 , Eddystone Rail Company, LLC is a 100% owned subsidiary and therefore is no longer an unconsolidated VIE. We do not have an obligation to and did not provide any additional financial support to the VIEs during the years ended December 31, 2017 and 2016.

LONG-TERM INVESTMENTS

LONG-TERM INVESTMENTS	12 Months Ended
	Dec. 31, 2017
Equity Method Investments and Joint Ventures [Abstract]
LONG-TERM INVESTMENTS	LONG-TERM INVESTMENTS Ownership December 31, Interest 2017 2016 (millions of Canadian dollars) EQUITY INVESTMENTS Liquids Pipelines Bakken Pipeline System 1 27.6 % 1,938 — Eddystone Rail Company, LLC 100.0 % — 19 Seaway Crude Pipeline System 50.0 % 2,882 3,129 Illinois Extension Pipeline Company, L.L.C. 2 65.0 % 686 759 Other 30.0% - 43.8% 87 70 Gas Transmission and Midstream Alliance Pipeline 3 50.0 % 375 411 Aux Sable 42.7% - 50.0% 300 324 DCP Midstream, LLC 4 50.0 % 2,143 — Gulfstream Natural Gas System, L.L.C. 4 50.0 % 1,205 — Nexus Gas Transmission, LLC 4 50.0 % 834 — Offshore - various joint ventures 22.0% - 74.3% 389 435 PennEast Pipeline Company LLC 4 20.0 % 69 — Sabal Trail Transmission, LLC 5 50.0 % 2,355 — Southeast Supply Header L.L.C. 4 50.0 % 486 — Steckman Ridge LP 4 49.5 % 221 — Texas Express Pipeline 35.0 % 430 484 Vector Pipeline L.P. 60.0 % 169 159 Other 4 33.3% - 50.0% 34 4 Gas Distribution Noverco Common Shares 38.9 % — — Other 4 50.0 % 15 — Green Power and Transmission Eolien Maritime France SAS 6 50.0 % 69 58 Hohe See Offshore Wind Project 7 50.0 % 763 — Rampion Offshore Wind Project 24.9 % 555 345 Other 19.0% - 50.0% 95 100 Eliminations and Other Other 19.0% - 42.7% 26 15 OTHER LONG-TERM INVESTMENTS Gas Distribution Noverco Preferred Shares 371 355 Green Power and Transmission Emerging Technologies and Other 80 90 Eliminations and Other Other 67 79 16,644 6,836 1 On February 15, 2017 , EEP acquired an effective 27.6% interest in the Dakota Access and Energy Transfer Crude Oil Pipelines (collectively, the Bakken Pipeline System) for a purchase price of $ 2 billion (US$ 1.5 billion ). The Bakken Pipeline System was placed into service on June 1, 2017 . For details regarding our funding arrangement, refer to Note 19 - Noncontrolling Interests . 2 Owns the Southern Access Extension Project. 3 Certain assets of the Alliance Pipeline are pledged as collateral to Alliance Pipeline lenders. 4 On February 27, 2017, we acquired Spectra Energy's interests in DCP Midstream, Gulfstream Natural Gas System, L.L.C, Nexus, PennEast, Southeast Supply Header L.L.C., Steckman Ridge LP and other equity investments as part of the Merger Transaction (Note 7) . 5 On February 27, 2017, we acquired Spectra Energy's consolidated interest in Sabal Trail as part of the Merger Transaction (Note 7) . On July 3, 2017, Sabal Trail was placed into service and the assets, liabilities, and noncontrolling interests were deconsolidated as at the in-service date. 6 On May 19, 2016, we acquired a 50% equity interest in Eolien Maritime France SAS. 7 On February 8, 2017 , we acquired an effective 50% interest in EnBW Hohe See GmbH & Co. KG. Equity investments include the unamortized excess of the purchase price over the underlying net book value of the investees’ assets at the purchase date. As at December 31, 2017 , this comprised of $2.0 billion in Goodwill and $643 million in amortizable assets. As at December 31, 2016 , this comprised of $859 million in Goodwill and $687 million in amortizable assets. For the years ended December 31, 2017 , 2016 and 2015 , dividends received from equity investments were $1.4 billion , $825 million and $719 million , respectively. Summarized combined financial information of our interest in unconsolidated equity investments (presented at 100%) is as follows: Year Ended December 31, 2017 2016 2015 Seaway Other Total Seaway Other Total Seaway Other Total (millions of Canadian dollars) Operating revenues 959 15,254 16,213 938 3,164 4,102 833 3,054 3,887 Operating expenses 286 12,911 13,197 293 3,051 3,344 263 2,210 2,473 Earnings 672 2,056 2,728 643 (2 ) 641 566 512 1,078 Earnings attributable to controlling interests 336 926 1,262 322 147 469 283 207 490 December 31, 2017 December 31, 2016 Seaway Other Total Seaway Other Total (millions of Canadian dollars) Current assets 106 3,432 3,538 86 842 928 Non-current assets 3,329 41,697 45,026 3,651 12,264 15,915 Current liabilities 143 3,311 3,454 172 831 1,003 Non-current liabilities 13 13,582 13,595 13 5,121 5,134 Noncontrolling interests — 3,191 3,191 — — — Eddystone Rail Company, LLC On October 19, 2017, we sold all assets related to Eddystone Rail Company, LLC (Eddystone Rail) in exchange for the remaining 25% interest of the joint venture. As a result, Eddystone Rail is now 100% owned and carried at nil value. During the year ended December 31, 2016 , we recorded an investment impairment of $184 million related to our 75% joint venture interest in Eddystone Rail at the time, which is held through Enbridge Rail (Philadelphia) L.L.C., a wholly-owned subsidiary. Eddystone Rail is a rail-to-barge transloading facility located in the greater Philadelphia, Pennsylvania area that delivers Bakken and other light sweet crude oil to Philadelphia area refineries. Due to a significant decrease in price spreads between Bakken crude oil and West Africa/Brent crude oil and increased competition in the region, demand for Eddystone Rail services dropped significantly, which led to the completion of an impairment test. The impairment charge is presented within Income from equity investments on the Consolidated Statements of Earnings. The investment in Eddystone Rail is a part of our Liquids Pipelines segment. The impairment charge was based on the amount by which the carrying value of the asset exceeded fair value, determined using an adjusted net worth approach. Our estimate of fair value required us to use significant unobservable inputs representative of a Level 3 fair value measurement, including assumptions related to the future performance of Eddystone Rail. Aux Sable During the year ended December 31, 2016, Aux Sable recorded an asset impairment charge of $37 million related to certain underutilized assets at Aux Sable US' NGL extraction and fractionation plant. Sabal Trail Transmission, LLC On July 3, 2017 , Sabal Trail was placed into service. In accordance with the Sabal Trail LLC Agreement, upon the in-service date, the power to direct Sabal Trail’s activities become shared with its members. We are no longer the primary beneficiary and deconsolidated the assets, liabilities and noncontrolling interests related to Sabal Trail as at the in-service date. At deconsolidation, our 50% interest in Sabal Trail was recorded at its fair value of $ 2.3 billion (US$ 1.9 billion ), which approximated its carrying value as a long-term equity investment. As a result, there was no gain or loss recognized for the year ended December 31, 2017 related to the remeasurement of the retained equity interest to its fair value. The fair value was determined using the income approach which is based on the present value of the future cash flows. Noverco Inc. As at December 31, 2017 and 2016, we owned an equity interest in Noverco through ownership of 38.9% of its common shares and an investment in preferred shares. The preferred shares are entitled to a cumulative preferred dividend based on the average yield of Government of Canada bonds maturing in 10 years plus a margin of 4.38% . As at December 31, 2017 and 2016, Noverco owned an approximate 1.9% and 3.4% reciprocal shareholding in our common shares, respectively. Through secondary offerings, Noverco purchased 1.2 million common shares in February 2016. Shares purchased and sold in this transaction were treated as treasury stock on the Consolidated Statements of Changes in Equity. As a result of Noverco’s reciprocal shareholding in our common shares, as at December 31, 2017 and 2016, we had an indirect pro-rata interest of 0.7% and 1.3% , respectively, in our own shares. Both the equity investment in Noverco and shareholders’ equity have been reduced by the reciprocal shareholding of $ 102 million as at December 31, 2017 and 2016 . Noverco records dividends paid from us as dividend income and we eliminate these dividends from our equity earnings of Noverco. We record our pro-rata share of dividends paid by us to Noverco as a reduction of dividends paid and an increase in our investment in Noverco.

RESTRICTED LONG-TERM INVESTMENT

RESTRICTED LONG-TERM INVESTMENTS	12 Months Ended
	Dec. 31, 2017
Assets Held-in-trust [Abstract]
RESTRICTED LONG-TERM INVESTMENTS	RESTRICTED LONG-TERM INVESTMENTS Effective January 1, 2015, we began collecting and setting aside funds to cover future pipeline abandonment costs for all NEB regulated pipelines as a result of the NEB’s regulatory requirements under LMCI. The funds collected are held in trusts in accordance with the NEB decision. The funds collected from shippers are reported within Transportation and other services revenues on the Consolidated Statements of Earnings and Restricted long-term investments on the Consolidated Statements of Financial Position. Concurrently, we reflect the future abandonment cost as an increase to Operating and administrative expense on the Consolidated Statements of Earnings and Other long-term liabilities on the Consolidated Statements of Financial Position. We routinely invest excess cash and various restricted balances in securities such as commercial paper, bankers acceptances, corporate debt securities, Canadian equity securities, treasury bills and money market securities in the United States and Canada. As at December 31, 2017 and 2016 , we had restricted long-term investments held in trust and classified as held for sale and carried at fair value of $267 million and $90 million , respectively. We had estimated future abandonment costs related to LMCI of $151 million and $97 million as at December 31, 2017 and 2016 , respectively.

INTANGIBLE ASSETS

INTANGIBLE ASSETS	12 Months Ended
	Dec. 31, 2017
Intangible Assets, Net (Excluding Goodwill) [Abstract]
INTANGIBLE ASSETS	INTANGIBLE ASSETS The following table provides the weighted average amortization rate, gross carrying value, accumulated amortization and net carrying value for each of our major classes of intangible assets: Weighted Average Accumulated December 31, 2017 1 Amortization Rate Cost Amortization Net (millions of Canadian dollars) Customer relationships 3.5 % 967 41 926 Power purchase agreements 3.5 % 99 17 82 Project agreement 2 4.0 % 150 3 147 Software 11.3 % 1,760 714 1,046 Other intangible assets 3 4.4 % 1,162 96 1,066 4,138 871 3,267 1 Certain assets were reclassified as held for sale as at December 31, 2017 (Note 7) . 2 Represents a project agreement acquired from the Merger Transaction (Note 7) . 3 The measurement of weighted average amortization rate excludes non-depreciable intangible assets. Weighted Average Accumulated December 31, 2016 Amortization Rate Cost Amortization Net (millions of Canadian dollars) Customer relationships 3.0 % 251 4 247 Natural gas supply opportunities 3.2 % 435 127 308 Power purchase agreements 3.2 % 100 14 86 Software 11.8 % 1,388 607 781 Other intangible assets 4.8 % 213 62 151 2,387 814 1,573 For the years ended December 31, 2017 , 2016 and 2015 , our amortization expense related to intangible assets totaled $280 million , $177 million and $158 million , respectively. The following table presents our forecast of amortization expense associated with existing intangible assets for the years indicated as follows in millions of Canadian dollars: 2018 2019 2020 2021 2022 264 240 217 197 179

GOODWILL

GOODWILL	12 Months Ended
	Dec. 31, 2017
Goodwill and Intangible Assets Disclosure [Abstract]
GOODWILL	GOODWILL Liquids Pipelines Gas Gas Green Power and Transmission Energy Services Eliminations and Other Consolidated (millions of Canadian dollars) Gross Cost Balance at January 1, 2016 60 458 7 — 2 13 540 Foreign exchange and other (1 ) (1 ) — — — — (2 ) Balance at December 31, 2016 59 457 7 — 2 13 538 Acquired in Merger Transaction (Note 7) 8,070 22,914 5,672 — — — 36,656 Sabal Trail deconsolidation (Note 12) — (966 ) (966 ) Disposition (29 ) — — — — — (29 ) Foreign exchange and other (314 ) (866 ) — — — — (1,180 ) Balance at December 31, 2017 7,786 21,539 5,679 — 2 13 35,019 Accumulated Impairment Balance at January 1, 2016 — (440 ) (7 ) — — (13 ) (460 ) Impairment — — — — — — — Balance at December 31, 2016 — (440 ) (7 ) — — (13 ) (460 ) Impairment — (102 ) — — — — (102 ) Balance at December 31, 2017 — (542 ) (7 ) — — (13 ) (562 ) Carrying Value Balance at December 31, 2016 59 17 — — 2 — 78 Balance at December 31, 2017 7,786 20,997 5,672 — 2 — 34,457 ACQUISITION AND DISPOSITION In 2017, we recognized $36.7 billion of goodwill on the Merger Transaction and derecognized $29 million of goodwill on the disposition of Olympic Pipeline. IMPAIRMENT Gas Transmission and Midstream US Midstream During the year ended December 31, 2017, we recorded a goodwill impairment charge of $102 million related to certain assets in our Gas Transmission and Midstream segment classified as held for sale (Note 7) . Goodwill was allocated to certain disposal groups qualifying as a business based on a relative fair value approach. In connection with the write-down of the carrying values of the assets held for sale to its fair value less costs to sell, the related goodwill was impaired. The fair value of these assets were estimated using the discounted cash flow method, which was negatively impacted by prolonged decline in commodity prices and deteriorating business performance. We also performed goodwill impairment testing on the associated gas midstream reporting unit resulting in no additional impairment charge. The estimate of the gas midstream reporting unit’s fair value required the use of significant unobservable inputs representative of a Level 3 fair value measurement, including assumptions related to the future performance of the reporting unit. Enbridge Energy Partners, L.P. During the year ended December 31, 2015, we recorded a goodwill impairment loss of $440 million ( $167 million after-tax attributable to us) related to EEP’s natural gas and NGL businesses, which EEP held directly and indirectly through its partially-owned subsidiary, MEP. Due to a prolonged decline in commodity prices, reduction in producers’ expected drilling programs negatively impacted forecasted cash flows from EEP’s natural gas and NGL systems. This change in circumstance led to the completion of an impairment test, resulting in a full impairment of goodwill on EEP’s natural gas and NGL businesses. In performing the impairment assessment, EEP measured the fair value of its reporting units primarily by using a discounted cash flow analysis and it also considered overall market capitalization of its business, cash flow measurement data and other factors. EEP’s estimate of fair value required it to use significant unobservable inputs representative of a Level 3 fair value measurement, including assumptions related to the future performance of its reporting units.

ACCOUNTS PAYABLE AND OTHER

ACCOUNTS PAYABLE AND OTHER	12 Months Ended
	Dec. 31, 2017
Payables and Accruals [Abstract]
ACCOUNTS PAYABLE AND OTHER	ACCOUNTS PAYABLE AND OTHER December 31, 2017 2016 (millions of Canadian dollars) Trade payables and operating accrued liabilities 5,135 3,718 Construction payables and contractor holdbacks 706 712 Current derivative liabilities 1,130 1,941 Dividends payable 1,169 29 Other 1,338 895 9,478 7,295

DEBT

DEBT	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
DEBT	DEBT Weighted Average December 31, Interest Rate Maturity 2017 2016 (millions of Canadian dollars) Enbridge Inc. United States dollar term notes 1 4.1 % 2022-2046 5,889 4,968 Medium-term notes 4.4 % 2019-2064 5,698 4,498 Fixed-to-floating subordinated term notes 2,3 5.6 % 2077 3,843 1,007 Floating rate notes 4 2019-2020 2,254 1,171 Commercial paper and credit facility draws 5 2.3 % 2019-2022 2,729 4,672 Other 6 3 4 Enbridge (U.S.) Inc. Medium-term notes 7 — 14 Commercial paper and credit facility draws 8 2.1 % 2019 490 126 Enbridge Energy Partners, L.P. Senior notes 9 6.2 % 2018-2045 6,328 6,781 Junior subordinated notes 10 2067 501 537 Commercial paper and credit facility draws 11 2.3 % 2019-2022 1,820 2,226 Enbridge Gas Distribution Inc. Medium-term notes 4.5 % 2020-2050 3,695 3,904 Debentures 9.9 % 2024 85 85 Commercial paper and credit facility draws 1.4 % 2019 960 351 Enbridge Income Fund Medium-term notes 4.3 % 2018-2044 1,750 2,075 Commercial paper and credit facility draws 2.9 % 2020 755 225 Enbridge Pipelines (Southern Lights) L.L.C. Senior notes 12 4.0 % 2040 1,207 1,342 Enbridge Pipelines Inc. Medium-term notes 13 4.5 % 2018-2046 4,525 4,525 Debentures 8.2 % 2024 200 200 Commercial paper and credit facility draws 14 1.5 % 2019 1,438 1,032 Other 6 4 4 Enbridge Southern Lights LP Senior notes 4.0 % 2040 315 323 Midcoast Energy Partners, L.P. Senior notes 15 4.1 % 2019-2024 501 537 Commercial paper and credit facility draws 16 — 564 Spectra Energy Capital 17 Senior notes 18 5.3 % 2018-2038 1,665 — Spectra Energy Partners, LP 17 Senior secured notes 19 6.1 % 2020 138 — Senior notes 20 2.7 % 2018-2045 7,192 — Floating rate notes 21 2020 501 — Commercial paper and credit facility draws 22 2.0 % 2022 2,824 — Union Gas Limited 17 Medium-term notes 4.2 % 2018-2047 3,490 — Senior debentures 8.7 % 2018 75 — Debentures 8.7 % 2018-2025 250 — Commercial paper and credit facility draws 1.3 % 2021 485 — Westcoast Energy Inc. 17 Senior secured notes 6.4 % 2019 66 — Medium-term notes 4.7 % 2019-2041 2,177 — Debentures 8.6 % 2018-2026 525 — Fair value adjustment - Spectra Energy acquisition 1,114 — Other 23 (312 ) (226 ) Total debt 65,180 40,945 Current maturities (2,871 ) (4,100 ) Short-term borrowings 24 (1,444 ) (351 ) Long-term debt 60,865 36,494 1 2017 - US $4,700 million ; 2016 - US $3,700 million . 2 2017 - $1,650 million and US $1,750 million ; 2016 - US $750 million . For the initial 10 years , the notes carry a fixed interest rate. Subsequently, the interest rate will be floating and set to equal the three-month Bankers' Acceptance Rate or London Interbank Offered Rate (LIBOR) plus a margin. 3 The notes would be converted automatically into Conversion Preference Shares in the event of bankruptcy and related events. 4 2017 - $750 million and US $1,200 million ; 2016 - $500 million and US $500 million . Carries an interest rate equal to the three-month Bankers' Acceptance Rate plus a margin of 59 basis points or LIBOR plus a margin of 40 or 70 basis points. 5 2017 - $1,593 million and US $907 million ; 2016 - $3,600 million and US $799 million . 6 Primarily capital lease obligations. 7 2016 - US $10 million . 8 2017 - US $391 million ; 2016 - US $94 million . 9 2017 - US $5,050 million ; 2016 - US $5,050 million . 10 2017 - US $400 million ; 2016 - US $400 million . Carries an interest rate equal to the three-month LIBOR plus a margin of 379.75 basis points. 11 2017 - US $1,453 million ; 2016 - US $1,658 million . 12 2017 - US $963 million ; 2016 - US $1,000 million . 13 Included in medium-term notes is $100 million with a maturity date of 2112. 14 2017 - $1,080 million and US $286 million ; 2016 - $750 million and US $210 million . 15 2017 - US $400 million ; 2016 - US $400 million . 16 2016 - US $420 million . 17 Debt acquired on February 27, 2017 in conjunction with the Merger Transaction (Note 7) . 18 2017 - US $1,329 million . 19 2017 - US $110 million . 20 2017 - US $5,740 million . 21 2017 - US $400 million . Carries an interest rate equal to the three-month LIBOR plus a margin of 70 basis points. 22 2017 - US $2,254 million . 23 Primarily debt discount and debt issue costs. 24 Weighted average interest rate - 1.4% ; 2016 - 0.8% . SECURED DEBT Senior secured notes, totaling $206 million as at December 31, 2017, includes project financings for M&N Canada and Express-Platte System. Ownership interests in M&N Canada and certain of its accounts, revenues, business contracts and other assets are pledged as collateral. Express-Platte System notes payable are secured by the assignment of the Express-Platte System transportation receivables and by the Canadian portion of the Express-Platte pipeline system assets. CREDIT FACILITIES The following table provides details of our committed credit facilities at December 31, 2017 : 2017 Total December 31, Maturity Facilities Draws 1 Available (millions of Canadian dollars) Enbridge Inc. 2 2019-2022 7,353 2,737 4,616 Enbridge (U.S.) Inc. 2019 3,590 490 3,100 Enbridge Energy Partners, L.P. 3 2019-2022 3,289 1,820 1,469 Enbridge Gas Distribution Inc. 2019 1,016 972 44 Enbridge Income Fund 2020 1,500 766 734 Enbridge Pipelines (Southern Lights) L.L.C. 2019 25 — 25 Enbridge Pipelines Inc. 2019 3,000 1,438 1,562 Enbridge Southern Lights LP 2019 5 — 5 Spectra Energy Partners, LP 4,5 2022 3,133 2,824 309 Union Gas Limited 5 2021 700 485 215 Westcoast Energy Inc. 5 2021 400 — 400 Total committed credit facilities 24,011 11,532 12,479 1 Includes facility draws, letters of credit and commercial paper issuances that are back-stopped by the credit facility. 2 Includes $135 million, $157 million (US$125 million) and $150 million of commitments that expire in 2018, 2018 and 2020, respectively. 3 Includes $219 million (US$175 million) and $232 million (US$185 million) of commitments that expire in 2018 and 2020, respectively. 4 Includes $421 million (US$336 million) of commitments that expire in 2021. 5 Committed credit facilities acquired on February 27, 2017 in conjunction with the Merger Transaction (Note 7) . During the first quarter of 2017, Enbridge established a five -year, term credit facility for $239 million (¥ 20,000 million ) with a syndicate of Japanese banks. In addition to the committed credit facilities noted above, we have $792 million of uncommitted demand credit facilities, of which $518 million were unutilized as at December 31, 2017 . As at December 31, 2016 , we had $335 million of uncommitted credit facilities, of which $177 million were unutilized. Credit facilities carry a weighted average standby fee of 0.2% per annum on the unused portion and draws bear interest at market rates. Certain credit facilities serve as a back-stop to the commercial paper programs and we have the option to extend such facilities, which are currently set to mature from 2019 to 2022 . As at December 31, 2017 and 2016 , commercial paper and credit facility draws, net of short-term borrowings and non-revolving credit facilities that mature within one year of $10,055 million and $7,344 million , respectively, are supported by the availability of long-term committed credit facilities and therefore have been classified as long-term debt. LONG-TERM DEBT ISSUANCES The following are long-term debt issuances made during 2017 and 2016: Company Issue Date Principal Amount (millions of Canadian dollars unless otherwise stated) Enbridge Inc. May 2017 Floating rate notes due May 2019 1 750 June 2017 3.19% medium-term notes due December 2022 450 June 2017 3.20% medium-term notes due June 2027 450 June 2017 4.57% medium-term notes due March 2044 300 June 2017 Floating rate notes due June 2020 2 US$500 July 2017 2.90% senior notes due July 2022 US$700 July 2017 3.70% senior notes due July 2027 US$700 July 2017 Fixed-to-floating rate subordinated notes due July 2077 3 US$1,000 September 2017 Fixed-to-floating rate subordinated notes due September 2077 4 1,000 October 2017 Fixed-to-floating rate subordinated notes due September 2077 4 650 October 2017 Floating rate notes due January 2020 5 US$700 November 2016 4.25% medium-term notes due December 2026 US$750 November 2016 5.50% medium-term notes due December 2046 US$750 December 2016 Fixed-to-floating rate subordinated notes due January 2077 6 US$750 Enbridge Gas Distribution Inc. November 2017 3.51% medium-term notes due November 2047 300 August 2016 2.50% medium-term notes due August 2026 300 Enbridge Pipelines Inc. August 2016 3.00% medium-term notes due August 2026 400 August 2016 4.13% medium-term notes due August 2046 400 Spectra Energy Partners, LP June 2017 Floating rate notes due June 2020 7 US$400 Union Gas Limited November 2017 2.88% medium-term notes due November 2027 250 November 2017 3.59% medium-term notes due November 2047 250 1 Carries an interest rate equal to the three-month Bankers' Acceptance Rate plus 59 basis points. 2 Carries an interest rate equal to the three-month LIBOR plus 70 basis points. 3 Matures in 60 years and are callable on or after year 10 . For the initial 10 years , the notes carry a fixed interest rate of 5.5% . Subsequently, the interest rate will be set to equal the three-month LIBOR plus a margin of 342 basis points from year 10 to 30 , and a margin of 417 basis points from year 30 to 60 . 4 Matures in 60 years and are callable on or after year 10 . For the initial 10 years , the notes carry a fixed interest rate of 5.4% . Subsequently, the interest rate will be set to equal the three-month Bankers' Acceptance Rate plus a margin of 325 basis points from year 10 to 30 , and a margin of 400 basis points from year 30 to 60 . 5 Carries an interest rate equal to the three-month LIBOR plus 40 basis points. 6 Matures in 60 years and are callable on or after year 10 . For the initial 10 years , the notes carry a fixed interest rate of 6.0% . Subsequently, the interest rate will be set to equal the three-month LIBOR plus a margin of 389 basis points from year 10 to 30 , and a margin of 464 basis points from year 30 to 60 . 7 Carries an interest rate equal to the three-month LIBOR plus 70 basis points. LONG-TERM DEBT REPAYMENTS The following are long-term debt repayments during 2017 and 2016: Company Retirement/Repayment Date Principal Amount (millions of Canadian dollars unless otherwise stated) Enbridge Inc. March 2017 Floating rate note 500 April 2017 5.60% medium-term notes US$400 June 2017 Floating rate note US$500 May 2016 5.17% medium-term notes 400 August 2016 5.00% medium-term notes 300 October 2016 Floating rate note US$350 Enbridge Energy Partners, L.P. December 2016 5.88% senior notes US$300 Enbridge Gas Distribution Inc. April 2017 1.85% medium-term notes 300 December 2017 5.16% medium-term notes 200 Enbridge Income Fund June 2017 5.00% medium-term notes 100 December 2017 2.92% medium-term notes 225 November 2016 Floating rate note 330 Enbridge Pipelines (Southern Lights) L.L.C. June and December 2017 3.98% medium-term note due June 2040 US$37 June and December 2016 3.98% medium-term note due June 2040 US$30 Enbridge Southern Lights LP June 2017 4.01% medium-term note due June 2040 7 June and December 2016 4.01% medium-term note due June 2040 14 Spectra Energy Capitals, LLC July and September 2017 1,3 8.00% senior notes due 2019 US$500 July 2017 2,3 Senior notes carrying interest ranging from 3.3% to 7.5% due 2018 to 2038 US$761 Spectra Energy Partners, LP September 2017 6.00% senior notes US$400 June and December 2017 7.39% subordinated secured notes US$12 Union Gas Limited November 2017 9.70% debentures 125 Westcoast Energy Inc. May and November 2017 6.90% senior secured notes 26 May and November 2017 4.34% senior secured notes 24 1 On July 7, 2017 and September 8, 2017, Enbridge and Spectra Energy Capital, LLC (Spectra Capital) completed a cash tender offer for and follow-up redemption of Spectra Capital’s outstanding 8.0% senior unsecured notes due 2019 . The aggregate principal amount tendered and redeemed was US $500 million . Spectra Capital paid the consenting note holders an aggregate cash consideration of US $581 million . 2 On July 13, 2017, pursuant to a cash tender offer, Spectra Capital purchased a portion of the principal amount of its outstanding senior unsecured notes carrying interest rates ranging from 3.3% to 7.5% , with maturities ranging from one to 21 years. The principal amount tendered and accepted was US $761 million . Spectra Capital paid the consenting note holders an aggregate cash consideration of US $857 million . 3 The loss on debt extinguishment of $50 million (US $38 million ), net of the fair value adjustment recorded upon completion of the Merger Transaction, was reported within Interest expense in the Consolidated Statements of Earnings. DEBT COVENANTS Our credit facility agreements and term debt indentures include standard events of default and covenant provisions whereby accelerated repayment and/or termination of the agreements may result if we were to default on payment or violate certain covenants. As at December 31, 2017 , we were in compliance with all debt covenants. INTEREST EXPENSE Year ended December 31, 2017 2016 2015 (millions of Canadian dollars) Debentures and term notes 3,011 1,714 1,805 Commercial paper and credit facility draws 206 197 172 Amortization of fair value adjustment - Spectra Energy acquisition (270 ) — — Capitalized (391 ) (321 ) (353 ) 2,556 1,590 1,624

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS	12 Months Ended
	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
ASSET RETIREMENT OBLIGATIONS	ASSET RETIREMENT OBLIGATIONS Our AROs relate mostly to the retirement of pipelines, renewable power generation assets, obligations related to right-of way agreements and contractual leases for land use. A reconciliation of movements in our ARO liabilities is as follows: December 31, 2017 2016 (millions of Canadian dollars) Obligations at beginning of year 232 198 Liabilities acquired 546 — Liabilities incurred — 2 Liabilities settled (22 ) (33 ) Change in estimate 18 63 Foreign currency translation adjustment (12 ) (5 ) Accretion expense 31 7 Obligations at end of year 793 232 Presented as follows: Accounts payable and other 2 2 Other long-term liabilities 791 230 793 232

NONCONTROLLING INTERESTS

NONCONTROLLING INTERESTS	12 Months Ended
	Dec. 31, 2017
Noncontrolling Interest [Abstract]
NONCONTROLLING INTERESTS	NONCONTROLLING INTERESTS NONCONTROLLING INTERESTS The following table provides additional information regarding Noncontrolling interests as presented in our Consolidated Statements of Financial Position: December 31, 2017 2016 (millions of Canadian dollars) Enbridge Energy Management, L.L.C. 1 34 36 Enbridge Energy Partners, L.P. 2 157 (99 ) Enbridge Gas Distribution Inc. 3 100 100 Renewable energy assets 4 806 516 Spectra Energy Partners, LP 5,8 5,385 — Union Gas Limited 6,8 110 — Westcoast Energy Inc. 7,8 1,005 — Other — 24 7,597 577 1 Represents the 88.3% of the listed shares of Enbridge Energy Management, L.L.C. (EEM) not held by us as at December 31, 2017 and 2016 . 2 Represents the 68.2% and 80.2% interest in EEP held by public unitholders as well as interests of third parties in subsidiaries of EEP as at December 31, 2017 and 2016 , respectively. 3 Represents the four million cumulative redeemable preferred shares held by third parties in EGD as at December 31, 2017 and 2016 . 4 Represents the tax equity investors' interests in our Magic Valley, Wildcat, Keechi, New Creek and Chapman Ranch wind farms, which are accounted for using the HLBV method, with an additional 20.0% noncontrolling interest in each of the Magic Valley and Wildcat wind farms held by third parties as at December 31, 2017 and 2016 . 5 Represents the 25.7% interest in SEP held by public unitholders as at December 31, 2017 . 6 Represents the four million cumulative redeemable preferred shares held by third parties in Union Gas as at December 31, 2017 . 7 Represents the 16.6 million cumulative redeemable preferred shares and 12 million cumulative first preferred shares as at December 31, 2017 held by third parties in Westcoast Energy Inc., and the 22.0% interest in Maritimes & Northeast Pipeline Limited Partnership held by third parties. 8 Represents noncontrolling interests resulting from the Merger Transaction (Note 7) . Enbridge Energy Partners, L.P. United States Sponsored Vehicle Strategy On April 28, 2017, we completed a strategic review of EEP and took the actions described below. As a result of these actions, we recorded an increase in Noncontrolling interests of $458 million , inclusive of foreign currency translation adjustments, and a decrease in Additional paid-in capital of $421 million , net of deferred income taxes of $253 million . Acquisition of Midcoast Assets and Privatization of Midcoast Energy Partners, L.P. On April 27, 2017, we completed our previously-announced merger through a wholly-owned subsidiary, through which we privatized MEP by acquiring all of the outstanding publicly-held common units of MEP for total consideration of approximately US $170 million . On June 28, 2017, we acquired, through a wholly-owned subsidiary, all of EEP’s interest in the Midcoast gas gathering and processing business for cash consideration of US $1.3 billion plus existing indebtedness of MEP of US $953 million . As a result of the above transactions, 100% of the Midcoast gas gathering and processing business is now owned by us. EEP Strategic Restructuring Actions On April 27, 2017, EEP redeemed all of its outstanding Series 1 Preferred Units held by us at face value of US $1.2 billion through the issuance of 64.3 million Class A common units to us. We also irrevocably waived all of our rights associated with our ownership of 66.1 million Class D units and 1,000 Incentive Distribution Units of EEP, in exchange for the issuance of 1,000 Class F units. The Class F units are entitled to (i) 13% of all distributions in excess of US $0.295 per EEP unit, but equal to or less than US $0.35 per EEP unit, and (ii) 23% of all distributions in excess of US $0.35 per EEP unit. The irrevocable waiver was effective with respect to distributions declared with a record date after April 27, 2017. In connection with these strategic restructuring actions, EEP reduced its quarterly distribution from US $0.583 per unit to US $0.35 per unit. Further, in conjunction with the restructuring actions, EEP terminated a receivable purchase agreement with a special purpose entity wholly-owned by us. Finalization of Bakken Pipeline System Joint Funding Agreement On April 27, 2017, we entered into a joint funding arrangement with EEP. Pursuant to this joint funding arrangement, we own 75% and EEP owns 25% of the combined 27.6% effective interest in the Bakken Pipeline System. Under this arrangement, EEP retains a five -year option to acquire an additional 20% interest in the Bakken Pipeline System. Upon the execution of the joint funding arrangement, EEP repaid the outstanding balance on its US $1.5 billion credit agreement with us, which it had drawn upon to fund the initial purchase. Drop Down of Interest to Enbridge Energy Partners, L.P. On January 2, 2015, we transferred our 66.7% interest in the United States segment of the Alberta Clipper pipeline, held through a wholly-owned subsidiary, to EEP for aggregate consideration of $1.1 billion (US $1 billion ), consisting of approximately $814 million (US $694 million ) of Class E equity units issued to us by EEP and the repayment of approximately $359 million (US $306 million ) of indebtedness owed to us. Prior to the transfer, EEP owned the remaining 33.3% interest in the United States segment of the Alberta Clipper pipeline. As a result of this transfer, we recorded a decrease in Noncontrolling interests of $304 million and increases in Additional paid-in capital and Deferred income tax liabilities of $218 million and $86 million , respectively. Other The EEP 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 other limited partners and the General Partner, generally on a pro-rata basis. Further, as outlined in the EEP partnership agreement, when a limited partner's capital accounts have positive capital balances, such limited partner must allocate its earnings to the General Partner of EEP to reimburse them for previous curing allocations. As a result, earnings attributable to noncontrolling interests in the Consolidated Statements of Earnings for the years ended December 31, 2017 and 2016 were lower by $73 million and higher by $816 million , respectively, due to these reallocations. On March 13, 2015, EEP completed a public common unit issuance. We participated only to the extent to maintain our 2% general partner interest. The common unit issuance resulted in contributions of $366 million (US $289 million ) from noncontrolling interest holders. REDEEMABLE NONCONTROLLING INTERESTS The following table presents additional information regarding Redeemable noncontrolling interests as presented in our Consolidated Statements of Financial Position: Year ended December 31, 2017 2016 2015 (millions of Canadian dollars) Balance at beginning of year 3,392 2,141 2,249 Earnings/(loss) attributable to redeemable noncontrolling interests 175 268 (3 ) Other comprehensive income/(loss), net of tax Change in unrealized loss on cash flow hedges (21 ) (17 ) (7 ) Other comprehensive loss from equity investees — — (12 ) Reclassification to earnings of loss on cash flow hedges 57 9 4 Foreign currency translation adjustments (6 ) (3 ) 18 Other comprehensive income/(loss), net of tax 30 (11 ) 3 Distributions to unitholders (247 ) (202 ) (114 ) Contributions from unitholders 1,178 591 670 Reversal of cumulative redemption value adjustment attributable to ECT preferred units — — (541 ) Net dilution loss (169 ) (81 ) (482 ) Redemption value adjustment (292 ) 686 359 Balance at end of year 4,067 3,392 2,141 Redeemable noncontrolling interests in the Fund as at December 31, 2017 , 2016 and 2015 represented 56.5% , 45.6% and 40.7% , respectively, of interests in the Fund’s trust units that are held by third parties. Common Share Issuances During the years ended December 31, 2017 , 2016 and 2015 , the following occurred: Year ended December 31, 2017 2016 2015 (millions of Canadian dollars) ENF issuance of common shares 1 : Gross proceeds from the public 575 575 700 Gross proceeds from us 2 143 143 174 ENF purchase of Fund trust units 1,3 : Contributions from redeemable noncontrolling interest holders, net of share issue costs 552 551 670 Dilution gain/(loss) for redeemable noncontrolling interests 5 (4 ) (355 ) Dilution gain/(loss) in Additional paid-in capital (5 ) 4 355 ECT purchase of EIPLP Class A units 1,4 : Proceeds used by ECT to purchase EIPLP Class A units 718 718 874 Dilution loss for redeemable noncontrolling interests (123 ) (103 ) (132 ) Dilution gain in Additional paid-in capital 123 103 132 ENF purchase of Fund trust units 5 : Contributions from redeemable noncontrolling interest holders 51 40 — Dilution gain/(loss) for redeemable noncontrolling interests (5 ) (4 ) — Dilution gain/(loss) in Additional paid-in capital 5 4 — 1 These transactions occurred in December 2017, April 2016 and November 2015. 2 Concurrent with the public offerings, we subscribed for ENF common shares on a private placement basis to maintain our 19.9% ownership interest in ENF. 3 ENF used the proceeds from the common share issuances to purchase additional trust units of the Fund. We did not participate in these offerings, resulting in increases in redeemable noncontrolling interests ( 2017 - 53.6% to 56.5% ; 2016 - 40.7% to 45.6% ; 2015 - 34.3% to 40.7% ). 4 The Fund used a portion of the proceeds from the trust unit issuances to purchase additional common units of ECT, and ECT used the proceeds to purchase additional Class A units of EIPLP, resulting in dilution losses for ECT. These dilution losses resulted in dilution losses for the Fund’s equity investment in ECT and the above-noted dilution gains/(losses) for redeemable noncontrolling interests and Additional paid-in capital. 5 For the years ended December 31, 2017, 2016 and 2015, ENF used cash in respect of reinvested dividends and option cash payments from its Dividend Reinvestment Plan (DRIP) to purchase 1.6 million , 1.3 million and nil Fund trust units, respectively, on behalf of the public. Further to the above, in April 2017, Enbridge and ENF completed the secondary public offering of ENF common shares for gross proceeds of $575 million (the Secondary Offering). To effect the Secondary Offering, we exchanged 21,657,617 Fund units we owned for an equivalent amount of ENF common shares. In order to maintain our 19.9% interest in ENF, we retained 4,309,867 of the common shares we received in the exchange, and sold the balance through the Secondary Offering. Upon closing of the Secondary Offering, our total economic interest in ENF decreased from 86.9% to 84.6% and redeemable noncontrolling interests increased from 45.6% to 53.7% . As a result of the Secondary Offering, we recorded a dilution loss for redeemable noncontrolling interests of $87 million and a dilution gain in Additional paid-in capital of $87 million . Canadian Restructuring Plan In September 2015, our unitholdings in the Fund increased upon closing of the Canadian Restructuring Plan (Note 1) , resulting in a decrease in redeemable noncontrolling interests. Upon closing of the Canadian Restructuring Plan, ECT, an equity investment of the Fund, reclassified its Preferred Units from mezzanine equity to liabilities. Accordingly, ECT reduced the recorded redemption value of its Preferred Units to their aggregate par value, resulting in an increase to the Fund’s equity investment in ECT. This resulted in an adjustment to redeemable noncontrolling interests of approximately $541 million . Upon closing of the Canadian Restructuring Plan, EIPLP, an indirect equity investment of the Fund, issued Special Interest Rights to us which are entitled to Temporary Performance Distribution Rights (TPDR) distributions. TPDR distributions occur when the Fund distribution rate exceeds a payout target and are paid in the form of Class D units. The Class D unitholders receive a distribution each month equal to the per unit amount paid on Class C units of EIPLP, but to be paid in kind in additional Class D units. The issuances of TPDR and additional Class D units resulted in a dilution gain for the Fund’s indirect equity investment in EIPLP, a dilution gain for redeemable noncontrolling interests of $41 million , $30 million and $5 million for the years ended December 31, 2017 , 2016 and 2015 , respectively, with offsetting dilution losses in Additional paid-in capital.

SHARE CAPITAL

SHARE CAPITAL	12 Months Ended
	Dec. 31, 2017
Equity [Abstract]
SHARE CAPITAL	SHARE CAPITAL Our authorized share capital consists of an unlimited number of common shares with no par value and an unlimited number of preference shares. COMMON SHARES 2017 2016 2015 Number Number Number December 31, of Shares Amount of Shares Amount of Shares Amount (millions of Canadian dollars; number of shares in millions) Balance at beginning of year 943 10,492 868 7,391 852 6,669 Common shares issued 1 33 1,500 56 2,241 — — Common shares issued in Merger Transaction (Note 7) 691 37,429 — — — — Dividend Reinvestment and Share Purchase Plan 25 1,226 16 795 12 646 Shares issued on exercise of stock options 3 90 3 65 4 76 Balance at end of year 1,695 50,737 943 10,492 868 7,391 1 Gross proceeds of $1.5 billion , $2.3 billion and nil for the years ended December 31, 2017 , 2016 and 2015 , respectively; net issuance costs of nil , $59 million and nil for the years ended December 31, 2017 , 2016 and 2015 , respectively. PREFERENCE SHARES 2017 2016 2015 Number Number Number December 31, of Shares Amount of Shares Amount of Shares Amount (millions of Canadian dollars; number of shares in millions) Preference Shares, Series A 5 125 5 125 5 125 Preference Shares, Series B 18 457 20 500 20 500 Preference Shares, Series C 2 43 — — — — Preference Shares, Series D 18 450 18 450 18 450 Preference Shares, Series F 20 500 20 500 20 500 Preference Shares, Series H 14 350 14 350 14 350 Preference Shares, Series J 8 199 8 199 8 199 Preference Shares, Series L 16 411 16 411 16 411 Preference Shares, Series N 18 450 18 450 18 450 Preference Shares, Series P 16 400 16 400 16 400 Preference Shares, Series R 16 400 16 400 16 400 Preference Shares, Series 1 16 411 16 411 16 411 Preference Shares, Series 3 24 600 24 600 24 600 Preference Shares, Series 5 8 206 8 206 8 206 Preference Shares, Series 7 10 250 10 250 10 250 Preference Shares, Series 9 11 275 11 275 11 275 Preference Shares, Series 11 20 500 20 500 20 500 Preference Shares, Series 13 14 350 14 350 14 350 Preference Shares, Series 15 11 275 11 275 11 275 Preference Shares, Series 17 30 750 30 750 — — Preference Shares, Series 19 20 500 — — — — Issuance costs (155 ) (147 ) (137 ) Balance at end of year 7,747 7,255 6,515 Characteristics of the preference shares are as follows: Dividend Rate Dividend 1 Per Share Base Redemption Value 2 Redemption and Conversion Option Date 2,3 Right to Convert Into 3,4 (Canadian dollars unless otherwise stated) Preference Shares, Series A 5.50 % $1.37500 $25 — — Preference Shares, Series B 5 3.42 % $0.85360 $25 June 1, 2022 Series C Preference Shares, Series C 5 3-month treasury bill plus 2.400% — $25 June 1, 2022 Series B Preference Shares, Series D 6 4.00 % $1.00000 $25 March 1, 2018 Series E Preference Shares, Series F 4.00 % $1.00000 $25 June 1, 2018 Series G Preference Shares, Series H 4.00 % $1.00000 $25 September 1, 2018 Series I Preference Shares, Series J 7 4.89 % US$1.22160 US$25 June 1, 2022 Series K Preference Shares, Series L 7 4.96 % US$1.23972 US$25 September 1, 2022 Series M Preference Shares, Series N 4.00 % $1.00000 $25 December 1, 2018 Series O Preference Shares, Series P 4.00 % $1.00000 $25 March 1, 2019 Series Q Preference Shares, Series R 4.00 % $1.00000 $25 June 1, 2019 Series S Preference Shares, Series 1 4.00 % US$1.00000 US$25 June 1, 2018 Series 2 Preference Shares, Series 3 4.00 % $1.00000 $25 September 1, 2019 Series 4 Preference Shares, Series 5 4.40 % US$1.10000 US$25 March 1, 2019 Series 6 Preference Shares, Series 7 4.40 % $1.10000 $25 March 1, 2019 Series 8 Preference Shares, Series 9 4.40 % $1.10000 $25 December 1, 2019 Series 10 Preference Shares, Series 11 4.40 % $1.10000 $25 March 1, 2020 Series 12 Preference Shares, Series 13 4.40 % $1.10000 $25 June 1, 2020 Series 14 Preference Shares, Series 15 4.40 % $1.10000 $25 September 1, 2020 Series 16 Preference Shares, Series 17 5.15 % $1.28750 $25 March 1, 2022 Series 18 Preference Shares, Series 19 4.90 % $1.22500 $25 March 1, 2023 Series 20 1 The holder is entitled to receive a fixed, cumulative, quarterly preferential dividend, as declared by the Board of Directors. With the exception of Series A and Series C Preference Shares, such fixed dividend rate resets every five years beginning on the initial redemption and conversion option date. The Series 17 and Series 19 Preference Shares contain a feature where the fixed dividend rate, when reset every five years , will not be less than 5.15% and 4.90% , respectively. No other series of Preference Shares has this feature. 2 Series A Preference Shares may be redeemed any time at our option. For all other series of Preference Shares, we, may at our option, redeem all or a portion of the outstanding Preference Shares for the Base Redemption Value per share plus all accrued and unpaid dividends on the Redemption Option Date and on every fifth anniversary thereafter. 3 The holder will have the right, subject to certain conditions, to convert their shares into Cumulative Redeemable Preference Shares of a specified series on a one -for-one basis on the Conversion Option Date and every fifth anniversary thereafter at an ascribed issue price equal to the Base Redemption Value. 4 With the exception of Series A Preference Shares, after the redemption and conversion option dates, holders may elect to receive quarterly floating rate cumulative dividends per share at a rate equal to: $25 x (number of days in quarter/ 365 ) x 90 day Government of Canada treasury bill rate + 2.4% (Series C), 2.4% (Series E), 2.5% (Series G), 2.1% (Series I), 2.7% (Series O), 2.5% (Series Q), 2.5% (Series S), 2.4% (Series 4), 2.6% (Series 8), 2.7% (Series 10), 2.6% (Series 12), 2.7% (Series 14), 2.7% (Series 16), 4.1% (Series 18) or 3.2% (Series 20); or US $25 x (number of days in quarter/ 365 ) x three -month United States Government treasury bill rate + 3.1% (Series K), 3.2% (Series M), 3.1% (Series 2) or 2.8% (Series 6). 5 On June 1, 2017, 1,730,188 of Series B fixed rate Preference Shares were converted to Series C floating rate Preference Shares based upon preference share holder elections under the terms of the Series B Preference Shares. The quarterly dividend amount for the Series B Preference Shares was decreased to $0.21340 from $0.25000 on June 1, 2017, due to the reset of the annual dividend rate on every fifth anniversary of the date of issuance of the Series B Preference Shares. The quarterly dividend amount for the Series C Preference Shares was set at $0.18600 on June 1, 2017, $0.19571 on September 1, 2017 and $0.20342 on December 1, 2017, due to reset on a quarterly basis following the issuance thereof. 6 On January 30, 2018, we announced that we do not intend to exercise our right to redeem our Series D Preference Shares on March 1, 2018. As a result, until February 14, 2018, the holders of such shares had the right to convert all or part of their Series D fixed rate Preference Shares on a one-for-one basis into Series E floating rate Preference Shares. As of February 14, 2018, less than the 1,000,000 Series D Preference Shares required to give effect to conversions into Series E Preference Shares were tendered for conversion. As a result, none of our outstanding Series D Preference Shares will be converted into Series E Preference Shares on March 1, 2018. However, on March 1, 2018, the quarterly dividend amount for the Series D Preference Shares will be increased to $0.27875 from $0.25000 , due to the reset of the annual dividend rate on every fifth anniversary of the date of issuance of the Series D Preference Shares. 7 No Series J or Series L Preference Shares were converted on the June 1, 2017 and September 1, 2017 conversion option dates, respectively. However, the quarterly dividend amounts for the Series J and Series L Preference Shares were increased to US $0.30540 from US $0.25000 on June 1, 2017, and to US $0.30993 from US $0.25000 on September 1, 2017, respectively, due to the reset of the annual dividend rate on every fifth anniversary of the date of issuance of the Series J and Serles L Preference Shares. DIVIDEND REINVESTMENT AND SHARE PURCHASE PLAN Under the DRIP, registered shareholders may reinvest dividends in our common shares and make additional optional cash payments to purchase common shares, free of brokerage or other charges. Participants in our DRIP receive a 2% discount on the purchase of common shares with reinvested dividends. For the years ended December 31, 2017 and 2016 , total dividends paid were $3.5 billion and $1.9 billion , respectively, of which $2.3 billion and $1.2 billion , respectively, were paid in cash and reflected in financing activities. The remaining $1.2 billion and $795 million , respectively, of dividends paid were reinvested pursuant to the DRIP and resulted in the issuance of common shares rather than a cash payment. In addition to amounts paid in cash and reflected in financing activities for the year ended December 31, 2017 , were $414 million in dividends declared to Spectra Energy shareholders prior to the Merger Transaction that were paid after the Merger Transaction. SHAREHOLDER RIGHTS PLAN The Shareholder Rights Plan is designed to encourage the fair treatment of shareholders in connection with any takeover offer for us. Rights issued under the plan become exercisable when a person and any related parties acquires or announces its intention to acquire 20% or more of our outstanding common shares without complying with certain provisions set out in the plan or without approval of our Board of Directors. Should such an acquisition occur, each rights holder, other than the acquiring person and related parties, will have the right to purchase our common shares at a 50% discount to the market price at that time.

STOCK OPTION AND STOCK UNIT PLA

STOCK OPTION AND STOCK UNIT PLANS	12 Months Ended
	Dec. 31, 2017
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
STOCK OPTION AND STOCK UNIT PLANS	STOCK OPTION AND STOCK UNIT PLANS We maintain four long-term incentive compensation plans: the ISO Plan, the Performance Stock Options (PSO) Plan, the Performance Stock Units (PSU) Plan and the RSU Plan. A maximum of 60 million common shares were reserved for issuance under the 2002 ISO Plan, of which 50 million have been issued to date. A further 71 million common shares have been reserved for issuance under the 2007 ISO and PSO Plans, of which 16 million have been issued to date. The PSU and RSU Plans grant notional units as if a unit was one Enbridge common share and are payable in cash. Prior to the Merger Transaction, Spectra Energy had a long-term incentive plan providing for the granting of stock options, restricted and unrestricted stock awards and units, and other equity-based awards. Upon closing of the Merger Transaction, Enbridge replaced existing Spectra Energy share-based payment awards with awards that will be settled in shares of Enbridge, with Spectra Energy's cash-settled phantom awards included in the fair value of the net assets acquired (Note 7) . Total stock-based compensation expense recorded for the years ended December 31, 2017 , 2016 and 2015 was $165 million , $130 million and $97 million , respectively. Disclosure of activity and assumptions for material stock-based compensation plans are included below. INCENTIVE STOCK OPTIONS Key employees are granted ISOs to purchase common shares at the market price on the grant date. ISOs vest in equal annual installments over a four -year period and expire 10 years after the issue date. December 31, 2017 Number Weighted Average Exercise Price Weighted Average Remaining Contractual Life (years) Aggregate Intrinsic Value (options in thousands; intrinsic value in millions of Canadian dollars) Options outstanding at beginning of year 32,909 42.51 Options granted 5,995 55.72 Options exercised 1 (3,350 ) 32.65 Options cancelled or expired (1,188 ) 53.23 Options outstanding at end of year 34,366 45.41 6.1 271 Options vested at end of year 2 20,403 40.89 4.7 228 1 The total intrinsic value of ISOs exercised during the years ended December 31, 2017 , 2016 and 2015 was $62 million , $123 million and $126 million , respectively, and cash received on exercise was $17 million , $37 million and $43 million , respectively. 2 The total fair value of ISOs vested during the years ended December 31, 2017 , 2016 and 2015 was $44 million , $36 million and $34 million , respectively. Weighted average assumptions used to determine the fair value of ISOs granted using the Black-Scholes-Merton option pricing model are as follows: Year ended December 31, 2017 2016 2015 Fair value per option (Canadian dollars) 1 6.00 7.37 6.48 Valuation assumptions Expected option term (years) 2 5 5 5 Expected volatility 3 20.4 % 25.1 % 19.9 % Expected dividend yield 4 4.2 % 4.4 % 3.2 % Risk-free interest rate 5 1.2 % 0.8 % 0.9 % 1 Options granted to United States employees are based on NYSE prices. The option value and assumptions shown are based on a weighted average of the United States and the Canadian options. The fair values per option for the years ended December 31, 2017 , 2016 and 2015 were $5.66 , $7.01 and $6.22 , respectively, for Canadian employees and US $5.72 , US $6.60 and US $6.16 , respectively, for United States employees. 2 The expected option term is six years based on historical exercise practice and three years for retirement eligible employees. 3 Expected volatility is determined with reference to historic daily share price volatility and consideration of the implied volatility observable in call option values near the grant date. 4 The expected dividend yield is the current annual dividend at the grant date divided by the current stock price. 5 The risk-free interest rate is based on the Government of Canada’s Canadian Bond Yields and the United States Treasury Bond Yields. Compensation expense recorded for the years ended December 31, 2017 , 2016 and 2015 for ISOs was $40 million , $43 million and $35 million , respectively. As at December 31, 2017 , unrecognized compensation expense related to non-vested stock-based compensation arrangements granted under the ISO Plan was $47 million . The expense is expected to be fully recognized over a weighted average period of approximately two years . RESTRICTED STOCK UNITS We have a RSU Plan where cash awards are paid to certain of our non-executive employees following a 35 -month maturity period. RSU holders receive cash equal to our weighted average share price for 20 days prior to the maturity of the grant multiplied by the units outstanding on the maturity date. December 31, 2017 Number Weighted Average Remaining Contractual Life (years) Aggregate Intrinsic Value (units in thousands; intrinsic value in millions of Canadian dollars) Units outstanding at beginning of year 1,854 Units granted 741 Units cancelled (186 ) Units matured 1 (839 ) Dividend reinvestment 123 Units outstanding at end of year 1,693 1.4 83 1 The total amount paid during the years ended December 31, 2017 , 2016 and 2015 for RSUs was $39 million , $56 million and $45 million , respectively. Compensation expense recorded for the years ended December 31, 2017 , 2016 and 2015 for RSUs was $46 million , $51 million and $47 million , respectively. As at December 31, 2017 , unrecognized compensation expense related to non-vested units granted under the RSU Plan was $48 million . The expense is expected to be fully recognized over a weighted average period of approximately one year .

COMPONENTS OF ACCUMULATED OTHER

COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS)	12 Months Ended
	Dec. 31, 2017
Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]
COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS)	COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS) Changes in AOCI attributable to our common shareholders for the years ended December 31, 2017 , 2016 and 2015 are as follows: Cash Flow Hedges Net Investment Hedges Cumulative Translation Adjustment Equity Investees Pension and OPEB Adjustment Total (millions of Canadian dollars) Balance at January 1, 2017 (746 ) (629 ) 2,700 37 (304 ) 1,058 Other comprehensive income/(loss) retained in AOCI 1 478 (2,623 ) (11 ) 18 (2,137 ) Other comprehensive (income)/loss reclassified to earnings Interest rate contracts 1 207 — — — — 207 Commodity contracts 2 (7 ) — — — — (7 ) Foreign exchange contracts 3 (6 ) — — — — (6 ) Other contracts 4 (6 ) — — — — (6 ) Amortization of pension and OPEB actuarial loss and prior service costs 5 — — — — 41 41 189 478 (2,623 ) (11 ) 59 (1,908 ) Tax impact Income tax on amounts retained in AOCI (16 ) 12 — (16 ) (10 ) (30 ) Income tax on amounts reclassified to earnings (71 ) — — — (22 ) (93 ) (87 ) 12 — (16 ) (32 ) (123 ) Balance at December 31, 2017 (644 ) (139 ) 77 10 (277 ) (973 ) Cash Flow Hedges Net Investment Hedges Cumulative Translation Adjustment Equity Investees Pension and OPEB Adjustment Total (millions of Canadian dollars) Balance at January 1, 2016 (688 ) (795 ) 3,365 37 (287 ) 1,632 Other comprehensive income/(loss) retained in AOCI (216 ) 171 (665 ) (5 ) (45 ) (760 ) Other comprehensive (income)/loss reclassified to earnings Interest rate contracts 1 147 — — — — 147 Commodity contracts 2 (11 ) — — — — (11 ) Foreign exchange contracts 3 1 — — — — 1 Other contracts 4 (18 ) — — — — (18 ) Amortization of pension and OPEB actuarial loss and prior service costs 5 — — — — 21 21 (97 ) 171 (665 ) (5 ) (24 ) (620 ) Tax impact Income tax on amounts retained in AOCI 91 (5 ) — 5 11 102 Income tax on amounts reclassified to earnings (52 ) — — — (4 ) (56 ) 39 (5 ) — 5 7 46 Balance at December 31, 2016 (746 ) (629 ) 2,700 37 (304 ) 1,058 Cash Flow Hedges Net Investment Hedges Cumulative Translation Adjustment Equity Investees Pension and OPEB Adjustment Total (millions of Canadian dollars) Balance at January 1, 2015 (488 ) 108 309 (5 ) (359 ) (435 ) Other comprehensive income/(loss) retained in AOCI 73 (952 ) 3,056 47 65 2,289 Other comprehensive (income)/loss reclassified to earnings Interest rate contracts 1 (34 ) — — — — (34 ) Commodity contracts 2 (11 ) — — — — (11 ) Foreign exchange contracts 3 7 — — — — 7 Other contracts 4 26 — — — — 26 Amortization of pension and OPEB actuarial loss and prior service costs 5 — — — — 32 32 Other comprehensive income reclassified to earnings of derecognized cash flow hedges (338 ) — — — — (338 ) (277 ) (952 ) 3,056 47 97 1,971 Tax impact Income tax on amounts retained in AOCI (29 ) 49 — (5 ) (14 ) 1 Income tax on amounts reclassified to earnings 15 — — — (11 ) 4 Income tax on amounts reclassified to earnings of derecognized cash flow hedges 91 — — — — 91 77 49 — (5 ) (25 ) 96 Balance at December 31, 2015 (688 ) (795 ) 3,365 37 (287 ) 1,632 1 Reported within Interest expense in the Consolidated Statements of Earnings. 2 Reported within Commodity costs in the Consolidated Statements of Earnings. 3 Reported within Other income/(expense) in the Consolidated Statements of Earnings. 4 Reported within Operating and administrative expense in the Consolidated Statements of Earnings. 5 These components are included in the computation of net benefit costs and are reported within Operating and administrative expense in the Consolidated Statements of Earnings.

RISK MANAGEMENT AND FINANCIAL I

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS	12 Months Ended
	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS	RISK MANAGEMENT AND FINANCIAL INSTRUMENTS MARKET RISK Our earnings, cash flows and OCI are subject to movements in foreign exchange rates, interest rates, commodity prices and our share price (collectively, market risk). Formal risk management policies, processes and systems have been designed to mitigate these risks. The following summarizes the types of market risks to which we are exposed and the risk management instruments used to mitigate them. We use a combination of qualifying and non-qualifying derivative instruments to manage the risks noted below. Foreign Exchange Risk We generate certain revenues, incur expenses, and hold a number of investments and subsidiaries that are denominated in currencies other than Canadian dollars. As a result, our earnings, cash flows and OCI are exposed to fluctuations resulting from foreign exchange rate variability. We employ financial derivative instruments to hedge foreign currency denominated earnings exposure. A combination of qualifying and non-qualifying derivative instruments are used to hedge anticipated foreign currency denominated revenues and expenses, and to manage variability in cash flows. We hedge certain net investments in United States dollar denominated investments and subsidiaries using foreign currency derivatives and United States dollar denominated debt. Interest Rate Risk Our earnings and cash flows are exposed to short-term interest rate variability due to the regular repricing of our variable rate debt, primarily commercial paper. Pay fixed-receive floating interest rate swaps are used to hedge against the effect of future interest rate movements. We have implemented a program to significantly mitigate the impact of short-term interest rate volatility on interest expense via execution of floating to fixed interest rate swaps with an average swap rate of 2.6% . As a result of the Merger Transaction, we are exposed to changes in the fair value of fixed rate debt that arise as a result of the changes in market interest rates. Pay floating-receive fixed interest rate swaps are used to hedge against future changes to the fair value of fixed rate debt. We have assumed a program within our subsidiaries to mitigate the impact of fluctuations in the fair value of fixed rate debt via execution of fixed to floating interest rate swaps with an average swap rate of 2.2% . Our earnings and cash flows are also exposed to variability in longer term interest rates ahead of anticipated fixed rate term debt issuances. Forward starting interest rate swaps are used to hedge against the effect of future interest rate movements. We have assumed a program within some of our subsidiaries to mitigate our exposure to long-term interest rate variability on select forecast term debt issuances via execution of floating to fixed interest rate swaps with an average swap rate of 3.1% . We also monitor our debt portfolio mix of fixed and variable rate debt instruments to maintain a consolidated portfolio of debt within the Board of Directors approved policy limit of a maximum of 25% floating rate debt as a percentage of total debt outstanding. Effective January 1, 2018, the Board of Directors approved a policy limit increase of a maximum of 30% floating rate debt as a percentage of total debt outstanding. We primarily use qualifying derivative instruments to manage interest rate risk. Commodity Price Risk Our earnings and cash flows are exposed to changes in commodity prices as a result of our ownership interests in certain assets and investments, as well as through the activities of our energy services subsidiaries. These commodities include natural gas, crude oil, power and NGL. We employ financial and physical derivative instruments to fix a portion of the variable price exposures that arise from physical transactions involving these commodities. We use primarily non-qualifying derivative instruments to manage commodity price risk. Emission Allowance Price Risk Emission allowance price risk is the risk of gain or loss due to changes in the market price of emission allowances that our gas distribution business is required to purchase for itself and most of its customers to meet GHG compliance obligations under the Ontario Cap and Trade framework. Similar to the gas supply procurement framework, the OEB's framework for emission allowance procurement allows recovery of fluctuations in emission allowance prices in customer rates, subject to OEB approval. Equity Price Risk Equity price risk is the risk of earnings fluctuations due to changes in our share price. We have exposure to our own common share price through the issuance of various forms of stock-based compensation, which affect earnings through revaluation of the outstanding units every period. We use equity derivatives to manage the earnings volatility derived from one form of stock-based compensation, restricted share units. We use a combination of qualifying and non-qualifying derivative instruments to manage equity price risk. TOTAL DERIVATIVE INSTRUMENTS The following table summarizes the Consolidated Statements of Financial Position location and carrying value of our derivative instruments. We generally have a policy of entering into individual International Swaps and Derivatives Association, Inc. agreements, or other similar derivative agreements, with the majority of our financial derivative counterparties. These agreements provide for the net settlement of derivative instruments outstanding with specific counterparties in the event of bankruptcy or other significant credit events, and reduces our credit risk exposure on financial derivative asset positions outstanding with the counterparties in those circumstances. The following table summarizes the maximum potential settlement in the event of these specific circumstances. All amounts are presented gross in the Consolidated Statements of Financial Position. December 31, 2017 Derivative Instruments Used as Cash Flow Hedges Derivative Instruments Used as Net Investment Hedges Derivative Non- Qualifying Derivative Instruments Total Gross Derivative Instruments as Presented Amounts Available for Offset Total Net Derivative Instruments (millions of Canadian dollars) Accounts receivable and other Foreign exchange contracts 1 4 — 138 143 (83 ) 60 Interest rate contracts 6 — 2 — 8 (3 ) 5 Commodity contracts 2 — — 143 145 (64 ) 81 9 4 2 281 296 (150 ) 146 Deferred amounts and other assets Foreign exchange contracts 1 1 — 143 145 (125 ) 20 Interest rate contracts 7 — 6 — 13 (2 ) 11 Commodity contracts 17 — — 6 23 (19 ) 4 25 1 6 149 181 (146 ) 35 Accounts payable and other Foreign exchange contracts (5 ) (42 ) — (312 ) (359 ) 83 (276 ) Interest rate contracts (140 ) — (6 ) (183 ) (329 ) 3 (326 ) Commodity contracts — — — (439 ) (439 ) 64 (375 ) Other contracts (1 ) — — (2 ) (3 ) — (3 ) (146 ) (42 ) (6 ) (936 ) (1,130 ) 150 (980 ) Other long-term liabilities Foreign exchange contracts (4 ) (9 ) — (1,299 ) (1,312 ) 125 (1,187 ) Interest rate contracts (38 ) — (2 ) — (40 ) 2 (38 ) Commodity contracts — — — (186 ) (186 ) 19 (167 ) Other contracts (1 ) — — — (1 ) — (1 ) (43 ) (9 ) (2 ) (1,485 ) (1,539 ) 146 (1,393 ) Total net derivative asset/(liability) Foreign exchange contracts (7 ) (46 ) — (1,330 ) (1,383 ) — (1,383 ) Interest rate contracts (165 ) — — (183 ) (348 ) — (348 ) Commodity contracts 19 — — (476 ) (457 ) — (457 ) Other contracts (2 ) — — (2 ) (4 ) — (4 ) (155 ) (46 ) — (1,991 ) (2,192 ) — (2,192 ) December 31, 2016 Derivative Derivative Non- Total Gross Amounts Total Net Derivative Instruments (millions of Canadian dollars) Accounts receivable and other Foreign exchange contracts 101 3 5 109 (103 ) 6 Interest rate contracts 3 — — 3 (3 ) — Commodity contracts 9 — 232 241 (125 ) 116 113 3 237 353 (231 ) 122 Deferred amounts and other assets Foreign exchange contracts 1 3 69 73 (72 ) 1 Interest rate contracts 8 — — 8 (6 ) 2 Commodity contracts 7 — 61 68 (22 ) 46 Other contracts 1 — 1 2 — 2 17 3 131 151 (100 ) 51 Accounts payable and other Foreign exchange contracts — (268 ) (727 ) (995 ) 103 (892 ) Interest rate contracts (452 ) — (131 ) (583 ) 3 (580 ) Commodity contracts — — (359 ) (359 ) 125 (234 ) Other contracts (1 ) — (3 ) (4 ) — (4 ) (453 ) (268 ) (1,220 ) (1,941 ) 231 (1,710 ) Other long-term liabilities Foreign exchange contracts — (68 ) (1,961 ) (2,029 ) 72 (1,957 ) Interest rate contracts (268 ) — (205 ) (473 ) 6 (467 ) Commodity contracts — — (211 ) (211 ) 22 (189 ) (268 ) (68 ) (2,377 ) (2,713 ) 100 (2,613 ) Total net derivative asset/(liability) Foreign exchange contracts 102 (330 ) (2,614 ) (2,842 ) — (2,842 ) Interest rate contracts (709 ) — (336 ) (1,045 ) — (1,045 ) Commodity contracts 16 — (277 ) (261 ) — (261 ) Other contracts — — (2 ) (2 ) — (2 ) (591 ) (330 ) (3,229 ) (4,150 ) — (4,150 ) The following table summarizes the maturity and notional principal or quantity outstanding related to our derivative instruments. 2017 2016 As at December 31, 2018 2019 2020 2021 2022 Thereafter Total Foreign exchange contracts - United States dollar forwards - purchase (millions of United States dollars) 755 2 2 — — — 997 Foreign exchange contracts - United States dollar forwards - sell (millions of United States dollars) 4,478 3,246 3,258 1,689 1,676 1,820 13,591 Foreign exchange contracts - British pound (GBP) forwards - purchase (millions of GBP) 18 — — — — — 97 Foreign exchange contracts - GBP forwards - sell (millions of GBP) — 89 25 27 28 149 285 Foreign exchange contracts - Euro forwards - purchase (millions of Euro) 280 375 — — — — — Foreign exchange contracts - Euro forwards - sell (millions of Euro) — — 35 169 169 889 — Foreign exchange contracts - Japanese yen forwards - purchase (millions of yen) — 32,662 — — 20,000 — 32,662 Interest rate contracts - short-term pay fixed rate (millions of Canadian dollars) 4,950 1,585 215 95 91 202 14,008 Interest rate contracts - long-term receive fixed rate (millions of Canadian dollars) 1,522 1,018 822 433 349 52 — Interest rate contracts - long-term pay fixed rate (millions of Canadian dollars) 4,007 957 438 — — — 7,509 Equity contracts (millions of Canadian dollars) 45 37 8 — — — 88 Commodity contracts - natural gas (billions of cubic feet) (59 ) (69 ) (20 ) (10 ) (1 ) — (161 ) Commodity contracts - crude oil (millions of barrels) (3 ) — — — — — (20 ) Commodity contracts - NGL (millions of barrels) (12 ) — — — — — (14 ) Commodity contracts - power (megawatt per hour (MW/H)) 42 51 55 (3 ) (43 ) (43 ) 1 (4 ) 2 1 As at December 31, 2017, thereafter includes an average net purchase/(sell) of power of (43) MW/H for 2023 through 2025. 2 As at December 31, 2016, the average net purchase/(sell) of power was (4) MW/H for 2017 through 2025 with a high of 40 MW/H and a low of (43) MW/H. The Effect of Derivative Instruments on the Consolidated Statements of Earnings and Comprehensive Income The following table presents the effect of cash flow hedges and net investment hedges on our consolidated earnings and consolidated comprehensive income, before the effect of income taxes: 2017 2016 2015 (millions of Canadian dollars) Amount of unrealized gain/(loss) recognized in OCI Cash flow hedges Foreign exchange contracts (5 ) (19 ) 77 Interest rate contracts 6 (90 ) (275 ) Commodity contracts 11 14 9 Other contracts 1 39 (47 ) Net investment hedges Foreign exchange contracts 284 22 (248 ) 297 (34 ) (484 ) Amount of (gain)/loss reclassified from AOCI to earnings (effective portion) Foreign exchange contracts 1 (104 ) 2 9 Interest rate contracts 2,3 388 145 128 Commodity contracts 4 (9 ) (12 ) (46 ) Other contracts 5 8 (29 ) 28 283 106 119 De-designation of qualifying hedges in connection with the Canadian Restructuring Plan Interest rate contracts 2 — — 338 — — 338 Amount of (gain)/loss reclassified from AOCI to earnings (ineffective portion and amount excluded from effectiveness testing) Interest rate contracts 2, 3 (4 ) 61 21 Commodity contracts 4 — — 5 (4 ) 61 26 1 Reported within Transportation and other services revenues and Other income/(expense) in the Consolidated Statements of Earnings. 2 Reported within Interest expense in the Consolidated Statements of Earnings. 3 For the year ended December 31, 2017, includes settlements of $296 million loss related to the termination of long-term interest rate swaps as not highly probable to issue long-term debt. 4 Reported within Transportation and other services revenues, Commodity sales revenues, Commodity costs and Operating and administrative expense in the Consolidated Statements of Earnings. 5 Reported within Operating and administrative expense in the Consolidated Statements of Earnings. We estimate that a loss of $38 million from AOCI related to cash flow hedges will be reclassified to earnings in the next 12 months. Actual amounts reclassified to earnings depend on the foreign exchange rates, interest rates and commodity prices in effect when derivative contracts that are currently outstanding mature. For all forecasted transactions, the maximum term over which we are hedging exposures to the variability of cash flows is 36 months as at December 31, 2017 . Fair Value Derivatives For interest rate derivative instruments that are designated and qualify as fair value hedges, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item attributable to the hedged risk is included in Interest expense in the Consolidated Statements of Earnings. During the years ended December 31, 2017 and 2016 , we recognized an unrealized loss of $10 million and nil , respectively, on the derivative and an unrealized gain of $11 million and nil , respectively, on the hedged item in earnings. During the years ended December 31, 2017 and 2016 , we recognized a realized gain of $2 million and nil , respectively, on the derivative and a realized loss of $2 million and nil , respectively, on the hedged item in earnings. The difference in the amounts, if any, represents hedge ineffectiveness. Non-Qualifying Derivatives The following table presents the unrealized gains and losses associated with changes in the fair value of our non-qualifying derivatives: Year ended December 31, 2017 2016 2015 (millions of Canadian dollars) Foreign exchange contracts 1 1,284 935 (2,187 ) Interest rate contracts 2 157 73 (363 ) Commodity contracts 3 (199 ) (508 ) 199 Other contracts 4 — 9 (22 ) Total unrealized derivative fair value gain/(loss), net 1,242 509 (2,373 ) 1 For the respective annual periods, reported within Transportation and other services revenues ( 2017 - $800 million gain; 2016 - $497 million gain; 2015 - $1,383 million loss) and Other income/(expense) ( 2017 - $484 million gain; 2016 - $438 million gain; 2015 - $804 million loss) in the Consolidated Statements of Earnings. 2 Reported as an (increase)/decrease within Interest expense in the Consolidated Statements of Earnings. 3 For the respective annual periods, reported within Transportation and other services revenues ( 2017 - $104 million loss; 2016 - $52 million loss; 2015 - $328 million gain), Commodity sales ( 2017 - $90 million gain 2016 - $474 million loss; 2015 - $226 million loss), Commodity costs ( 2017 - $223 million loss; 2016 - $38 million gain; 2015 - $99 million gain) and Operating and administrative expense ( 2017 - $38 million gain; 2016 - $20 million loss; 2015 - $2 million loss) in the Consolidated Statements of Earnings. 4 Reported within Operating and administrative expense in the Consolidated Statements of Earnings. LIQUIDITY RISK Liquidity risk is the risk that we will not be able to meet our financial obligations, including commitments and guarantees, as they become due. In order to mitigate this risk, we forecast cash requirements over a 12 month rolling time period to determine whether sufficient funds will be available and maintain substantial capacity under our committed bank lines of credit to address any contingencies. Our primary sources of liquidity and capital resources are funds generated from operations, the issuance of commercial paper and draws under committed credit facilities and long-term debt, which includes debentures and medium-term notes. We also maintain current shelf prospectuses with securities regulators which enables, subject to market conditions, ready access to either the Canadian or United States public capital markets. In addition, we maintain sufficient liquidity through committed credit facilities with a diversified group of banks and institutions which, if necessary, enables us to fund all anticipated requirements for approximately one year without accessing the capital markets. We are in compliance with all the terms and conditions of our committed credit facility agreements and term debt indentures as at December 31, 2017 . As a result, all credit facilities are available to us and the banks are obligated to fund and have been funding us under the terms of the facilities. CREDIT RISK Entering into derivative instruments may result in exposure to credit risk from the possibility that a counterparty will default on its contractual obligations. In order to mitigate this risk, we enter into risk management transactions primarily with institutions that possess investment grade credit ratings. Credit risk relating to derivative counterparties is mitigated by credit exposure limits and contractual requirements, netting arrangements, and ongoing monitoring of counterparty credit exposure using external credit rating services and other analytical tools. We have group credit concentrations and maximum credit exposure, with respect to derivative instruments, in the following counterparty segments: December 31, 2017 2016 (millions of Canadian dollars) Canadian financial institutions 82 39 United States financial institutions 19 179 European financial institutions 145 106 Asian financial institutions 2 1 Other 1 137 162 385 487 1 Other is comprised of commodity clearing house and physical natural gas and crude oil counterparties. As at December 31, 2017 , we provided letters of credit totaling nil in lieu of providing cash collateral to our counterparties pursuant to the terms of the relevant ISDA agreements. We held no cash collateral on derivative asset exposures as at December 31, 2017 and December 31, 2016 . Gross derivative balances have been presented without the effects of collateral posted. Derivative assets are adjusted for non-performance risk of our counterparties using their credit default swap spread rates, and are reflected at fair value. For derivative liabilities, our non-performance risk is considered in the valuation. Credit risk also arises from trade and other long-term receivables, and is mitigated through credit exposure limits and contractual requirements, assessment of credit ratings and netting arrangements. Within EGD and Union Gas, credit risk is mitigated by the utilities' large and diversified customer base and the ability to recover an estimate for doubtful accounts through the ratemaking process. We actively monitor the financial strength of large industrial customers and, in select cases, have obtained additional security to minimize the risk of default on receivables. Generally, we classify and provide for receivables older than 20 days as past due. The maximum exposure to credit risk related to non-derivative financial assets is their carrying value. FAIR VALUE MEASUREMENTS Our financial assets and liabilities measured at fair value on a recurring basis include derivative instruments. We also disclose the fair value of other financial instruments not measured at fair value. The fair value of financial instruments reflects our best estimates of market value based on generally accepted valuation techniques or models and is supported by observable market prices and rates. When such values are not available, we use discounted cash flow analysis from applicable yield curves based on observable market inputs to estimate fair value. FAIR VALUE OF FINANCIAL INSTRUMENTS We categorize our derivative instruments measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. Level 1 Level 1 includes derivatives measured at fair value based on unadjusted quoted prices for identical assets and liabilities in active markets that are accessible at the measurement date. An active market for a derivative is considered to be a market where transactions occur with sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 instruments consist primarily of exchange-traded derivatives used to mitigate the risk of crude oil price fluctuations. Level 2 Level 2 includes derivative valuations determined using directly or indirectly observable inputs other than quoted prices included within Level 1. Derivatives in this category are valued using models or other industry standard valuation techniques derived from observable market data. Such valuation techniques include inputs such as quoted forward prices, time value, volatility factors and broker quotes that can be observed or corroborated in the market for the entire duration of the derivative. Derivatives valued using Level 2 inputs include non-exchange traded derivatives such as over-the-counter foreign exchange forward and cross currency swap contracts, interest rate swaps, physical forward commodity contracts, as well as commodity swaps and options for which observable inputs can be obtained. We have also categorized the fair value of our held to maturity preferred share investment and long-term debt as Level 2. The fair value of our held to maturity preferred share investment is primarily based on the yield of certain Government of Canada bonds. The fair value of our long-term debt is based on quoted market prices for instruments of similar yield, credit risk and tenor. Level 3 Level 3 includes derivative valuations based on inputs which are less observable, unavailable or where the observable data does not support a significant portion of the derivatives’ fair value. Generally, Level 3 derivatives are longer dated transactions, occur in less active markets, occur at locations where pricing information is not available or have no binding broker quote to support Level 2 classification. We have developed methodologies, benchmarked against industry standards, to determine fair value for these derivatives based on extrapolation of observable future prices and rates. Derivatives valued using Level 3 inputs primarily include long-dated derivative power contracts and NGL and natural gas contracts, basis swaps, commodity swaps, power and energy swaps, as well as options. We do not have any other financial instruments categorized in Level 3. We use the most observable inputs available to estimate the fair value of our derivatives. When possible, we estimate the fair value of our derivatives based on quoted market prices. If quoted market prices are not available, we use estimates from third party brokers. For non-exchange traded derivatives classified in Levels 2 and 3, we use standard valuation techniques to calculate the estimated fair value. These methods include discounted cash flows for forwards and swaps and Black-Scholes-Merton pricing models for options. Depending on the type of derivative and nature of the underlying risk, we use observable market prices (interest, foreign exchange, commodity and share price) and volatility as primary inputs to these valuation techniques. Finally, we consider our own credit default swap spread as well as the credit default swap spreads associated with our counterparties in our estimation of fair value. We have categorized our derivative assets and liabilities measured at fair value as follows: December 31, 2017 Level 1 Level 2 Level 3 Total Gross Derivative Instruments (millions of Canadian dollars) Financial assets Current derivative assets Foreign exchange contracts — 143 — 143 Interest rate contracts — 8 — 8 Commodity contracts 1 30 114 145 1 181 114 296 Long-term derivative assets Foreign exchange contracts — 145 — 145 Interest rate contracts — 13 — 13 Commodity contracts — 2 21 23 — 160 21 181 Financial liabilities Current derivative liabilities Foreign exchange contracts — (359 ) — (359 ) Interest rate contracts — (329 ) — (329 ) Commodity contracts (13 ) (87 ) (339 ) (439 ) Other contracts — (3 ) — (3 ) (13 ) (778 ) (339 ) (1,130 ) Long-term derivative liabilities Foreign exchange contracts — (1,312 ) — (1,312 ) Interest rate contracts — (40 ) — (40 ) Commodity contracts — (3 ) (183 ) (186 ) Other contracts — (1 ) — (1 ) — (1,356 ) (183 ) (1,539 ) Total net financial asset/(liability) Foreign exchange contracts — (1,383 ) — (1,383 ) Interest rate contracts — (348 ) — (348 ) Commodity contracts (12 ) (58 ) (387 ) (457 ) Other contracts — (4 ) — (4 ) (12 ) (1,793 ) (387 ) (2,192 ) December 31, 2016 Level 1 Level 2 Level 3 Total Gross Derivative Instruments (millions of Canadian dollars) Financial assets Current derivative assets Foreign exchange contracts — 109 — 109 Interest rate contracts — 3 — 3 Commodity contracts 2 86 153 241 2 198 153 353 Long-term derivative assets Foreign exchange contracts — 73 — 73 Interest rate contracts — 8 — 8 Commodity contracts — 43 25 68 Other contracts — 2 — 2 — 126 25 151 Financial liabilities Current derivative liabilities Foreign exchange contracts — (995 ) — (995 ) Interest rate contracts — (583 ) — (583 ) Commodity contracts (12 ) (75 ) (272 ) (359 ) Other contracts — (4 ) — (4 ) (12 ) (1,657 ) (272 ) (1,941 ) Long-term derivative liabilities Foreign exchange contracts — (2,029 ) — (2,029 ) Interest rate contracts — (473 ) — (473 ) Commodity contracts — (10 ) (201 ) (211 ) — (2,512 ) (201 ) (2,713 ) Total net financial asset/(liability) Foreign exchange contracts — (2,842 ) — (2,842 ) Interest rate contracts — (1,045 ) — (1,045 ) Commodity contracts (10 ) 44 (295 ) (261 ) Other contracts — (2 ) — (2 ) (10 ) (3,845 ) (295 ) (4,150 ) The significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments were as follows: December 31, 2017 Fair Value Unobservable Input Minimum Price/Volatility Maximum Price/Volatility Weighted Average Price/Volatility Unit of Measurement (fair value in millions of Canadian dollars) Commodity contracts - financial 1 Natural gas (1 ) Forward gas price 2.67 5.52 3.38 $/mmbtu 3 Crude (4 ) Forward crude price 43.76 65.60 51.03 $/barrel NGL (12 ) Forward NGL price 0.30 1.83 1.32 $/gallon Power (110 ) Forward power price 15.39 71.41 50.72 $/MW/H Commodity contracts - physical 1 Natural gas (114 ) Forward gas price 2.51 7.57 2.93 $/mmbtu 3 Crude (148 ) Forward crude price 34.38 80.56 69.01 $/barrel NGL 3 Forward NGL price 0.28 1.94 0.93 $/gallon Commodity options 2 Crude (1 ) Option volatility 15 % 24 % 22 % Power — Option volatility 29 % 55 % 35 % (387 ) 1 Financial and physical forward commodity contracts are valued using a market approach valuation technique. 2 Commodity options contracts are valued using an option model valuation technique. 3 One million British thermal units (mmbtu). If adjusted, the significant unobservable inputs disclosed in the table above would have a direct impact on the fair value of our Level 3 derivative instruments. The significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments include forward commodity prices and, for option contracts, price volatility. Changes in forward commodity prices could result in significantly different fair values for our Level 3 derivatives. Changes in price volatility would change the value of the option contracts. Generally, a change in the estimate of forward commodity prices is unrelated to a change in the estimate of price volatility. Changes in net fair value of derivative assets and liabilities classified as Level 3 in the fair value hierarchy were as follows: Year ended December 31, 2017 2016 (millions of Canadian dollars) Level 3 net derivative asset/(liability) at beginning of period (295 ) 54 Total gain/(loss) Included in earnings 1 (184 ) (113 ) Included in OCI 4 3 Settlements 88 (239 ) Level 3 net derivative liability at end of period (387 ) (295 ) 1 Reported within Transportation and other services revenues, Commodity costs and Operating and administrative expense in the Consolidated Statements of Earnings. Our policy is to recognize transfers as at the last day of the reporting period. There were no transfers between levels as at December 31, 2017 or 2016 . FAIR VALUE OF OTHER FINANCIAL INSTRUMENTS Our other long-term investments in other entities with no actively quoted prices are recorded at cost. The carrying value of other long-term investments recognized at cost totaled $ 99 million and $110 million as at December 31, 2017 and 2016 , respectively. We have Restricted long-term investments held in trust totaling $267 million and $90 million as at December 31, 2017 and 2016 , respectively, which are recognized at fair value. We have a held to maturity preferred share investment carried at its amortized cost of $371 million and $355 million as at December 31, 2017 and 2016 , respectively. These preferred shares are entitled to a cumulative preferred dividend based on the yield of 10 -year Government of Canada bonds plus a margin of 4.38% . The fair value of this preferred share investment approximates its face value of $580 million as at December 31, 2017 and 2016 . As at December 31, 2017 and 2016 , our long-term debt had a carrying value of $64.0 billion and $40.8 billion , respectively, before debt issuance costs and a fair value of $67.4 billion and $43.9 billion , respectively. We also have noncurrent notes receivable carried at book value recorded in Deferred amounts and other assets in the Consolidated Statements of Financial Position. As at December 31, 2017 and 2016 , the noncurrent notes receivable had a carrying value of $89 million and nil , and a fair value of $89 million and nil , respectively. NET INVESTMENT HEDGES We have designated a portion of our United States dollar denominated debt, as well as a portfolio of foreign exchange forward contracts, as a hedge of our net investment in United States dollar denominated investments and subsidiaries. During the years ended December 31, 2017 and 2016 , we recognized an unrealized foreign exchange gain on the translation of United States dollar denominated debt of $367 million and $121 million , respectively, and an unrealized gain on the change in fair value of our outstanding foreign exchange forward contracts of $286 million and $21 million , respectively, in OCI. During the years ended December 31, 2017 and 2016 , we recognized a realized loss of $198 million and a realized gain of $3 million , respectively, in OCI associated with the settlement of foreign exchange forward contracts and also recognized a realized gain of $23 million and $26 million , respectively, in OCI associated with the settlement of United States dollar denominated debt that had matured during the period. There was no ineffectiveness during the years ended December 31, 2017 and 2016 .

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
INCOME TAXES	INCOME TAXES INCOME TAX RATE RECONCILIATION Year ended December 31, 2017 2016 2015 (millions of Canadian dollars) Earnings before income taxes 569 2,451 11 Canadian federal statutory income tax rate 15 % 15 % 15 % Expected federal taxes at statutory rate 85 368 2 Increase/(decrease) resulting from: Provincial and state income taxes 1 133 34 (204 ) Foreign and other statutory rate differentials (601 ) (56 ) 310 Impact of United States tax reform 2 (2,045 ) — — Effects of rate-regulated accounting (189 ) (116 ) (52 ) Foreign allowable interest deductions (124 ) (107 ) (84 ) Part VI.1 tax, net of federal Part I deduction 68 56 55 Goodwill write-down 3 15 — — Intercompany sale of investment 4 — 6 23 Non-taxable portion of gain on sale of investment to unrelated party 5 — (61 ) — Valuation allowance 6 (17 ) 22 154 Intercorporate investment in EIPLP 7 77 — — Noncontrolling interests (80 ) (15 ) (28 ) Other 8 (19 ) 11 (6 ) Income tax (recovery)/expense (2,697 ) 142 170 Effective income tax rate (474.0 )% 5.8 % 1,545.5 % 1 The change in provincial and state income taxes from 2016 to 2017 reflects the increase in earnings from the Canadian operations and the impact of the United States tax reform on state income tax expense. 2 The amount was due to the enactment of the “Tax Cuts and Jobs Act” by the United States on December 22, 2017, which included a reduction in the federal corporate income tax rate from 35% to 21% effective for taxation years beginning after December 31, 2017. 3 The amount relates to the federal component of the tax effect a goodwill write-down pursuant to ASU 2017-04. 4 In November 2016 and September 2015, certain assets were sold to entities under common control. The intercompany gains realized on these transfers were eliminated. However, because these transactions involved the sale of partnership units, tax consequences have been recognized in earnings. 5 The amount in 2016 represents the federal component of the non-taxable portion of the gain on the sale of the South Prairie Region assets to unrelated party. 6 The decrease from 2015 to 2016 is due to the federal component of the tax effect of a valuation allowance on the deferred tax assets related to an outside basis temporary difference that, in 2015, was no longer more likely than not to be realized. 7 There was a change in assertion regarding the manner of recovery of the intercorporate investment in EIPLP such that deferred tax related to outside basis temporary differences was required to be recorded. 8 2015 included $17 million recovery related to the federal component of the tax effect of adjustments related to prior periods. COMPONENTS OF PRETAX EARNINGS AND INCOME TAXES Year ended December 31, 2017 2016 2015 (millions of Canadian dollars) Earnings/(loss) before income taxes Canada 2,200 2,034 (1,365 ) United States (2,431 ) (333 ) 808 Other 800 750 568 569 2,451 11 Current income taxes Canada 129 74 157 United States 46 21 3 Other 5 4 3 180 99 163 Deferred income taxes Canada 299 188 (558 ) United States (3,160 ) (151 ) 565 Other (16 ) 6 — (2,877 ) 43 7 Income tax (recovery)/expense (2,697 ) 142 170 COMPONENTS OF DEFERRED INCOME TAXES Deferred tax assets and liabilities are recognized for the future tax consequences of differences between carrying amounts of assets and liabilities and their respective tax bases. Major components of deferred income tax assets and liabilities are as follows: December 31, 2017 2016 (millions of Canadian dollars) Deferred income tax liabilities Property, plant and equipment (4,089 ) (3,867 ) Investments (6,596 ) (2,938 ) Regulatory assets (977 ) (439 ) Other (50 ) (47 ) Total deferred income tax liabilities (11,712 ) (7,291 ) Deferred income tax assets Financial instruments 697 1,215 Pension and OPEB plans 258 219 Loss carryforwards 1,781 1,189 Other 1,057 374 Total deferred income tax assets 3,793 2,997 Less valuation allowance (286 ) (572 ) Total deferred income tax assets, net 3,507 2,425 Net deferred income tax liabilities (8,205 ) (4,866 ) Presented as follows: Total deferred income tax assets 1,090 1,170 Total deferred income tax liabilities (9,295 ) (6,036 ) Net deferred income tax liabilities (8,205 ) (4,866 ) A valuation allowance has been established for certain loss and credit carryforwards, and outside basis temporary differences on investments that reduce deferred income tax assets to an amount that will more likely than not be realized. As at December 31, 2017 and 2016 , we recognized the benefit of unused tax loss carryforwards of $3.8 billion and $2.5 billion , respectively, in Canada which expire in 2025 and beyond. As at December 31, 2017 and 2016 , we recognized the benefit of unused tax loss carryforwards of $2.1 billion and $1.3 billion , respectively, in the United States which expire in 2021 and beyond. As at December 31, 2017 and 2016, we recognized the benefit of unused capital loss carryforwards of $143 million and nil , respectively, in Canada which can be carried forward indefinitely. As at December 31, 2017 and 2016 , we recognized the benefit of unused capital loss carryforwards of $ 20 million and nil , respectively, in the United States which will expire in 2021. We have not provided for deferred income taxes on the difference between the carrying value of substantially all of our foreign subsidiaries and their corresponding tax basis as the earnings of those subsidiaries are intended to be permanently reinvested in their operations. As such these investments are not anticipated to give rise to income taxes in the foreseeable future. The difference between the carrying values of the investments and their tax bases is largely a result of unremitted earnings and currency translation adjustments. The unremitted earnings and currency translation adjustment for which no deferred taxes have been recognized in respect of foreign subsidiaries were $2.1 billion and $4.1 billion for the period December 31, 2017 and 2016 , respectively. If such earnings are remitted, in the form of dividends or otherwise, we may be subject to income taxes and foreign withholding taxes. The determination of the amount of unrecognized deferred income tax liabilities on such amounts is not practicable. Enbridge and one or more of our subsidiaries are subject to taxation in Canada, the United States and other foreign jurisdictions. The material jurisdictions in which we are subject to potential examinations include the United States (Federal) and Canada (Federal, Alberta and Ontario). We are open to examination by Canadian tax authorities for the 2009 to 2017 tax years and by United States tax authorities for the 2014 to 2017 tax years. We are currently under examination for income tax matters in Canada for the 2013 to 2016 tax years. We are not currently under examination for income tax matters in any other material jurisdiction where we are subject to income tax. United States Tax Reform On December 22, 2017, the United States enacted the TCJA. The changes in the TCJA are effective for taxation years beginning after December 31, 2017. While the changes are broad and complex, the most significant change is the reduction in the corporate federal income tax rate from 35% to 21% . We are also impacted by a one-time deemed repatriation or “toll” tax on undistributed earnings and profits of United States controlled foreign affiliates, including Canadian subsidiaries. We have made reasonable estimates for the measurement and accounting of certain effects of the TCJA in accordance with SEC Staff Accounting Bulletin No.118 (SAB 118). We recorded a provisional $34 million increase to our 2017 current income tax provision related to the toll tax, payable over eight years. We recorded a provisional $2.0 billion decrease to our 2017 deferred income tax provision related to the reduction in the corporate federal income tax rate. The accounting for these provisional items decreased our accumulated deferred income tax liability by $3.1 billion and increased our regulatory liability by $1.1 billion . We have also adjusted our valuation allowance for certain deferred tax assets existing at December 31, 2016 for the reduction in the corporate federal income tax rate by $0.2 billion . We have recognized these provisional tax impacts and included these amounts in our consolidated financial statements for the year ended December 31, 2017. The ultimate impact may differ from these provisional amounts, possibly materially, due to, among other things, additional analysis, changes in interpretations and assumptions we have made, additional regulatory guidance that may be issued, and actions we may take as a result of the TCJA. The accounting is expected to be complete when the 2017 US corporate income tax return is filed in 2018. As provided for under SAB 118, we have not recorded the impact for certain items under the TCJA for which we have not yet been able to gather, prepare and analyze the necessary information in reasonable detail to complete the ASC 740 accounting. For these items, the current and deferred taxes were recognized and measured based on the provisions of the tax laws that were in effect immediately prior to the TCJA being enacted. These certain items include but are not limited to the computation of state income taxes as there is uncertainty on conformity to the federal tax system following the TCJA, global intangible low taxed income, and base erosion and anti-abuse tax. The determination of the impact of the income tax effects of these items will require additional analysis of historical records and further interpretation of the TCJA from yet to be issued United States Treasury regulations which will require more time, information and resources than currently available to us. UNRECOGNIZED TAX BENEFITS Year ended December 31, 2017 2016 (millions of Canadian dollars) Unrecognized tax benefits at beginning of year 84 65 Gross increases for tax positions of current year 15 27 Gross increases for tax positions of prior year 65 — Change in translation of foreign currency (2 ) (2 ) Lapses of statute of limitations (8 ) (6 ) Settlements (4 ) — Unrecognized tax benefits at end of year 150 84 The unrecognized tax benefits as at December 31, 2017 , if recognized, would impact our effective income tax rate. We do not anticipate further adjustments to the unrecognized tax benefits during the next 12 months that would have a material impact on our consolidated financial statements. We recognize accrued interest and penalties related to unrecognized tax benefits as a component of income taxes. Income taxes for the years ended December 31, 2017 and 2016 included $3 million and $1 million recoveries, respectively, of interest and penalties. As at December 31, 2017 and 2016 , interest and penalties of $8 million and $6 million , respectively, have been accrued.

PENSION AND OTHER POSTRETIREMEN

PENSION AND OTHER POSTRETIREMENT BENEFITS	12 Months Ended
	Dec. 31, 2017
Retirement Benefits [Abstract]
PENSION AND OTHER POSTRETIREMENT BENEFITS	PENSION AND OTHER POSTRETIREMENT BENEFITS PENSION PLANS We maintain registered and non-registered, contributory and non-contributory pension plans which provide defined benefit and/or defined contribution pension benefits covering substantially all employees. The Canadian Plans provide Company funded defined benefit and/or defined contribution pension benefits to our Canadian employees. The United States Plans provide Company funded defined benefit pension benefits to our United States employees. We also maintain supplemental pension plans that provide pension benefits in excess of the basic plans for certain employees. Defined Benefit Plans Benefits payable from the defined benefit plans are based on each plan participant’s years of service and final average remuneration. These benefits are partially inflation-indexed after a plan participant’s retirement. Our contributions are made in accordance with independent actuarial valuations and are invested primarily in publicly-traded equity and fixed income securities. Defined Contribution Plans Contributions are generally based on each plan participant’s age, years of service and current eligible remuneration. For defined contribution plans, benefit costs equal amounts required to be contributed by us. Benefit Obligation, Plan Assets and Funded Status The following table details the changes in the projected benefit obligation, the fair value of plan assets and the recorded asset or liability for our defined benefit pension plans: Canada United States December 31, 2017 2016 2017 2016 (millions of Canadian dollars) Change in projected benefit obligation Projected benefit obligation at beginning of year 2,270 2,064 508 487 Service cost 156 129 48 26 Interest cost 116 73 35 16 Actuarial loss 145 97 57 15 Benefits paid (165 ) (87 ) (42 ) (21 ) Foreign currency exchange rate changes — — (63 ) (14 ) Acquired in Merger Transaction 1,505 — 811 — Plan settlements — — (59 ) — Other 6 (6 ) (16 ) (1 ) Projected benefit obligation at end of year 1 4,033 2,270 1,279 508 Change in plan assets Fair value of plan assets at beginning of year 2,019 1,886 361 343 Actual return on plan assets 308 146 113 22 Employer contributions 161 74 57 28 Benefits paid (165 ) (87 ) (42 ) (21 ) Foreign currency exchange rate changes — — (51 ) (10 ) Acquired in Merger Transaction 1,290 — 731 — Plan settlements — — (59 ) — Other 6 — (13 ) (1 ) Fair value of plan assets at end of year 2 3,619 2,019 1,097 361 Underfunded status at end of year (414 ) (251 ) (182 ) (147 ) Presented as follows: Deferred amounts and other assets 38 5 — — Accounts payable and other (60 ) — (3 ) — Other long-term liabilities (392 ) (256 ) (179 ) (147 ) (414 ) (251 ) (182 ) (147 ) 1 The accumulated benefit obligation for our Canadian pension plans was $3.7 billion and $ 978 million as at December 31, 2017 and 2016 , respectively. The accumulated benefit obligation for our United States pension plans was $ $1.2 billion and $ 462 million as at December 31, 2017 and 2016 , respectively. 2 Assets in the amount of $ 9 million ( 2016 - $ 8 million ) and $ 40 million ( 2016 - $ 44 million ), related to our Canadian and United States non-registered supplemental pension plan obligations, are held in grantor trusts that, in accordance with federal tax regulations, are not restricted from creditors. These assets are committed for the future settlement of benefit obligations included in the underfunded status as at the end of the year, however they are excluded from plan assets for accounting purposes. Certain of our pension plans have accumulated benefit obligations in excess of the fair value of plan assets. For these plans, the projected benefit obligations, accumulated benefit obligations and the fair value of plan assets were as follows: Canada United States December 31, 2017 2016 2017 2016 (millions of Canadian dollars) Projected benefit obligations 1,444 2,188 1,280 508 Accumulated benefit obligations 1,306 978 1,217 462 Fair value of plan assets 1,131 1,927 1,098 361 Amount Recognized in Accumulated Other Comprehensive Income The amounts of pre-tax AOCI relating to our pension plans are as follows: Canada United States December 31, 2017 2016 2017 2016 (millions of Canadian dollars) Net actuarial gain 334 310 112 121 Total amount recognized in AOCI 334 310 112 121 Net Benefit Costs Recognized The components of net benefit cost and other amounts recognized in pre-tax OCI related to our pension plans are as follows: Canada United States Year ended December 31, 2017 2016 2015 2017 2016 2015 (millions of Canadian dollars) Service cost 156 129 137 48 26 30 Interest cost 116 73 81 35 16 17 Expected return on plan assets (201 ) (127 ) (120 ) (57 ) (21 ) (22 ) Amortization of actuarial loss 29 32 39 10 3 10 Net defined benefit costs 100 107 137 36 24 35 Defined contribution benefit costs 11 3 3 15 — — Net benefit cost recognized in Earnings 111 110 140 51 24 35 Amount recognized in OCI: Net actuarial (gain)/loss arising during the year 38 28 (58 ) — 16 (19 ) Amortization of net actuarial gain (14 ) (14 ) (20 ) (9 ) (6 ) (10 ) Total amount recognized in OCI 24 14 (78 ) (9 ) 10 (29 ) Total amount recognized in Comprehensive income 135 124 62 42 34 6 We estimate that approximately $25 million related to the Canadian pension plans and $4 million related to the United States pension plans as at December 31, 2017 will be reclassified from AOCI into earnings in the next 12 months. Actuarial Assumptions The weighted average assumptions made in the measurement of the projected benefit obligations and net benefit cost of our pension plans are as follows: Canada United States 2017 2016 2015 2017 2016 2015 Projected benefit obligations Discount rate 3.6 % 4.0 % 4.2 % 3.5 % 4.0 % 4.1 % Rate of salary increase 3.2 % 3.7 % 3.6 % 3.1 % 3.3 % 3.3 % Net benefit cost Discount rate 4.0 % 4.2 % 4.0 % 4.0 % 4.1 % 3.7 % Rate of return on plan assets 6.5 % 6.5 % 4.4 % 7.2 % 7.2 % 7.1 % Rate of salary increase 3.7 % 3.6 % 2.5 % 3.3 % 3.2 % 4.0 % The overall expected rate of return is based on the asset allocation targets with estimates for returns on equity and debt securities based on long-term expectations. OTHER POSTRETIREMENT BENEFITS OPEB primarily includes supplemental health and dental, health spending accounts and life insurance coverage for qualifying retired employees on a non-contributory basis. The following table details the changes in the accumulated postretirement benefit obligation, the fair value of plan assets and the recorded asset or liability for our OPEB plans: Canada United States December 31, 2017 2016 2017 2016 (millions of Canadian dollars) Change in accumulated postretirement benefit obligation Accumulated postretirement benefit obligation at beginning of year 179 173 133 135 Service cost 7 4 5 4 Interest cost 10 6 10 5 Participant contributions — — 4 1 Actuarial (gain)/loss (8 ) 2 (34 ) 10 Benefits paid (10 ) (6 ) (19 ) (6 ) Foreign currency exchange rate changes — — (17 ) (4 ) Acquired in Merger Transaction 146 — 254 — Other (3 ) — 1 (12 ) Accumulated postretirement benefit obligation at end of year 321 179 337 133 Change in plan assets Fair value of plan assets at beginning of year — — 115 115 Actual return on plan assets — — 21 5 Employer contributions 10 6 1 3 Participant contributions — — 4 1 Benefits paid (10 ) (6 ) (19 ) (6 ) Foreign currency exchange rate changes — — (11 ) (3 ) Acquired in Merger Transaction — — 102 — Fair value of plan assets at end of year — — 213 115 Underfunded status at end of year (321 ) (179 ) (124 ) (18 ) Presented as follows: Deferred amounts and other assets — — 7 4 Accounts payable and other (12 ) (7 ) (7 ) — Other long-term liabilities (309 ) (172 ) (124 ) (22 ) (321 ) (179 ) (124 ) (18 ) Amount Recognized in Accumulated Other Comprehensive Income The amounts of pre-tax AOCI relating to our OPEB plans are as follows: Canada United States December 31, 2017 2016 2017 2016 (millions of Canadian dollars) Net actuarial gain/(loss) 17 25 (15 ) 29 Prior service cost (2 ) 2 (11 ) (15 ) Total amount recognized in AOCI 15 27 (26 ) 14 Net Benefit Costs Recognized The components of net benefit cost and other amounts recognized in pre-tax OCI related to our OPEB plans are as follows: Canada United States Year ended December 31, 2017 2016 2015 2017 2016 2015 (millions of Canadian dollars) Service cost 7 4 3 5 4 5 Interest cost 10 6 7 10 5 4 Expected return on plan assets — — — (10 ) (6 ) (6 ) Amortization of actuarial loss and prior service cost 1 — 1 — — — Net OPEB cost recognized in Earnings 18 10 11 5 3 3 Amount recognized in OCI: Net actuarial (gain)/loss arising during the year (8 ) 2 2 (42 ) 12 16 Amortization of net actuarial (gain)/loss (1 ) (1 ) (1 ) 1 (1 ) — Prior service cost (3 ) — — 1 (12 ) (7 ) Total amount recognized in OCI (12 ) 1 1 (40 ) (1 ) 9 Total amount recognized in Comprehensive income 6 11 12 (35 ) 2 12 We estimate that approximately nil related to the Canadian OPEB plans and $2 million related to the United States OPEB plans as at December 31, 2017 will be reclassified from AOCI into earnings in the next 12 months. Actuarial Assumptions The weighted average assumptions made in the measurement of the accumulated postretirement benefit obligations and net benefit cost of our OPEB plans are as follows: Canada United States 2017 2016 2015 2017 2016 2015 Accumulated postretirement benefit obligations Discount rate 3.6 % 4.0 % 4.2 % 3.5 % 3.6 % 4.2 % Net OPEB cost Discount rate 4.0 % 4.2 % 4.0 % 4.0 % 3.8 % 3.9 % Rate of return on plan assets 6.0 % 6.0 % 6.0 % The overall expected rate of return is based on the asset allocation targets with estimates for returns on equity and debt securities based on long-term expectations. Assumed Health Care Cost Trend Rates The assumed rates for the next year used to measure the expected cost of benefits are as follows: Canada United States 2017 2016 2017 2016 Health care cost trend rate assumed for next year 5.5 % 5.4 % 7.4 % 6.9 % Rate to which the cost trend is assumed to decline (the ultimate trend rate) 4.4 % 4.5 % 4.5 % 4.5 % Year that the rate reaches the ultimate trend rate 2034 2034 2037 2037 A 1% change in the assumed health care cost trend rate would have the following effects for the year ended and as at December 31, 2017 : Canada United States 1% Increase 1% Decrease 1% Increase 1% Decrease (millions of Canadian dollars) Effect on total service and interest costs 2 (1 ) 1 (1 ) Effect on accumulated postretirement benefit obligation 28 (23 ) 20 (17 ) PLAN ASSETS We manage the investment risk of our pension funds by setting a long-term asset mix policy for each plan after consideration of: (i) the nature of pension plan liabilities; (ii) the investment horizon of the plan; (iii) the going concern and solvency funded status and cash flow requirements of the plan; (iv) our operating environment and financial situation and our ability to withstand fluctuations in pension contributions; and (v) the future economic and capital markets outlook with respect to investment returns, volatility of returns and correlation between assets. The asset allocation targets and major categories of plan assets are as follows: Canada United States Target December 31, Target December 31, Asset Category Allocation 2017 2016 Allocation 2017 2016 Equity securities 40.0 - 70.0% 52.0 % 47.0 % 52.5 - 70.0% 47.1 % 55.4 % Fixed income securities 27.5 - 60.0% 34.2 % 39.0 % 27.5 - 30.0% 47.7 % 33.0 % Other 0.0 - 20.0% 13.8 % 14.0 % 0.0 - 20.0% 5.2 % 11.6 % The following tables summarize the fair value of plan assets for our pension and OPEB plans recorded at each fair value hierarchy level. Pension Canada United States Level 1 1 Level 2 2 Level 3 3 Total Level 1 1 Level 2 2 Level 3 3 Total (millions of Canadian dollars) December 31, 2017 Cash and cash equivalents 169 — — 169 2 — — 2 Equity securities Canada 842 425 — 1,267 — — — — United States 427 — — 427 343 — — 343 Global 189 — — 189 122 52 — 174 Fixed income securities Government 933 — — 933 — — — — Corporate 301 3 — 304 522 1 — 523 Infrastructure and real estate 4 — — 340 340 — — 56 56 Forward currency contracts — (10 ) — (10 ) — (1 ) — (1 ) Total pension plan assets at fair value 2,861 418 340 3,619 989 52 56 1,097 December 31, 2016 Cash and cash equivalents 156 — — 156 3 — — 3 Equity securities United States 219 — — 219 54 — — 54 Canada 425 — — 425 — — — — Global 165 140 — 305 116 30 — 146 Fixed income securities Government 351 — — 351 — — — — Corporate 277 3 — 280 116 — — 116 Infrastructure and real estate 4 — — 281 281 — — 40 40 Forward currency contracts — 2 — 2 — 2 — 2 Total pension plan assets at fair value 1,593 145 281 2,019 289 32 40 361 OPEB Canada United States Level 1 1 Level 2 2 Level 3 3 Total Level 1 1 Level 2 2 Level 3 3 Total (millions of Canadian dollars) December 31, 2017 Cash and cash equivalents — — — — 1 — — 1 Equity securities United States — — — — 80 — — 80 Global — — — — 36 — — 36 Fixed income securities Government — — — — 96 — — 96 Total OPEB plan assets at fair value — — — — 213 — — 213 December 31, 2016 Cash and cash equivalents — — — — 1 — — 1 Equity securities United States — — — — 35 — — 35 Global — — — — 34 — — 34 Fixed income securities Government — — — — 45 — — 45 Total OPEB plan assets at fair value — — — — 115 — — 115 1 Level 1 assets include assets with quoted prices in active markets for identical assets. 2 Level 2 assets include assets with significant observable inputs. 3 Level 3 assets include assets with significant unobservable inputs. 4 The fair values of the infrastructure and real estate investments are established through the use of valuation models. Changes in the net fair value of plan assets classified as Level 3 in the fair value hierarchy were as follows: Canada United States December 31, 2017 2016 2017 2016 (millions of Canadian dollars) Balance at beginning of year 281 248 40 49 Unrealized and realized gains 26 20 5 2 Purchases and settlements, net 33 13 11 (11 ) Balance at end of year 340 281 56 40 EXPECTED BENEFIT PAYMENTS AND EMPLOYER CONTRIBUTIONS Year ended December 31, 2018 2019 2020 2021 2022 2023-2027 (millions of Canadian dollars) Pension Canada 158 165 172 180 187 1,036 United States 82 81 85 83 92 453 OPEB Canada 12 12 13 13 14 43 United States 25 25 25 25 24 110 In 2018 , we expect to contribute approximately $126 million and $36 million to the Canadian and United States pension plans, respectively, and $12 million and $7 million to the Canadian and United States OPEB plans, respectively. RETIREMENT SAVINGS PLANS In addition to the retirement plans discussed above, we also have defined contribution employee savings plans available to both Canadian and United States employees. Employees may participate in a matching contribution where we match a certain percentage of before-tax employee contributions of up to 5.0% of eligible pay per pay period for Canadian employees and up to 6.0% of eligible pay per pay period for United States employees. For the years ended December 31, 2017 , 2016 and 2015 , we expensed pre-tax employer matching contributions of $14 million , nil and nil for Canadian employees and $ 31 million , $ 13 million and $ 15 million for United States employees, respectively.

CHANGES IN OPERATING ASSETS AND

CHANGES IN OPERATING ASSETS AND LIABILITIES	12 Months Ended
	Dec. 31, 2017
CHANGES IN OPERATING ASSETS AND LIABILITIES
CHANGES IN OPERATING ASSETS AND LIABILITIES	CHANGES IN OPERATING ASSETS AND LIABILITIES Year ended December 31, 2017 2016 2015 (millions of Canadian dollars) Restricted Cash 15 — — Accounts receivable and other (783 ) (437 ) 698 Accounts receivable from affiliates 24 (7 ) 82 Inventory (289 ) (371 ) (315 ) Deferred amounts and other assets (138 ) (183 ) 364 Accounts payable and other 286 396 (1,472 ) Accounts payable to affiliates (62 ) 71 (26 ) Interest payable 124 20 31 Other long-term liabilities 509 153 (7 ) (314 ) (358 ) (645 )

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS	12 Months Ended
	Dec. 31, 2017
Related Party Transactions [Abstract]
RELATED PARTY TRANSACTIONS	RELATED PARTY TRANSACTIONS Related party transactions are conducted in the normal course of business and unless otherwise noted, are measured at the exchange amount, which is the amount of consideration established and agreed to by the related parties. SERVICE AGREEMENTS Vector Pipeline L.P. (Vector), a joint venture, contracts our services to operate the pipeline. Amounts for these services, which are charged at cost in accordance with service agreements, were $14 million for the year ended December 31, 2017 and $7 million for each of the years ended December 31, 2016 and 2015. TRANSPORTATION AGREEMENTS Certain wholly-owned subsidiaries within the Liquids Pipelines, Gas Transmission and Midstream, Gas Distribution and Energy Services segments have committed and uncommitted transportation arrangements with several joint venture affiliates that are accounted for using the equity method. Total amounts charged to us for transportation services for the years ended December 31, 2017 , 2016 and 2015 were $417 million , $357 million and $332 million , respectively. LEASE AGREEMENTS A wholly-owned subsidiary within the Liquids Pipelines segment has a lease arrangement with a joint venture affiliate. During the years ended December 31, 2017 , 2016 and 2015 , expenses related to the lease arrangement totaled $304 million , $287 million and $151 million , respectively, and were recorded to Operating and administrative expense in the Consolidated Statements of Earnings. AFFILIATE REVENUES AND PURCHASES Certain wholly-owned subsidiaries within the Gas Distribution and Energy Services segments made natural gas and NGL purchases of $142 million , $98 million and $228 million from several joint venture affiliates during the years ended December 31, 2017 , 2016 and 2015 , respectively. Natural gas sales of $60 million , $49 million and $5 million were made by certain wholly-owned subsidiaries within the Energy Services segment to several joint venture affiliates during the years ended December 31, 2017 , 2016 and 2015 , respectively. DCP Midstream processes certain of our pipeline customers' gas to meet gas quality specifications in order to be transported on our system. DCP Midstream processes the gas and sells the NGLs that are extracted from the gas. A portion of the proceeds from those sales are retained by DCP Midstream and the balance is remitted to us. We received proceeds of $ 47 million (US$ 36 million ) during the year ended December 31, 2017 from DCP Midstream related to those sales. In addition to the above, we recorded other revenues from DCP Midstream and its affiliates related to the transportation and storage of natural gas of $ 4 million (US$ 3 million ) during the year ended December 31, 2017 . In the ordinary course of business, we are reimbursed by joint venture partners for operating and maintenance expenses for certain projects. We received reimbursements from Spectra Energy joint ventures of $ 10 million (US$ 8 million ) during the year ended December 31, 2017 . RECOVERIES OF COSTS We provide certain administrative and other services to certain operating entities acquired through the Merger Transaction, and recorded recoveries of costs from these affiliates of $ 88 million (US $68 million ) for the year ended December 31, 2017. Cost recoveries are recorded as a reduction to Operating and administrative expense in the Consolidated Statements of Earnings. LONG-TERM NOTES RECEIVABLE FROM AFFILIATES As at December 31, 2017 , amounts receivable from affiliates include a series of loans to Vector and other affiliates totaling $109 million and $167 million , respectively ( $130 million and $140 million , respectively as at December 31, 2016), which require quarterly interest payments at annual interest rates ranging from 4% to 12% . These amounts are included in Deferred amounts and other assets in the Consolidated Statements of Financial position.

COMMITMENTS AND CONTINGENCIES

COMMITMENTS AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	COMMITMENTS AND CONTINGENCIES COMMITMENTS At December 31, 2017 , we have commitments as detailed below. Total Less than 1 year 2 years 3 years 4 years 5 years Thereafter (millions of Canadian dollars) Annual debt maturities 1,2 62,927 2,831 6,273 6,722 2,505 8,839 35,757 Interest obligations 2,3 42,083 2,485 2,298 2,117 1,941 1,853 31,389 Purchase of services, pipe and other materials, including transportation 4,5 14,396 4,144 2,455 1,496 1,255 1,163 3,883 Operating leases 746 91 86 80 74 78 337 Capital leases 35 9 8 2 2 2 12 Maintenance agreements 322 38 32 17 15 15 205 Land lease commitments 405 15 16 16 16 16 326 Total 120,914 9,613 11,168 10,450 5,808 11,966 71,909 1 Includes debentures, term notes, commercial paper and credit facility draws based on the facility's maturity date and excludes short-term borrowings, debt discount, debt issue costs and capital lease obligations. We have the ability under certain debt facilities to call and repay the obligations prior to scheduled maturities. Therefore, the actual timing of future cash repayments could be materially different than presented above. 2 Excludes the debt issuance of US$800 million senior notes that occurred subsequent to December 31, 2017 (Note 30) . 3 Includes debentures and term notes bearing interest at fixed, floating and fixed-to-floating rates. 4 Includes capital and operating commitments. 5 Consists primarily of gas transportation and storage contracts (EGD), firm capacity payments and gas purchase commitments (Spectra Energy), transportation, service and product purchase obligations (MEP), and power commitments (EEP). Total rental expense for operating leases included in Operating and administrative expense were $ 118 million , $ 85 million and $ 72 million for the years ended December 31, 2017 , 2016 and 2015 , respectively. ENVIRONMENTAL We are subject to various federal, state and local laws relating to the protection of the environment. These laws and regulations can change from time to time, imposing new obligations on us. Environmental risk is inherent to liquid hydrocarbon and natural gas pipeline operations, and Enbridge and our affiliates are, at times, subject to environmental remediation at various contaminated sites. We manage this environmental risk through appropriate environmental policies and practices to minimize any impact our operations may have on the environment. To the extent that we are unable to recover payment for environmental liabilities from insurance or other potentially responsible parties, we will be responsible for payment of liabilities arising from environmental incidents associated with the operating activities of our liquids and natural gas businesses. Lakehead System Lines 6A and 6B Crude Oil Releases Line 6B Crude Oil Release On July 26, 2010, a release of crude oil on Line 6B of EEP’s Lakehead System was reported near Marshall, Michigan. Further, on September 9, 2010, a release of crude oil from Line 6A of EEP’s Lakehead System was reported in an industrial area of Romeoville, Illinois. As at December 31, 2017 , EEP’s total cost estimate for the Line 6B crude oil release remains at US $1.2 billion ( $195 million after-tax attributable to us) including those costs that were considered probable and that could be reasonably estimated as at December 31, 2017 . As at December 31, 2017 , EEP's remaining estimated liability is approximately US$ 62 million . Insurance EEP is included in the comprehensive insurance program that is maintained by Enbridge for its subsidiaries and affiliates. As at December 31, 2017 , EEP has recorded total insurance recoveries of US$ 547 million ($ 80 million after-tax attributable to us) for the Line 6B crude oil release out of the US$ 650 million applicable limit. Of the remaining US$ 103 million coverage limit, US$ 85 million was the subject matter of a lawsuit against one particular insurer. In March 2015, we reached an agreement with that insurer to submit the US$ 85 million claim to binding arbitration. On May 2, 2017, the arbitration panel issued a decision that was not favorable to us. As a result, EEP will not receive any additional insurance recoveries in connection with the Line 6B crude oil release. Legal and Regulatory Proceedings A number of United States governmental agencies and regulators initiated investigations into the Line 6B crude oil release. As at December 31, 2017 , there are no claims pending against Enbridge, EEP or their affiliates in United States state courts in connection with the 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 note. Line 6B Fines and Penalties As at December 31, 2017 , EEP’s total estimated costs related to the Line 6B crude oil release include US$ 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, approved the Consent Decree. The Consent Decree is EEP’s signed settlement agreement with the United States Environmental Protection Agency (EPA) and the DOJ regarding the Lines 6A and 6B crude oil releases. On June 15, 2017, we made a total payment of US$68 million as required by the Consent Decree, which reflects US$61 million for the civil penalty for the Line 6B release, US$1 million for the Line 6A release, and US$6 million for past removal costs and interest. AUX SABLE Notice of Violation In September 2014, Aux Sable US received a Notice and Finding of Violation (NFOV) from the United States EPA for alleged violations of the Clean Air Act related to the Leak Detection and Repair program, and related provisions of the Clean Air Act permit for Aux Sable’s Channahon, Illinois facility. As part of the ongoing process of responding to the September 2014 NFOV, Aux Sable discovered what it believed to be an exceedance of currently permitted limits for Volatile Organic Material. In April 2015, a second NFOV from the EPA was received in connection with this potential exceedance. Aux Sable engaged in discussions with the EPA to evaluate the impacts and ultimate resolution of these issues, including with respect to a draft Consent Decree, and those discussions are continuing. The Consent Decree, when finalized, is not expected to have a material impact. On October 14, 2016, an amended claim was filed against Aux Sable by a counterparty to an NGL supply agreement. On January 5, 2017, Aux Sable filed a Statement of Defence with respect to this claim. While the final outcome of this action cannot be predicted with certainty, at this time management believes that the ultimate resolution of this action will not have a material impact on the our consolidated financial position or results of operations. TAX MATTERS We maintain tax liabilities related to uncertain tax positions. While fully supportable in our view, these tax positions, if challenged by tax authorities, may not be fully sustained on review. OTHER LITIGATION We are subject to various other 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. While the final outcome of such actions and proceedings cannot be predicted with certainty, management believes that the resolution of such actions and proceedings will not have a material impact on our consolidated financial position or results of operations.

GUARANTEES

GUARANTEES	12 Months Ended
	Dec. 31, 2017
Guarantees [Abstract]
GUARANTEES	GUARANTEES In the normal course of conducting business, we enter into agreements which indemnify third parties and affiliates. Examples include indemnifying counterparties pursuant to sale agreements for assets or businesses in matters such as breaches of representations, warranties or covenants, loss or damages to property, environmental liabilities, changes in laws, valuation differences, and litigation and contingent liabilities. We may indemnify the purchaser for certain tax liabilities incurred while we owned the assets or for a misrepresentation related to taxes that result in a loss to the purchaser. Similarly, we may indemnify the purchaser of assets for certain tax liabilities related to those assets. As discussed below, these contracts include financial guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications. We enter into these arrangements to facilitate commercial transactions with third parties by enhancing the value of the transactions to the third parties. To varying degrees, these guarantees involve elements of performance and credit risk, which are not included on our Consolidated Statements of Financial Position. The possibility of having to perform under these guarantees and indemnifications is largely dependent upon future operations of various subsidiaries, investees and other third parties, or the occurrence of certain future events. We cannot reasonably estimate the maximum potential amounts that could become payable to third parties and affiliates under these agreements; however, historically, we have not made any significant payments under indemnification provisions. While these agreements may specify a maximum potential exposure, or a specified duration to the indemnification obligation, there are circumstances where the amount and duration are unlimited. The indemnifications and guarantees have not had, and are not reasonably likely to have, a material effect on our financial condition, changes in financial condition, earnings, liquidity, capital expenditures or capital resources. We have agreed to indemnify EEP from and against substantially all liabilities, including liabilities relating to environmental matters, arising from operations prior to the transfer of our pipeline operations to EEP in 1991. This indemnification does not apply to amounts that EEP would be able to recover in its tariff rates if not recovered through insurance or to any liabilities relating to a change in laws after December 27, 1991. We have also agreed to indemnify EEM for any tax liability related to EEM’s formation, management of EEP and ownership of i-units of EEP. We have not made any significant payment under these tax indemnifications. We do not believe there is a material exposure at this time. We have agreed to indemnify the Fund Group for certain liabilities relating to environmental matters arising from operations prior to the transfer of certain assets and interests to the Fund Group in 2012 and prior to the transfer of certain assets and interests to the Fund Group as part of the Canadian Restructuring Plan. We have also agreed to pay defined payments to the Fund Group on their investment in Southern Lights Pipeline in the event shippers do not elect to extend their current contracts post June 2025. In connection with Spectra Energy's spin-off from Duke Energy in 2007, certain guarantees that were previously issued by Spectra Energy were assigned to, or replaced by, Duke Energy as guarantor in 2006. For any remaining guarantees of other Duke Energy obligations, Duke Energy has indemnified Spectra Energy against any losses incurred under these guarantee arrangements. The maximum potential amount of future payments we could have been required to make under these performance guarantees as at December 31, 2017 was approximately US $406 million , which has been indemnified by Duke Energy as discussed above. One of these outstanding performance guarantees, which has a maximum potential future payment of US $201 million , expires in 2028. The remaining guarantees have no contractual expirations. Spectra Energy has also issued joint and several guarantees to some of the Duke/Fluor Daniel (D/FD) project owners, guaranteeing the performance of D/FD under its engineering, procurement and construction contracts and other contractual commitments in place at the time of Spectra Energy's spin-off from Duke Energy. D/FD is one of the entities transferred to Duke Energy in connection with Spectra Energy's spin-off. Substantially all of these guarantees have no contractual expiration and no stated maximum amount of future payments that we could be required to make. Fluor Enterprises Inc., as 50% owner in D/FD, issued similar joint and several guarantees to the same D/FD project owners. In connection with Spectra Energy's 50% ownership in DCP Midstream, Spectra Energy has agreed to guarantee their portion of the obligations of the joint venture under a US $424 million term loan agreement of which US $350 million is outstanding as at December 31, 2017. If DCP Midstream fails to meet its obligations under the credit agreement, Spectra Energy's maximum potential total future payments to lenders under the guarantee based on the amounts outstanding as at December 31, 2017 would be US $175 million . The guarantee will terminate upon the payment of all obligations under the credit agreement, which expires in December 2019. SEP has issued performance guarantees to a third party and an affiliate on behalf of an equity method investee. These guarantees were issued to enable the equity method investee to enter into long-term transportation contracts with the third party. While the likelihood is remote, the maximum potential amount of future payments that could be required to be made as at December 31, 2017 is US $90 million . These performance guarantees expire in 2032. Westcoast Energy Inc., a 100% -owned subsidiary, has issued performance guarantees to third parties guaranteeing the performance of unconsolidated entities, such as equity method investees, and of entities previously sold by Westcoast Energy Inc. to third parties. Those guarantees require Westcoast Energy Inc. to make payment to the guaranteed third party upon the failure of such unconsolidated or sold entity to make payment under some of its contractual obligations, such as debt agreements, purchase contracts and leases.

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS	12 Months Ended
	Dec. 31, 2017
Subsequent Events [Abstract]
SUBSEQUENT EVENTS	SUBSEQUENT EVENTS On January 9, 2018, Texas Eastern Transmission, LP, a wholly-owned operating subsidiary of SEP, completed an offering of US$800 million of senior notes, which consisted of two US$400 million tranches with fixed interest rates of 3.50% and 4.15% which mature in 2028 and 2048, respectively. On January 22, 2018, Enbridge and SEP announced the execution of a definitive agreement, resulting in us converting all of our incentive distribution rights (IDRs) and general partner economic interests in SEP into 172.5 million newly issued SEP common units. As part of the transaction, all of the IDRs have been eliminated. We now hold a non-economic general partner interest in SEP and own approximately 403 million of SEP common units, representing approximately 83% of SEP's outstanding common units.

QUARTERLY FINANCIAL DATA

QUARTERLY FINANCIAL DATA	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
QUARTERLY FINANCIAL DATA	QUARTERLY FINANCIAL DATA Q1 Q2 Q3 Q4 Total (unaudited; millions of Canadian dollars, except per share amounts) 2017 1 Operating revenues 11,146 11,116 9,227 12,889 44,378 Operating income/(loss) 1,358 1,684 1,490 (2,961 ) 1,571 Earnings 945 1,241 1,015 65 3,266 Earnings attributable to controlling interests 721 1,000 847 291 2,859 Earnings attributable to common shareholders 638 919 765 207 2,529 Earnings per common share Basic 0.54 0.56 0.47 0.13 1.66 Diluted 0.54 0.56 0.47 0.12 1.65 2016 Operating revenues 8,795 7,939 8,488 9,338 34,560 Operating income/(loss) 1,674 794 (216 ) 329 2,581 Earnings/(loss) 1,347 352 (237 ) 847 2,309 Earnings/(loss) attributable to controlling interests 1,286 372 (30 ) 441 2,069 Earnings/(loss) attributable to common shareholders 1,213 301 (103 ) 365 1,776 Earnings/(loss) per common share Basic 1.38 0.33 (0.11 ) 0.39 1.95 Diluted 1.38 0.33 (0.11 ) 0.39 1.93 1 The 2017 quarterly financial data reflects the effect of the Merger Transaction closed on February 27, 2017 (Note 7) .

SUMMARY OF ACCOUNTING POLICIES

SUMMARY OF 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 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. Significant estimates and assumptions used in the preparation of the consolidated financial statements include, but are not limited to: carrying values of regulatory assets and liabilities (Note 6) ; purchase price allocations (Note 7) ; unbilled revenues; depreciation rates and carrying value of property, plant and equipment (Note 10) ; amortization rates of intangible assets (Note 14) ; measurement of goodwill (Note 15) ; fair value of asset retirement obligations (ARO) (Note 18) ; valuation of stock-based compensation (Note 21) ; fair value of financial instruments (Note 23) ; provisions for income taxes (Note 24) ; assumptions used to measure retirement and other postretirement benefit obligations (OPEB) (Note 25) ; commitments and contingencies (Note 28) ; and estimates of losses related to environmental remediation obligations (Note 28) . Actual results could differ from these estimates.
PRINCIPLES OF CONSOLIDATION	PRINCIPLES OF CONSOLIDATION The consolidated financial statements include our accounts and accounts of our subsidiaries and variable interest entities (VIEs) for which we are the primary beneficiary. A VIE is a legal entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support or is structured such that equity investors lack the ability to make significant decisions relating to the entity’s operations through voting rights or do not substantively participate in the gains and losses of the entity. 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. 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 entity that could potentially be significant to the VIE. Where we conclude that we are the primary beneficiary of a VIE, we will consolidate the accounts of that VIE. We assess all variable interests in the entity and use our judgment when determining if we are the primary beneficiary. 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. We assess the primary beneficiary determination for a VIE on an ongoing basis, as there are changes in the facts and circumstances related to a VIE. The consolidated financial statements also include the accounts of any limited partnerships where we represent the general partner and, based on all facts and circumstances, control such limited partnerships, unless the limited partner has substantive participating rights or substantive kick-out rights. For certain investments where we retain an undivided interest in assets and liabilities, we record our proportionate share of assets, liabilities, revenues and expenses. If an entity is determined to not be a VIE, the voting interest entity model will be applied. 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 noncontrolling interests and redeemable noncontrolling interests. Investments and entities over which we exercise significant influence are accounted for using the equity method. As a result of the Canadian Restructuring Plan, ECT, our subsidiary, determines its equity investment earnings from EIPLP using the Hypothetical Liquidation at Book Value (HLBV) method. ECT applies the HLBV method to its equity method investments where cash distributions, including both preference and residual distributions, are not based on the investor’s ownership percentages. Under the HLBV method, a calculation is prepared at each balance sheet date to determine the amount that ECT would receive if EIPLP were to liquidate all of its assets, as valued in accordance with U.S. GAAP, and distribute that cash to the investors. The difference between the calculated liquidation distribution amounts at the beginning and the end of the reporting period, after adjusting for capital contributions and distributions, is ECT’s share of the earnings or losses from the equity investment for the period. While ECT and EIPLP are both consolidated in these financial statements, the use of the HLBV method by ECT impacts the earnings attributable to redeemable noncontrolling interests reported on Enbridge’s Consolidated Statements of Earnings. We continue to recognize Redeemable noncontrolling interests on the Consolidated Statements of Financial Position at the maximum redemption value of the trust units held by third parties, which references the market price of ENF common shares.
REGULATION	REGULATION Certain parts of our businesses are subject to regulation by various authorities including, but not limited to, the National Energy Board (NEB), the Federal Energy Regulatory Commission (FERC), the Alberta Energy Regulator, the New Brunswick Energy and Utilities Board (EUB), the Ontario Energy Board (OEB) and La Régie de l’Energie du Québec. Regulatory bodies exercise statutory authority over matters such as construction, rates and ratemaking and agreements with customers. 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. Regulatory assets represent amounts that are expected to be recovered from customers in future periods through rates. Regulatory liabilities represent amounts that are expected to be refunded to customers in future periods through rates or expected to be paid to cover future abandonment costs in relation to the NEB’s Land Matters Consultation Initiative (LMCI). Long-term regulatory assets are recorded in Deferred amounts and other assets and current regulatory assets are recorded in Accounts receivable and other. Long-term regulatory liabilities are included in Other long-term liabilities and current regulatory liabilities are recorded in Accounts payable and other. Regulatory assets are assessed for impairment if we identify an event indicative of possible impairment. The recognition of regulatory assets and liabilities is based on the actions, or expected future actions, of the regulator. To the extent that the regulator’s actions differ from our expectations, the timing and amount of recovery or settlement of regulatory balances could differ significantly from those recorded. In the absence of rate regulation, we would generally not recognize regulatory assets or liabilities and the earnings impact would be recorded in the period the expenses are incurred or revenues are earned. A regulatory asset or liability is recognized in respect of deferred income taxes when it is expected the amounts will be recovered or settled through future regulator-approved rates. 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 its cost of borrowing, whereas the capitalized equity component, the corresponding earnings during the construction phase and the subsequent depreciation would not be recognized. For certain regulated operations to which U.S. GAAP guidance for phase-in plans applies, negotiated depreciation rates recovered in transportation tolls may be less than the depreciation expense calculated in accordance with U.S. GAAP in early years of long-term contracts but recovered in future periods when tolls exceed depreciation. Depreciation expense on such assets is recorded in accordance with U.S. GAAP and no deferred regulatory asset is recorded (Note 6) . With the approval of the applicable regulator, EGD, Union Gas and certain distribution operations capitalize a percentage of specified operating costs. These operations are authorized to charge depreciation and earn a return on the net book value of such capitalized costs in future years. To the extent that the regulator’s actions differ from our expectations, the timing and amount of recovery or settlement of capitalized costs could differ significantly from those recorded. In the absence of rate regulation, a portion of such costs may be charged to current period earnings.
REVENUE RECOGNITION	REVENUE RECOGNITION For businesses that are not rate-regulated, revenues are recorded when products have been delivered or services have been performed, the amount of revenue can be reliably measured and collectability is reasonably assured. Customer credit worthiness is assessed prior to agreement signing, as well as throughout the contract duration. Certain revenues from liquids and gas pipeline businesses are recognized under the terms of committed delivery contracts rather than the cash tolls received. Long-term take-or-pay contracts, under which shippers are obligated to pay fixed amounts rateably over the contract period regardless of volumes shipped, may contain make-up rights. Make-up rights are earned by shippers when minimum volume commitments are not utilized during the period but under certain circumstances can be used to offset overages in future periods, subject to expiry periods. We recognize revenues associated with make-up rights at the earlier of when the make-up volume is shipped, the make-up right expires or when it is determined that the likelihood that the shipper will utilize the make-up right is remote. Certain offshore pipeline transportation contracts require Enbridge to provide transportation services for the life of the underlying producing fields. Under these arrangements, shippers pay Enbridge a fixed monthly toll for a defined period of time which may be shorter than the estimated reserve life of the underlying producing fields, resulting in a contract period which extends past the period of cash collection. Fixed monthly toll revenues are recognized ratably over the committed volume made available to shippers throughout the contract period, regardless of when cash is received. For the years ended December 31, 2017 , 2016 and 2015 , cash received net of revenue recognized for contracts under make-up rights and similar deferred revenue arrangements was $196 million , $249 million , and $61 million , respectively. For rate-regulated businesses, revenues are recognized in a manner that is consistent with the underlying agreements as approved by the regulators. Natural gas utilities revenues are recorded on the basis of regular meter readings and estimates of customer usage from the last meter reading to the end of the reporting period. Estimates are based on historical consumption patterns and heating degree days experienced. Heating degree days is a measure of coldness that is indicative of volumetric requirements for natural gas utilized for heating purposes in our distribution franchise area. Since July 1, 2011, Canadian Mainline (excluding Lines 8 and 9) earnings are governed by the Competitive Toll Settlement (CTS), under which revenues are recorded when services are performed. Effective on that date, we prospectively discontinued the application of rate-regulated accounting for those assets with the exception of flow-through income taxes covered by specific rate orders. For our energy marketing contracts, an estimate of revenues and commodity costs for the month of December is included in the Consolidated Statements of Earnings for each year based on the best available volume and price data for the commodity delivered and received.
DERIVATIVE INSTRUMENTS AND HEDGING	DERIVATIVE INSTRUMENTS AND HEDGING Non-qualifying Derivatives Non-qualifying derivative instruments are used primarily to economically hedge foreign exchange, interest rate and commodity price earnings exposure. Non-qualifying derivatives are measured at fair value with changes in fair value recognized in earnings in Transportation and other services revenues, Commodity costs, Operating and administrative expense, Other income/(expense) and Interest expense. Derivatives in Qualifying Hedging Relationships We use derivative financial instruments to manage our exposure to changes in commodity prices, foreign exchange rates, interest rates and certain compensation tied to our share price. Hedge accounting is optional and requires Enbridge to document the hedging relationship and test the hedging item’s effectiveness in offsetting changes in fair values or cash flows of the underlying hedged item on an ongoing basis. We present the earnings effects of hedging items with the hedged transaction. Derivatives in qualifying hedging relationships are categorized as cash flow hedges, fair value hedges or net investment hedges. Cash Flow Hedges We use cash flow hedges to manage our exposure to changes in commodity prices, foreign exchange rates, interest rates and certain compensation tied to our share price. The effective portion of the change in the fair value of a cash flow hedging instrument is recorded in Other comprehensive income/(loss) (OCI) and is reclassified to earnings when the hedged item impacts earnings. Any hedge ineffectiveness is recorded in current period earnings. If a derivative instrument designated as a cash flow hedge ceases to be effective or is terminated, hedge accounting is discontinued and the gain or loss at that date is deferred in OCI and recognized concurrently with the related transaction. If a hedged anticipated transaction is no longer probable, the gain or loss is recognized immediately in earnings. Subsequent gains and losses from derivative instruments for which hedge accounting has been discontinued are recognized in earnings in the period in which they occur. Fair Value Hedges We use fair value hedges to hedge the fair value of debt instruments. The change in the fair value of the hedging instrument is recorded in earnings with changes in the fair value of the hedged asset or liability that is designated as part of the hedging relationship. If a fair value hedge is discontinued or ceases to be effective, the hedged asset or liability, otherwise required to be carried at cost or amortized cost, ceases to be remeasured at fair value and the cumulative fair value adjustment to the carrying value of the hedged item is recognized in earnings over the remaining life of the hedged item. Net Investment Hedges Gains and losses arising from translation of net investment in foreign operations from their functional currencies to Enbridge’s Canadian dollar presentation currency are included in cumulative translation adjustments (CTA). We designate foreign currency derivatives and United States dollar denominated debt as hedges of net investments in United States dollar denominated foreign operations. As a result, the effective portion of the change in the fair value of the foreign currency derivatives as well as the translation of United States dollar denominated debt are reflected in OCI and any ineffectiveness is reflected in current period earnings. Amounts recognized previously in Accumulated other comprehensive income/(loss) (AOCI) are reclassified to earnings when there is a reduction of the hedged net investment resulting from disposal of a foreign operation. Classification of Derivatives We recognize the fair market value of derivative instruments on the Consolidated Statements of Financial Position as current and non-current assets or liabilities depending on the timing of the settlements and the resulting cash flows associated with the instruments. Fair value amounts related to cash flows occurring beyond one year are classified as non-current. Cash inflows and outflows related to derivative instruments are classified as Operating activities on the Consolidated Statements of Cash Flows. Balance Sheet Offset Assets and liabilities arising from derivative instruments may be offset in the Consolidated Statements of Financial Position when we have the legal right and intention to settle them on a net basis. 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 account 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 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.
RESTRICTED LONG-TERM INVESTMENTS	RESTRICTED LONG-TERM INVESTMENTS Long-term investments that are restricted as to withdrawal or usage, for the purposes of the NEB’s LMCI, are presented as Restricted long-term investments on the Consolidated Statements of Financial Position.
OTHER INVESTMENTS	OTHER INVESTMENTS Generally, we classify equity investments in entities over which we do not exercise significant influence and that do not trade on an actively quoted market as other investments carried at cost. Financial assets in this category are initially recorded at fair value with no subsequent re-measurement. Any investments which do trade on an active market are classified as available for sale investments measured at fair value through OCI. Dividends received from investments carried at cost are recognized in earnings when the right to receive payment is established.
NONCONTROLLING INTERESTS	NONCONTROLLING INTERESTS Noncontrolling interests represent ownership interests attributable to third parties in certain consolidated subsidiaries, limited partnerships and VIEs. The portion of equity not owned by us in such entities is reflected as Noncontrolling interests within the equity section of the Consolidated Statements of Financial Position and, in the case of redeemable noncontrolling interests, within the mezzanine section of the Consolidated Statements of Financial Position between long-term liabilities and equity. The Fund’s noncontrolling interest holders have the option to redeem the Fund trust units for cash, subject to certain limitations. Redeemable noncontrolling interests are recognized at the maximum redemption value of the trust units held by third parties, which references the market price of ENF common shares. On a quarterly basis, changes in estimated redemption values are reflected as a charge or credit to retained earnings. The use of the HLBV method by ECT impacts the earnings attributable to redeemable noncontrolling interests reported on our Consolidated Statements of Earnings.
INCOME TAXES	INCOME TAXES Income taxes are accounted for using the liability method. Deferred income tax assets and liabilities are recorded based on temporary differences between the tax bases of assets and liabilities and their carrying values for accounting purposes. Deferred income tax assets and liabilities are measured using the tax rate that is expected to apply when the temporary differences reverse. For our regulated operations, a deferred income tax liability or asset is recognized with a corresponding regulatory asset or liability, respectively, to the extent taxes can be recovered through rates. Any interest and/or penalty incurred related to tax is reflected in Income taxes.
FOREIGN CURRENCY TRANSACTIONS AND TRANSLATION	FOREIGN CURRENCY TRANSACTIONS AND TRANSLATION Foreign currency transactions are those transactions whose terms are denominated in a currency other than the currency of the primary economic environment in which Enbridge or a reporting subsidiary operates, referred to as the functional currency. Transactions denominated in foreign currencies are translated into the functional currency using the exchange rate prevailing at the date of transaction. Monetary assets and liabilities denominated in foreign currencies are translated to the functional currency using the rate of exchange in effect at the balance sheet date. Exchange gains and losses resulting from translation of monetary assets and liabilities are included in the Consolidated Statements of Earnings in the period in which they arise. Gains and losses arising from translation of foreign operations’ functional currencies to our Canadian dollar presentation currency are included in the CTA component of AOCI and are recognized in earnings upon sale of the foreign operation. Asset and liability accounts are translated at the exchange rates in effect on the balance sheet date, while revenues and expenses are translated using monthly average exchange rates.
CASH AND CASH EQUIVALENTS	CASH AND CASH EQUIVALENTS Cash and cash equivalents include short-term investments with a term to maturity of three months or less when purchased.
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 the Consolidated Statements of Financial Position.
LOANS AND RECEIVABLES	LOANS AND RECEIVABLES Affiliate long-term notes receivable are measured at amortized cost using the effective interest rate method, net of any impairment losses recognized. Accounts receivable and other are measured at cost.
ALLOWANCE FOR DOUBTFUL ACCOUNTS	ALLOWANCE FOR DOUBTFUL ACCOUNTS Allowance for doubtful accounts is determined based on collection history. When we have determined that further collection efforts are unlikely to be successful, amounts charged to the allowance for doubtful accounts are applied against the impaired accounts receivable.
NATURAL GAS IMBALANCES	NATURAL GAS IMBALANCES The Consolidated Statements of Financial Position include in-kind balances as a result of differences in gas volumes received and delivered for customers. Since settlement of certain imbalances is in-kind, changes in the balances do not have an effect on our Consolidated Statements of Earnings or Consolidated Statements of Cash Flows. Most natural gas volumes owed to or by us are valued at natural gas market index prices as at the balance sheet dates.
INVENTORY	INVENTORY Inventory is comprised of natural gas in storage held in EGD and Union Gas, and crude oil and natural gas held primarily by energy services businesses in the Energy Services segment. Natural gas in storage in EGD and Union Gas is recorded at the quarterly prices approved by the OEB in the determination of distribution rates. The actual price of gas purchased may differ from the OEB approved price. The difference between the approved price and the actual cost of the gas purchased is deferred as a liability for future refund or as an asset for collection as approved by the OEB. Other commodities inventory is recorded at the lower of cost, as determined on a weighted average basis, or market value. Upon disposition, other commodities inventory is recorded to Commodity costs on the Consolidated Statements of Earnings at the weighted average cost of inventory, including any adjustments recorded to reduce inventory to market value.
PROPERTY, PLANT AND EQUIPMENT	PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment is recorded at historical cost. Expenditures for construction, expansion, major renewals and betterments are capitalized. Maintenance and repair costs are expensed as incurred. Expenditures for project development are capitalized if they are expected to have future benefit. We capitalize interest incurred during construction for non-rate-regulated assets. For rate-regulated assets, 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. Two primary methods of depreciation are utilized. For distinct assets, depreciation is generally provided on a straight-line basis over the estimated useful lives of the assets commencing when the asset is placed in service. For largely homogeneous groups of assets with comparable useful lives, the pool method of accounting for property, plant and equipment is followed whereby similar assets are grouped and depreciated as a pool. When group assets are retired or otherwise disposed of, gains and losses are generally not reflected in earnings but are booked as an adjustment to accumulated depreciation.
DEFERRED AMOUNTS AND OTHER ASSETS	DEFERRED AMOUNTS AND OTHER ASSETS Deferred amounts and other assets primarily include: costs which regulatory authorities have permitted, or are expected to permit, to be recovered through future rates including deferred income taxes; contractual receivables under the terms of long-term delivery contracts; and derivative financial instruments.
INTANGIBLE ASSETS	INTANGIBLE ASSETS Intangible assets consist primarily of certain software costs, customer relationships and emission allowances. We capitalize costs incurred during the application development stage of internal use software projects . Customer relationships represent the underlying relationship from long-term agreements with customers that are capitalized upon acquisition. Emission allowances, which are recorded at their original cost, are purchased in order to meet greenhouse gas (GHG) compliance obligations. Intangible assets are generally amortized on a straight-line basis over their expected lives, commencing when the asset is available for use, with the exception of emission allowances, which are not amortized as they will be used to satisfy compliance obligations as they come due.
GOODWILL	GOODWILL Goodwill represents the excess of the purchase price over the fair value of net identifiable assets on acquisition of a business. The carrying value of goodwill, which is not amortized, is assessed for impairment annually, or more frequently if events or changes in circumstances arise that suggest the carrying value of goodwill may be impaired. We perform our annual review for impairment at the reporting unit level, which is identified by assessing whether the components of our operating segments constitute businesses for which discrete information is available, whether segment management regularly reviews the operating results of those components and whether the economic and regulatory characteristics are similar. We determined that our reporting units are equivalent to our reportable segments, with the exception of the gas transmission and gas midstream reportable segment which is divided at the component level into two reporting units. We have the option to first assess qualitative factors to determine whether it is necessary to perform the quantitative goodwill impairment test. The quantitative goodwill impairment test involves determining the fair value of our reporting units and comparing those values to the carrying value of each reporting unit. If the carrying value of a reporting unit, including allocated goodwill, exceeds its fair value, goodwill impairment is measured at the amount by which the reporting unit’s carrying value exceeds its fair value. This amount should not exceed the carrying amount of goodwill.
IMPAIRMENT	IMPAIRMENT We review the carrying values of our long-lived assets as events or changes in circumstances warrant. If it is determined that the carrying value of an asset exceeds the undiscounted cash flows expected from the asset, we calculate fair value based on the discounted cash flows and write the assets down to the extent that the carrying value exceeds the fair value. With respect to investments in debt and equity securities, we assess at each balance sheet date whether there is objective evidence that a financial asset is impaired by completing a quantitative or qualitative analysis of factors impacting the investment. If there is objective evidence of impairment, we value the expected discounted cash flows using observable market inputs and determine whether the decline below carrying value is other than temporary. If the decline is determined to be other than temporary, an impairment charge is recorded in earnings with an offsetting reduction to the carrying value of the asset. With respect to other financial assets, we assess the assets for impairment when there is no longer reasonable assurance of timely collection. If evidence of impairment is noted, we reduce the value of the financial asset to its estimated realizable amount, determined using discounted expected future cash flows.
ASSET RETIREMENT OBLIGATIONS	ASSET RETIREMENT OBLIGATIONS ARO associated with the retirement of long-lived assets are measured at fair value and recognized as Accounts payable and other or Other long-term liabilities in the period in which they can be reasonably determined. The fair value approximates the cost a third party would charge to perform the tasks necessary to retire such assets and is recognized at the present value of expected future cash flows. AROs are added to the carrying value of the associated asset and depreciated over the asset’s useful life. The corresponding liability is accreted over time through charges to earnings and is reduced by actual costs of decommissioning and reclamation. Our estimates of retirement costs could change as a result of changes in cost estimates and regulatory requirements.
RETIREMENT AND POSTRETIREMENT BENEFITS	RETIREMENT AND POSTRETIREMENT BENEFITS We maintain pension plans which provide defined benefit and defined contribution pension benefits. Defined benefit pension plan costs are determined using actuarial methods and are funded through contributions determined using the projected benefit method, which incorporates management’s best estimates of future salary levels, other cost escalations, retirement ages of employees and other actuarial factors including discount rates and mortality. We use mortality tables issued by the Society of Actuaries in the United States (revised in 2016) and the Canadian Institute of Actuaries tables (revised in 2014) to measure our benefit obligations of our United States pension plan (the United States Plan) and our Canadian pension plans (the Canadian Plans), respectively. We determine discount rates by reference to rates of high-quality long-term corporate bonds with maturities that approximate the timing of future payments we anticipate making under each of the respective plans. Pension cost is charged to earnings and includes: • Cost of pension plan benefits provided in exchange for employee services rendered during the year; • Interest cost of pension plan obligations; • Expected return on pension plan assets; • Amortization of the prior service costs and amendments on a straight-line basis over the expected average remaining service period of the active employee group covered by the plans; and • Amortization of cumulative unrecognized net actuarial gains and losses in excess of 10% of the greater of the accrued benefit obligation or the fair value of plan assets, over the expected average remaining service life of the active employee group covered by the plans. Actuarial gains and losses arise from the difference between the actual and expected rate of return on plan assets for that period or from changes in actuarial assumptions used to determine the accrued benefit obligation, including discount rate, changes in headcount or salary inflation experience. Pension plan assets are measured at fair value. The expected return on pension plan assets is determined using market related values and assumptions on the specific invested asset mix within the pension plans. The market related values reflect estimated return on investments consistent with long-term historical averages for similar assets. For defined contribution plans, contributions made by Enbridge are expensed in the period in which the contribution occurs. We also provide OPEB other than pensions, including group health care and life insurance benefits for eligible retirees, their spouses and qualified dependents. The cost of such benefits is accrued during the years in which employees render service. The overfunded or underfunded status of defined benefit pension and OPEB plans is recognized as Deferred amounts and other assets, Accounts payable and other or Other long-term liabilities, on the Consolidated Statements of Financial Position. A plan’s funded status is measured as the difference between the fair value of plan assets and the plan’s projected benefit obligation. Any unrecognized actuarial gains and losses and prior service costs and credits that arise during the period are recognized as a component of OCI, net of tax. Certain regulated utility operations of Enbridge record regulatory adjustments to reflect the difference between pension expense and OPEB costs for accounting purposes and the pension expense and OPEB costs for ratemaking purposes. Offsetting regulatory assets or liabilities are recorded to the extent pension expense or OPEB costs are expected to be collected from or refunded to customers, respectively, in future rates. In the absence of rate regulation, regulatory balances would not be recorded and pension and OPEB costs would be charged to earnings and OCI on an accrual basis.
STOCK-BASED COMPENSATION	STOCK-BASED COMPENSATION Incentive Stock Options (ISO) granted are recorded using the fair value method. Under this method, compensation expense is measured at the grant date based on the fair value of the ISO granted as calculated by the Black-Scholes-Merton model and is recognized on a straight-line basis over the shorter of the vesting period or the period to early retirement eligibility, with a corresponding credit to Additional paid-in capital. Balances in Additional paid-in capital are transferred to Share capital when the options are exercised. Restricted Stock Units (RSU) are cash settled awards for which the related liability is remeasured each reporting period. RSUs vest at the completion of a 35 -month term. During the vesting term, compensation expense is recorded based on the number of units outstanding and the current market price of Enbridge’s shares with an offset to Accounts payable and other or to Other long-term liabilities.
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 costs incurred 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 the Consolidated Statements of Financial Position at their undiscounted amounts. There is always a 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 the Consolidated Statements of Financial Position. Liabilities for other commitments and contingencies are recognized when, after fully analyzing 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 recognize the most likely amount, or if no amount is more likely than another, the minimum of the range of probable loss is accrued. We expense legal costs associated with loss contingencies as such costs are incurred.
CHANGE IN ACCOUNTING POLICY - GOODWILL	CHANGES IN ACCOUNTING POLICIES Goodwill We previously performed our annual goodwill impairment test on October 1 of each fiscal year. Beginning with the quarter ended December 31, 2017, we moved the annual goodwill impairment test from October 1 to April 1 to better align with the preparation and review of our business plan, which is used in the test. The change does not delay, accelerate or avoid an impairment charge.
ADOPTION OF NEW STANDARDS	ADOPTION OF NEW STANDARDS Simplifying the Measurement of Goodwill Impairment Effective January 1, 2017, we early adopted Accounting Standards Update (ASU) 2017-04 and applied the standard on a prospective basis. Under the new guidance, goodwill impairment will now be the amount by which a reporting unit’s carrying value exceeds its fair value; this amount should not exceed the carrying amount of goodwill. We applied this standard as at December 31, 2017 in the measurement of the goodwill impairment relating to the gas midstream reporting unit (Note 15) . Clarifying the Definition of a Business in an Acquisition Effective January 1, 2017, we early adopted 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. This accounting update was applied to acquisitions and dispositions that occurred in the year. 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. Improvements to Employee Share-Based Payment Accounting Effective January 1, 2017, we adopted ASU 2016-09 and applied certain amendments on a modified retrospective basis with the remaining amendments applied on a prospective basis. The new standard was issued with the intent of simplifying and improving several aspects of accounting for share-based payment transactions including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. 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 Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income ASU 2018-02 was issued in February 2018 to address a specific consequence of the Tax Cuts and Jobs Act (TCJA). This accounting update allows a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from TCJA. The amendments eliminate the stranded tax effects that were created as a result of the reduction of historical U.S. federal corporate income tax rate to the newly enacted U.S. federal corporate income tax rate. The accounting update is effective January 1, 2019, with early adoption permitted, and is to be applied either in the period of adoption or retrospectively to each period in which the effect of the change in the U.S. federal corporate income tax rate in the TCJA is recognized. We are currently assessing the impact of the new standard on the consolidated financial statements. 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 our consolidated financial statements. Clarifying Guidance on the Application of Modification Accounting on Stock Compensation ASU 2017-09 was issued in May 2017 with the intent to clarify the scope of modification accounting and when it should be applied to a change to the terms or conditions of a share based payment award. Under the new guidance, modification accounting is required for all changes to share based payment awards, unless all of the following are met: 1) there is no change to the fair value of the award, 2) the vesting conditions have not changed, and 3) the classification of the award as an equity instrument or a debt instrument has not changed. 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. Amending the Amortization Period for Certain Callable Debt Securities Purchased at a Premium ASU 2017-08 was issued in March 2017 with the intent of shortening the amortization period to the earliest call date for certain callable debt securities held at a premium. The accounting update is effective January 1, 2019 and will be applied on a modified retrospective basis. We are currently assessing the impact of the new standard on our consolidated financial statements. Improving the Presentation of Net Periodic Benefit Cost related to Defined Benefit Plans ASU 2017-07 was issued in March 2017 primarily to improve the income statement presentation of the components of net periodic pension cost and net periodic postretirement benefit cost for an entity’s sponsored defined benefit pension and OPEB plans. In addition, only the service cost component of net benefit cost is eligible for capitalization. The accounting update is effective January 1, 2018 and will be applied on a retrospective basis for the statement of earnings presentation component and a prospective basis for the capitalization component. We do not expect the adoption of this accounting update to have a material impact on our consolidated financial statements. Clarifying Guidance on Derecognition and Partial Sales of Nonfinancial Assets ASU 2017-05 was issued in February 2017 with the intent of clarifying the scope of asset derecognition guidance and accounting for partial sales of nonfinancial assets. The ASU clarifies the scope provisions of nonfinancial assets and how to allocate consideration to each distinct asset, and amends the guidance for derecognition of a distinct nonfinancial asset in partial sale transactions. The accounting update is effective January 1, 2018 and will be applied on a modified retrospective basis. We do not expect the adoption of this accounting update to have a material impact on our consolidated financial statements. Clarifying the Presentation of Restricted Cash in the Statement of Cash Flows ASU 2016-18 was issued in November 2016 with the intent to clarify guidance on the classification and presentation of changes in restricted cash and restricted cash equivalents within the statement of cash flows. The accounting update requires that changes in restricted cash and restricted cash equivalents be included within cash and cash equivalents when reconciling the opening and closing period amounts shown on the statement of cash flows. We currently present the changes in restricted cash and restricted cash equivalents under investing activities in the Consolidated Statement of Cash Flows. The accounting update is effective January 1, 2018 and will be applied on a retrospective basis. We will amend the presentation in the Consolidated Statement of Cash Flows to include restricted cash and restricted cash equivalents with cash and cash equivalents and we will retrospectively reclassify all periods presented. 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 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 our revenue recognition practices. Based on our assessment to-date, the adoption of the new standard will have the following impact to our financial statements: • A change in presentation in the Gas Distribution business related to payments to customers under the earnings sharing mechanism which are currently shown as an expense in the Consolidated Statements of Earnings. Under the new standard, these payments will be reflected as a reduction of revenue. • Estimates of variable consideration, required under the new standard for certain Liquids Pipelines, Gas Transmission and Midstream and Green Power and Transmission revenue contracts as well as the allocation of the transaction price for certain Liquids Pipelines revenue contracts, may result in changes to the pattern or timing of revenue recognition for those contracts. • Non-cash consideration received in the form of a percentage of the products derived from processing natural gas in the Gas Transmission and Midstream business was previously accounted for as revenue when the commodity was sold to third parties. Under the new standard, the non-cash consideration will be accounted for as revenue when processing services are performed. The commodity will continue to be accounted for as revenue when it is subsequently sold to third parties. The impact of this change will be an increase in costs and revenues due to the recognition of this non-cash consideration. • Service fee revenue, from processing natural gas for certain contracts in the Gas Transmission and Midstream business whereby Enbridge purchases natural gas at the wellhead, then processes and subsequently sells the gas, was previously presented as revenue. Under the new standard, processing fees charged on natural gas purchased by Enbridge are presented as a reduction of commodity costs upon the transfer of control of the natural gas at the wellhead . • Revenue from certain contracts in the Gas Transmission and Midstream business that provide for Enbridge to process and sell customers’ natural gas and retain a percentage of the resulting processed natural gas and/or NGLs as payment for processing services rendered, commonly referred to as Percentage of Proceeds and Percentage of Liquids contracts, was previously presented on a gross basis whereby Enbridge recorded one hundred percent of the value of the natural gas and products sold as revenue, with the cost of the natural gas purchased recorded as commodity cost. Under the new standard only Enbridge’s share of the products retained and sold is presented as revenue and no commodity cost is recorded. • Certain payments received from customers to offset the cost of constructing assets required to provide services to those customers, referred to as Contributions in Aid of Construction (CIAC) 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 as revenue 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. Upon adoption, we will recognize the significant cumulative effect of initially applying the new standard as an increase in the opening balance of retained deficit of approximately $120 million, an increase in property, plant and equipment of $130 million and an increase in deferred revenue of $120 million, subject to final determination, as at January 1, 2018. The adoption of the new standard will also result in changes in classification between Revenue and Commodity costs as discussed above. We have also developed and tested processes to generate the disclosures which will be required under the new standard commencing in the first quarter of 2018.

SEGMENTED INFORMATION (Tables)

SEGMENTED INFORMATION (Tables)	12 Months Ended
	Dec. 31, 2017
Segment Reporting [Abstract]
Schedule of reporting information by segment	Segmented information for the years ended December 31, 2017 , 2016 and 2015 are as follows: Year ended December 31, 2017 Liquids Pipelines Gas Transmission and Midstream Gas Distribution Green Power and Transmission Energy Services Eliminations and Other Consolidated (millions of Canadian dollars) Revenues 8,913 7,067 4,992 534 23,282 (410 ) 44,378 Commodity and gas distribution costs (18 ) (2,834 ) (2,689 ) — (23,508 ) 412 (28,637 ) Operating and administrative (2,949 ) (1,756 ) (960 ) (163 ) (47 ) (567 ) (6,442 ) Impairment of long-lived assets — (4,463 ) — — — — (4,463 ) Impairment of goodwill — (102 ) — — — — (102 ) Income/(loss) from equity investments 416 653 23 6 8 (4 ) 1,102 Other income/(expense) 33 166 24 (5 ) 2 232 452 Earnings/(loss) before interest, income tax expense, and depreciation and amortization 6,395 (1,269 ) 1,390 372 (263 ) (337 ) 6,288 Depreciation and amortization (3,163 ) Interest expense (2,556 ) Income tax recovery 2,697 Earnings 3,266 Capital expenditures 1 2,799 4,016 1,177 321 1 108 8,422 Total assets 63,881 60,745 25,956 6,289 2,514 2,708 162,093 Year ended December 31, 2016 Liquids Pipelines Gas Transmission and Midstream Gas Distribution Green Power and Transmission Energy Services Eliminations and Other Consolidated (millions of Canadian dollars) Revenues 8,176 2,877 2,976 502 20,364 (335 ) 34,560 Commodity and gas distribution costs (12 ) (2,206 ) (1,653 ) 5 (20,473 ) 334 (24,005 ) Operating and administrative (2,908 ) (446 ) (553 ) (173 ) (63 ) (215 ) (4,358 ) Impairment of long-lived assets (1,365 ) (11 ) — — — — (1,376 ) Income/(loss) from equity investments 194 223 12 2 (3 ) — 428 Other income/(expense) 841 27 49 8 (8 ) 115 1,032 Earnings/(loss) before interest, income tax expense, and depreciation and amortization 4,926 464 831 344 (183 ) (101 ) 6,281 Depreciation and amortization (2,240 ) Interest expense (1,590 ) Income tax expense (142 ) Earnings 2,309 Capital expenditures 1 3,957 176 713 251 — 32 5,129 Total assets 52,007 11,182 10,132 5,571 1,951 4,366 85,209 Year ended December 31, 2015 Liquids Pipelines Gas Transmission and Midstream Gas Distribution Green Power and Transmission Energy Services Eliminations and Other Consolidated (millions of Canadian dollars) Revenues 5,589 3,803 3,609 498 20,842 (547 ) 33,794 Commodity and gas distribution costs (9 ) (3,002 ) (2,349 ) 4 (20,443 ) 558 (25,241 ) Operating and administrative (2,748 ) (506 ) (536 ) (143 ) (66 ) (132 ) (4,131 ) Impairment of long-lived assets (80 ) (16 ) — — — — (96 ) Impairment of goodwill — (440 ) — — — — (440 ) Income/(loss) from equity investments 296 200 (10 ) 2 (9 ) (4 ) 475 Other income/(expense) (15 ) 4 49 2 — (742 ) (702 ) Earnings/(loss) before interest, income tax expense, and depreciation and amortization 3,033 43 763 363 324 (867 ) 3,659 Depreciation and amortization (2,024 ) Interest expense (1,624 ) Income tax expense (170 ) Loss (159 ) Capital expenditures 1 5,884 385 858 68 — 80 7,275 1 Includes allowance for equity funds used during construction.
Schedule of revenues by geographical segments	Revenues 1 Year ended December 31, 2017 2016 2015 (millions of Canadian dollars) Canada 18,076 12,470 11,087 United States 26,302 22,090 22,707 44,378 34,560 33,794 1 Revenues are based on the country of origin of the product or service sold.
Schedule of property, plant and equipment by geographical segments	Property, Plant and Equipment 1 December 31, 2017 2016 (millions of Canadian dollars) Canada 46,025 32,008 United States 44,686 32,276 90,711 64,284 1 Amounts are based on the location where the assets are held.

EARNINGS PER COMMON SHARE (Tabl

EARNINGS PER COMMON SHARE (Tables)	12 Months Ended
	Dec. 31, 2017
Earnings Per Share [Abstract]
Schedule of Weighted Average Shares Outstanding Used to Calculate Basic and Diluted Earnings Per Share	Weighted average shares outstanding used to calculate basic and diluted earnings per share are as follows: December 31, 2017 2016 2015 (number of shares in millions) Weighted average shares outstanding 1,525 911 847 Effect of dilutive options 7 7 — Diluted weighted average shares outstanding 1,532 918 847

REGULATORY MATTERS (Tables)

REGULATORY MATTERS (Tables)	12 Months Ended
	Dec. 31, 2017
Regulated Operations [Abstract]
Schedule of Regulatory Assets	Accounting for rate-regulated activities has resulted in the recognition of the following significant regulatory assets and liabilities: December 31, Recovery/Refund Period Ends 2017 2016 (millions of Canadian dollars) Regulatory assets/(liabilities) Liquids Pipelines Deferred income taxes Various 1,492 1,270 Tolling deferrals 2018 (34 ) (37 ) Recoverable income taxes Through 2030 46 51 Pipeline future abandonment costs 1 Various (141 ) (88 ) Gas Transmission and Midstream Deferred income taxes Various 717 — Regulatory liability related to income taxes 2 Various (1,078 ) — Other Various (16 ) — Gas Distribution Deferred income taxes Various 1,000 385 Purchased gas variance 3 Various 51 5 Pension plans and OPEB 4 Various 102 116 Constant dollar net salvage adjustment 2018 38 38 Future removal and site restoration reserves Various (1,066 ) (606 ) Site restoration clearance adjustment Various (31 ) (109 ) Other Various 31 (4 ) 1 Funds collected are included in Restricted long-term investments (Note 13) . 2 Relates to the establishment of a regulatory liability as a result of the United States tax reform legislation dated December 22, 2017. 3 Purchase gas variance is the difference between the actual cost and the approved cost of natural gas reflected in rates. EGD and Union Gas have been granted OEB approval to refund this balance to, or to collect this balance from, customers on a rolling 12-month basis via the Quarterly Rate Adjustment Mechanism process. 4 The balances are excluded from the rate base and do not earn an ROE.
Schedule of Regulatory Liabilities	Accounting for rate-regulated activities has resulted in the recognition of the following significant regulatory assets and liabilities: December 31, Recovery/Refund Period Ends 2017 2016 (millions of Canadian dollars) Regulatory assets/(liabilities) Liquids Pipelines Deferred income taxes Various 1,492 1,270 Tolling deferrals 2018 (34 ) (37 ) Recoverable income taxes Through 2030 46 51 Pipeline future abandonment costs 1 Various (141 ) (88 ) Gas Transmission and Midstream Deferred income taxes Various 717 — Regulatory liability related to income taxes 2 Various (1,078 ) — Other Various (16 ) — Gas Distribution Deferred income taxes Various 1,000 385 Purchased gas variance 3 Various 51 5 Pension plans and OPEB 4 Various 102 116 Constant dollar net salvage adjustment 2018 38 38 Future removal and site restoration reserves Various (1,066 ) (606 ) Site restoration clearance adjustment Various (31 ) (109 ) Other Various 31 (4 ) 1 Funds collected are included in Restricted long-term investments (Note 13) . 2 Relates to the establishment of a regulatory liability as a result of the United States tax reform legislation dated December 22, 2017. 3 Purchase gas variance is the difference between the actual cost and the approved cost of natural gas reflected in rates. EGD and Union Gas have been granted OEB approval to refund this balance to, or to collect this balance from, customers on a rolling 12-month basis via the Quarterly Rate Adjustment Mechanism process. 4 The balances are excluded from the rate base and do not earn an ROE.

ACQUISITIONS AND DISPOSITIONS (

ACQUISITIONS AND DISPOSITIONS (Tables)	12 Months Ended
	Dec. 31, 2017
Business Combinations [Abstract]
Summary of Estimated Fair Values Assigned to Net Assets and Final Purchase Price Allocation	The final purchase price allocation was as follows: April 1, 2016 (millions of Canadian dollars) Fair value of net assets acquired: Property, plant and equipment 288 Intangible assets 251 539 Purchase price: Cash 539 The following table summarizes the estimated fair values that were assigned to the net assets of Spectra Energy: February 27, 2017 (millions of Canadian dollars) Fair value of net assets acquired: Current assets (a) 2,432 Property, plant and equipment, net (b) 33,555 Restricted long-term investments 144 Long-term investments (c) 5,000 Deferred amounts and other assets (d) 2,390 Intangible assets, net (e) 1,288 Current liabilities (a) (3,982 ) Long-term debt (d) (21,444 ) Other long-term liabilities (1,983 ) Deferred income taxes (b) (7,670 ) Noncontrolling interests (f) (8,877 ) 853 Goodwill (g) 36,656 37,509 Purchase price: Common shares 37,429 Cash 3 Fair value of outstanding earned stock compensation awards recorded in Additional paid-in capital 77 37,509 a) Accounts receivable is comprised primarily of customer trade receivables and natural gas imbalances. As such, the fair value of accounts receivable approximates the net carrying value of $1,174 million . The gross amount due of $1,190 million , of which $16 million is not expected to be collected, is included in current assets. During the fourth quarter of 2017, we identified certain transactions that were not reflected in the purchase price equation. This resulted in a $67 million and $548 million increase in current assets and current liabilities, respectively, and a $481 million decrease in long-term debt. b) We have applied the valuation methodologies described in ASC 820 Fair Value Measurements and Disclosures , to value the property, plant and equipment purchased. The fair value of Spectra Energy’s rate-regulated property, plant and equipment was determined using a market participant perspective, which is their carrying amount. The fair value of the remaining non-regulated property, plant and equipment was determined primarily using variations of the income approach, which is based on the present value of the future after-tax cash flows attributable to each non-regulated asset. Some of the more significant assumptions inherent in the development of the values, from the perspective of a market participant, include, but are not limited to, the amount and timing of projected future cash flows (including revenue and profitability); the discount rate selected to measure the risks inherent in the future cash flows; the assessment of the asset’s life cycle; the competitive trends impacting the asset; and customer turnover. During the third quarter of 2017, Spectra Energy's right-of-way agreements were reclassified from intangible assets to property, plant and equipment to conform the presentation of these agreements with our accounting policy pertaining to rights-of-way. The purchase price allocation above reflects this reclassification, which amounted to $830 million as at February 27, 2017. There is no change in the amortization period for the right-of-way agreements as a result of this reclassification. During the fourth quarter of 2017, we finalized our fair value measurement of the BC Pipeline & Field Services businesses, which resulted in decreases to property, plant and equipment of $1,955 million and deferred income tax liabilities of $661 million as at February 27, 2017. c) Long-term investments represent Spectra Energy’s 50% equity investment in DCP Midstream, Gulfstream Natural Gas System, L.L.C., Nexus Gas Transmission, LLC (Nexus), Steckman Ridge LP, Islander East Pipeline Company, L.L.C., Southeast Supply Header L.L.C., and 20% equity interest in PennEast Pipeline Company LLC (PennEast). The fair value of these investments was determined using an income approach. d) Fair value of long-term debt was determined based on the current underlying Government of Canada and United States Treasury interest rates on the corresponding bonds, as well as an implied credit spread based on current market conditions and resulted in an increase in the book value of debt of $1.5 billion . The fair value adjustment to long-term debt related to rate-regulated entities of $629 million also results in a regulatory offset in Deferred amounts and other assets in the Consolidated Statements of Financial Position. During the fourth quarter of 2017, deferred amounts and other assets decreased by $530 million as at February 27, 2017 due to the finalization of BC Pipelines & Field Services' fair value measurement, as discussed under (b) above. During the fourth quarter of 2017, we identified certain transactions that were not reflected in the purchase price equation. This resulted in a $481 million decrease in long-term debt, as discussed under (a) above. e) Intangible assets primarily consist of customer relationships in the non-regulated business, which represent the underlying relationship from long-term agreements with customers that are capitalized upon acquisition, determined using the income approach. Intangible assets are amortized on a straight-line basis over their expected lives. During the third quarter of 2017, intangible assets decreased by $830 million as at February 27, 2017 due to a reclassification to property, plant and equipment, as discussed under (b) above. The fair value of intangible assets acquired through the Merger Transaction, by major classes is as follows: Weighted Average Fair As at February 27, 2017 Amortization Rate Value (millions of Canadian dollars) Customer relationships 1 3.7 % 739 Project agreement 2 4.0 % 105 Software 11.1 % 329 Other 4.2 % 115 1,288 1 Represents customer relationships in the non-regulated business, which were capitalized upon acquisition. 2 Represents a project agreement between SEP, NextEra Energy, Inc., Duke Energy Corporation (Duke Energy) and Williams Partners L.P. In accordance with the agreement, payments will be made, based on our proportional ownership interest in Sabal Trail Transmission, LLC (Sabal Trail), as certain milestones of the project are met. Amortization of the intangible asset began on July 3, 2017 , when Sabal Trail was placed into service (Note 12) . f) The fair value of Spectra Energy’s noncontrolling interests includes approximately 78.4 million SEP common units outstanding to the public, valued at the February 24, 2017 closing price of US $44.88 per common unit on the NYSE, and units held by third parties in Maritimes & Northeast Pipeline, L.L.C., Sabal Trail and Algonquin Gas Transmission, L.L.C., valued based on the underlying net assets of each reporting unit and preferred stock held by third parties in Union Gas and Westcoast Energy Inc. During the third quarter of 2017, we finalized our fair value measurement of Sabal Trail, which resulted in an increase to noncontrolling interests of $85 million as at February 27, 2017. g) We recorded $36.7 billion in goodwill, which is primarily related to expected synergies from the Merger Transaction. The goodwill balance recognized is not deductible for tax purposes. Factors that contributed to the goodwill include the opportunity to expand our natural gas pipelines segment, the potential for cost and supply chain optimization synergies, existing assembled assets and work force that cannot be duplicated at the same cost by a new entrant, franchise rights and other intangibles not separately identifiable because they are inextricably linked to the provision of regulated utility service and the enhanced scale and geographic diversity which provide greater optionality and platforms for future growth. During the third quarter of 2017, goodwill increased by $85 million as at February 27, 2017 due to the finalization of the fair value measurement of Sabal Trail as discussed under (f) above. During the fourth quarter of 2017, goodwill increased by $1,824 million as at February 27, 2017 due to the finalization of the fair value measurement of BC Pipelines & Field Services as discussed under (b) above.
Schedule of Fair Value of Intangible Assets Acquired	The fair value of intangible assets acquired through the Merger Transaction, by major classes is as follows: Weighted Average Fair As at February 27, 2017 Amortization Rate Value (millions of Canadian dollars) Customer relationships 1 3.7 % 739 Project agreement 2 4.0 % 105 Software 11.1 % 329 Other 4.2 % 115 1,288 1 Represents customer relationships in the non-regulated business, which were capitalized upon acquisition. 2 Represents a project agreement between SEP, NextEra Energy, Inc., Duke Energy Corporation (Duke Energy) and Williams Partners L.P. In accordance with the agreement, payments will be made, based on our proportional ownership interest in Sabal Trail Transmission, LLC (Sabal Trail), as certain milestones of the project are met. Amortization of the intangible asset began on July 3, 2017 , when Sabal Trail was placed into service (Note 12) .
Schedule of Supplemental Pro Forma Consolidated Financial Information	Our supplemental pro forma consolidated financial information for the years ended December 31, 2017 and 2016, including the results of operations for Spectra Energy as if the Merger Transaction had been completed on January 1, 2016 are as follows: Year ended December 31, 2017 2016 (unaudited; millions of Canadian dollars) Revenues 45,669 40,934 Earnings attributable to common shareholders 1 2,902 2,820 1 Merger Transaction costs of $180 million (after-tax $131 million ) were excluded from earnings for the year ended December 31, 2017.
Summary of Net Assets Held for Sale	The table below summarizes the presentation of net assets held for sale in our Consolidated Statements of Financial Position: December 31, 2017 2016 (millions of Canadian dollars) Accounts receivable and other (current assets held for sale) 424 — Deferred amounts and other assets (long-term assets held for sale) 1,190 278 Accounts payable and other (current liabilities held for sale) (315 ) — Net assets held for sale 1,299 278

ACCOUNTS RECEIVABLE AND OTHER (

ACCOUNTS RECEIVABLE AND OTHER (Tables)	12 Months Ended
	Dec. 31, 2017
Receivables [Abstract]
Schedule of accounts receivable and other	December 31, 2017 2016 (millions of Canadian dollars) Trade receivables and unbilled revenues 1 5,325 3,814 Other 1,728 1,164 7,053 4,978 1 Net of allowance for doubtful accounts of $50 million and $46 million as at December 31, 2017 and 2016 , respectively.

INVENTORY (Tables)

INVENTORY (Tables)	12 Months Ended
	Dec. 31, 2017
Inventory Disclosure [Abstract]
Schedule of inventory	December 31, 2017 2016 (millions of Canadian dollars) Natural gas 695 594 Crude oil 744 634 Other commodities 89 5 1,528 1,233

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 December 31, Depreciation Rate 2017 2016 (millions of Canadian dollars) Pipeline 2.5 % 47,720 34,474 Pumping equipment, buildings, tanks and other 2.9 % 16,610 15,554 Land and right-of-way 1 2.1 % 2,538 2,067 Gas mains, services and other 2.1 % 17,026 10,022 Compressors, meters and other operating equipment 2.1 % 5,774 4,014 Processing and treating plants 3.1 % 1,440 846 Storage 2.0 % 1,545 — Wind turbines, solar panels and other 3.3 % 4,804 4,259 Power transmission 2.2 % 365 378 Vehicles, office furniture, equipment and other buildings and improvements 6.5 % 390 315 Under construction — 7,601 6,966 Total property, plant and equipment 2 105,813 78,895 Total accumulated depreciation (15,102 ) (14,611 ) Property, plant and equipment, net 90,711 64,284 1 The measurement of weighted average depreciation rate excludes non-depreciable assets. 2 Certain assets were reclassified as held for sale as at December 31, 2017 (Note 7) .

VARIABLE INTEREST ENTITIES (Tab

VARIABLE INTEREST ENTITIES (Tables)	12 Months Ended
	Dec. 31, 2017
Equity Method Investments and Joint Ventures [Abstract]
Schedule of Assets and Liabilities of Consolidated VIEs	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 the Consolidated Statements of Financial Position. December 31, 2017 2016 (millions of Canadian dollars) Assets Cash and cash equivalents 368 314 Accounts receivable and other 2,132 781 Accounts receivable from affiliates 3 3 Inventory 220 53 2,723 1,151 Property, plant and equipment, net 68,685 45,720 Long-term investments 6,258 954 Restricted long-term investments 206 83 Deferred amounts and other assets 2,921 2,227 Intangible assets, net 296 488 Goodwill 29 29 Deferred income taxes 145 231 81,263 50,883 Liabilities Short-term borrowings 485 — Accounts payable and other 2,859 1,446 Accounts payable to affiliates 131 105 Interest payable 312 204 Environmental liabilities 35 140 Current portion of long-term debt 2,129 342 5,951 2,237 Long-term debt 31,469 20,176 Other long-term liabilities 4,301 1,207 Deferred income taxes 3,010 1,753 44,731 25,373 Net assets before noncontrolling interests 36,532 25,510
Schedule of the Carrying Amount of Interest in VIEs	The carrying amount of our interest in VIEs that are unconsolidated and our estimated maximum exposure to loss as at December 31, 2017 and 2016 is presented below. Carrying Amount of Investment Enbridge’s Maximum Exposure to December 31, 2017 in VIE Loss (millions of Canadian dollars) Aux Sable Liquid Products L.P. 1 300 361 Eolien Maritime France SAS 2 69 754 Hohe See Offshore Wind Project 3 763 2,484 Illinois Extension Pipeline Company, L.L.C. 4 686 686 Nexus Gas Transmission, LLC 5 834 1,678 PennEast Pipeline Company, LLC 5 69 345 Rampion Offshore Wind Limited 6 555 679 Sabal Trail Transmissions, LLC 5 2,355 2,529 Vector Pipeline L.P. 7 169 278 Other 4 21 21 5,821 9,815 Carrying Amount of Investment Enbridge’s Maximum Exposure to December 31, 2016 in VIE Loss (millions of Canadian dollars) Aux Sable Liquid Products L.P. 158 223 Eddystone Rail Company, LLC 8 19 25 Eolien Maritime France SAS 58 686 Illinois Extension Pipeline Company, L.L.C. 759 759 Rampion Offshore Wind Limited 345 457 Vector Pipeline L.P. 159 289 Other 17 17 1,515 2,456 1 At December 31, 2017 , the maximum exposure to loss includes a guarantee by us for our respective share of the VIE’s borrowing on a bank credit facility. 2 At December 31, 2017 , the maximum exposure to loss includes the portion of our parental guarantee that has been committed in project construction contracts in which we would be liable for in the event of default by the VIE and an outstanding affiliate loan receivable for $163 million held by us. 3 At December 31, 2017 , the maximum exposure to loss includes the portion of our parental guarantee that has been committed in project construction contracts in which we would be liable for in the event of default by the VIE. 4 At December 31, 2017 , the maximum exposure to loss is limited to our equity investment as these companies are in operation and self-sustaining. 5 At December 31, 2017 the maximum exposure to loss is limited to our equity investment and the remaining expected contributions for each joint venture. 6 At December 31, 2017 , the maximum exposure to loss includes the portion of our parental guarantee that has been committed in project construction contracts in which we would be liable for in the event of default by the VIE. 7 At December 31, 2017 the maximum exposure to loss includes the carrying value of an outstanding loan issued by us. 8 As at December 31, 2017 , Eddystone Rail Company, LLC is a 100% owned subsidiary and therefore is no longer an unconsolidated VIE.

LONG-TERM INVESTMENTS (Tables)

LONG-TERM INVESTMENTS (Tables)	12 Months Ended
	Dec. 31, 2017
Equity Method Investments and Joint Ventures [Abstract]
Schedule of Long-Term Investments	Ownership December 31, Interest 2017 2016 (millions of Canadian dollars) EQUITY INVESTMENTS Liquids Pipelines Bakken Pipeline System 1 27.6 % 1,938 — Eddystone Rail Company, LLC 100.0 % — 19 Seaway Crude Pipeline System 50.0 % 2,882 3,129 Illinois Extension Pipeline Company, L.L.C. 2 65.0 % 686 759 Other 30.0% - 43.8% 87 70 Gas Transmission and Midstream Alliance Pipeline 3 50.0 % 375 411 Aux Sable 42.7% - 50.0% 300 324 DCP Midstream, LLC 4 50.0 % 2,143 — Gulfstream Natural Gas System, L.L.C. 4 50.0 % 1,205 — Nexus Gas Transmission, LLC 4 50.0 % 834 — Offshore - various joint ventures 22.0% - 74.3% 389 435 PennEast Pipeline Company LLC 4 20.0 % 69 — Sabal Trail Transmission, LLC 5 50.0 % 2,355 — Southeast Supply Header L.L.C. 4 50.0 % 486 — Steckman Ridge LP 4 49.5 % 221 — Texas Express Pipeline 35.0 % 430 484 Vector Pipeline L.P. 60.0 % 169 159 Other 4 33.3% - 50.0% 34 4 Gas Distribution Noverco Common Shares 38.9 % — — Other 4 50.0 % 15 — Green Power and Transmission Eolien Maritime France SAS 6 50.0 % 69 58 Hohe See Offshore Wind Project 7 50.0 % 763 — Rampion Offshore Wind Project 24.9 % 555 345 Other 19.0% - 50.0% 95 100 Eliminations and Other Other 19.0% - 42.7% 26 15 OTHER LONG-TERM INVESTMENTS Gas Distribution Noverco Preferred Shares 371 355 Green Power and Transmission Emerging Technologies and Other 80 90 Eliminations and Other Other 67 79 16,644 6,836 1 On February 15, 2017 , EEP acquired an effective 27.6% interest in the Dakota Access and Energy Transfer Crude Oil Pipelines (collectively, the Bakken Pipeline System) for a purchase price of $ 2 billion (US$ 1.5 billion ). The Bakken Pipeline System was placed into service on June 1, 2017 . For details regarding our funding arrangement, refer to Note 19 - Noncontrolling Interests . 2 Owns the Southern Access Extension Project. 3 Certain assets of the Alliance Pipeline are pledged as collateral to Alliance Pipeline lenders. 4 On February 27, 2017, we acquired Spectra Energy's interests in DCP Midstream, Gulfstream Natural Gas System, L.L.C, Nexus, PennEast, Southeast Supply Header L.L.C., Steckman Ridge LP and other equity investments as part of the Merger Transaction (Note 7) . 5 On February 27, 2017, we acquired Spectra Energy's consolidated interest in Sabal Trail as part of the Merger Transaction (Note 7) . On July 3, 2017, Sabal Trail was placed into service and the assets, liabilities, and noncontrolling interests were deconsolidated as at the in-service date. 6 On May 19, 2016, we acquired a 50% equity interest in Eolien Maritime France SAS. 7 On February 8, 2017 , we acquired an effective 50% interest in EnBW Hohe See GmbH & Co. KG.
Summary of Combined Financial Information	Summarized combined financial information of our interest in unconsolidated equity investments (presented at 100%) is as follows: Year Ended December 31, 2017 2016 2015 Seaway Other Total Seaway Other Total Seaway Other Total (millions of Canadian dollars) Operating revenues 959 15,254 16,213 938 3,164 4,102 833 3,054 3,887 Operating expenses 286 12,911 13,197 293 3,051 3,344 263 2,210 2,473 Earnings 672 2,056 2,728 643 (2 ) 641 566 512 1,078 Earnings attributable to controlling interests 336 926 1,262 322 147 469 283 207 490 December 31, 2017 December 31, 2016 Seaway Other Total Seaway Other Total (millions of Canadian dollars) Current assets 106 3,432 3,538 86 842 928 Non-current assets 3,329 41,697 45,026 3,651 12,264 15,915 Current liabilities 143 3,311 3,454 172 831 1,003 Non-current liabilities 13 13,582 13,595 13 5,121 5,134 Noncontrolling interests — 3,191 3,191 — — —

INTANGIBLE ASSETS (Tables)

INTANGIBLE ASSETS (Tables)	12 Months Ended
	Dec. 31, 2017
Intangible Assets, Net (Excluding Goodwill) [Abstract]
Schedule of intangible assets	The following table provides the weighted average amortization rate, gross carrying value, accumulated amortization and net carrying value for each of our major classes of intangible assets: Weighted Average Accumulated December 31, 2017 1 Amortization Rate Cost Amortization Net (millions of Canadian dollars) Customer relationships 3.5 % 967 41 926 Power purchase agreements 3.5 % 99 17 82 Project agreement 2 4.0 % 150 3 147 Software 11.3 % 1,760 714 1,046 Other intangible assets 3 4.4 % 1,162 96 1,066 4,138 871 3,267 1 Certain assets were reclassified as held for sale as at December 31, 2017 (Note 7) . 2 Represents a project agreement acquired from the Merger Transaction (Note 7) . 3 The measurement of weighted average amortization rate excludes non-depreciable intangible assets. Weighted Average Accumulated December 31, 2016 Amortization Rate Cost Amortization Net (millions of Canadian dollars) Customer relationships 3.0 % 251 4 247 Natural gas supply opportunities 3.2 % 435 127 308 Power purchase agreements 3.2 % 100 14 86 Software 11.8 % 1,388 607 781 Other intangible assets 4.8 % 213 62 151 2,387 814 1,573
Schedule of future amortization expense	The following table presents our forecast of amortization expense associated with existing intangible assets for the years indicated as follows in millions of Canadian dollars: 2018 2019 2020 2021 2022 264 240 217 197 179

GOODWILL (Tables)

GOODWILL (Tables)	12 Months Ended
	Dec. 31, 2017
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of goodwill	Liquids Pipelines Gas Gas Green Power and Transmission Energy Services Eliminations and Other Consolidated (millions of Canadian dollars) Gross Cost Balance at January 1, 2016 60 458 7 — 2 13 540 Foreign exchange and other (1 ) (1 ) — — — — (2 ) Balance at December 31, 2016 59 457 7 — 2 13 538 Acquired in Merger Transaction (Note 7) 8,070 22,914 5,672 — — — 36,656 Sabal Trail deconsolidation (Note 12) — (966 ) (966 ) Disposition (29 ) — — — — — (29 ) Foreign exchange and other (314 ) (866 ) — — — — (1,180 ) Balance at December 31, 2017 7,786 21,539 5,679 — 2 13 35,019 Accumulated Impairment Balance at January 1, 2016 — (440 ) (7 ) — — (13 ) (460 ) Impairment — — — — — — — Balance at December 31, 2016 — (440 ) (7 ) — — (13 ) (460 ) Impairment — (102 ) — — — — (102 ) Balance at December 31, 2017 — (542 ) (7 ) — — (13 ) (562 ) Carrying Value Balance at December 31, 2016 59 17 — — 2 — 78 Balance at December 31, 2017 7,786 20,997 5,672 — 2 — 34,457

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 (millions of Canadian dollars) Trade payables and operating accrued liabilities 5,135 3,718 Construction payables and contractor holdbacks 706 712 Current derivative liabilities 1,130 1,941 Dividends payable 1,169 29 Other 1,338 895 9,478 7,295

DEBT (Tables)

DEBT (Tables)	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Schedule of Debt	Weighted Average December 31, Interest Rate Maturity 2017 2016 (millions of Canadian dollars) Enbridge Inc. United States dollar term notes 1 4.1 % 2022-2046 5,889 4,968 Medium-term notes 4.4 % 2019-2064 5,698 4,498 Fixed-to-floating subordinated term notes 2,3 5.6 % 2077 3,843 1,007 Floating rate notes 4 2019-2020 2,254 1,171 Commercial paper and credit facility draws 5 2.3 % 2019-2022 2,729 4,672 Other 6 3 4 Enbridge (U.S.) Inc. Medium-term notes 7 — 14 Commercial paper and credit facility draws 8 2.1 % 2019 490 126 Enbridge Energy Partners, L.P. Senior notes 9 6.2 % 2018-2045 6,328 6,781 Junior subordinated notes 10 2067 501 537 Commercial paper and credit facility draws 11 2.3 % 2019-2022 1,820 2,226 Enbridge Gas Distribution Inc. Medium-term notes 4.5 % 2020-2050 3,695 3,904 Debentures 9.9 % 2024 85 85 Commercial paper and credit facility draws 1.4 % 2019 960 351 Enbridge Income Fund Medium-term notes 4.3 % 2018-2044 1,750 2,075 Commercial paper and credit facility draws 2.9 % 2020 755 225 Enbridge Pipelines (Southern Lights) L.L.C. Senior notes 12 4.0 % 2040 1,207 1,342 Enbridge Pipelines Inc. Medium-term notes 13 4.5 % 2018-2046 4,525 4,525 Debentures 8.2 % 2024 200 200 Commercial paper and credit facility draws 14 1.5 % 2019 1,438 1,032 Other 6 4 4 Enbridge Southern Lights LP Senior notes 4.0 % 2040 315 323 Midcoast Energy Partners, L.P. Senior notes 15 4.1 % 2019-2024 501 537 Commercial paper and credit facility draws 16 — 564 Spectra Energy Capital 17 Senior notes 18 5.3 % 2018-2038 1,665 — Spectra Energy Partners, LP 17 Senior secured notes 19 6.1 % 2020 138 — Senior notes 20 2.7 % 2018-2045 7,192 — Floating rate notes 21 2020 501 — Commercial paper and credit facility draws 22 2.0 % 2022 2,824 — Union Gas Limited 17 Medium-term notes 4.2 % 2018-2047 3,490 — Senior debentures 8.7 % 2018 75 — Debentures 8.7 % 2018-2025 250 — Commercial paper and credit facility draws 1.3 % 2021 485 — Westcoast Energy Inc. 17 Senior secured notes 6.4 % 2019 66 — Medium-term notes 4.7 % 2019-2041 2,177 — Debentures 8.6 % 2018-2026 525 — Fair value adjustment - Spectra Energy acquisition 1,114 — Other 23 (312 ) (226 ) Total debt 65,180 40,945 Current maturities (2,871 ) (4,100 ) Short-term borrowings 24 (1,444 ) (351 ) Long-term debt 60,865 36,494 1 2017 - US $4,700 million ; 2016 - US $3,700 million . 2 2017 - $1,650 million and US $1,750 million ; 2016 - US $750 million . For the initial 10 years , the notes carry a fixed interest rate. Subsequently, the interest rate will be floating and set to equal the three-month Bankers' Acceptance Rate or London Interbank Offered Rate (LIBOR) plus a margin. 3 The notes would be converted automatically into Conversion Preference Shares in the event of bankruptcy and related events. 4 2017 - $750 million and US $1,200 million ; 2016 - $500 million and US $500 million . Carries an interest rate equal to the three-month Bankers' Acceptance Rate plus a margin of 59 basis points or LIBOR plus a margin of 40 or 70 basis points. 5 2017 - $1,593 million and US $907 million ; 2016 - $3,600 million and US $799 million . 6 Primarily capital lease obligations. 7 2016 - US $10 million . 8 2017 - US $391 million ; 2016 - US $94 million . 9 2017 - US $5,050 million ; 2016 - US $5,050 million . 10 2017 - US $400 million ; 2016 - US $400 million . Carries an interest rate equal to the three-month LIBOR plus a margin of 379.75 basis points. 11 2017 - US $1,453 million ; 2016 - US $1,658 million . 12 2017 - US $963 million ; 2016 - US $1,000 million . 13 Included in medium-term notes is $100 million with a maturity date of 2112. 14 2017 - $1,080 million and US $286 million ; 2016 - $750 million and US $210 million . 15 2017 - US $400 million ; 2016 - US $400 million . 16 2016 - US $420 million . 17 Debt acquired on February 27, 2017 in conjunction with the Merger Transaction (Note 7) . 18 2017 - US $1,329 million . 19 2017 - US $110 million . 20 2017 - US $5,740 million . 21 2017 - US $400 million . Carries an interest rate equal to the three-month LIBOR plus a margin of 70 basis points. 22 2017 - US $2,254 million . 23 Primarily debt discount and debt issue costs. 24 Weighted average interest rate - 1.4% ; 2016 - 0.8% .
Schedule of Committed Credit Facilities	The following table provides details of our committed credit facilities at December 31, 2017 : 2017 Total December 31, Maturity Facilities Draws 1 Available (millions of Canadian dollars) Enbridge Inc. 2 2019-2022 7,353 2,737 4,616 Enbridge (U.S.) Inc. 2019 3,590 490 3,100 Enbridge Energy Partners, L.P. 3 2019-2022 3,289 1,820 1,469 Enbridge Gas Distribution Inc. 2019 1,016 972 44 Enbridge Income Fund 2020 1,500 766 734 Enbridge Pipelines (Southern Lights) L.L.C. 2019 25 — 25 Enbridge Pipelines Inc. 2019 3,000 1,438 1,562 Enbridge Southern Lights LP 2019 5 — 5 Spectra Energy Partners, LP 4,5 2022 3,133 2,824 309 Union Gas Limited 5 2021 700 485 215 Westcoast Energy Inc. 5 2021 400 — 400 Total committed credit facilities 24,011 11,532 12,479 1 Includes facility draws, letters of credit and commercial paper issuances that are back-stopped by the credit facility. 2 Includes $135 million, $157 million (US$125 million) and $150 million of commitments that expire in 2018, 2018 and 2020, respectively. 3 Includes $219 million (US$175 million) and $232 million (US$185 million) of commitments that expire in 2018 and 2020, respectively. 4 Includes $421 million (US$336 million) of commitments that expire in 2021. 5 Committed credit facilities acquired on February 27, 2017 in conjunction with the Merger Transaction (Note 7) .
Schedule of Long-term Debt Issuances	The following are long-term debt issuances made during 2017 and 2016: Company Issue Date Principal Amount (millions of Canadian dollars unless otherwise stated) Enbridge Inc. May 2017 Floating rate notes due May 2019 1 750 June 2017 3.19% medium-term notes due December 2022 450 June 2017 3.20% medium-term notes due June 2027 450 June 2017 4.57% medium-term notes due March 2044 300 June 2017 Floating rate notes due June 2020 2 US$500 July 2017 2.90% senior notes due July 2022 US$700 July 2017 3.70% senior notes due July 2027 US$700 July 2017 Fixed-to-floating rate subordinated notes due July 2077 3 US$1,000 September 2017 Fixed-to-floating rate subordinated notes due September 2077 4 1,000 October 2017 Fixed-to-floating rate subordinated notes due September 2077 4 650 October 2017 Floating rate notes due January 2020 5 US$700 November 2016 4.25% medium-term notes due December 2026 US$750 November 2016 5.50% medium-term notes due December 2046 US$750 December 2016 Fixed-to-floating rate subordinated notes due January 2077 6 US$750 Enbridge Gas Distribution Inc. November 2017 3.51% medium-term notes due November 2047 300 August 2016 2.50% medium-term notes due August 2026 300 Enbridge Pipelines Inc. August 2016 3.00% medium-term notes due August 2026 400 August 2016 4.13% medium-term notes due August 2046 400 Spectra Energy Partners, LP June 2017 Floating rate notes due June 2020 7 US$400 Union Gas Limited November 2017 2.88% medium-term notes due November 2027 250 November 2017 3.59% medium-term notes due November 2047 250 1 Carries an interest rate equal to the three-month Bankers' Acceptance Rate plus 59 basis points. 2 Carries an interest rate equal to the three-month LIBOR plus 70 basis points. 3 Matures in 60 years and are callable on or after year 10 . For the initial 10 years , the notes carry a fixed interest rate of 5.5% . Subsequently, the interest rate will be set to equal the three-month LIBOR plus a margin of 342 basis points from year 10 to 30 , and a margin of 417 basis points from year 30 to 60 . 4 Matures in 60 years and are callable on or after year 10 . For the initial 10 years , the notes carry a fixed interest rate of 5.4% . Subsequently, the interest rate will be set to equal the three-month Bankers' Acceptance Rate plus a margin of 325 basis points from year 10 to 30 , and a margin of 400 basis points from year 30 to 60 . 5 Carries an interest rate equal to the three-month LIBOR plus 40 basis points. 6 Matures in 60 years and are callable on or after year 10 . For the initial 10 years , the notes carry a fixed interest rate of 6.0% . Subsequently, the interest rate will be set to equal the three-month LIBOR plus a margin of 389 basis points from year 10 to 30 , and a margin of 464 basis points from year 30 to 60 . 7 Carries an interest rate equal to the three-month LIBOR plus 70 basis points.
Schedule of Long-Term Debt Repayments	The following are long-term debt repayments during 2017 and 2016: Company Retirement/Repayment Date Principal Amount (millions of Canadian dollars unless otherwise stated) Enbridge Inc. March 2017 Floating rate note 500 April 2017 5.60% medium-term notes US$400 June 2017 Floating rate note US$500 May 2016 5.17% medium-term notes 400 August 2016 5.00% medium-term notes 300 October 2016 Floating rate note US$350 Enbridge Energy Partners, L.P. December 2016 5.88% senior notes US$300 Enbridge Gas Distribution Inc. April 2017 1.85% medium-term notes 300 December 2017 5.16% medium-term notes 200 Enbridge Income Fund June 2017 5.00% medium-term notes 100 December 2017 2.92% medium-term notes 225 November 2016 Floating rate note 330 Enbridge Pipelines (Southern Lights) L.L.C. June and December 2017 3.98% medium-term note due June 2040 US$37 June and December 2016 3.98% medium-term note due June 2040 US$30 Enbridge Southern Lights LP June 2017 4.01% medium-term note due June 2040 7 June and December 2016 4.01% medium-term note due June 2040 14 Spectra Energy Capitals, LLC July and September 2017 1,3 8.00% senior notes due 2019 US$500 July 2017 2,3 Senior notes carrying interest ranging from 3.3% to 7.5% due 2018 to 2038 US$761 Spectra Energy Partners, LP September 2017 6.00% senior notes US$400 June and December 2017 7.39% subordinated secured notes US$12 Union Gas Limited November 2017 9.70% debentures 125 Westcoast Energy Inc. May and November 2017 6.90% senior secured notes 26 May and November 2017 4.34% senior secured notes 24 1 On July 7, 2017 and September 8, 2017, Enbridge and Spectra Energy Capital, LLC (Spectra Capital) completed a cash tender offer for and follow-up redemption of Spectra Capital’s outstanding 8.0% senior unsecured notes due 2019 . The aggregate principal amount tendered and redeemed was US $500 million . Spectra Capital paid the consenting note holders an aggregate cash consideration of US $581 million . 2 On July 13, 2017, pursuant to a cash tender offer, Spectra Capital purchased a portion of the principal amount of its outstanding senior unsecured notes carrying interest rates ranging from 3.3% to 7.5% , with maturities ranging from one to 21 years. The principal amount tendered and accepted was US $761 million . Spectra Capital paid the consenting note holders an aggregate cash consideration of US $857 million . 3 The loss on debt extinguishment of $50 million (US $38 million ), net of the fair value adjustment recorded upon completion of the Merger Transaction, was reported within Interest expense in the Consolidated Statements of Earnings.
Schedule of Interest Expense	INTEREST EXPENSE Year ended December 31, 2017 2016 2015 (millions of Canadian dollars) Debentures and term notes 3,011 1,714 1,805 Commercial paper and credit facility draws 206 197 172 Amortization of fair value adjustment - Spectra Energy acquisition (270 ) — — Capitalized (391 ) (321 ) (353 ) 2,556 1,590 1,624

ASSET RETIREMENT OBLIGATIONS (T

ASSET RETIREMENT OBLIGATIONS (Tables)	12 Months Ended
	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Reconciliation of movements in the Company's ARO	A reconciliation of movements in our ARO liabilities is as follows: December 31, 2017 2016 (millions of Canadian dollars) Obligations at beginning of year 232 198 Liabilities acquired 546 — Liabilities incurred — 2 Liabilities settled (22 ) (33 ) Change in estimate 18 63 Foreign currency translation adjustment (12 ) (5 ) Accretion expense 31 7 Obligations at end of year 793 232 Presented as follows: Accounts payable and other 2 2 Other long-term liabilities 791 230 793 232

NONCONTROLLING INTERESTS (Table

NONCONTROLLING INTERESTS (Tables)	12 Months Ended
	Dec. 31, 2017
Noncontrolling Interest [Abstract]
Schedule of noncontrolling interests	The following table provides additional information regarding Noncontrolling interests as presented in our Consolidated Statements of Financial Position: December 31, 2017 2016 (millions of Canadian dollars) Enbridge Energy Management, L.L.C. 1 34 36 Enbridge Energy Partners, L.P. 2 157 (99 ) Enbridge Gas Distribution Inc. 3 100 100 Renewable energy assets 4 806 516 Spectra Energy Partners, LP 5,8 5,385 — Union Gas Limited 6,8 110 — Westcoast Energy Inc. 7,8 1,005 — Other — 24 7,597 577 1 Represents the 88.3% of the listed shares of Enbridge Energy Management, L.L.C. (EEM) not held by us as at December 31, 2017 and 2016 . 2 Represents the 68.2% and 80.2% interest in EEP held by public unitholders as well as interests of third parties in subsidiaries of EEP as at December 31, 2017 and 2016 , respectively. 3 Represents the four million cumulative redeemable preferred shares held by third parties in EGD as at December 31, 2017 and 2016 . 4 Represents the tax equity investors' interests in our Magic Valley, Wildcat, Keechi, New Creek and Chapman Ranch wind farms, which are accounted for using the HLBV method, with an additional 20.0% noncontrolling interest in each of the Magic Valley and Wildcat wind farms held by third parties as at December 31, 2017 and 2016 . 5 Represents the 25.7% interest in SEP held by public unitholders as at December 31, 2017 . 6 Represents the four million cumulative redeemable preferred shares held by third parties in Union Gas as at December 31, 2017 . 7 Represents the 16.6 million cumulative redeemable preferred shares and 12 million cumulative first preferred shares as at December 31, 2017 held by third parties in Westcoast Energy Inc., and the 22.0% interest in Maritimes & Northeast Pipeline Limited Partnership held by third parties. 8 Represents noncontrolling interests resulting from the Merger Transaction (Note 7) .
Schedule of redeemable noncontrolling interests	The following table presents additional information regarding Redeemable noncontrolling interests as presented in our Consolidated Statements of Financial Position: Year ended December 31, 2017 2016 2015 (millions of Canadian dollars) Balance at beginning of year 3,392 2,141 2,249 Earnings/(loss) attributable to redeemable noncontrolling interests 175 268 (3 ) Other comprehensive income/(loss), net of tax Change in unrealized loss on cash flow hedges (21 ) (17 ) (7 ) Other comprehensive loss from equity investees — — (12 ) Reclassification to earnings of loss on cash flow hedges 57 9 4 Foreign currency translation adjustments (6 ) (3 ) 18 Other comprehensive income/(loss), net of tax 30 (11 ) 3 Distributions to unitholders (247 ) (202 ) (114 ) Contributions from unitholders 1,178 591 670 Reversal of cumulative redemption value adjustment attributable to ECT preferred units — — (541 ) Net dilution loss (169 ) (81 ) (482 ) Redemption value adjustment (292 ) 686 359 Balance at end of year 4,067 3,392 2,141 Redeemable noncontrolling interests in the Fund as at December 31, 2017 , 2016 and 2015 represented 56.5% , 45.6% and 40.7% , respectively, of interests in the Fund’s trust units that are held by third parties. Common Share Issuances During the years ended December 31, 2017 , 2016 and 2015 , the following occurred: Year ended December 31, 2017 2016 2015 (millions of Canadian dollars) ENF issuance of common shares 1 : Gross proceeds from the public 575 575 700 Gross proceeds from us 2 143 143 174 ENF purchase of Fund trust units 1,3 : Contributions from redeemable noncontrolling interest holders, net of share issue costs 552 551 670 Dilution gain/(loss) for redeemable noncontrolling interests 5 (4 ) (355 ) Dilution gain/(loss) in Additional paid-in capital (5 ) 4 355 ECT purchase of EIPLP Class A units 1,4 : Proceeds used by ECT to purchase EIPLP Class A units 718 718 874 Dilution loss for redeemable noncontrolling interests (123 ) (103 ) (132 ) Dilution gain in Additional paid-in capital 123 103 132 ENF purchase of Fund trust units 5 : Contributions from redeemable noncontrolling interest holders 51 40 — Dilution gain/(loss) for redeemable noncontrolling interests (5 ) (4 ) — Dilution gain/(loss) in Additional paid-in capital 5 4 — 1 These transactions occurred in December 2017, April 2016 and November 2015. 2 Concurrent with the public offerings, we subscribed for ENF common shares on a private placement basis to maintain our 19.9% ownership interest in ENF. 3 ENF used the proceeds from the common share issuances to purchase additional trust units of the Fund. We did not participate in these offerings, resulting in increases in redeemable noncontrolling interests ( 2017 - 53.6% to 56.5% ; 2016 - 40.7% to 45.6% ; 2015 - 34.3% to 40.7% ). 4 The Fund used a portion of the proceeds from the trust unit issuances to purchase additional common units of ECT, and ECT used the proceeds to purchase additional Class A units of EIPLP, resulting in dilution losses for ECT. These dilution losses resulted in dilution losses for the Fund’s equity investment in ECT and the above-noted dilution gains/(losses) for redeemable noncontrolling interests and Additional paid-in capital. 5 For the years ended December 31, 2017, 2016 and 2015, ENF used cash in respect of reinvested dividends and option cash payments from its Dividend Reinvestment Plan (DRIP) to purchase 1.6 million , 1.3 million and nil Fund trust units, respectively, on behalf of the public.

SHARE CAPITAL (Tables)

SHARE CAPITAL (Tables)	12 Months Ended
	Dec. 31, 2017
Equity [Abstract]
Schedule of common shares	COMMON SHARES 2017 2016 2015 Number Number Number December 31, of Shares Amount of Shares Amount of Shares Amount (millions of Canadian dollars; number of shares in millions) Balance at beginning of year 943 10,492 868 7,391 852 6,669 Common shares issued 1 33 1,500 56 2,241 — — Common shares issued in Merger Transaction (Note 7) 691 37,429 — — — — Dividend Reinvestment and Share Purchase Plan 25 1,226 16 795 12 646 Shares issued on exercise of stock options 3 90 3 65 4 76 Balance at end of year 1,695 50,737 943 10,492 868 7,391 1 Gross proceeds of $1.5 billion , $2.3 billion and nil for the years ended December 31, 2017 , 2016 and 2015 , respectively; net issuance costs of nil , $59 million and nil for the years ended December 31, 2017 , 2016 and 2015 , respectively.
Schedule of preference shares	PREFERENCE SHARES 2017 2016 2015 Number Number Number December 31, of Shares Amount of Shares Amount of Shares Amount (millions of Canadian dollars; number of shares in millions) Preference Shares, Series A 5 125 5 125 5 125 Preference Shares, Series B 18 457 20 500 20 500 Preference Shares, Series C 2 43 — — — — Preference Shares, Series D 18 450 18 450 18 450 Preference Shares, Series F 20 500 20 500 20 500 Preference Shares, Series H 14 350 14 350 14 350 Preference Shares, Series J 8 199 8 199 8 199 Preference Shares, Series L 16 411 16 411 16 411 Preference Shares, Series N 18 450 18 450 18 450 Preference Shares, Series P 16 400 16 400 16 400 Preference Shares, Series R 16 400 16 400 16 400 Preference Shares, Series 1 16 411 16 411 16 411 Preference Shares, Series 3 24 600 24 600 24 600 Preference Shares, Series 5 8 206 8 206 8 206 Preference Shares, Series 7 10 250 10 250 10 250 Preference Shares, Series 9 11 275 11 275 11 275 Preference Shares, Series 11 20 500 20 500 20 500 Preference Shares, Series 13 14 350 14 350 14 350 Preference Shares, Series 15 11 275 11 275 11 275 Preference Shares, Series 17 30 750 30 750 — — Preference Shares, Series 19 20 500 — — — — Issuance costs (155 ) (147 ) (137 ) Balance at end of year 7,747 7,255 6,515
Schedule of characteristics of preference shares	Characteristics of the preference shares are as follows: Dividend Rate Dividend 1 Per Share Base Redemption Value 2 Redemption and Conversion Option Date 2,3 Right to Convert Into 3,4 (Canadian dollars unless otherwise stated) Preference Shares, Series A 5.50 % $1.37500 $25 — — Preference Shares, Series B 5 3.42 % $0.85360 $25 June 1, 2022 Series C Preference Shares, Series C 5 3-month treasury bill plus 2.400% — $25 June 1, 2022 Series B Preference Shares, Series D 6 4.00 % $1.00000 $25 March 1, 2018 Series E Preference Shares, Series F 4.00 % $1.00000 $25 June 1, 2018 Series G Preference Shares, Series H 4.00 % $1.00000 $25 September 1, 2018 Series I Preference Shares, Series J 7 4.89 % US$1.22160 US$25 June 1, 2022 Series K Preference Shares, Series L 7 4.96 % US$1.23972 US$25 September 1, 2022 Series M Preference Shares, Series N 4.00 % $1.00000 $25 December 1, 2018 Series O Preference Shares, Series P 4.00 % $1.00000 $25 March 1, 2019 Series Q Preference Shares, Series R 4.00 % $1.00000 $25 June 1, 2019 Series S Preference Shares, Series 1 4.00 % US$1.00000 US$25 June 1, 2018 Series 2 Preference Shares, Series 3 4.00 % $1.00000 $25 September 1, 2019 Series 4 Preference Shares, Series 5 4.40 % US$1.10000 US$25 March 1, 2019 Series 6 Preference Shares, Series 7 4.40 % $1.10000 $25 March 1, 2019 Series 8 Preference Shares, Series 9 4.40 % $1.10000 $25 December 1, 2019 Series 10 Preference Shares, Series 11 4.40 % $1.10000 $25 March 1, 2020 Series 12 Preference Shares, Series 13 4.40 % $1.10000 $25 June 1, 2020 Series 14 Preference Shares, Series 15 4.40 % $1.10000 $25 September 1, 2020 Series 16 Preference Shares, Series 17 5.15 % $1.28750 $25 March 1, 2022 Series 18 Preference Shares, Series 19 4.90 % $1.22500 $25 March 1, 2023 Series 20 1 The holder is entitled to receive a fixed, cumulative, quarterly preferential dividend, as declared by the Board of Directors. With the exception of Series A and Series C Preference Shares, such fixed dividend rate resets every five years beginning on the initial redemption and conversion option date. The Series 17 and Series 19 Preference Shares contain a feature where the fixed dividend rate, when reset every five years , will not be less than 5.15% and 4.90% , respectively. No other series of Preference Shares has this feature. 2 Series A Preference Shares may be redeemed any time at our option. For all other series of Preference Shares, we, may at our option, redeem all or a portion of the outstanding Preference Shares for the Base Redemption Value per share plus all accrued and unpaid dividends on the Redemption Option Date and on every fifth anniversary thereafter. 3 The holder will have the right, subject to certain conditions, to convert their shares into Cumulative Redeemable Preference Shares of a specified series on a one -for-one basis on the Conversion Option Date and every fifth anniversary thereafter at an ascribed issue price equal to the Base Redemption Value. 4 With the exception of Series A Preference Shares, after the redemption and conversion option dates, holders may elect to receive quarterly floating rate cumulative dividends per share at a rate equal to: $25 x (number of days in quarter/ 365 ) x 90 day Government of Canada treasury bill rate + 2.4% (Series C), 2.4% (Series E), 2.5% (Series G), 2.1% (Series I), 2.7% (Series O), 2.5% (Series Q), 2.5% (Series S), 2.4% (Series 4), 2.6% (Series 8), 2.7% (Series 10), 2.6% (Series 12), 2.7% (Series 14), 2.7% (Series 16), 4.1% (Series 18) or 3.2% (Series 20); or US $25 x (number of days in quarter/ 365 ) x three -month United States Government treasury bill rate + 3.1% (Series K), 3.2% (Series M), 3.1% (Series 2) or 2.8% (Series 6). 5 On June 1, 2017, 1,730,188 of Series B fixed rate Preference Shares were converted to Series C floating rate Preference Shares based upon preference share holder elections under the terms of the Series B Preference Shares. The quarterly dividend amount for the Series B Preference Shares was decreased to $0.21340 from $0.25000 on June 1, 2017, due to the reset of the annual dividend rate on every fifth anniversary of the date of issuance of the Series B Preference Shares. The quarterly dividend amount for the Series C Preference Shares was set at $0.18600 on June 1, 2017, $0.19571 on September 1, 2017 and $0.20342 on December 1, 2017, due to reset on a quarterly basis following the issuance thereof. 6 On January 30, 2018, we announced that we do not intend to exercise our right to redeem our Series D Preference Shares on March 1, 2018. As a result, until February 14, 2018, the holders of such shares had the right to convert all or part of their Series D fixed rate Preference Shares on a one-for-one basis into Series E floating rate Preference Shares. As of February 14, 2018, less than the 1,000,000 Series D Preference Shares required to give effect to conversions into Series E Preference Shares were tendered for conversion. As a result, none of our outstanding Series D Preference Shares will be converted into Series E Preference Shares on March 1, 2018. However, on March 1, 2018, the quarterly dividend amount for the Series D Preference Shares will be increased to $0.27875 from $0.25000 , due to the reset of the annual dividend rate on every fifth anniversary of the date of issuance of the Series D Preference Shares. 7 No Series J or Series L Preference Shares were converted on the June 1, 2017 and September 1, 2017 conversion option dates, respectively. However, the quarterly dividend amounts for the Series J and Series L Preference Shares were increased to US $0.30540 from US $0.25000 on June 1, 2017, and to US $0.30993 from US $0.25000 on September 1, 2017, respectively, due to the reset of the annual dividend rate on every fifth anniversary of the date of issuance of the Series J and Serles L Preference Shares.

STOCK OPTION AND STOCK UNIT P56

STOCK OPTION AND STOCK UNIT PLANS (Tables)	12 Months Ended
	Dec. 31, 2017
INCENTIVE STOCK OPTIONS
STOCK OPTION AND STOCK UNIT PLANS
Schedule of outstanding stock options	December 31, 2017 Number Weighted Average Exercise Price Weighted Average Remaining Contractual Life (years) Aggregate Intrinsic Value (options in thousands; intrinsic value in millions of Canadian dollars) Options outstanding at beginning of year 32,909 42.51 Options granted 5,995 55.72 Options exercised 1 (3,350 ) 32.65 Options cancelled or expired (1,188 ) 53.23 Options outstanding at end of year 34,366 45.41 6.1 271 Options vested at end of year 2 20,403 40.89 4.7 228 1 The total intrinsic value of ISOs exercised during the years ended December 31, 2017 , 2016 and 2015 was $62 million , $123 million and $126 million , respectively, and cash received on exercise was $17 million , $37 million and $43 million , respectively. 2 The total fair value of ISOs vested during the years ended December 31, 2017 , 2016 and 2015 was $44 million , $36 million and $34 million , respectively.
Schedule of weighted average assumptions used to determine the fair value of stock options granted	Weighted average assumptions used to determine the fair value of ISOs granted using the Black-Scholes-Merton option pricing model are as follows: Year ended December 31, 2017 2016 2015 Fair value per option (Canadian dollars) 1 6.00 7.37 6.48 Valuation assumptions Expected option term (years) 2 5 5 5 Expected volatility 3 20.4 % 25.1 % 19.9 % Expected dividend yield 4 4.2 % 4.4 % 3.2 % Risk-free interest rate 5 1.2 % 0.8 % 0.9 % 1 Options granted to United States employees are based on NYSE prices. The option value and assumptions shown are based on a weighted average of the United States and the Canadian options. The fair values per option for the years ended December 31, 2017 , 2016 and 2015 were $5.66 , $7.01 and $6.22 , respectively, for Canadian employees and US $5.72 , US $6.60 and US $6.16 , respectively, for United States employees. 2 The expected option term is six years based on historical exercise practice and three years for retirement eligible employees. 3 Expected volatility is determined with reference to historic daily share price volatility and consideration of the implied volatility observable in call option values near the grant date. 4 The expected dividend yield is the current annual dividend at the grant date divided by the current stock price. 5 The risk-free interest rate is based on the Government of Canada’s Canadian Bond Yields and the United States Treasury Bond Yields.
Restricted Stock Units (RSU)
STOCK OPTION AND STOCK UNIT PLANS
Schedule of outstanding stock units	December 31, 2017 Number Weighted Average Remaining Contractual Life (years) Aggregate Intrinsic Value (units in thousands; intrinsic value in millions of Canadian dollars) Units outstanding at beginning of year 1,854 Units granted 741 Units cancelled (186 ) Units matured 1 (839 ) Dividend reinvestment 123 Units outstanding at end of year 1,693 1.4 83 1 The total amount paid during the years ended December 31, 2017 , 2016 and 2015 for RSUs was $39 million , $56 million and $45 million , respectively.

COMPONENTS OF ACCUMULATED OTH57

COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS) (Tables)	12 Months Ended
	Dec. 31, 2017
Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]
Schedule of changes in AOCI attributable to Enbridge common shareholders	Changes in AOCI attributable to our common shareholders for the years ended December 31, 2017 , 2016 and 2015 are as follows: Cash Flow Hedges Net Investment Hedges Cumulative Translation Adjustment Equity Investees Pension and OPEB Adjustment Total (millions of Canadian dollars) Balance at January 1, 2017 (746 ) (629 ) 2,700 37 (304 ) 1,058 Other comprehensive income/(loss) retained in AOCI 1 478 (2,623 ) (11 ) 18 (2,137 ) Other comprehensive (income)/loss reclassified to earnings Interest rate contracts 1 207 — — — — 207 Commodity contracts 2 (7 ) — — — — (7 ) Foreign exchange contracts 3 (6 ) — — — — (6 ) Other contracts 4 (6 ) — — — — (6 ) Amortization of pension and OPEB actuarial loss and prior service costs 5 — — — — 41 41 189 478 (2,623 ) (11 ) 59 (1,908 ) Tax impact Income tax on amounts retained in AOCI (16 ) 12 — (16 ) (10 ) (30 ) Income tax on amounts reclassified to earnings (71 ) — — — (22 ) (93 ) (87 ) 12 — (16 ) (32 ) (123 ) Balance at December 31, 2017 (644 ) (139 ) 77 10 (277 ) (973 ) Cash Flow Hedges Net Investment Hedges Cumulative Translation Adjustment Equity Investees Pension and OPEB Adjustment Total (millions of Canadian dollars) Balance at January 1, 2016 (688 ) (795 ) 3,365 37 (287 ) 1,632 Other comprehensive income/(loss) retained in AOCI (216 ) 171 (665 ) (5 ) (45 ) (760 ) Other comprehensive (income)/loss reclassified to earnings Interest rate contracts 1 147 — — — — 147 Commodity contracts 2 (11 ) — — — — (11 ) Foreign exchange contracts 3 1 — — — — 1 Other contracts 4 (18 ) — — — — (18 ) Amortization of pension and OPEB actuarial loss and prior service costs 5 — — — — 21 21 (97 ) 171 (665 ) (5 ) (24 ) (620 ) Tax impact Income tax on amounts retained in AOCI 91 (5 ) — 5 11 102 Income tax on amounts reclassified to earnings (52 ) — — — (4 ) (56 ) 39 (5 ) — 5 7 46 Balance at December 31, 2016 (746 ) (629 ) 2,700 37 (304 ) 1,058 Cash Flow Hedges Net Investment Hedges Cumulative Translation Adjustment Equity Investees Pension and OPEB Adjustment Total (millions of Canadian dollars) Balance at January 1, 2015 (488 ) 108 309 (5 ) (359 ) (435 ) Other comprehensive income/(loss) retained in AOCI 73 (952 ) 3,056 47 65 2,289 Other comprehensive (income)/loss reclassified to earnings Interest rate contracts 1 (34 ) — — — — (34 ) Commodity contracts 2 (11 ) — — — — (11 ) Foreign exchange contracts 3 7 — — — — 7 Other contracts 4 26 — — — — 26 Amortization of pension and OPEB actuarial loss and prior service costs 5 — — — — 32 32 Other comprehensive income reclassified to earnings of derecognized cash flow hedges (338 ) — — — — (338 ) (277 ) (952 ) 3,056 47 97 1,971 Tax impact Income tax on amounts retained in AOCI (29 ) 49 — (5 ) (14 ) 1 Income tax on amounts reclassified to earnings 15 — — — (11 ) 4 Income tax on amounts reclassified to earnings of derecognized cash flow hedges 91 — — — — 91 77 49 — (5 ) (25 ) 96 Balance at December 31, 2015 (688 ) (795 ) 3,365 37 (287 ) 1,632 1 Reported within Interest expense in the Consolidated Statements of Earnings. 2 Reported within Commodity costs in the Consolidated Statements of Earnings. 3 Reported within Other income/(expense) in the Consolidated Statements of Earnings. 4 Reported within Operating and administrative expense in the Consolidated Statements of Earnings. 5 These components are included in the computation of net benefit costs and are reported within Operating and administrative expense in the Consolidated Statements of Earnings.

RISK MANAGEMENT AND FINANCIAL58

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (Tables)	12 Months Ended
	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Summary of the Consolidated Statements of Financial Position location and carrying value of derivative instruments	December 31, 2017 Derivative Instruments Used as Cash Flow Hedges Derivative Instruments Used as Net Investment Hedges Derivative Non- Qualifying Derivative Instruments Total Gross Derivative Instruments as Presented Amounts Available for Offset Total Net Derivative Instruments (millions of Canadian dollars) Accounts receivable and other Foreign exchange contracts 1 4 — 138 143 (83 ) 60 Interest rate contracts 6 — 2 — 8 (3 ) 5 Commodity contracts 2 — — 143 145 (64 ) 81 9 4 2 281 296 (150 ) 146 Deferred amounts and other assets Foreign exchange contracts 1 1 — 143 145 (125 ) 20 Interest rate contracts 7 — 6 — 13 (2 ) 11 Commodity contracts 17 — — 6 23 (19 ) 4 25 1 6 149 181 (146 ) 35 Accounts payable and other Foreign exchange contracts (5 ) (42 ) — (312 ) (359 ) 83 (276 ) Interest rate contracts (140 ) — (6 ) (183 ) (329 ) 3 (326 ) Commodity contracts — — — (439 ) (439 ) 64 (375 ) Other contracts (1 ) — — (2 ) (3 ) — (3 ) (146 ) (42 ) (6 ) (936 ) (1,130 ) 150 (980 ) Other long-term liabilities Foreign exchange contracts (4 ) (9 ) — (1,299 ) (1,312 ) 125 (1,187 ) Interest rate contracts (38 ) — (2 ) — (40 ) 2 (38 ) Commodity contracts — — — (186 ) (186 ) 19 (167 ) Other contracts (1 ) — — — (1 ) — (1 ) (43 ) (9 ) (2 ) (1,485 ) (1,539 ) 146 (1,393 ) Total net derivative asset/(liability) Foreign exchange contracts (7 ) (46 ) — (1,330 ) (1,383 ) — (1,383 ) Interest rate contracts (165 ) — — (183 ) (348 ) — (348 ) Commodity contracts 19 — — (476 ) (457 ) — (457 ) Other contracts (2 ) — — (2 ) (4 ) — (4 ) (155 ) (46 ) — (1,991 ) (2,192 ) — (2,192 ) December 31, 2016 Derivative Derivative Non- Total Gross Amounts Total Net Derivative Instruments (millions of Canadian dollars) Accounts receivable and other Foreign exchange contracts 101 3 5 109 (103 ) 6 Interest rate contracts 3 — — 3 (3 ) — Commodity contracts 9 — 232 241 (125 ) 116 113 3 237 353 (231 ) 122 Deferred amounts and other assets Foreign exchange contracts 1 3 69 73 (72 ) 1 Interest rate contracts 8 — — 8 (6 ) 2 Commodity contracts 7 — 61 68 (22 ) 46 Other contracts 1 — 1 2 — 2 17 3 131 151 (100 ) 51 Accounts payable and other Foreign exchange contracts — (268 ) (727 ) (995 ) 103 (892 ) Interest rate contracts (452 ) — (131 ) (583 ) 3 (580 ) Commodity contracts — — (359 ) (359 ) 125 (234 ) Other contracts (1 ) — (3 ) (4 ) — (4 ) (453 ) (268 ) (1,220 ) (1,941 ) 231 (1,710 ) Other long-term liabilities Foreign exchange contracts — (68 ) (1,961 ) (2,029 ) 72 (1,957 ) Interest rate contracts (268 ) — (205 ) (473 ) 6 (467 ) Commodity contracts — — (211 ) (211 ) 22 (189 ) (268 ) (68 ) (2,377 ) (2,713 ) 100 (2,613 ) Total net derivative asset/(liability) Foreign exchange contracts 102 (330 ) (2,614 ) (2,842 ) — (2,842 ) Interest rate contracts (709 ) — (336 ) (1,045 ) — (1,045 ) Commodity contracts 16 — (277 ) (261 ) — (261 ) Other contracts — — (2 ) (2 ) — (2 ) (591 ) (330 ) (3,229 ) (4,150 ) — (4,150 )
Summary of the maturity and notional principal or quantity outstanding related to derivative instruments	The following table summarizes the maturity and notional principal or quantity outstanding related to our derivative instruments. 2017 2016 As at December 31, 2018 2019 2020 2021 2022 Thereafter Total Foreign exchange contracts - United States dollar forwards - purchase (millions of United States dollars) 755 2 2 — — — 997 Foreign exchange contracts - United States dollar forwards - sell (millions of United States dollars) 4,478 3,246 3,258 1,689 1,676 1,820 13,591 Foreign exchange contracts - British pound (GBP) forwards - purchase (millions of GBP) 18 — — — — — 97 Foreign exchange contracts - GBP forwards - sell (millions of GBP) — 89 25 27 28 149 285 Foreign exchange contracts - Euro forwards - purchase (millions of Euro) 280 375 — — — — — Foreign exchange contracts - Euro forwards - sell (millions of Euro) — — 35 169 169 889 — Foreign exchange contracts - Japanese yen forwards - purchase (millions of yen) — 32,662 — — 20,000 — 32,662 Interest rate contracts - short-term pay fixed rate (millions of Canadian dollars) 4,950 1,585 215 95 91 202 14,008 Interest rate contracts - long-term receive fixed rate (millions of Canadian dollars) 1,522 1,018 822 433 349 52 — Interest rate contracts - long-term pay fixed rate (millions of Canadian dollars) 4,007 957 438 — — — 7,509 Equity contracts (millions of Canadian dollars) 45 37 8 — — — 88 Commodity contracts - natural gas (billions of cubic feet) (59 ) (69 ) (20 ) (10 ) (1 ) — (161 ) Commodity contracts - crude oil (millions of barrels) (3 ) — — — — — (20 ) Commodity contracts - NGL (millions of barrels) (12 ) — — — — — (14 ) Commodity contracts - power (megawatt per hour (MW/H)) 42 51 55 (3 ) (43 ) (43 ) 1 (4 ) 2 1 As at December 31, 2017, thereafter includes an average net purchase/(sell) of power of (43) MW/H for 2023 through 2025. 2 As at December 31, 2016, the average net purchase/(sell) of power was (4) MW/H for 2017 through 2025 with a high of 40 MW/H and a low of (43) MW/H.
Schedule of effect of cash flow hedges and net investment hedges on consolidated earnings and consolidated comprehensive income, before income taxes	The following table presents the effect of cash flow hedges and net investment hedges on our consolidated earnings and consolidated comprehensive income, before the effect of income taxes: 2017 2016 2015 (millions of Canadian dollars) Amount of unrealized gain/(loss) recognized in OCI Cash flow hedges Foreign exchange contracts (5 ) (19 ) 77 Interest rate contracts 6 (90 ) (275 ) Commodity contracts 11 14 9 Other contracts 1 39 (47 ) Net investment hedges Foreign exchange contracts 284 22 (248 ) 297 (34 ) (484 ) Amount of (gain)/loss reclassified from AOCI to earnings (effective portion) Foreign exchange contracts 1 (104 ) 2 9 Interest rate contracts 2,3 388 145 128 Commodity contracts 4 (9 ) (12 ) (46 ) Other contracts 5 8 (29 ) 28 283 106 119 De-designation of qualifying hedges in connection with the Canadian Restructuring Plan Interest rate contracts 2 — — 338 — — 338 Amount of (gain)/loss reclassified from AOCI to earnings (ineffective portion and amount excluded from effectiveness testing) Interest rate contracts 2, 3 (4 ) 61 21 Commodity contracts 4 — — 5 (4 ) 61 26 1 Reported within Transportation and other services revenues and Other income/(expense) in the Consolidated Statements of Earnings. 2 Reported within Interest expense in the Consolidated Statements of Earnings. 3 For the year ended December 31, 2017, includes settlements of $296 million loss related to the termination of long-term interest rate swaps as not highly probable to issue long-term debt. 4 Reported within Transportation and other services revenues, Commodity sales revenues, Commodity costs and Operating and administrative expense in the Consolidated Statements of Earnings. 5 Reported within Operating and administrative expense in the Consolidated Statements of Earnings.
Schedule of unrealized gains and losses associated with changes in the fair value of non-qualifying derivatives	The following table presents the unrealized gains and losses associated with changes in the fair value of our non-qualifying derivatives: Year ended December 31, 2017 2016 2015 (millions of Canadian dollars) Foreign exchange contracts 1 1,284 935 (2,187 ) Interest rate contracts 2 157 73 (363 ) Commodity contracts 3 (199 ) (508 ) 199 Other contracts 4 — 9 (22 ) Total unrealized derivative fair value gain/(loss), net 1,242 509 (2,373 ) 1 For the respective annual periods, reported within Transportation and other services revenues ( 2017 - $800 million gain; 2016 - $497 million gain; 2015 - $1,383 million loss) and Other income/(expense) ( 2017 - $484 million gain; 2016 - $438 million gain; 2015 - $804 million loss) in the Consolidated Statements of Earnings. 2 Reported as an (increase)/decrease within Interest expense in the Consolidated Statements of Earnings. 3 For the respective annual periods, reported within Transportation and other services revenues ( 2017 - $104 million loss; 2016 - $52 million loss; 2015 - $328 million gain), Commodity sales ( 2017 - $90 million gain 2016 - $474 million loss; 2015 - $226 million loss), Commodity costs ( 2017 - $223 million loss; 2016 - $38 million gain; 2015 - $99 million gain) and Operating and administrative expense ( 2017 - $38 million gain; 2016 - $20 million loss; 2015 - $2 million loss) in the Consolidated Statements of Earnings. 4 Reported within Operating and administrative expense in the Consolidated Statements of Earnings
Schedule of group credit concentrations and maximum credit exposure, with respect to derivative instruments	We have group credit concentrations and maximum credit exposure, with respect to derivative instruments, in the following counterparty segments: December 31, 2017 2016 (millions of Canadian dollars) Canadian financial institutions 82 39 United States financial institutions 19 179 European financial institutions 145 106 Asian financial institutions 2 1 Other 1 137 162 385 487 1 Other is comprised of commodity clearing house and physical natural gas and crude oil counterparties.
Schedule of derivative assets and liabilities measured at fair value	We have categorized our derivative assets and liabilities measured at fair value as follows: December 31, 2017 Level 1 Level 2 Level 3 Total Gross Derivative Instruments (millions of Canadian dollars) Financial assets Current derivative assets Foreign exchange contracts — 143 — 143 Interest rate contracts — 8 — 8 Commodity contracts 1 30 114 145 1 181 114 296 Long-term derivative assets Foreign exchange contracts — 145 — 145 Interest rate contracts — 13 — 13 Commodity contracts — 2 21 23 — 160 21 181 Financial liabilities Current derivative liabilities Foreign exchange contracts — (359 ) — (359 ) Interest rate contracts — (329 ) — (329 ) Commodity contracts (13 ) (87 ) (339 ) (439 ) Other contracts — (3 ) — (3 ) (13 ) (778 ) (339 ) (1,130 ) Long-term derivative liabilities Foreign exchange contracts — (1,312 ) — (1,312 ) Interest rate contracts — (40 ) — (40 ) Commodity contracts — (3 ) (183 ) (186 ) Other contracts — (1 ) — (1 ) — (1,356 ) (183 ) (1,539 ) Total net financial asset/(liability) Foreign exchange contracts — (1,383 ) — (1,383 ) Interest rate contracts — (348 ) — (348 ) Commodity contracts (12 ) (58 ) (387 ) (457 ) Other contracts — (4 ) — (4 ) (12 ) (1,793 ) (387 ) (2,192 ) December 31, 2016 Level 1 Level 2 Level 3 Total Gross Derivative Instruments (millions of Canadian dollars) Financial assets Current derivative assets Foreign exchange contracts — 109 — 109 Interest rate contracts — 3 — 3 Commodity contracts 2 86 153 241 2 198 153 353 Long-term derivative assets Foreign exchange contracts — 73 — 73 Interest rate contracts — 8 — 8 Commodity contracts — 43 25 68 Other contracts — 2 — 2 — 126 25 151 Financial liabilities Current derivative liabilities Foreign exchange contracts — (995 ) — (995 ) Interest rate contracts — (583 ) — (583 ) Commodity contracts (12 ) (75 ) (272 ) (359 ) Other contracts — (4 ) — (4 ) (12 ) (1,657 ) (272 ) (1,941 ) Long-term derivative liabilities Foreign exchange contracts — (2,029 ) — (2,029 ) Interest rate contracts — (473 ) — (473 ) Commodity contracts — (10 ) (201 ) (211 ) — (2,512 ) (201 ) (2,713 ) Total net financial asset/(liability) Foreign exchange contracts — (2,842 ) — (2,842 ) Interest rate contracts — (1,045 ) — (1,045 ) Commodity contracts (10 ) 44 (295 ) (261 ) Other contracts — (2 ) — (2 ) (10 ) (3,845 ) (295 ) (4,150 )
Schedule of significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments	The significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments were as follows: December 31, 2017 Fair Value Unobservable Input Minimum Price/Volatility Maximum Price/Volatility Weighted Average Price/Volatility Unit of Measurement (fair value in millions of Canadian dollars) Commodity contracts - financial 1 Natural gas (1 ) Forward gas price 2.67 5.52 3.38 $/mmbtu 3 Crude (4 ) Forward crude price 43.76 65.60 51.03 $/barrel NGL (12 ) Forward NGL price 0.30 1.83 1.32 $/gallon Power (110 ) Forward power price 15.39 71.41 50.72 $/MW/H Commodity contracts - physical 1 Natural gas (114 ) Forward gas price 2.51 7.57 2.93 $/mmbtu 3 Crude (148 ) Forward crude price 34.38 80.56 69.01 $/barrel NGL 3 Forward NGL price 0.28 1.94 0.93 $/gallon Commodity options 2 Crude (1 ) Option volatility 15 % 24 % 22 % Power — Option volatility 29 % 55 % 35 % (387 ) 1 Financial and physical forward commodity contracts are valued using a market approach valuation technique. 2 Commodity options contracts are valued using an option model valuation technique. 3 One million British thermal units (mmbtu).
Schedule of changes in net fair value of derivative assets and liabilities classified as Level 3 in the fair value hierarchy	Changes in net fair value of derivative assets and liabilities classified as Level 3 in the fair value hierarchy were as follows: Year ended December 31, 2017 2016 (millions of Canadian dollars) Level 3 net derivative asset/(liability) at beginning of period (295 ) 54 Total gain/(loss) Included in earnings 1 (184 ) (113 ) Included in OCI 4 3 Settlements 88 (239 ) Level 3 net derivative liability at end of period (387 ) (295 ) 1 Reported within Transportation and other services revenues, Commodity costs and Operating and administrative expense in the Consolidated Statements of Earnings.

INCOME TAXES (Tables)

INCOME TAXES (Tables)	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Schedule of income tax rate reconciliation	INCOME TAX RATE RECONCILIATION Year ended December 31, 2017 2016 2015 (millions of Canadian dollars) Earnings before income taxes 569 2,451 11 Canadian federal statutory income tax rate 15 % 15 % 15 % Expected federal taxes at statutory rate 85 368 2 Increase/(decrease) resulting from: Provincial and state income taxes 1 133 34 (204 ) Foreign and other statutory rate differentials (601 ) (56 ) 310 Impact of United States tax reform 2 (2,045 ) — — Effects of rate-regulated accounting (189 ) (116 ) (52 ) Foreign allowable interest deductions (124 ) (107 ) (84 ) Part VI.1 tax, net of federal Part I deduction 68 56 55 Goodwill write-down 3 15 — — Intercompany sale of investment 4 — 6 23 Non-taxable portion of gain on sale of investment to unrelated party 5 — (61 ) — Valuation allowance 6 (17 ) 22 154 Intercorporate investment in EIPLP 7 77 — — Noncontrolling interests (80 ) (15 ) (28 ) Other 8 (19 ) 11 (6 ) Income tax (recovery)/expense (2,697 ) 142 170 Effective income tax rate (474.0 )% 5.8 % 1,545.5 % 1 The change in provincial and state income taxes from 2016 to 2017 reflects the increase in earnings from the Canadian operations and the impact of the United States tax reform on state income tax expense. 2 The amount was due to the enactment of the “Tax Cuts and Jobs Act” by the United States on December 22, 2017, which included a reduction in the federal corporate income tax rate from 35% to 21% effective for taxation years beginning after December 31, 2017. 3 The amount relates to the federal component of the tax effect a goodwill write-down pursuant to ASU 2017-04. 4 In November 2016 and September 2015, certain assets were sold to entities under common control. The intercompany gains realized on these transfers were eliminated. However, because these transactions involved the sale of partnership units, tax consequences have been recognized in earnings. 5 The amount in 2016 represents the federal component of the non-taxable portion of the gain on the sale of the South Prairie Region assets to unrelated party. 6 The decrease from 2015 to 2016 is due to the federal component of the tax effect of a valuation allowance on the deferred tax assets related to an outside basis temporary difference that, in 2015, was no longer more likely than not to be realized. 7 There was a change in assertion regarding the manner of recovery of the intercorporate investment in EIPLP such that deferred tax related to outside basis temporary differences was required to be recorded. 8 2015 included $17 million recovery related to the federal component of the tax effect of adjustments related to prior periods.
Schedule of components of pretax earnings and income taxes	COMPONENTS OF PRETAX EARNINGS AND INCOME TAXES Year ended December 31, 2017 2016 2015 (millions of Canadian dollars) Earnings/(loss) before income taxes Canada 2,200 2,034 (1,365 ) United States (2,431 ) (333 ) 808 Other 800 750 568 569 2,451 11 Current income taxes Canada 129 74 157 United States 46 21 3 Other 5 4 3 180 99 163 Deferred income taxes Canada 299 188 (558 ) United States (3,160 ) (151 ) 565 Other (16 ) 6 — (2,877 ) 43 7 Income tax (recovery)/expense (2,697 ) 142 170
Schedule of major components of deferred income tax assets and liabilities	Major components of deferred income tax assets and liabilities are as follows: December 31, 2017 2016 (millions of Canadian dollars) Deferred income tax liabilities Property, plant and equipment (4,089 ) (3,867 ) Investments (6,596 ) (2,938 ) Regulatory assets (977 ) (439 ) Other (50 ) (47 ) Total deferred income tax liabilities (11,712 ) (7,291 ) Deferred income tax assets Financial instruments 697 1,215 Pension and OPEB plans 258 219 Loss carryforwards 1,781 1,189 Other 1,057 374 Total deferred income tax assets 3,793 2,997 Less valuation allowance (286 ) (572 ) Total deferred income tax assets, net 3,507 2,425 Net deferred income tax liabilities (8,205 ) (4,866 ) Presented as follows: Total deferred income tax assets 1,090 1,170 Total deferred income tax liabilities (9,295 ) (6,036 ) Net deferred income tax liabilities (8,205 ) (4,866 )
Schedule of unrecognized tax benefits	UNRECOGNIZED TAX BENEFITS Year ended December 31, 2017 2016 (millions of Canadian dollars) Unrecognized tax benefits at beginning of year 84 65 Gross increases for tax positions of current year 15 27 Gross increases for tax positions of prior year 65 — Change in translation of foreign currency (2 ) (2 ) Lapses of statute of limitations (8 ) (6 ) Settlements (4 ) — Unrecognized tax benefits at end of year 150 84

PENSION AND OTHER POSTRETIREM60

PENSION AND OTHER POSTRETIREMENT BENEFITS (Tables)	12 Months Ended
	Dec. 31, 2017
Retirement Benefits [Abstract]
Schedule of Changes in Projected Benefit Obligation, Plan Assets and Funded Status	The following table details the changes in the projected benefit obligation, the fair value of plan assets and the recorded asset or liability for our defined benefit pension plans: Canada United States December 31, 2017 2016 2017 2016 (millions of Canadian dollars) Change in projected benefit obligation Projected benefit obligation at beginning of year 2,270 2,064 508 487 Service cost 156 129 48 26 Interest cost 116 73 35 16 Actuarial loss 145 97 57 15 Benefits paid (165 ) (87 ) (42 ) (21 ) Foreign currency exchange rate changes — — (63 ) (14 ) Acquired in Merger Transaction 1,505 — 811 — Plan settlements — — (59 ) — Other 6 (6 ) (16 ) (1 ) Projected benefit obligation at end of year 1 4,033 2,270 1,279 508 Change in plan assets Fair value of plan assets at beginning of year 2,019 1,886 361 343 Actual return on plan assets 308 146 113 22 Employer contributions 161 74 57 28 Benefits paid (165 ) (87 ) (42 ) (21 ) Foreign currency exchange rate changes — — (51 ) (10 ) Acquired in Merger Transaction 1,290 — 731 — Plan settlements — — (59 ) — Other 6 — (13 ) (1 ) Fair value of plan assets at end of year 2 3,619 2,019 1,097 361 Underfunded status at end of year (414 ) (251 ) (182 ) (147 ) Presented as follows: Deferred amounts and other assets 38 5 — — Accounts payable and other (60 ) — (3 ) — Other long-term liabilities (392 ) (256 ) (179 ) (147 ) (414 ) (251 ) (182 ) (147 ) 1 The accumulated benefit obligation for our Canadian pension plans was $3.7 billion and $ 978 million as at December 31, 2017 and 2016 , respectively. The accumulated benefit obligation for our United States pension plans was $ $1.2 billion and $ 462 million as at December 31, 2017 and 2016 , respectively. 2 Assets in the amount of $ 9 million ( 2016 - $ 8 million ) and $ 40 million ( 2016 - $ 44 million ), related to our Canadian and United States non-registered supplemental pension plan obligations, are held in grantor trusts that, in accordance with federal tax regulations, are not restricted from creditors. These assets are committed for the future settlement of benefit obligations included in the underfunded status as at the end of the year, however they are excluded from plan assets for accounting purposes. For these plans, the projected benefit obligations, accumulated benefit obligations and the fair value of plan assets were as follows: Canada United States December 31, 2017 2016 2017 2016 (millions of Canadian dollars) Projected benefit obligations 1,444 2,188 1,280 508 Accumulated benefit obligations 1,306 978 1,217 462 Fair value of plan assets 1,131 1,927 1,098 361
Schedule of Amount Recognized in Accumulated Other Comprehensive Income	The amounts of pre-tax AOCI relating to our pension plans are as follows: Canada United States December 31, 2017 2016 2017 2016 (millions of Canadian dollars) Net actuarial gain 334 310 112 121 Total amount recognized in AOCI 334 310 112 121 The amounts of pre-tax AOCI relating to our OPEB plans are as follows: Canada United States December 31, 2017 2016 2017 2016 (millions of Canadian dollars) Net actuarial gain/(loss) 17 25 (15 ) 29 Prior service cost (2 ) 2 (11 ) (15 ) Total amount recognized in AOCI 15 27 (26 ) 14
Schedule of Net Benefit Costs Recognized	The components of net benefit cost and other amounts recognized in pre-tax OCI related to our OPEB plans are as follows: Canada United States Year ended December 31, 2017 2016 2015 2017 2016 2015 (millions of Canadian dollars) Service cost 7 4 3 5 4 5 Interest cost 10 6 7 10 5 4 Expected return on plan assets — — — (10 ) (6 ) (6 ) Amortization of actuarial loss and prior service cost 1 — 1 — — — Net OPEB cost recognized in Earnings 18 10 11 5 3 3 Amount recognized in OCI: Net actuarial (gain)/loss arising during the year (8 ) 2 2 (42 ) 12 16 Amortization of net actuarial (gain)/loss (1 ) (1 ) (1 ) 1 (1 ) — Prior service cost (3 ) — — 1 (12 ) (7 ) Total amount recognized in OCI (12 ) 1 1 (40 ) (1 ) 9 Total amount recognized in Comprehensive income 6 11 12 (35 ) 2 12 The components of net benefit cost and other amounts recognized in pre-tax OCI related to our pension plans are as follows: Canada United States Year ended December 31, 2017 2016 2015 2017 2016 2015 (millions of Canadian dollars) Service cost 156 129 137 48 26 30 Interest cost 116 73 81 35 16 17 Expected return on plan assets (201 ) (127 ) (120 ) (57 ) (21 ) (22 ) Amortization of actuarial loss 29 32 39 10 3 10 Net defined benefit costs 100 107 137 36 24 35 Defined contribution benefit costs 11 3 3 15 — — Net benefit cost recognized in Earnings 111 110 140 51 24 35 Amount recognized in OCI: Net actuarial (gain)/loss arising during the year 38 28 (58 ) — 16 (19 ) Amortization of net actuarial gain (14 ) (14 ) (20 ) (9 ) (6 ) (10 ) Total amount recognized in OCI 24 14 (78 ) (9 ) 10 (29 ) Total amount recognized in Comprehensive income 135 124 62 42 34 6
Schedule of Actuarial Assumptions Used	The weighted average assumptions made in the measurement of the accumulated postretirement benefit obligations and net benefit cost of our OPEB plans are as follows: Canada United States 2017 2016 2015 2017 2016 2015 Accumulated postretirement benefit obligations Discount rate 3.6 % 4.0 % 4.2 % 3.5 % 3.6 % 4.2 % Net OPEB cost Discount rate 4.0 % 4.2 % 4.0 % 4.0 % 3.8 % 3.9 % Rate of return on plan assets 6.0 % 6.0 % 6.0 % The weighted average assumptions made in the measurement of the projected benefit obligations and net benefit cost of our pension plans are as follows: Canada United States 2017 2016 2015 2017 2016 2015 Projected benefit obligations Discount rate 3.6 % 4.0 % 4.2 % 3.5 % 4.0 % 4.1 % Rate of salary increase 3.2 % 3.7 % 3.6 % 3.1 % 3.3 % 3.3 % Net benefit cost Discount rate 4.0 % 4.2 % 4.0 % 4.0 % 4.1 % 3.7 % Rate of return on plan assets 6.5 % 6.5 % 4.4 % 7.2 % 7.2 % 7.1 % Rate of salary increase 3.7 % 3.6 % 2.5 % 3.3 % 3.2 % 4.0 %
Schedule of Other Postretirement Benefits	The following table details the changes in the accumulated postretirement benefit obligation, the fair value of plan assets and the recorded asset or liability for our OPEB plans: Canada United States December 31, 2017 2016 2017 2016 (millions of Canadian dollars) Change in accumulated postretirement benefit obligation Accumulated postretirement benefit obligation at beginning of year 179 173 133 135 Service cost 7 4 5 4 Interest cost 10 6 10 5 Participant contributions — — 4 1 Actuarial (gain)/loss (8 ) 2 (34 ) 10 Benefits paid (10 ) (6 ) (19 ) (6 ) Foreign currency exchange rate changes — — (17 ) (4 ) Acquired in Merger Transaction 146 — 254 — Other (3 ) — 1 (12 ) Accumulated postretirement benefit obligation at end of year 321 179 337 133 Change in plan assets Fair value of plan assets at beginning of year — — 115 115 Actual return on plan assets — — 21 5 Employer contributions 10 6 1 3 Participant contributions — — 4 1 Benefits paid (10 ) (6 ) (19 ) (6 ) Foreign currency exchange rate changes — — (11 ) (3 ) Acquired in Merger Transaction — — 102 — Fair value of plan assets at end of year — — 213 115 Underfunded status at end of year (321 ) (179 ) (124 ) (18 ) Presented as follows: Deferred amounts and other assets — — 7 4 Accounts payable and other (12 ) (7 ) (7 ) — Other long-term liabilities (309 ) (172 ) (124 ) (22 ) (321 ) (179 ) (124 ) (18 )
Schedule of Assumed Health Care Cost Trend Rates	The assumed rates for the next year used to measure the expected cost of benefits are as follows: Canada United States 2017 2016 2017 2016 Health care cost trend rate assumed for next year 5.5 % 5.4 % 7.4 % 6.9 % Rate to which the cost trend is assumed to decline (the ultimate trend rate) 4.4 % 4.5 % 4.5 % 4.5 % Year that the rate reaches the ultimate trend rate 2034 2034 2037 2037
Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates	A 1% change in the assumed health care cost trend rate would have the following effects for the year ended and as at December 31, 2017 : Canada United States 1% Increase 1% Decrease 1% Increase 1% Decrease (millions of Canadian dollars) Effect on total service and interest costs 2 (1 ) 1 (1 ) Effect on accumulated postretirement benefit obligation 28 (23 ) 20 (17 )
Schedule of Allocation of Plan Assets	The asset allocation targets and major categories of plan assets are as follows: Canada United States Target December 31, Target December 31, Asset Category Allocation 2017 2016 Allocation 2017 2016 Equity securities 40.0 - 70.0% 52.0 % 47.0 % 52.5 - 70.0% 47.1 % 55.4 % Fixed income securities 27.5 - 60.0% 34.2 % 39.0 % 27.5 - 30.0% 47.7 % 33.0 % Other 0.0 - 20.0% 13.8 % 14.0 % 0.0 - 20.0% 5.2 % 11.6 %
Schedule of Changes in Fair Value of Plan Assets	Changes in the net fair value of plan assets classified as Level 3 in the fair value hierarchy were as follows: Canada United States December 31, 2017 2016 2017 2016 (millions of Canadian dollars) Balance at beginning of year 281 248 40 49 Unrealized and realized gains 26 20 5 2 Purchases and settlements, net 33 13 11 (11 ) Balance at end of year 340 281 56 40 The following tables summarize the fair value of plan assets for our pension and OPEB plans recorded at each fair value hierarchy level. Pension Canada United States Level 1 1 Level 2 2 Level 3 3 Total Level 1 1 Level 2 2 Level 3 3 Total (millions of Canadian dollars) December 31, 2017 Cash and cash equivalents 169 — — 169 2 — — 2 Equity securities Canada 842 425 — 1,267 — — — — United States 427 — — 427 343 — — 343 Global 189 — — 189 122 52 — 174 Fixed income securities Government 933 — — 933 — — — — Corporate 301 3 — 304 522 1 — 523 Infrastructure and real estate 4 — — 340 340 — — 56 56 Forward currency contracts — (10 ) — (10 ) — (1 ) — (1 ) Total pension plan assets at fair value 2,861 418 340 3,619 989 52 56 1,097 December 31, 2016 Cash and cash equivalents 156 — — 156 3 — — 3 Equity securities United States 219 — — 219 54 — — 54 Canada 425 — — 425 — — — — Global 165 140 — 305 116 30 — 146 Fixed income securities Government 351 — — 351 — — — — Corporate 277 3 — 280 116 — — 116 Infrastructure and real estate 4 — — 281 281 — — 40 40 Forward currency contracts — 2 — 2 — 2 — 2 Total pension plan assets at fair value 1,593 145 281 2,019 289 32 40 361 OPEB Canada United States Level 1 1 Level 2 2 Level 3 3 Total Level 1 1 Level 2 2 Level 3 3 Total (millions of Canadian dollars) December 31, 2017 Cash and cash equivalents — — — — 1 — — 1 Equity securities United States — — — — 80 — — 80 Global — — — — 36 — — 36 Fixed income securities Government — — — — 96 — — 96 Total OPEB plan assets at fair value — — — — 213 — — 213 December 31, 2016 Cash and cash equivalents — — — — 1 — — 1 Equity securities United States — — — — 35 — — 35 Global — — — — 34 — — 34 Fixed income securities Government — — — — 45 — — 45 Total OPEB plan assets at fair value — — — — 115 — — 115 1 Level 1 assets include assets with quoted prices in active markets for identical assets. 2 Level 2 assets include assets with significant observable inputs. 3 Level 3 assets include assets with significant unobservable inputs. 4 The fair values of the infrastructure and real estate investments are established through the use of valuation models.
Schedule of Expected Benefit Payments and Employer Contributions	Year ended December 31, 2018 2019 2020 2021 2022 2023-2027 (millions of Canadian dollars) Pension Canada 158 165 172 180 187 1,036 United States 82 81 85 83 92 453 OPEB Canada 12 12 13 13 14 43 United States 25 25 25 25 24 110

CHANGES IN OPERATING ASSETS A61

CHANGES IN OPERATING ASSETS AND LIABILITIES (Tables)	12 Months Ended
	Dec. 31, 2017
CHANGES IN OPERATING ASSETS AND LIABILITIES
Schedule of changes in operating assets and liabilities	Year ended December 31, 2017 2016 2015 (millions of Canadian dollars) Restricted Cash 15 — — Accounts receivable and other (783 ) (437 ) 698 Accounts receivable from affiliates 24 (7 ) 82 Inventory (289 ) (371 ) (315 ) Deferred amounts and other assets (138 ) (183 ) 364 Accounts payable and other 286 396 (1,472 ) Accounts payable to affiliates (62 ) 71 (26 ) Interest payable 124 20 31 Other long-term liabilities 509 153 (7 ) (314 ) (358 ) (645 )

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Tables)	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Schedule of commitments	At December 31, 2017 , we have commitments as detailed below. Total Less than 1 year 2 years 3 years 4 years 5 years Thereafter (millions of Canadian dollars) Annual debt maturities 1,2 62,927 2,831 6,273 6,722 2,505 8,839 35,757 Interest obligations 2,3 42,083 2,485 2,298 2,117 1,941 1,853 31,389 Purchase of services, pipe and other materials, including transportation 4,5 14,396 4,144 2,455 1,496 1,255 1,163 3,883 Operating leases 746 91 86 80 74 78 337 Capital leases 35 9 8 2 2 2 12 Maintenance agreements 322 38 32 17 15 15 205 Land lease commitments 405 15 16 16 16 16 326 Total 120,914 9,613 11,168 10,450 5,808 11,966 71,909 1 Includes debentures, term notes, commercial paper and credit facility draws based on the facility's maturity date and excludes short-term borrowings, debt discount, debt issue costs and capital lease obligations. We have the ability under certain debt facilities to call and repay the obligations prior to scheduled maturities. Therefore, the actual timing of future cash repayments could be materially different than presented above. 2 Excludes the debt issuance of US$800 million senior notes that occurred subsequent to December 31, 2017 (Note 30) . 3 Includes debentures and term notes bearing interest at fixed, floating and fixed-to-floating rates. 4 Includes capital and operating commitments. 5 Consists primarily of gas transportation and storage contracts (EGD), firm capacity payments and gas purchase commitments (Spectra Energy), transportation, service and product purchase obligations (MEP), and power commitments (EEP).

QUARTERLY FINANCIAL DATA (Table

QUARTERLY FINANCIAL DATA (Tables)	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Quarterly Financial Information	Q1 Q2 Q3 Q4 Total (unaudited; millions of Canadian dollars, except per share amounts) 2017 1 Operating revenues 11,146 11,116 9,227 12,889 44,378 Operating income/(loss) 1,358 1,684 1,490 (2,961 ) 1,571 Earnings 945 1,241 1,015 65 3,266 Earnings attributable to controlling interests 721 1,000 847 291 2,859 Earnings attributable to common shareholders 638 919 765 207 2,529 Earnings per common share Basic 0.54 0.56 0.47 0.13 1.66 Diluted 0.54 0.56 0.47 0.12 1.65 2016 Operating revenues 8,795 7,939 8,488 9,338 34,560 Operating income/(loss) 1,674 794 (216 ) 329 2,581 Earnings/(loss) 1,347 352 (237 ) 847 2,309 Earnings/(loss) attributable to controlling interests 1,286 372 (30 ) 441 2,069 Earnings/(loss) attributable to common shareholders 1,213 301 (103 ) 365 1,776 Earnings/(loss) per common share Basic 1.38 0.33 (0.11 ) 0.39 1.95 Diluted 1.38 0.33 (0.11 ) 0.39 1.93 1 The 2017 quarterly financial data reflects the effect of the Merger Transaction closed on February 27, 2017 (Note 7) .

BUSINESS OVERVIEW (Details)

BUSINESS OVERVIEW (Details) CAD in Millions	Feb. 27, 2017CADshares	Dec. 31, 2017operating_segment	Sep. 01, 2015CAD
GENERAL BUSINESS DESCRIPTION
Number of operating segments | operating_segment		5
Canadian Liquids Pipeline business and certain Canadian renewable energy assets
GENERAL BUSINESS DESCRIPTION
Segment Reporting Value Consideration From Transfer			CAD 30,400
Amount of units received in transfer			18,700
Debt assumed in transfer			11,700
The Fund | Canadian Liquids Pipeline business and certain Canadian renewable energy assets
GENERAL BUSINESS DESCRIPTION
Amount of units received in transfer			3,000
Enbridge Income Partners LP | Canadian Liquids Pipeline business and certain Canadian renewable energy assets
GENERAL BUSINESS DESCRIPTION
Amount of units received in transfer			CAD 15,700
Spectra Energy Corp
GENERAL BUSINESS DESCRIPTION
Purchase price	CAD 37,509
Combined entity shares to be paid for each share of acquiree stock (in shares) | shares	0.984
Ownership interest acquired (as a percent)	100.00%

SUMMARY OF ACCOUNTING POLICIE65

SUMMARY OF ACCOUNTING POLICIES (Details) CAD in Millions	12 Months Ended
	Dec. 31, 2017CADreporting_unit	Dec. 31, 2016CAD	Dec. 31, 2015CAD
Cash and Cash Equivalents [Line Items]
Net cash (used in) provided by financing activities	CAD 3,476	CAD 840	CAD 3,074
Number of reporting units | reporting_unit	2
Restatement Adjustment
Cash and Cash Equivalents [Line Items]
Net cash (used in) provided by financing activities		(300)	CAD 100
Restatement Adjustment | Cash and cash equivalents
Cash and Cash Equivalents [Line Items]
Bank indebtedness	CAD 600	CAD 600

SUMMARY OF ACCOUNTING POLICIE66

SUMMARY OF ACCOUNTING POLICIES - REGULATION (Details)	Dec. 31, 2017CAD
Deferral for Depreciation for Phase-In Plans under U.S. GAAP Guidance
REGULATION
Regulatory assets	CAD 0

SUMMARY OF ACCOUNTING POLICIE67

SUMMARY OF ACCOUNTING POLICIES - REVENUE RECOGNITION (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Accounting Policies [Abstract]
Revenue recognized for contracts	CAD 196	CAD 249	CAD 61

SUMMARY OF ACCOUNTING POLICIE68

SUMMARY OF ACCOUNTING POLICIES - PROPERTY, PLANT AND EQUIPMENT (Details)	12 Months Ended
	Dec. 31, 2017number_of_primary_method_of_depreciation
Accounting Policies [Abstract]
Number of primary methods of depreciation which are utilized	2

SUMMARY OF ACCOUNTING POLICIE69

SUMMARY OF ACCOUNTING POLICIES - STOCK-BASED COMPENSATION (Details)	12 Months Ended
	Dec. 31, 2017
Restricted Stock Units (RSU)
STOCK-BASED COMPENSATION
Vesting period	35 months

CHANGES IN ACCOUNTING POLICIES

CHANGES IN ACCOUNTING POLICIES (Details) - CAD CAD in Millions	Dec. 31, 2017	Dec. 31, 2016
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Deficit	CAD (2,468)	CAD (716)
Property, plant and equipment, net	90,711	CAD 64,284
Difference between revenue guidance in effect before and after Topic 606 | Accounting Standards Update 2014-09 | Pro Forma
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Deficit	120
Property, plant and equipment, net	130
Deferred revenue	CAD 120

SEGMENTED INFORMATION (Details)

SEGMENTED INFORMATION (Details) - CAD CAD 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
Segmented Information
Revenues	CAD 12,889	CAD 9,227	CAD 11,116	CAD 11,146	CAD 9,338	CAD 8,488	CAD 7,939	CAD 8,795	CAD 44,378	CAD 34,560	CAD 33,794
Commodity and gas distribution costs									(28,637)	(24,005)	(25,241)
Operating and administrative									(6,442)	(4,358)	(4,131)
Impairment of property, plant and equipment									(4,463)	(1,376)	(96)
Goodwill impairment									(102)	0	(440)
Income/(loss) from equity investments									1,102	428	475
Other income/(expense)									452	1,032	(702)
Earnings/(loss) before interest and income taxes									6,288	6,281	3,659
Depreciation and amortization									(3,163)	(2,240)	(2,024)
Interest expense									(2,556)	(1,590)	(1,624)
Income taxes									2,697	(142)	(170)
Earnings/(loss)									3,266	2,309	(159)
Capital expenditures									8,422	5,129	7,275
Total assets	162,093				85,209				162,093	85,209
Out of period adjustments
Out of period non-cash adjustment to income taxes											71
Liquids Pipelines
Segmented Information
Goodwill impairment									0	0
Gas Distribution
Segmented Information
Goodwill impairment									0	0
Green Power and Transmission
Segmented Information
Goodwill impairment									0	0
Operating Segments | Liquids Pipelines
Segmented Information
Revenues									8,913	8,176	5,589
Commodity and gas distribution costs									(18)	(12)	(9)
Operating and administrative									(2,949)	(2,908)	(2,748)
Impairment of property, plant and equipment									0	(1,365)	(80)
Goodwill impairment									0		0
Income/(loss) from equity investments									416	194	296
Other income/(expense)									33	841	(15)
Earnings/(loss) before interest and income taxes									6,395	4,926	3,033
Capital expenditures									2,799	3,957	5,884
Total assets	63,881				52,007				63,881	52,007
Operating Segments | Gas Transmission and Midstream
Segmented Information
Revenues									7,067	2,877	3,803
Commodity and gas distribution costs									(2,834)	(2,206)	(3,002)
Operating and administrative									(1,756)	(446)	(506)
Impairment of property, plant and equipment									(4,463)	(11)	(16)
Goodwill impairment									(102)		(440)
Income/(loss) from equity investments									653	223	200
Other income/(expense)									166	27	4
Earnings/(loss) before interest and income taxes									(1,269)	464	43
Capital expenditures									4,016	176	385
Total assets	60,745				11,182				60,745	11,182
Operating Segments | Gas Distribution
Segmented Information
Revenues									4,992	2,976	3,609
Commodity and gas distribution costs									(2,689)	(1,653)	(2,349)
Operating and administrative									(960)	(553)	(536)
Impairment of property, plant and equipment									0	0	0
Goodwill impairment									0		0
Income/(loss) from equity investments									23	12	(10)
Other income/(expense)									24	49	49
Earnings/(loss) before interest and income taxes									1,390	831	763
Capital expenditures									1,177	713	858
Total assets	25,956				10,132				25,956	10,132
Operating Segments | Green Power and Transmission
Segmented Information
Revenues									534	502	498
Commodity and gas distribution costs									0	5	4
Operating and administrative									(163)	(173)	(143)
Impairment of property, plant and equipment									0	0	0
Goodwill impairment									0		0
Income/(loss) from equity investments									6	2	2
Other income/(expense)									(5)	8	2
Earnings/(loss) before interest and income taxes									372	344	363
Capital expenditures									321	251	68
Total assets	6,289				5,571				6,289	5,571
Operating Segments | Energy Services
Segmented Information
Revenues									23,282	20,364	20,842
Commodity and gas distribution costs									(23,508)	(20,473)	(20,443)
Operating and administrative									(47)	(63)	(66)
Impairment of property, plant and equipment									0	0	0
Goodwill impairment									0		0
Income/(loss) from equity investments									8	(3)	(9)
Other income/(expense)									2	(8)	0
Earnings/(loss) before interest and income taxes									(263)	(183)	324
Capital expenditures									1	0	0
Total assets	2,514				1,951				2,514	1,951
Intersegment Eliminations | Eliminations and Other
Segmented Information
Revenues									(410)	(335)	(547)
Commodity and gas distribution costs									412	334	558
Operating and administrative									(567)	(215)	(132)
Impairment of property, plant and equipment									0	0	0
Goodwill impairment									0		0
Income/(loss) from equity investments									(4)	0	(4)
Other income/(expense)									232	115	(742)
Earnings/(loss) before interest and income taxes									(337)	(101)	(867)
Capital expenditures									108	32	CAD 80
Total assets	CAD 2,708				CAD 4,366				CAD 2,708	CAD 4,366
Customer Concentration Risk | Sales Revenue, Net | Largest Non-Affiliated Customer
Out of period adjustments
Concentration risk, percentage									11.80%	18.00%	21.80%
Customer Concentration Risk | Sales Revenue, Net | Second Largest Customer
Out of period adjustments
Concentration risk, percentage										10.40%
Customer Concentration Risk | Sales Revenue, Net | Third Largest Customer
Out of period adjustments
Concentration risk, percentage											10.80%

SEGMENTED INFORMATION - GEOGRAP

SEGMENTED INFORMATION - GEOGRAPHIC INFORMATION (Details) - CAD CAD 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
Geographic Information
Revenues	CAD 12,889	CAD 9,227	CAD 11,116	CAD 11,146	CAD 9,338	CAD 8,488	CAD 7,939	CAD 8,795	CAD 44,378	CAD 34,560	CAD 33,794
Property, plant and equipment, net	90,711				64,284				90,711	64,284
Canada
Geographic Information
Revenues									18,076	12,470	11,087
Property, plant and equipment, net	46,025				32,008				46,025	32,008
United States
Geographic Information
Revenues									26,302	22,090	CAD 22,707
Property, plant and equipment, net	CAD 44,686				CAD 32,276				CAD 44,686	CAD 32,276

EARNINGS PER COMMON SHARE (Deta

EARNINGS PER COMMON SHARE (Details) - CAD / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Earnings Per Share [Abstract]
Weighted average basic shares outstanding, pro forma (in shares)	13,000,000	13,000,000	12,000,000
Weighted average shares outstanding (in shares)	1,525,000,000	911,000,000	847,000,000
Effect of dilutive options (in shares)	7,000,000	7,000,000	0
Diluted weighted average shares outstanding (in shares)	1,532,000,000	918,000,000	847,000,000
Anti-dilutive stock options excluded from diluted earnings per common share calculation (in shares)	14,271,615	10,803,672	36,005,043
Weighted average exercise price of anti-dilutive stock options (in CAD per share)	CAD 56.71	CAD 52.92	CAD 40.26

REGULATORY MATTERS - Liquids Pi

REGULATORY MATTERS - Liquids Pipelines (Narrative) (Details)	12 Months Ended
	Dec. 31, 2017
Canadian Mainline
Public Utilities, General Disclosures [Line Items]
Term of CTS establishing a Canadian Local Toll	10 years
Southern Lights Pipeline
Public Utilities, General Disclosures [Line Items]
Pre-determined after-tax rate of return on equity (ROE) (as a percent)	10.00%
Debt structure (as a percent)	70.00%
Equity structure (as a percent)	30.00%

REGULATORY MATTERS - Enbridge G

REGULATORY MATTERS - Enbridge Gas Distribution Inc. (Narrative) (Details) - Enbridge Gas Distribution	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Public Utilities, General Disclosures [Line Items]
After-tax rate of return on common equity embedded in rates (as a percent)	8.80%	9.20%
Common equity component of capital (as a percent)	36.00%	36.00%

REGULATORY MATTERS - Union Gas

REGULATORY MATTERS - Union Gas Limited (Narrative) (Details) - Union Gas Limited	12 Months Ended
	Dec. 31, 2017
Public Utilities, General Disclosures [Line Items]
Term of incentive regulation framework	5 years
Return on common equity (as a percent)	8.93%
Fully retained
Public Utilities, General Disclosures [Line Items]
Return on common equity (as a percent)	9.93%
50% of any earnings
Public Utilities, General Disclosures [Line Items]
Earnings allowed to be retained under earnings sharing mechanism (as a percent)	50.00%
50% of any earnings | Minimum
Public Utilities, General Disclosures [Line Items]
Return on common equity (as a percent)	9.93%
50% of any earnings | Maximum
Public Utilities, General Disclosures [Line Items]
Return on common equity (as a percent)	10.93%
90% of any earnings
Public Utilities, General Disclosures [Line Items]
Return on common equity (as a percent)	10.93%
Earnings allowed to be retained under earnings sharing mechanism (as a percent)	90.00%

REGULATORY MATTERS - Schedule o

REGULATORY MATTERS - Schedule of Regulatory Assets and Liabilities (Details) - CAD CAD in Millions	Dec. 31, 2017	Dec. 31, 2016
Liquids Pipelines | Tolling deferrals
Regulatory Liabilities [Line Items]
Regulatory (liabilities)	CAD (34)	CAD (37)
Liquids Pipelines | Pipeline future abandonment costs
Regulatory Liabilities [Line Items]
Regulatory (liabilities)	(141)	(88)
Liquids Pipelines | Deferred income taxes
Regulatory Assets [Line Items]
Regulatory assets	1,492	1,270
Liquids Pipelines | Recoverable income taxes
Regulatory Assets [Line Items]
Regulatory assets	46	51
Gas Transmission and Midstream | Regulatory liability related to income taxes2
Regulatory Liabilities [Line Items]
Regulatory (liabilities)	(1,078)	0
Gas Transmission and Midstream | Other
Regulatory Liabilities [Line Items]
Regulatory (liabilities)	(16)	0
Gas Transmission and Midstream | Deferred income taxes
Regulatory Assets [Line Items]
Regulatory assets	717	0
Gas Distribution | Future removal and site restoration reserves
Regulatory Liabilities [Line Items]
Regulatory (liabilities)	(1,066)	(606)
Gas Distribution | Site restoration clearance adjustment
Regulatory Liabilities [Line Items]
Regulatory (liabilities)	(31)	(109)
Gas Distribution | Other
Regulatory Liabilities [Line Items]
Regulatory (liabilities)		(4)
Gas Distribution | Deferred income taxes
Regulatory Assets [Line Items]
Regulatory assets	1,000	385
Gas Distribution | Purchased gas variance
Regulatory Assets [Line Items]
Regulatory assets	51	5
Gas Distribution | Pension plans and OPEB
Regulatory Assets [Line Items]
Regulatory assets	102	116
Gas Distribution | Constant dollar net salvage adjustment
Regulatory Assets [Line Items]
Regulatory assets	38	CAD 38
Gas Distribution | Other
Regulatory Assets [Line Items]
Regulatory assets	CAD 31

REGULATORY MATTERS - Operating

REGULATORY MATTERS - Operating Cost Capitalization (Narrative) (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Costs capitalized to Property, plant and equipment, net | Enbridge Gas Distribution
Schedule of Capitalization [Line Items]
Net book value of capitalized costs	CAD 118	CAD 125

ACQUISITIONS AND DISPOSITIONS -

ACQUISITIONS AND DISPOSITIONS - Acquisitions (Narrative) (Details) CAD in Millions	Feb. 27, 2017CADshares	Apr. 01, 2016CAD	Dec. 31, 2016CAD	Dec. 31, 2017CAD	Dec. 31, 2017CADreporting_unit	Dec. 31, 2016CAD	Dec. 31, 2015CAD	Feb. 27, 2017$ / shares
Business Acquisition [Line Items]
Number of reporting units | reporting_unit					2
Cash consideration					CAD 0	CAD 644	CAD 106
Spectra Energy
Business Acquisition [Line Items]
Purchase price	CAD 37,509
Shares paid to acquiree for each share of acquiree stock (in shares) | shares	0.984
Ownership interest acquired (as a percent)								100.00%
Cash paid in lieu of fractional shares	CAD 3
Acquisition-related expenses/transaction costs incurred				CAD 231	231
Costs incurred					180	51
Revenues generated by acquiree				5,740
Earnings generated by acquiree				CAD 2,574
Cash consideration	CAD 3
Pro forma revenues					CAD 45,669	40,934
Tupper Main and Tupper West
Business Acquisition [Line Items]
Acquisition-related expenses/transaction costs incurred		CAD 1
Revenues generated by acquiree			CAD 33
Cash consideration		CAD 539
Earnings before interest and income taxes of acquiree			CAD 22
Pro forma revenues						44
Pro forma earnings before interest and income taxes						CAD 28
Common shares | Spectra Energy
Business Acquisition [Line Items]
Shares paid as consideration (in shares) | shares	691,000,000
Share price (in USD per share) | $ / shares								$ 41.34
Value of shares issued	CAD 37,429
Share options | Spectra Energy
Business Acquisition [Line Items]
Shares paid as consideration (in shares) | shares	3,500,000
Value of shares issued	CAD 77
Gas Transmission and Midstream
Business Acquisition [Line Items]
Number of reporting units | reporting_unit					2

ACQUISITIONS AND DISPOSITIONS80

ACQUISITIONS AND DISPOSITIONS - Summary of Estimated Fair Values Assigned to Net Assets (Details) $ / shares in Units, shares in Millions, CAD in Millions, $ in Millions	Feb. 27, 2017CADshares	Dec. 31, 2017USD ($)	Dec. 31, 2017CAD	Dec. 31, 2016CAD	Dec. 31, 2015CAD	Feb. 27, 2017$ / shares
Fair value of net assets acquired:
Goodwill (Note 15)			CAD 34,457	CAD 78
Purchase price:
Cash			0	644	CAD 106
Fair value adjustment to long-term debt related to rate-regulated entities			1,114	0
Decrease to deferred amounts and other assets			CAD (138)	CAD (183)	CAD 364
Spectra Energy
Fair value of net assets acquired:
Current assets	CAD 2,432
Property, plant and equipment, net	33,555
Restricted long-term investments	144
Long-term investments	5,000
Deferred amounts and other assets	2,390
Intangible assets, net	1,288
Current liabilities (a)	(3,982)
Long-term debt	(21,444)
Other long-term liabilities	(1,983)
Deferred income taxes	(7,670)
Noncontrolling interests	(8,877)
Fair value of net assets acquired	853
Goodwill (Note 15)	36,656
Fair value of net assets acquired and goodwill	37,509
Purchase price:
Cash	3
Purchase price	37,509
Net carrying value of accounts receivable	1,174
Gross amount due	1,190
Not expected to be collected	16
Business Combination, adjustment, current assets | $		$ 67
Business Combination, adjustment, current liabilities | $		548
Business Combination, adjustment, long-term debt | $		$ 481
Reclassification from intangible assets to property, plant and equipment	830
Increase in the book value of debt	1,500
Fair value adjustment to long-term debt related to rate-regulated entities	629
Spectra Energy | Common shares
Purchase price:
Equity issued	37,429
Spectra Energy | Earned stock compensation awards
Purchase price:
Equity issued	CAD 77
Spectra Energy | SEP
Purchase price:
SEP common units outstanding to the public (in shares) | shares	78.4
Closing price per common unit (in USD per share) | $ / shares						$ 44.88
Spectra Energy | Various equity investments of acquiree
Purchase price:
Long-term investments (as a percent)	50.00%
Spectra Energy | PennEast
Purchase price:
Long-term investments (as a percent)	20.00%
Sabal Trail
Purchase price:
Increase to noncontrolling interests	CAD 85
BC Pipelines & Field Services
Purchase price:
Decrease to property, plant and equipment	1,955
Decrease to deferred income tax liabilities	661
Decrease to deferred amounts and other assets	530
Increase to noncontrolling interests	CAD 1,824

ACQUISITIONS AND DISPOSITIONS81

ACQUISITIONS AND DISPOSITIONS - Schedule of Fair Value of Intangible Assets Acquired (Details) - Spectra Energy CAD in Millions	Feb. 27, 2017CAD
Acquired Finite-Lived Intangible Assets [Line Items]
Fair Value	CAD 1,288
Customer relationships
Acquired Finite-Lived Intangible Assets [Line Items]
Weighted Average Amortization Rate	3.70%
Fair Value	CAD 739
Project agreement
Acquired Finite-Lived Intangible Assets [Line Items]
Weighted Average Amortization Rate	4.00%
Fair Value	CAD 105
Software
Acquired Finite-Lived Intangible Assets [Line Items]
Weighted Average Amortization Rate	11.10%
Fair Value	CAD 329
Other
Acquired Finite-Lived Intangible Assets [Line Items]
Weighted Average Amortization Rate	4.20%
Fair Value	CAD 115

ACQUISITIONS AND DISPOSITIONS82

ACQUISITIONS AND DISPOSITIONS - Schedule of Supplemental Pro Forma Consolidated Financial Information (Details) - Spectra Energy - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Business Acquisition [Line Items]
Revenues	CAD 45,669	CAD 40,934
Earnings attributable to common shareholders	2,902	2,820
Merger Transaction costs	180	CAD 51
After-tax Merger Transaction costs	CAD 131

ACQUISITIONS AND DISPOSITIONS83

ACQUISITIONS AND DISPOSITIONS - Schedule of Final Purchase Price Allocation (Details) - CAD CAD in Millions	Apr. 01, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Purchase price:
Cash		CAD 0	CAD 644	CAD 106
Tupper Main and Tupper West
Fair value of net assets acquired:
Property, plant and equipment	CAD 288
Intangible assets	251
Fair value of net assets acquired	539
Purchase price:
Cash	CAD 539

ACQUISITIONS AND DISPOSITIONS84

ACQUISITIONS AND DISPOSITIONS - Other Acquistions (Narrative) (Details) $ in Millions

Nov. 02, 2016CAD

Nov. 02, 2016USD ($)

Sep. 09, 2016CADMW

Sep. 09, 2016USD ($)MW

Feb. 27, 2015CAD

Feb. 27, 2015USD ($)

Nov. 30, 2015CADMW

Nov. 30, 2015USD ($)MW

Dec. 31, 2017CAD

Dec. 31, 2016CAD

Dec. 31, 2015CAD

Nov. 02, 2016USD ($)

Sep. 09, 2016USD ($)

Nov. 30, 2015USD ($)

Feb. 27, 2015USD ($)

Business Acquisition [Line Items]

Cash consideration | CAD

CAD 0

CAD 644,000,000

CAD 106,000,000

Chapman Ranch

Business Acquisition [Line Items]

Ownership interest acquired (as a percent)

100.00%

100.00%

Capacity acquired (in megawatts) | MW

249

249

Cash consideration

CAD 40,000,000

$ 30

CAD 65,000,000

$ 50

Purchase price allocated to property, plant and equipment

23,000,000

CAD 62,000,000

$ 17

$ 48

Pro forma effect on earnings | CAD

CAD 0

New Creek

Business Acquisition [Line Items]

Ownership interest acquired (as a percent)

100.00%

100.00%

Capacity acquired (in megawatts) | MW

103

103

Cash consideration

CAD 48,000,000

$ 36

Purchase price allocated to property, plant and equipment

CAD 35,000,000

$ 26

Midstream Business

Business Acquisition [Line Items]

Cash consideration

CAD 106,000,000

$ 85

Purchase price allocated to property, plant and equipment

69,000,000

$ 55

Contingent future payment (up to)

CAD 21,000,000

$ 17

ACQUISITIONS AND DISPOSITIONS85

ACQUISITIONS AND DISPOSITIONS - Assets Held for Sale (Narrative) (Details) CAD in Millions, $ in Millions	3 Months Ended		12 Months Ended
	Mar. 31, 2018CAD	Mar. 31, 2018USD ($)	Dec. 31, 2017CAD	Dec. 31, 2016CAD	Dec. 31, 2015CAD
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Loss from remeasurement			CAD 4,463	CAD 1,376	CAD 96
Goodwill impairment			102	0	CAD 440
Gas Transmission and Midstream
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Loss from remeasurement			4,400
After-tax loss from remeasurement			2,800
Goodwill impairment			CAD 102	CAD 0
Scenario, Forecast | Gas Distribution | Disposal group, held-for-sale, not discontinued operations | St. Lawrence Gas
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash proceeds from sale	CAD 88	$ 70

ACQUISITIONS AND DISPOSITIONS86

ACQUISITIONS AND DISPOSITIONS - Schedule of Net Assets Held for Sale (Details) - St. Lawrence Gas - Disposal group, held-for-sale, not discontinued operations - CAD CAD in Millions	Dec. 31, 2017	Dec. 31, 2016
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Accounts receivable and other (current assets held for sale)	CAD 424	CAD 0
Deferred amounts and other assets (long-term assets held for sale)	1,190	278
Accounts payable and other (current liabilities held for sale)	(315)	0
Net assets held for sale	CAD 1,299	CAD 278

ACQUISITIONS AND DISPOSITIONS87

ACQUISITIONS AND DISPOSITIONS - Dispositions (Narrative) (Details) CAD in Millions, $ in Millions	Jul. 31, 2017CAD	Jul. 31, 2017USD ($)	Mar. 01, 2017CAD	Mar. 01, 2017USD ($)	Dec. 01, 2016CAD	Dec. 31, 2017CAD	Dec. 31, 2017USD ($)	Dec. 31, 2016CAD	Dec. 31, 2015CAD
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain on disposal of assets						CAD 120		CAD 848	CAD 94
Dispositions | Liquids Pipelines | Olympic Pipeline
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash proceeds from sale of interest	CAD 203	$ 160
Dispositions | Liquids Pipelines | Sandpiper
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash proceeds from sale of assets						148	$ 111
Gain on disposal of assets						CAD 83	$ 63
Dispositions | Liquids Pipelines | Ozark Pipeline
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash proceeds from sale of assets			CAD 294	$ 220
Gain on disposal of assets			CAD 14	$ 10
Dispositions | Liquids Pipelines | South Prairie Region
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash proceeds from sale of assets					CAD 1,100
Other income/(expense) | Dispositions | Liquids Pipelines | Olympic Pipeline
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain on disposal of interest	CAD 27	$ 21
Other income/(expense) | Dispositions | Liquids Pipelines | South Prairie Region
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain on disposal of interest					CAD 850

ACQUISITIONS AND DISPOSITIONS88

ACQUISITIONS AND DISPOSITIONS - Other Disposition (Narrative) (Details) CAD in Millions, $ in Millions	1 Months Ended				12 Months Ended
	Dec. 31, 2016CAD	Aug. 31, 2015CAD	Aug. 31, 2015USD ($)	May 31, 2015CAD	Dec. 31, 2017CAD	Dec. 31, 2016CAD	Dec. 31, 2015CAD
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain on disposal					CAD 120	CAD 848	CAD 94
Other miscellaneous non-core assets | Dispositions
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash proceeds	CAD 286
Frontier Pipeline Company | Dispositions
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash proceeds		CAD 112	$ 85
Interest sold (as a percent)		77.80%	77.80%
Gain on disposal		CAD 70	$ 53
Crude oil pipeline system | Dispositions
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash proceeds				CAD 26
Gain on disposal				CAD 22

ACCOUNTS RECEIVABLE AND OTHER89

ACCOUNTS RECEIVABLE AND OTHER (Details) - CAD CAD in Millions	Dec. 31, 2017	Dec. 31, 2016
Receivables [Abstract]
Trade receivables and unbilled revenues	CAD 5,325	CAD 3,814
Other	1,728	1,164
Accounts receivable and other	7,053	4,978
Allowance for doubtful accounts receivable	CAD 50	CAD 46

INVENTORY (Details)

INVENTORY (Details) - CAD CAD in Millions	Dec. 31, 2017	Dec. 31, 2016
Inventory Disclosure [Abstract]
Natural gas	CAD 695	CAD 594
Crude oil	744	634
Other commodities	89	5
Total	CAD 1,528	CAD 1,233

PROPERTY, PLANT AND EQUIPMENT -

PROPERTY, PLANT AND EQUIPMENT - Schedule of Property, Plant and Equipment (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
PROPERTY, PLANT AND EQUIPMENT
Total property, plant and equipment	CAD 105,813	CAD 78,895
Total accumulated depreciation	(15,102)	(14,611)
Property, plant and equipment, net	CAD 90,711	64,284
Pipeline
PROPERTY, PLANT AND EQUIPMENT
Weighted Average Depreciation Rate	2.50%
Total property, plant and equipment	CAD 47,720	34,474
Pumping equipment, buildings, tanks and other
PROPERTY, PLANT AND EQUIPMENT
Weighted Average Depreciation Rate	2.90%
Total property, plant and equipment	CAD 16,610	15,554
Land and right-of-way1
PROPERTY, PLANT AND EQUIPMENT
Weighted Average Depreciation Rate	2.10%
Total property, plant and equipment	CAD 2,538	2,067
Gas mains, services and other
PROPERTY, PLANT AND EQUIPMENT
Weighted Average Depreciation Rate	2.10%
Total property, plant and equipment	CAD 17,026	10,022
Compressors, meters and other operating equipment
PROPERTY, PLANT AND EQUIPMENT
Weighted Average Depreciation Rate	2.10%
Total property, plant and equipment	CAD 5,774	4,014
Processing and treating plants
PROPERTY, PLANT AND EQUIPMENT
Weighted Average Depreciation Rate	3.10%
Total property, plant and equipment	CAD 1,440	846
Storage
PROPERTY, PLANT AND EQUIPMENT
Weighted Average Depreciation Rate	2.00%
Total property, plant and equipment	CAD 1,545	0
Wind turbines, solar panels and other
PROPERTY, PLANT AND EQUIPMENT
Weighted Average Depreciation Rate	3.30%
Total property, plant and equipment	CAD 4,804	4,259
Power transmission
PROPERTY, PLANT AND EQUIPMENT
Weighted Average Depreciation Rate	2.20%
Total property, plant and equipment	CAD 365	378
Vehicles, office furniture, equipment and other buildings and improvements
PROPERTY, PLANT AND EQUIPMENT
Weighted Average Depreciation Rate	6.50%
Total property, plant and equipment	CAD 390	315
Under construction
PROPERTY, PLANT AND EQUIPMENT
Weighted Average Depreciation Rate	0.00%
Total property, plant and equipment	CAD 7,601	CAD 6,966

PROPERTY, PLANT AND EQUIPMENT92

PROPERTY, PLANT AND EQUIPMENT - Narrative (Details) - CAD CAD in Millions	Nov. 29, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
PROPERTY, PLANT AND EQUIPMENT
Depreciation expense		CAD 2,900	CAD 2,000	CAD 1,900
Impairment loss		CAD 4,463	1,376	96
Northern Gateway Project
PROPERTY, PLANT AND EQUIPMENT
Impairment loss	CAD 373
Impairment loss, after-tax	CAD 272
Sandpiper Project
PROPERTY, PLANT AND EQUIPMENT
Impairment loss			992
Impairment loss, after-tax			81
EEP
PROPERTY, PLANT AND EQUIPMENT
Impairment charges				96
Land | Sandpiper Project
PROPERTY, PLANT AND EQUIPMENT
Estimated fair value			3
Non-core trucking assets and related facilities | EEP
PROPERTY, PLANT AND EQUIPMENT
Impairment charges			CAD 11
Berthold rail facility | EEP
PROPERTY, PLANT AND EQUIPMENT
Impairment charges				80
Louisiana propylene pipeline | EEP
PROPERTY, PLANT AND EQUIPMENT
Impairment charges				CAD 16

VARIABLE INTEREST ENTITIES - CO

VARIABLE INTEREST ENTITIES - CONSOLIDATED VARIABLE INTEREST ENTITIES (Narrative) (Details)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
EECI
Schedule of Equity Method Investments [Line Items]
Ownership interest in subsidiary (as a percent)	100.00%
EIPLP | Alliance Pipeline
Schedule of Equity Method Investments [Line Items]
Ownership interest of equity method investment (as a percent)	50.00%
Enbridge Management Services Inc.
Schedule of Equity Method Investments [Line Items]
Ownership interest in subsidiary (as a percent)	100.00%
Direct common interest (as a percent)	53.10%
EEP
Schedule of Equity Method Investments [Line Items]
Economic interest (as a percent)	34.60%	35.30%
Enbridge Income Fund
Schedule of Equity Method Investments [Line Items]
Economic interest (as a percent)	82.50%	86.90%
Direct common interest (as a percent)	29.40%	43.20%
EIPLP
Schedule of Equity Method Investments [Line Items]
Economic interest (as a percent)	73.50%	79.10%
DakTex
Schedule of Equity Method Investments [Line Items]
Ownership interest in subsidiary (as a percent)	75.00%
DakTex | EEP
Schedule of Equity Method Investments [Line Items]
Ownership interest in subsidiary (as a percent)	25.00%
Bakken Pipeline System
Schedule of Equity Method Investments [Line Items]
Ownership interest of equity method investment (as a percent)	27.60%
SEP
Schedule of Equity Method Investments [Line Items]
Direct common interest (as a percent)	75.00%
Other Limited Partnerships
Schedule of Equity Method Investments [Line Items]
Direct common interest (as a percent)	100.00%

VARIABLE INTEREST ENTITIES - Sc

VARIABLE INTEREST ENTITIES - Schedule of Assets and Liabilities of Consolidated VIEs (Details) - CAD CAD in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Assets
Cash and cash equivalents	CAD 480	CAD 1,494	CAD 654	CAD 799
Accounts receivable and other	7,053	4,978
Accounts receivable from affiliates	47	14
Inventory	1,528	1,233
Total Current assets	9,215	7,787
Property, plant and equipment, net	90,711	64,284
Long-term investments	16,644	6,836
Restricted long-term investments	267	90
Deferred amounts and other assets	6,442	3,391
Intangible assets, net	3,267	1,573
Goodwill	34,457	78
Deferred income taxes	1,090	1,170
Total assets	162,093	85,209
Liabilities
Short-term borrowings	1,444	351
Accounts payable and other	9,478	7,295
Accounts payable to affiliates	157	122
Interest payable	634	333
Environmental liabilities	40	142
Current portion of long-term debt	2,871	4,100
Total Current liabilities	14,624	12,343
Long-term debt	60,865	36,494
Other long-term liabilities	7,510	4,981
Deferred income taxes	8,205	4,866
Total Liabilities	92,294	59,854
Variable Interest Entity, Primary Beneficiary
Assets
Cash and cash equivalents	368	314
Accounts receivable and other	2,132	781
Accounts receivable from affiliates	3	3
Inventory	220	53
Total Current assets	2,723	1,151
Property, plant and equipment, net	68,685	45,720
Long-term investments	6,258	954
Restricted long-term investments	206	83
Deferred amounts and other assets	2,921	2,227
Intangible assets, net	296	488
Goodwill	29	29
Deferred income taxes	145	231
Total assets	81,263	50,883
Liabilities
Short-term borrowings	485	0
Accounts payable and other	2,859	1,446
Accounts payable to affiliates	131	105
Interest payable	312	204
Environmental liabilities	35	140
Current portion of long-term debt	2,129	342
Total Current liabilities	5,951	2,237
Long-term debt	31,469	20,176
Other long-term liabilities	4,301	1,207
Deferred income taxes	3,010	1,753
Total Liabilities	44,731	25,373
Net assets before noncontrolling interests	CAD 36,532	CAD 25,510

VARIABLE INTEREST ENTITIES - UN

VARIABLE INTEREST ENTITIES - UNCONSOLIDATED VARIABLE INTEREST ENTITIES (Narrative) (Details)	1 Months Ended	6 Months Ended	12 Months Ended
	Jun. 30, 2017	Dec. 31, 2017	Dec. 31, 2017
Sabal Trail
Variable Interest Entity [Line Items]
Direct common interest (as a percent)			50.00%
Nexus
Variable Interest Entity [Line Items]
Direct common interest (as a percent)			50.00%
PennEast
Variable Interest Entity [Line Items]
Direct common interest (as a percent)	10.00%	20.00%

VARIABLE INTEREST ENTITIES - 96

VARIABLE INTEREST ENTITIES - Schedule of the Carrying Amount of Interest in VIEs (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Variable Interest Entity, Not Primary Beneficiary
VARIABLE INTEREST ENTITY
Carrying Amount of Investment in VIE	CAD 5,821	CAD 1,515
Maximum Exposure to Loss	9,815	2,456
Aux Sable Liquid Products L.P.
VARIABLE INTEREST ENTITY
Carrying Amount of Investment in VIE	300	158
Maximum Exposure to Loss	CAD 361	223
Eddystone Rail Company, LLC
VARIABLE INTEREST ENTITY
Carrying Amount of Investment in VIE		19
Maximum Exposure to Loss		25
Ownership interest in subsidiary (as a percent)	100.00%
Eolien Maritime France SAS
VARIABLE INTEREST ENTITY
Carrying Amount of Investment in VIE	CAD 69	58
Maximum Exposure to Loss	754	686
Affiliate loan receivable	163
Hohe See Offshore Wind Project
VARIABLE INTEREST ENTITY
Carrying Amount of Investment in VIE	763
Maximum Exposure to Loss	2,484
Illinois Extension Pipeline Company, L.L.C.
VARIABLE INTEREST ENTITY
Carrying Amount of Investment in VIE	686	759
Maximum Exposure to Loss	686	759
Nexus Gas Transmission, LLC
VARIABLE INTEREST ENTITY
Carrying Amount of Investment in VIE	834
Maximum Exposure to Loss	1,678
PennEast Pipeline Company, LLC
VARIABLE INTEREST ENTITY
Carrying Amount of Investment in VIE	69
Maximum Exposure to Loss	345
Rampion Offshore Wind Limited
VARIABLE INTEREST ENTITY
Carrying Amount of Investment in VIE	555	345
Maximum Exposure to Loss	679	457
Sabal Trail Transmissions, LLC
VARIABLE INTEREST ENTITY
Carrying Amount of Investment in VIE	2,355
Maximum Exposure to Loss	2,529
Vector Pipeline L.P.
VARIABLE INTEREST ENTITY
Carrying Amount of Investment in VIE	169	159
Maximum Exposure to Loss	278	289
Other
VARIABLE INTEREST ENTITY
Carrying Amount of Investment in VIE	21	17
Maximum Exposure to Loss	CAD 21	CAD 17

LONG-TERM INVESTMENTS - Schedul

LONG-TERM INVESTMENTS - Schedule of Long-Term Investments (Details) CAD in Millions, $ in Billions	Dec. 31, 2017CAD	Apr. 27, 2017	Feb. 15, 2017CAD	Feb. 15, 2017USD ($)	Feb. 08, 2017	Dec. 31, 2016CAD	May 19, 2016
LONG-TERM INVESTMENTS
Total long-term investments	CAD 16,644					CAD 6,836
Noverco | Common shares
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	38.90%					38.90%
Noverco | Common shares | Gas Distribution
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	38.90%
EQUITY INVESTMENTS	CAD 0					CAD 0
Noverco | Preference shares | Gas Distribution
LONG-TERM INVESTMENTS
OTHER LONG-TERM INVESTMENTS	CAD 371					355
Hohe See Offshore Wind Project
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)					50.00%
Bakken Pipeline System
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)		27.60%
Bakken Pipeline System | EEP
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)			27.60%	27.60%
Purchase price			CAD 2,000	$ 1.5
Bakken Pipeline System | Liquids Pipelines
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	27.60%
EQUITY INVESTMENTS	CAD 1,938					CAD 0
Eddystone Rail Company, LLC | Liquids Pipelines
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	100.00%					75.00%
EQUITY INVESTMENTS	CAD 0					CAD 19
Seaway | Liquids Pipelines
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	50.00%
EQUITY INVESTMENTS	CAD 2,882					3,129
Illinois Extension Pipeline Company, L.L.C.2 | Liquids Pipelines
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	65.00%
EQUITY INVESTMENTS	CAD 686					759
Alliance Pipeline | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	50.00%
EQUITY INVESTMENTS	CAD 375					411
Aux Sable | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
EQUITY INVESTMENTS	CAD 300					324
Aux Sable | Gas Transmission and Midstream | Minimum
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	42.70%
Aux Sable | Gas Transmission and Midstream | Maximum
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	50.00%
DCP Midstream, LLC | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	50.00%
EQUITY INVESTMENTS	CAD 2,143					0
Gulfstream Natural Gas System, L.L.C. | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	50.00%
EQUITY INVESTMENTS	CAD 1,205					0
Nexus Gas Transmission, LLC | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	50.00%
EQUITY INVESTMENTS	CAD 834					0
Offshore - various joint ventures | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
EQUITY INVESTMENTS	CAD 389					435
Offshore - various joint ventures | Gas Transmission and Midstream | Minimum
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	22.00%
Offshore - various joint ventures | Gas Transmission and Midstream | Maximum
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	74.30%
PennEast Pipeline Company, LLC | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	20.00%
EQUITY INVESTMENTS	CAD 69					0
Sabal Trail Transmission, LLC | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	50.00%
EQUITY INVESTMENTS	CAD 2,355					0
Southeast Supply Header L.L.C. | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	50.00%
EQUITY INVESTMENTS	CAD 486					0
Steckman Ridge LP | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	49.50%
EQUITY INVESTMENTS	CAD 221					0
Texas Express Pipeline | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	35.00%
EQUITY INVESTMENTS	CAD 430					484
Vector Pipeline L.P. | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	60.00%
EQUITY INVESTMENTS	CAD 169					159
Eolien Maritime France SAS
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)							50.00%
Eolien Maritime France SAS | Green Power and Transmission
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	50.00%
EQUITY INVESTMENTS	CAD 69					58
Hohe See Offshore Wind Project | Green Power and Transmission
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	50.00%
EQUITY INVESTMENTS	CAD 763					0
Rampion Offshore Wind Project | Green Power and Transmission
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	24.90%
EQUITY INVESTMENTS	CAD 555					345
Emerging Technologies and Other | Green Power and Transmission
LONG-TERM INVESTMENTS
OTHER LONG-TERM INVESTMENTS	80					90
Other equity investments | Liquids Pipelines
LONG-TERM INVESTMENTS
EQUITY INVESTMENTS	CAD 87					70
Other equity investments | Liquids Pipelines | Minimum
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	30.00%
Other equity investments | Liquids Pipelines | Maximum
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	43.80%
Other equity investments | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
EQUITY INVESTMENTS	CAD 34					4
Other equity investments | Gas Transmission and Midstream | Minimum
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	33.30%
Other equity investments | Gas Transmission and Midstream | Maximum
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	70.00%
Other equity investments | Green Power and Transmission
LONG-TERM INVESTMENTS
EQUITY INVESTMENTS	CAD 95					100
Other equity investments | Green Power and Transmission | Minimum
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	19.00%
Other equity investments | Green Power and Transmission | Maximum
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	50.00%
Other equity investments | Eliminations and Other
LONG-TERM INVESTMENTS
EQUITY INVESTMENTS	CAD 26					15
Other equity investments | Eliminations and Other | Minimum
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	19.00%
Other equity investments | Eliminations and Other | Maximum
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	42.70%
Other equity investments | Common shares | Gas Distribution
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)	50.00%
EQUITY INVESTMENTS	CAD 15					0
Other long-term investments | Eliminations and Other
LONG-TERM INVESTMENTS
OTHER LONG-TERM INVESTMENTS	CAD 67					CAD 79

LONG-TERM INVESTMENTS - Summary

LONG-TERM INVESTMENTS - Summary of Combined Financial Information (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income statement information
Operating revenues	CAD 16,213	CAD 4,102	CAD 3,887
Operating expenses	13,197	3,344	2,473
Earnings	2,728	641	1,078
Earnings attributable to controlling interests	1,262	469	490
Balance sheet information
Current assets	3,538	928
Non-current assets	45,026	15,915
Current liabilities	3,454	1,003
Non-current liabilities	13,595	5,134
Noncontrolling interests	3,191	0
Seaway
Income statement information
Operating revenues	959	938	833
Operating expenses	286	293	263
Earnings	672	643	566
Earnings attributable to controlling interests	336	322	283
Balance sheet information
Current assets	106	86
Non-current assets	3,329	3,651
Current liabilities	143	172
Non-current liabilities	13	13
Noncontrolling interests	0	0
Other
Income statement information
Operating revenues	15,254	3,164	3,054
Operating expenses	12,911	3,051	2,210
Earnings	2,056	(2)	512
Earnings attributable to controlling interests	926	147	CAD 207
Balance sheet information
Current assets	3,432	842
Non-current assets	41,697	12,264
Current liabilities	3,311	831
Non-current liabilities	13,582	5,121
Noncontrolling interests	CAD 3,191	CAD 0

LONG-TERM INVESTMENTS - Narrati

LONG-TERM INVESTMENTS - Narrative (Details) shares in Millions, CAD in Millions, $ in Billions	1 Months Ended	12 Months Ended
	Feb. 29, 2016shares	Dec. 31, 2017CAD	Dec. 31, 2016CAD	Dec. 31, 2015CAD	Dec. 31, 2017USD ($)
Schedule of Equity Method Investments [Line Items]
Goodwill of investee		CAD 2,000	CAD 859
Amortizable assets of investee		643	687
Dividends received from equity investments		1,400	825	CAD 719
Asset impairment charge		CAD 4,565	CAD 1,620	CAD 536
Preference shares
Schedule of Equity Method Investments [Line Items]
Margin (as a percent)		4.38%			4.38%
Sabal Trail
Schedule of Equity Method Investments [Line Items]
Equity investment		CAD 2,300			$ 1.9
Noverco | Common shares
Schedule of Equity Method Investments [Line Items]
Ownership interest (as a percent)		38.90%	38.90%		38.90%
Reciprocal shareholding (as a percent)		1.90%	3.40%		1.90%
Shares purchased (in shares) | shares	1.2
Indirect pro-rata interest (as a percent)		0.70%	1.30%		0.70%
Reduction from reciprocal shareholding		CAD 102	CAD 102
Noverco | Preference shares
Schedule of Equity Method Investments [Line Items]
Maturity period		10 years
Margin (as a percent)		4.38%			4.38%
Aux Sable
Schedule of Equity Method Investments [Line Items]
Asset impairment charge			CAD 37
Liquids Pipelines | Eddystone Rail Company, LLC
Schedule of Equity Method Investments [Line Items]
Ownership interest (as a percent)		100.00%	75.00%		100.00%
Investment impairment			CAD 184
Equity investment		CAD 0	19
Gas Transmission and Midstream | Aux Sable
Schedule of Equity Method Investments [Line Items]
Equity investment		CAD 300	324
Gas Transmission and Midstream | Sabal Trail
Schedule of Equity Method Investments [Line Items]
Ownership interest (as a percent)		50.00%			50.00%
Equity investment		CAD 2,355	CAD 0

RESTRICTED LONG-TERM INVESTM100

RESTRICTED LONG-TERM INVESTMENTS (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Assets Held-in-trust [Abstract]
Restricted long-term investments	CAD 267	CAD 90
Future abandonment costs	CAD 151	CAD 97

INTANGIBLE ASSETS (Details)

INTANGIBLE ASSETS (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
INTANGIBLE ASSETS
Cost	CAD 4,138	CAD 2,387
Accumulated Amortization	871	814
Net	3,267	1,573
Amortization expenses
Amortization expense for intangible assets	280	CAD 177	CAD 158
Expected amortization expense for intangible assets
2,018	264
2,019	240
2,020	217
2,021	197
2,022	CAD 179
Customer relationships
INTANGIBLE ASSETS
Weighted Average Amortization Rate (as a percent)	3.50%	3.00%
Cost	CAD 967	CAD 251
Accumulated Amortization	41	4
Net	CAD 926	CAD 247
Natural gas supply opportunities
INTANGIBLE ASSETS
Weighted Average Amortization Rate (as a percent)		3.20%
Cost		CAD 435
Accumulated Amortization		127
Net		CAD 308
Power purchase agreements
INTANGIBLE ASSETS
Weighted Average Amortization Rate (as a percent)	3.50%	3.20%
Cost	CAD 99	CAD 100
Accumulated Amortization	17	14
Net	CAD 82	CAD 86
Project agreement
INTANGIBLE ASSETS
Weighted Average Amortization Rate (as a percent)	4.00%
Cost	CAD 150
Accumulated Amortization	3
Net	CAD 147
Software
INTANGIBLE ASSETS
Weighted Average Amortization Rate (as a percent)	11.30%	11.80%
Cost	CAD 1,760	CAD 1,388
Accumulated Amortization	714	607
Net	CAD 1,046	CAD 781
Other intangible assets3
INTANGIBLE ASSETS
Weighted Average Amortization Rate (as a percent)	4.40%	4.80%
Cost	CAD 1,162	CAD 213
Accumulated Amortization	96	62
Net	CAD 1,066	CAD 151

GOODWILL (Details)

GOODWILL (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Gross Cost
Goodwill, gross at beginning of period	CAD 538	CAD 540
Foreign exchange and other	(1,180)	(2)
Acquired in Merger Transaction (Note 7)	36,656
Sabal Trail deconsolidation (Note 12)	(966)
Disposition	(29)
Goodwill, gross at end of period	35,019	538	CAD 540
Accumulated Impairment
Goodwill, impaired, accumulated impairment loss at beginning of period	(460)	(460)
Impairment	(102)	0	(440)
Goodwill, impaired, accumulated impairment loss at end of period	(562)	(460)	(460)
Goodwill	34,457	78
Consolidation, Eliminations
Gross Cost
Goodwill, gross at beginning of period	13	13
Foreign exchange and other	0	0
Acquired in Merger Transaction (Note 7)	0
Disposition	0
Goodwill, gross at end of period	13	13	13
Accumulated Impairment
Goodwill, impaired, accumulated impairment loss at beginning of period	(13)	(13)
Impairment	0	0
Goodwill, impaired, accumulated impairment loss at end of period	(13)	(13)	(13)
Goodwill	0	0
Liquids Pipelines
Gross Cost
Goodwill, gross at beginning of period	59	60
Foreign exchange and other	(314)	(1)
Acquired in Merger Transaction (Note 7)	8,070
Sabal Trail deconsolidation (Note 12)	0
Disposition	(29)
Goodwill, gross at end of period	7,786	59	60
Accumulated Impairment
Goodwill, impaired, accumulated impairment loss at beginning of period	0	0
Impairment	0	0
Goodwill, impaired, accumulated impairment loss at end of period	0	0	0
Goodwill	7,786	59
Gas Transmission & Midstream
Gross Cost
Goodwill, gross at beginning of period	457	458
Foreign exchange and other	(866)	(1)
Acquired in Merger Transaction (Note 7)	22,914
Sabal Trail deconsolidation (Note 12)	(966)
Disposition	0
Goodwill, gross at end of period	21,539	457	458
Accumulated Impairment
Goodwill, impaired, accumulated impairment loss at beginning of period	(440)	(440)
Impairment	(102)	0
Goodwill, impaired, accumulated impairment loss at end of period	(542)	(440)	(440)
Goodwill	20,997	17
Gas Distribution
Gross Cost
Goodwill, gross at beginning of period	7	7
Foreign exchange and other	0	0
Acquired in Merger Transaction (Note 7)	5,672
Disposition	0
Goodwill, gross at end of period	5,679	7	7
Accumulated Impairment
Goodwill, impaired, accumulated impairment loss at beginning of period	(7)	(7)
Impairment	0	0
Goodwill, impaired, accumulated impairment loss at end of period	(7)	(7)	(7)
Goodwill	5,672	0
Green Power and Transmission
Gross Cost
Goodwill, gross at beginning of period	0	0
Foreign exchange and other	0	0
Acquired in Merger Transaction (Note 7)	0
Disposition	0
Goodwill, gross at end of period	0	0	0
Accumulated Impairment
Goodwill, impaired, accumulated impairment loss at beginning of period	0	0
Impairment	0	0
Goodwill, impaired, accumulated impairment loss at end of period	0	0	0
Goodwill	0	0
Energy Services
Gross Cost
Goodwill, gross at beginning of period	2	2
Foreign exchange and other	0	0
Acquired in Merger Transaction (Note 7)	0
Disposition	0
Goodwill, gross at end of period	2	2	2
Accumulated Impairment
Goodwill, impaired, accumulated impairment loss at beginning of period	0	0
Impairment	0	0
Goodwill, impaired, accumulated impairment loss at end of period	0	0	CAD 0
Goodwill	CAD 2	CAD 2

GOODWILL GOODWILL - NARRATIVE (

GOODWILL GOODWILL - NARRATIVE (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Feb. 27, 2017
GOODWILL
Goodwill	CAD 34,457	CAD 78
Goodwill, Written off Related to Sale of Business Unit	29
Impairment	CAD 102	CAD 0	CAD 440
Goodwill, impairment loss, net of tax			CAD 167
Spectra Energy Corp
GOODWILL
Goodwill				CAD 36,656

ACCOUNTS PAYABLE AND OTHER (Det

ACCOUNTS PAYABLE AND OTHER (Details) - CAD CAD in Millions	Dec. 31, 2017	Dec. 31, 2016
Payables and Accruals [Abstract]
Trade payables and operating accrued liabilities	CAD 5,135	CAD 3,718
Construction payables and contractor holdbacks	706	712
Current derivative liabilities	1,130	1,941
Dividends payable	1,169	29
Other	1,338	895
Accounts payable and other liabilities	CAD 9,478	CAD 7,295

DEBT - Schedule of Debt (Detail

DEBT - Schedule of Debt (Details) CAD in Millions, $ in Millions	1 Months Ended	12 Months Ended
	Sep. 30, 2017	Dec. 31, 2017CAD	Dec. 31, 2017USD ($)	Dec. 31, 2016CAD	Dec. 31, 2016USD ($)
DEBT
Total debt		CAD 65,180		CAD 40,945
Fair value adjustment - Spectra Energy acquisition		1,114		0
Other		(312)		(226)
Current maturities		(2,871)		(4,100)
Short-term borrowings		(1,444)		(351)
Long-term debt		CAD 60,865		CAD 36,494
Weighted average interest rate (as a percent)		1.40%	1.40%	0.80%	0.80%
Fixed-to-floating rate subordinated notes due September 2077 | Enbridge Inc.
DEBT
Term of fixed rate	10 years
Term of credit facility	60 years
United States dollar term notes | Enbridge Inc.
DEBT
Weighted Average Interest Rate		4.10%	4.10%
Total debt		CAD 5,889	$ 4,700	CAD 4,968	$ 3,700
Medium-term notes | Enbridge Inc.
DEBT
Weighted Average Interest Rate		4.40%	4.40%
Total debt		CAD 5,698		4,498
Medium-term notes | Enbridge (U.S.) Inc.
DEBT
Total debt		CAD 0		14	10
Medium-term notes | Enbridge Gas Distribution Inc.
DEBT
Weighted Average Interest Rate		4.50%	4.50%
Total debt		CAD 3,695		3,904
Medium-term notes | Enbridge Income Fund
DEBT
Weighted Average Interest Rate		4.30%	4.30%
Total debt		CAD 1,750		2,075
Medium-term notes | Enbridge Pipelines Inc.
DEBT
Weighted Average Interest Rate		4.50%	4.50%
Total debt		CAD 4,525		4,525
Carrying value		CAD 100
Medium-term notes | Westcoast Energy Inc.
DEBT
Weighted Average Interest Rate		4.70%	4.70%
Total debt		CAD 2,177		0
Medium-term notes | Union Gas Limited
DEBT
Weighted Average Interest Rate		4.20%	4.20%
Total debt		CAD 3,490		0
Fixed-to-floating subordinated term notes | Enbridge Inc.
DEBT
Weighted Average Interest Rate		5.60%	5.60%
Total debt		CAD 3,843	$ 1,750	1,007	750
Term of fixed rate		10 years
Carrying value		CAD 1,650
Floating rate notes | Enbridge Inc.
DEBT
Total debt		2,254		1,171
Carrying value		750	1,200	500	500
Floating rate notes | Spectra Energy Partners, LP
DEBT
Total debt		501	$ 400	0
Commercial paper and credit facility draws
DEBT
Long-term debt		CAD 10,055		7,344
Commercial paper and credit facility draws | Enbridge Inc.
DEBT
Weighted Average Interest Rate		2.30%	2.30%
Total debt		CAD 2,729		4,672
Carrying value		CAD 1,593	$ 907	3,600	799
Commercial paper and credit facility draws | Enbridge (U.S.) Inc.
DEBT
Weighted Average Interest Rate		2.10%	2.10%
Total debt		CAD 490	$ 391	126	94
Commercial paper and credit facility draws | Enbridge Energy Partners, L.P.
DEBT
Weighted Average Interest Rate		2.30%	2.30%
Total debt		CAD 1,820	$ 1,453	2,226	1,658
Commercial paper and credit facility draws | Enbridge Gas Distribution Inc.
DEBT
Weighted Average Interest Rate		1.40%	1.40%
Total debt		CAD 960		351
Commercial paper and credit facility draws | Enbridge Income Fund
DEBT
Weighted Average Interest Rate		2.90%	2.90%
Total debt		CAD 755		225
Commercial paper and credit facility draws | Enbridge Pipelines Inc.
DEBT
Weighted Average Interest Rate		1.50%	1.50%
Total debt		CAD 1,438		1,032
Draws		1,080	$ 286	750	210
Commercial paper and credit facility draws | Midcoast Energy Partners, L.P.
DEBT
Total debt		CAD 0	$ 420	564
Commercial paper and credit facility draws | Spectra Energy Partners, LP
DEBT
Weighted Average Interest Rate		2.00%	2.00%
Total debt		CAD 2,824	$ 2,254	0
Commercial paper and credit facility draws | Union Gas Limited
DEBT
Weighted Average Interest Rate		1.30%	1.30%
Total debt		CAD 485		0
Other | Enbridge Inc.
DEBT
Total debt		3		4
Other | Enbridge Pipelines Inc.
DEBT
Total debt		CAD 4		4
Senior notes | Enbridge Energy Partners, L.P.
DEBT
Weighted Average Interest Rate		6.20%	6.20%
Total debt		CAD 6,328	$ 5,050	6,781	5,050
Senior notes | Enbridge Pipelines (Southern Lights) L.L.C.
DEBT
Weighted Average Interest Rate		4.00%	4.00%
Total debt		CAD 1,207	$ 963	1,342	1,000
Senior notes | Enbridge Southern Lights LP
DEBT
Weighted Average Interest Rate		4.00%	4.00%
Total debt		CAD 315		323
Senior notes | Midcoast Energy Partners, L.P.
DEBT
Weighted Average Interest Rate		4.10%	4.10%
Total debt		CAD 501	$ 400	537	400
Senior notes | Spectra Energy Capital
DEBT
Weighted Average Interest Rate		5.30%	5.30%
Total debt		CAD 1,665	$ 1,329	0
Senior notes | Spectra Energy Partners, LP
DEBT
Weighted Average Interest Rate		2.70%	2.70%
Total debt		CAD 7,192	$ 5,740	0
Junior subordinated notes | Enbridge Energy Partners, L.P.
DEBT
Total debt		CAD 501	$ 400	537	$ 400
Debentures | Enbridge Gas Distribution Inc.
DEBT
Weighted Average Interest Rate		9.90%	9.90%
Total debt		CAD 85		85
Debentures | Enbridge Pipelines Inc.
DEBT
Weighted Average Interest Rate		8.20%	8.20%
Total debt		CAD 200		200
Debentures | Westcoast Energy Inc.
DEBT
Weighted Average Interest Rate		8.60%	8.60%
Total debt		CAD 525		0
Debentures | Union Gas Limited
DEBT
Weighted Average Interest Rate		8.70%	8.70%
Total debt		CAD 250		0
Senior secured notes | Spectra Energy Partners, LP
DEBT
Weighted Average Interest Rate		6.10%	6.10%
Total debt		CAD 138	$ 110	0
Senior secured notes | Westcoast Energy Inc.
DEBT
Weighted Average Interest Rate		6.40%	6.40%
Total debt		CAD 66		0
Senior debentures | Union Gas Limited
DEBT
Weighted Average Interest Rate		8.70%	8.70%
Total debt		CAD 75		CAD 0
Bankers' Acceptance Rate | Floating rate notes | Enbridge Inc.
DEBT
Basis spread on variable rate (as a percent)		0.59%
London Interbank Offered Rate (LIBOR) | Floating rate notes | Spectra Energy Partners, LP
DEBT
Basis spread on variable rate (as a percent)		0.70%
London Interbank Offered Rate (LIBOR) | Junior subordinated notes | Enbridge Energy Partners, L.P.
DEBT
Basis spread on variable rate (as a percent)		3.7975%
Minimum | London Interbank Offered Rate (LIBOR) | Floating rate notes | Enbridge Inc.
DEBT
Basis spread on variable rate (as a percent)		0.40%
Maximum | London Interbank Offered Rate (LIBOR) | Floating rate notes | Enbridge Inc.
DEBT
Basis spread on variable rate (as a percent)		0.70%

DEBT - Secured Debt (Narrative)

DEBT - Secured Debt (Narrative) (Details) CAD in Millions	Dec. 31, 2017CAD
Debt Disclosure [Abstract]
Senior secured notes	CAD 206

DEBT - Schedule of Committed Cr

DEBT - Schedule of Committed Credit Facilities (Details) - Dec. 31, 2017 CAD in Millions, $ in Millions	CAD	USD ($)
DEBT
Commitments that expire in 2018	CAD 2,831
Commitments that expire in 2020	6,722
Commitments that expire in 2021	2,505
Committed credit facilities
DEBT
Total Facilities	24,011
Draws	11,532
Available	12,479
Enbridge (U.S.) Inc. | Committed credit facilities
DEBT
Total Facilities	3,590
Draws	490
Available	3,100
Enbridge Energy Partners, L.P. | Committed credit facilities
DEBT
Total Facilities	3,289
Draws	1,820
Available	1,469
Commitments that expire in 2018	219	$ 175
Commitments that expire in 2020	232	185
Enbridge Gas Distribution Inc. | Committed credit facilities
DEBT
Total Facilities	1,016
Draws	972
Available	44
Enbridge Income Fund | Committed credit facilities
DEBT
Total Facilities	1,500
Draws	766
Available	734
Enbridge Pipelines (Southern Lights) L.L.C. | Committed credit facilities
DEBT
Total Facilities	25
Draws	0
Available	25
Enbridge Pipelines Inc. | Committed credit facilities
DEBT
Total Facilities	3,000
Draws	1,438
Available	1,562
Enbridge Southern Lights LP | Committed credit facilities
DEBT
Total Facilities	5
Draws	0
Available	5
Spectra Energy Partners, LP | Committed credit facilities
DEBT
Total Facilities	3,133
Draws	2,824
Available	309
Commitments that expire in 2021	421	336
Union Gas Limited | Committed credit facilities
DEBT
Total Facilities	700
Draws	485
Available	215
Westcoast Energy Inc. | Committed credit facilities
DEBT
Total Facilities	400
Draws	0
Available	400
Enbridge Inc. | Committed credit facilities
DEBT
Total Facilities	7,353
Draws	2,737
Available	4,616
Commitments that expire in 2018 | $		$ 125
Commitments that expire in 2020	150
Debt Instrument, Redemption, Period One | Enbridge Inc. | Committed credit facilities
DEBT
Commitments that expire in 2018	135
Debt Instrument, Redemption, Period Two | Enbridge Inc. | Committed credit facilities
DEBT
Commitments that expire in 2018	CAD 157

DEBT - Credit Facilities (Narra

DEBT - Credit Facilities (Narrative) (Details) ¥ in Millions, CAD in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2017CAD	Dec. 31, 2017CAD	Mar. 31, 2017JPY (¥)	Dec. 31, 2016CAD
Line of Credit Facility [Line Items]
Weighted average standby fee (as a percent)		0.20%
Long-term debt		CAD 60,865		CAD 36,494
Uncommitted credit facilities
Line of Credit Facility [Line Items]
Term credit facility		792		335
Unutilized credit facility		518		177
Japanese banks
Line of Credit Facility [Line Items]
Term of credit facility	5 years
Term credit facility	CAD 239		¥ 20,000
Commercial paper and credit facility draws
Line of Credit Facility [Line Items]
Long-term debt		CAD 10,055		CAD 7,344

DEBT - Schedule of Long-term De

DEBT - Schedule of Long-term Debt Issuances (Details) - CAD CAD in Millions	1 Months Ended
	Oct. 31, 2017	Sep. 30, 2017	Jul. 31, 2017	Jun. 30, 2017	May 31, 2017	Dec. 31, 2016	Dec. 31, 2017	Nov. 30, 2017	Jul. 13, 2017	Nov. 30, 2016	Aug. 31, 2016
Enbridge Gas Distribution Inc. | 3.51% medium-term notes due November 2047
Debt Instrument [Line Items]
Principal Amount								CAD 300
Fixed interest rate (as a percent)							3.51%
Enbridge Gas Distribution Inc. | 2.50% medium-term notes due August 2026
Debt Instrument [Line Items]
Principal Amount											CAD 300
Fixed interest rate (as a percent)							2.50%
Enbridge Pipelines Inc. | 3.00% medium-term notes due August 2026
Debt Instrument [Line Items]
Principal Amount											400
Fixed interest rate (as a percent)							3.00%
Enbridge Pipelines Inc. | 4.13% medium-term notes due August 2046
Debt Instrument [Line Items]
Principal Amount											CAD 400
Fixed interest rate (as a percent)							4.13%
Spectra Energy Partners, LP | Floating rate notes due June 2020
Debt Instrument [Line Items]
Principal Amount				CAD 400
Basis spread on variable rate (as a percent)				0.70%
Union Gas Limited | 2.88% medium-term notes due November 2027
Debt Instrument [Line Items]
Principal Amount								250
Fixed interest rate (as a percent)							2.88%
Union Gas Limited | 3.59% medium-term notes due November 2047
Debt Instrument [Line Items]
Principal Amount								CAD 250
Fixed interest rate (as a percent)							3.59%
Enbridge Inc. | Floating rate notes due May 2019
Debt Instrument [Line Items]
Principal Amount					CAD 750
Basis spread on variable rate (as a percent)					0.59%
Enbridge Inc. | 3.19% medium-term notes due December 2022
Debt Instrument [Line Items]
Principal Amount				CAD 450
Fixed interest rate (as a percent)							3.19%
Enbridge Inc. | 3.20% medium-term notes due June 2027
Debt Instrument [Line Items]
Principal Amount				450
Fixed interest rate (as a percent)							3.20%
Enbridge Inc. | 4.57% medium-term notes due March 2044
Debt Instrument [Line Items]
Principal Amount				300
Fixed interest rate (as a percent)							4.57%
Enbridge Inc. | Floating rate notes due June 2020
Debt Instrument [Line Items]
Principal Amount				CAD 500
Basis spread on variable rate (as a percent)				0.70%
Enbridge Inc. | 2.90% senior notes due July 2022
Debt Instrument [Line Items]
Principal Amount			CAD 700
Fixed interest rate (as a percent)							2.90%
Enbridge Inc. | 3.70% senior notes due July 2027
Debt Instrument [Line Items]
Principal Amount			700
Fixed interest rate (as a percent)							3.70%
Enbridge Inc. | Fixed-to-floating rate subordinated notes due July 2077
Debt Instrument [Line Items]
Principal Amount			CAD 1,000
Term of credit facility			60 years
Callable period			10 years
Term of fixed rate			10 years
Fixed interest rate (as a percent)			5.50%
Enbridge Inc. | Fixed-to-floating rate subordinated notes due September 2077
Debt Instrument [Line Items]
Principal Amount	CAD 650	CAD 1,000
Term of credit facility		60 years
Callable period		10 years
Term of fixed rate		10 years
Fixed interest rate (as a percent)		5.40%
Enbridge Inc. | Floating rate notes due January 2020
Debt Instrument [Line Items]
Principal Amount	CAD 700
Basis spread on variable rate (as a percent)	0.40%
Enbridge Inc. | 4.25% medium-term notes due December 2026
Debt Instrument [Line Items]
Principal Amount										CAD 750
Fixed interest rate (as a percent)							4.25%
Enbridge Inc. | 5.50% medium-term notes due December 2046
Debt Instrument [Line Items]
Principal Amount										CAD 750
Fixed interest rate (as a percent)							5.50%
Enbridge Inc. | Fixed-to-floating rate subordinated notes due January 2077
Debt Instrument [Line Items]
Principal Amount						CAD 750
Term of credit facility						60 years
Callable period						10 years
Term of fixed rate						10 years
Fixed interest rate (as a percent)						6.00%
Minimum | Enbridge Inc. | Fixed-to-floating rate subordinated notes due July 2077
Debt Instrument [Line Items]
Period when the notes carry a variable interest rate			10 years
Maximum
Debt Instrument [Line Items]
Fixed interest rate (as a percent)							7.50%		7.50%
Debt Instrument, Redemption, Period One | Enbridge Inc. | Fixed-to-floating rate subordinated notes due July 2077
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)			3.42%
Debt Instrument, Redemption, Period One | Enbridge Inc. | Fixed-to-floating rate subordinated notes due September 2077
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)		3.25%
Debt Instrument, Redemption, Period One | Enbridge Inc. | Fixed-to-floating rate subordinated notes due January 2077
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)						3.89%
Debt Instrument, Redemption, Period One | Minimum | Enbridge Inc. | Fixed-to-floating rate subordinated notes due September 2077
Debt Instrument [Line Items]
Period when the notes carry a variable interest rate		10 years
Debt Instrument, Redemption, Period One | Minimum | Enbridge Inc. | Fixed-to-floating rate subordinated notes due January 2077
Debt Instrument [Line Items]
Period when the notes carry a variable interest rate						10 years
Debt Instrument, Redemption, Period One | Maximum | Enbridge Inc. | Fixed-to-floating rate subordinated notes due July 2077
Debt Instrument [Line Items]
Period when the notes carry a variable interest rate			30 years
Debt Instrument, Redemption, Period One | Maximum | Enbridge Inc. | Fixed-to-floating rate subordinated notes due September 2077
Debt Instrument [Line Items]
Period when the notes carry a variable interest rate		30 years
Debt Instrument, Redemption, Period One | Maximum | Enbridge Inc. | Fixed-to-floating rate subordinated notes due January 2077
Debt Instrument [Line Items]
Period when the notes carry a variable interest rate						30 years
Debt Instrument, Redemption, Period Two | Enbridge Inc. | Fixed-to-floating rate subordinated notes due July 2077
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)			4.17%
Debt Instrument, Redemption, Period Two | Enbridge Inc. | Fixed-to-floating rate subordinated notes due September 2077
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)		4.00%
Debt Instrument, Redemption, Period Two | Enbridge Inc. | Fixed-to-floating rate subordinated notes due January 2077
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)						4.64%
Debt Instrument, Redemption, Period Two | Minimum | Enbridge Inc. | Fixed-to-floating rate subordinated notes due July 2077
Debt Instrument [Line Items]
Period when the notes carry a variable interest rate			30 years
Debt Instrument, Redemption, Period Two | Minimum | Enbridge Inc. | Fixed-to-floating rate subordinated notes due September 2077
Debt Instrument [Line Items]
Period when the notes carry a variable interest rate		30 years
Debt Instrument, Redemption, Period Two | Minimum | Enbridge Inc. | Fixed-to-floating rate subordinated notes due January 2077
Debt Instrument [Line Items]
Period when the notes carry a variable interest rate						30 years
Debt Instrument, Redemption, Period Two | Maximum | Enbridge Inc. | Fixed-to-floating rate subordinated notes due July 2077
Debt Instrument [Line Items]
Period when the notes carry a variable interest rate			60 years
Debt Instrument, Redemption, Period Two | Maximum | Enbridge Inc. | Fixed-to-floating rate subordinated notes due September 2077
Debt Instrument [Line Items]
Period when the notes carry a variable interest rate		60 years
Debt Instrument, Redemption, Period Two | Maximum | Enbridge Inc. | Fixed-to-floating rate subordinated notes due January 2077
Debt Instrument [Line Items]
Period when the notes carry a variable interest rate						60 years

DEBT - Schedule of Long-Term110

DEBT - Schedule of Long-Term Debt Repayments (Details) CAD in Millions, $ in Millions

Jul. 13, 2017USD ($)

Dec. 31, 2017CAD

Nov. 30, 2017CAD

Sep. 30, 2017CAD

Jul. 31, 2017CAD

Jun. 30, 2017CAD

Apr. 30, 2017CAD

Mar. 31, 2017CAD

Dec. 31, 2016CAD

Nov. 30, 2016CAD

Oct. 31, 2016CAD

Aug. 31, 2016CAD

May 31, 2016CAD

Sep. 08, 2017USD ($)

Sep. 30, 2017CAD

Dec. 31, 2017CAD

Nov. 30, 2017CAD

Dec. 31, 2016CAD

Dec. 31, 2017CAD

Dec. 31, 2017USD ($)

8.00% senior notes due 2019

Debt Instrument [Line Items]

Aggregate principal amount tendered and redeemed | $

$ 500

Enbridge Energy Partners, L.P. | 5.88% senior notes

Debt Instrument [Line Items]

Principal Amount

CAD 300

Interest rate

5.88%

5.88%

5.88%

5.88%

Enbridge Gas Distribution Inc. | 1.85% medium-term notes

Debt Instrument [Line Items]

Principal Amount

CAD 0

Interest rate

1.85%

1.85%

1.85%

1.85%

Enbridge Gas Distribution Inc. | 5.16% medium-term notes

Debt Instrument [Line Items]

Principal Amount

CAD 0

Interest rate

5.16%

5.16%

5.16%

5.16%

Enbridge Income Fund | Floating rate note

Debt Instrument [Line Items]

Principal Amount

CAD 0

Enbridge Income Fund | 5.00% medium-term notes

Debt Instrument [Line Items]

Principal Amount

CAD 0

Interest rate

5.00%

5.00%

5.00%

5.00%

Enbridge Income Fund | 2.92% medium-term notes

Debt Instrument [Line Items]

Principal Amount

CAD 0

Interest rate

2.92%

2.92%

2.92%

2.92%

Enbridge Pipelines (Southern Lights) L.L.C. | 3.98% medium-term note due June 2040

Debt Instrument [Line Items]

Principal Amount

CAD 37

CAD 30

Interest rate

3.98%

3.98%

3.98%

3.98%

Enbridge Southern Lights LP | 4.01% medium-term note due June 2040

Debt Instrument [Line Items]

Principal Amount

0

CAD 0

Interest rate

4.01%

4.01%

4.01%

4.01%

Spectra Energy Capitals, LLC

Debt Instrument [Line Items]

Loss on debt extinguishment

CAD 50

$ 38

Spectra Energy Capitals, LLC | 8.00% senior notes due 2019

Debt Instrument [Line Items]

Principal Amount

$ 581

CAD 500

Interest rate

8.00%

8.00%

8.00%

8.00%

8.00%

Spectra Energy Capitals, LLC | Senior notes carrying interest ranging from 3.3% to 7.5% due 2018 to 2038

Debt Instrument [Line Items]

Principal Amount

$ 761

CAD 761

Repayments of related party debt | $

$ 857

Spectra Energy Partners, LP | 6.00% senior notes

Debt Instrument [Line Items]

Principal Amount

CAD 400

Interest rate

6.00%

6.00%

6.00%

6.00%

Spectra Energy Partners, LP | 7.39% subordinated secured notes

Debt Instrument [Line Items]

Principal Amount

CAD 12

Interest rate

7.39%

7.39%

7.39%

7.39%

Union Gas Limited | 9.70% debentures

Debt Instrument [Line Items]

Principal Amount

CAD 0

Interest rate

9.70%

9.70%

9.70%

9.70%

Westcoast Energy Inc. | 6.90% senior secured notes

Debt Instrument [Line Items]

Principal Amount

CAD 0

Interest rate

6.90%

6.90%

6.90%

6.90%

Westcoast Energy Inc. | 4.34% senior secured notes

Debt Instrument [Line Items]

Principal Amount

CAD 0

Interest rate

4.34%

4.34%

4.34%

4.34%

Enbridge Inc. | Floating rate note

Debt Instrument [Line Items]

Principal Amount

CAD 500

CAD 0

CAD 350

Enbridge Inc. | 5.60% medium-term notes

Debt Instrument [Line Items]

Principal Amount

CAD 400

Interest rate

5.60%

5.60%

5.60%

5.60%

Enbridge Inc. | 5.17% medium-term notes

Debt Instrument [Line Items]

Principal Amount

CAD 0

Interest rate

5.17%

5.17%

5.17%

5.17%

Enbridge Inc. | 5.00% medium-term notes

Debt Instrument [Line Items]

Principal Amount

CAD 0

Interest rate

5.00%

5.00%

5.00%

5.00%

Minimum | Spectra Energy Capitals, LLC | Senior notes carrying interest ranging from 3.3% to 7.5% due 2018 to 2038

Debt Instrument [Line Items]

Interest rate

3.30%

3.30%

3.30%

3.30%

3.30%

Debt maturity (term)

1 year

Maximum

Debt Instrument [Line Items]

Interest rate

7.50%

7.50%

7.50%

7.50%

7.50%

Maximum | Spectra Energy Capitals, LLC | Senior notes carrying interest ranging from 3.3% to 7.5% due 2018 to 2038

Debt Instrument [Line Items]

Debt maturity (term)

21 years

DEBT - Schedule of Interest Exp

DEBT - Schedule of Interest Expense (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
DEBT
Capitalized	CAD (391)	CAD (321)	CAD (353)
Total interest expense	2,556	1,590	1,624
Spectra Energy
DEBT
Amortization of fair value adjustment - Spectra Energy acquisition	(270)	0	0
Debentures and term notes
DEBT
Interest expense on debt	3,011	1,714	1,805
Commercial paper and credit facility draws
DEBT
Interest expense on debt	CAD 206	CAD 197	CAD 172

ASSET RETIREMENT OBLIGATIONS (D

ASSET RETIREMENT OBLIGATIONS (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Reconciliation of movements in the Company's ARO
Obligations at beginning of year	CAD 232	CAD 198
Liabilities acquired	546	0
Liabilities incurred	0	2
Liabilities settled	(22)	(33)
Change in estimate	18	63
Foreign currency translation adjustment	(12)	(5)
Accretion expense	31	7
Obligations at end of year	793	232
Accounts payable and other	2	2
Other long-term liabilities	CAD 791	CAD 230

NONCONTROLLING INTERESTS - NONC

NONCONTROLLING INTERESTS - NONCONTROLLING (Details) - CAD shares in Millions, CAD in Millions	Dec. 31, 2017	Dec. 31, 2016
NONCONTROLLING INTERESTS
Noncontrolling interests	CAD 7,597	CAD 577
Enbridge Energy Management, L.L.C. (EEM)
NONCONTROLLING INTERESTS
Noncontrolling interests	CAD 34	CAD 36
Ownership interest percentage held by noncontrolling owners	88.30%	88.30%
Enbridge Energy Partners, L.P.
NONCONTROLLING INTERESTS
Noncontrolling interests	CAD 157	CAD (99)
Ownership interest percentage held by noncontrolling owners	68.20%	80.20%
Enbridge Gas Distribution Inc.
NONCONTROLLING INTERESTS
Noncontrolling interests	CAD 100	CAD 100
Enbridge Gas Distribution Inc. | Preference shares
NONCONTROLLING INTERESTS
Number of redeemable preferred shares held by noncontrolling owners (in shares)		4
Renewable energy assets
NONCONTROLLING INTERESTS
Noncontrolling interests	806	CAD 516
Spectra Energy Corp
NONCONTROLLING INTERESTS
Noncontrolling interests	CAD 5,385	0
Ownership interest percentage held by noncontrolling owners	25.70%
Union Gas Limited
NONCONTROLLING INTERESTS
Noncontrolling interests	CAD 110	0
Union Gas Limited | Preference shares
NONCONTROLLING INTERESTS
Number of redeemable preferred shares held by noncontrolling owners (in shares)	4
Westcoast Energy Inc.
NONCONTROLLING INTERESTS
Noncontrolling interests	CAD 1,005	0
Westcoast Energy Inc. | Preference shares
NONCONTROLLING INTERESTS
Number of redeemable preferred shares held by noncontrolling owners (in shares)	16.6
umber of first preferred shares held by noncontrolling owners (in shares)	12
Other noncontrolling interest
NONCONTROLLING INTERESTS
Noncontrolling interests	CAD 0	CAD 24
Magic Valley
NONCONTROLLING INTERESTS
Ownership interest percentage held by noncontrolling owners		20.00%
Wildcat
NONCONTROLLING INTERESTS
Ownership interest percentage held by noncontrolling owners	20.00%	20.00%
Maritimes and Northeast Pipeline
NONCONTROLLING INTERESTS
Ownership interest percentage held by noncontrolling owners	22.00%

NONCONTROLLING INTERESTS - N114

NONCONTROLLING INTERESTS - NONCONTROLLING INFORMATION (Details) CAD / shares in Units, $ / shares in Units, CAD in Millions, $ in Millions

Jun. 28, 2017USD ($)

Apr. 28, 2017CAD

Apr. 27, 2017USD ($)shares

Mar. 13, 2015CAD

Mar. 13, 2015USD ($)

Jan. 02, 2015CAD

Jan. 02, 2015USD ($)

Jan. 01, 2015

Dec. 31, 2017CAD

Dec. 31, 2016CAD

Apr. 27, 2017CAD / shares

Apr. 27, 2017$ / shares

Feb. 15, 2017

Enbridge Energy Partners, L.P.

NONCONTROLLING INTERESTS

Increase (decrease) in noncontrolling interest

CAD (304)

Increase to additional paid in capital

218

Increase to deferred income taxes

CAD 86

Common units, quarterly distribution per unit | (per share)

CAD 0.583

$ 0.35

Reduction in income (loss) attributable to noncontrolling interests and redeemable noncontrolling interests due to reallocation

CAD 73

CAD 816

GP interest percent in EEP

2.00%

2.00%

Contributions from unitholders

CAD 366

$ 289

Strategic Review Actions | Enbridge Energy Partners, L.P.

NONCONTROLLING INTERESTS

Increase (decrease) in noncontrolling interest

CAD 458

Increase to additional paid in capital

421

Increase to deferred income taxes

CAD 253

Enbridge Inc. | Enbridge Energy Partners, L.P.

NONCONTROLLING INTERESTS

Repayments of related party debt | $

$ 1,500

Midcoast Energy Partners, L.P.

NONCONTROLLING INTERESTS

Total ownership interest (as a percent)

100.00%

Midcoast Energy Partners, L.P. | Midcoast Public Unitholders [Member]

NONCONTROLLING INTERESTS

Purchase price | $

170

Midcoast Energy Partners, L.P. | Enbridge Energy Partners, L.P.

NONCONTROLLING INTERESTS

Payments to acquire businesses, gross | $

$ 1,300

Liabilities assumed | $

$ 953

Preferred Units Series1 | Enbridge Inc. | Enbridge Energy Partners, L.P.

NONCONTROLLING INTERESTS

Partners' capital account, redemptions | $

$ 1,200

Common Units Classa | Enbridge Inc. | Enbridge Energy Partners, L.P.

NONCONTROLLING INTERESTS

Partners' capital account, units, sold in private placement | shares

64,300,000

Common Units Class D | Enbridge Inc. | Enbridge Energy Partners, L.P.

NONCONTROLLING INTERESTS

Common units rights waived, number of units | shares

66,100,000

Incentive Distribution Units | Enbridge Inc. | Enbridge Energy Partners, L.P.

NONCONTROLLING INTERESTS

Common units rights waived, number of units | shares

1,000

Common Units Class F | Enbridge Energy Partners, L.P.

NONCONTROLLING INTERESTS

Common units distribution percentage above first threshold

13.00%

13.00%

Common units first distribution threshold | $ / shares

$ 0.295

Common units second distribution threshold | $ / shares

$ 0.35

Common units distribution percentage above second threshold

23.00%

23.00%

Common Units Class F | Enbridge Inc. | Enbridge Energy Partners, L.P.

NONCONTROLLING INTERESTS

Partners' capital account, units, sold in private placement | shares

1,000

Bakken Pipeline System

NONCONTROLLING INTERESTS

Joint funding arrangement, ownership percentage

75.00%

75.00%

Ownership interest (as a percent)

27.60%

27.60%

Bakken Pipeline System | Enbridge Energy Partners, L.P.

NONCONTROLLING INTERESTS

Joint funding arrangement, ownership percentage

25.00%

25.00%

Ownership interest (as a percent)

27.60%

Joint funding arrangement, period of option to purchase additional interest

5 years

Joint funding arrangement, additional interest under option

20.00%

20.00%

Alberta Clipper Pipeline | Enbridge Energy Partners, L.P.

NONCONTROLLING INTERESTS

Ownership percentage before transfer

33.30%

Alberta Clipper Pipeline | Enbridge Energy Partners, L.P.

NONCONTROLLING INTERESTS

Investment ownership percentage transferred

66.70%

66.70%

Consideration received

CAD 1,100

$ 1,000

Consideration received as debt repayment

359

306

Preference Shares, Series E | Alberta Clipper Pipeline | Enbridge Energy Partners, L.P.

NONCONTROLLING INTERESTS

Equity received as consideration

CAD 814

$ 694

NONCONTROLLING INTERESTS - REDE

NONCONTROLLING INTERESTS - REDEEMABLE NONCONTROLLING INFORMATION (Details) $ in Millions	Apr. 18, 2017CADshares	Apr. 30, 2017USD ($)	Mar. 31, 2017CAD	Dec. 31, 2017CADshares	Dec. 31, 2016CADshares	Dec. 31, 2015CADshares	Nov. 30, 2017	Apr. 30, 2016	Mar. 31, 2016	Nov. 30, 2015	Oct. 31, 2015
REDEEMABLE NONCONTROLLING INTERESTS
Balance at beginning of year			CAD 3,392,000,000	CAD 3,392,000,000	CAD 2,141,000,000	CAD 2,249,000,000
Earnings/(loss) attributable to redeemable noncontrolling interests				175,000,000	268,000,000	(3,000,000)
Change in unrealized loss on cash flow hedges				(21,000,000)	(17,000,000)	(7,000,000)
Other comprehensive loss from equity investees				0	0	(12,000,000)
Reclassification to earnings of loss on cash flow hedges				57,000,000	9,000,000	4,000,000
Foreign currency translation adjustments				(6,000,000)	(3,000,000)	18,000,000
Other comprehensive income/(loss)				30,000,000	(11,000,000)	3,000,000
Distributions to unitholders				(247,000,000)	(202,000,000)	(114,000,000)
Contributions from unitholders				1,178,000,000	591,000,000	670,000,000
Reversal of cumulative redemption value adjustment attributable to ECT preferred units				0	0	(541,000,000)
Dilution gain/(loss) for redeemable noncontrolling interests				(169,000,000)	(81,000,000)	(482,000,000)
Redemption value adjustment				(292,000,000)	686,000,000	359,000,000
Balance at end of year				4,067,000,000	3,392,000,000	2,141,000,000
Redeemable Noncontrolling Interest, Common Share Issuances [Abstract]
Common shares issued				1,549,000,000	2,260,000,000	57,000,000
Dilution gain/(loss) for redeemable noncontrolling interests				CAD (169,000,000)	CAD (81,000,000)	CAD (482,000,000)
Additional disclosure
Units purchased | shares				1,600,000	1,300,000	0
Enbridge Commercial Trust
REDEEMABLE NONCONTROLLING INTERESTS
Dilution gain/(loss) for redeemable noncontrolling interests				CAD (123,000,000)	CAD (103,000,000)	CAD (132,000,000)
Redeemable Noncontrolling Interest, Common Share Issuances [Abstract]
Dilution gain/(loss) for redeemable noncontrolling interests				(123,000,000)	(103,000,000)	(132,000,000)
Dilution gain/(loss) in Additional paid-in capital				123,000,000	103,000,000	132,000,000
Enbridge Commercial Trust | Enbridge Income Fund
Redeemable Noncontrolling Interest, Common Share Issuances [Abstract]
Proceeds from issuance				CAD 718,000,000	CAD 718,000,000	CAD 874,000,000
Enbridge Income Fund
Additional disclosure
Ownership interest percentage held by noncontrolling owners				56.50%	45.60%	40.70%	53.60%	45.60%	40.70%	40.70%	34.30%
Enbridge Income Fund Holdings Inc | Common Stock Issuance
REDEEMABLE NONCONTROLLING INTERESTS
Dilution gain/(loss) for redeemable noncontrolling interests				CAD 5,000,000	CAD (4,000,000)	CAD (355,000,000)
Redeemable Noncontrolling Interest, Common Share Issuances [Abstract]
Proceeds from issuance				552,000,000	551,000,000	670,000,000
Dilution gain/(loss) for redeemable noncontrolling interests				5,000,000	(4,000,000)	(355,000,000)
Dilution gain/(loss) in Additional paid-in capital				(5,000,000)	4,000,000	355,000,000
Enbridge Income Fund Holdings Inc | Dividend Reinvestment Plan
REDEEMABLE NONCONTROLLING INTERESTS
Dilution gain/(loss) for redeemable noncontrolling interests				0	0	0
Redeemable Noncontrolling Interest, Common Share Issuances [Abstract]
Proceeds from issuance				51	40	0
Dilution gain/(loss) for redeemable noncontrolling interests				0	0	0
Dilution gain/(loss) in Additional paid-in capital				0	0	0
Enbridge Income Fund Holdings Inc | Public investors
Redeemable Noncontrolling Interest, Common Share Issuances [Abstract]
Common shares issued				575,000,000	575,000,000	700,000,000
Enbridge Income Fund Holdings Inc | Enbridge Inc.
Redeemable Noncontrolling Interest, Common Share Issuances [Abstract]
Common shares issued				143,000,000	143,000,000	174,000,000
Secondary Offering By Parent | Enbridge Income Fund Holdings Inc
REDEEMABLE NONCONTROLLING INTERESTS
Dilution gain/(loss) for redeemable noncontrolling interests | $		$ (87)
Redeemable Noncontrolling Interest, Common Share Issuances [Abstract]
Dilution gain/(loss) for redeemable noncontrolling interests | $		$ (87)
Additional disclosure
Sale of stock, percentage of ownership after transaction	19.90%
Sale of stock, number of shares retained by parent (in shares) | shares	4,309,867
Secondary Offering By Parent | Enbridge Income Fund Holdings Inc | Public investors
Additional disclosure
Sale of stock, consideration received by parent	CAD 575,000,000
Secondary Offering By Parent | Enbridge Income Fund Holdings Inc | Enbridge Inc.
Additional disclosure
Stock issued during period, shares, conversion of units (in shares) | shares	21,657,617
Enbridge Income Fund Holdings Inc
Redeemable Noncontrolling Interest, Common Share Issuances [Abstract]
Dilution gain/(loss) in Additional paid-in capital				CAD 41,000,000	CAD 30,000,000	CAD 5,000,000
Additional disclosure
Ownership interest percentage held by noncontrolling owners			45.60%	53.70%
Economic interest (as a percent)	84.60%		86.90%
Ownership interest (as a percent)				19.90%

SHARE CAPITAL - COMMON SHARES (

SHARE CAPITAL - COMMON SHARES (Details) shares in Millions, CAD in Millions	12 Months Ended
	Dec. 31, 2017CADshares	Dec. 31, 2016CADshares	Dec. 31, 2015CADshares	Dec. 31, 2017$ / shares
Share Capital
Common shares par value (in dollars per share) | $ / shares				$ 0
Common Shares
Balance at beginning of period (in shares) | shares	943
Balance at end of period (in shares) | shares	1,695	943
Gross proceeds | CAD	CAD 1,549	CAD 2,260	CAD 57
Issuance costs | CAD	CAD 0	CAD 59	CAD 0
Common shares
Common Shares
Balance at beginning of period (in shares) | shares	943	868	852
Balance at beginning of period, Amount | CAD	CAD 10,492	CAD 7,391	CAD 6,669
Common shares issued (in shares) | shares	33	56	0
Common shares issued, Amount | CAD	CAD 1,500	CAD 2,241	CAD 0
Common shares issued in Merger Transaction (in shares) | shares	691	0	0
Common shares issued in Merger Transaction, Amount | CAD	CAD 37,429	CAD 0	CAD 0
Dividend Reinvestment and Share Purchase Plan (in shares) | shares	25	16	12
Dividend Reinvestment and Share Purchase Plan | CAD	CAD 1,226	CAD 795	CAD 646
Shares issued on exercise of stock options (in shares) | shares	3	3	4
Shares issued on exercise of stock options, Amount | CAD	CAD 90	CAD 65	CAD 76
Balance at end of period (in shares) | shares	1,695	943	868
Balance at end of period, Amount | CAD	CAD 50,737	CAD 10,492	CAD 7,391

SHARE CAPITAL - PREFERRED SHARE

SHARE CAPITAL - PREFERRED SHARES (Details) CAD / shares in Units, CAD in Millions

Mar. 01, 2018CAD / shares

Feb. 28, 2018CAD / shares

Dec. 01, 2017CAD / shares

Sep. 01, 2017CAD / shares

Sep. 01, 2017$ / shares

Aug. 31, 2017$ / shares

Jun. 01, 2017CAD / sharesshares

Jun. 01, 2017$ / sharesshares

May 31, 2017CAD / shares

May 31, 2017$ / shares

Dec. 31, 2017CADCAD / sharesshares

Dec. 31, 2017CADCAD / shares$ / sharesshares

Dec. 31, 2016CADshares

Dec. 31, 2015CADshares

Feb. 14, 2018shares

Dec. 31, 2017$ / shares

Preference Shares

Issuance costs | CAD

CAD 0

CAD (59)

CAD 0

Convertible Preferred Stock, Shares Issued upon Conversion | shares

1,730,188

1,730,188

Preference Shares, Series B

Preference Shares

Yearly dividend per share (in dollars per share)

CAD 0.21340

CAD 0.25000

Preference Shares, Series C

Preference Shares

Yearly dividend per share (in dollars per share)

CAD 0.20342

CAD 0.19571

CAD 0.18600

Preference Shares, Series J

Preference Shares

Yearly dividend per share (in dollars per share) | $ / shares

$ 0.30540

$ 0.25000

Preference Shares, Series L

Preference Shares

Yearly dividend per share (in dollars per share) | $ / shares

$ 0.30993

$ 0.25000

Preference shares

Preference Shares

Preferred stock, value, outstanding | CAD

7,747

CAD 7,747

7,255

6,515

Issuance costs | CAD

CAD (155)

CAD (147)

CAD (137)

Recurring anniversary period following the redemption option date, at which the entity may redeem preferred shares

5 years

Stock split conversion ratio

1

Quarterly floating rate cumulative dividends per share calculation, base multiplier (in dollars per share) | (per share)

CAD 25

CAD 25

Quarterly floating rate cumulative dividends per share calculation, period of calendar year

365 days

Quarterly floating rate cumulative dividends per share calculation, maturity period of Government of Canada treasury bill

90 days

Quarterly floating rate cumulative dividends per share calculation, maturity period of Government of US treasury bill

3 months

Preference shares | Preference Shares, Series A

Preference Shares

Preferred stock, shares outstanding (in shares) | shares

5,000,000

5,000,000

5,000,000

5,000,000

Preferred stock, value, outstanding | CAD

CAD 125

CAD 125

CAD 125

CAD 125

Initial Yield (as a percent)

5.50%

Yearly dividend per share (in dollars per share)

CAD 1.37500

Per Share Base Redemption Value (in dollars per shares)

CAD 25

CAD 25

Preference shares | Preference Shares, Series B

Preference Shares

Preferred stock, shares outstanding (in shares) | shares

18,000,000

18,000,000

20,000,000

20,000,000

Preferred stock, value, outstanding | CAD

CAD 457

CAD 457

CAD 500

CAD 500

Initial Yield (as a percent)

3.415%

Yearly dividend per share (in dollars per share)

CAD 0.85360

Per Share Base Redemption Value (in dollars per shares)

CAD 25

CAD 25

Preference shares | Preference Shares, Series C

Preference Shares

Preferred stock, shares outstanding (in shares) | shares

2,000,000

2,000,000

0

0

Preferred stock, value, outstanding | CAD

CAD 43

CAD 43

CAD 0

CAD 0

Initial Yield (as a percent)

2.40%

Yearly dividend per share (in dollars per share)

CAD 0

Per Share Base Redemption Value (in dollars per shares)

CAD 25

CAD 25

Quarterly floating rate cumulative dividends per share calculation, spread on Government of Canada treasury bill rate (as a percent)

2.40%

Preference shares | Preference Shares, Series D

Preference Shares

Preferred stock, shares outstanding (in shares) | shares

18,000,000

18,000,000

18,000,000

18,000,000

Preferred stock, value, outstanding | CAD

CAD 450

CAD 450

CAD 450

CAD 450

Initial Yield (as a percent)

4.00%

Yearly dividend per share (in dollars per share)

CAD 1

Per Share Base Redemption Value (in dollars per shares)

CAD 25

CAD 25

Preference shares | Preference Shares, Series F

Preference Shares

Preferred stock, shares outstanding (in shares) | shares

20,000,000

20,000,000

20,000,000

20,000,000

Preferred stock, value, outstanding | CAD

CAD 500

CAD 500

CAD 500

CAD 500

Initial Yield (as a percent)

4.00%

Yearly dividend per share (in dollars per share)

CAD 1

Per Share Base Redemption Value (in dollars per shares)

CAD 25

CAD 25

Preference shares | Preference Shares, Series H

Preference Shares

Preferred stock, shares outstanding (in shares) | shares

14,000,000

14,000,000

14,000,000

14,000,000

Preferred stock, value, outstanding | CAD

CAD 350

CAD 350

CAD 350

CAD 350

Initial Yield (as a percent)

4.00%

Yearly dividend per share (in dollars per share)

CAD 1

Per Share Base Redemption Value (in dollars per shares)

CAD 25

CAD 25

Preference shares | Preference Shares, Series J

Preference Shares

Preferred stock, shares outstanding (in shares) | shares

8,000,000

8,000,000

8,000,000

8,000,000

Preferred stock, value, outstanding | CAD

CAD 199

CAD 199

CAD 199

CAD 199

Initial Yield (as a percent)

4.887%

Yearly dividend per share (in dollars per share) | $ / shares

CAD 1.22160

Per Share Base Redemption Value (in dollars per shares) | $ / shares

$ 25

Preference shares | Preference Shares, Series L

Preference Shares

Preferred stock, shares outstanding (in shares) | shares

16,000,000

16,000,000

16,000,000

16,000,000

Preferred stock, value, outstanding | CAD

CAD 411

CAD 411

CAD 411

CAD 411

Initial Yield (as a percent)

4.959%

Yearly dividend per share (in dollars per share) | $ / shares

CAD 1.23972

Per Share Base Redemption Value (in dollars per shares) | $ / shares

25

Preference shares | Preference Shares, Series N

Preference Shares

Preferred stock, shares outstanding (in shares) | shares

18,000,000

18,000,000

18,000,000

18,000,000

Preferred stock, value, outstanding | CAD

CAD 450

CAD 450

CAD 450

CAD 450

Initial Yield (as a percent)

4.00%

Yearly dividend per share (in dollars per share)

CAD 1

Per Share Base Redemption Value (in dollars per shares)

CAD 25

CAD 25

Preference shares | Preference Shares, Series P

Preference Shares

Preferred stock, shares outstanding (in shares) | shares

16,000,000

16,000,000

16,000,000

16,000,000

Preferred stock, value, outstanding | CAD

CAD 400

CAD 400

CAD 400

CAD 400

Initial Yield (as a percent)

4.00%

Yearly dividend per share (in dollars per share)

CAD 1

Per Share Base Redemption Value (in dollars per shares)

CAD 25

CAD 25

Preference shares | Preference Shares, Series R

Preference Shares

Preferred stock, shares outstanding (in shares) | shares

16,000,000

16,000,000

16,000,000

16,000,000

Preferred stock, value, outstanding | CAD

CAD 400

CAD 400

CAD 400

CAD 400

Initial Yield (as a percent)

4.00%

Yearly dividend per share (in dollars per share)

CAD 1

Per Share Base Redemption Value (in dollars per shares)

CAD 25

CAD 25

Preference shares | Preference Shares, Series 1

Preference Shares

Preferred stock, shares outstanding (in shares) | shares

16,000,000

16,000,000

16,000,000

16,000,000

Preferred stock, value, outstanding | CAD

CAD 411

CAD 411

CAD 411

CAD 411

Initial Yield (as a percent)

4.00%

Yearly dividend per share (in dollars per share) | $ / shares

CAD 1

Per Share Base Redemption Value (in dollars per shares) | $ / shares

25

Preference shares | Preference Shares, Series 3

Preference Shares

Preferred stock, shares outstanding (in shares) | shares

24,000,000

24,000,000

24,000,000

24,000,000

Preferred stock, value, outstanding | CAD

CAD 600

CAD 600

CAD 600

CAD 600

Initial Yield (as a percent)

4.00%

Yearly dividend per share (in dollars per share)

CAD 1

Per Share Base Redemption Value (in dollars per shares)

CAD 25

CAD 25

Preference shares | Preference Shares, Series 5

Preference Shares

Preferred stock, shares outstanding (in shares) | shares

8,000,000

8,000,000

8,000,000

8,000,000

Preferred stock, value, outstanding | CAD

CAD 206

CAD 206

CAD 206

CAD 206

Initial Yield (as a percent)

4.40%

Yearly dividend per share (in dollars per share) | $ / shares

CAD 1.100

Per Share Base Redemption Value (in dollars per shares) | $ / shares

$ 25

Preference shares | Preference Shares, Series 7

Preference Shares

Preferred stock, shares outstanding (in shares) | shares

10,000,000

10,000,000

10,000,000

10,000,000

Preferred stock, value, outstanding | CAD

CAD 250

CAD 250

CAD 250

CAD 250

Initial Yield (as a percent)

4.40%

Yearly dividend per share (in dollars per share)

CAD 1.10000

Per Share Base Redemption Value (in dollars per shares)

CAD 25

CAD 25

Preference shares | Preference Shares, Series 9

Preference Shares

Preferred stock, shares outstanding (in shares) | shares

11,000,000

11,000,000

11,000,000

11,000,000

Preferred stock, value, outstanding | CAD

CAD 275

CAD 275

CAD 275

CAD 275

Initial Yield (as a percent)

4.40%

Yearly dividend per share (in dollars per share)

CAD 1.10000

Per Share Base Redemption Value (in dollars per shares)

CAD 25

CAD 25

Preference shares | Preference Shares, Series 11

Preference Shares

Preferred stock, shares outstanding (in shares) | shares

20,000,000

20,000,000

20,000,000

20,000,000

Preferred stock, value, outstanding | CAD

CAD 500

CAD 500

CAD 500

CAD 500

Initial Yield (as a percent)

4.40%

Yearly dividend per share (in dollars per share)

CAD 1.10000

Per Share Base Redemption Value (in dollars per shares)

CAD 25

CAD 25

Preference shares | Preference Shares, Series 13

Preference Shares

Preferred stock, shares outstanding (in shares) | shares

14,000,000

14,000,000

14,000,000

14,000,000

Preferred stock, value, outstanding | CAD

CAD 350

CAD 350

CAD 350

CAD 350

Initial Yield (as a percent)

4.40%

Yearly dividend per share (in dollars per share)

CAD 1.10000

Per Share Base Redemption Value (in dollars per shares)

CAD 25

CAD 25

Preference shares | Preference Shares, Series 15

Preference Shares

Preferred stock, shares outstanding (in shares) | shares

11,000,000

11,000,000

11,000,000

11,000,000

Preferred stock, value, outstanding | CAD

CAD 275

CAD 275

CAD 275

CAD 275

Initial Yield (as a percent)

4.40%

Yearly dividend per share (in dollars per share)

CAD 1.10000

Per Share Base Redemption Value (in dollars per shares)

CAD 25

CAD 25

Preference shares | Preference Shares, Series 17

Preference Shares

Preferred stock, shares outstanding (in shares) | shares

30,000,000

30,000,000

30,000,000

0

Preferred stock, value, outstanding | CAD

CAD 750

CAD 750

CAD 750

CAD 0

Initial Yield (as a percent)

5.15%

Yearly dividend per share (in dollars per share)

CAD 1.28750

Per Share Base Redemption Value (in dollars per shares)

CAD 25

CAD 25

Minimum fixed dividend rate upon reset (as a percent)

5.15%

Preference shares | Preference Shares, Series 19

Preference Shares

Preferred stock, shares outstanding (in shares) | shares

20,000,000

20,000,000

0

0

Preferred stock, value, outstanding | CAD

CAD 500

CAD 500

CAD 0

CAD 0

Initial Yield (as a percent)

4.90%

Yearly dividend per share (in dollars per share)

CAD 1.22500

Per Share Base Redemption Value (in dollars per shares)

CAD 25

CAD 25

Minimum fixed dividend rate upon reset (as a percent)

4.90%

Preference shares | Preferred Stock Excluding Series

Preference Shares

Reset term of fixed dividend rate

5 years

Preference shares | Preference Shares, Series E

Preference Shares

Quarterly floating rate cumulative dividends per share calculation, spread on Government of Canada treasury bill rate (as a percent)

2.40%

Preference shares | Series G Preferred Stock

Preference Shares

Quarterly floating rate cumulative dividends per share calculation, spread on Government of Canada treasury bill rate (as a percent)

2.50%

Preference shares | Series I Preferred Stock

Preference Shares

Quarterly floating rate cumulative dividends per share calculation, spread on Government of Canada treasury bill rate (as a percent)

2.10%

Preference shares | Series O Preferred Stock

Preference Shares

Quarterly floating rate cumulative dividends per share calculation, spread on Government of Canada treasury bill rate (as a percent)

2.70%

Preference shares | Series Q Preferred Stock

Preference Shares

Quarterly floating rate cumulative dividends per share calculation, spread on Government of Canada treasury bill rate (as a percent)

2.50%

Preference shares | Series S Preferred Stock

Preference Shares

Quarterly floating rate cumulative dividends per share calculation, spread on Government of Canada treasury bill rate (as a percent)

2.50%

Preference shares | Series 4 Preferred Stock

Preference Shares

Quarterly floating rate cumulative dividends per share calculation, spread on Government of Canada treasury bill rate (as a percent)

2.40%

Preference shares | Series 8 Preferred Stock

Preference Shares

Quarterly floating rate cumulative dividends per share calculation, spread on Government of Canada treasury bill rate (as a percent)

2.60%

Preference shares | Series10 Preferred Stock

Preference Shares

Quarterly floating rate cumulative dividends per share calculation, spread on Government of Canada treasury bill rate (as a percent)

2.70%

Preference shares | Series12 Preferred Stock

Preference Shares

Quarterly floating rate cumulative dividends per share calculation, spread on Government of Canada treasury bill rate (as a percent)

2.60%

Preference shares | Series14 Preferred Stock

Preference Shares

Quarterly floating rate cumulative dividends per share calculation, spread on Government of Canada treasury bill rate (as a percent)

2.70%

Preference shares | Series16 Preferred Stock

Preference Shares

Quarterly floating rate cumulative dividends per share calculation, spread on Government of Canada treasury bill rate (as a percent)

2.70%

Preference shares | Series18 Preferred Stock

Preference Shares

Quarterly floating rate cumulative dividends per share calculation, spread on Government of Canada treasury bill rate (as a percent)

4.10%

Preference shares | Series 20 Preferred Stock

Preference Shares

Quarterly floating rate cumulative dividends per share calculation, spread on Government of Canada treasury bill rate (as a percent)

3.20%

Preference shares | Series K Preferred Stock

Preference Shares

Quarterly floating rate cumulative dividends per share calculation, spread on Government of US treasury bill rate (as a percent)

3.10%

Preference shares | Series M Preferred Stock

Preference Shares

Quarterly floating rate cumulative dividends per share calculation, spread on Government of US treasury bill rate (as a percent)

3.20%

Preference shares | Series 2 Preferred Stock

Preference Shares

Quarterly floating rate cumulative dividends per share calculation, spread on Government of US treasury bill rate (as a percent)

3.10%

Preference shares | Series 6 Preferred Stock

Preference Shares

Quarterly floating rate cumulative dividends per share calculation, spread on Government of US treasury bill rate (as a percent)

2.80%

Scenario, Forecast | Preference Shares, Series D

Preference Shares

Yearly dividend per share (in dollars per share)

CAD 0.27875

CAD 0.25000

Convertible Preferred Stock, Shares Issued upon Conversion | shares

1,000,000

SHARE CAPITAL - PLANS (Details)

SHARE CAPITAL - PLANS (Details) CAD in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2017CAD	Dec. 31, 2017USD ($)	Dec. 31, 2016CAD	Dec. 31, 2016USD ($)	Dec. 31, 2015CAD
Dividends Payable [Line Items]
Discount on the purchase of common shares with reinvested dividends (as a percent)	2.00%	2.00%
Payments of dividends | $		$ 3,500		$ 1,900
Common share dividends	CAD 2,750		CAD 1,150		CAD 950
Minimum outstanding common shares required to be acquired to exercise the Shareholder Rights Plan (as a percent)	20.00%	20.00%
Discount to the market price available to each rights holder, other than the acquiring person and related parties, under the Shareholder Rights Plan (as a percent)	50.00%	50.00%
Common shares
Dividends Payable [Line Items]
Payments of Ordinary Dividends	CAD 2,300		1,200
Dividend Reinvestment and Share Purchase Plan	CAD 1,226		CAD 795		CAD 646
Spectra Energy Corp
Dividends Payable [Line Items]
Common share dividends | $		$ 414

STOCK OPTION AND STOCK UNIT 119

STOCK OPTION AND STOCK UNIT PLANS - INCENTIVE PLANS (Details) CAD in Millions	12 Months Ended
	Dec. 31, 2017CADcompensation_planshares	Dec. 31, 2016CAD	Dec. 31, 2015CAD
STOCK OPTION AND STOCK UNIT PLANS
Number of long-term incentive compensation plans | compensation_plan	4
Compensation expense | CAD	CAD 165	CAD 130	CAD 97
2002 ISO plan
STOCK OPTION AND STOCK UNIT PLANS
Maximum number of common shares reserved for issuance under the share-based compensation plan (in shares)	60,000,000
Number of shares issued to date under the share-based compensation plan (in shares)	50,000,000
2007 ISO and PSO plans
STOCK OPTION AND STOCK UNIT PLANS
Maximum number of common shares reserved for issuance under the share-based compensation plan (in shares)	71,000,000
Number of shares issued to date under the share-based compensation plan (in shares)	16,000,000
PSU and RSU plans
STOCK OPTION AND STOCK UNIT PLANS
Number of common shares for each stock unit granted (in shares)	1

STOCK OPTION AND STOCK UNIT 120

STOCK OPTION AND STOCK UNIT PLANS - STOCK OPTION ACTIVITY (Details) - INCENTIVE STOCK OPTIONS - CAD CAD / shares in Units, shares in Thousands, CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
STOCK OPTION AND STOCK UNIT PLANS
Vesting period	4 years
Expiration term	10 years
Number
Options outstanding at beginning of year (in shares)	32,909
Options granted (in shares)	5,995
Options exercised (in shares)	(3,350)
Options cancelled or expired (in shares)	(1,188)
Options outstanding at end of year (in shares)	34,366	32,909
Options vested at end of year (in shares)	20,403
Weighted Average Exercise Price
Options outstanding at beginning of year (in dollars per share)	CAD 42.51
Options granted (in dollars per share)	55.72
Options exercised (in dollars per share)	32.65
Options cancelled or expired (in dollars per share)	53.23
Options outstanding at end of year (in dollars per share)	45.41	CAD 42.51
Options vested at end of year (in dollars per share)	CAD 40.89
Weighted Average Remaining Contractual Life (years)
Options outstanding at end of year	6 years 1 month 6 days
Options vested at end of year	4 years 8 months 12 days
Aggregate Intrinsic Value
Options outstanding at end of year	CAD 271
Options vested at end of year	228
Stock options, additional disclosures
Total intrinsic value of awards exercised	62	CAD 123	CAD 126
Cash received on exercise of awards	17	37	43
Total fair value of options vested	CAD 44	CAD 36	CAD 34

STOCK OPTION AND STOCK UNIT 121

STOCK OPTION AND STOCK UNIT PLANS - WEIGHTED AVERAGE ASSUMPTIONS (Details) CAD / shares in Units, CAD in Millions	12 Months Ended
	Dec. 31, 2017CADCAD / shares	Dec. 31, 2016CADCAD / shares	Dec. 31, 2015CADCAD / shares	Dec. 31, 2017$ / shares	Dec. 31, 2016$ / shares	Dec. 31, 2015$ / shares
Weighted average assumptions used to determine the fair value of options
Compensation expense	CAD 165	CAD 130	CAD 97
INCENTIVE STOCK OPTIONS
Weighted average assumptions used to determine the fair value of options
Fair value per option (in dollars per share) | CAD / shares	CAD 6	CAD 7.37	CAD 6.48
Expected option term (in years)	5 years	5 years	5 years
Expected volatility (as a percent)	20.40%	25.10%	19.90%
Expected dividend yield (as a percent)	4.20%	4.40%	3.20%
Risk-free interest rate (as a percent)	1.20%	0.80%	0.90%
Expected option term based on historical practice	6 years
Expected option term based on historical practice for retirement eligible employees	3 years
Compensation expense	CAD 40	CAD 43	CAD 35
Unrecognized compensation cost related to non-vested share-based compensation arrangements granted	CAD 47
Weighted average period over which compensation cost is expected to be recognized	2 years
INCENTIVE STOCK OPTIONS | Canadian employees
Weighted average assumptions used to determine the fair value of options
Fair value per option (in dollars per share) | CAD / shares	CAD 5.66	CAD 7.01	CAD 6.22
INCENTIVE STOCK OPTIONS | United States employees
Weighted average assumptions used to determine the fair value of options
Fair value per option (in dollars per share) | $ / shares				$ 5.72	$ 6.60	$ 6.16

STOCK OPTION AND STOCK UNIT 122

STOCK OPTION AND STOCK UNIT PLANS - PSUs AND RSUs (Details) - CAD shares in Thousands, CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Stock units, additional disclosures
Compensation expense	CAD 165	CAD 130	CAD 97
Restricted Stock Units (RSU)
STOCK OPTION AND STOCK UNIT PLANS
Vesting period	35 months
Period prior to the maturity of the grant for which weighted average share price is used to calculate cash awards	20 days
Number
Units outstanding at beginning of year (in shares)	1,854
Units granted (in shares)	741
Units cancelled (in shares)	(186)
Units matured (in shares)	(839)
Dividend reinvestment (in shares)	123
Units outstanding at end of year (in shares)	1,693	1,854
Weighted Average Remaining Contractual Life (years)
Units outstanding at end of year	1 year 4 months 24 days
Aggregate Intrinsic Value
Units outstanding at end of year	CAD 83
Stock units, additional disclosures
Total amount paid	39	CAD 56	45
Compensation expense	46	CAD 51	CAD 47
Unrecognized compensation expense related to non-vested units granted	CAD 48
Weighted average period over which compensation cost is expected to be recognized	1 year

COMPONENTS OF ACCUMULATED OT123

COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS) (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Changes in AOCI
Balance at the beginning of the period	CAD 21,386
Income tax on amounts reclassified to earnings of derecognized cash flow hedges			CAD 91
Balance at the end of the period	58,135	CAD 21,386
Derecognized cash flow hedges
Changes in AOCI
Other comprehensive (income)/loss reclassified to earnings, Pension and OPEB			338
Accumulated other comprehensive income/(loss)
Changes in AOCI
Balance at the beginning of the period	1,058	1,632	(435)
Other comprehensive income/(loss) retained in AOCI	(2,137)	(760)	2,289
Other comprehensive (income)/loss reclassified to earnings, Pension and OPEB	(41)	(21)	(32)
Total before tax impact	(1,908)	(620)	1,971
Income tax on amounts retained in AOCI	(30)	102	1
Income tax on amounts reclassified to earnings	(93)	(56)	4
Tax impact	123	(46)	96
Balance at the end of the period	(973)	1,058	1,632
Accumulated other comprehensive income/(loss) | Interest rate contracts
Changes in AOCI
Other comprehensive (income)/loss reclassified to earnings, Cash Flow Hedges	207	147	(34)
Accumulated other comprehensive income/(loss) | Commodity contracts
Changes in AOCI
Other comprehensive (income)/loss reclassified to earnings, Cash Flow Hedges	(7)	(11)	(11)
Accumulated other comprehensive income/(loss) | Forward currency contracts
Changes in AOCI
Other comprehensive (income)/loss reclassified to earnings, Cash Flow Hedges	(6)	1	7
Accumulated other comprehensive income/(loss) | Other contracts
Changes in AOCI
Other comprehensive (income)/loss reclassified to earnings, Cash Flow Hedges	(6)	(18)	26
Cash Flow Hedges
Changes in AOCI
Balance at the beginning of the period	(746)	(688)	(488)
Other comprehensive income/(loss) retained in AOCI	1	(216)	73
Total before tax impact	189	(97)	(277)
Income tax on amounts retained in AOCI	(16)	91	(29)
Income tax on amounts reclassified to earnings	(71)	(52)	15
Income tax on amounts reclassified to earnings of derecognized cash flow hedges			91
Tax impact	87	(39)	77
Balance at the end of the period	(644)	(746)	(688)
Cash Flow Hedges | Interest rate contracts
Changes in AOCI
Other comprehensive (income)/loss reclassified to earnings	207	147	(34)
Cash Flow Hedges | Commodity contracts
Changes in AOCI
Other comprehensive (income)/loss reclassified to earnings	(7)	(11)	(11)
Cash Flow Hedges | Forward currency contracts
Changes in AOCI
Other comprehensive (income)/loss reclassified to earnings	(6)	1	7
Cash Flow Hedges | Other contracts
Changes in AOCI
Other comprehensive (income)/loss reclassified to earnings	(6)	(18)	26
Cash Flow Hedges | Derecognized cash flow hedges
Changes in AOCI
Other comprehensive (income)/loss reclassified to earnings			(338)
Net Investment Hedges
Changes in AOCI
Balance at the beginning of the period	(629)	(795)	108
Other comprehensive income/(loss) retained in AOCI	478	171	(952)
Total before tax impact	478	171	(952)
Income tax on amounts retained in AOCI	12	(5)	49
Tax impact	(12)	5	49
Balance at the end of the period	(139)	(629)	(795)
Cumulative Translation Adjustment
Changes in AOCI
Balance at the beginning of the period	2,700	3,365	309
Other comprehensive income/(loss) retained in AOCI	(2,623)	(665)	3,056
Total before tax impact	(2,623)	(665)	3,056
Tax impact	0	0	0
Balance at the end of the period	77	2,700	3,365
Equity Investees
Changes in AOCI
Balance at the beginning of the period	37	37	(5)
Other comprehensive income/(loss) retained in AOCI	(11)	(5)	47
Total before tax impact	(11)	(5)	47
Income tax on amounts retained in AOCI	(16)	5	(5)
Tax impact	16	(5)	(5)
Balance at the end of the period	10	37	37
Pension and OPEB Adjustment
Changes in AOCI
Balance at the beginning of the period	(304)	(287)	(359)
Other comprehensive income/(loss) retained in AOCI	18	(45)	65
Other comprehensive (income)/loss reclassified to earnings			32
Other comprehensive (income)/loss reclassified to earnings, Pension and OPEB	(41)	(21)
Total before tax impact	59	(24)	97
Income tax on amounts retained in AOCI	(10)	11	(14)
Income tax on amounts reclassified to earnings	(22)	(4)	(11)
Tax impact	32	(7)	(25)
Balance at the end of the period	CAD (277)	CAD (304)	CAD (287)

RISK MANAGEMENT AND FINANCIA124

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - MARKET RISK (Details)	1 Months Ended	12 Months Ended
	Feb. 01, 2018	Dec. 31, 2017CADNumber_of_equity	Dec. 31, 2016CAD
Fair Value Hedges
Outstanding fair value hedges | CAD		CAD 0	CAD 0
Minimum
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
Floating rate debt as a percentage of total debt outstanding		2.20%
Maximum
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
Floating rate debt as a percentage of total debt outstanding		25.00%
Interest rate contracts - short-term borrowings
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
Average swap rate (as a percent)		2.60%
Interest rate contracts - long-term debt
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
Average swap rate (as a percent)		3.10%
Equity contracts
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
Number of forms of stock-based compensation with equity price risk | Number_of_equity		1
Subsequent Event | Maximum
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
Floating rate debt as a percentage of total debt outstanding	30.00%

RISK MANAGEMENT AND FINANCIA125

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - TOTAL DERIVATIVE INSTRUMENTS (Details) - CAD CAD in Millions	Dec. 31, 2017	Dec. 31, 2016
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	CAD (2,192)	CAD (4,150)
Derivative assets, Amounts Available for Offset		0
Total Net Derivative Instruments	(2,192)	(4,150)
Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(1,991)	(3,229)
Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(155)	(591)
Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(46)	(330)
Accounts receivable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	296	353
Derivative assets, Amounts Available for Offset	(150)	(231)
Derivative assets, Total Net Derivative Instruments	146	122
Accounts receivable and other | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	281	237
Accounts receivable and other | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	9	113
Accounts receivable and other | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	4	3
Accounts receivable and other | Fair Value Hedging | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	2
Deferred amounts and other assets
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	181	151
Derivative assets, Amounts Available for Offset	(146)	(100)
Derivative assets, Total Net Derivative Instruments	35	51
Deferred amounts and other assets | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	149	131
Deferred amounts and other assets | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	25	17
Deferred amounts and other assets | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	1	3
Deferred amounts and other assets | Fair Value Hedging | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	6
Accounts payable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(1,130)	(1,941)
Derivative liabilities, Amounts Available for Offset	150	231
Derivative liabilities, Total Net Derivative Instruments	(980)	(1,710)
Accounts payable and other | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(936)	(1,220)
Accounts payable and other | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(146)	(453)
Accounts payable and other | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(42)	(268)
Accounts payable and other | Fair Value Hedging | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(6)
Other long-term liabilities
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(1,539)	(2,713)
Derivative liabilities, Amounts Available for Offset	146	100
Derivative liabilities, Total Net Derivative Instruments	(1,393)	(2,613)
Other long-term liabilities | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(1,485)	(2,377)
Other long-term liabilities | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(43)	(268)
Other long-term liabilities | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(9)	(68)
Other long-term liabilities | Fair Value Hedging | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(2)
Forward currency contracts
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(1,383)	(2,842)
Total Net Derivative Instruments	(1,383)	(2,842)
Forward currency contracts | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(1,330)	(2,614)
Forward currency contracts | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(7)	102
Forward currency contracts | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(46)	(330)
Forward currency contracts | Accounts receivable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	143	109
Derivative assets, Amounts Available for Offset	(83)	(103)
Derivative assets, Total Net Derivative Instruments	60	6
Forward currency contracts | Accounts receivable and other | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	138	5
Forward currency contracts | Accounts receivable and other | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	1	101
Forward currency contracts | Accounts receivable and other | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	4	3
Forward currency contracts | Deferred amounts and other assets
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	145	73
Derivative assets, Amounts Available for Offset	(125)	(72)
Derivative assets, Total Net Derivative Instruments	20	1
Forward currency contracts | Deferred amounts and other assets | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	143	69
Forward currency contracts | Deferred amounts and other assets | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	1	1
Forward currency contracts | Deferred amounts and other assets | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	1	3
Forward currency contracts | Accounts payable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(359)	(995)
Derivative liabilities, Amounts Available for Offset	83	103
Derivative liabilities, Total Net Derivative Instruments	(276)	(892)
Forward currency contracts | Accounts payable and other | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(312)	(727)
Forward currency contracts | Accounts payable and other | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(5)	0
Forward currency contracts | Accounts payable and other | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(42)	(268)
Forward currency contracts | Other long-term liabilities
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(1,312)	(2,029)
Derivative liabilities, Amounts Available for Offset	125	72
Derivative liabilities, Total Net Derivative Instruments	(1,187)	(1,957)
Forward currency contracts | Other long-term liabilities | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(1,299)	(1,961)
Forward currency contracts | Other long-term liabilities | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(4)
Forward currency contracts | Other long-term liabilities | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(9)	(68)
Interest rate contracts
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(348)	(1,045)
Total Net Derivative Instruments	(348)	(1,045)
Interest rate contracts | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(183)	(336)
Interest rate contracts | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(165)	(709)
Interest rate contracts | Accounts receivable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	8	3
Derivative assets, Amounts Available for Offset	(3)	(3)
Derivative assets, Total Net Derivative Instruments	5
Interest rate contracts | Accounts receivable and other | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	6	3
Interest rate contracts | Accounts receivable and other | Fair Value Hedging | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	2
Interest rate contracts | Deferred amounts and other assets
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	13	8
Derivative assets, Amounts Available for Offset	(2)	(6)
Derivative assets, Total Net Derivative Instruments	11	2
Interest rate contracts | Deferred amounts and other assets | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	7	8
Interest rate contracts | Deferred amounts and other assets | Fair Value Hedging | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	6
Interest rate contracts | Accounts payable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(329)	(583)
Derivative liabilities, Amounts Available for Offset	3	3
Derivative liabilities, Total Net Derivative Instruments	(326)	(580)
Interest rate contracts | Accounts payable and other | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(183)	(131)
Interest rate contracts | Accounts payable and other | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(140)	(452)
Interest rate contracts | Accounts payable and other | Fair Value Hedging | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(6)
Interest rate contracts | Other long-term liabilities
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(40)	(473)
Derivative liabilities, Amounts Available for Offset	2	6
Derivative liabilities, Total Net Derivative Instruments	(38)	(467)
Interest rate contracts | Other long-term liabilities | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	0	(205)
Interest rate contracts | Other long-term liabilities | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(38)	(268)
Interest rate contracts | Other long-term liabilities | Fair Value Hedging | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(2)
Commodity contracts
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(457)	(261)
Derivative assets, Amounts Available for Offset		0
Total Net Derivative Instruments	(457)	(261)
Commodity contracts | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(476)	(277)
Commodity contracts | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	19	16
Commodity contracts | Accounts receivable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	145	241
Derivative assets, Amounts Available for Offset	(64)	(125)
Derivative assets, Total Net Derivative Instruments	81	116
Commodity contracts | Accounts receivable and other | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	143	232
Commodity contracts | Accounts receivable and other | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	2	9
Commodity contracts | Deferred amounts and other assets
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	23	68
Derivative assets, Amounts Available for Offset	(19)	(22)
Derivative assets, Total Net Derivative Instruments	4	46
Commodity contracts | Deferred amounts and other assets | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	6	61
Commodity contracts | Deferred amounts and other assets | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	17	7
Commodity contracts | Accounts payable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(439)	(359)
Derivative liabilities, Amounts Available for Offset	64	125
Derivative liabilities, Total Net Derivative Instruments	(375)	(234)
Commodity contracts | Accounts payable and other | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(439)	(359)
Commodity contracts | Other long-term liabilities
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(186)	(211)
Derivative liabilities, Amounts Available for Offset	19	22
Derivative liabilities, Total Net Derivative Instruments	(167)	(189)
Commodity contracts | Other long-term liabilities | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(186)	(211)
Other contracts
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(4)	(2)
Total Net Derivative Instruments	(4)	(2)
Other contracts | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(2)	(2)
Other contracts | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(2)	0
Other contracts | Deferred amounts and other assets
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented		2
Derivative assets, Amounts Available for Offset		0
Derivative assets, Total Net Derivative Instruments		2
Other contracts | Deferred amounts and other assets | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented		1
Other contracts | Deferred amounts and other assets | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented		1
Other contracts | Accounts payable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(3)	(4)
Derivative liabilities, Total Net Derivative Instruments	(3)	(4)
Other contracts | Accounts payable and other | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(2)	(3)
Other contracts | Accounts payable and other | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(1)	CAD (1)
Other contracts | Other long-term liabilities
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(1)
Derivative liabilities, Total Net Derivative Instruments	(1)
Other contracts | Other long-term liabilities | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	CAD (1)

RISK MANAGEMENT AND FINANCIA126

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - NOTIONAL PRINCIPAL OR QUANTITY INFORMATION (Details) € in Millions, ¥ in Millions, £ in Millions, MWh in Millions, MMBbls in Millions, CAD in Millions, Bcf in Millions, $ in Millions	Dec. 31, 2017CADMWhBcfMMBbls	Dec. 31, 2017USD ($)MWhBcfMMBbls	Dec. 31, 2017JPY (¥)MWhBcfMMBbls	Dec. 31, 2017GBP (£)MWhBcfMMBbls	Dec. 31, 2017EUR (€)MWhBcfMMBbls	Dec. 31, 2016CADMWhBcfMMBbls	Dec. 31, 2016USD ($)MWhBcfMMBbls	Dec. 31, 2016JPY (¥)MWhBcfMMBbls	Dec. 31, 2016GBP (£)MWhBcfMMBbls	Dec. 31, 2016EUR (€)MWhBcfMMBbls
Foreign exchange contracts - United States dollar or GBP or Japanese yen forwards - purchase
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2018 Notional Amount		$ 755	¥ 0	£ 18	€ 280
2019 Notional Amount		2	32,662	0	375
2020 Notional Amount		2	0	0	0
2021 Notional Amount		0	0	0	0
2022 Notional amount		0	20,000	0	0
Thereafter		0	¥ 0	0	0
Total Notional Amount Outstanding							$ 997	¥ 32,662	£ 97	€ 0
Foreign exchange contracts - United States dollar or GBP forwards - sell
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2018 Notional Amount		4,478		0	0
2019 Notional Amount		3,246		89	0
2020 Notional Amount		3,258		25	35
2021 Notional Amount		1,689		27	169
2022 Notional amount		1,676		28	169
Thereafter		$ 1,820		£ 149	€ 889
Total Notional Amount Outstanding							$ 13,591		£ 285	€ 0
Interest rate contracts - short-term borrowings
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2018 Notional Amount	CAD 4,950
2019 Notional Amount	1,585
2020 Notional Amount	215
2021 Notional Amount	95
2022 Notional amount	91
Thereafter	202
Total Notional Amount Outstanding						CAD 14,008
Interest rate contracts - long-term debt
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2018 Notional Amount	1,522
2019 Notional Amount	1,018
2020 Notional Amount	822
2021 Notional Amount	433
2022 Notional amount	349
Thereafter	52
Total Notional Amount Outstanding						0
Interest rate contract - long term debt - Pay Fixed Rate
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2018 Notional Amount	4,007
2019 Notional Amount	957
2020 Notional Amount	438
2021 Notional Amount	0
2022 Notional amount	0
Thereafter	0
Total Notional Amount Outstanding						7,509
Equity contracts
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2018 Notional Amount	45
2019 Notional Amount	37
2020 Notional Amount	8
2021 Notional Amount	0
2022 Notional amount	0
Thereafter	CAD 0
Total Notional Amount Outstanding						CAD 88
Commodity contracts | Natural gas
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2018 Nonmonetary Notional Amount | Bcf	(59)	(59)	(59)	(59)	(59)
2019 Nonmonetary Notional Amount | Bcf	(69)	(69)	(69)	(69)	(69)
2020 Nonmonetary Notional Amount | Bcf	(20)	(20)	(20)	(20)	(20)
2021 Nonmonetary Notional amount | Bcf	(10)	(10)	(10)	(10)	(10)
2022 Nonmonetary Notional Amount | Bcf	(1)	(1)	(1)	(1)	(1)
Thereafter | Bcf	0	0	0	0	0
Derivative Nonmonetary Notional Amount Outstanding | Bcf						(161)	(161)	(161)	(161)	(161)
Commodity contracts | Crude oil
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2018 Nonmonetary Notional Amount | MMBbls	(3)	(3)	(3)	(3)	(3)
2019 Nonmonetary Notional Amount | MMBbls	0	0	0	0	0
2020 Nonmonetary Notional Amount | MMBbls	0	0	0	0	0
2021 Nonmonetary Notional amount | MMBbls	0	0	0	0	0
2022 Nonmonetary Notional Amount | MMBbls	0	0	0	0	0
Thereafter | MMBbls	0	0	0	0	0
Derivative Nonmonetary Notional Amount Outstanding | MMBbls						(20)	(20)	(20)	(20)	(20)
Commodity contracts | NGL
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2018 Nonmonetary Notional Amount | MMBbls	(12)	(12)	(12)	(12)	(12)
2019 Nonmonetary Notional Amount | MMBbls	0	0	0	0	0
2020 Nonmonetary Notional Amount | MMBbls	0	0	0	0	0
2021 Nonmonetary Notional amount | MMBbls	0	0	0	0	0
2022 Nonmonetary Notional Amount | MMBbls	0	0	0	0	0
Thereafter | MMBbls	0	0	0	0	0
Derivative Nonmonetary Notional Amount Outstanding | MMBbls						(14)	(14)	(14)	(14)	(14)
Commodity contracts | Power
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2016/2017 | MWh	42	42	42	42	42
2017/2018 | MWh	51	51	51	51	51
2018/2019 | MWh	55	55	55	55	55
2019/2020 | MWh	(3)	(3)	(3)	(3)	(3)
2020/2021 | MWh	(43)	(43)	(43)	(43)	(43)
Thereafter | MWh	(43)	(43)	(43)	(43)	(43)
Derivative Nonmonetary Rate Notional Amount Outstanding | MWh						(4)	(4)	(4)	(4)	(4)

RISK MANAGEMENT AND FINANCIA127

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - EFFECTS ON EARNINGS AND COMPREHENSIVE INCOME (Details) - CAD	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of unrealized gains/(loss) recognized in OCI	CAD 297,000,000	CAD (34,000,000)	CAD (484,000,000)
Amount of (gains)/loss reclassified from AOCI to earnings (effective portion)	283,000,000	106,000,000	119,000,000
De-designation of qualifying hedges in connection with the Canadian Restructuring Plan (Note 1)	0	0	338,000,000
Amount of (gains)/loss reclassified from AOCI to earnings (ineffective portion and amount excluded from effectiveness testing)	(4,000,000)	61,000,000	26,000,000
Total unrealized derivative fair value gains/(loss), net	(1,242,000,000)	(509,000,000)	2,373,000,000
Gain (loss) on derivative	2,000,000
Designated as hedging instrument
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Total unrealized derivative fair value gains/(loss), net	(11,000,000)	0
Non-Qualifying Derivative Instruments
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Total unrealized derivative fair value gains/(loss), net	(10,000,000)
Gain (loss) on derivative	2,000,000
Cash Flow Hedges
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Estimated gain of AOCI related to cash flow hedges reclassified to earnings in the next 12 months	CAD 38,000,000
Period to hedge exposures to the variability of cash flows for all forecasted transactions	36 months
Forward currency contracts | Other income/(expense)
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of (gains)/loss reclassified from AOCI to earnings (effective portion)	CAD (104,000,000)	2,000,000	9,000,000
Forward currency contracts | Non-Qualifying Derivative Instruments
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Total unrealized derivative fair value gains/(loss), net	(1,284,000,000)	(935,000,000)	2,187,000,000
Forward currency contracts | Non-Qualifying Derivative Instruments | Transportation and other services revenues
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Total unrealized derivative fair value gains/(loss), net	(800,000,000)	497,000,000	1,383,000,000
Forward currency contracts | Non-Qualifying Derivative Instruments | Other income/(expense)
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Total unrealized derivative fair value gains/(loss), net	(484,000,000)	438,000,000	804,000,000
Forward currency contracts | Cash Flow Hedges
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of unrealized gains/(loss) recognized in OCI	(5,000,000)	(19,000,000)	77,000,000
Forward currency contracts | Net Investment Hedges
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of unrealized gains/(loss) recognized in OCI	284,000,000	22,000,000	(248,000,000)
Interest rate contracts | Interest expense
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of (gains)/loss reclassified from AOCI to earnings (effective portion)	388,000,000	145,000,000	128,000,000
De-designation of qualifying hedges in connection with the Canadian Restructuring Plan (Note 1)	0	0	338,000,000
Amount of (gains)/loss reclassified from AOCI to earnings (ineffective portion and amount excluded from effectiveness testing)	(4,000,000)	61,000,000	21,000,000
Interest rate contracts | Non-Qualifying Derivative Instruments
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Total unrealized derivative fair value gains/(loss), net	(157,000,000)	(73,000,000)	363,000,000
Interest rate contracts | Cash Flow Hedges
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of unrealized gains/(loss) recognized in OCI	6,000,000	(90,000,000)	(275,000,000)
Commodity contracts | Commodity costs
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of (gains)/loss reclassified from AOCI to earnings (effective portion)	(9,000,000)	(12,000,000)	(46,000,000)
Amount of (gains)/loss reclassified from AOCI to earnings (ineffective portion and amount excluded from effectiveness testing)	0	0	5,000,000
Commodity contracts | Non-Qualifying Derivative Instruments
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Total unrealized derivative fair value gains/(loss), net	199,000,000	508,000,000	(199,000,000)
Commodity contracts | Non-Qualifying Derivative Instruments | Transportation and other services revenues
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Total unrealized derivative fair value gains/(loss), net	104,000,000	(52,000,000)	(328,000,000)
Commodity contracts | Non-Qualifying Derivative Instruments | Commodity sales
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Total unrealized derivative fair value gains/(loss), net	90,000,000	474,000,000	(226,000,000)
Commodity contracts | Non-Qualifying Derivative Instruments | Commodity costs
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Total unrealized derivative fair value gains/(loss), net	(223,000,000)	(38,000,000)	(99,000,000)
Commodity contracts | Non-Qualifying Derivative Instruments | Operating and administrative expense
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Total unrealized derivative fair value gains/(loss), net	38,000,000	20,000,000	2,000,000
Commodity contracts | Cash Flow Hedges
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of unrealized gains/(loss) recognized in OCI	11,000,000	14,000,000	9,000,000
Other contracts | Operating and administrative expense
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of (gains)/loss reclassified from AOCI to earnings (effective portion)	8,000,000	(29,000,000)	28,000,000
Other contracts | Non-Qualifying Derivative Instruments
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Total unrealized derivative fair value gains/(loss), net	0	(9,000,000)	22,000,000
Other contracts | Cash Flow Hedges
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of unrealized gains/(loss) recognized in OCI	1,000,000	CAD 39,000,000	CAD (47,000,000)
Interest Rate Swap | Interest expense
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of (gains)/loss reclassified from AOCI to earnings (effective portion)	CAD 296,000,000

RISK MANAGEMENT AND FINANCIA128

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - LIQUIDITY AND CREDIT RISK (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
LIQUIDITY RISK AND CREDIT RISK
Rolling time period over which the Company forecasts cash requirements	12 months
Period of anticipated requirements for which the Company maintains sufficient liquidity through committed credit facilities	1 year
Period after which receivables are classified as past due	20 days
Derivative instruments
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	CAD 385	CAD 487
Derivative instruments | Canadian financial institutions
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	82	39
Derivative instruments | United States financial institutions
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	19	179
Derivative instruments | European financial institutions
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	145	106
Derivative instruments | Asian financial institutions
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	2	1
Derivative instruments | Other
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	CAD 137	CAD 162

RISK MANAGEMENT AND FINANCIA129

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - FAIR VALUE OF DERIVATIVES (Details) - CAD CAD in Millions	Dec. 31, 2017	Dec. 31, 2016
Fair Value of Derivatives
Current derivative liabilities	CAD (1,130)	CAD (1,941)
Fair Value	(2,192)	(4,150)
Forward currency contracts
Fair Value of Derivatives
Fair Value	(1,383)	(2,842)
Interest rate contracts
Fair Value of Derivatives
Fair Value	(348)	(1,045)
Commodity contracts
Fair Value of Derivatives
Fair Value	(457)	(261)
Other contracts
Fair Value of Derivatives
Fair Value	(4)	(2)
Fair Value
Fair Value of Derivatives
Current derivative assets	296	353
Long-term derivative assets	181	151
Current derivative liabilities	(1,130)	(1,941)
Long-term derivative liabilities	(1,539)	(2,713)
Fair Value	(2,192)	(4,150)
Fair Value | Forward currency contracts
Fair Value of Derivatives
Current derivative assets	143	109
Long-term derivative assets	145	73
Current derivative liabilities	(359)	(995)
Long-term derivative liabilities	(1,312)
Fair Value	(1,383)	(2,842)
Fair Value | Interest rate contracts
Fair Value of Derivatives
Current derivative assets	8	3
Long-term derivative assets	13	8
Current derivative liabilities	(329)	(583)
Long-term derivative liabilities	(40)	(2,029)
Fair Value	(348)	(1,045)
Fair Value | Commodity contracts
Fair Value of Derivatives
Current derivative assets	145	241
Long-term derivative assets	23	68
Current derivative liabilities	(439)	(359)
Long-term derivative liabilities	(186)	(473)
Fair Value	(457)	(261)
Fair Value | Other contracts
Fair Value of Derivatives
Long-term derivative assets		2
Current derivative liabilities	(3)	(4)
Long-term derivative liabilities	(1)	(211)
Fair Value		(2)
Level 1 | Fair Value
Fair Value of Derivatives
Current derivative assets	1	2
Current derivative liabilities	(13)	(12)
Fair Value	(12)	(10)
Level 1 | Fair Value | Commodity contracts
Fair Value of Derivatives
Current derivative assets	1	2
Current derivative liabilities	(13)	(12)
Fair Value	(12)	(10)
Level 2 | Fair Value
Fair Value of Derivatives
Current derivative assets	181	198
Long-term derivative assets	160	126
Current derivative liabilities	(778)	(1,657)
Long-term derivative liabilities	(1,356)	(2,512)
Fair Value	(1,793)	(3,845)
Level 2 | Fair Value | Forward currency contracts
Fair Value of Derivatives
Current derivative assets	143	109
Long-term derivative assets	145	73
Current derivative liabilities	(359)	(995)
Long-term derivative liabilities	(1,312)
Fair Value	(1,383)	(2,842)
Level 2 | Fair Value | Interest rate contracts
Fair Value of Derivatives
Current derivative assets	8	3
Long-term derivative assets	13	8
Current derivative liabilities	(329)	(583)
Long-term derivative liabilities	(40)	(2,029)
Fair Value	(348)	(1,045)
Level 2 | Fair Value | Commodity contracts
Fair Value of Derivatives
Current derivative assets	30	86
Long-term derivative assets	2	43
Current derivative liabilities	(87)	(75)
Long-term derivative liabilities	(3)	(473)
Fair Value	(58)	44
Level 2 | Fair Value | Other contracts
Fair Value of Derivatives
Long-term derivative assets		2
Current derivative liabilities	(3)	(4)
Long-term derivative liabilities	(1)	(10)
Fair Value	(4)	(2)
Level 3 | Fair Value
Fair Value of Derivatives
Current derivative assets	114	153
Long-term derivative assets	21	25
Current derivative liabilities	(339)	(272)
Long-term derivative liabilities	(183)	(201)
Fair Value	(387)	(295)
Level 3 | Fair Value | Commodity contracts
Fair Value of Derivatives
Current derivative assets	114	153
Long-term derivative assets	21
Current derivative liabilities	(339)	(272)
Long-term derivative liabilities	(183)	0
Fair Value	CAD (387)	(295)
Level 3 | Fair Value | Other contracts
Fair Value of Derivatives
Long-term derivative assets		0
Long-term derivative liabilities		CAD (201)

RISK MANAGEMENT AND FINANCIA130

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - LEVEL 3 INPUTS (Details) CAD in Millions	12 Months Ended
	Dec. 31, 2017CADCAD / bblCAD / Gallon-galCAD / MWhCAD / MillionsofBTU-MMBTU	Dec. 31, 2016CAD
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	CAD (2,192)	CAD (4,150)
Fair Value
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	(2,192)	(4,150)
Level 3 | Fair Value
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	CAD (387)	CAD (295)
Market approach valuation technique | Level 3 | Commodity Contracts - Financial | Natural gas | Minimum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | CAD / MillionsofBTU-MMBTU	2.67
Market approach valuation technique | Level 3 | Commodity Contracts - Financial | Natural gas | Maximum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | CAD / MillionsofBTU-MMBTU	5.52
Market approach valuation technique | Level 3 | Commodity Contracts - Financial | Natural gas | Weighted Average
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | CAD / MillionsofBTU-MMBTU	3.38
Market approach valuation technique | Level 3 | Commodity Contracts - Financial | Crude oil | Minimum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | CAD / bbl	43.76
Market approach valuation technique | Level 3 | Commodity Contracts - Financial | Crude oil | Maximum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | CAD / bbl	65.60
Market approach valuation technique | Level 3 | Commodity Contracts - Financial | Crude oil | Weighted Average
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | CAD / bbl	51.03
Market approach valuation technique | Level 3 | Commodity Contracts - Financial | NGL | Minimum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | CAD / Gallon-gal	0.30
Market approach valuation technique | Level 3 | Commodity Contracts - Financial | NGL | Maximum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | CAD / Gallon-gal	1.83
Market approach valuation technique | Level 3 | Commodity Contracts - Financial | NGL | Weighted Average
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | CAD / Gallon-gal	1.32
Market approach valuation technique | Level 3 | Commodity Contracts - Financial | Power | Minimum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | CAD / MWh	15.39
Market approach valuation technique | Level 3 | Commodity Contracts - Financial | Power | Maximum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | CAD / MWh	71.41
Market approach valuation technique | Level 3 | Commodity Contracts - Financial | Power | Weighted Average
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | CAD / MWh	50.72
Market approach valuation technique | Level 3 | Commodity Contracts - Physical | Natural gas | Minimum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | CAD / MillionsofBTU-MMBTU	2.51
Market approach valuation technique | Level 3 | Commodity Contracts - Physical | Natural gas | Maximum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | CAD / MillionsofBTU-MMBTU	7.57
Market approach valuation technique | Level 3 | Commodity Contracts - Physical | Natural gas | Weighted Average
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | CAD / MillionsofBTU-MMBTU	2.93
Market approach valuation technique | Level 3 | Commodity Contracts - Physical | Crude oil | Minimum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | CAD / bbl	34.38
Market approach valuation technique | Level 3 | Commodity Contracts - Physical | Crude oil | Maximum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | CAD / bbl	80.56
Market approach valuation technique | Level 3 | Commodity Contracts - Physical | Crude oil | Weighted Average
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | CAD / bbl	69.01
Market approach valuation technique | Level 3 | Commodity Contracts - Physical | NGL | Minimum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | CAD / Gallon-gal	0.28
Market approach valuation technique | Level 3 | Commodity Contracts - Physical | NGL | Maximum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | CAD / Gallon-gal	1.94
Market approach valuation technique | Level 3 | Commodity Contracts - Physical | NGL | Weighted Average
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | CAD / Gallon-gal	0.93
Market approach valuation technique | Level 3 | Fair Value | Commodity Contracts - Financial | Natural gas
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	CAD (1)
Market approach valuation technique | Level 3 | Fair Value | Commodity Contracts - Financial | Crude oil
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	(4)
Market approach valuation technique | Level 3 | Fair Value | Commodity Contracts - Financial | NGL
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	(12)
Market approach valuation technique | Level 3 | Fair Value | Commodity Contracts - Financial | Power
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	(110)
Market approach valuation technique | Level 3 | Fair Value | Commodity Contracts - Physical | Natural gas
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	(114)
Market approach valuation technique | Level 3 | Fair Value | Commodity Contracts - Physical | Crude oil
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	(148)
Market approach valuation technique | Level 3 | Fair Value | Commodity Contracts - Physical | NGL
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	CAD 3
Option model valuation technique | Level 3 | Commodity Options | Crude oil | Minimum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Option Volatility (as a percent)	15.00%
Option model valuation technique | Level 3 | Commodity Options | Crude oil | Maximum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Option Volatility (as a percent)	24.00%
Option model valuation technique | Level 3 | Commodity Options | Crude oil | Weighted Average
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Option Volatility (as a percent)	22.00%
Option model valuation technique | Level 3 | Commodity Options | Power | Minimum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Option Volatility (as a percent)	29.00%
Option model valuation technique | Level 3 | Commodity Options | Power | Maximum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Option Volatility (as a percent)	55.00%
Option model valuation technique | Level 3 | Commodity Options | Power | Weighted Average
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Option Volatility (as a percent)	35.00%
Option model valuation technique | Level 3 | Fair Value | Commodity Options | Crude oil
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	CAD (1)
Option model valuation technique | Level 3 | Fair Value | Commodity Options | Power
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	CAD 0

RISK MANAGEMENT AND FINANCIA131

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - CHANGES IN LEVEL 3 (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Changes in net fair value of derivative assets and liabilities classified as Level 3
Level 3 net derivative asset at beginning of period	CAD (295)	CAD 54
Total gains/(loss)
Included in earnings	(184)	(113)
Included in OCI	4	3
Settlements	88	(239)
Level 3 net derivative asset at end of period	(387)	(295)
Amount of transfer of fair value of assets between levels	0	0
Amount of transfer of fair value of liabilities between levels	CAD 0	CAD 0

RISK MANAGEMENT AND FINANCIA132

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - OTHER FINANCIAL INSTRUMENTS (Details) - CAD	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Fair Value of Other Financial Instruments
Equity investments at carrying value	CAD 99,000,000	CAD 110,000,000
Restricted investments, at fair value	267,000,000	90,000,000
Long-term debt	67,400,000,000	43,900,000,000
Notes receivable, noncurrent	89,000,000	0
Notes receivable, fair value	89,000,000	0
Net Investment Hedges
Fair Value of Other Financial Instruments
Unrealized foreign exchange gain (loss) on translation of United States dollar denominated debt	367,000,000	121,000,000
Unrealized gain (loss) on change in fair value of outstanding forward exchange forward contracts	286,000,000	21,000,000
Realized gain associated with the settlement of foreign exchange forward contracts	(198,000,000)	3,000,000
Realized gain (loss) associated with the settlement of United Stated dollar denominated debt that matured	23,000,000	26,000,000
Amount of ineffectiveness	CAD 0
Preference shares
Fair Value of Other Financial Instruments
Cumulative dividends based on average yield of Government of Canada bonds, maturity period of bonds	10 years
Cumulative dividends based on average yield of Government of Canada bonds, spread over reference rate (as a percent)	4.38%
Carrying value
Fair Value of Other Financial Instruments
Long-term debt	CAD 64,000,000,000	40,800,000,000
Carrying value | Preference shares
Fair Value of Other Financial Instruments
Held to maturity preferred share investment	371,000,000	CAD 355,000,000
Fair Value | Preference shares
Fair Value of Other Financial Instruments
Held to maturity preferred share investment	CAD 580,000,000

INCOME TAXES - RATE RECONCILIAT

INCOME TAXES - RATE RECONCILIATION (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
INCOME TAX RATE RECONCILIATION
Earnings before income taxes and discontinued operation	CAD 569	CAD 2,451	CAD 11
Canadian federal statutory income tax rate	15.00%	15.00%	15.00%
Expected federal taxes at statutory rate	CAD 85	CAD 368	CAD 2
Increase/(decrease) resulting from:
Provincial and state income taxes	133	34	(204)
Foreign and other statutory rate differentials	(601)	(56)	310
Impact of United States tax reform	(2,045)	0	0
Effects of rate-regulated accounting	(189)	(116)	(52)
Foreign allowable interest deductions	(124)	(107)	(84)
Part VI.1 tax, net of federal Part I deduction	68	56	55
Goodwill write-down	15	0	0
Intercompany sale of investment	0	6	23
Non-taxable portion of gain on sale of investment to unrelated party	0	(61)	0
Valuation allowance	(17)	22	154
Effective Income Tax Rate Reconciliation, Intercorporate Investments, Amount	77	0	0
Noncontrolling interests	(80)	(15)	(28)
Other	(19)	11	(6)
Income taxes on earnings before discontinued operations	CAD (2,697)	CAD 142	CAD 170
Effective income tax rate (as a percent)	(474.00%)	5.80%	1545.50%
Federal component of tax expense (recovery) of adjustments related to prior periods			CAD (17)

INCOME TAXES - COMPONENTS (Deta

INCOME TAXES - COMPONENTS (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Earnings/(loss) before income taxes and discontinued operations
Earnings before income taxes	CAD 569	CAD 2,451	CAD 11
Current income taxes
Total current income taxes	180	99	163
Deferred income taxes
Total deferred income taxes	(2,877)	43	7
Income taxes on earnings before discontinued operations	(2,697)	142	170
Canada
Income Taxes
Operating Loss Carryforwards	3,800	2,500
Earnings/(loss) before income taxes and discontinued operations
Domestic	2,200	2,034	(1,365)
Current income taxes
Domestic	129	74	157
Deferred income taxes
Domestic	299	188	(558)
United States
Income Taxes
Operating Loss Carryforwards	2,100	1,300
Earnings/(loss) before income taxes and discontinued operations
Foreign	(2,431)	(333)	808
Current income taxes
Foreign	46	21	3
Deferred income taxes
Foreign	(3,160)	(151)	565
Other
Earnings/(loss) before income taxes and discontinued operations
Foreign	800	750	568
Current income taxes
Foreign	5	4	3
Deferred income taxes
Foreign	CAD (16)	CAD 6	CAD 0

INCOME TAXES - UNITED STATES TA

INCOME TAXES - UNITED STATES TAX REFROM (Details) CAD in Millions, $ in Billions	12 Months Ended
	Dec. 31, 2017CAD	Dec. 31, 2017USD ($)	Dec. 31, 2016CAD	Dec. 31, 2015CAD
Income Tax Disclosure [Abstract]
Provisional tax expense	CAD 34
Deferred income tax provision	3,100
Deferred income tax asset benefit	1,100
Impact of United States tax reform	CAD 2,045		CAD 0	CAD 0
Reduction in tax amount | $		$ 0.2

INCOME TAXES - DEFERRED INCOME

INCOME TAXES - DEFERRED INCOME TAXES (Details) - CAD	Dec. 31, 2017	Dec. 31, 2016
Deferred income tax liabilities
Property, plant and equipment	CAD (4,089,000,000)	CAD (3,867,000,000)
Investments	(6,596,000,000)	(2,938,000,000)
Regulatory assets	(977,000,000)	(439,000,000)
Other	(50,000,000)	(47,000,000)
Total deferred income tax liabilities	(11,712,000,000)	(7,291,000,000)
Deferred income tax assets
Financial instruments	697,000,000	1,215,000,000
Pension and OPEB plans	258,000,000	219,000,000
Loss carryforwards	1,781,000,000	1,189,000,000
Other	1,057,000,000	374,000,000
Total deferred income tax assets	3,793,000,000	2,997,000,000
Less valuation allowance	(286,000,000)	(572,000,000)
Total deferred income tax assets, net	3,507,000,000	2,425,000,000
Net deferred income tax liabilities	(8,205,000,000)	(4,866,000,000)
Total deferred income tax assets	1,090,000,000	1,170,000,000
Total deferred income tax liabilities	(9,295,000,000)	(6,036,000,000)
Deferred taxes on unremitted earnings and currency translation adjustment	0	0
Foreign subsidiaries' undistributed earnings on which deferred income taxes has not been provided	2,100,000,000	4,100,000,000
Canada
Deferred income tax assets
Benefit of unused tax loss carryforwards recognized	3,800,000,000	2,500,000,000
Capital loss carryforwards	143,000,000	0
United States
Deferred income tax assets
Benefit of unused tax loss carryforwards recognized	2,100,000,000	1,300,000,000
Capital loss carryforwards	CAD 20,000,000	CAD 0

INCOME TAXES - UNRECOGNIZED TAX

INCOME TAXES - UNRECOGNIZED TAX BENEFITS (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
UNRECOGNIZED TAX BENEFITS
Unrecognized tax benefits at beginning of year	CAD 84	CAD 65
Gross increases for tax positions of current year	15	27
Gross increases for tax positions of prior year	65	0
Change in translation of foreign currency	(2)	(2)
Lapses of statute of limitations	(8)	(6)
Settlements	(4)	0
Unrecognized tax benefits at end of year	150	84
Interest and penalties expense (recovery) related to unrecognized tax benefits	3	1
Accrued interest and penalties related to unrecognized tax benefits	CAD 8	CAD 6

PENSION AND OTHER POSTRETIRE138

PENSION AND OTHER POSTRETIREMENT BENEFITS - BENEFIT OBLIGATION, PLAN ASSETS AND FUNDED STATUS (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Canada
Change in plan assets
Employer contributions	CAD 14	CAD 0	CAD 0
Presented as follows:
Deferred amounts and other assets	9	8
Canada | OPEB
Change in projected benefit obligation
Benefit obligation at beginning of year	179	173
Service cost	7	4	3
Interest cost	10	6	7
Actuarial loss	(8)	2
Benefits paid	(10)	(6)
Foreign currency exchange rate changes	0	0
Acquired in Merger Transaction	146	0
Other	(3)	0
Benefit obligation at beginning of year	321	179	173
Change in plan assets
Fair value of plan assets at beginning of year	0	0
Actual return on plan assets	0	0
Employer contributions	10	6
Benefits paid	(10)	(6)
Foreign currency exchange rate changes	0	0
Acquired in Merger Transaction	0	0
Fair value of plan assets at end of year	0	0	0
Underfunded status at end of year	(321)	(179)
Presented as follows:
Deferred amounts and other assets	0	0
Accounts payable and other	(12)	(7)
Other long-term liabilities	(309)	(172)
Amount recognized in balance sheet	(321)	(179)
Canada | Pension
Change in projected benefit obligation
Benefit obligation at beginning of year	2,270	2,064
Service cost	156	129	137
Interest cost	116	73	81
Actuarial loss	145	97
Benefits paid	(165)	(87)
Foreign currency exchange rate changes	0	0
Acquired in Merger Transaction	1,505	0
Plan settlements	0	0
Other	6	(6)
Benefit obligation at beginning of year	4,033	2,270	2,064
Change in plan assets
Fair value of plan assets at beginning of year	2,019	1,886
Actual return on plan assets	308	146
Employer contributions	161	74
Benefits paid	(165)	(87)
Foreign currency exchange rate changes	0	0
Acquired in Merger Transaction	1,290	0
Plan settlements	0	0
Other	6	0
Fair value of plan assets at end of year	3,619	2,019	1,886
Underfunded status at end of year	(414)	(251)
Presented as follows:
Deferred amounts and other assets	38	5
Accounts payable and other	(60)	0
Other long-term liabilities	(392)	(256)
Amount recognized in balance sheet	(414)	(251)
Accumulated benefit obligation	3,700	978
United States
Change in plan assets
Employer contributions	31	13	15
Presented as follows:
Deferred amounts and other assets	40	44
United States | OPEB
Change in projected benefit obligation
Benefit obligation at beginning of year	133	135
Service cost	5	4	5
Interest cost	10	5	4
Actuarial loss	(34)	10
Benefits paid	(19)	(6)
Foreign currency exchange rate changes	(17)	(4)
Acquired in Merger Transaction	254	0
Other	1	(12)
Benefit obligation at beginning of year	337	133	135
Change in plan assets
Fair value of plan assets at beginning of year	115	115
Actual return on plan assets	21	5
Employer contributions	1	3
Benefits paid	(19)	(6)
Foreign currency exchange rate changes	(11)	(3)
Acquired in Merger Transaction	102	0
Fair value of plan assets at end of year	213	115	115
Underfunded status at end of year	(124)	(18)
Presented as follows:
Deferred amounts and other assets	7	4
Accounts payable and other	(7)	0
Other long-term liabilities	(124)	(22)
Amount recognized in balance sheet	(124)	(18)
United States | Pension
Change in projected benefit obligation
Benefit obligation at beginning of year	508	487
Service cost	48	26	30
Interest cost	35	16	17
Actuarial loss	57	15
Benefits paid	(42)	(21)
Foreign currency exchange rate changes	(63)	(14)
Acquired in Merger Transaction	811	0
Plan settlements	(59)	0
Other	(16)	(1)
Benefit obligation at beginning of year	1,279	508	487
Change in plan assets
Fair value of plan assets at beginning of year	361	343
Actual return on plan assets	113	22
Employer contributions	57	28
Benefits paid	(42)	(21)
Foreign currency exchange rate changes	(51)	(10)
Acquired in Merger Transaction	731	0
Plan settlements	(59)	0
Other	(13)	(1)
Fair value of plan assets at end of year	1,097	361	CAD 343
Underfunded status at end of year	(182)	(147)
Presented as follows:
Deferred amounts and other assets	0	0
Accounts payable and other	(3)	0
Other long-term liabilities	(179)	(147)
Amount recognized in balance sheet	(182)	(147)
Accumulated benefit obligation	CAD 1,200	CAD 462

PENSION AND OTHER POSTRETIRE139

PENSION AND OTHER POSTRETIREMENT BENEFITS PENSION AND OTHER POSTRETIREMENT BENEFITS - AMOUNT RECOGNIZED IN EXCESS OF ACCUMULATED OTHER COMPREHENSIVE INCOME (Details) - Pension - CAD CAD in Millions	Dec. 31, 2017	Dec. 31, 2016
Canada
Pension and Other Postretirement Benefit Disclosures
Projected benefit obligations	CAD 1,444	CAD 2,188
Accumulated benefit obligations	1,306	978
Fair value of plan assets	1,131	1,927
United States
Pension and Other Postretirement Benefit Disclosures
Projected benefit obligations	1,280	508
Accumulated benefit obligations	1,217	462
Fair value of plan assets	CAD 1,098	CAD 361

PENSION AND OTHER POSTRETIRE140

PENSION AND OTHER POSTRETIREMENT BENEFITS - AMOUNT RECOGNIZED IN ACCUMULATED OTHER COMPREHENSIVE INCOME (Details) - CAD CAD in Millions	Dec. 31, 2017	Dec. 31, 2016
Canada | Pension
Amount included in AOCI
Net actuarial gain	CAD 334	CAD 310
Total amount recognized in AOCI	334	310
Canada | OPEB
Amount included in AOCI
Net actuarial gain	17	25
Prior service cost	(2)	2
Total amount recognized in AOCI	15	27
United States | Pension
Amount included in AOCI
Net actuarial gain	112	121
Total amount recognized in AOCI	112	121
United States | OPEB
Amount included in AOCI
Net actuarial gain	(15)	29
Prior service cost	(11)	(15)
Total amount recognized in AOCI	CAD (26)	CAD 14

PENSION AND OTHER POSTRETIRE141

PENSION AND OTHER POSTRETIREMENT BENEFITS - NET BENEFIT COSTS RECOGNIZED (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Pension | Canada
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	CAD 156	CAD 129	CAD 137
Interest cost	116	73	81
Expected return on plan assets	(201)	(127)	(120)
Amortization of actuarial loss	29	32	39
Net defined benefit costs	100	107	137
Defined contribution benefit costs	11	3	3
Net benefit cost recognized in Earnings	111	110	140
Amount recognized in OCI:
Net actuarial (gain)/loss arising during the year	38	28	(58)
Amortization of net actuarial gain	(14)	(14)	(20)
Total amount recognized in OCI	24	14	(78)
Total amount recognized in Comprehensive income	135	124	62
Expected amortization, next fiscal year	25
Pension | United States
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	48	26	30
Interest cost	35	16	17
Expected return on plan assets	(57)	(21)	(22)
Amortization of actuarial loss	10	3	10
Net defined benefit costs	36	24	35
Defined contribution benefit costs	15	0	0
Net benefit cost recognized in Earnings	51	24	35
Amount recognized in OCI:
Net actuarial (gain)/loss arising during the year	0	16	(19)
Amortization of net actuarial gain	(9)	(6)	(10)
Total amount recognized in OCI	(9)	10	(29)
Total amount recognized in Comprehensive income	42	34	6
Expected amortization, next fiscal year	4
OPEB | Canada
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	7	4	3
Interest cost	10	6	7
Expected return on plan assets	0	0	0
Amortization of actuarial loss	1	0	1
Net defined benefit costs	18	10	11
Amount recognized in OCI:
Net actuarial (gain)/loss arising during the year	(8)	2	2
Amortization of net actuarial gain	(1)	(1)	(1)
Prior service cost	(3)	0	0
Total amount recognized in OCI	(12)	1	1
Total amount recognized in Comprehensive income	6	11	12
Expected amortization, next fiscal year	0
OPEB | United States
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	5	4	5
Interest cost	10	5	4
Expected return on plan assets	(10)	(6)	(6)
Amortization of actuarial loss	0	0	0
Net defined benefit costs	5	3	3
Amount recognized in OCI:
Net actuarial (gain)/loss arising during the year	(42)	12	16
Amortization of net actuarial gain	1	(1)	0
Prior service cost	1	(12)	(7)
Total amount recognized in OCI	(40)	(1)	9
Total amount recognized in Comprehensive income	(35)	CAD 2	CAD 12
Expected amortization, next fiscal year	CAD 2

PENSION AND OTHER POSTRETIRE142

PENSION AND OTHER POSTRETIREMENT BENEFITS - ACTUARIAL ASSUMPTIONS (Details)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Pension | Canada
Projected benefit obligations
Discount rate	3.60%	4.00%	4.20%
Rate of salary increase	3.20%	3.70%	3.60%
Net benefit cost
Discount rate	4.00%	4.20%	4.00%
Rate of return on plan assets	6.50%	6.50%	4.40%
Rate of salary increase	3.70%	3.60%	2.50%
Pension | United States
Projected benefit obligations
Discount rate	3.50%	4.00%	4.10%
Rate of salary increase	3.10%	3.30%	3.30%
Net benefit cost
Discount rate	4.00%	4.10%	3.70%
Rate of return on plan assets	7.20%	7.20%	7.10%
Rate of salary increase	3.30%	3.20%	4.00%
OPEB | Canada
Projected benefit obligations
Discount rate	3.60%	4.00%	4.20%
Net benefit cost
Discount rate	4.00%	4.20%	4.00%
Rate of return on plan assets
OPEB | United States
Projected benefit obligations
Discount rate	3.50%	3.60%	4.20%
Net benefit cost
Discount rate	4.00%	3.80%	3.90%
Rate of return on plan assets	6.00%	6.00%	6.00%

PENSION AND OTHER POSTRETIRE143

PENSION AND OTHER POSTRETIREMENT BENEFITS - OTHER POSTRETIREMENT BENEFITS (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Canada
Change in plan assets
Employer contributions	CAD 14	CAD 0	CAD 0
Presented as follows:
Deferred amounts and other assets	9	8
United States
Change in plan assets
Employer contributions	31	13	15
Presented as follows:
Deferred amounts and other assets	40	44
OPEB | Canada
Change in accumulate postretirement benefit obligation
Benefit obligation at beginning of year	179	173
Service cost	7	4	3
Interest cost	10	6	7
Participant contributions	0	0
Actuarial (gain)/loss	8	(2)
Benefits paid	10	6
Foreign currency exchange rate changes	0	0
Acquired in Merger Transaction	146	0
Other	(3)	0
Benefit obligation at beginning of year	321	179	173
Change in plan assets
Fair value of plan assets at beginning of year	0	0
Actual return on plan assets	0	0
Employer contributions	10	6
Participant contributions	0	0
Benefits paid	10	6
Foreign currency exchange rate changes	0	0
Acquired in Merger Transaction	0	0
Fair value of plan assets at end of year	0	0	0
Underfunded status at end of year	(321)	(179)
Presented as follows:
Deferred amounts and other assets	0	0
Accounts payable and other	(12)	(7)
Other long-term liabilities	309	172
Amount recognized in balance sheet	(321)	(179)
OPEB | United States
Change in accumulate postretirement benefit obligation
Benefit obligation at beginning of year	133	135
Service cost	5	4	5
Interest cost	10	5	4
Participant contributions	4	1
Actuarial (gain)/loss	34	(10)
Benefits paid	19	6
Foreign currency exchange rate changes	(17)	(4)
Acquired in Merger Transaction	254	0
Other	1	(12)
Benefit obligation at beginning of year	337	133	135
Change in plan assets
Fair value of plan assets at beginning of year	115	115
Actual return on plan assets	21	5
Employer contributions	1	3
Participant contributions	4	1
Benefits paid	19	6
Foreign currency exchange rate changes	(11)	(3)
Acquired in Merger Transaction	102	0
Fair value of plan assets at end of year	213	115	CAD 115
Underfunded status at end of year	(124)	(18)
Presented as follows:
Deferred amounts and other assets	7	4
Accounts payable and other	(7)	0
Other long-term liabilities	124	22
Amount recognized in balance sheet	CAD (124)	CAD (18)

PENSION AND OTHER POSTRETIRE144

PENSION AND OTHER POSTRETIREMENT BENEFITS - ASSUMED HEALTH CARE COST TREND RATES (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Canada
MEDICAL COST TRENDS
Health care cost trend rate assumed for next year	5.50%	5.40%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	4.40%	4.50%
Year that the rate reaches the ultimate trend rate	2,034	2,034
Effect of 1% change in assumed medical care trend rate
Increase in service and interest cost due to 1% increase in the assumed medical care trend rate	CAD 2
Decrease in service and interest cost due to 1% decrease in the assumed medical care trend rate	(1)
Increase in benefit obligation due to 1% increase in the assumed medical care trend rate	28
Decrease in benefit obligation due to 1% decrease in the assumed medical care trend rate	CAD (23)
United States
MEDICAL COST TRENDS
Health care cost trend rate assumed for next year	7.40%	6.90%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	4.50%	4.50%
Year that the rate reaches the ultimate trend rate	2,037	2,037
Effect of 1% change in assumed medical care trend rate
Increase in service and interest cost due to 1% increase in the assumed medical care trend rate	CAD 1
Decrease in service and interest cost due to 1% decrease in the assumed medical care trend rate	(1)
Increase in benefit obligation due to 1% increase in the assumed medical care trend rate	20
Decrease in benefit obligation due to 1% decrease in the assumed medical care trend rate	CAD (17)

PENSION AND OTHER POSTRETIRE145

PENSION AND OTHER POSTRETIREMENT BENEFITS - PLAN ASSETS (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Pension | Equity securities | United States | Level 2
Change in plan assets
Fair value of plan assets at end of year	CAD 0
Pension | Equity securities | United States | Level 3
Change in plan assets
Fair value of plan assets at end of year	0
Canada | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	281	CAD 248
Unrealized and realized gains	26	20
Purchases and settlements, net	33	13
Fair value of plan assets at end of year	CAD 340	CAD 281
Canada | Equity securities
Pension and Other Postretirement Benefit Disclosures
Plan asset allocations	52.00%	47.00%
Canada | Fixed income securities
Pension and Other Postretirement Benefit Disclosures
Plan asset allocations	34.20%	39.00%
Canada | Other
Pension and Other Postretirement Benefit Disclosures
Plan asset allocations	13.80%	14.00%
Canada | Pension
Change in plan assets
Fair value of plan assets at beginning of year	CAD 2,019	CAD 1,886
Fair value of plan assets at end of year	3,619	2,019
Canada | Pension | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	1,593
Fair value of plan assets at end of year	2,861	1,593
Canada | Pension | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	145
Fair value of plan assets at end of year	418	145
Canada | Pension | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	281
Fair value of plan assets at end of year	340	281
Canada | Pension | Level 3 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year		0
Canada | Pension | Equity securities | United States
Change in plan assets
Fair value of plan assets at beginning of year	219
Fair value of plan assets at end of year	427	219
Canada | Pension | Equity securities | United States | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	219
Fair value of plan assets at end of year	427	219
Canada | Pension | Equity securities | United States | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year		0
Canada | Pension | Equity securities | United States | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year		0
Canada | Pension | Equity securities | Canada
Change in plan assets
Fair value of plan assets at beginning of year	425
Fair value of plan assets at end of year	1,267	425
Canada | Pension | Equity securities | Canada | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	425
Fair value of plan assets at end of year	842	425
Canada | Pension | Equity securities | Canada | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	425	0
Canada | Pension | Equity securities | Canada | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | Pension | Equity securities | Global
Change in plan assets
Fair value of plan assets at beginning of year	305
Fair value of plan assets at end of year	189	305
Canada | Pension | Equity securities | Global | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	165
Fair value of plan assets at end of year	189	165
Canada | Pension | Equity securities | Global | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	140
Fair value of plan assets at end of year	0	140
Canada | Pension | Equity securities | Global | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | Pension | Cash and cash equivalents | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	156
Fair value of plan assets at end of year	169	156
Canada | Pension | Cash and cash equivalents | Level 1 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	156
Fair value of plan assets at end of year	169	156
Canada | Pension | Government | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	351
Fair value of plan assets at end of year	933	351
Canada | Pension | Government | Level 1 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	351
Fair value of plan assets at end of year	933	351
Canada | Pension | Government | Level 2 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | Pension | Government | Level 3 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | Pension | Corporate | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	280
Fair value of plan assets at end of year	304	280
Canada | Pension | Corporate | Level 1 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	277
Fair value of plan assets at end of year	301	277
Canada | Pension | Corporate | Level 2 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	3
Fair value of plan assets at end of year	3	3
Canada | Pension | Corporate | Level 3 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | Pension | Infrastructure and real estate | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	281
Fair value of plan assets at end of year	340	281
Canada | Pension | Infrastructure and real estate | Level 1 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | Pension | Infrastructure and real estate | Level 2 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | Pension | Infrastructure and real estate | Level 3 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	281
Fair value of plan assets at end of year	340	281
Canada | Pension | Forward currency contracts | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	2
Fair value of plan assets at end of year	(10)	2
Canada | Pension | Forward currency contracts | Level 1 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | Pension | Forward currency contracts | Level 2 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	2
Fair value of plan assets at end of year	(10)	2
Canada | Pension | Forward currency contracts | Level 3 | Fair Value
Change in plan assets
Fair value of plan assets at end of year	0
Canada | OPEB
Change in plan assets
Fair value of plan assets at beginning of year	0	0
Fair value of plan assets at end of year	0	0
Canada | OPEB | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | OPEB | Level 1 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | OPEB | Level 2 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | OPEB | Level 3 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | OPEB | Equity securities | United States
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | OPEB | Equity securities | United States | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | OPEB | Equity securities | United States | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | OPEB | Equity securities | United States | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | OPEB | Equity securities | Global
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | OPEB | Equity securities | Global | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | OPEB | Equity securities | Global | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | OPEB | Equity securities | Global | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | OPEB | Cash and cash equivalents | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | OPEB | Cash and cash equivalents | Level 1 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | OPEB | Government | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
Canada | OPEB | Government | Level 1 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	40	49
Unrealized and realized gains	5	2
Purchases and settlements, net	11	(11)
Fair value of plan assets at end of year	CAD 56	CAD 40
United States | Equity securities
Pension and Other Postretirement Benefit Disclosures
Plan asset allocations	47.10%	55.40%
United States | Fixed income securities
Pension and Other Postretirement Benefit Disclosures
Plan asset allocations	47.70%	33.00%
United States | Other
Pension and Other Postretirement Benefit Disclosures
Plan asset allocations	5.20%	11.60%
United States | Pension
Change in plan assets
Fair value of plan assets at beginning of year	CAD 361	CAD 343
Fair value of plan assets at end of year	1,097	361
United States | Pension | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	289
Fair value of plan assets at end of year	989	289
United States | Pension | Level 1 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year		0
United States | Pension | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	32
Fair value of plan assets at end of year	52	32
United States | Pension | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	40
Fair value of plan assets at end of year	56	40
United States | Pension | Level 3 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year		0
United States | Pension | Equity securities
Change in plan assets
Fair value of plan assets at end of year	343
United States | Pension | Equity securities | United States
Change in plan assets
Fair value of plan assets at beginning of year	54
Fair value of plan assets at end of year		54
United States | Pension | Equity securities | United States | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	54
Fair value of plan assets at end of year	343	54
United States | Pension | Equity securities | United States | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year		0
United States | Pension | Equity securities | United States | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year		0
United States | Pension | Equity securities | Canada
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Equity securities | Canada | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Equity securities | Canada | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Equity securities | Canada | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Equity securities | Global
Change in plan assets
Fair value of plan assets at beginning of year	146
Fair value of plan assets at end of year	174	146
United States | Pension | Equity securities | Global | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	116
Fair value of plan assets at end of year	122	116
United States | Pension | Equity securities | Global | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	30
Fair value of plan assets at end of year	52	30
United States | Pension | Equity securities | Global | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Cash and cash equivalents | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	3
Fair value of plan assets at end of year	2	3
United States | Pension | Cash and cash equivalents | Level 1 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	3
Fair value of plan assets at end of year	2	3
United States | Pension | Government | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Government | Level 1 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Government | Level 2 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Government | Level 3 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Corporate | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	116
Fair value of plan assets at end of year	523	116
United States | Pension | Corporate | Level 1 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	116
Fair value of plan assets at end of year	522	116
United States | Pension | Corporate | Level 2 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	1	0
United States | Pension | Corporate | Level 3 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Infrastructure and real estate | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	40
Fair value of plan assets at end of year	56	40
United States | Pension | Infrastructure and real estate | Level 1 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Infrastructure and real estate | Level 2 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | Pension | Infrastructure and real estate | Level 3 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	40
Fair value of plan assets at end of year	56	40
United States | Pension | Forward currency contracts | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	2
Fair value of plan assets at end of year	(1)	2
United States | Pension | Forward currency contracts | Level 1 | Fair Value
Change in plan assets
Fair value of plan assets at end of year	0
United States | Pension | Forward currency contracts | Level 2 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	2
Fair value of plan assets at end of year	(1)	2
United States | Pension | Forward currency contracts | Level 3 | Fair Value
Change in plan assets
Fair value of plan assets at end of year	0
United States | OPEB
Change in plan assets
Fair value of plan assets at beginning of year	115	115
Fair value of plan assets at end of year	213	115
United States | OPEB | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	115
Fair value of plan assets at end of year	213	115
United States | OPEB | Level 1 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	115
Fair value of plan assets at end of year	213	115
United States | OPEB | Level 2 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | OPEB | Level 3 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | OPEB | Equity securities | United States
Change in plan assets
Fair value of plan assets at beginning of year	35
Fair value of plan assets at end of year	80	35
United States | OPEB | Equity securities | United States | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	35
Fair value of plan assets at end of year	80	35
United States | OPEB | Equity securities | United States | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | OPEB | Equity securities | United States | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | OPEB | Equity securities | Global
Change in plan assets
Fair value of plan assets at beginning of year	34
Fair value of plan assets at end of year	36	34
United States | OPEB | Equity securities | Global | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	34
Fair value of plan assets at end of year	36	34
United States | OPEB | Equity securities | Global | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | OPEB | Equity securities | Global | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	0
Fair value of plan assets at end of year	0	0
United States | OPEB | Cash and cash equivalents | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	1
Fair value of plan assets at end of year	1	1
United States | OPEB | Cash and cash equivalents | Level 1 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	1
Fair value of plan assets at end of year	1	1
United States | OPEB | Government | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	45
Fair value of plan assets at end of year	96	45
United States | OPEB | Government | Level 1 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	45
Fair value of plan assets at end of year	CAD 96	CAD 45
Minimum | Canada | Equity securities
Pension and Other Postretirement Benefit Disclosures
Allocation of plan assets (as a percent)	40.00%
Minimum | Canada | Fixed income securities
Pension and Other Postretirement Benefit Disclosures
Allocation of plan assets (as a percent)	27.50%
Minimum | Canada | Other
Pension and Other Postretirement Benefit Disclosures
Allocation of plan assets (as a percent)	0.00%
Minimum | United States | Equity securities
Pension and Other Postretirement Benefit Disclosures
Allocation of plan assets (as a percent)	52.50%
Minimum | United States | Fixed income securities
Pension and Other Postretirement Benefit Disclosures
Allocation of plan assets (as a percent)	27.50%
Minimum | United States | Other
Pension and Other Postretirement Benefit Disclosures
Allocation of plan assets (as a percent)	0.00%
Maximum | Canada | Equity securities
Pension and Other Postretirement Benefit Disclosures
Allocation of plan assets (as a percent)	70.00%
Maximum | Canada | Fixed income securities
Pension and Other Postretirement Benefit Disclosures
Allocation of plan assets (as a percent)	60.00%
Maximum | Canada | Other
Pension and Other Postretirement Benefit Disclosures
Allocation of plan assets (as a percent)	20.00%
Maximum | United States | Equity securities
Pension and Other Postretirement Benefit Disclosures
Allocation of plan assets (as a percent)	70.00%
Maximum | United States | Fixed income securities
Pension and Other Postretirement Benefit Disclosures
Allocation of plan assets (as a percent)	30.00%
Maximum | United States | Other
Pension and Other Postretirement Benefit Disclosures
Allocation of plan assets (as a percent)	20.00%

PENSION AND OTHER POSTRETIRE146

PENSION AND OTHER POSTRETIREMENT BENEFITS - EXPECTED BENEFIT PAYMENTS AND EMPLOYER CONTRIBUTIONS (Details) CAD in Millions	Dec. 31, 2017CAD
Canada | Pension
Benefits Expected to be Paid by the Company
Expected future benefit payments for 2018	CAD 158
Expected future benefit payments for 2019	165
Expected future benefit payments for 2020	172
Expected future benefit payments for 2021	180
Expected future benefit payments for 2022	187
Expected future benefit payments for 2023-2027	1,036
Contributions expected to be paid in next fiscal year	36
Canada | OPEB
Benefits Expected to be Paid by the Company
Expected future benefit payments for 2018	12
Expected future benefit payments for 2019	12
Expected future benefit payments for 2020	13
Expected future benefit payments for 2021	13
Expected future benefit payments for 2022	14
Expected future benefit payments for 2023-2027	43
Contributions expected to be paid in next fiscal year	7
United States | Pension
Benefits Expected to be Paid by the Company
Expected future benefit payments for 2018	82
Expected future benefit payments for 2019	81
Expected future benefit payments for 2020	85
Expected future benefit payments for 2021	83
Expected future benefit payments for 2022	92
Expected future benefit payments for 2023-2027	453
Contributions expected to be paid in next fiscal year	126
United States | OPEB
Benefits Expected to be Paid by the Company
Expected future benefit payments for 2018	25
Expected future benefit payments for 2019	25
Expected future benefit payments for 2020	25
Expected future benefit payments for 2021	25
Expected future benefit payments for 2022	24
Expected future benefit payments for 2023-2027	110
Contributions expected to be paid in next fiscal year	CAD 12

PENSION AND OTHER POSTRETIRE147

PENSION AND OTHER POSTRETIREMENT BENEFITS - RETIREMENT SAVINGS PLAN (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Canada
Pension and Other Postretirement Benefit Disclosures
Percent of match	5.00%
Total contributions by the Company	CAD 14	CAD 0	CAD 0
Canada | Pension
Pension and Other Postretirement Benefit Disclosures
Total contributions by the Company	161	74
Canada | OPEB
Pension and Other Postretirement Benefit Disclosures
Total contributions by the Company	CAD 10	6
United States
Pension and Other Postretirement Benefit Disclosures
Percent of match	6.00%
Total contributions by the Company	CAD 31	13	CAD 15
United States | Pension
Pension and Other Postretirement Benefit Disclosures
Total contributions by the Company	57	28
United States | OPEB
Pension and Other Postretirement Benefit Disclosures
Total contributions by the Company	CAD 1	CAD 3

CHANGES IN OPERATING ASSETS 148

CHANGES IN OPERATING ASSETS AND LIABILITIES (Details) - CAD CAD in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
CHANGES IN OPERATING ASSETS AND LIABILITIES
Restricted Cash	CAD 15	CAD 0	CAD 0
Accounts receivable and other	(783)	(437)	698
Accounts receivable from affiliates	24	(7)	82
Inventory	(289)	(371)	(315)
Deferred amounts and other assets	(138)	(183)	364
Accounts payable and other	286	396	(1,472)
Accounts payable to affiliates	(62)	71	(26)
Interest payable	124	20	31
Other long-term liabilities	509	153	(7)
Changes in operating assets and liabilities	CAD (314)	CAD (358)	CAD (645)

RELATED PARTY TRANSACTIONS (Det

RELATED PARTY TRANSACTIONS (Details) CAD in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2017CAD	Dec. 31, 2017USD ($)	Dec. 31, 2016CAD	Dec. 31, 2015CAD
RELATED PARTY TRANSACTIONS
Amounts charged to the Company for transportation services	CAD 417		CAD 357	CAD 332
Lease arrangement expenses	304		287	151
Purchase of natural gas by wholly owned subsidiaries	142		98	228
Sale of natural gas by wholly owned subsidiaries	CAD 60		49	5
Minimum
RELATED PARTY TRANSACTIONS
Annual interest rate on the loans (as a percent)	4.00%	4.00%
Maximum
RELATED PARTY TRANSACTIONS
Annual interest rate on the loans (as a percent)	12.00%	12.00%
Cost Recoveries
RELATED PARTY TRANSACTIONS
Revenue from related parties	CAD 88	$ 68
Vector Pipeline joint venture
RELATED PARTY TRANSACTIONS
Revenue from related parties	14		7	CAD 7
Amounts receivable from affiliates	109		130
DCP Midstream, LLC
RELATED PARTY TRANSACTIONS
Natural gas midstream revenue	47	36
Natural gas storage revenue	4	3
Spectra Energy Corp | Reimbursed Maintenance Expenses
RELATED PARTY TRANSACTIONS
Revenue from related parties	10	$ 8
Other affiliates
RELATED PARTY TRANSACTIONS
Amounts receivable from affiliates	CAD 167		CAD 140

COMMITMENTS AND CONTINGENCIES -

COMMITMENTS AND CONTINGENCIES - COMMITMENTS (Details) CAD in Millions	12 Months Ended
	Dec. 31, 2017CAD	Dec. 31, 2016CAD	Dec. 31, 2015CAD	Jan. 09, 2018USD ($)
Annual debt maturities
Total	CAD 62,927
Less than 1 year	2,831
2 years	6,273
3 years	6,722
4 years	2,505
5 years	8,839
Thereafter	35,757
Interest obligations
Total	42,083
Less than 1 year	2,485
2 years	2,298
3 years	2,117
4 years	1,941
5 years	1,853
Thereafter	31,389
Purchase of services, pipe and other materials, including transportation
Total	14,396
Less than 1 year	4,144
2 years	2,455
3 years	1,496
4 years	1,255
5 years	1,163
Thereafter	3,883
Operating leases
Total	746
Less than 1 year	91
2 years	86
3 years	80
4 years	74
5 years	78
Thereafter	337
Capital leases
Total	35
Less than 1 year	9
2 years	8
3 years	2
4 years	2
5 years	2
Thereafter	12
Maintenance agreements
Total	322
Less than 1 year	38
2 years	32
3 years	17
4 years	15
5 years	15
Thereafter	205
Land lease commitments
Total	405
Less than 1 year	15
2 years	16
3 years	16
4 years	16
5 years	16
Thereafter	326
Total
Total	120,914
Total Less than 1 year	9,613
Total 2 years	11,168
Total 3 years	10,450
Total 4 years	5,808
Total 5 years	11,966
Total thereafter	71,909
Operating leases, rent expense	CAD 118	CAD 85	CAD 72
Senior notes | 3.5% and 4.15% Senior Notes, Maturing Twenty 2028 and 2048 | Texas Eastern Transmission, LP | Subsequent Event
Total
Principal Amount | $				$ 800,000,000

COMMITMENTS AND CONTINGENCIE151

COMMITMENTS AND CONTINGENCIES - ENVIRONMENTAL (Details) CAD in Millions, $ in Millions	Jun. 15, 2017CAD	Dec. 31, 2017CAD	Dec. 31, 2016CAD	Dec. 31, 2015CAD	Dec. 31, 2016USD ($)	Dec. 31, 2017USD ($)	Mar. 31, 2015USD ($)
CONTINGENCIES
Operating leases, rent expense | CAD		CAD 118	CAD 85	CAD 72
Line 6B Crude Oil Release
CONTINGENCIES
Estimated cost, net of tax						$ 195
Amount of insurance claim recognized, net of tax					$ 80
Aggregate limited amount for pollution liability under insurance program						650
Insurance coverage remaining						103
Amount receivable subject to lawsuit						85
Unfavorable binding arbitration							$ 85
Civil penalties paid | CAD	CAD 61
Line 6B Crude Oil Release | Enbridge Energy Partners, L.P.
CONTINGENCIES
Estimated cost						1,200
Amount of insurance claim recognized					$ 547
Estimated fine or penalty amount						69
Lakehead System Line 6A and 6B Crude Oil Release
CONTINGENCIES
Payments | CAD	68
Removal costs and interest paid | CAD	6
Lakehead System Line 6A and 6B Crude Oil Release | Enbridge Energy Partners, L.P.
CONTINGENCIES
Estimated liability						$ 62
Line 6A Crude Oil Release
CONTINGENCIES
Civil penalties paid | CAD	CAD 1

GUARANTEES (Details)

GUARANTEES (Details) CAD in Millions	Dec. 31, 2017CAD	Dec. 31, 2017USD ($)
Guarantor Obligations [Line Items]
Long-term debt | CAD	CAD 62,927
Westcoast Energy Inc.
Guarantor Obligations [Line Items]
Ownership interest (as a percent)	100.00%	100.00%
Fluor Enterprises Inc | Duke/Fluor Daniel
Guarantor Obligations [Line Items]
Ownership interest (as a percent)	50.00%	50.00%
Spectra Energy Partners, LP | DCP Midstream, LLC
Guarantor Obligations [Line Items]
Ownership interest (as a percent)	50.00%	50.00%
Medium-term notes | DCP Midstream, LLC
Guarantor Obligations [Line Items]
Principal Amount		$ 424,000,000
Long-term debt		350,000,000
Performance Guarantee [Member]
Guarantor Obligations [Line Items]
Guarantor obligations, maximum exposure		406,000,000
Performance Guarantee, Expiring 2028
Guarantor Obligations [Line Items]
Guarantor obligations, maximum exposure		201,000,000
Term Loan Agreement | Spectra Energy Partners, LP
Guarantor Obligations [Line Items]
Guarantor obligations, maximum exposure		175,000,000
Performance Guarantee, Expiring 2032 | Spectra Energy Partners, LP
Guarantor Obligations [Line Items]
Guarantor obligations, maximum exposure		$ 90,000,000

SUBSEQUENT EVENTS (Details)

SUBSEQUENT EVENTS (Details) - Subsequent Event shares in Millions	Jan. 22, 2018shares	Jan. 09, 2018USD ($)tranche
Variable Interest Entity, Primary Beneficiary
SUBSEQUENT EVENTS
Direct common interest (as a percent)	83.00%
Shares owned (in shares) | shares	403
Texas Eastern Transmission, LP | 3.5% Senior Notes, Maturing 2028
SUBSEQUENT EVENTS
Interest rate		3.50%
Texas Eastern Transmission, LP | 4.15% Senior Notes, Maturing 2048
SUBSEQUENT EVENTS
Interest rate		4.15%
Texas Eastern Transmission, LP | Senior notes | 3.5% and 4.15% Senior Notes, Maturing Twenty 2028 and 2048
SUBSEQUENT EVENTS
Principal Amount		$ 800,000,000
Number of tranches | tranche		2
Texas Eastern Transmission, LP | Senior notes | 3.5% Senior Notes, Maturing 2028
SUBSEQUENT EVENTS
Principal Amount		$ 400,000,000
Texas Eastern Transmission, LP | Senior notes | 4.15% Senior Notes, Maturing 2048
SUBSEQUENT EVENTS
Principal Amount		$ 400,000,000
Spectra Energy Partners, LP
SUBSEQUENT EVENTS
Stock issued during period, shares, conversion of units (in shares) | shares	172.5

QUARTERLY FINANCIAL DATA (Detai

QUARTERLY FINANCIAL DATA (Details) - CAD CAD / shares in Units, CAD 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 Information Disclosure [Abstract]
Revenues	CAD 12,889	CAD 9,227	CAD 11,116	CAD 11,146	CAD 9,338	CAD 8,488	CAD 7,939	CAD 8,795	CAD 44,378	CAD 34,560	CAD 33,794
Operating income/(loss)	(2,961)	1,490	1,684	1,358	329	(216)	794	1,674	1,571	2,581	1,862
Earnings	65	1,015	1,241	945	847	(237)	352	1,347	3,266	2,309	(159)
Earnings attributable to controlling interests	291	847	1,000	721	441	(30)	372	1,286	2,859	2,069	251
Earnings/(loss) attributable to common shareholders	CAD 207	CAD 765	CAD 919	CAD 638	CAD 365	CAD (103)	CAD 301	CAD 1,213	CAD 2,529	CAD 1,776	CAD (37)
Earnings per common share
Basic (in dollars per share)	CAD 0.13	CAD 0.47	CAD 0.56	CAD 0.54	CAD 0.39	CAD (0.11)	CAD 0.33	CAD 1.38	CAD 1.66	CAD 1.95	CAD (0.04)
Diluted (in dollars per share)	CAD 0.12	CAD 0.47	CAD 0.56	CAD 0.54	CAD 0.39	CAD (0.11)	CAD 0.33	CAD 1.38	CAD 1.65	CAD 1.93	CAD (0.04)