Enbridge (ENB) 10-K 15 Feb 19 2018 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2018	Feb. 08, 2019	Jun. 30, 2018
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, 2018
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 Emerging Growth Company	false
Entity Small Business	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		2,022,657,570
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	FY
Entity Public Float			$ 61.1

CONSOLIDATED STATEMENTS OF EARN

CONSOLIDATED STATEMENTS OF EARNINGS - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Operating revenues
Total operating revenues (Note 4)	$ 46,378	$ 44,378	$ 34,560
Operating expenses
Operating and administrative	6,792	6,442	4,358
Depreciation and amortization	3,246	3,163	2,240
Impairment of long-lived assets (Note 8 and Note 11)	1,104	4,463	1,376
Impairment of goodwill (Note 8 and Note 16)	1,019	102	0
Total operating expenses	41,562	42,807	31,979
Operating income	4,816	1,571	2,581
Income from equity investments (Note 13)	1,509	1,102	428
Other income/(expense)
Net foreign currency gain/(loss)	(522)	237	91
Gain/(loss) on dispositions	(46)	16	848
Other	516	199	93
Interest expense (Note 18)	(2,703)	(2,556)	(1,590)
Earnings before income taxes	3,570	569	2,451
Income tax recovery/(expense) (Note 25)	(237)	2,697	(142)
Earnings	3,333	3,266	2,309
Earnings attributable to noncontrolling interests and redeemable noncontrolling interests	(451)	(407)	(240)
Earnings attributable to controlling interests	2,882	2,859	2,069
Preference share dividends	(367)	(330)	(293)
Earnings attributable to common shareholders	$ 2,515	$ 2,529	$ 1,776
Earnings/(loss) per common share attributable to Enbridge Inc. common shareholders (in dollars per share)	$ 1.46	$ 1.66	$ 1.95
Diluted earnings/(loss) per common share attributable to Enbridge Inc. common shareholders (in dollars per share)	$ 1.46	$ 1.65	$ 1.93
Commodity sales
Operating revenues
Total operating revenues (Note 4)	$ 27,660	$ 26,286	$ 22,816
Operating expenses
Cost of goods and services sold	26,818	26,065	22,409
Gas distribution sales
Operating revenues
Total operating revenues (Note 4)	4,360	4,215	2,486
Operating expenses
Cost of goods and services sold	2,583	2,572	1,596
Transportation and other services revenues
Operating revenues
Total operating revenues (Note 4)	$ 14,358	$ 13,877	$ 9,258

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Statement of Comprehensive Income [Abstract]
Earnings	$ 3,333	$ 3,266	$ 2,309
Other comprehensive income/(loss), net of tax
Change in unrealized loss on cash flow hedges	(153)	(21)	(138)
Change in unrealized gain/(loss) on net investment hedges	(458)	490	166
Other comprehensive income/(loss) from equity investees	38	(27)	0
Reclassification to earnings of loss on cash flow hedges	152	313	116
Reclassification to earnings of pension and other postretirement benefits amounts	12	19	17
Actuarial gain/(loss) on pension plans and other postretirement benefits	(52)	8	(34)
Foreign currency translation adjustments	4,599	(3,060)	(712)
Other comprehensive income/(loss), net of tax	4,138	(2,278)	(585)
Comprehensive income	7,471	988	1,724
Comprehensive income attributable to noncontrolling interests and redeemable noncontrolling interests	(801)	(160)	(229)
Comprehensive income attributable to controlling interests	6,670	828	1,495
Preference share dividends	(367)	(330)	(293)
Comprehensive income attributable to common shareholders	$ 6,303	$ 498	$ 1,202

CONSOLIDATED STATEMENTS OF CHAN

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY - 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	Merger TransactionCommon shares
Balance at Dec. 31, 2015		$ 6,515	$ 7,391	$ 3,301	$ 142	$ 1,632	$ (83)		$ 1,300
Increase (Decrease) in Stockholders' Equity
Shares issued		740	2,241
Common shares issued in Merger Transaction (Note 8)										$ 0
Dividend Reinvestment and Share Purchase Plan			795
Stock-based compensation				41
Exercised of stock options			65	(24)
Dilution gain/(loss) and other				81
Earnings attributable to controlling interests	$ 2,069				2,069
Preference share dividends					(293)
Common share dividends declared					(1,945)
Dividends paid to reciprocal shareholder					26
Redemption value adjustment attributable to redeemable noncontrolling interests (Note 20)	686				(686)
Adjustment relating to equity method investment					(29)
Other comprehensive income/(loss) attributable to common shareholders, net of tax						(574)
Change in reciprocal interest							(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)
Distributions									(720)
Contributions									28
Purchase of noncontrolling interests on Sponsored Vehicles buy-in (Note 20)	0
Other									(3)
Balance at Dec. 31, 2016	$ 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	$ 2.12
Modified retrospective adoption of ASC 606 Revenue from Contracts with Customers (Note 3)	$ 0				0
Shares issued		492	1,500
Common shares issued in Merger Transaction (Note 8)										37,429
Dividend Reinvestment and Share Purchase Plan			1,226
Stock-based compensation				82
Exercised of stock options			90	(95)
Dilution gain/(loss) and other				(192)
Earnings attributable to controlling interests	2,859				2,859
Preference share dividends					(330)
Common share dividends declared					(4,702)
Dividends paid to reciprocal shareholder					30
Redemption value adjustment attributable to redeemable noncontrolling interests (Note 20)	(292)				292
Other					99
Other comprehensive income/(loss) attributable to common shareholders, net of tax						(2,031)
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 8)									8,955
Enbridge Energy Company, Inc. common control transaction									(343)
Distributions									(839)
Contributions									832
Deconsolidation of Sabal Trail Transmission, LLC									(2,318)
Purchase of noncontrolling interests on Sponsored Vehicles buy-in (Note 20)	0
Dilution gain									832
Other									(54)
Balance at Dec. 31, 2017	$ 65,732	7,747	50,737	3,194	(2,468)	(973)	(102)	58,135	7,597
Increase (Decrease) in Stockholders' Equity
Dividends paid per common share	$ 2.41
Modified retrospective adoption of ASC 606 Revenue from Contracts with Customers (Note 3)	$ 0				0
Shares issued			0
Common shares issued in Merger Transaction (Note 8)			12,727							$ 0
Dividend Reinvestment and Share Purchase Plan			1,181
Stock-based compensation				49
Sponsored Vehicles buy-in (Note 20)				(4,323)					(210)
Exercised of stock options			32	(24)
Dilution gain on Spectra Energy Partners, LP restructuring (Note 20)				1,136
Dilution gain/(loss) and other				(111)
Sale of noncontrolling interest in subsidiaries				$ 79					1,183
Earnings attributable to controlling interests	2,882				2,882
Preference share dividends					(367)
Common share dividends declared					(5,019)
Dividends paid to reciprocal shareholder					33
Redemption value adjustment attributable to redeemable noncontrolling interests (Note 20)	456				(456)				(210)
Other					(57)
Impact of Sponsored Vehicles buy-in						(142)
Other comprehensive income/(loss) attributable to common shareholders, net of tax						3,787
Change in reciprocal interest							14
Earnings/(loss) attributable to noncontrolling interests									334
Change in unrealized gain on cash flow hedges									31
Foreign currency translation adjustments									294
Reclassification to earnings of (gain)/loss on cash flow hedges									4
Other comprehensive income/(loss) attributable to noncontrolling interests, net of tax									329
Comprehensive income/(loss) attributable to noncontrolling interests									663
Distributions									(857)
Contributions									24
Spectra Energy Partners, LP restructuring (Note 20)									(1,486)
Purchase of noncontrolling interests on Sponsored Vehicles buy-in (Note 20)	(4,469)								(2,657)
Other									(82)
Balance at Dec. 31, 2018	$ 73,435	$ 7,747	$ 64,677		(5,538)	$ 2,672	$ (88)	$ 69,470	$ 3,965
Increase (Decrease) in Stockholders' Equity
Dividends paid per common share	$ 2.68
Modified retrospective adoption of ASC 606 Revenue from Contracts with Customers (Note 3)	$ (38)				$ (86)

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS $ in Millions, $ in Billions	12 Months Ended
	Dec. 31, 2018CAD ($)	Dec. 31, 2017CAD ($)	Dec. 31, 2016CAD ($)
Operating activities
Earnings	$ 3,333	$ 3,266	$ 2,309
Depreciation and amortization	3,246	3,163	2,240
Deferred income tax (recovery)/expense	(148)	(2,877)	43
Changes in unrealized (gain)/loss on derivative instruments, net (Note 24)	903	(1,242)	(509)
Earnings from equity investments	(1,509)	(1,102)	(656)
Distributions from equity investments	1,539	1,264	827
Impairment of long-lived assets	1,104	4,463	1,620
Goodwill impairment	1,019	102	0
(Gain)/loss on dispositions	8	(120)	(848)
Other	92	79	547
Changes in operating assets and liabilities (Note 27)	915	(338)	(368)
Net cash provided by operating activities	10,502	6,658	5,205
Investing activities
Capital expenditures	(6,806)	(8,287)	(5,128)
Long-term investments	(1,312)	(3,586)	(514)
Distributions from equity investments in excess of cumulative earnings	1,277	125	0
Additions to intangible assets	(540)	(789)	(127)
Acquisitions	0	0	(644)
Cash acquired in Merger Transaction (Note 8)	0	682	0
Proceeds from dispositions	4,452	628	1,379
Reimbursement of capital expenditures	0	212	0
Other	(88)	(22)	(118)
Net cash used in investing activities	(3,017)	(11,037)	(5,152)
Financing activities
Net change in short-term borrowings (Note 18)	(420)	721	(248)
Net change in commercial paper and credit facility draws	(2,256)	(1,249)	(2,297)
Debenture and term note issues, net of issue costs	3,537	9,483	4,080
Debenture and term note repayments	(4,445)	(5,054)	(1,946)
Sale of noncontrolling interest in subsidiary	1,289	0	0
Purchase of interest in consolidated subsidiary	0	(227)	0
Contributions from noncontrolling interests	24	832	28
Distributions to noncontrolling interests	(857)	(919)	(720)
Contributions from redeemable noncontrolling interests	70	1,178	591
Distributions to redeemable noncontrolling interests	(325)	(247)	(202)
Sponsored Vehicle buy-in cash payment	(64)	0	0
Preference shares issued	0	489	737
Redemption of preferred shares	(210)	0	0
Common shares issued	21	1,549	2,260
Preference share dividends	(364)	(330)	(293)
Common share dividends	(3,480)	(2,750)	(1,150)
Other	(23)	0	0
Net cash (used in)/provided by financing activities	(7,503)	3,476	840
Effect of translation of foreign denominated cash and cash equivalents and restricted cash	68	(72)	(19)
Net increase/(decrease) in cash and cash equivalents and restricted cash	50	(975)	874
Cash and cash equivalents and restricted cash at beginning of year	587	1,562	688
Cash and cash equivalents and restricted cash at end of year	637	587	1,562
Supplementary cash flow information
Cash paid for income taxes	277	172	194
Cash paid for interest, net of amount capitalized	2,508	2,668	1,820
Property, plant and equipment non-cash accruals	$ 847	$ 889	$ 773

CONSOLIDATED STATEMENTS OF FINA

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Current assets
Cash and cash equivalents (Note 2)	$ 518	$ 480
Restricted cash	119	107
Accounts receivable and other (Note 9)	6,517	7,053
Accounts receivable from affiliates	79	47
Inventory (Note 10)	1,339	1,528
Total Current assets	8,572	9,215
Property, plant and equipment, net (Note 11)	94,540	90,711
Long-term investments (Note 13)	16,707	16,644
Restricted long-term investments (Note 14)	323	267
Deferred amounts and other assets	8,558	6,442
Intangible assets, net (Note 15)	2,372	3,267
Goodwill (Note 16)	34,459	34,457
Deferred income taxes (Note 25)	1,374	1,090
Total assets	166,905	162,093
Current liabilities
Short-term borrowings (Note 18)	1,024	1,444
Accounts payable and other (Note 17)	9,836	9,478
Accounts payable to affiliates	40	157
Interest payable	669	634
Environmental liabilities	27	40
Current portion of long-term debt (Note 18)	3,259	2,871
Total Current liabilities	14,855	14,624
Long-term debt (Note 18)	60,327	60,865
Other long-term liabilities	8,834	7,510
Deferred income taxes (Note 25)	9,454	9,295
Total Liabilities	93,470	92,294
Commitments and contingencies (Note 29)
Redeemable noncontrolling interests (Note 20)	0	4,067
Share capital (Note 21)
Preference shares	7,747	7,747
Common shares (1,695 and 943 outstanding at December 31, 2017 and December 31,2016, respectively)	64,677	50,737
Additional paid-in capital	0	3,194
Deficit	(5,538)	(2,468)
Accumulated other comprehensive income/(loss) (Note 23)	2,672	(973)
Reciprocal shareholding	(88)	(102)
Total Enbridge Inc. shareholders’ equity	69,470	58,135
Noncontrolling interests (Note 20)	3,965	7,597
Total Equity	73,435	65,732
Total liabilities and equity	$ 166,905	$ 162,093

CONSOLIDATED STATEMENTS OF FI_2

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION (Parenthetical) - shares shares in Millions	Dec. 31, 2018	Dec. 31, 2017
Statement of Financial Position [Abstract]
Common shares, outstanding (in shares)	2,022	1,695

BUSINESS OVERVIEW

BUSINESS OVERVIEW	12 Months Ended
	Dec. 31, 2018
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. 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, Gulf Coast and Mid-Continent, Southern Lights Pipeline, Express-Platte System, Bakken System, and Feeder Pipelines and Other. GAS TRANSMISSION AND MIDSTREAM Gas Transmission and Midstream consists of investments in natural gas pipelines and gathering and processing facilities in Canada and the United States. 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 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 natural gas distribution activities in Quebec and New Brunswick and an investment in Noverco Inc. (Noverco). 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 in operation and 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 the impact of foreign exchange hedge settlements, which are not allocated to business segments. Also included in Eliminations and Other are new business development activities, general corporate investments and a portion of the synergies achieved thus far related to the integration of corporate functions due to the Merger Transaction, as defined in Acquisition of Spectra Energy Corp . SPONSORED VEHICLES BUY-IN In the fourth quarter of 2018, Enbridge completed the buy-ins of our sponsored vehicles: Spectra Energy Partners, LP (SEP), Enbridge Energy Partners, L.P. (EEP), Enbridge Energy Management, L.L.C. (EEM) and Enbridge Income Fund Holdings Inc. (ENF), (referred to herein collectively as the Sponsored Vehicles) in a series of combination transactions, through which we acquired all of the outstanding equity securities of the Sponsored Vehicles not beneficially owned by us (collectively, the Sponsored Vehicles buy-in). Please refer to Note 20 - Noncontrolling Interests for further discussion of the transactions. 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 common stock for each share of Spectra Energy common stock that they owned, resulting in us acquiring 100% ownership of Spectra Energy. Please refer to Note 8 - Acquisitions and Dispositions for further discussion of the transaction. DISPOSITIONS During the years ended December 31, 2018 and 2017, we have disposed of a number of our non-core assets. Please refer to Note 8 - Acquisitions and Dispositions for further discussion of these transactions.

SIGNIFICANT ACCOUNTING POLICIES

SIGNIFICANT ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2018
Accounting Policies [Abstract]
SIGNIFICANT 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 7) ; purchase price allocations (Note 8) ; unbilled revenues; depreciation rates and carrying value of property, plant and equipment (Note 11) ; amortization rates of intangible assets (Note 15) ; measurement of goodwill (Note 16) ; fair value of asset retirement obligations (ARO) (Note 19) ; valuation of stock-based compensation (Note 22) ; fair value of financial instruments (Note 24) ; provisions for income taxes (Note 25) ; assumptions used to measure retirement and other postretirement benefit obligations (OPEB) (Note 26) ; commitments and contingencies (Note 29) ; and estimates of losses related to environmental remediation obligations (Note 29) . Actual results could differ from these estimates. Certain comparative figures in our Consolidated Statements of Cash Flows have been reclassified to conform to the current year's presentation. 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. Net cash provided by financing activities in the Consolidated Statements of Cash Flows for the year ended December 31, 2016 have decreased by $0.3 billion 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 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, if 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 is applied, where an investor holding the majority voting rights consolidates the entity. 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 for comparative periods. Redeemable noncontrolling interests on the Consolidated Statements of Financial Position as at December 31, 2017 are recognized 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 (NBEUB), 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 7) . 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, 2018 , 2017 and 2016 , cash received net of revenue recognized for contracts under make-up rights and similar deferred revenue arrangements was $208 million , $196 million , and $249 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. Our Energy Services segment enters into commodity purchase and sale arrangements that are recorded gross because the related contracts are not held for trading purposes and we are acting as the principal in the transactions. 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 have readily determinable fair values as other investments measured at fair value measurement alternative and 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 impairment each reporting period. Equity investments with readily determinable fair values are measured at fair value through net income. Dividends received from investments in equity securities are recognized in earnings when the right to receive payment is established. Investments in debt securities are classified either as available for sale securities measured at fair value through OCI or as held to maturity securities measured at amortized cost. NONCONTROLLING INTERESTS Noncontrolling interests represent ownership interests attributable to third parties in certain consolidated subsidiaries. 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 as at December 31, 2017, within the mezzanine section of the Consolidated Statements of Financial Position between long-term liabilities and equity. Enbridge Income Fund (The Fund)'s noncontrolling interest holders had the option to redeem the Fund trust units for cash, subject to certain limitations. Redeemable noncontrolling interests as at December 31, 2017 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 and up until redeemable noncontrolling interest repurchase date, 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 for comparative periods. 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. From January 1, 2017 through July 3, 2018, emission allowances, which are recorded at their original cost, were 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 of the goodwill balance on April 1. 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. The allocation of goodwill to held for sale and disposed businesses is based on the relative fair value of businesses included in the particular reporting unit. Fair value of our reporting unit is estimated using a combination of discounted cash flow model and earnings multiples techniques. The determination of fair value using the discounted cash flow model technique requires the use of estimates and assumptions related to discount rates, projected operating income, terminal value growth rates, capital expenditures and working capital levels. The cash flow projections included significant judgments and assumptions relating to revenue growth rates and expected future capital expenditure. The determination of fair value using the earnings multiples technique requires assumptions to be made in relation to maintainable earnings and earnings multipliers for reporting units. 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 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. ARO

CHANGES IN ACCOUNTING POLICIES

CHANGES IN ACCOUNTING POLICIES	12 Months Ended
	Dec. 31, 2018
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
CHANGES IN ACCOUNTING POLICIES	CHANGES IN ACCOUNTING POLICIES CHANGES IN ACCOUNTING POLICIES There were no changes in accounting policies during the year ended December 31, 2018. ADOPTION OF NEW ACCOUNTING STANDARDS Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income Effective January 1, 2018, we adopted Accounting Standards Update (ASU) 2018-02 to address a specific consequence of the Tax Cuts and Jobs Act (TCJA or United States Tax Reform) enacted by the United States federal government on December 22, 2017. The amendments in this accounting update allowed a reclassification from accumulated other comprehensive income (AOCI) to retained earnings for stranded tax effects resulting from the TCJA. The amendments eliminated the stranded tax effects recognized as a result of the reduction of the historical United States federal corporate income tax rate to the newly enacted United States federal corporate income tax rate. The adoption of this accounting update did not have a material impact on our consolidated financial statements. Clarifying Guidance on the Application of Modification Accounting on Stock Compensation Effective January 1, 2018, we adopted ASU 2017-09 and applied the standard on a prospective basis. The new standard was issued to clarify the scope of modification accounting. Under the new guidance, modification accounting is required for all changes to share-based payment awards, unless all of the following conditions 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 adoption of this accounting update did not, and is not expected to have a material impact on our consolidated financial statements. Improving the Presentation of Net Periodic Benefit Cost related to Defined Benefit Plans Effective January 1, 2018, we adopted ASU 2017-07 which was issued 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 other postretirement plans. Upon adoption of this accounting update, our Consolidated Statements of Earnings presents the current service cost within Operating and administrative expenses and the other components of net benefit cost within Other income/(expense). Previously, all components of net benefit cost were presented within Operating and administrative expenses. In addition, only the service cost component of net benefit cost will be capitalized on a prospective basis. The adoption of this accounting update did not, and is not expected to have a material impact on our consolidated financial statements. Clarifying Guidance on Derecognition and Partial Sales of Nonfinancial Assets Effective January 1, 2018, we adopted ASU 2017-05 on a modified retrospective basis. The new standard clarifies the scope provisions of nonfinancial assets and how to allocate consideration to each distinct asset, and amends the guidance for derecognition of a distinct nonfinancial asset in partial sale transactions. The adoption of this accounting update did not have a material impact on our consolidated financial statements. Clarifying the Presentation of Restricted Cash in the Statement of Cash Flows Effective January 1, 2018, we adopted ASU 2016-18 on a retrospective basis. The new standard clarifies guidance on the classification and presentation of changes in restricted cash and restricted cash equivalents within the statement of cash flows. The amendments require that changes in restricted cash and restricted cash equivalents be included within cash and cash equivalents when reconciling the opening and closing period amounts shown on the statement of cash flows. For current and comparative periods, we amended the presentation in the Consolidated Statements of Cash Flows to include restricted cash and restricted cash equivalents with cash and cash equivalents. Simplifying Cash Flow Classification Effective January 1, 2018, we adopted ASU 2016-15 on a retrospective basis. The new standard reduces diversity in practice of how certain cash receipts and cash payments are classified in the Consolidated Statements of Cash Flows. The new guidance addresses eight specific presentation issues. We assessed each of the eight specific presentation issues and the adoption of this ASU did not have a material impact on our consolidated financial statements. Recognition and Measurement of Financial Assets and Liabilities Effective January 1, 2018, we adopted ASU 2016-01 on a prospective basis. The new standard addresses 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 assets and liabilities is measured using the exit price notion. The adoption of this accounting update did not have a material impact on our consolidated financial statements. Revenue from Contracts with Customers Effective January 1, 2018, we adopted ASU 2014-09 on a modified retrospective basis to contracts that were not complete at the date of initial application. The new standard was issued with the intent of significantly enhancing consistency and comparability of revenue recognition practices across entities and industries. The new standard establishes a single, principles-based five-step model to be applied to all contracts with customers and introduces new and enhanced disclosure requirements. It also requires the use of more estimates and judgments than the previous standards. In adopting Accounting Standards Codification (ASC) 606, we applied the practical expedient for contract modifications whereby contracts that were modified before January 1, 2018 were not retrospectively restated. Instead, the aggregate effect of all contract modifications occurring before that time has been reflected when identifying satisfied and unsatisfied performance obligations, determining the transaction price and allocating the transaction price to satisfied and unsatisfied performance obligations. Revenue was previously recognized for a certain contract within the Liquids Pipelines business unit using a formula-based method. Under the new revenue standard, revenue is recognized on a straight-line basis over the term of the agreement in order to reflect the fulfillment of our performance obligation to provide up to a specified volume of pipeline capacity throughout the term of the contract. 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 (CIACs) were previously recorded as reductions of property, plant and equipment regardless of whether the amounts were imposed by regulation or arose from negotiations with customers. Under the new revenue standard, CIACs which are negotiated as part of an agreement to provide transportation and other services to a customer are deemed to be advance payments for future services and are recognized as revenue when those future services are provided. Accordingly, negotiated CIACs are accounted for as deferred revenue and recognized as revenue over the term of the associated revenue contract. Amounts which are required to be collected from the customer based on requirements of the regulator continue to be accounted for as reductions of property, plant and equipment. The below table presents the cumulative, immaterial effect of the adoption of ASC 606 on our Consolidated Statement of Financial Position as at January 1, 2018 on each affected financial statement line item. For the year ended December 31, 2018, the effect of the adoption of ASC 606 on our Consolidated Statement of Earnings was not material. Balance at December 31, 2017 Adjustments Due to ASC 606 Balance at January 1, 2018 (millions of Canadian dollars) Assets Deferred amounts and other assets 6,442 (170 ) 6,272 Property, plant and equipment, net 90,711 112 90,823 Liabilities and equity Accounts payable and other 9,478 62 9,540 Other long-term liabilities 7,510 66 7,576 Deferred income taxes 9,295 (62 ) 9,233 Redeemable noncontrolling interests 4,067 (38 ) 4,029 Deficit (2,468 ) (86 ) (2,554 ) The following ASU’s have been issued, but not yet adopted Clarifying Interaction between Collaborative Arrangements and Revenue from Contracts with Customers In November 2018, ASU 2018-18 was issued to provide clarity on when transactions between entities in a collaborative arrangement should be accounted for under the new revenue standard, ASC 606. In determining whether transactions in collaborative arrangements should be accounted under the revenue standard, the update specifies that entities shall apply unit of account guidance to identify distinct goods or services and whether such goods and services are separately identifiable from other promises in the contract. ASU 2018-18 also precludes entities from presenting transactions with a collaborative partner which are not in scope of the new revenue standard together with revenue from contracts with customers. The accounting update is effective January 1, 2020 and early adoption is permitted. We are currently assessing the impact of the new standard on our consolidated financial statements. Improvements to Related Party Guidance for Variable Interest Entities ASU 2018-17 was issued in October 2018 to improve the related party guidance on determining whether fees paid to decision makers and service providers (“decision-maker fees”) are variable interests. Under the new guidance, reporting entities must consider indirect interests held through related parties in common control arrangements on a proportionate basis, rather than as the equivalent of a direct interest in its entirety, when determining if a decision maker’s fees constitute a variable interest. The accounting update is effective January 1, 2020 and must be applied on a retrospective basis. We are currently assessing the impact of the new standard on our consolidated financial statements. Amended Guidance on Cloud Computing Arrangements In August 2018, ASU 2018-15 was issued to provide guidance on the accounting for implementation costs incurred in a cloud computing arrangement (CCA) that is a service contract. The amendment aligns the accounting for costs incurred to implement a CCA that is a service arrangement with the guidance on capitalizing costs associated with developing or obtaining internal-use software. Additionally, ASU 2018-15 specifies that an entity would apply ASC 350-40, Internal-use software, to determine which implementation costs related to a hosting arrangement that is a service contract should be capitalized and which should be expensed. Furthermore, the amendments in the update require capitalized costs be amortized on a straight-line basis generally over the term of the arrangement and presented in the same income statement line as fees paid for the hosting service. The new standard also requires that the balance sheet presentation of capitalized implementation costs to be the same as that of the prepayment of fees related to the hosting arrangement, as well as similar consistency in classifications from a cash flow statement perspective. ASU 2018-15 is effective January 1, 2020 and we have elected to early adopt the standard as of January 1, 2019, as permitted. We do not expect the adoption of this accounting update to have a material impact on our consolidated financial statements. Disclosure Effectiveness In August 2018, the Financial Accounting Standards Board issued two amendments as a part of its disclosure framework project aimed to improve the effectiveness of disclosures in the notes to financial statements. ASU 2018-14 was issued in August 2018 to improve disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. The amendment modifies the current guidance by adding and removing several disclosure requirements while also clarifying the guidance on current disclosure requirements. ASU 2018-14 is effective January 1, 2021 and entities are permitted to adopt the standard early. We are currently assessing the impact of the new standard on our consolidated financial statements. ASU 2018-13 was issued to improve the disclosure requirements for fair value measurements by eliminating and modifying some disclosures, while also adding new disclosures. This update is effective January 1, 2020, however entities are permitted to early adopt the eliminated or modified disclosures. We are currently assessing the impact of the new standard on our consolidated financial statements. Improvements to Accounting for Hedging Activities ASU 2017-12 was issued in August 2017 with the objective of better aligning a company’s risk management activities and the resulting hedge accounting reflected in the financial statements. The amendments allow cash flow hedging of contractually specified components in financial and non-financial items. Under the new guidance, hedge ineffectiveness is no longer required to be measured and hedging instruments’ fair value changes will be recorded in the same income statement line as the hedged item. The ASU also allows the initial quantitative hedge effectiveness assessment to be performed at any time before the end of the quarter in which the hedge is designated. After initial quantitative testing is performed, an ongoing qualitative effectiveness assessment is permitted. The accounting update is effective January 1, 2019, with early adoption permitted, and is to be applied on a modified retrospective basis. Based upon our current assessment, we do not expect the standard to have a material impact on our consolidated financial statements. In October 2018, ASU 2018-16 was issued to permit the use of the Overnight Index Swap rate based on the Secured Overnight Financing Rate as a U.S. benchmark interest rate for hedge accounting purposes. ASU 2018-16 is effective concurrently with ASU 2017-12. 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 do not expect the adoption of this accounting update to 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 will recognize as an allowance its estimate of expected credit losses, which the Financial Accounting Standards Board believes will result in more timely recognition of such losses. Further, ASU 2018-19 was issued in November 2018 to clarify that operating lease receivables should be accounted for under the new leases standard, ASC 842, and are not within the scope of ASC 326, Financial Instrument - Credit Losses. Both accounting updates are effective January 1, 2020. We are currently assessing the impact of the new standard on our consolidated financial statements. Recognition of Leases ASU 2016-02 was issued in February 2016 with the intent to increase transparency and comparability among organizations. It requires lessees of operating lease arrangements to recognize lease assets and lease liabilities on the statements of financial position and disclose additional key information about lease agreements. The accounting update also replaces the current definition of a lease and requires that an arrangement be recognized as a lease when a customer has the right to obtain substantially all of the economic benefits from the use of an asset, as well as the right to direct the use of the asset. The new standard became effective January 1, 2019 and in adopting ASC 842, we have applied the package of practical expedients offered in connection with this update. Application of the package of practical expedients permits entities not to reassess a) whether any expired or existing contracts contain leases in accordance with the new guidance, b) lease classifications, and c) whether initial direct costs capitalized under current guidance continue to meet the definition of initial direct costs under the new guidance. Under the new lease guidance, we have also decided to elect, by class of underlying asset, to not separate non-lease components from the associated lease components of our lessee contract and account for both components as a single lease component. ASU 2018-01 was issued in January 2018 to address stakeholder concerns about the costs and complexity of complying with the transition provisions of the new lease requirements as they relate to land easements. The amendments provide an optional transition practical expedient to not evaluate existing or expired land easements that were not previously accounted for as leases under existing guidance. We have elected this practical expedient in connection with the adoption of the new lease requirements. In July 2018, ASU 2018-11 was issued to address additional stakeholder concerns regarding the unanticipated costs and complexities associated with the modified retrospective transition method as well as the requirement for lessors to separate components of a contract. Under the new guidance, entities are provided with an additional transition method which allows entities to apply the new standard at the date of adoption and to elect not to recast comparative periods presented. This amendment also permits lessors to combine associated lease and non-lease components within a contract for operating leases when certain conditions are met. We have elected both of these practical expedients in the adoption of the new lease standard. We have identified all lease contracts existing as at November 30, 2018 and have performed detailed evaluations of those lease contracts under the requirements of the transitional guidance. We estimate that we will recognize right-of-use lease assets and related lease liabilities for existing operating leases where we are the lessee in the range of $750 million to $900 million , with no impact to our Consolidated Statements of Earnings or Consolidated Statements of Cash Flows. This estimate represents the net present value of future lease payments payable under operating lease contracts we had entered into as at November 30, 2018, and that have commenced or are scheduled to commence by January 1, 2019. We do not expect any adjustments will be made to our accounting for existing lessor contracts as a result of implementing this new standard.

REVENUE

REVENUE	12 Months Ended
	Dec. 31, 2018
Revenue from Contract with Customer [Abstract]
REVENUE	REVENUE REVENUE FROM CONTRACTS WITH CUSTOMERS Major Products and Services Liquids Pipelines Gas Transmission and Midstream Gas Distribution Green Power and Transmission Energy Services Eliminations and Other Consolidated Year ended December 31, 2018 (millions of Canadian dollars) Transportation revenue 8,488 3,928 875 — — — 13,291 Storage and other revenue 101 222 196 — — — 519 Gas gathering and processing revenue — 815 — — — — 815 Gas distribution revenue — — 4,376 — — — 4,376 Electricity and transmission revenue — — — 559 — — 559 Commodity sales — 1,590 — — — — 1,590 Total revenue from contracts with customers 8,589 6,555 5,447 559 — — 21,150 Commodity sales — — — — 26,070 — 26,070 Other revenue 1 (894 ) 6 9 8 4 25 (842 ) Intersegment revenue 384 10 14 — 154 (562 ) — Total revenue 8,079 6,571 5,470 567 26,228 (537 ) 46,378 1 Includes mark-to-market gains/(losses) from our hedging program. We disaggregate revenue into categories which represent our principal performance obligations within each business segment because these revenue categories represent the most significant revenue streams in each segment and consequently are considered to be the most relevant revenue information for management to consider in evaluating performance. Contract Balances Receivables Contract Assets Contract Liabilities (millions of Canadian dollars) Balance as at January 1, 2018 2,475 290 992 Balance as at December 31, 2018 1,929 191 1,245 Contract receivables represent the amount of receivables derived from contracts with customers. The decrease in contract receivables for the year ended December 31, 2018, is primarily attributed to the sale of Midcoast Operating, L.P. and its subsidiaries to AL Midcoast Holdings, LLC (an affiliate of ArcLight Capital Partners, LLC), refer to Note 8 - Acquisitions and Dispositions for further discussion. Contract assets represent the amount of revenue which has been recognized in advance of payments received for performance obligations we have fulfilled (or partially fulfilled) and prior to the point in time at which our right to the payment is unconditional. Amounts included in contract assets are transferred to accounts receivable when our right to the consideration becomes unconditional. Contract liabilities represent payments received for performance obligations which have not been fulfilled. Contract liabilities primarily relate to make-up rights and deferred revenue. Revenue recognized during the year ended December 31, 2018 included in contract liabilities at the beginning of the period is $ 183 million . Increases in contract liabilities from cash received, net of amounts recognized as revenue during the year ended December 31, 2018 were $ 449 million . Performance Obligations Segment Nature of Performance Obligation Liquids Pipelines • Transportation and storage of crude oil and NGLs Gas Transmission and Midstream • Sale of crude oil, natural gas and NGLs • Transportation, storage, gathering, compression and treating of natural gas • Transportation of NGLs Gas Distribution • Supply and delivery of natural gas • Transportation of natural gas • Storage of natural gas Green Power and Transmission • Generation and transmission of electricity • Delivery of electricity from renewable energy generation facilities There was no material revenue recognized in the year ended December 31, 2018 from performance obligations satisfied in previous periods. Payment Terms Payments are received monthly from customers under long-term transportation, commodity sales, and gas gathering and processing contracts. Payments from Gas Distribution customers are received on a continuous basis based on established billing cycles. Certain contracts in the United States offshore business provide for us to receive a series of fixed monthly payments (FMPs) for a specified period which is less than the period during which the performance obligations are satisfied. As a result, a portion of the FMPs is recorded as a contract liability. The FMPs are not considered to be a financing arrangement because the payments are scheduled to match the production profiles of offshore oil and gas fields, which generate greater revenue in the initial years of their productive lives. Revenue to be Recognized from Unfulfilled Performance Obligations Total revenue from performance obligations expected to be fulfilled in future periods is $ 67.4 billion , of which $ 7.1 billion is expected to be recognized during the year ending December 31, 2019. The revenues excluded from the amounts above based on optional exemptions available under ASC 606, as explained below, represent a significant portion of our overall revenues and revenues from contracts with customers. Certain revenues such as flow-through operating costs charged to shippers are recognized at the amount for which we have the right to invoice our customers and are excluded from the amounts for revenue to be recognized in the future from unfulfilled performance obligations above. Variable consideration is excluded from the amounts above due to the uncertainty of the associated consideration, which is generally resolved when actual volumes and prices are determined. For example, we consider interruptible transportation service revenues to be variable revenues since volumes cannot be estimated. Additionally, the effect of escalation on certain tolls which are contractually escalated for inflation has not been reflected in the amounts above as it is not possible to reliably estimate future inflation rates. Revenues for periods extending beyond the current rate settlement term for regulated contracts where the tolls are periodically reset by the regulator are excluded from the amounts above since future tolls remain unknown. Finally, revenues from contracts with customers which have an original expected duration of one year or less are excluded from the amounts above. SIGNIFICANT JUDGMENTS MADE IN RECOGNIZING REVENUE Long-Term Transportation Agreements For long-term transportation agreements, significant judgments pertain to the period over which revenue is recognized and whether the agreement provides for make-up rights for the shippers. Transportation revenue earned from firm contracted capacity arrangements is recognized ratably over the contract period. Transportation revenue from interruptible or volumetric-based arrangements is recognized when services are performed. Estimates of Variable Consideration Revenue from arrangements subject to variable consideration is recognized only to the extent that it is probable that a significant reversal in the amount of cumulative revenue recognized will not occur when the uncertainty associated with the variable consideration is subsequently resolved. Uncertainties associated with variable consideration relate principally to differences between estimated and actual volumes and prices. These uncertainties are resolved each month when actual volumes are sold or transported and actual tolls and prices are determined. Recognition and Measurement of Revenue Liquids Pipelines Gas Transmission and Midstream Gas Distribution Green Power and Transmission Energy Services Consolidated Year ended December 31, 2018 (millions of Canadian dollars) Revenue from products transferred at a point in time 1 — 1,590 68 — — 1,658 Revenue from products and services transferred over time 2 8,589 4,965 5,379 559 — 19,492 Total revenue from contracts with customers 8,589 6,555 5,447 559 — 21,150 1 Revenue from sales of crude oil, natural gas and NGLs. 2 Revenue from crude oil and natural gas pipeline transportation, storage, natural gas gathering, compression and treating, natural gas distribution, natural gas storage services and electricity sales. Performance Obligations Satisfied at a Point in Time Revenue from commodity sales where the commodity sold is not immediately consumed prior to use is recognized at the point in time when the contractually specified volume of the commodity has been delivered, as control over the commodity transfers to the customer upon delivery. Performance Obligations Satisfied Over Time For arrangements involving the transportation and sale of petroleum products and natural gas where the transportation services or commodities are simultaneously received and consumed by the shipper or customer, we recognize revenue over time using an output method based on volumes of commodities delivered or transported. The measurement of the volumes transported or delivered corresponds directly to the benefits received by the shippers or customers during that period. Determination of Transaction Prices Prices for gas processing and transportation services are determined based on the capital cost of the facilities, pipelines and associated infrastructure required to provide such services plus a rate of return on capital invested that is determined either through negotiations with customers or through regulatory processes for those operations that are subject to rate regulation. Prices for commodities sold are determined by reference to market price indices plus or minus a negotiated differential and in certain cases a marketing fee. Prices for natural gas sold and distribution services provided by regulated natural gas distribution operations are prescribed by regulation.

SEGMENTED INFORMATION

SEGMENTED INFORMATION	12 Months Ended
	Dec. 31, 2018
Segment Reporting [Abstract]
SEGMENTED INFORMATION	SEGMENTED INFORMATION Segmented information for the years ended December 31, 2018 , 2017 and 2016 are as follows: Year ended December 31, 2018 Liquids Pipelines Gas Transmission and Midstream Gas Distribution Green Power and Transmission Energy Services Eliminations and Other Consolidated (millions of Canadian dollars) Revenues 8,079 6,571 5,470 567 26,228 (537 ) 46,378 Commodity and gas distribution costs (16 ) (1,481 ) (2,748 ) (7 ) (25,689 ) 540 (29,401 ) Operating and administrative (3,124 ) (2,102 ) (1,111 ) (157 ) (73 ) (225 ) (6,792 ) Impairment of long-lived assets (180 ) (914 ) — (4 ) — (6 ) (1,104 ) Impairment of goodwill — (1,019 ) — — — — (1,019 ) Income/(loss) from equity investments 577 930 11 (28 ) 18 1 1,509 Other income/(expense) (5 ) 349 89 (2 ) (2 ) (481 ) (52 ) Earnings/(loss) before interest, income tax expense, and depreciation and amortization 5,331 2,334 1,711 369 482 (708 ) 9,519 Depreciation and amortization (3,246 ) Interest expense (2,703 ) Income tax expense (237 ) Earnings 3,333 Capital expenditures 1 3,102 2,644 1,066 33 — 27 6,872 Total assets 68,798 60,559 25,748 5,716 1,042 5,042 166,905 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 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) . No non-affiliated customer exceeds 10% of our third-party revenues for the year ended December 31, 2018 . Our largest non-affiliated customer accounted for approximately 11.8% , and 18.0% of our third-party revenues for the years ended December 31, 2017 and 2016 , respectively. A second customer accounted for approximately 10.4% of our third-party revenues for the year ended December 31, 2016 . Revenues from these two customers are primarily reported in the Energy Services segment. GEOGRAPHIC INFORMATION Revenues 1 Year ended December 31, 2018 2017 2016 (millions of Canadian dollars) Canada 19,023 18,076 12,470 United States 27,355 26,302 22,090 46,378 44,378 34,560 1 Revenues are based on the country of origin of the product or service sold. Property, Plant and Equipment 1 December 31, 2018 2017 (millions of Canadian dollars) Canada 44,716 46,025 United States 49,824 44,686 94,540 90,711 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, 2018
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 12 million as at December 31, 2018 , and 13 million as at December 31, 2017 and 2016 , 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, 2018 2017 2016 (number of shares in millions) Weighted average shares outstanding 1,724 1,525 911 Effect of dilutive options 3 7 7 Diluted weighted average shares outstanding 1,727 1,532 918 For the years ended December 31, 2018 , 2017 and 2016 , 26,837,822 , 14,271,615 and 10,803,672 , respectively, of anti-dilutive stock options with a weighted average exercise price of $50.38 , $56.71 and $52.92 , respectively, were excluded from the diluted earnings per common share calculation.

REGULATORY MATTERS

REGULATORY MATTERS	12 Months Ended
	Dec. 31, 2018
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 - Significant Accounting Policies 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 14) . 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 (BC) Pipeline and BC Field Services Under the current NEB-authorized rate structure for BC Pipeline, 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 the temporary differences that created the deferred income taxes, it is expected that tolls will be adjusted to recover these taxes. Since most of these temporary differences are related to property, plant and equipment costs, this recovery is expected to occur over the life of those assets. On July 4, 2018, we entered into agreements to sell our Canadian natural gas gathering and processing businesses ( Note 8 ) . On October 1, 2018, we closed the sale of the provincially regulated facilities. The sale of the federally regulated facilities is expected to close in mid-2019. 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, BC Pipelines, BC Field Services and SEP, refer to Note 8 - Acquisitions and Dispositions . Gas Distribution On August 30, 2018, we received a decision from the OEB approving the application to amalgamate EGD and Union Gas (Amalgamation). On October 15, 2018, we announced that we would proceed with the Amalgamation, with an expected effective date of January 1, 2019. On January 1, 2019, the Amalgamation was completed and the amalgamated company continued as Enbridge Gas Inc. (EGI). The OEB decision also approved the rate setting mechanism for the amalgamated entity to be employed during a five-year deferred rebasing period from 2019 through 2023, after which time rates will be rebased. The decision also approved the continuation and establishment of certain deferral and variance accounts, as well as an earnings sharing mechanism that requires the amalgamated entity to share equally with customers, any earnings in excess of 150 basis points over the OEB approved ROE. Enbridge Gas Distribution Inc. EGD’s gas distribution operations are regulated by the OEB. Rates for the years ended December 31, 2018 and 2017 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 IR plan 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 9.0% and 8.8% for the years ended December 31, 2018 and 2017 , 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. On December 4, 2018, we announced that we entered into a definitive agreement for the sale of Enbridge Gas New Brunswick Inc. ( Note 8 ) . Closing of the transaction remains subject to the receipt of regulatory approvals and other customary closing conditions expected to occur in 2019. As such, we classified Enbridge Gas New Brunswick Inc. assets as held for sale and measured them at the lower of their carrying value or fair value less costs to sell. As the carrying value does not exceed the fair value, no impairment has been recorded for the year ended December 31, 2018. 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 2018 2017 (millions of Canadian dollars) Regulatory assets/(liabilities) Liquids Pipelines Deferred income taxes Various 1,673 1,492 Tolling deferrals Various (28 ) (34 ) Recoverable income taxes Through 2030 27 46 Pipeline future abandonment costs 1 Various (201 ) (141 ) Gas Transmission and Midstream Deferred income taxes Various 826 717 Regulatory liability related to income taxes 2 Various (912 ) (1,078 ) Other Various 94 (16 ) Gas Distribution Deferred income taxes Various 1,132 1,000 Purchased gas variance 3 Various 197 51 Pension plans and OPEB 4 Through 2033 118 102 Constant dollar net salvage adjustment 2018 6 38 Future removal and site restoration reserves 5 Various (1,107 ) (1,066 ) Site restoration clearance adjustment Various — (31 ) Other Various (4 ) 31 1 Funds collected are included in Restricted long-term investments (Note 14) . 2 Relates to the establishment of a regulatory liability as a result of the United States tax reform legislation enacted 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. 5 Future removal and site restoration reserves result from amounts collected from customers by the Company, with the approval of the OEB, to fund future costs for removal and site restoration relating to property, plant and equipment. These costs are collected as part of depreciation charged on property, plant and equipment that is recorded in rates. The balance represents the amount that the Company has collected from customers, net of actual costs expended on removal and site restoration. The settlement of this balance will occur over the long-term as future removal and site restoration costs are incurred. In the absence of rate regulation accounting, costs incurred for removal and site restoration would be charged to earnings as incurred with recognition of revenue for amounts previously collected. 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, 2018 and 2017 , the net book value of these costs included in gas mains in Property, plant and equipment, net was $110 million and $118 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, 2018
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 common stock 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 16) . 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 LLC (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 13) . 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 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 In 2018, the assets of the Tupper Plants were subsequently reclassified to assets held for sale and sold as part of the provincially regulated assets of the Canadian Natural Gas Gathering and Processing transaction. See Assets Held for Sale section below for further details of the transaction. 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, 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 Enbridge Gas New Brunswick In December 2018, we entered into an agreement for the sale of Enbridge Gas New Brunswick Limited Partnership and Enbridge Gas New Brunswick Inc. (collectively, EGNB) to Liberty Utilities (Canada) LP, a wholly-owned subsidiary of Algonquin Power and Utilities Corp., for a cash purchase price of $331 million . EGNB operates and maintains natural gas distribution pipelines in southern New Brunswick, and its related assets are included in our Gas Distribution segment. Subject to certain regulatory approvals and customary closing conditions, the transaction is expected to close in 2019. As these assets represented a portion of a reporting unit, we allocated a portion of the goodwill of the reporting unit to these assets using a relative fair value approach. As such, we have classified EGNB assets and an allocated goodwill of $133 million as held for sale and measured them at the lower of their carrying value or fair value less costs to sell. As the carrying value does not exceed the fair value, no impairment has been recorded for the year ended December 31, 2018. Canadian Natural Gas Gathering and Processing Businesses On July 4, 2018, we entered into agreements to sell our Canadian natural gas gathering and processing businesses to Brookfield Infrastructure Partners L.P. and its institutional partners for a cash purchase price of approximately $4.3 billion , subject to customary closing adjustments. Separate agreements were entered into for those facilities currently governed by provincial regulations and those governed by federal regulations (collectively, Canadian Natural Gas Gathering and Processing Businesses assets). On October 1, 2018, we closed the sale of the provincially regulated facilities for proceeds of approximately $2.5 billion . These assets were included within our Gas Transmission and Midstream segment. Please see Dispositions discussion below for further details regarding the transaction. As at December 31, 2018, the net assets of the federally regulated facilities of our Canadian Natural Gas Gathering and Processing Business remain classified as held for sale, including $55 million of allocated goodwill. The sale of the federally regulated facilities is expected to close in mid-2019 for proceeds of approximately $1.8 billion . In addition, upon classifying the Canadian Natural Gas Gathering and Processing Businesses assets as held for sale in the third quarter of 2018, as these assets represented a portion of a reporting unit, we allocated a portion of the goodwill of the reporting unit to these assets using a relative fair value approach. As a result of the goodwill allocation, the carrying value of Canadian Natural Gas Gathering and Processing Businesses assets is greater than the sale price consideration less the cost to sell. Therefore, we recorded a goodwill impairment of $1,019 million on the Consolidated Statements of Earnings for the year ended December 31, 2018. The held for sale classification represented a triggering event and required us to perform a goodwill impairment test for the related reporting unit. The results of the test did not indicate any additional goodwill impairment. Line 10 Crude Oil Pipeline In the first quarter of 2018, we satisfied the condition as set out in our agreements for the sale of our Line 10 crude oil pipeline (Line 10), which originates near Hamilton, Ontario and terminates at West Seneca, New York. Our subsidiaries, Enbridge Pipelines Inc. and EEP, own the Canadian and United States portions of Line 10, respectively, and the related assets are included in our Liquids Pipeline segment. We expect to close the sale of Line 10 within one year, subject to regulatory approval and certain closing conditions. As such, during the first quarter of 2018, we classified Line 10 assets as held for sale and measured them at the lower of their carrying value or fair value less costs to sell, which resulted in a loss of $154 million ( $95 million after-tax attributable to us) included within Asset impairment on the Consolidated Statements of Earnings for the year ended December 31, 2018. 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 $96 million (US $70 million ). Subject to regulatory approval and certain pre-closing conditions, the transaction is expected to close in 2019. As at December 31, 2018 and 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, 2018 December 31, 2017 (millions of Canadian dollars) Accounts receivable and other (current assets held for sale) 117 424 Deferred amounts and other assets (long-term assets held for sale) 1 2,383 1,190 Accounts payable and other (current liabilities held for sale) (63 ) (315 ) Other long-term liabilities (long-term liabilities held for sale) (96 ) (34 ) Net assets held for sale 2,341 1,265 1 Included within Deferred amounts and other assets at December 31, 2018 and 2017 respectively is property, plant and equipment of $2.1 billion and $1.1 billion . DISPOSITIONS Canadian Natural Gas Gathering and Processing Businesses On October 1, 2018, we closed the sale of the provincially regulated facilities of the Canadian Natural Gas Gathering and Processing Businesses assets for proceeds of approximately $2.5 billion . After closing adjustments, a gain on disposal of $34 million before tax was included in Other income/(expense) in the Consolidated Statements of Earnings. Please see Assets Held for Sale discussion above for further details regarding the transaction. Renewable Assets On August 1, 2018, we closed the sale of a 49% interest in all of our Canadian renewable assets, a 49% interest in two United States renewable assets and 49% of our interest in the Hohe See Offshore wind power project and its subsequent expansion, both concurrently under construction in Germany, (collectively, the Renewable Assets) to the Canada Pension Plan Investment Board (CPPIB). Total cash proceeds from the transaction were $1.75 billion . In addition, CPPIB will fund their pro-rata share of the remaining capital expenditures on the Hohe See Offshore wind power project. We maintain a 51% interest in the Renewable Assets and will continue to manage, operate and provide administrative services for these assets. A loss on disposal of $20 million ( €14 million ) was included in Other income/(expense) in the Consolidated Statements of Earnings for the sale of 49% of our interest in the Hohe See Offshore wind power project and its subsequent expansion. Subsequent to the sale, the remaining interests in these assets continue to be accounted for as an equity method investment, and are a part of our Green Power and Transmission segment. Gains of $62 million and $17 million (US $13 million ) were included in Additional paid-in capital in the Consolidated Statements of Financial Position for the sale of 49% interest in the Canadian and United States renewable assets, respectively. Subsequent to the sale, because we maintained a controlling interest, these assets continue to be consolidated and are a part of our Green Power and Transmission segment. In addition, we recognized noncontrolling interests in our Consolidated Statements of Financial Position as at December 31, 2018 to reflect the interests that we do not hold ( Note 20 ) . Also, a deferred income tax recovery of $267 million ( $196 million attributable to us) was recorded in the year ended December 31, 2018 as a result of the agreement entered into during the second quarter of 2018 for the Renewable Assets (Note 25) . In connection with our sale of the Renewable Assets, we have new consolidated and unconsolidated VIEs (Note 12) . Midcoast Operating, L.P. On August 1, 2018, we closed the sale of Midcoast Operating, L.P. and its subsidiaries (collectively, MOLP) to AL Midcoast Holdings, LLC (an affiliate of ArcLight Capital Partners, LLC) for total cash proceeds of $1.4 billion (US $1.1 billion ). After closing adjustments recorded in the fourth quarter of 2018, a loss on disposal of $41 million (US $32 million ) was included in Other income/(expense) in the Consolidated Statements of Earnings. MOLP conducted our United States natural gas and natural gas liquids gathering, processing, transportation and marketing businesses, and was a part of our Gas Transmission and Midstream segment. Upon closing of the sale, we also recorded a liability of $387 million (US $298 million ) for future volume commitments retained by us. The associated loss is included in the loss on disposal of $41 million discussed above. As at December 31, 2018, $79 million (US $58 million ) and $296 million (US $216 million ) were included in Accounts payable and other and Other long-term liabilities, respectively, on the Consolidated Statements of Financial Position. In the second quarter of 2018, our equity method investment in the Texas Express NGL pipeline system, together with the MOLP assets that have been held for sale since December 31, 2017, also met the conditions for assets held for sale. The $447 million carrying value of Texas Express NGL pipeline system equity investment and an allocated goodwill of $262 million , were included within the disposal group as at June 30, 2018 and subsequently disposed on August 1, 2018. In the first quarter of 2018, as a result of entering into a definitive sales agreement, the fair value of the assets held for sale as at March 31, 2018 were revised based on the sale price. Accordingly, we recorded a loss of $913 million ( $701 million after-tax). This loss has been included within Asset impairment on the Consolidated Statements of Earnings for the year ended December 31, 2018. Previously 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 an asset impairment loss of $4.4 billion ( $2.8 billion after-tax) and a related goodwill impairment of $102 million , which were included in the Consolidated Statement of Earnings for the year ended December 31, 2017. Sandpiper Project During the years ended December 31, 2018 and 2017, we sold unused pipe related to the Sandpiper Project (Sandpiper) for cash proceeds of approximately $38 million ( US$30 million ) and $148 million (US $111 million ), respectively. Gains on disposal of $29 million ( US$22 million ) and $83 million (US $63 million ) before tax were included in Operating and administrative expense in the Consolidated Statements of Earnings for the years ended December 31, 2018 and 2017, respectively. These assets were a part of our Liquids Pipelines segment. 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. 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 .

ACCOUNTS RECEIVABLE AND OTHER

ACCOUNTS RECEIVABLE AND OTHER	12 Months Ended
	Dec. 31, 2018
Receivables [Abstract]
ACCOUNTS RECEIVABLE AND OTHER	ACCOUNTS RECEIVABLE AND OTHER December 31, 2018 2017 (millions of Canadian dollars) Trade receivables and unbilled revenues 1 4,711 5,325 Short-term portion of derivative assets 498 296 Other 1,308 1,432 6,517 7,053 1 Net of allowance for doubtful accounts of $64 million and $50 million as at December 31, 2018 and 2017 , respectively. During 2017, in conjunction with its restructuring actions (Note 20) , EEP terminated a receivable purchase agreement with a special purpose entity wholly-owned by us.

INVENTORY

INVENTORY	12 Months Ended
	Dec. 31, 2018
Inventory Disclosure [Abstract]
INVENTORY	INVENTORY December 31, 2018 2017 (millions of Canadian dollars) Natural gas 776 695 Crude oil 482 744 Other commodities 81 89 1,339 1,528 Adjustments of $93 million , nil and nil were included in Commodity costs on the Consolidated Statements of Earnings for the years ended December 31, 2018, 2017 and 2016, respectively, to reduce inventory to market value.

PROPERTY, PLANT AND EQUIPMENT

PROPERTY, PLANT AND EQUIPMENT	12 Months Ended
	Dec. 31, 2018
Property, Plant and Equipment [Abstract]
PROPERTY, PLANT AND EQUIPMENT	PROPERTY, PLANT AND EQUIPMENT Weighted Average December 31, Depreciation Rate 2018 2017 (millions of Canadian dollars) Pipelines 2.6 % 50,078 47,720 Pumping equipment, buildings, tanks and other 3.0 % 16,935 16,610 Land and right-of-way 1 2.7 % 2,603 2,538 Gas mains, services and other 3.2 % 17,474 17,026 Compressors, meters and other operating equipment 1.7 % 5,893 5,774 Processing and treating plants 1.5 % 1,634 1,440 Storage 1.9 % 1,713 1,545 Wind turbines, solar panels and other 4.2 % 5,063 4,804 Power transmission 2.6 % 383 365 Vehicles, office furniture, equipment and other buildings and improvements 5.9 % 630 390 Under construction — 9,778 7,601 Total property, plant and equipment 2 112,184 105,813 Total accumulated depreciation (17,644 ) (15,102 ) Property, plant and equipment, net 94,540 90,711 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, 2018 and December 31, 2017 (Note 8) . Depreciation expense for the years ended December 31, 2018 , 2017 and 2016 was $2.9 billion , $2.9 billion and $2.0 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 the 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 8) . 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. 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, 2018
Equity Method Investments and Joint Ventures [Abstract]
VARIABLE INTEREST ENTITIES	VARIABLE INTEREST ENTITIES CONSOLIDATED VARIABLE INTEREST ENTITIES Enbridge Canadian Renewable LP (ECRLP) To facilitate the sale on August 1, 2018 of the Renewable Assets ( Note 8 ) , we and our subsidiaries transferred our Canadian renewable assets to a newly formed partnership, ECRLP. Subsequently, a 49% interest in ECRLP was sold to CPPIB. ECRLP is a VIE as its limited partners do not have substantive kick-out rights or participating rights. Because we have the power to direct the activities of ECRLP, we are exposed to potential losses, and we have the right to receive benefits from ECRLP, we are considered the primary beneficiary. Enbridge Energy Partners, L.P. EEP is a 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 , our economic interest in EEP was 34.6% and the public owned the remaining interests in EEP. As at December 31, 2018 , subsequent to the Sponsored Vehicles buy-in (Note 20 ) , our interest in EEP was 100% . 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 100% direct common interest in the Fund. We also serve in the capacity of Manager of the Fund and Affiliates. As at December 31, 2017 , our combined economic interest and direct common interest in the Fund were 82.5% and 29.4% , respectively. As at December 31, 2018 , subsequent to the Sponsored Vehicles buy-in (Note 20 ) , our interest in the Fund was 100% . Enbridge Commercial Trust (ECT) 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 and Affiliates. Enbridge Income Partners LP (EIPLP) 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 a direct 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 a 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 , our economic interest and direct common interest in EIPLP were 73.5% and 53.1% , respectively. As at December 31, 2018 , subsequent to the Sponsored Vehicles buy-in (Note 20 ) , our interest in EIPLP was 100% . Green Power and Transmission Through various subsidiaries, we have a majority ownership interest in Magic Valley, Wildcat, Keechi Wind Project (Keechi), New Creek and Chapman Ranch wind facilities. These wind facilities are considered VIEs due to the members’ lack of substantive kick-out rights and participating rights. 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 facilities, 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 13) . 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 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. We acquired a 75% o wnership in SEP through the Merger Transaction in 2017. As at December 31, 2018 , subsequent to the Sponsored Vehicles buy-in (Note 20 ) , our interest in SEP was 100% . Valley Crossing Pipeline, LLC Valley Crossing Pipeline, LLC (Valley Crossing), a wholly-owned subsidiary of Enbridge, has constructed a natural gas pipeline to transport natural gas within Texas. The pipeline was placed into service in October 2018. Following the completion of the pipeline construction and beginning of the long term transportation services agreement, Valley Crossing was concluded to have sufficient equity at risk to finance its activities without additional subordinated financial support and thus is no longer a VIE after October 2018. 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, 2018 2017 (millions of Canadian dollars) Assets Cash and cash equivalents 506 368 Restricted cash 27 — Accounts receivable and other 2,073 2,132 Accounts receivable from affiliates 5 3 Inventory 244 220 2,855 2,723 Property, plant and equipment, net 72,737 68,685 Long-term investments 6,481 6,258 Restricted long-term investments 244 206 Deferred amounts and other assets 3,156 2,921 Intangible assets, net 317 296 Goodwill 29 29 Deferred income taxes 131 145 85,950 81,263 Liabilities Short-term borrowings 275 485 Accounts payable and other 2,925 2,859 Accounts payable to affiliates 4 131 Interest payable 303 312 Environmental liabilities 22 35 Current portion of long-term debt 1,034 2,129 4,563 5,951 Long-term debt 29,577 31,469 Other long-term liabilities 5,074 4,301 Deferred income taxes 6,911 3,010 46,125 44,731 Net assets before noncontrolling interests 39,825 36,532 We do not have an obligation to provide financial support to any of the consolidated VIEs. UNCONSOLIDATED VARIABLE INTEREST ENTITIES 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, 2018 and 2017 is presented below. Carrying Amount of Investment Enbridge’s Maximum Exposure to December 31, 2018 in VIE Loss (millions of Canadian dollars) Aux Sable Liquid Products L.P. 1 311 375 Eolien Maritime France SAS 2 68 784 Enbridge Renewable Infrastructure Investments S.a.r.l. 3, 9 127 3,250 Illinois Extension Pipeline Company, L.L.C. 4 724 724 Nexus Gas Transmission, LLC 5 1,757 2,668 PennEast Pipeline Company, LLC 6 97 385 Rampion Offshore Wind Limited 7 638 648 Vector Pipeline L.P. 8 198 301 Other 4 27 27 3,947 9,162 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. 300 361 Eolien Maritime France SAS 69 754 Hohe See Offshore Wind Project 9 763 2,484 Illinois Extension Pipeline Company, L.L.C. 686 686 Nexus Gas Transmission, LLC 834 1,678 PennEast Pipeline Company, LLC 69 345 Rampion Offshore Wind Limited 555 679 Sabal Trail Transmissions, LLC 2,355 2,529 Vector Pipeline L.P. 169 278 Other 21 21 5,821 9,815 1 At December 31, 2018 , 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, 2018 , 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 $202 million held by us. 3 At December 31, 2018 , 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, 2018 , the maximum exposure to loss is limited to our equity investment as these companies are in operation and self-sustaining. 5 At December 31, 2018 , the maximum exposure to loss includes the remaining expected contributions to the joint venture and parental guarantees for our portion of capacity lease agreements. 6 At December 31, 2018 the maximum exposure to loss includes the remaining expected contributions to the joint venture. 7 At December 31, 2018 , the maximum exposure to loss includes the portion of our parental guarantee that has been committed in project contracts in which we would be liable for in the event of default by the VIE. 8 At December 31, 2018 the maximum exposure to loss includes the carrying value of an outstanding affiliate loan receivable for $ 102 million held by us. 9 As at December 31, 2018 , the carrying amount of investment and maximum exposure to loss related to Hohe See Offshore Wind Project are included in the amounts shown for ERII. We do not have an obligation to and did not provide any additional financial support to the VIEs during the years ended December 31, 2018 and 2017 . Enbridge Renewable Infrastructure Investments S.a.r.l. (ERII) To facilitate the sale on August 1, 2018 of the Renewable Assets ( Note 8 ) , we transferred our interest in the Hohe See Offshore wind facilities and its subsequent expansion to a newly formed entity, ERII. Subsequently, a 49% interest in ERII was sold to CPPIB. ERII is a VIE due to insufficient equity at risk to finance its activities. We are not the primary beneficiary of ERII since the power to direct the activities of ERII that most significantly impacts its economic performance is shared. We account for ERII by using the equity method as we retain significant influence through a 51% voting interest in substantive decisions. 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 and has been classified as a variable interest entity. On April 30, 2018, Sabal Trail issued US$500 million in aggregate principal amount of 4.25% senior notes due in 2028, US$600 million in aggregate principal amount of 4.68% senior notes due in 2038 and US$400 million in aggregate principal amount of 4.83% senior notes due in 2048. Sabal Trail distributed net proceeds from the offering to the members as a partial reimbursement of construction and development costs incurred by the members. The net distribution made to SEP was US$744 million and was used to pay down indebtedness and is included within Distributions from equity investments in excess of cumulative earnings on the Consolidated Statements of Cash Flows for the year ended December 31, 2018. These events triggered reconsideration and as a result, it was concluded that Sabal Trail was no longer a VIE as of June 30, 2018 due to sufficient equity at risk to finance its activities.

LONG-TERM INVESTMENTS

LONG-TERM INVESTMENTS	12 Months Ended
	Dec. 31, 2018
Equity Method Investments and Joint Ventures [Abstract]
LONG-TERM INVESTMENTS	LONG-TERM INVESTMENTS Ownership December 31, Interest 2018 2017 (millions of Canadian dollars) EQUITY INVESTMENTS Liquids Pipelines Bakken Pipeline System 1 27.6 % 2,039 1,938 Seaway Crude Pipeline System 50.0 % 3,113 2,882 Illinois Extension Pipeline Company, L.L.C. 2 65.0 % 724 686 Other 30.0% - 43.8% 97 87 Gas Transmission and Midstream Alliance Pipeline 3 50.0 % 368 375 Aux Sable 42.7% - 50.0% 311 300 DCP Midstream, LLC 4 50.0 % 2,368 2,143 Gulfstream Natural Gas System, L.L.C. 4 50.0 % 1,289 1,205 Nexus Gas Transmission, LLC 4 50.0 % 1,757 834 Offshore - various joint ventures 22.0% - 74.3% 400 389 PennEast Pipeline Company LLC 4 20.0 % 97 69 Sabal Trail Transmission, LLC 5 50.0 % 1,586 2,355 Southeast Supply Header L.L.C. 4 50.0 % 519 486 Steckman Ridge LP 4 49.5 % 237 221 Texas Express Pipeline 6 35.0 % — 430 Vector Pipeline L.P. 60.0 % 198 169 Other 4 33.3% - 50.0% 6 34 Gas Distribution Noverco Common Shares 38.9 % — — Other 4 50.0 % 15 15 Green Power and Transmission Eolien Maritime France SAS 50.0 % 68 69 Enbridge Renewable Infrastructure Investments S.a.r.l. 7 25.5 % 127 763 Rampion Offshore Wind Project 24.9 % 638 555 Other 19.0% - 50.0% 72 95 Eliminations and Other Other 19.0% - 42.7% 10 26 OTHER LONG-TERM INVESTMENTS Gas Distribution Noverco Preferred Shares 478 371 Green Power and Transmission Emerging Technologies and Other 80 80 Eliminations and Other Other 110 67 16,707 16,644 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 20 - 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 8) . 5 On February 27, 2017, we acquired Spectra Energy's consolidated interest in Sabal Trail as part of the Merger Transaction (Note 8) . 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 August 1, 2018 the sale of Midcoast Operating, L.P. and its subsidiaries closed. Upon closing of the sale, our interest in the Texas Express NGL pipeline system was sold along with the MOLP assets. The carrying value of $447 million of our equity method investment in the Texas Express NGL pipeline system was included within the disposal group of the transaction. For further details on the sale transaction please refer to Note 8 - Acquisitions and Dispositions . 7 On February 8, 2017 , we acquired an effective 50% interest in EnBW Hohe See GmbH & Co. KG. On August 1, 2018 we transferred our interest in the Hohe See Offshore wind facilities and its subsequent expansion to a newly formed entity, ERII. Subsequently, we sold a 49% interest in ERII to CPPIB, reducing our interest in the project to 25.5% . 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, 2018 , this comprised of $2.2 billion in Goodwill and $706 million in amortizable assets. As at December 31, 2017 , this comprised of $2.0 billion in Goodwill and $643 million in amortizable assets. For the years ended December 31, 2018 , 2017 and 2016 , dividends received from equity investments were $2.8 billion , $1.4 billion and $825 million , respectively. Summarized combined financial information of our interest in unconsolidated equity investments (presented at 100%) is as follows: Year Ended December 31, 2018 2017 2016 Seaway Other Total Seaway Other Total Seaway Other Total (millions of Canadian dollars) Operating revenues 966 18,251 19,217 959 15,254 16,213 938 3,164 4,102 Operating expenses 212 15,422 15,634 286 12,911 13,197 293 3,051 3,344 Earnings/(loss) 646 2,308 2,954 672 2,056 2,728 643 (2 ) 641 Earnings attributable to controlling interests 323 1,059 1,382 336 926 1,262 322 147 469 December 31, 2018 December 31, 2017 Seaway Other Total Seaway Other Total (millions of Canadian dollars) Current assets 113 3,176 3,289 106 3,432 3,538 Non-current assets 3,585 45,531 49,116 3,329 41,697 45,026 Current liabilities 123 5,413 5,536 143 3,311 3,454 Non-current liabilities 16 15,859 15,875 13 13,582 13,595 Noncontrolling interests — 3,479 3,479 — 3,191 3,191 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 became 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, 2018 and 2017 , 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, 2018 and 2017 , Noverco owned an approximate 1.4% and 1.9% reciprocal shareholding in our common shares, respectively. Noverco sold 4.4 million common shares in December 2018 and purchased 1.2 million common shares in February 2016. Shares purchased and sold 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, 2018 and 2017 , we had an indirect pro-rata interest of 0.5% and 0.7% , respectively, in our own shares. Both the equity investment in Noverco and shareholders’ equity have been reduced by the reciprocal shareholding of $88 million and $102 million as at December 31, 2018 and 2017 . 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, 2018
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, 2018 and 2017 , we had restricted long-term investments held in trust and classified as available for sale or held to maturity of $323 million and $267 million , respectively. We had estimated future abandonment costs related to LMCI of $212 million and $151 million as at December 31, 2018 and 2017 , respectively.

INTANGIBLE ASSETS

INTANGIBLE ASSETS	12 Months Ended
	Dec. 31, 2018
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, 2018 1 Amortization Rate Cost Amortization Net (millions of Canadian dollars) Customer relationships 5.0 % 762 70 692 Power purchase agreements 4.4 % 96 21 75 Project agreement 2 4.0 % 164 10 154 Software 11.4 % 1,827 814 1,013 Other intangible assets 4.1 % 508 70 438 3,357 985 2,372 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, 2018 and December 31, 2017 (Note 8) . 2 Represents a project agreement acquired from the Merger Transaction (Note 8) . 3 The measurement of weighted average amortization rate excludes non-depreciable intangible assets. For the years ended December 31, 2018 , 2017 and 2016 , our amortization expense related to intangible assets totaled $281 million , $280 million and $177 million , respectively. The following table presents our forecast of amortization expense associated with existing intangible assets for the years indicated as follows: 2019 2020 2021 2022 2023 Forecast of amortization expense (millions of Canadian dollars) 278 251 227 205 186

GOODWILL

GOODWILL	12 Months Ended
	Dec. 31, 2018
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, 2017 59 457 7 — 2 13 538 Acquired in Merger Transaction (Note 8) 8,070 22,914 5,672 — — — 36,656 Sabal Trail deconsolidation (Note 13) — (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 Disposition — (628 ) — — — — (628 ) Allocation to assets held for sale — (55 ) (133 ) — — — (188 ) Foreign exchange and other 538 1,482 (183 ) — — — 1,837 Balance at December 31, 2018 8,324 22,338 5,363 — 2 13 36,040 Accumulated Impairment Balance at January 1, 2017 — (440 ) (7 ) — — (13 ) (460 ) Impairment — (102 ) — — — — (102 ) Balance at December 31, 2017 — (542 ) (7 ) — — (13 ) (562 ) Impairment — (1,019 ) — — — — (1,019 ) Balance at December 31, 2018 — (1,561 ) (7 ) — — (13 ) (1,581 ) Carrying Value Balance at December 31, 2017 7,786 20,997 5,672 — 2 — 34,457 Balance at December 31, 2018 8,324 20,777 5,356 — 2 — 34,459 IMPAIRMENT Gas Transmission and Midstream Canadian Natural Gas Gathering and Processing Businesses During the year ended December 31, 2018, we recorded a goodwill impairment charge of $1,019 million related to our Canadian Natural Gas Gathering and Processing Businesses assets which were classified as held for sale in the third quarter. The provincially regulated assets were subsequently sold in the fourth quarter ( Note 8 ). As these assets represented a portion of a reporting unit, we allocated a portion of the goodwill of the reporting unit to these assets using a relative fair value approach. In connection with the write-down of the carrying values of the assets held for sale to its sale price consideration less costs to sell, the related goodwill was impaired. We also performed a goodwill impairment test for the related reporting unit resulting in no additional impairment charge. 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 8 ) . 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. DISPOSITIONS In 2018 , we derecognized $262 million of goodwill on the disposition of Midcoast Operating, L.P. and its subsidiaries and $366 million on the disposition of the provincially regulated facilities of our Canadian Natural Gas Gathering and Processing Business ( Note 8 ) . In 2017 , we derecognized $29 million of goodwill on the disposition of Olympic Pipeline ( Note 8 ) . ASSETS HELD FOR SALE As at December 31, 2018, the net assets of the federally regulated facilities of our Canadian Natural Gas Gathering and Processing Business remain classified as held for sale, including $55 million of allocated goodwill. In addition, as at December 31, 2018, the net assets of EGNB were also classified as held for sale, including $133 million of allocated goodwill. ACQUISITIONS In 2017, we recognized $36.7 billion of goodwill on the Merger Transaction ( Note 8 ) .

ACCOUNTS PAYABLE AND OTHER

ACCOUNTS PAYABLE AND OTHER	12 Months Ended
	Dec. 31, 2018
Payables and Accruals [Abstract]
ACCOUNTS PAYABLE AND OTHER	ACCOUNTS PAYABLE AND OTHER December 31, 2018 2017 (millions of Canadian dollars) Trade payables and operating accrued liabilities 4,604 5,135 Construction payables and contractor holdbacks 804 706 Current derivative liabilities 1,234 1,130 Dividends payable 1,539 1,169 Taxes payable 801 522 Other 854 816 9,836 9,478

DEBT

DEBT	12 Months Ended
	Dec. 31, 2018
Debt Disclosure [Abstract]
DEBT	DEBT Weighted Average December 31, Interest Rate Maturity 2018 2017 (millions of Canadian dollars) Enbridge Inc. United States dollar term notes 1 4.1 % 2022-2046 6,419 5,889 Medium-term notes 2 4.3 % 2019-2064 7,323 5,698 Fixed-to-floating subordinated term notes 3,4 5.9 % 2077-2078 6,771 3,843 Floating rate notes 5 2019-2020 2,389 2,254 Commercial paper and credit facility draws 6 2.2 % 2019-2023 1,999 2,729 Other 7 — 3 Enbridge (U.S.) Inc. Commercial paper and credit facility draws 8 3.5 % 2020 1,065 490 Enbridge Energy Partners, L.P. Senior notes 9 6.2 % 2019-2045 6,214 6,328 Junior subordinated notes 10 2067 546 501 Commercial paper and credit facility draws 11 3.3 % 2022 1,044 1,820 Enbridge Gas Distribution Inc. Medium-term notes 4.5 % 2020-2050 3,695 3,695 Debentures 9.9 % 2024 85 85 Commercial paper and credit facility draws 2.3 % 2020 750 960 Enbridge Income Fund Medium-term notes 2 — 1,750 Commercial paper and credit facility draws — 755 Enbridge Pipelines (Southern Lights) L.L.C. Senior notes 12 4.0 % 2040 1,257 1,207 Enbridge Pipelines Inc. Medium-term notes 13 4.3 % 2019-2046 4,225 4,525 Debentures 8.2 % 2024 200 200 Commercial paper and credit facility draws 14 2.4 % 2020 2,200 1,438 Other 7 4 4 Enbridge Southern Lights LP Senior notes 4.0 % 2040 289 315 Midcoast Energy Partners, L.P. Senior notes 15 — 501 Spectra Energy Capital 16 Senior notes 17 7.1 % 2032-2038 236 1,665 Spectra Energy Partners, LP 16 Senior secured notes 18 6.1 % 2020 150 138 Senior notes 19 4.3 % 2020-2048 8,249 7,192 Floating rate notes 20 2020 546 501 Commercial paper and credit facility draws 21 3.2 % 2022 2,065 2,824 Union Gas Limited 16 Medium-term notes 4.1 % 2021-2047 3,290 3,490 Senior debentures — 75 Debentures 8.7 % 2025 125 250 Commercial paper and credit facility draws 2.3 % 2021 275 485 Westcoast Energy Inc. 16 Senior secured notes 6.2 % 2019 33 66 Medium-term notes 4.7 % 2019-2041 2,175 2,177 Debentures 8.6 % 2020-2026 375 525 Fair value adjustment - Spectra Energy acquisition 964 1,114 Other 22 (348 ) (312 ) Total debt 64,610 65,180 Current maturities (3,259 ) (2,871 ) Short-term borrowings 23 (1,024 ) (1,444 ) Long-term debt 60,327 60,865 1 2018 - US $4,700 million ; 2017 - US $4,700 million . 2 On December 21, 2018, Enbridge and Enbridge Income Fund (the Fund) completed a transaction to exchange certain series of the Fund's outstanding medium-term notes (Legacy Fund Notes) for an equal principal amount of newly issued medium term notes of Enbridge, having financial terms that are the same as the financial terms of the Fund Notes. See Debt Exchange discussion below. 3 2018 - $2,400 million and US $3,200 million ; 2017 - $1,650 million and US $1,750 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. 4 The notes would be converted automatically into Conversion Preference Shares in the event of bankruptcy and related events. 5 2018 - $750 million and US $1,200 million ; 2017 - $750 million and US $1,200 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. 6 2018 - $1,906 million and US $69 million ; 2017 - $1,593 million and US $907 million . 7 Primarily capital lease obligations. 8 2018 - US $780 million ; 2017 - US $391 million . 9 2018 - US $4,550 million ; 2017 - US $5,050 million . 10 2018 - US $400 million ; 2017 - US $400 million . Carries an interest rate equal to the three-month LIBOR plus a margin of 379.75 basis points. 11 2018 - US $764 million ; 2017 - US $1,453 million . 12 2018 - US $920 million ; 2017 - US $963 million . 13 Included in medium-term notes is $100 million with a maturity date of 2112. 14 2018 - $1,905 million and US $216 million ; 2017 - $1,080 million and US $286 million . 15 2017 - US $400 million . 16 Debt acquired in conjunction with the Merger Transaction (Note 8) . 17 2018 - US $173 million ; 2017 - US $1,329 million . 18 2018 - US $110 million ; 2017 - US $110 million . 19 2018 - US $6,040 million ; 2017 - US $5,740 million . 20 2018 - US $400 million ; 2017 - US $400 million . Carries an interest rate equal to the three-month LIBOR plus a margin of 70 basis points. 21 2018 - US $1,512 million ; 2017 - US $2,254 million . 22 Primarily debt discount and debt issue costs. 23 Weighted average interest rate - 2.3% ; 2017 - 1.4% . SECURED DEBT Senior secured notes, totaling $183 million as at December 31, 2018 , 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, 2018 : 2018 Total December 31, Maturity Facilities Draws 1 Available (millions of Canadian dollars) Enbridge Inc. 2019-2023 5,751 2,008 3,743 Enbridge (U.S.) Inc. 2020 1,932 1,065 867 Enbridge Energy Partners, L.P. 2 2022 2,493 1,044 1,449 Enbridge Gas Distribution Inc. 2019-2020 1,018 760 258 Enbridge Pipelines Inc. 2020 3,000 2,200 800 Spectra Energy Partners, LP 3,4 2022 3,414 2,065 1,349 Union Gas Limited 4 2021 700 275 425 Total committed credit facilities 18,308 9,417 8,891 1 Includes facility draws, letters of credit and commercial paper issuances that are back-stopped by the credit facility. 2 Includes $253 million (US$185 million) of facilities that expire in 2020. 3 Includes $459 million (US$336 million) of facilities that expire in 2021. 4 Committed credit facilities acquired in conjunction with the Merger Transaction (Note 8) . Enbridge terminated a US$650 million credit facility, which was scheduled to mature in 2019 , and repaid drawn amounts. In addition, an unutilized Enbridge US$100 million credit facility expired. Enbridge (U.S.) Inc. terminated an unutilized US$950 million credit facility, which was scheduled to mature in 2019 . In addition, Enbridge (U.S.) Inc. terminated a US$500 million credit facility, which was scheduled to mature in 2019 , and repaid drawn amounts. An unutilized EEP US$625 million credit facility matured on December 31, 2018 . Enbridge Income Fund substantially terminated its $1,500 million credit facility, which was scheduled to mature in 2020 , and repaid drawn amounts. Westcoast Energy Inc. terminated an unutilized $400 million credit facility, which was scheduled to mature in 2021 . The facility was acquired in conjunction with the Merger Transaction. On February 7, 2019 and February 8, 2019, we terminated certain Canadian and United States dollar credit facilities, including facilities held by Enbridge, Union Gas, EEP and SEP. We also increased existing facilities or obtained new facilities to replace the terminated ones under Enbridge, Enbridge (U.S.) Inc. and EGI. As a result, our total credit facility availability increased by approximately $390 million Canadian dollar equivalent, when translated using the year end December 31, 2018 spot rate . In addition to the committed credit facilities noted above, we have $807 million of uncommitted demand credit facilities, of which $548 million were unutilized as at December 31, 2018 . As at December 31, 2017 , we had $792 million of uncommitted credit facilities, of which $518 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 2020 to 2023 . As at December 31, 2018 and 2017 , commercial paper and credit facility draws, net of short-term borrowings and non-revolving credit facilities that mature within one year of $7,967 million and $10,055 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 2018 and 2017 , excluding the debt exchange discussed below: Company Issue Date Principal Amount (millions of Canadian dollars unless otherwise stated) Enbridge Inc. March 2018 Fixed-to-floating rate subordinated notes due March 2078 1 US$850 April 2018 Fixed-to-floating rate subordinated notes due April 2078 2 $750 April 2018 Fixed-to-floating rate subordinated notes due April 2078 3 US$600 May 2017 Floating rate notes due May 2019 4 $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 5 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 6 US$1,000 September 2017 Fixed-to-floating rate subordinated notes due September 2077 7 $1,000 October 2017 Fixed-to-floating rate subordinated notes due September 2077 7 $650 October 2017 Floating rate notes due January 2020 8 US$700 Enbridge Gas Distribution Inc. November 2017 3.51% medium-term notes due November 2047 $300 Spectra Energy Partners, LP January 2018 3.50% senior notes due January 2028 9 US$400 January 2018 4.15% senior notes due January 2048 9 US$400 June 2017 Floating rate notes due June 2020 10 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 Notes mature in 60 years and are callable on or after year 10 . For the initial 10 years , the notes carry a fixed interest rate of 6.25% . Subsequently, the interest rate will be set to equal the three-month LIBOR plus a margin of 364 basis points from years 10 to 30 , and a margin of 439 basis points from years 30 to 60 . 2 Notes mature in 60 years and are callable on or after year 10 . For the initial 10 years , the notes carry a fixed interest rate of 6.625% . Subsequently, the interest rate will be set to equal the Canadian Dollar Offered Rate plus a margin of 432 basis points from years 10 to 30 , and a margin of 507 basis points from years 30 to 60 . 3 Notes mature in 60 years and are callable on or after year five . For the initial five years , the notes carry a fixed interest rate of 6.375% . Subsequently, the interest rate will be set to equal the three-month LIBOR plus a margin of 359 basis points from years five to 10 , a margin of 384 basis points from years 10 to 25 , and a margin of 459 basis points from years 25 to 60 . 4 Carries an interest rate equal to the three-month Bankers' Acceptance Rate plus 59 basis points. 5 Carries an interest rate equal to the three-month LIBOR plus 70 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 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 . 7 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 . 8 Carries an interest rate equal to the three-month LIBOR plus 40 basis points. 9 Issued through Texas Eastern Transmission, L.P. (Texas Eastern), a wholly-owned operating subsidiary of SEP. 10 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 2018 and 2017 , excluding the debt exchange discussed below: Company Retirement/Repayment Date Principal Amount Cash Consideration 1 (millions of Canadian dollars unless otherwise stated) Enbridge Inc. March 2017 Floating rate notes $500 April 2017 5.60% medium-term notes US$400 June 2017 Floating rate notes US$500 Enbridge Energy Partners, L.P. April 2018 6.50% senior notes US$400 October 2018 7.00% senior notes US$100 Enbridge Gas Distribution Inc. April 2017 1.85% medium-term notes $300 December 2017 5.16% medium-term notes $200 Enbridge Income Fund December 2018 4.00% medium-term notes $125 June 2017 5.00% medium-term notes $100 December 2017 2.92% medium-term notes $225 Enbridge Pipelines (Southern Lights) L.L.C. June and December 2018 3.98% medium-term notes due June 2040 US$43 June and December 2017 3.98% medium-term note due June 2040 US$37 Enbridge Pipelines Inc. November 2018 6.62% medium-term notes $170 November 2018 6.62% medium-term notes $130 Enbridge Southern Lights LP January, July and December 2018 4.01% medium-term notes due June 2040 $27 June 2017 4.01% medium-term notes due June 2040 $7 Midcoast Energy Partners, L.P. Redemption July 2018 2 3.56% senior notes due September 2019 US$75 US$76 July 2018 2 4.04% senior notes due September 2021 US$175 US$182 July 2018 2 4.42% senior notes due September 2024 US$150 US$161 Spectra Energy Capital, LLC Repurchase via Tender Offer March 2018 2 6.75% senior unsecured notes due 2032 US$64 US$80 March 2018 2 7.50% senior unsecured notes due 2038 US$43 US$59 July 2017 3 Senior notes carrying interest ranging from 3.3% to 7.5% due 2018 to 2038 US$761 US$857 Redemption March 2018 2 5.65% senior unsecured notes due 2020 US$163 US$172 March 2018 2 3.30% senior unsecured notes due 2023 US$498 US$508 July and September 2017 3 8.00% senior notes due 2019 US$500 US$581 Repayment April 2018 6.20% senior notes US$272 July 2018 6.75% senior notes US$118 Spectra Energy Partners, LP September 2018 2.95% senior notes US$500 September 2017 6.00% senior notes US$400 June and December 2017 7.39% subordinated secured notes US$12 Union Gas Limited April 2018 5.35% medium-term notes $200 August 2018 8.75% debentures $125 October 2018 8.65% senior debentures $75 November 2017 9.70% debentures $125 Westcoast Energy Inc. May and November 2018 6.90% senior secured notes due 2019 $26 May and November 2018 4.34% senior secured notes due 2019 $9 September 2018 8.50% debenture $150 May and November 2017 6.90% senior secured notes due 2019 $26 May and November 2017 4.34% senior secured notes due 2019 $24 1 Cash consideration disclosed for repayments where the cash paid differs from the principal amount. 2 The loss on debt extinguishment of $64 million (US $50 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. 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 EXCHANGE On December 21, 2018, Enbridge and the Fund completed a transaction to exchange certain series of the Legacy Fund Notes for an equal principal amount of newly issued medium term notes of Enbridge (Enbridge Notes), having financial terms that are the same as the financial terms of the Fund Notes. The following Enbridge Notes were issued in exchange for the previously held Fund Notes: • Enbridge 4.10% medium-term notes, due February 22, 2019 issued in exchange for Fund 4.10% medium-term notes, due February 22, 2019 with a principal amount of $300 million ; • Enbridge 4.85% medium-term notes, due November 12, 2020 issued in exchange for Fund 4.85% medium-term notes, due November 12, 2020 with a principal amount of $100 million ; • Enbridge 4.85% medium-term notes, due February 22, 2022 issued in exchange for Fund 4.85% medium-term notes, due February 22, 2022 with a principal amount of $200 million ; • Enbridge 3.94% medium-term notes, due January 13, 2023 issued in exchange for Fund 3.94% medium-term notes, due January 13, 2023 with a principal amount of $275 million ; • Enbridge 3.95% medium-term notes, due November 19, 2024 issued in exchange for Fund 3.95% medium-term notes, due November 19, 2024 with a principal amount of $500 million ; and • Enbridge 4.87% medium-term notes, due November 21, 2044 issued in exchange for Fund 4.87% medium-term notes, due November 21, 2044 with a principal amount of $250 million . 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, 2018 , we were in compliance with all debt covenants. INTEREST EXPENSE Year ended December 31, 2018 2017 2016 (millions of Canadian dollars) Debentures and term notes 3,011 3,011 1,714 Commercial paper and credit facility draws 171 206 197 Amortization of fair value adjustment - Spectra Energy acquisition (131 ) (270 ) — Capitalized (348 ) (391 ) (321 ) 2,703 2,556 1,590

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS	12 Months Ended
	Dec. 31, 2018
Asset Retirement Obligation Disclosure [Abstract]
ASSET RETIREMENT OBLIGATIONS	ASSET RETIREMENT OBLIGATIONS Our ARO relate mostly to the retirement of pipelines, renewable power generation assets, obligations related to right-of way agreements and contractual leases for land use. The liability for the expected cash flows as recognized in the financial statements reflected discount rates ranging from 1.8% to 9.0% . A reconciliation of movements in our ARO liabilities is as follows: December 31, 2018 2017 (millions of Canadian dollars) Obligations at beginning of year 793 232 Liabilities acquired — 546 Liabilities disposed (13 ) — Liabilities incurred 145 — Liabilities settled (21 ) (22 ) Change in estimate 29 18 Foreign currency translation adjustment 22 (12 ) Accretion expense 34 31 Obligations at end of year 989 793 Presented as follows: Accounts payable and other 6 2 Other long-term liabilities 983 791 989 793

NONCONTROLLING INTERESTS

NONCONTROLLING INTERESTS	12 Months Ended
	Dec. 31, 2018
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, 2018 2017 (millions of Canadian dollars) Algonquin Gas Transmission, L.L.C 1 518 476 Enbridge Energy Management, L.L.C. 2 — 34 Enbridge Energy Partners, L.P. 3 — 138 Enbridge Gas Distribution Inc. 4 — 100 Maritimes & Northeast Pipeline, L.L.C 1 613 572 Renewable energy assets 5 1,961 806 Spectra Energy Partners, LP 6 — 4,335 Union Gas Limited 7 — 110 Westcoast Energy Inc. 8 841 1,005 Other 9 32 21 3,965 7,597 1 Represents subsidiaries of SEP and the interests in these subsidiaries held by third parties. 2 On December 20, 2018, we executed the definitive agreement with EEM and acquired all of the publicly held shares of EEM not already owned by us or our subsidiaries. As at December 31, 2017 , the balance represented 88.3% interest in EEM held by public shareholders. 3 On December 20, 2018, we executed the definitive agreement with EEP and acquired all of the publicly held Class A common units of EEP not already owned by us or our subsidiaries. As at December 31, 2017 , the balance represented 68.2% interest in EEP held by public unitholders. 4 On November 29, 2018, EGD redeemed all of its four million cumulative redeemable preferred shares held by third parties. As at December 31, 2017 , the balance of these preferred shares was $100 million . 5 On August 1, 2018, we closed the sale of 49% of our interest in the Renewable Assets (Note 8) . The remaining balance represents the tax equity investors' interests in Magic Valley, Wildcat, Keechi, New Creek and Chapman Ranch wind facilities, which are accounted for using the HLBV method, with an additional 20.0% noncontrolling interest in each of the Magic Valley and Wildcat wind facilities held by third parties as at December 31, 2018 and 2017 . 6 On December 17, 2018, we closed the definitive agreement with SEP and acquired all of the publicly listed common units of SEP not already owned by us or our subsidiaries. As at December 31, 2017 , the balance represented 25.7% interest in SEP held by public unitholders. 7 On November 29, 2018, Union Gas redeemed all of its four million cumulative redeemable preferred shares held by third parties. As at December 31, 2017 , the balance of these preferred shares was $110 million . 8 Represents the 16.6 million cumulative redeemable preferred shares and 12 million cumulative first preferred shares as at December 31, 2018 and 2017 held by third parties in Westcoast Energy Inc., and the 22.0% interest in Maritimes & Northeast Pipeline Limited Partnership held by third parties as at December 31, 2018 and 2017. 9 Represents subsidiary of EEP and the interests in this subsidiary held by third parties. United States Sponsored Vehicles Buy-in On August 24, 2018, we entered into a definitive agreement with SEP under which we agreed to acquire all of the outstanding public common units of SEP not already owned by us or our subsidiaries on the basis of 1.111 of our common shares for each common unit of SEP. Upon the closing of the transaction on December 17, 2018, we acquired all of the public common units of SEP and SEP became an indirect, wholly-owned subsidiary of Enbridge. The transaction is valued at $3.9 billion based on the closing price of our common shares on the New York Stock Exchange on December 14, 2018. As a result of this buy-in, we recorded a decrease in Noncontrolling interests, Additional paid-in capital and Deferred income tax liabilities of $3.0 billion , $642 million and $167 million , respectively. On September 17, 2018, we entered into definitive agreements with each of EEP and EEM under which we agreed to acquire all of the outstanding public class A common units of EEP and all of the outstanding public listed shares of EEM not already owned by us or our subsidiaries. Under the agreements, EEP public unitholders will receive 0.335 of our common shares for each class A common unit of EEP, and EEM public shareholders will receive 0.335 of our common shares for each listed share of EEM. Upon the closing of the respective transactions on December 20, 2018, we acquired all of the public Class A common units of EEP and shares of EEM, and both EEP and EEM became indirect, wholly-owned subsidiaries of Enbridge. The EEP and EEM transactions are valued at $3.0 billion and $1.3 billion , respectively, based on the closing price of our common shares on the New York Stock Exchange on December 19, 2018. As a result of the buy-ins, collectedly for EEP and EEM, we recorded an increase in Noncontrolling interests and a decrease in Additional paid-in capital and Deferred income tax liabilities of $185 million , $3.7 billion and $707 million , respectively. For discussion on the roll-up of ENF, refer to Canadian Sponsored Vehicles Buy-in under Redeemable Noncontrolling Interests below. Renewable Assets On August 1, 2018, we closed the sale of a 49% interest in all of our Canadian renewable assets and a 49% interest in two United States renewable assets to CPPIB (Note 8) . As a result, we recorded an increase in Noncontrolling interests, Additional paid-in capital and Deferred income tax liabilities of $1,183 million , $79 million and $27 million , respectively, in the third quarter of 2018. For 2018, CPPIB's distributions and allocation of earnings were not proportionate to its ownership. SEP Incentive Distribution Rights As at December 31, 2017, we collectively owned a 75% ownership interest in SEP, together with 100% of SEP's incentive distribution rights (IDRs). On January 22, 2018, Enbridge and SEP announced the execution of a definitive agreement, resulting in us converting all of our 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 were eliminated. In the first quarter of 2018, we held a non-economic general partner interest in SEP and owned approximately 403 million SEP common units, representing approximately 83% of SEP's outstanding common units. As a result of this restructuring, we recorded a decrease in Noncontrolling interests of $1.5 billion and increases in Additional paid-in capital and Deferred income tax liabilities of $1.1 billion and $333 million , respectively. Subsequently in 2018, we acquired all of the outstanding common units of SEP (refer to United States Sponsored Vehicles Buy-in above). 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 MEP 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 was owned by us and subsequently sold on August 1, 2018 (see Note 8 - Acquisitions and Dispositions for further details). 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. 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, 2018 2017 2016 (millions of Canadian dollars) Balance at beginning of year 4,067 3,392 2,141 Earnings attributable to redeemable noncontrolling interests 117 175 268 Other comprehensive income/(loss), net of tax Change in unrealized loss on cash flow hedges 3 (21 ) (17 ) Other comprehensive loss from equity investees 14 — — Reclassification to earnings of loss on cash flow hedges — 57 9 Foreign currency translation adjustments 4 (6 ) (3 ) Other comprehensive income/(loss), net of tax 21 30 (11 ) Distributions to unitholders (300 ) (247 ) (202 ) Contributions from unitholders 70 1,178 591 Modified retrospective adoption of accounting standard (note 3) (38 ) — — Net dilution gain/(loss) 76 (169 ) (81 ) Redemption value adjustment 456 (292 ) 686 Sponsored vehicle buy-in 1 (4,469 ) — — Balance at end of year — 4,067 3,392 1. On November 8, 2018, we executed the definitive agreement with ENF and acquired all of the publicly held shares of ENF not already owned by us or our subsidiaries. Canadian Sponsored Vehicle Buy-in On September 17, 2018, we entered into a definitive agreement with ENF under which we would acquire all of the outstanding public common shares of ENF not already owned by us or our subsidiaries on the basis of 0.735 of our common shares and cash of $0.45 for each common share of ENF. Upon the closing of the transaction on November 8, 2018, we acquired all of the public common shares of ENF and ENF become a wholly-owned subsidiary of Enbridge. The transaction, excluding the cash component, is valued at $4.5 billion based on the closing price of our common shares on the Toronto Stock Exchange on November 7, 2018. As a result of this buy-in, we recorded a decrease in Redeemable noncontrolling interests and Additional paid-in capital of $4.5 billion and $25 million , respectively, with nil deferred tax impact. As at December 31, 2017 and 2016 , Redeemable Noncontrolling Interest represented 56.5% and 45.6% , respectively, of interests in the Fund’s trust units that are held by third parties.

SHARE CAPITAL

SHARE CAPITAL	12 Months Ended
	Dec. 31, 2018
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 2018 2017 2016 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 1,695 50,737 943 10,492 868 7,391 Common shares issued 1 — — 33 1,500 56 2,241 Common shares issued in Merger Transaction (Note 8) — — 691 37,429 — — Common shares issued in Sponsored Vehicle buy-in (SEP) (Note 20) 91 3,888 — — — — Common shares issued in Sponsored Vehicle buy-in (EEP) (Note 20) 72 3,042 — — — — Common shares issued in Sponsored Vehicle buy-in (EEM) (Note 20) 30 1,267 — — — — Common shares issued in Sponsored Vehicle buy-in (ENF) (Note 20) 104 4,530 — — — — Dividend Reinvestment and Share Purchase Plan 28 1,181 25 1,226 16 795 Shares issued on exercise of stock options 2 32 3 90 3 65 Balance at end of year 2,022 64,677 1,695 50,737 943 10,492 1 Gross proceeds of nil , $1.5 billion and $2.3 billion for the years ended December 31, 2018 , 2017 and 2016 , respectively; net issuance costs of nil , nil and $59 million for the years ended December 31, 2018 , 2017 and 2016 , respectively. PREFERENCE SHARES 2018 2017 2016 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 18 457 20 500 Preference Shares, Series C 2 43 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 30 750 Preference Shares, Series 19 20 500 20 500 — — Issuance costs (155 ) (155 ) (147 ) Balance at end of year 7,747 7,747 7,255 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 3.42 % $0.85360 $25 June 1, 2022 Series C Preference Shares, Series C 5 3-month treasury bill plus 2.40% — $25 June 1, 2022 Series B Preference Shares, Series D 6 4.46 % $1.11500 $25 March 1, 2023 Series E Preference Shares, Series F 6 4.69 % $1.17225 $25 June 1, 2023 Series G Preference Shares, Series H 6 4.38 % $1.09400 $25 September 1, 2023 Series I Preference Shares, Series J 4.89 % US$1.22160 US$25 June 1, 2022 Series K Preference Shares, Series L 4.96 % US$1.23972 US$25 September 1, 2022 Series M Preference Shares, Series N 6 5.09 % $1.27150 $25 December 1, 2023 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 6 5.95 % US$1.48728 US$25 June 1, 2023 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 The floating quarterly dividend amount for the Series C Preference Shares was increased to $0.22685 from $0.20342 on March 1, 2018, was increased to $0.22748 from $0.22685 on June 1, 2018, was increased to $0.23934 from $0.22748 on September 1, 2018 and was increased to $0.25459 from $0.23934 on December 1, 2018, due to reset on a quarterly basis following the issuance thereof. 6 No Series D, F, H, N, or 1 Preference shares were converted on the March 1, 2018, June 1, 2018, September 1, 2018, December 1, 2018 or June 1, 2018 conversion option dates, respectively. However, the quarterly dividend amounts for Series D, F, H, N, and 1, were increased to $0.27875 from $0.25000 on March 1, 2018, $0.29306 from $0.25000 on June 1, 2018, $0.27350 from $0.25000 on September 1, 2018, $0.31788 from $0.25000 on December 1, 2018 and US $0.37182 from US $0.25000 on June 1, 2018, respectively, due to reset on every fifth anniversary thereafter. DIVIDEND REINVESTMENT AND SHARE PURCHASE PLAN On November 2, 2018, we announced the suspension of our DRIP, effective immediately. Prior to the announcement, our shareholders were able to participate in the DRIP, which enabled participants to reinvest their dividends in our common shares at a 2% discount to market price and to make additional optional cash payments to purchase common shares at the market price, free of brokerage or other charges. Refer to Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Share Issuances for details on dividends paid. 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, 2018
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 17 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 8) . Total stock-based compensation expense recorded for the years ended December 31, 2018 , 2017 and 2016 was $106 million , $165 million and $130 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, 2018 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 34,366 45.41 Options granted 5,775 32.32 Options exercised 1 (2,519 ) 27.11 Options cancelled or expired (3,235 ) 44.11 Options outstanding at end of year 34,387 43.47 6.1 108 Options vested at end of year 2 21,064 43.48 4.7 84 1 The total intrinsic value of ISOs exercised during the years ended December 31, 2018 , 2017 and 2016 was $42 million , $62 million and $123 million , respectively, and cash received on exercise was $15 million , $17 million and $37 million , respectively. 2 The total fair value of ISOs vested during the years ended December 31, 2018 , 2017 and 2016 was $36 million , $44 million and $36 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, 2018 2017 2016 Fair value per option (Canadian dollars) 1 3.86 6.00 7.37 Valuation assumptions Expected option term (years) 2 5 5 5 Expected volatility 3 21.9 % 20.4 % 25.1 % Expected dividend yield 4 6.4 % 4.4 % 4.4 % Risk-free interest rate 5 2.2 % 1.2 % 0.8 % 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, 2018 , 2017 and 2016 were $3.75 , $5.66 and $7.01 , respectively, for Canadian employees and US $3.30 , US $5.72 and US $6.60 , 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, 2018 , 2017 and 2016 for ISOs was $28 million , $40 million and $43 million , respectively. As at December 31, 2018 , unrecognized compensation expense related to non-vested stock-based compensation arrangements granted under the ISO Plan was $23 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 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, 2018 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 1,693 Units granted 542 Units cancelled (191 ) Units matured 1 (971 ) Dividend reinvestment 140 Units outstanding at end of year 1,213 1.3 52 1 The total amount paid during the years ended December 31, 2018 , 2017 and 2016 for RSUs was $41 million , $39 million and $56 million , respectively. Compensation expense recorded for the years ended December 31, 2018 , 2017 and 2016 for RSUs was $32 million , $46 million and $51 million , respectively. As at December 31, 2018 , unrecognized compensation expense related to non-vested units granted under the RSU Plan was $26 million . The expense is expected to be fully recognized over a weighted average period of approximately two years .

COMPONENTS OF ACCUMULATED OTHER

COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS)	12 Months Ended
	Dec. 31, 2018
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, 2018 , 2017 and 2016 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, 2018 (644 ) (139 ) 77 10 (277 ) (973 ) Other comprehensive income/(loss) retained in AOCI (244 ) (509 ) 4,301 16 (85 ) 3,479 Other comprehensive (income)/loss reclassified to earnings Interest rate contracts 1 157 — — — — 157 Commodity contracts 2 (1 ) — — — — (1 ) Foreign exchange contracts 3 7 — — — — 7 Other contracts 4 22 — — — — 22 Amortization of pension and OPEB actuarial loss and prior service costs 5 — — — — 16 16 (59 ) (509 ) 4,301 16 (69 ) 3,680 Tax impact Income tax on amounts retained in AOCI 57 50 — 8 33 148 Income tax on amounts reclassified to earnings (37 ) — — — (4 ) (41 ) 20 50 — 8 29 107 Sponsored Vehicles buy-in 6 (87 ) — (55 ) — — (142 ) Balance at December 31, 2018 (770 ) (598 ) 4,323 34 (317 ) 2,672 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 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. 6 Represents the historical noncontrolling interests and redeemable noncontrolling interests related to the Sponsored Vehicles reclassified to AOCI, upon the completion of the buy-in.

RISK MANAGEMENT AND FINANCIAL I

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS	12 Months Ended
	Dec. 31, 2018
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 risks). 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 may be 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 2.8% . 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, when applicable, to hedge against future changes to the fair value of fixed rate debt which mitigates the impact of fluctuations in the fair value of fixed rate debt via execution of fixed to floating interest rate swaps . As of December 31, 2018, we do not have any pay floating-receive fixed interest rate swaps outstanding . 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 established 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 3.2% . We also monitor our debt portfolio mix of fixed and variable rate debt instruments to manage a consolidated portfolio of floating rate debt within the Board of Directors approved policy limit of a maximum of 30% of 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. 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 amounts in the event of these specific circumstances. All amounts are presented gross in the Consolidated Statements of Financial Position. December 31, 2018 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 — — — 47 47 (37 ) 10 Interest rate contracts 22 — — — 22 (2 ) 20 Commodity contracts 2 — — 427 429 (114 ) 315 24 — — 474 498 (153 ) 345 Deferred amounts and other assets Foreign exchange contracts 23 — — 39 62 (39 ) 23 Interest rate contracts 5 — — — 5 — 5 Commodity contracts 19 — — 33 52 (21 ) 31 47 — — 72 119 (60 ) 59 Accounts payable and other Foreign exchange contracts (5 ) — — (610 ) (615 ) 37 (578 ) Interest rate contracts (163 ) — — (178 ) (341 ) 2 (339 ) Commodity contracts — — — (273 ) (273 ) 114 (159 ) Other contracts (1 ) — — (4 ) (5 ) — (5 ) (169 ) — — (1,065 ) (1,234 ) 153 (1,081 ) Other long-term liabilities Foreign exchange contracts (1 ) (15 ) — (2,196 ) (2,212 ) 39 (2,173 ) Interest rate contracts (201 ) — — — (201 ) — (201 ) Commodity contracts — — — (178 ) (178 ) 21 (157 ) Other contracts (1 ) — — (1 ) (2 ) — (2 ) (203 ) (15 ) — (2,375 ) (2,593 ) 60 (2,533 ) Total net derivative asset/(liability) Foreign exchange contracts 17 (15 ) — (2,720 ) (2,718 ) — (2,718 ) Interest rate contracts (337 ) — — (178 ) (515 ) — (515 ) Commodity contracts 21 — — 9 30 — 30 Other contracts (2 ) — — (5 ) (7 ) — (7 ) (301 ) (15 ) — (2,894 ) (3,210 ) — (3,210 ) December 31, 2017 Derivative Derivative Derivative Instruments Used as Fair Value Hedges Non- Total Gross Amounts 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 ) The following table summarizes the maturity and notional principal or quantity outstanding related to our derivative instruments. 2018 2017 As at December 31, 2019 2020 2021 2022 2023 Thereafter Total Foreign exchange contracts - United States dollar forwards - purchase (millions of United States dollars) 925 1 — — — — 759 Foreign exchange contracts - United States dollar forwards - sell (millions of United States dollars) 4,969 4,893 3,608 1,944 1,804 1,857 16,167 Foreign exchange contracts - British pound (GBP) forwards - purchase (millions of GBP) — — — — — — 18 Foreign exchange contracts - GBP forwards - sell (millions of GBP) 89 25 27 28 29 120 318 Foreign exchange contracts - Euro forwards - purchase (millions of Euro) 226 — — — — — 655 Foreign exchange contracts - Euro forwards - sell (millions of Euro) — 23 94 94 92 606 1,262 Foreign exchange contracts - Japanese yen forwards - purchase (millions of yen) 32,662 — — 20,000 — — 52,662 Interest rate contracts - short-term pay fixed rate (millions of Canadian dollars) 8,616 6,243 4,188 412 49 156 7,138 Interest rate contracts - long-term receive fixed rate (millions of Canadian dollars) — — — — — — 4,196 Interest rate contracts - long-term pay fixed rate (millions of Canadian dollars) 3,777 3,185 1,596 — — — 5,402 Equity contracts (millions of Canadian dollars) 35 20 — — — — 90 Commodity contracts - natural gas (billions of cubic feet) (141 ) (16 ) (6 ) (4 ) — — (159 ) Commodity contracts - crude oil (millions of barrels) 4 — — — — — (3 ) Commodity contracts - NGL (millions of barrels) — — — — — — (12 ) Commodity contracts - power (megawatt per hour (MW/H)) 64 66 (3 ) (43 ) (43 ) (43 ) 1 (43 ) 2 1 As at December 31, 2018 , thereafter includes an average net purchase/(sell) of power of (43) MW/H for 2024 through 2025. 2 As at December 31, 2017, thereafter includes an average net purchase/(sell) of power of (43) MW/H for 2023 through 2025. The Effect of Derivative Instruments on the 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: 2018 2017 2016 (millions of Canadian dollars) Amount of unrealized gain/(loss) recognized in OCI Cash flow hedges Foreign exchange contracts 19 (5 ) (19 ) Interest rate contracts (190 ) 6 (90 ) Commodity contracts 2 11 14 Other contracts (3 ) 1 39 Net investment hedges Foreign exchange contracts 31 284 22 (141 ) 297 (34 ) Amount of (gain)/loss reclassified from AOCI to earnings (effective portion) Foreign exchange contracts 1 5 (104 ) 2 Interest rate contracts 2,3 161 388 145 Commodity contracts 4 (1 ) (9 ) (12 ) Other contracts 5 3 8 (29 ) 168 283 106 Amount of (gain)/loss reclassified from AOCI to earnings (ineffective portion and amount excluded from effectiveness testing) Interest rate contracts 2, 3 23 (4 ) 61 23 (4 ) 61 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 $18 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, 2018 . 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. Year ended December 31, 2018 2017 (millions of Canadian dollars) Unrealized gain/(loss) on derivative 7 (10 ) Unrealized gain/(loss) on hedged item 1 11 Realized gain/(loss) on derivative (8 ) 2 Realized gain/(loss) on hedged item (1 ) (2 ) 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, 2018 2017 2016 (millions of Canadian dollars) Foreign exchange contracts 1 (1,390 ) 1,284 935 Interest rate contracts 2 5 157 73 Commodity contracts 3 485 (199 ) (508 ) Other contracts 4 (3 ) — 9 Total unrealized derivative fair value gain/(loss), net (903 ) 1,242 509 1 For the respective annual periods, reported within Transportation and other services revenues ( 2018 - $1,108 million loss; 2017 - $800 million gain; 2016 - $497 million gain) and Other income/(expense) ( 2018 - $282 million loss; 2017 - $484 million gain; 2016 - $438 million gain) 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 ( 2018 - $66 million gain; 2017 - $104 million loss; 2016 - $52 million loss), Commodity sales ( 2018 - $599 million gain; 2017 - $90 million gain; 2016 - $474 million loss), Commodity costs ( 2018 - $193 million loss; 2017 - $223 million loss; 2016 - $38 million gain) and Operating and administrative expense ( 2018 - $13 million gain; 2017 - $38 million gain; 2016 - $20 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, 2018 . 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 strong investment grade credit ratings. Credit risk relating to derivative counterparties is mitigated through maintenance and monitoring of 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 credit concentrations and credit exposure, with respect to derivative instruments, in the following counterparty segments: December 31, 2018 2017 (millions of Canadian dollars) Canadian financial institutions 28 82 United States financial institutions 107 19 European financial institutions 84 145 Asian financial institutions 6 2 Other 1 337 137 562 385 1 Other is comprised of commodity clearing house and physical natural gas and crude oil counterparties. As at December 31, 2018 , 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, 2018 and December 31, 2017 . 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 30 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, 2018 Level 1 Level 2 Level 3 Total Gross Derivative Instruments (millions of Canadian dollars) Financial assets Current derivative assets Foreign exchange contracts — 47 — 47 Interest rate contracts — 22 — 22 Commodity contracts 24 45 360 429 24 114 360 498 Long-term derivative assets Foreign exchange contracts — 62 — 62 Interest rate contracts — 5 — 5 Commodity contracts — 30 22 52 — 97 22 119 Financial liabilities Current derivative liabilities Foreign exchange contracts — (615 ) — (615 ) Interest rate contracts — (341 ) — (341 ) Commodity contracts (7 ) (28 ) (238 ) (273 ) Other contracts — (5 ) — (5 ) (7 ) (989 ) (238 ) (1,234 ) Long-term derivative liabilities Foreign exchange contracts — (2,212 ) — (2,212 ) Interest rate contracts — (201 ) — (201 ) Commodity contracts — (23 ) (155 ) (178 ) Other contracts — (2 ) — (2 ) — (2,438 ) (155 ) (2,593 ) Total net financial asset/(liability) Foreign exchange contracts — (2,718 ) — (2,718 ) Interest rate contracts — (515 ) — (515 ) Commodity contracts 17 24 (11 ) 30 Other contracts — (7 ) — (7 ) 17 (3,216 ) (11 ) (3,210 ) 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 ) The significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments were as follows: December 31, 2018 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 (9 ) Forward gas price 2.54 6.37 3.58 $/mmbtu 3 Crude 28 Forward crude price 27.50 123.20 59.32 $/barrel NGL — Forward NGL price — — — $/gallon Power (91 ) Forward power price 16.21 96.72 48.33 $/MW/H Commodity contracts - physical 1 Natural gas (119 ) Forward gas price 1.09 6.95 1.51 $/mmbtu 3 Crude 186 Forward crude price 16.45 123.22 59.22 $/barrel NGL (6 ) Forward NGL price 0.13 1.40 0.59 $/gallon (11 ) 1 Financial and physical forward commodity contracts are valued using a market approach valuation technique. 2 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, 2018 2017 (millions of Canadian dollars) Level 3 net derivative asset/(liability) at beginning of period (387 ) (295 ) Total gain/(loss) Included in earnings 1 206 (184 ) Included in OCI 2 4 Settlements 168 88 Level 3 net derivative liability at end of period (11 ) (387 ) 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, 2018 or 2017 . FAIR VALUE OF OTHER FINANCIAL INSTRUMENTS Our other long-term investments in other entities with no actively quoted prices are classified as Fair Value Measurement Alternative (FVMA) investments and are recorded at cost less impairment. The carrying value of FVMA and other long-term investments totaled $ 102 million and $99 million as at December 31, 2018 and 2017 , respectively. We have Restricted long-term investments held in trust totaling $323 million and $267 million as at December 31, 2018 and 2017 , respectively, which are recognized at fair value. We have a held to maturity preferred share investment carried at its amortized cost of $478 million and $371 million as at December 31, 2018 and 2017 , 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, 2018 and 2017 . As at December 31, 2018 and 2017 , our long-term debt had a carrying value of $63.9 billion and $64.0 billion , respectively, before debt issuance costs and a fair value of $64.4 billion and $67.4 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, 2018 and 2017 , the noncurrent notes receivable had a carrying value of $97 million and $89 million , and a fair value of $97 million and $89 million , respectively. The fair value of other financial assets and liabilities other than derivative instruments, other long-term investments, restricted long-term investments and long-term debt approximate their cost due to the short period to maturity. 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, 2018 and 2017 , we recognized an unrealized foreign exchange loss of $479 million and a gain of $367 million , respectively, on the translation of United States dollar denominated debt and an unrealized gain on the change in fair value of our outstanding foreign exchange forward contracts of $30 million and $286 million , respectively, in OCI. During the years ended December 31, 2018 and 2017 , we recognized a realized loss of $45 million and $198 million , respectively, in OCI associated with the settlement of foreign exchange forward contracts and also recognized a realized loss of $14 million and gain of $23 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, 2018 and 2017 .

INCOME TAXES

INCOME TAXES	12 Months Ended
	Dec. 31, 2018
Income Tax Disclosure [Abstract]
INCOME TAXES	INCOME TAXES INCOME TAX RATE RECONCILIATION Year ended December 31, 2018 2017 2016 (millions of Canadian dollars) Earnings before income taxes 3,570 569 2,451 Canadian federal statutory income tax rate 15 % 15 % 15 % Expected federal taxes at statutory rate 536 85 368 Increase/(decrease) resulting from: Provincial and state income taxes 1 (24 ) 133 34 Foreign and other statutory rate differentials 94 (601 ) (56 ) Impact of United States tax reform 2 (2 ) (2,045 ) — Effects of rate-regulated accounting (163 ) (189 ) (116 ) Foreign allowable interest deductions (134 ) (124 ) (107 ) Part VI.1 tax, net of federal Part I deduction 76 68 56 Impairment of goodwill 3 192 15 — Intercompany sale of investment 4 — — 6 United States BEAT tax 43 — — Non-taxable portion of gain/(loss) on sale of investment to unrelated party 5 31 — (61 ) Valuation allowance 6 (172 ) (17 ) 22 Intercorporate investments 7 (149 ) 77 — Noncontrolling interests (47 ) (80 ) (15 ) Other (44 ) (19 ) 11 Income tax (recovery)/expense 237 (2,697 ) 142 Effective income tax rate 6.6 % (474.0 )% 5.8 % 1 The change in provincial and state income taxes from 2017 to 2018 reflects the increase in earnings from the Canadian operations, the impact of the US tax reform on state income tax expense, and the impact of changes to the unitary state income tax rate in 2018. 2 The amount was due to the enactment of the TCJA 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 for the tax effect of impairment of goodwill. 4 In November 2016, 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 were recognized in earnings. 5 The amount represents the federal component of the non-taxable portion of the gain on the sales of the Canadian Natural Gas Gathering and Processing Businesses in 2018 and the South Prairie Region assets in 2016 to unrelated parties. 6 The increase from 2017 to 2018 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 2018, was now more likely than not to be realized. 7 The amount relates to the federal component of changes in assertions regarding the manner of recovery of intercorporate investments such that deferred tax related to outside basis temporary differences was required to be recorded for Renewable Assets in 2018 and for EIPLP in 2017. COMPONENTS OF PRETAX EARNINGS AND INCOME TAXES Year ended December 31, 2018 2017 2016 (millions of Canadian dollars) Earnings/(loss) before income taxes Canada 118 2,200 2,034 United States 2,582 (2,431 ) (333 ) Other 870 800 750 3,570 569 2,451 Current income taxes Canada 311 129 74 United States 66 46 21 Other 8 5 4 385 180 99 Deferred income taxes Canada (598 ) 299 188 United States 439 (3,160 ) (151 ) Other 11 (16 ) 6 (148 ) (2,877 ) 43 Income tax (recovery)/expense 237 (2,697 ) 142 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, 2018 2017 (millions of Canadian dollars) Deferred income tax liabilities Property, plant and equipment (7,018 ) (4,089 ) Investments (4,441 ) (6,596 ) Regulatory assets (756 ) (977 ) Other (192 ) (50 ) Total deferred income tax liabilities (12,407 ) (11,712 ) Deferred income tax assets Financial instruments 1,103 697 Pension and OPEB plans 181 258 Loss carryforwards 1,820 1,781 Other 1,274 1,057 Total deferred income tax assets 4,378 3,793 Less valuation allowance (51 ) (286 ) Total deferred income tax assets, net 4,327 3,507 Net deferred income tax liabilities (8,080 ) (8,205 ) Presented as follows: Total deferred income tax assets 1,374 1,090 Total deferred income tax liabilities (9,454 ) (9,295 ) Net deferred income tax liabilities (8,080 ) (8,205 ) 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, 2018 and 2017 , we recognized the benefit of unused tax loss carryforwards of $3.4 billion and $3.8 billion , respectively, in Canada which expire in 2025 and beyond. As at December 31, 2018 and 2017 , we recognized the benefit of unused tax loss carryforwards of $3.4 billion and $2.1 billion , respectively, in the United States which expire in 2023 and beyond. As at December 31, 2018 and 2017 , we recognized the benefit of unused capital loss carryforwards of nil and $143 million , respectively, in Canada. As at December 31, 2018 and 2017 , we recognized the benefit of unused capital loss carryforwards of nil and $20 million , respectively, in the United States. 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 $5.8 billion and $2.1 billion for the period December 31, 2018 and 2017 , 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 2010 to 2018 tax years and by United States tax authorities for the 2013 to 2018 tax years. We are currently under examination for income tax matters in Canada for the 2013 to 2017 tax years and in the United States for the 2013 to 2014 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. As disclosed in our Annual Report on Form 10-K, as filed with the Securities and Exchange Commission on February 16, 2018, we made certain estimates for the measurement and accounting of certain effects of the TCJA for the year ended and as at December 31, 2017. As we continue to gather, prepare and analyze the necessary information in reasonable detail to complete the accounting for the impact of TCJA, we continue to refine our estimates. During the first quarter of 2018 we refined our calculation of the regulatory liability associated with the TCJA which resulted in a $30 million reduction to the overall regulatory liability. An additional reduction to the regulated liability in the amount of $223 million was recorded in the fourth quarter in connection with rate cases filed that eliminated a portion of regulated liability formerly included in SEP's rate base. We recorded $43 million in tax expense for the year ended December 31, 2018 in connection with the Base Erosion and Anti-abuse Tax (BEAT); and we recorded no provision for the Global Intangible Low Taxed Income Tax (GILTI). Most changes to the TCJA are effective for taxation years beginning after December 31, 2017. While the changes are broad and complex, the most significant change was the reduction in the corporate federal income tax rate from 35% to 21% . In 2017 we were 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. In 2017 we 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). Accordingly, 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 in 2017. 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. UNRECOGNIZED TAX BENEFITS Year ended December 31, 2018 2017 (millions of Canadian dollars) Unrecognized tax benefits at beginning of year 150 84 Gross increases for tax positions of current year 2 15 Gross increases for tax positions of prior year — 65 Gross decreases for tax positions of prior year (12 ) — Change in translation of foreign currency 3 (2 ) Lapses of statute of limitations (3 ) (8 ) Settlements (1 ) (4 ) Unrecognized tax benefits at end of year 139 150 The unrecognized tax benefits as at December 31, 2018 , 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, 2018 and 2017 were $5 million expense and $3 million recovery, respectively, of interest and penalties. As at December 31, 2018 and 2017 , interest and penalties of $12 million and $8 million , respectively, have been accrued.

PENSION AND OTHER POSTRETIREMEN

PENSION AND OTHER POSTRETIREMENT BENEFITS	12 Months Ended
	Dec. 31, 2018
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, 2018 2017 2018 2017 (millions of Canadian dollars) Change in projected benefit obligation Projected benefit obligation at beginning of year 4,033 2,270 1,279 508 Service cost 149 156 45 48 Interest cost 130 116 38 35 Participant contributions 25 6 — — Actuarial (gain)/loss (146 ) 145 (103 ) 57 Benefits paid (184 ) (165 ) (60 ) (42 ) Plan settlements — — (65 ) (59 ) Transfer out (10 ) — — — Acquired in Merger Transaction — 1,505 — 811 Foreign currency exchange rate changes — — 105 (63 ) Other — — (25 ) (16 ) Projected benefit obligation at end of year 1 3,997 4,033 1,214 1,279 Change in plan assets Fair value of plan assets at beginning of year 3,619 2,019 1,097 361 Actual return/(loss) on plan assets (42 ) 308 (48 ) 113 Employer contributions 113 161 40 57 Participant contributions 25 6 — — Benefits paid (184 ) (165 ) (60 ) (42 ) Plan settlements — — (65 ) (59 ) Transfer out (8 ) — — — Acquired in Merger Transaction — 1,290 731 Foreign currency exchange rate changes — — 91 (51 ) Other — — (10 ) (13 ) Fair value of plan assets at end of year 2 3,523 3,619 1,045 1,097 Underfunded status at end of year (474 ) (414 ) (169 ) (182 ) Presented as follows: Deferred amounts and other assets 29 38 — — Accounts payable and other (9 ) (60 ) (4 ) (3 ) Other long-term liabilities (494 ) (392 ) (165 ) (179 ) (474 ) (414 ) (169 ) (182 ) 1 The accumulated benefit obligation for our Canadian pension plans was $ 3.7 billion as at December 31, 2018 and 2017 . The accumulated benefit obligation for our United States pension plans was $1.2 billion as at December 31, 2018 and 2017 . 2 Assets in the amount of $ 7 million ( 2017 - $ 9 million ) and $ 39 million ( 2017 - $ 40 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, 2018 2017 2018 2017 (millions of Canadian dollars) Projected benefit obligations 1,422 1,444 1,214 1,280 Accumulated benefit obligations 1,299 1,306 1,179 1,217 Fair value of plan assets 1,064 1,131 1,045 1,098 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, 2018 2017 2018 2017 (millions of Canadian dollars) Net actuarial loss 435 334 133 112 Prior service credit — — (3 ) — Total amount recognized in AOCI 1 435 334 130 112 1 Includes amounts related to cumulative translation adjustment. 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, 2018 2017 2016 2018 2017 2016 (millions of Canadian dollars) Service cost 149 156 129 45 48 26 Interest cost 130 116 73 38 35 16 Expected return on plan assets (245 ) (201 ) (127 ) (88 ) (57 ) (21 ) Amortization/settlement of net actuarial loss 25 29 32 7 10 3 Amortization/curtailment of prior service cost — — — 3 — — Net defined benefit costs 59 100 107 — 5 36 24 Defined contribution benefit costs 11 11 3 19 15 — Net benefit cost recognized in Earnings 70 111 110 24 51 24 Amount recognized in OCI: Amortization/settlement of net actuarial loss (11 ) (14 ) (14 ) (7 ) (9 ) (6 ) Amortization/curtailment of prior service cost — — — (3 ) — — Net actuarial loss arising during the year 112 38 28 28 — 16 Total amount recognized in OCI 101 24 14 18 (9 ) 10 Total amount recognized in Comprehensive income 171 135 124 42 42 34 We estimate that approximately $32 million related to the Canadian pension plans and $0 million related to the United States pension plans as at December 31, 2018 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 2018 2017 2016 2018 2017 2016 Projected benefit obligations Discount rate 3.8 % 3.6 % 4.0 % 3.9 % 3.5 % 4.0 % Rate of salary increase 3.2 % 3.2 % 3.7 % 2.8 % 3.1 % 3.3 % Net benefit cost Discount rate 3.6 % 4.0 % 4.2 % 3.4 % 4.0 % 4.1 % Rate of return on plan assets 6.8 % 6.5 % 6.5 % 7.4 % 7.2 % 7.2 % Rate of salary increase 3.2 % 3.7 % 3.6 % 2.9 % 3.3 % 3.2 % 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 defined benefit OPEB plans: Canada United States December 31, 2018 2017 2018 2017 (millions of Canadian dollars) Change in accumulated postretirement benefit obligation Accumulated postretirement benefit obligation at beginning of year 321 179 337 133 Service cost 8 7 3 5 Interest cost 10 10 10 10 Participant contributions — — 6 4 Actuarial gain (45 ) (8 ) (25 ) (34 ) Benefits paid (11 ) (10 ) (29 ) (19 ) Plan amendments — (3 ) (8 ) 1 Acquired in Merger Transaction — 146 — 254 Foreign currency exchange rate changes — — 27 (17 ) Other (1 ) — (16 ) — Accumulated postretirement benefit obligation at end of year 282 321 305 337 Change in plan assets Fair value of plan assets at beginning of year — — 213 115 Actual return/(loss) on plan assets — — (13 ) 21 Employer contributions 11 10 8 1 Participant contributions — — 6 4 Benefits paid (11 ) (10 ) (29 ) (19 ) Acquired in Merger Transaction — — — 102 Foreign currency exchange rate changes — — 16 (11 ) Other — — (20 ) — Fair value of plan assets at end of year — — 181 213 Underfunded status at end of year (282 ) (321 ) (124 ) (124 ) Presented as follows: Deferred amounts and other assets — — 2 7 Accounts payable and other (12 ) (12 ) (7 ) (7 ) Other long-term liabilities (270 ) (309 ) (119 ) (124 ) (282 ) (321 ) (124 ) (124 ) 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, 2018 2017 2018 2017 (millions of Canadian dollars) Net actuarial (gain)/loss (29 ) 17 (15 ) (15 ) Prior service credit (2 ) (2 ) (15 ) (11 ) Total amount recognized in AOCI 1 (31 ) 15 (30 ) (26 ) 1 Includes amounts related to cumulative translation adjustment. 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, 2018 2017 2016 2018 2017 2016 (millions of Canadian dollars) Service cost 8 7 4 3 5 4 Interest cost 10 10 6 10 10 5 Expected return on plan assets — — — (12 ) (10 ) (6 ) Amortization/settlement of net actuarial gain — — — (1 ) — — Amortization/curtailment of prior service (credit)/cost — 1 — (4 ) — — Net benefit cost recognized in Earnings 18 18 10 (4 ) 5 3 Amount recognized in OCI: Amortization/settlement of net actuarial gain/(loss) — (1 ) (1 ) 1 1 (1 ) Amortization/curtailment of prior service credit — — — 4 — — Net actuarial (gain)/loss arising during the year (46 ) (8 ) 2 (1 ) (42 ) 12 Prior service (credit)/cost — (3 ) — (8 ) 1 (12 ) Total amount recognized in OCI (46 ) (12 ) 1 (4 ) (40 ) (1 ) Total amount recognized in Comprehensive income (28 ) 6 11 (8 ) (35 ) 2 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, 2018 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 2018 2017 2016 2018 2017 2016 Accumulated postretirement benefit obligations Discount rate 3.8 % 3.6 % 4.0 % 4.0 % 3.5 % 3.6 % Net OPEB cost Discount rate 3.6 % 4.0 % 4.2 % 3.3 % 4.0 % 3.8 % Rate of return on plan assets N/A N/A N/A 5.7 % 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 2018 2017 2018 2017 Health care cost trend rate assumed for next year 5.6 % 5.5 % 7.4 % 7.4 % Rate to which the cost trend is assumed to decline (the ultimate trend rate) 4.4 % 4.4 % 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, 2018 : Canada United States 1% Increase 1% Decrease 1% Increase 1% Decrease (millions of Canadian dollars) Effect on total service and interest costs 1 (1 ) 1 (1 ) Effect on accumulated postretirement benefit obligation 20 (16 ) 18 (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 2018 2017 Allocation 2018 2017 Equity securities 40.0 - 70.0% 45.8 % 52.0 % 52.5 - 70.0% 51.7 % 47.1 % Fixed income securities 27.5 - 60.0% 33.4 % 34.2 % 27.5 - 30.0% 32.9 % 47.7 % Other 0.0 - 20.0% 20.7 % 13.8 % 0.0 - 20.0% 15.4 % 5.2 % 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, 2018 Cash and cash equivalents 246 — — 246 56 — — 56 Equity securities Canada 623 — — 623 1 — — 1 United States (1 ) — — (1 ) 50 — — 50 Global 993 — — 993 489 — — 489 Fixed income securities Government 661 — — 661 265 — — 265 Corporate 457 — 60 517 54 — 25 79 Infrastructure and real estate 4 — — 502 502 — — 105 105 Forward currency contracts — (18 ) — (18 ) — — — — Total pension plan assets at fair value 2,979 (18 ) 562 3,523 915 — 130 1,045 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 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, 2018 Cash and cash equivalents — — — — 7 — — 7 Equity securities United States — — — — 63 — — 63 Global — — — — 35 — — 35 Fixed income securities Government — — — — 68 — — 68 Corporate — — — — 3 — 2 5 Infrastructure and real estate — — — — — — 3 3 Total OPEB plan assets at fair value — — — — 176 — 5 181 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 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: Pension Canada United States December 31, 2018 2017 2018 2017 (millions of Canadian dollars) Balance at beginning of year 340 281 56 40 Unrealized and realized gains 77 26 9 5 Purchases and settlements, net 145 33 65 11 Balance at end of year 562 340 130 56 OPEB Canada United States December 31, 2018 2017 2018 2017 (millions of Canadian dollars) Balance at beginning of year — — — — Unrealized and realized gains — — — — Purchases and settlements, net — — 5 — Balance at end of year — — 5 — EXPECTED BENEFIT PAYMENTS AND EMPLOYER CONTRIBUTIONS Year ended December 31, 2019 2020 2021 2022 2023 2023-2027 (millions of Canadian dollars) Pension Canada 174 180 187 194 201 1,104 United States 124 96 97 98 95 438 OPEB Canada 13 12 13 13 13 39 United States 26 26 25 24 23 98 In 2019 , we expect to contribute approximately $114 million and $47 million to the Canadian and United States pension plans, respectively, and $13 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% of eligible pay per pay period for Canadian employees and up to 6% of eligible pay per pay period for United States employees. For the years ended December 31, 2018 , 2017 and 2016 , we expensed pre-tax employer matching contributions of $13 million , $ 14 million and nil for Canadian employees and $ 27 million , $ 31 million and $ 13 million for United States employees, respectively.

CHANGES IN OPERATING ASSETS AND

CHANGES IN OPERATING ASSETS AND LIABILITIES	12 Months Ended
	Dec. 31, 2018
CHANGES IN OPERATING ASSETS AND LIABILITIES
CHANGES IN OPERATING ASSETS AND LIABILITIES	CHANGES IN OPERATING ASSETS AND LIABILITIES Year ended December 31, 2018 2017 2016 (millions of Canadian dollars) Accounts receivable and other 857 (783 ) (437 ) Accounts receivable from affiliates 54 24 (7 ) Inventory 164 (289 ) (371 ) Deferred amounts and other assets 226 (138 ) (183 ) Accounts payable and other (151 ) 277 386 Accounts payable to affiliates (122 ) (62 ) 71 Interest payable 25 124 20 Other long-term liabilities (138 ) 509 153 915 (338 ) (368 )

RELATED PARTY TRANSACTIONS

RELATED PARTY TRANSACTIONS	12 Months Ended
	Dec. 31, 2018
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 $7 million , $14 million and $7 million for the years ended December 31, 2018 , 2017 and 2016 , respectively. 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, 2018 , 2017 and 2016 were $572 million , $721 million and $644 million , respectively. AFFILIATE REVENUES AND PURCHASES Certain wholly-owned subsidiaries within the Gas Distribution and Energy Services segments made natural gas and NGL purchases of $322 million , $142 million and $98 million from several joint venture affiliates during the years ended December 31, 2018 , 2017 and 2016 , respectively. Natural gas sales of $122 million , $60 million and $49 million were made by certain wholly-owned subsidiaries within the Energy Services segment to several joint venture affiliates during the years ended December 31, 2018 , 2017 and 2016 , 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 $ 52 million (US$ 40 million ) and $ 47 million (US$ 36 million ) during the years ended December 31, 2018 , and 2017 , respectively, 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 $ 14 million (US$ 11 million ) and $ 4 million (US$ 3 million ) during the years ended December 31, 2018 , and 2017 , respectively. 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 $ 28 million (US$ 22 million ) and $ 10 million (US$ 8 million ) during the years ended December 31, 2018 , and 2017 , respectively. 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 $ 104 million (US $80 million ) and $ 88 million (US$ 68 million ) for the years ended December 31, 2018 , and 2017 , respectively. 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, 2018 , amounts receivable from affiliates include a series of loans totaling $769 million ( $275 million as at December 31, 2017 ), which require quarterly interest payments at annual interest rates ranging from 4% to 8% . 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, 2018
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS AND CONTINGENCIES	COMMITMENTS AND CONTINGENCIES COMMITMENTS At December 31, 2018 , 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 62,967 3,255 9,262 2,389 4,571 5,963 37,527 Interest obligations 2 30,236 2,459 2,279 2,103 2,022 1,883 19,490 Purchase of services, pipe and other materials, including transportation 3,4 11,084 3,833 1,473 1,225 1,025 501 3,027 Operating leases 1,079 132 134 100 98 93 522 Capital leases 23 7 — — 2 2 12 Maintenance agreements 477 52 51 51 50 22 251 Land lease commitments 651 21 21 21 21 22 545 Total 106,517 9,759 13,220 5,889 7,789 8,486 61,374 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 Includes debentures and term notes bearing interest at fixed, floating and fixed-to-floating rates. 3 Includes capital and operating commitments. 4 Consists primarily of gas transportation and storage contracts, firm capacity payments and gas purchase commitments, transportation, service and product purchase obligations, and power commitments. Total rental expense for operating leases included in Operating and administrative expense were $ 91 million , $ 108 million and $ 79 million for the years ended December 31, 2018 , 2017 and 2016 , 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. AUX SABLE Notice of Violation In September 2014, Aux Sable US received a Notice and Finding of Violation (NFOV) from the United States Environmental Protection Agency (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, which is effective as of December 31, 2018, did not 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 our consolidated financial position or results of operations. TAX MATTERS We and our subsidiaries 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. [NTD: contingencies disclosures to be monitored and updated based on review of legal letters, up to filing]

GUARANTEES

GUARANTEES	12 Months Ended
	Dec. 31, 2018
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, and litigation and contingent liabilities. We may indemnify third parties for certain liabilities relating to environmental matters arising from operations prior to the purchase or transfer of certain assets and interests. Similarly, we may indemnify the purchaser of assets for certain tax liabilities incurred while we owned the assets, a misrepresentation related to taxes that result in a loss to the purchaser or other certain tax liabilities related to those assets. We may also be a party to agreements with subsidiaries, jointly owned entities, unconsolidated entities such as equity method investees, or entities with other ownership arrangements that require us to provide financial and performance guarantees. Financial guarantees include stand-by letters of credit, debt guarantees, surety bonds and indemnifications. To varying degrees, these guarantees involve elements of performance and credit risk, which are not included on our Consolidated Statements of Financial Position. Performance guarantees require us to make payments to a third party if the guaranteed affiliate entity does not perform on its contractual obligations, such as debt agreements, purchase or sale agreements, and construction contracts and leases. We typically enter into these arrangements to facilitate commercial transactions with third parties. The likelihood 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 total maximum potential amounts that could become payable to third parties and affiliates under such agreements described above; however, historically, we have not made any significant payments under guarantee or indemnification provisions. While these agreements may specify a maximum potential exposure, or a specified duration to the guarantee or indemnification obligation, there are circumstances where the amount and duration are unlimited. The guarantees and indemnifications 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.

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS	12 Months Ended
	Dec. 31, 2018
Subsequent Events [Abstract]
SUBSEQUENT EVENTS	SUBSEQUENT EVENTS On January 1, 2019, the previously approved OEB application to amalgamate EGD and Union Gas took effect and the amalgamated company continued as EGI. Refer to Note 7 - Regulatory Matters for further discussion. On January 15, 2019, Enbridge closed the acquisition of 100% of pipeline and tankage infrastructure assets at the Cheecham tank farm for a purchase price of $265 million . These assets were acquired from Athabasca Oil Corporation and were associated with the Leismer SAGD oil sands assets, and are included in our Liquids Pipelines segment. Our wholly-owned subsidiaries, EEP and SEP (the Partnerships), commenced solicitations to holders of certain of the Partnerships' senior unsecured notes (the Notes) to amend (the Amendments) the respective indentures governing the Notes. The purpose of the consent solicitations is to modify the reporting covenant contained in the indentures governing the respective Notes to provide that, in the event Enbridge guarantees a series of such Notes, then in lieu of the respective Partnership's current reporting obligations, Enbridge would be subject to the reporting obligations under such indenture similar to those in the indenture governing Enbridge's U.S. dollar denominated senior notes. The Amendments will also add provisions, in the event Enbridge guarantees a series of Notes, implementing the unconditional guarantee of such series of Notes by Enbridge. On January 18, 2019, the Partnerships received the requisite consents from the holders of the majority in principal amount of each series of outstanding Notes (collectively, the "Consenting EEP and SEP Notes"). On January 22, 2019, each Partnership entered into supplemental indentures to effect the proposed amendments described in the consent solicitation statement dated January 8, 2019 (the "Statement") with respect to each series of the Consenting EEP and SEP Notes and, together with Enbridge, entered into supplemental indentures to implement the unconditional guarantee of each series of Consenting EEP and SEP Notes by Enbridge as described in the Statement. Subject to the terms and conditions set forth in the Statement, each Partnership made a cash payment of $1.00 for each $1,000 principal amount of a series of its Notes to each holder of record of that series of Notes who delivered (and did not revoke) a consent to the applicable Amendments. The supplemental indentures that were executed in connection with the completion of the consent solicitations will bind all holders of the Consenting EEP and SEP Notes. [NTD: Monitor to filing]

QUARTERLY FINANCIAL DATA

QUARTERLY FINANCIAL DATA	12 Months Ended
	Dec. 31, 2018
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) 2018 Operating revenues 12,726 10,745 11,345 11,562 46,378 Operating income 878 1,571 854 1,513 4,816 Earnings 510 1,327 213 1,283 3,333 Earnings attributable to controlling interests 534 1,160 4 1,184 2,882 Earnings/(loss) attributable to common shareholders 445 1,071 (90 ) 1,089 2,515 Earnings/(loss) per common share Basic 0.26 0.63 (0.05 ) 0.60 1.46 Diluted 0.26 0.63 (0.05 ) 0.60 1.46 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/(loss) 945 1,241 1,015 65 3,266 Earnings/(loss) attributable to controlling interests 721 1,000 847 291 2,859 Earnings/(loss) attributable to common shareholders 638 919 765 207 2,529 Earnings/(loss) 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 1 The 2017 quarterly financial data reflects the effect of the Merger Transaction closed on February 27, 2017 (Note 8) .

SIGNIFICANT ACCOUNTING POLICI_2

SIGNIFICANT ACCOUNTING POLICIES (Policies)	12 Months Ended
	Dec. 31, 2018
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 7) ; purchase price allocations (Note 8) ; unbilled revenues; depreciation rates and carrying value of property, plant and equipment (Note 11) ; amortization rates of intangible assets (Note 15) ; measurement of goodwill (Note 16) ; fair value of asset retirement obligations (ARO) (Note 19) ; valuation of stock-based compensation (Note 22) ; fair value of financial instruments (Note 24) ; provisions for income taxes (Note 25) ; assumptions used to measure retirement and other postretirement benefit obligations (OPEB) (Note 26) ; commitments and contingencies (Note 29) ; and estimates of losses related to environmental remediation obligations (Note 29) . 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 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, if 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 is applied, where an investor holding the majority voting rights consolidates the entity. 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 for comparative periods. Redeemable noncontrolling interests on the Consolidated Statements of Financial Position as at December 31, 2017 are recognized 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 (NBEUB), 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 7) . 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/NATIONAL GAS IMBALANCES	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, 2018 , 2017 and 2016 , cash received net of revenue recognized for contracts under make-up rights and similar deferred revenue arrangements was $208 million , $196 million , and $249 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. Our Energy Services segment enters into commodity purchase and sale arrangements that are recorded gross because the related contracts are not held for trading purposes and we are acting as the principal in the transactions. 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. 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.
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 have readily determinable fair values as other investments measured at fair value measurement alternative and 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 impairment each reporting period. Equity investments with readily determinable fair values are measured at fair value through net income. Dividends received from investments in equity securities are recognized in earnings when the right to receive payment is established. Investments in debt securities are classified either as available for sale securities measured at fair value through OCI or as held to maturity securities measured at amortized cost.
NONCONTROLLING INTERESTS	NONCONTROLLING INTERESTS Noncontrolling interests represent ownership interests attributable to third parties in certain consolidated subsidiaries. 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 as at December 31, 2017, within the mezzanine section of the Consolidated Statements of Financial Position between long-term liabilities and equity. Enbridge Income Fund (The Fund)'s noncontrolling interest holders had the option to redeem the Fund trust units for cash, subject to certain limitations. Redeemable noncontrolling interests as at December 31, 2017 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 and up until redeemable noncontrolling interest repurchase date, 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 for comparative periods.
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.
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. From January 1, 2017 through July 3, 2018, emission allowances, which are recorded at their original cost, were 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 of the goodwill balance on April 1. 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. The allocation of goodwill to held for sale and disposed businesses is based on the relative fair value of businesses included in the particular reporting unit. Fair value of our reporting unit is estimated using a combination of discounted cash flow model and earnings multiples techniques. The determination of fair value using the discounted cash flow model technique requires the use of estimates and assumptions related to discount rates, projected operating income, terminal value growth rates, capital expenditures and working capital levels. The cash flow projections included significant judgments and assumptions relating to revenue growth rates and expected future capital expenditure. The determination of fair value using the earnings multiples technique requires assumptions to be made in relation to maintainable earnings and earnings multipliers for reporting units.
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 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. ARO 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 2018) 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.
ADOPTION OF NEW STANDARDS	ADOPTION OF NEW ACCOUNTING STANDARDS Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income Effective January 1, 2018, we adopted Accounting Standards Update (ASU) 2018-02 to address a specific consequence of the Tax Cuts and Jobs Act (TCJA or United States Tax Reform) enacted by the United States federal government on December 22, 2017. The amendments in this accounting update allowed a reclassification from accumulated other comprehensive income (AOCI) to retained earnings for stranded tax effects resulting from the TCJA. The amendments eliminated the stranded tax effects recognized as a result of the reduction of the historical United States federal corporate income tax rate to the newly enacted United States federal corporate income tax rate. The adoption of this accounting update did not have a material impact on our consolidated financial statements. Clarifying Guidance on the Application of Modification Accounting on Stock Compensation Effective January 1, 2018, we adopted ASU 2017-09 and applied the standard on a prospective basis. The new standard was issued to clarify the scope of modification accounting. Under the new guidance, modification accounting is required for all changes to share-based payment awards, unless all of the following conditions 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 adoption of this accounting update did not, and is not expected to have a material impact on our consolidated financial statements. Improving the Presentation of Net Periodic Benefit Cost related to Defined Benefit Plans Effective January 1, 2018, we adopted ASU 2017-07 which was issued 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 other postretirement plans. Upon adoption of this accounting update, our Consolidated Statements of Earnings presents the current service cost within Operating and administrative expenses and the other components of net benefit cost within Other income/(expense). Previously, all components of net benefit cost were presented within Operating and administrative expenses. In addition, only the service cost component of net benefit cost will be capitalized on a prospective basis. The adoption of this accounting update did not, and is not expected to have a material impact on our consolidated financial statements. Clarifying Guidance on Derecognition and Partial Sales of Nonfinancial Assets Effective January 1, 2018, we adopted ASU 2017-05 on a modified retrospective basis. The new standard clarifies the scope provisions of nonfinancial assets and how to allocate consideration to each distinct asset, and amends the guidance for derecognition of a distinct nonfinancial asset in partial sale transactions. The adoption of this accounting update did not have a material impact on our consolidated financial statements. Clarifying the Presentation of Restricted Cash in the Statement of Cash Flows Effective January 1, 2018, we adopted ASU 2016-18 on a retrospective basis. The new standard clarifies guidance on the classification and presentation of changes in restricted cash and restricted cash equivalents within the statement of cash flows. The amendments require that changes in restricted cash and restricted cash equivalents be included within cash and cash equivalents when reconciling the opening and closing period amounts shown on the statement of cash flows. For current and comparative periods, we amended the presentation in the Consolidated Statements of Cash Flows to include restricted cash and restricted cash equivalents with cash and cash equivalents. Simplifying Cash Flow Classification Effective January 1, 2018, we adopted ASU 2016-15 on a retrospective basis. The new standard reduces diversity in practice of how certain cash receipts and cash payments are classified in the Consolidated Statements of Cash Flows. The new guidance addresses eight specific presentation issues. We assessed each of the eight specific presentation issues and the adoption of this ASU did not have a material impact on our consolidated financial statements. Recognition and Measurement of Financial Assets and Liabilities Effective January 1, 2018, we adopted ASU 2016-01 on a prospective basis. The new standard addresses 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 assets and liabilities is measured using the exit price notion. The adoption of this accounting update did not have a material impact on our consolidated financial statements. Revenue from Contracts with Customers Effective January 1, 2018, we adopted ASU 2014-09 on a modified retrospective basis to contracts that were not complete at the date of initial application. The new standard was issued with the intent of significantly enhancing consistency and comparability of revenue recognition practices across entities and industries. The new standard establishes a single, principles-based five-step model to be applied to all contracts with customers and introduces new and enhanced disclosure requirements. It also requires the use of more estimates and judgments than the previous standards. In adopting Accounting Standards Codification (ASC) 606, we applied the practical expedient for contract modifications whereby contracts that were modified before January 1, 2018 were not retrospectively restated. Instead, the aggregate effect of all contract modifications occurring before that time has been reflected when identifying satisfied and unsatisfied performance obligations, determining the transaction price and allocating the transaction price to satisfied and unsatisfied performance obligations. Revenue was previously recognized for a certain contract within the Liquids Pipelines business unit using a formula-based method. Under the new revenue standard, revenue is recognized on a straight-line basis over the term of the agreement in order to reflect the fulfillment of our performance obligation to provide up to a specified volume of pipeline capacity throughout the term of the contract. 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 (CIACs) were previously recorded as reductions of property, plant and equipment regardless of whether the amounts were imposed by regulation or arose from negotiations with customers. Under the new revenue standard, CIACs which are negotiated as part of an agreement to provide transportation and other services to a customer are deemed to be advance payments for future services and are recognized as revenue when those future services are provided. Accordingly, negotiated CIACs are accounted for as deferred revenue and recognized as revenue over the term of the associated revenue contract. Amounts which are required to be collected from the customer based on requirements of the regulator continue to be accounted for as reductions of property, plant and equipment. The below table presents the cumulative, immaterial effect of the adoption of ASC 606 on our Consolidated Statement of Financial Position as at January 1, 2018 on each affected financial statement line item. For the year ended December 31, 2018, the effect of the adoption of ASC 606 on our Consolidated Statement of Earnings was not material. Balance at December 31, 2017 Adjustments Due to ASC 606 Balance at January 1, 2018 (millions of Canadian dollars) Assets Deferred amounts and other assets 6,442 (170 ) 6,272 Property, plant and equipment, net 90,711 112 90,823 Liabilities and equity Accounts payable and other 9,478 62 9,540 Other long-term liabilities 7,510 66 7,576 Deferred income taxes 9,295 (62 ) 9,233 Redeemable noncontrolling interests 4,067 (38 ) 4,029 Deficit (2,468 ) (86 ) (2,554 ) The following ASU’s have been issued, but not yet adopted Clarifying Interaction between Collaborative Arrangements and Revenue from Contracts with Customers In November 2018, ASU 2018-18 was issued to provide clarity on when transactions between entities in a collaborative arrangement should be accounted for under the new revenue standard, ASC 606. In determining whether transactions in collaborative arrangements should be accounted under the revenue standard, the update specifies that entities shall apply unit of account guidance to identify distinct goods or services and whether such goods and services are separately identifiable from other promises in the contract. ASU 2018-18 also precludes entities from presenting transactions with a collaborative partner which are not in scope of the new revenue standard together with revenue from contracts with customers. The accounting update is effective January 1, 2020 and early adoption is permitted. We are currently assessing the impact of the new standard on our consolidated financial statements. Improvements to Related Party Guidance for Variable Interest Entities ASU 2018-17 was issued in October 2018 to improve the related party guidance on determining whether fees paid to decision makers and service providers (“decision-maker fees”) are variable interests. Under the new guidance, reporting entities must consider indirect interests held through related parties in common control arrangements on a proportionate basis, rather than as the equivalent of a direct interest in its entirety, when determining if a decision maker’s fees constitute a variable interest. The accounting update is effective January 1, 2020 and must be applied on a retrospective basis. We are currently assessing the impact of the new standard on our consolidated financial statements. Amended Guidance on Cloud Computing Arrangements In August 2018, ASU 2018-15 was issued to provide guidance on the accounting for implementation costs incurred in a cloud computing arrangement (CCA) that is a service contract. The amendment aligns the accounting for costs incurred to implement a CCA that is a service arrangement with the guidance on capitalizing costs associated with developing or obtaining internal-use software. Additionally, ASU 2018-15 specifies that an entity would apply ASC 350-40, Internal-use software, to determine which implementation costs related to a hosting arrangement that is a service contract should be capitalized and which should be expensed. Furthermore, the amendments in the update require capitalized costs be amortized on a straight-line basis generally over the term of the arrangement and presented in the same income statement line as fees paid for the hosting service. The new standard also requires that the balance sheet presentation of capitalized implementation costs to be the same as that of the prepayment of fees related to the hosting arrangement, as well as similar consistency in classifications from a cash flow statement perspective. ASU 2018-15 is effective January 1, 2020 and we have elected to early adopt the standard as of January 1, 2019, as permitted. We do not expect the adoption of this accounting update to have a material impact on our consolidated financial statements. Disclosure Effectiveness In August 2018, the Financial Accounting Standards Board issued two amendments as a part of its disclosure framework project aimed to improve the effectiveness of disclosures in the notes to financial statements. ASU 2018-14 was issued in August 2018 to improve disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. The amendment modifies the current guidance by adding and removing several disclosure requirements while also clarifying the guidance on current disclosure requirements. ASU 2018-14 is effective January 1, 2021 and entities are permitted to adopt the standard early. We are currently assessing the impact of the new standard on our consolidated financial statements. ASU 2018-13 was issued to improve the disclosure requirements for fair value measurements by eliminating and modifying some disclosures, while also adding new disclosures. This update is effective January 1, 2020, however entities are permitted to early adopt the eliminated or modified disclosures. We are currently assessing the impact of the new standard on our consolidated financial statements. Improvements to Accounting for Hedging Activities ASU 2017-12 was issued in August 2017 with the objective of better aligning a company’s risk management activities and the resulting hedge accounting reflected in the financial statements. The amendments allow cash flow hedging of contractually specified components in financial and non-financial items. Under the new guidance, hedge ineffectiveness is no longer required to be measured and hedging instruments’ fair value changes will be recorded in the same income statement line as the hedged item. The ASU also allows the initial quantitative hedge effectiveness assessment to be performed at any time before the end of the quarter in which the hedge is designated. After initial quantitative testing is performed, an ongoing qualitative effectiveness assessment is permitted. The accounting update is effective January 1, 2019, with early adoption permitted, and is to be applied on a modified retrospective basis. Based upon our current assessment, we do not expect the standard to have a material impact on our consolidated financial statements. In October 2018, ASU 2018-16 was issued to permit the use of the Overnight Index Swap rate based on the Secured Overnight Financing Rate as a U.S. benchmark interest rate for hedge accounting purposes. ASU 2018-16 is effective concurrently with ASU 2017-12. 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 do not expect the adoption of this accounting update to 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 will recognize as an allowance its estimate of expected credit losses, which the Financial Accounting Standards Board believes will result in more timely recognition of such losses. Further, ASU 2018-19 was issued in November 2018 to clarify that operating lease receivables should be accounted for under the new leases standard, ASC 842, and are not within the scope of ASC 326, Financial Instrument - Credit Losses. Both accounting updates are effective January 1, 2020. We are currently assessing the impact of the new standard on our consolidated financial statements. Recognition of Leases ASU 2016-02 was issued in February 2016 with the intent to increase transparency and comparability among organizations. It requires lessees of operating lease arrangements to recognize lease assets and lease liabilities on the statements of financial position and disclose additional key information about lease agreements. The accounting update also replaces the current definition of a lease and requires that an arrangement be recognized as a lease when a customer has the right to obtain substantially all of the economic benefits from the use of an asset, as well as the right to direct the use of the asset. The new standard became effective January 1, 2019 and in adopting ASC 842, we have applied the package of practical expedients offered in connection with this update. Application of the package of practical expedients permits entities not to reassess a) whether any expired or existing contracts contain leases in accordance with the new guidance, b) lease classifications, and c) whether initial direct costs capitalized under current guidance continue to meet the definition of initial direct costs under the new guidance. Under the new lease guidance, we have also decided to elect, by class of underlying asset, to not separate non-lease components from the associated lease components of our lessee contract and account for both components as a single lease component. ASU 2018-01 was issued in January 2018 to address stakeholder concerns about the costs and complexity of complying with the transition provisions of the new lease requirements as they relate to land easements. The amendments provide an optional transition practical expedient to not evaluate existing or expired land easements that were not previously accounted for as leases under existing guidance. We have elected this practical expedient in connection with the adoption of the new lease requirements. In July 2018, ASU 2018-11 was issued to address additional stakeholder concerns regarding the unanticipated costs and complexities associated with the modified retrospective transition method as well as the requirement for lessors to separate components of a contract. Under the new guidance, entities are provided with an additional transition method which allows entities to apply the new standard at the date of adoption and to elect not to recast comparative periods presented. This amendment also permits lessors to combine associated lease and non-lease components within a contract for operating leases when certain conditions are met. We have elected both of these practical expedients in the adoption of the new lease standard. We have identified all lease contracts existing as at November 30, 2018 and have performed detailed evaluations of those lease contracts under the requirements of the transitional guidance. We estimate that we will recognize right-of-use lease assets and related lease liabilities for existing operating leases where we are the lessee in the range of $750 million to $900 million , with no impact to our Consolidated Statements of Earnings or Consolidated Statements of Cash Flows. This estimate represents the net present value of future lease payments payable under operating lease contracts we had entered into as at November 30, 2018, and that have commenced or are scheduled to commence by January 1, 2019. We do not expect any adjustments will be made to our accounting for existing lessor contracts as a result of implementing this new standard.

CHANGES IN ACCOUNTING POLICIES

CHANGES IN ACCOUNTING POLICIES (Tables)	12 Months Ended
	Dec. 31, 2018
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
Schedule of New Accounting Pronouncements and Changes in Accounting Principles	The below table presents the cumulative, immaterial effect of the adoption of ASC 606 on our Consolidated Statement of Financial Position as at January 1, 2018 on each affected financial statement line item. For the year ended December 31, 2018, the effect of the adoption of ASC 606 on our Consolidated Statement of Earnings was not material. Balance at December 31, 2017 Adjustments Due to ASC 606 Balance at January 1, 2018 (millions of Canadian dollars) Assets Deferred amounts and other assets 6,442 (170 ) 6,272 Property, plant and equipment, net 90,711 112 90,823 Liabilities and equity Accounts payable and other 9,478 62 9,540 Other long-term liabilities 7,510 66 7,576 Deferred income taxes 9,295 (62 ) 9,233 Redeemable noncontrolling interests 4,067 (38 ) 4,029 Deficit (2,468 ) (86 ) (2,554 ) Liquids Pipelines Gas Transmission and Midstream Gas Distribution Green Power and Transmission Energy Services Consolidated Year ended December 31, 2018 (millions of Canadian dollars) Revenue from products transferred at a point in time 1 — 1,590 68 — — 1,658 Revenue from products and services transferred over time 2 8,589 4,965 5,379 559 — 19,492 Total revenue from contracts with customers 8,589 6,555 5,447 559 — 21,150 1 Revenue from sales of crude oil, natural gas and NGLs. 2 Revenue from crude oil and natural gas pipeline transportation, storage, natural gas gathering, compression and treating, natural gas distribution, natural gas storage services and electricity sales.

REVENUE (Tables)

REVENUE (Tables)	12 Months Ended
	Dec. 31, 2018
Revenue from Contract with Customer [Abstract]
Disaggregation of Revenue	Liquids Pipelines Gas Transmission and Midstream Gas Distribution Green Power and Transmission Energy Services Eliminations and Other Consolidated Year ended December 31, 2018 (millions of Canadian dollars) Transportation revenue 8,488 3,928 875 — — — 13,291 Storage and other revenue 101 222 196 — — — 519 Gas gathering and processing revenue — 815 — — — — 815 Gas distribution revenue — — 4,376 — — — 4,376 Electricity and transmission revenue — — — 559 — — 559 Commodity sales — 1,590 — — — — 1,590 Total revenue from contracts with customers 8,589 6,555 5,447 559 — — 21,150 Commodity sales — — — — 26,070 — 26,070 Other revenue 1 (894 ) 6 9 8 4 25 (842 ) Intersegment revenue 384 10 14 — 154 (562 ) — Total revenue 8,079 6,571 5,470 567 26,228 (537 ) 46,378 1 Includes mark-to-market gains/(losses) from our hedging program.
Contract with Customer, Asset and Liability	Receivables Contract Assets Contract Liabilities (millions of Canadian dollars) Balance as at January 1, 2018 2,475 290 992 Balance as at December 31, 2018 1,929 191 1,245
Schedule of New Accounting Pronouncements and Changes in Accounting Principles	The below table presents the cumulative, immaterial effect of the adoption of ASC 606 on our Consolidated Statement of Financial Position as at January 1, 2018 on each affected financial statement line item. For the year ended December 31, 2018, the effect of the adoption of ASC 606 on our Consolidated Statement of Earnings was not material. Balance at December 31, 2017 Adjustments Due to ASC 606 Balance at January 1, 2018 (millions of Canadian dollars) Assets Deferred amounts and other assets 6,442 (170 ) 6,272 Property, plant and equipment, net 90,711 112 90,823 Liabilities and equity Accounts payable and other 9,478 62 9,540 Other long-term liabilities 7,510 66 7,576 Deferred income taxes 9,295 (62 ) 9,233 Redeemable noncontrolling interests 4,067 (38 ) 4,029 Deficit (2,468 ) (86 ) (2,554 ) Liquids Pipelines Gas Transmission and Midstream Gas Distribution Green Power and Transmission Energy Services Consolidated Year ended December 31, 2018 (millions of Canadian dollars) Revenue from products transferred at a point in time 1 — 1,590 68 — — 1,658 Revenue from products and services transferred over time 2 8,589 4,965 5,379 559 — 19,492 Total revenue from contracts with customers 8,589 6,555 5,447 559 — 21,150 1 Revenue from sales of crude oil, natural gas and NGLs. 2 Revenue from crude oil and natural gas pipeline transportation, storage, natural gas gathering, compression and treating, natural gas distribution, natural gas storage services and electricity sales.

SEGMENTED INFORMATION (Tables)

SEGMENTED INFORMATION (Tables)	12 Months Ended
	Dec. 31, 2018
Segment Reporting [Abstract]
Schedule of reporting information by segment	Segmented information for the years ended December 31, 2018 , 2017 and 2016 are as follows: Year ended December 31, 2018 Liquids Pipelines Gas Transmission and Midstream Gas Distribution Green Power and Transmission Energy Services Eliminations and Other Consolidated (millions of Canadian dollars) Revenues 8,079 6,571 5,470 567 26,228 (537 ) 46,378 Commodity and gas distribution costs (16 ) (1,481 ) (2,748 ) (7 ) (25,689 ) 540 (29,401 ) Operating and administrative (3,124 ) (2,102 ) (1,111 ) (157 ) (73 ) (225 ) (6,792 ) Impairment of long-lived assets (180 ) (914 ) — (4 ) — (6 ) (1,104 ) Impairment of goodwill — (1,019 ) — — — — (1,019 ) Income/(loss) from equity investments 577 930 11 (28 ) 18 1 1,509 Other income/(expense) (5 ) 349 89 (2 ) (2 ) (481 ) (52 ) Earnings/(loss) before interest, income tax expense, and depreciation and amortization 5,331 2,334 1,711 369 482 (708 ) 9,519 Depreciation and amortization (3,246 ) Interest expense (2,703 ) Income tax expense (237 ) Earnings 3,333 Capital expenditures 1 3,102 2,644 1,066 33 — 27 6,872 Total assets 68,798 60,559 25,748 5,716 1,042 5,042 166,905 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 1 Includes allowance for equity funds used during construction.
Schedule of revenues by geographical segments	Revenues 1 Year ended December 31, 2018 2017 2016 (millions of Canadian dollars) Canada 19,023 18,076 12,470 United States 27,355 26,302 22,090 46,378 44,378 34,560 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, 2018 2017 (millions of Canadian dollars) Canada 44,716 46,025 United States 49,824 44,686 94,540 90,711 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, 2018
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, 2018 2017 2016 (number of shares in millions) Weighted average shares outstanding 1,724 1,525 911 Effect of dilutive options 3 7 7 Diluted weighted average shares outstanding 1,727 1,532 918

REGULATORY MATTERS (Tables)

REGULATORY MATTERS (Tables)	12 Months Ended
	Dec. 31, 2018
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 2018 2017 (millions of Canadian dollars) Regulatory assets/(liabilities) Liquids Pipelines Deferred income taxes Various 1,673 1,492 Tolling deferrals Various (28 ) (34 ) Recoverable income taxes Through 2030 27 46 Pipeline future abandonment costs 1 Various (201 ) (141 ) Gas Transmission and Midstream Deferred income taxes Various 826 717 Regulatory liability related to income taxes 2 Various (912 ) (1,078 ) Other Various 94 (16 ) Gas Distribution Deferred income taxes Various 1,132 1,000 Purchased gas variance 3 Various 197 51 Pension plans and OPEB 4 Through 2033 118 102 Constant dollar net salvage adjustment 2018 6 38 Future removal and site restoration reserves 5 Various (1,107 ) (1,066 ) Site restoration clearance adjustment Various — (31 ) Other Various (4 ) 31 1 Funds collected are included in Restricted long-term investments (Note 14) . 2 Relates to the establishment of a regulatory liability as a result of the United States tax reform legislation enacted 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. 5 Future removal and site restoration reserves result from amounts collected from customers by the Company, with the approval of the OEB, to fund future costs for removal and site restoration relating to property, plant and equipment. These costs are collected as part of depreciation charged on property, plant and equipment that is recorded in rates. The balance represents the amount that the Company has collected from customers, net of actual costs expended on removal and site restoration. The settlement of this balance will occur over the long-term as future removal and site restoration costs are incurred. In the absence of rate regulation accounting, costs incurred for removal and site restoration would be charged to earnings as incurred with recognition of revenue for amounts previously collected.
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 2018 2017 (millions of Canadian dollars) Regulatory assets/(liabilities) Liquids Pipelines Deferred income taxes Various 1,673 1,492 Tolling deferrals Various (28 ) (34 ) Recoverable income taxes Through 2030 27 46 Pipeline future abandonment costs 1 Various (201 ) (141 ) Gas Transmission and Midstream Deferred income taxes Various 826 717 Regulatory liability related to income taxes 2 Various (912 ) (1,078 ) Other Various 94 (16 ) Gas Distribution Deferred income taxes Various 1,132 1,000 Purchased gas variance 3 Various 197 51 Pension plans and OPEB 4 Through 2033 118 102 Constant dollar net salvage adjustment 2018 6 38 Future removal and site restoration reserves 5 Various (1,107 ) (1,066 ) Site restoration clearance adjustment Various — (31 ) Other Various (4 ) 31 1 Funds collected are included in Restricted long-term investments (Note 14) . 2 Relates to the establishment of a regulatory liability as a result of the United States tax reform legislation enacted 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. 5 Future removal and site restoration reserves result from amounts collected from customers by the Company, with the approval of the OEB, to fund future costs for removal and site restoration relating to property, plant and equipment. These costs are collected as part of depreciation charged on property, plant and equipment that is recorded in rates. The balance represents the amount that the Company has collected from customers, net of actual costs expended on removal and site restoration. The settlement of this balance will occur over the long-term as future removal and site restoration costs are incurred. In the absence of rate regulation accounting, costs incurred for removal and site restoration would be charged to earnings as incurred with recognition of revenue for amounts previously collected.

ACQUISITIONS AND DISPOSITIONS (

ACQUISITIONS AND DISPOSITIONS (Tables)	12 Months Ended
	Dec. 31, 2018
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 LLC (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 13) . 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 13) .
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, 2018 December 31, 2017 (millions of Canadian dollars) Accounts receivable and other (current assets held for sale) 117 424 Deferred amounts and other assets (long-term assets held for sale) 1 2,383 1,190 Accounts payable and other (current liabilities held for sale) (63 ) (315 ) Other long-term liabilities (long-term liabilities held for sale) (96 ) (34 ) Net assets held for sale 2,341 1,265 1 Included within Deferred amounts and other assets at December 31, 2018 and 2017 respectively is property, plant and equipment of $2.1 billion and $1.1 billion .

ACCOUNTS RECEIVABLE AND OTHER (

ACCOUNTS RECEIVABLE AND OTHER (Tables)	12 Months Ended
	Dec. 31, 2018
Receivables [Abstract]
Schedule of accounts receivable and other	December 31, 2018 2017 (millions of Canadian dollars) Trade receivables and unbilled revenues 1 4,711 5,325 Short-term portion of derivative assets 498 296 Other 1,308 1,432 6,517 7,053 1 Net of allowance for doubtful accounts of $64 million and $50 million as at December 31, 2018 and 2017 , respectively.

INVENTORY (Tables)

INVENTORY (Tables)	12 Months Ended
	Dec. 31, 2018
Inventory Disclosure [Abstract]
Schedule of inventory	December 31, 2018 2017 (millions of Canadian dollars) Natural gas 776 695 Crude oil 482 744 Other commodities 81 89 1,339 1,528

PROPERTY, PLANT AND EQUIPMENT (

PROPERTY, PLANT AND EQUIPMENT (Tables)	12 Months Ended
	Dec. 31, 2018
Property, Plant and Equipment [Abstract]
Schedule of Property, Plant and Equipment	Weighted Average December 31, Depreciation Rate 2018 2017 (millions of Canadian dollars) Pipelines 2.6 % 50,078 47,720 Pumping equipment, buildings, tanks and other 3.0 % 16,935 16,610 Land and right-of-way 1 2.7 % 2,603 2,538 Gas mains, services and other 3.2 % 17,474 17,026 Compressors, meters and other operating equipment 1.7 % 5,893 5,774 Processing and treating plants 1.5 % 1,634 1,440 Storage 1.9 % 1,713 1,545 Wind turbines, solar panels and other 4.2 % 5,063 4,804 Power transmission 2.6 % 383 365 Vehicles, office furniture, equipment and other buildings and improvements 5.9 % 630 390 Under construction — 9,778 7,601 Total property, plant and equipment 2 112,184 105,813 Total accumulated depreciation (17,644 ) (15,102 ) Property, plant and equipment, net 94,540 90,711 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, 2018 and December 31, 2017 (Note 8) .

VARIABLE INTEREST ENTITIES (Tab

VARIABLE INTEREST ENTITIES (Tables)	12 Months Ended
	Dec. 31, 2018
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, 2018 2017 (millions of Canadian dollars) Assets Cash and cash equivalents 506 368 Restricted cash 27 — Accounts receivable and other 2,073 2,132 Accounts receivable from affiliates 5 3 Inventory 244 220 2,855 2,723 Property, plant and equipment, net 72,737 68,685 Long-term investments 6,481 6,258 Restricted long-term investments 244 206 Deferred amounts and other assets 3,156 2,921 Intangible assets, net 317 296 Goodwill 29 29 Deferred income taxes 131 145 85,950 81,263 Liabilities Short-term borrowings 275 485 Accounts payable and other 2,925 2,859 Accounts payable to affiliates 4 131 Interest payable 303 312 Environmental liabilities 22 35 Current portion of long-term debt 1,034 2,129 4,563 5,951 Long-term debt 29,577 31,469 Other long-term liabilities 5,074 4,301 Deferred income taxes 6,911 3,010 46,125 44,731 Net assets before noncontrolling interests 39,825 36,532
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, 2018 and 2017 is presented below. Carrying Amount of Investment Enbridge’s Maximum Exposure to December 31, 2018 in VIE Loss (millions of Canadian dollars) Aux Sable Liquid Products L.P. 1 311 375 Eolien Maritime France SAS 2 68 784 Enbridge Renewable Infrastructure Investments S.a.r.l. 3, 9 127 3,250 Illinois Extension Pipeline Company, L.L.C. 4 724 724 Nexus Gas Transmission, LLC 5 1,757 2,668 PennEast Pipeline Company, LLC 6 97 385 Rampion Offshore Wind Limited 7 638 648 Vector Pipeline L.P. 8 198 301 Other 4 27 27 3,947 9,162 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. 300 361 Eolien Maritime France SAS 69 754 Hohe See Offshore Wind Project 9 763 2,484 Illinois Extension Pipeline Company, L.L.C. 686 686 Nexus Gas Transmission, LLC 834 1,678 PennEast Pipeline Company, LLC 69 345 Rampion Offshore Wind Limited 555 679 Sabal Trail Transmissions, LLC 2,355 2,529 Vector Pipeline L.P. 169 278 Other 21 21 5,821 9,815 1 At December 31, 2018 , 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, 2018 , 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 $202 million held by us. 3 At December 31, 2018 , 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, 2018 , the maximum exposure to loss is limited to our equity investment as these companies are in operation and self-sustaining. 5 At December 31, 2018 , the maximum exposure to loss includes the remaining expected contributions to the joint venture and parental guarantees for our portion of capacity lease agreements. 6 At December 31, 2018 the maximum exposure to loss includes the remaining expected contributions to the joint venture. 7 At December 31, 2018 , the maximum exposure to loss includes the portion of our parental guarantee that has been committed in project contracts in which we would be liable for in the event of default by the VIE. 8 At December 31, 2018 the maximum exposure to loss includes the carrying value of an outstanding affiliate loan receivable for $ 102 million held by us. 9 As at December 31, 2018 , the carrying amount of investment and maximum exposure to loss related to Hohe See Offshore Wind Project are included in the amounts shown for ERII.

LONG-TERM INVESTMENTS (Tables)

LONG-TERM INVESTMENTS (Tables)	12 Months Ended
	Dec. 31, 2018
Equity Method Investments and Joint Ventures [Abstract]
Schedule of Long-Term Investments	Ownership December 31, Interest 2018 2017 (millions of Canadian dollars) EQUITY INVESTMENTS Liquids Pipelines Bakken Pipeline System 1 27.6 % 2,039 1,938 Seaway Crude Pipeline System 50.0 % 3,113 2,882 Illinois Extension Pipeline Company, L.L.C. 2 65.0 % 724 686 Other 30.0% - 43.8% 97 87 Gas Transmission and Midstream Alliance Pipeline 3 50.0 % 368 375 Aux Sable 42.7% - 50.0% 311 300 DCP Midstream, LLC 4 50.0 % 2,368 2,143 Gulfstream Natural Gas System, L.L.C. 4 50.0 % 1,289 1,205 Nexus Gas Transmission, LLC 4 50.0 % 1,757 834 Offshore - various joint ventures 22.0% - 74.3% 400 389 PennEast Pipeline Company LLC 4 20.0 % 97 69 Sabal Trail Transmission, LLC 5 50.0 % 1,586 2,355 Southeast Supply Header L.L.C. 4 50.0 % 519 486 Steckman Ridge LP 4 49.5 % 237 221 Texas Express Pipeline 6 35.0 % — 430 Vector Pipeline L.P. 60.0 % 198 169 Other 4 33.3% - 50.0% 6 34 Gas Distribution Noverco Common Shares 38.9 % — — Other 4 50.0 % 15 15 Green Power and Transmission Eolien Maritime France SAS 50.0 % 68 69 Enbridge Renewable Infrastructure Investments S.a.r.l. 7 25.5 % 127 763 Rampion Offshore Wind Project 24.9 % 638 555 Other 19.0% - 50.0% 72 95 Eliminations and Other Other 19.0% - 42.7% 10 26 OTHER LONG-TERM INVESTMENTS Gas Distribution Noverco Preferred Shares 478 371 Green Power and Transmission Emerging Technologies and Other 80 80 Eliminations and Other Other 110 67 16,707 16,644 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 20 - 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 8) . 5 On February 27, 2017, we acquired Spectra Energy's consolidated interest in Sabal Trail as part of the Merger Transaction (Note 8) . 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 August 1, 2018 the sale of Midcoast Operating, L.P. and its subsidiaries closed. Upon closing of the sale, our interest in the Texas Express NGL pipeline system was sold along with the MOLP assets. The carrying value of $447 million of our equity method investment in the Texas Express NGL pipeline system was included within the disposal group of the transaction. For further details on the sale transaction please refer to Note 8 - Acquisitions and Dispositions . 7 On February 8, 2017 , we acquired an effective 50% interest in EnBW Hohe See GmbH & Co. KG. On August 1, 2018 we transferred our interest in the Hohe See Offshore wind facilities and its subsequent expansion to a newly formed entity, ERII. Subsequently, we sold a 49% interest in ERII to CPPIB, reducing our interest in the project to 25.5% .
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, 2018 2017 2016 Seaway Other Total Seaway Other Total Seaway Other Total (millions of Canadian dollars) Operating revenues 966 18,251 19,217 959 15,254 16,213 938 3,164 4,102 Operating expenses 212 15,422 15,634 286 12,911 13,197 293 3,051 3,344 Earnings/(loss) 646 2,308 2,954 672 2,056 2,728 643 (2 ) 641 Earnings attributable to controlling interests 323 1,059 1,382 336 926 1,262 322 147 469 December 31, 2018 December 31, 2017 Seaway Other Total Seaway Other Total (millions of Canadian dollars) Current assets 113 3,176 3,289 106 3,432 3,538 Non-current assets 3,585 45,531 49,116 3,329 41,697 45,026 Current liabilities 123 5,413 5,536 143 3,311 3,454 Non-current liabilities 16 15,859 15,875 13 13,582 13,595 Noncontrolling interests — 3,479 3,479 — 3,191 3,191

INTANGIBLE ASSETS (Tables)

INTANGIBLE ASSETS (Tables)	12 Months Ended
	Dec. 31, 2018
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, 2018 1 Amortization Rate Cost Amortization Net (millions of Canadian dollars) Customer relationships 5.0 % 762 70 692 Power purchase agreements 4.4 % 96 21 75 Project agreement 2 4.0 % 164 10 154 Software 11.4 % 1,827 814 1,013 Other intangible assets 4.1 % 508 70 438 3,357 985 2,372 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, 2018 and December 31, 2017 (Note 8) . 2 Represents a project agreement acquired from the Merger Transaction (Note 8) . 3 The measurement of weighted average amortization rate excludes non-depreciable intangible assets.
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: 2019 2020 2021 2022 2023 Forecast of amortization expense (millions of Canadian dollars) 278 251 227 205 186

GOODWILL (Tables)

GOODWILL (Tables)	12 Months Ended
	Dec. 31, 2018
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, 2017 59 457 7 — 2 13 538 Acquired in Merger Transaction (Note 8) 8,070 22,914 5,672 — — — 36,656 Sabal Trail deconsolidation (Note 13) — (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 Disposition — (628 ) — — — — (628 ) Allocation to assets held for sale — (55 ) (133 ) — — — (188 ) Foreign exchange and other 538 1,482 (183 ) — — — 1,837 Balance at December 31, 2018 8,324 22,338 5,363 — 2 13 36,040 Accumulated Impairment Balance at January 1, 2017 — (440 ) (7 ) — — (13 ) (460 ) Impairment — (102 ) — — — — (102 ) Balance at December 31, 2017 — (542 ) (7 ) — — (13 ) (562 ) Impairment — (1,019 ) — — — — (1,019 ) Balance at December 31, 2018 — (1,561 ) (7 ) — — (13 ) (1,581 ) Carrying Value Balance at December 31, 2017 7,786 20,997 5,672 — 2 — 34,457 Balance at December 31, 2018 8,324 20,777 5,356 — 2 — 34,459

ACCOUNTS PAYABLE AND OTHER (Tab

ACCOUNTS PAYABLE AND OTHER (Tables)	12 Months Ended
	Dec. 31, 2018
Payables and Accruals [Abstract]
Schedule of accounts payable and other	December 31, 2018 2017 (millions of Canadian dollars) Trade payables and operating accrued liabilities 4,604 5,135 Construction payables and contractor holdbacks 804 706 Current derivative liabilities 1,234 1,130 Dividends payable 1,539 1,169 Taxes payable 801 522 Other 854 816 9,836 9,478

DEBT (Tables)

DEBT (Tables)	12 Months Ended
	Dec. 31, 2018
Debt Disclosure [Abstract]
Schedule of Debt	Weighted Average December 31, Interest Rate Maturity 2018 2017 (millions of Canadian dollars) Enbridge Inc. United States dollar term notes 1 4.1 % 2022-2046 6,419 5,889 Medium-term notes 2 4.3 % 2019-2064 7,323 5,698 Fixed-to-floating subordinated term notes 3,4 5.9 % 2077-2078 6,771 3,843 Floating rate notes 5 2019-2020 2,389 2,254 Commercial paper and credit facility draws 6 2.2 % 2019-2023 1,999 2,729 Other 7 — 3 Enbridge (U.S.) Inc. Commercial paper and credit facility draws 8 3.5 % 2020 1,065 490 Enbridge Energy Partners, L.P. Senior notes 9 6.2 % 2019-2045 6,214 6,328 Junior subordinated notes 10 2067 546 501 Commercial paper and credit facility draws 11 3.3 % 2022 1,044 1,820 Enbridge Gas Distribution Inc. Medium-term notes 4.5 % 2020-2050 3,695 3,695 Debentures 9.9 % 2024 85 85 Commercial paper and credit facility draws 2.3 % 2020 750 960 Enbridge Income Fund Medium-term notes 2 — 1,750 Commercial paper and credit facility draws — 755 Enbridge Pipelines (Southern Lights) L.L.C. Senior notes 12 4.0 % 2040 1,257 1,207 Enbridge Pipelines Inc. Medium-term notes 13 4.3 % 2019-2046 4,225 4,525 Debentures 8.2 % 2024 200 200 Commercial paper and credit facility draws 14 2.4 % 2020 2,200 1,438 Other 7 4 4 Enbridge Southern Lights LP Senior notes 4.0 % 2040 289 315 Midcoast Energy Partners, L.P. Senior notes 15 — 501 Spectra Energy Capital 16 Senior notes 17 7.1 % 2032-2038 236 1,665 Spectra Energy Partners, LP 16 Senior secured notes 18 6.1 % 2020 150 138 Senior notes 19 4.3 % 2020-2048 8,249 7,192 Floating rate notes 20 2020 546 501 Commercial paper and credit facility draws 21 3.2 % 2022 2,065 2,824 Union Gas Limited 16 Medium-term notes 4.1 % 2021-2047 3,290 3,490 Senior debentures — 75 Debentures 8.7 % 2025 125 250 Commercial paper and credit facility draws 2.3 % 2021 275 485 Westcoast Energy Inc. 16 Senior secured notes 6.2 % 2019 33 66 Medium-term notes 4.7 % 2019-2041 2,175 2,177 Debentures 8.6 % 2020-2026 375 525 Fair value adjustment - Spectra Energy acquisition 964 1,114 Other 22 (348 ) (312 ) Total debt 64,610 65,180 Current maturities (3,259 ) (2,871 ) Short-term borrowings 23 (1,024 ) (1,444 ) Long-term debt 60,327 60,865 1 2018 - US $4,700 million ; 2017 - US $4,700 million . 2 On December 21, 2018, Enbridge and Enbridge Income Fund (the Fund) completed a transaction to exchange certain series of the Fund's outstanding medium-term notes (Legacy Fund Notes) for an equal principal amount of newly issued medium term notes of Enbridge, having financial terms that are the same as the financial terms of the Fund Notes. See Debt Exchange discussion below. 3 2018 - $2,400 million and US $3,200 million ; 2017 - $1,650 million and US $1,750 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. 4 The notes would be converted automatically into Conversion Preference Shares in the event of bankruptcy and related events. 5 2018 - $750 million and US $1,200 million ; 2017 - $750 million and US $1,200 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. 6 2018 - $1,906 million and US $69 million ; 2017 - $1,593 million and US $907 million . 7 Primarily capital lease obligations. 8 2018 - US $780 million ; 2017 - US $391 million . 9 2018 - US $4,550 million ; 2017 - US $5,050 million . 10 2018 - US $400 million ; 2017 - US $400 million . Carries an interest rate equal to the three-month LIBOR plus a margin of 379.75 basis points. 11 2018 - US $764 million ; 2017 - US $1,453 million . 12 2018 - US $920 million ; 2017 - US $963 million . 13 Included in medium-term notes is $100 million with a maturity date of 2112. 14 2018 - $1,905 million and US $216 million ; 2017 - $1,080 million and US $286 million . 15 2017 - US $400 million . 16 Debt acquired in conjunction with the Merger Transaction (Note 8) . 17 2018 - US $173 million ; 2017 - US $1,329 million . 18 2018 - US $110 million ; 2017 - US $110 million . 19 2018 - US $6,040 million ; 2017 - US $5,740 million . 20 2018 - US $400 million ; 2017 - US $400 million . Carries an interest rate equal to the three-month LIBOR plus a margin of 70 basis points. 21 2018 - US $1,512 million ; 2017 - US $2,254 million . 22 Primarily debt discount and debt issue costs. 23 Weighted average interest rate - 2.3% ; 2017 - 1.4% .
Schedule of Committed Credit Facilities	The following table provides details of our committed credit facilities at December 31, 2018 : 2018 Total December 31, Maturity Facilities Draws 1 Available (millions of Canadian dollars) Enbridge Inc. 2019-2023 5,751 2,008 3,743 Enbridge (U.S.) Inc. 2020 1,932 1,065 867 Enbridge Energy Partners, L.P. 2 2022 2,493 1,044 1,449 Enbridge Gas Distribution Inc. 2019-2020 1,018 760 258 Enbridge Pipelines Inc. 2020 3,000 2,200 800 Spectra Energy Partners, LP 3,4 2022 3,414 2,065 1,349 Union Gas Limited 4 2021 700 275 425 Total committed credit facilities 18,308 9,417 8,891 1 Includes facility draws, letters of credit and commercial paper issuances that are back-stopped by the credit facility. 2 Includes $253 million (US$185 million) of facilities that expire in 2020. 3 Includes $459 million (US$336 million) of facilities that expire in 2021. 4 Committed credit facilities acquired in conjunction with the Merger Transaction (Note 8) .
Schedule of Long-term Debt Issuances	The following are long-term debt issuances made during 2018 and 2017 , excluding the debt exchange discussed below: Company Issue Date Principal Amount (millions of Canadian dollars unless otherwise stated) Enbridge Inc. March 2018 Fixed-to-floating rate subordinated notes due March 2078 1 US$850 April 2018 Fixed-to-floating rate subordinated notes due April 2078 2 $750 April 2018 Fixed-to-floating rate subordinated notes due April 2078 3 US$600 May 2017 Floating rate notes due May 2019 4 $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 5 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 6 US$1,000 September 2017 Fixed-to-floating rate subordinated notes due September 2077 7 $1,000 October 2017 Fixed-to-floating rate subordinated notes due September 2077 7 $650 October 2017 Floating rate notes due January 2020 8 US$700 Enbridge Gas Distribution Inc. November 2017 3.51% medium-term notes due November 2047 $300 Spectra Energy Partners, LP January 2018 3.50% senior notes due January 2028 9 US$400 January 2018 4.15% senior notes due January 2048 9 US$400 June 2017 Floating rate notes due June 2020 10 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 Notes mature in 60 years and are callable on or after year 10 . For the initial 10 years , the notes carry a fixed interest rate of 6.25% . Subsequently, the interest rate will be set to equal the three-month LIBOR plus a margin of 364 basis points from years 10 to 30 , and a margin of 439 basis points from years 30 to 60 . 2 Notes mature in 60 years and are callable on or after year 10 . For the initial 10 years , the notes carry a fixed interest rate of 6.625% . Subsequently, the interest rate will be set to equal the Canadian Dollar Offered Rate plus a margin of 432 basis points from years 10 to 30 , and a margin of 507 basis points from years 30 to 60 . 3 Notes mature in 60 years and are callable on or after year five . For the initial five years , the notes carry a fixed interest rate of 6.375% . Subsequently, the interest rate will be set to equal the three-month LIBOR plus a margin of 359 basis points from years five to 10 , a margin of 384 basis points from years 10 to 25 , and a margin of 459 basis points from years 25 to 60 . 4 Carries an interest rate equal to the three-month Bankers' Acceptance Rate plus 59 basis points. 5 Carries an interest rate equal to the three-month LIBOR plus 70 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 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 . 7 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 . 8 Carries an interest rate equal to the three-month LIBOR plus 40 basis points. 9 Issued through Texas Eastern Transmission, L.P. (Texas Eastern), a wholly-owned operating subsidiary of SEP. 10 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 2018 and 2017 , excluding the debt exchange discussed below: Company Retirement/Repayment Date Principal Amount Cash Consideration 1 (millions of Canadian dollars unless otherwise stated) Enbridge Inc. March 2017 Floating rate notes $500 April 2017 5.60% medium-term notes US$400 June 2017 Floating rate notes US$500 Enbridge Energy Partners, L.P. April 2018 6.50% senior notes US$400 October 2018 7.00% senior notes US$100 Enbridge Gas Distribution Inc. April 2017 1.85% medium-term notes $300 December 2017 5.16% medium-term notes $200 Enbridge Income Fund December 2018 4.00% medium-term notes $125 June 2017 5.00% medium-term notes $100 December 2017 2.92% medium-term notes $225 Enbridge Pipelines (Southern Lights) L.L.C. June and December 2018 3.98% medium-term notes due June 2040 US$43 June and December 2017 3.98% medium-term note due June 2040 US$37 Enbridge Pipelines Inc. November 2018 6.62% medium-term notes $170 November 2018 6.62% medium-term notes $130 Enbridge Southern Lights LP January, July and December 2018 4.01% medium-term notes due June 2040 $27 June 2017 4.01% medium-term notes due June 2040 $7 Midcoast Energy Partners, L.P. Redemption July 2018 2 3.56% senior notes due September 2019 US$75 US$76 July 2018 2 4.04% senior notes due September 2021 US$175 US$182 July 2018 2 4.42% senior notes due September 2024 US$150 US$161 Spectra Energy Capital, LLC Repurchase via Tender Offer March 2018 2 6.75% senior unsecured notes due 2032 US$64 US$80 March 2018 2 7.50% senior unsecured notes due 2038 US$43 US$59 July 2017 3 Senior notes carrying interest ranging from 3.3% to 7.5% due 2018 to 2038 US$761 US$857 Redemption March 2018 2 5.65% senior unsecured notes due 2020 US$163 US$172 March 2018 2 3.30% senior unsecured notes due 2023 US$498 US$508 July and September 2017 3 8.00% senior notes due 2019 US$500 US$581 Repayment April 2018 6.20% senior notes US$272 July 2018 6.75% senior notes US$118 Spectra Energy Partners, LP September 2018 2.95% senior notes US$500 September 2017 6.00% senior notes US$400 June and December 2017 7.39% subordinated secured notes US$12 Union Gas Limited April 2018 5.35% medium-term notes $200 August 2018 8.75% debentures $125 October 2018 8.65% senior debentures $75 November 2017 9.70% debentures $125 Westcoast Energy Inc. May and November 2018 6.90% senior secured notes due 2019 $26 May and November 2018 4.34% senior secured notes due 2019 $9 September 2018 8.50% debenture $150 May and November 2017 6.90% senior secured notes due 2019 $26 May and November 2017 4.34% senior secured notes due 2019 $24 1 Cash consideration disclosed for repayments where the cash paid differs from the principal amount. 2 The loss on debt extinguishment of $64 million (US $50 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. 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, 2018 2017 2016 (millions of Canadian dollars) Debentures and term notes 3,011 3,011 1,714 Commercial paper and credit facility draws 171 206 197 Amortization of fair value adjustment - Spectra Energy acquisition (131 ) (270 ) — Capitalized (348 ) (391 ) (321 ) 2,703 2,556 1,590

ASSET RETIREMENT OBLIGATIONS (T

ASSET RETIREMENT OBLIGATIONS (Tables)	12 Months Ended
	Dec. 31, 2018
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, 2018 2017 (millions of Canadian dollars) Obligations at beginning of year 793 232 Liabilities acquired — 546 Liabilities disposed (13 ) — Liabilities incurred 145 — Liabilities settled (21 ) (22 ) Change in estimate 29 18 Foreign currency translation adjustment 22 (12 ) Accretion expense 34 31 Obligations at end of year 989 793 Presented as follows: Accounts payable and other 6 2 Other long-term liabilities 983 791 989 793

NONCONTROLLING INTERESTS (Table

NONCONTROLLING INTERESTS (Tables)	12 Months Ended
	Dec. 31, 2018
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, 2018 2017 (millions of Canadian dollars) Algonquin Gas Transmission, L.L.C 1 518 476 Enbridge Energy Management, L.L.C. 2 — 34 Enbridge Energy Partners, L.P. 3 — 138 Enbridge Gas Distribution Inc. 4 — 100 Maritimes & Northeast Pipeline, L.L.C 1 613 572 Renewable energy assets 5 1,961 806 Spectra Energy Partners, LP 6 — 4,335 Union Gas Limited 7 — 110 Westcoast Energy Inc. 8 841 1,005 Other 9 32 21 3,965 7,597 1 Represents subsidiaries of SEP and the interests in these subsidiaries held by third parties. 2 On December 20, 2018, we executed the definitive agreement with EEM and acquired all of the publicly held shares of EEM not already owned by us or our subsidiaries. As at December 31, 2017 , the balance represented 88.3% interest in EEM held by public shareholders. 3 On December 20, 2018, we executed the definitive agreement with EEP and acquired all of the publicly held Class A common units of EEP not already owned by us or our subsidiaries. As at December 31, 2017 , the balance represented 68.2% interest in EEP held by public unitholders. 4 On November 29, 2018, EGD redeemed all of its four million cumulative redeemable preferred shares held by third parties. As at December 31, 2017 , the balance of these preferred shares was $100 million . 5 On August 1, 2018, we closed the sale of 49% of our interest in the Renewable Assets (Note 8) . The remaining balance represents the tax equity investors' interests in Magic Valley, Wildcat, Keechi, New Creek and Chapman Ranch wind facilities, which are accounted for using the HLBV method, with an additional 20.0% noncontrolling interest in each of the Magic Valley and Wildcat wind facilities held by third parties as at December 31, 2018 and 2017 . 6 On December 17, 2018, we closed the definitive agreement with SEP and acquired all of the publicly listed common units of SEP not already owned by us or our subsidiaries. As at December 31, 2017 , the balance represented 25.7% interest in SEP held by public unitholders. 7 On November 29, 2018, Union Gas redeemed all of its four million cumulative redeemable preferred shares held by third parties. As at December 31, 2017 , the balance of these preferred shares was $110 million . 8 Represents the 16.6 million cumulative redeemable preferred shares and 12 million cumulative first preferred shares as at December 31, 2018 and 2017 held by third parties in Westcoast Energy Inc., and the 22.0% interest in Maritimes & Northeast Pipeline Limited Partnership held by third parties as at December 31, 2018 and 2017. 9 Represents subsidiary of EEP and the interests in this subsidiary held by third parties.
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, 2018 2017 2016 (millions of Canadian dollars) Balance at beginning of year 4,067 3,392 2,141 Earnings attributable to redeemable noncontrolling interests 117 175 268 Other comprehensive income/(loss), net of tax Change in unrealized loss on cash flow hedges 3 (21 ) (17 ) Other comprehensive loss from equity investees 14 — — Reclassification to earnings of loss on cash flow hedges — 57 9 Foreign currency translation adjustments 4 (6 ) (3 ) Other comprehensive income/(loss), net of tax 21 30 (11 ) Distributions to unitholders (300 ) (247 ) (202 ) Contributions from unitholders 70 1,178 591 Modified retrospective adoption of accounting standard (note 3) (38 ) — — Net dilution gain/(loss) 76 (169 ) (81 ) Redemption value adjustment 456 (292 ) 686 Sponsored vehicle buy-in 1 (4,469 ) — — Balance at end of year — 4,067 3,392 1. On November 8, 2018, we executed the definitive agreement with ENF and acquired all of the publicly held shares of ENF not already owned by us or our subsidiaries.

SHARE CAPITAL (Tables)

SHARE CAPITAL (Tables)	12 Months Ended
	Dec. 31, 2018
Equity [Abstract]
Schedule of common shares	COMMON SHARES 2018 2017 2016 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 1,695 50,737 943 10,492 868 7,391 Common shares issued 1 — — 33 1,500 56 2,241 Common shares issued in Merger Transaction (Note 8) — — 691 37,429 — — Common shares issued in Sponsored Vehicle buy-in (SEP) (Note 20) 91 3,888 — — — — Common shares issued in Sponsored Vehicle buy-in (EEP) (Note 20) 72 3,042 — — — — Common shares issued in Sponsored Vehicle buy-in (EEM) (Note 20) 30 1,267 — — — — Common shares issued in Sponsored Vehicle buy-in (ENF) (Note 20) 104 4,530 — — — — Dividend Reinvestment and Share Purchase Plan 28 1,181 25 1,226 16 795 Shares issued on exercise of stock options 2 32 3 90 3 65 Balance at end of year 2,022 64,677 1,695 50,737 943 10,492 1 Gross proceeds of nil , $1.5 billion and $2.3 billion for the years ended December 31, 2018 , 2017 and 2016 , respectively; net issuance costs of nil , nil and $59 million for the years ended December 31, 2018 , 2017 and 2016 , respectively.
Schedule of preference shares	PREFERENCE SHARES 2018 2017 2016 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 18 457 20 500 Preference Shares, Series C 2 43 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 30 750 Preference Shares, Series 19 20 500 20 500 — — Issuance costs (155 ) (155 ) (147 ) Balance at end of year 7,747 7,747 7,255
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 3.42 % $0.85360 $25 June 1, 2022 Series C Preference Shares, Series C 5 3-month treasury bill plus 2.40% — $25 June 1, 2022 Series B Preference Shares, Series D 6 4.46 % $1.11500 $25 March 1, 2023 Series E Preference Shares, Series F 6 4.69 % $1.17225 $25 June 1, 2023 Series G Preference Shares, Series H 6 4.38 % $1.09400 $25 September 1, 2023 Series I Preference Shares, Series J 4.89 % US$1.22160 US$25 June 1, 2022 Series K Preference Shares, Series L 4.96 % US$1.23972 US$25 September 1, 2022 Series M Preference Shares, Series N 6 5.09 % $1.27150 $25 December 1, 2023 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 6 5.95 % US$1.48728 US$25 June 1, 2023 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 The floating quarterly dividend amount for the Series C Preference Shares was increased to $0.22685 from $0.20342 on March 1, 2018, was increased to $0.22748 from $0.22685 on June 1, 2018, was increased to $0.23934 from $0.22748 on September 1, 2018 and was increased to $0.25459 from $0.23934 on December 1, 2018, due to reset on a quarterly basis following the issuance thereof. 6 No Series D, F, H, N, or 1 Preference shares were converted on the March 1, 2018, June 1, 2018, September 1, 2018, December 1, 2018 or June 1, 2018 conversion option dates, respectively. However, the quarterly dividend amounts for Series D, F, H, N, and 1, were increased to $0.27875 from $0.25000 on March 1, 2018, $0.29306 from $0.25000 on June 1, 2018, $0.27350 from $0.25000 on September 1, 2018, $0.31788 from $0.25000 on December 1, 2018 and US $0.37182 from US $0.25000 on June 1, 2018, respectively, due to reset on every fifth anniversary thereafter.

STOCK OPTION AND STOCK UNIT P_2

STOCK OPTION AND STOCK UNIT PLANS (Tables)	12 Months Ended
	Dec. 31, 2018
INCENTIVE STOCK OPTIONS
STOCK OPTION AND STOCK UNIT PLANS
Schedule of outstanding stock options	December 31, 2018 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 34,366 45.41 Options granted 5,775 32.32 Options exercised 1 (2,519 ) 27.11 Options cancelled or expired (3,235 ) 44.11 Options outstanding at end of year 34,387 43.47 6.1 108 Options vested at end of year 2 21,064 43.48 4.7 84 1 The total intrinsic value of ISOs exercised during the years ended December 31, 2018 , 2017 and 2016 was $42 million , $62 million and $123 million , respectively, and cash received on exercise was $15 million , $17 million and $37 million , respectively. 2 The total fair value of ISOs vested during the years ended December 31, 2018 , 2017 and 2016 was $36 million , $44 million and $36 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, 2018 2017 2016 Fair value per option (Canadian dollars) 1 3.86 6.00 7.37 Valuation assumptions Expected option term (years) 2 5 5 5 Expected volatility 3 21.9 % 20.4 % 25.1 % Expected dividend yield 4 6.4 % 4.4 % 4.4 % Risk-free interest rate 5 2.2 % 1.2 % 0.8 % 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, 2018 , 2017 and 2016 were $3.75 , $5.66 and $7.01 , respectively, for Canadian employees and US $3.30 , US $5.72 and US $6.60 , 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, 2018 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 1,693 Units granted 542 Units cancelled (191 ) Units matured 1 (971 ) Dividend reinvestment 140 Units outstanding at end of year 1,213 1.3 52 1 The total amount paid during the years ended December 31, 2018 , 2017 and 2016 for RSUs was $41 million , $39 million and $56 million , respectively.

COMPONENTS OF ACCUMULATED OTH_2

COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS) (Tables)	12 Months Ended
	Dec. 31, 2018
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, 2018 , 2017 and 2016 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, 2018 (644 ) (139 ) 77 10 (277 ) (973 ) Other comprehensive income/(loss) retained in AOCI (244 ) (509 ) 4,301 16 (85 ) 3,479 Other comprehensive (income)/loss reclassified to earnings Interest rate contracts 1 157 — — — — 157 Commodity contracts 2 (1 ) — — — — (1 ) Foreign exchange contracts 3 7 — — — — 7 Other contracts 4 22 — — — — 22 Amortization of pension and OPEB actuarial loss and prior service costs 5 — — — — 16 16 (59 ) (509 ) 4,301 16 (69 ) 3,680 Tax impact Income tax on amounts retained in AOCI 57 50 — 8 33 148 Income tax on amounts reclassified to earnings (37 ) — — — (4 ) (41 ) 20 50 — 8 29 107 Sponsored Vehicles buy-in 6 (87 ) — (55 ) — — (142 ) Balance at December 31, 2018 (770 ) (598 ) 4,323 34 (317 ) 2,672 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 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. 6 Represents the historical noncontrolling interests and redeemable noncontrolling interests related to the Sponsored Vehicles reclassified to AOCI, upon the completion of the buy-in.

RISK MANAGEMENT AND FINANCIAL_2

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (Tables)	12 Months Ended
	Dec. 31, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Summary of the Consolidated Statements of Financial Position location and carrying value of derivative instruments	The following table summarizes the maximum potential settlement amounts in the event of these specific circumstances. All amounts are presented gross in the Consolidated Statements of Financial Position. December 31, 2018 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 — — — 47 47 (37 ) 10 Interest rate contracts 22 — — — 22 (2 ) 20 Commodity contracts 2 — — 427 429 (114 ) 315 24 — — 474 498 (153 ) 345 Deferred amounts and other assets Foreign exchange contracts 23 — — 39 62 (39 ) 23 Interest rate contracts 5 — — — 5 — 5 Commodity contracts 19 — — 33 52 (21 ) 31 47 — — 72 119 (60 ) 59 Accounts payable and other Foreign exchange contracts (5 ) — — (610 ) (615 ) 37 (578 ) Interest rate contracts (163 ) — — (178 ) (341 ) 2 (339 ) Commodity contracts — — — (273 ) (273 ) 114 (159 ) Other contracts (1 ) — — (4 ) (5 ) — (5 ) (169 ) — — (1,065 ) (1,234 ) 153 (1,081 ) Other long-term liabilities Foreign exchange contracts (1 ) (15 ) — (2,196 ) (2,212 ) 39 (2,173 ) Interest rate contracts (201 ) — — — (201 ) — (201 ) Commodity contracts — — — (178 ) (178 ) 21 (157 ) Other contracts (1 ) — — (1 ) (2 ) — (2 ) (203 ) (15 ) — (2,375 ) (2,593 ) 60 (2,533 ) Total net derivative asset/(liability) Foreign exchange contracts 17 (15 ) — (2,720 ) (2,718 ) — (2,718 ) Interest rate contracts (337 ) — — (178 ) (515 ) — (515 ) Commodity contracts 21 — — 9 30 — 30 Other contracts (2 ) — — (5 ) (7 ) — (7 ) (301 ) (15 ) — (2,894 ) (3,210 ) — (3,210 ) December 31, 2017 Derivative Derivative Derivative Instruments Used as Fair Value Hedges Non- Total Gross Amounts 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 )
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. 2018 2017 As at December 31, 2019 2020 2021 2022 2023 Thereafter Total Foreign exchange contracts - United States dollar forwards - purchase (millions of United States dollars) 925 1 — — — — 759 Foreign exchange contracts - United States dollar forwards - sell (millions of United States dollars) 4,969 4,893 3,608 1,944 1,804 1,857 16,167 Foreign exchange contracts - British pound (GBP) forwards - purchase (millions of GBP) — — — — — — 18 Foreign exchange contracts - GBP forwards - sell (millions of GBP) 89 25 27 28 29 120 318 Foreign exchange contracts - Euro forwards - purchase (millions of Euro) 226 — — — — — 655 Foreign exchange contracts - Euro forwards - sell (millions of Euro) — 23 94 94 92 606 1,262 Foreign exchange contracts - Japanese yen forwards - purchase (millions of yen) 32,662 — — 20,000 — — 52,662 Interest rate contracts - short-term pay fixed rate (millions of Canadian dollars) 8,616 6,243 4,188 412 49 156 7,138 Interest rate contracts - long-term receive fixed rate (millions of Canadian dollars) — — — — — — 4,196 Interest rate contracts - long-term pay fixed rate (millions of Canadian dollars) 3,777 3,185 1,596 — — — 5,402 Equity contracts (millions of Canadian dollars) 35 20 — — — — 90 Commodity contracts - natural gas (billions of cubic feet) (141 ) (16 ) (6 ) (4 ) — — (159 ) Commodity contracts - crude oil (millions of barrels) 4 — — — — — (3 ) Commodity contracts - NGL (millions of barrels) — — — — — — (12 ) Commodity contracts - power (megawatt per hour (MW/H)) 64 66 (3 ) (43 ) (43 ) (43 ) 1 (43 ) 2 1 As at December 31, 2018 , thereafter includes an average net purchase/(sell) of power of (43) MW/H for 2024 through 2025. 2 As at December 31, 2017, thereafter includes an average net purchase/(sell) of power of (43) MW/H for 2023 through 2025.
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: 2018 2017 2016 (millions of Canadian dollars) Amount of unrealized gain/(loss) recognized in OCI Cash flow hedges Foreign exchange contracts 19 (5 ) (19 ) Interest rate contracts (190 ) 6 (90 ) Commodity contracts 2 11 14 Other contracts (3 ) 1 39 Net investment hedges Foreign exchange contracts 31 284 22 (141 ) 297 (34 ) Amount of (gain)/loss reclassified from AOCI to earnings (effective portion) Foreign exchange contracts 1 5 (104 ) 2 Interest rate contracts 2,3 161 388 145 Commodity contracts 4 (1 ) (9 ) (12 ) Other contracts 5 3 8 (29 ) 168 283 106 Amount of (gain)/loss reclassified from AOCI to earnings (ineffective portion and amount excluded from effectiveness testing) Interest rate contracts 2, 3 23 (4 ) 61 23 (4 ) 61 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. Year ended December 31, 2018 2017 (millions of Canadian dollars) Unrealized gain/(loss) on derivative 7 (10 ) Unrealized gain/(loss) on hedged item 1 11 Realized gain/(loss) on derivative (8 ) 2 Realized gain/(loss) on hedged item (1 ) (2 )
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, 2018 2017 2016 (millions of Canadian dollars) Foreign exchange contracts 1 (1,390 ) 1,284 935 Interest rate contracts 2 5 157 73 Commodity contracts 3 485 (199 ) (508 ) Other contracts 4 (3 ) — 9 Total unrealized derivative fair value gain/(loss), net (903 ) 1,242 509 1 For the respective annual periods, reported within Transportation and other services revenues ( 2018 - $1,108 million loss; 2017 - $800 million gain; 2016 - $497 million gain) and Other income/(expense) ( 2018 - $282 million loss; 2017 - $484 million gain; 2016 - $438 million gain) 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 ( 2018 - $66 million gain; 2017 - $104 million loss; 2016 - $52 million loss), Commodity sales ( 2018 - $599 million gain; 2017 - $90 million gain; 2016 - $474 million loss), Commodity costs ( 2018 - $193 million loss; 2017 - $223 million loss; 2016 - $38 million gain) and Operating and administrative expense ( 2018 - $13 million gain; 2017 - $38 million gain; 2016 - $20 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 credit concentrations and credit exposure, with respect to derivative instruments, in the following counterparty segments: December 31, 2018 2017 (millions of Canadian dollars) Canadian financial institutions 28 82 United States financial institutions 107 19 European financial institutions 84 145 Asian financial institutions 6 2 Other 1 337 137 562 385 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, 2018 Level 1 Level 2 Level 3 Total Gross Derivative Instruments (millions of Canadian dollars) Financial assets Current derivative assets Foreign exchange contracts — 47 — 47 Interest rate contracts — 22 — 22 Commodity contracts 24 45 360 429 24 114 360 498 Long-term derivative assets Foreign exchange contracts — 62 — 62 Interest rate contracts — 5 — 5 Commodity contracts — 30 22 52 — 97 22 119 Financial liabilities Current derivative liabilities Foreign exchange contracts — (615 ) — (615 ) Interest rate contracts — (341 ) — (341 ) Commodity contracts (7 ) (28 ) (238 ) (273 ) Other contracts — (5 ) — (5 ) (7 ) (989 ) (238 ) (1,234 ) Long-term derivative liabilities Foreign exchange contracts — (2,212 ) — (2,212 ) Interest rate contracts — (201 ) — (201 ) Commodity contracts — (23 ) (155 ) (178 ) Other contracts — (2 ) — (2 ) — (2,438 ) (155 ) (2,593 ) Total net financial asset/(liability) Foreign exchange contracts — (2,718 ) — (2,718 ) Interest rate contracts — (515 ) — (515 ) Commodity contracts 17 24 (11 ) 30 Other contracts — (7 ) — (7 ) 17 (3,216 ) (11 ) (3,210 ) 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 )
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, 2018 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 (9 ) Forward gas price 2.54 6.37 3.58 $/mmbtu 3 Crude 28 Forward crude price 27.50 123.20 59.32 $/barrel NGL — Forward NGL price — — — $/gallon Power (91 ) Forward power price 16.21 96.72 48.33 $/MW/H Commodity contracts - physical 1 Natural gas (119 ) Forward gas price 1.09 6.95 1.51 $/mmbtu 3 Crude 186 Forward crude price 16.45 123.22 59.22 $/barrel NGL (6 ) Forward NGL price 0.13 1.40 0.59 $/gallon (11 ) 1 Financial and physical forward commodity contracts are valued using a market approach valuation technique. 2 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, 2018 2017 (millions of Canadian dollars) Level 3 net derivative asset/(liability) at beginning of period (387 ) (295 ) Total gain/(loss) Included in earnings 1 206 (184 ) Included in OCI 2 4 Settlements 168 88 Level 3 net derivative liability at end of period (11 ) (387 ) 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, 2018
Income Tax Disclosure [Abstract]
Schedule of income tax rate reconciliation	INCOME TAX RATE RECONCILIATION Year ended December 31, 2018 2017 2016 (millions of Canadian dollars) Earnings before income taxes 3,570 569 2,451 Canadian federal statutory income tax rate 15 % 15 % 15 % Expected federal taxes at statutory rate 536 85 368 Increase/(decrease) resulting from: Provincial and state income taxes 1 (24 ) 133 34 Foreign and other statutory rate differentials 94 (601 ) (56 ) Impact of United States tax reform 2 (2 ) (2,045 ) — Effects of rate-regulated accounting (163 ) (189 ) (116 ) Foreign allowable interest deductions (134 ) (124 ) (107 ) Part VI.1 tax, net of federal Part I deduction 76 68 56 Impairment of goodwill 3 192 15 — Intercompany sale of investment 4 — — 6 United States BEAT tax 43 — — Non-taxable portion of gain/(loss) on sale of investment to unrelated party 5 31 — (61 ) Valuation allowance 6 (172 ) (17 ) 22 Intercorporate investments 7 (149 ) 77 — Noncontrolling interests (47 ) (80 ) (15 ) Other (44 ) (19 ) 11 Income tax (recovery)/expense 237 (2,697 ) 142 Effective income tax rate 6.6 % (474.0 )% 5.8 % 1 The change in provincial and state income taxes from 2017 to 2018 reflects the increase in earnings from the Canadian operations, the impact of the US tax reform on state income tax expense, and the impact of changes to the unitary state income tax rate in 2018. 2 The amount was due to the enactment of the TCJA 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 for the tax effect of impairment of goodwill. 4 In November 2016, 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 were recognized in earnings. 5 The amount represents the federal component of the non-taxable portion of the gain on the sales of the Canadian Natural Gas Gathering and Processing Businesses in 2018 and the South Prairie Region assets in 2016 to unrelated parties. 6 The increase from 2017 to 2018 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 2018, was now more likely than not to be realized. 7 The amount relates to the federal component of changes in assertions regarding the manner of recovery of intercorporate investments such that deferred tax related to outside basis temporary differences was required to be recorded for Renewable Assets in 2018 and for EIPLP in 2017.
Schedule of components of pretax earnings and income taxes	COMPONENTS OF PRETAX EARNINGS AND INCOME TAXES Year ended December 31, 2018 2017 2016 (millions of Canadian dollars) Earnings/(loss) before income taxes Canada 118 2,200 2,034 United States 2,582 (2,431 ) (333 ) Other 870 800 750 3,570 569 2,451 Current income taxes Canada 311 129 74 United States 66 46 21 Other 8 5 4 385 180 99 Deferred income taxes Canada (598 ) 299 188 United States 439 (3,160 ) (151 ) Other 11 (16 ) 6 (148 ) (2,877 ) 43 Income tax (recovery)/expense 237 (2,697 ) 142
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, 2018 2017 (millions of Canadian dollars) Deferred income tax liabilities Property, plant and equipment (7,018 ) (4,089 ) Investments (4,441 ) (6,596 ) Regulatory assets (756 ) (977 ) Other (192 ) (50 ) Total deferred income tax liabilities (12,407 ) (11,712 ) Deferred income tax assets Financial instruments 1,103 697 Pension and OPEB plans 181 258 Loss carryforwards 1,820 1,781 Other 1,274 1,057 Total deferred income tax assets 4,378 3,793 Less valuation allowance (51 ) (286 ) Total deferred income tax assets, net 4,327 3,507 Net deferred income tax liabilities (8,080 ) (8,205 ) Presented as follows: Total deferred income tax assets 1,374 1,090 Total deferred income tax liabilities (9,454 ) (9,295 ) Net deferred income tax liabilities (8,080 ) (8,205 )
Schedule of unrecognized tax benefits	UNRECOGNIZED TAX BENEFITS Year ended December 31, 2018 2017 (millions of Canadian dollars) Unrecognized tax benefits at beginning of year 150 84 Gross increases for tax positions of current year 2 15 Gross increases for tax positions of prior year — 65 Gross decreases for tax positions of prior year (12 ) — Change in translation of foreign currency 3 (2 ) Lapses of statute of limitations (3 ) (8 ) Settlements (1 ) (4 ) Unrecognized tax benefits at end of year 139 150

PENSION AND OTHER POSTRETIREM_2

PENSION AND OTHER POSTRETIREMENT BENEFITS (Tables)	12 Months Ended
	Dec. 31, 2018
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, 2018 2017 2018 2017 (millions of Canadian dollars) Change in projected benefit obligation Projected benefit obligation at beginning of year 4,033 2,270 1,279 508 Service cost 149 156 45 48 Interest cost 130 116 38 35 Participant contributions 25 6 — — Actuarial (gain)/loss (146 ) 145 (103 ) 57 Benefits paid (184 ) (165 ) (60 ) (42 ) Plan settlements — — (65 ) (59 ) Transfer out (10 ) — — — Acquired in Merger Transaction — 1,505 — 811 Foreign currency exchange rate changes — — 105 (63 ) Other — — (25 ) (16 ) Projected benefit obligation at end of year 1 3,997 4,033 1,214 1,279 Change in plan assets Fair value of plan assets at beginning of year 3,619 2,019 1,097 361 Actual return/(loss) on plan assets (42 ) 308 (48 ) 113 Employer contributions 113 161 40 57 Participant contributions 25 6 — — Benefits paid (184 ) (165 ) (60 ) (42 ) Plan settlements — — (65 ) (59 ) Transfer out (8 ) — — — Acquired in Merger Transaction — 1,290 731 Foreign currency exchange rate changes — — 91 (51 ) Other — — (10 ) (13 ) Fair value of plan assets at end of year 2 3,523 3,619 1,045 1,097 Underfunded status at end of year (474 ) (414 ) (169 ) (182 ) Presented as follows: Deferred amounts and other assets 29 38 — — Accounts payable and other (9 ) (60 ) (4 ) (3 ) Other long-term liabilities (494 ) (392 ) (165 ) (179 ) (474 ) (414 ) (169 ) (182 ) 1 The accumulated benefit obligation for our Canadian pension plans was $ 3.7 billion as at December 31, 2018 and 2017 . The accumulated benefit obligation for our United States pension plans was $1.2 billion as at December 31, 2018 and 2017 . 2 Assets in the amount of $ 7 million ( 2017 - $ 9 million ) and $ 39 million ( 2017 - $ 40 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, 2018 2017 2018 2017 (millions of Canadian dollars) Projected benefit obligations 1,422 1,444 1,214 1,280 Accumulated benefit obligations 1,299 1,306 1,179 1,217 Fair value of plan assets 1,064 1,131 1,045 1,098
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, 2018 2017 2018 2017 (millions of Canadian dollars) Net actuarial loss 435 334 133 112 Prior service credit — — (3 ) — Total amount recognized in AOCI 1 435 334 130 112 1 Includes amounts related to cumulative translation adjustment. The amounts of pre-tax AOCI relating to our OPEB plans are as follows: Canada United States December 31, 2018 2017 2018 2017 (millions of Canadian dollars) Net actuarial (gain)/loss (29 ) 17 (15 ) (15 ) Prior service credit (2 ) (2 ) (15 ) (11 ) Total amount recognized in AOCI 1 (31 ) 15 (30 ) (26 ) 1 Includes amounts related to cumulative translation adjustment.
Schedule of 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, 2018 2017 2016 2018 2017 2016 (millions of Canadian dollars) Service cost 149 156 129 45 48 26 Interest cost 130 116 73 38 35 16 Expected return on plan assets (245 ) (201 ) (127 ) (88 ) (57 ) (21 ) Amortization/settlement of net actuarial loss 25 29 32 7 10 3 Amortization/curtailment of prior service cost — — — 3 — — Net defined benefit costs 59 100 107 — 5 36 24 Defined contribution benefit costs 11 11 3 19 15 — Net benefit cost recognized in Earnings 70 111 110 24 51 24 Amount recognized in OCI: Amortization/settlement of net actuarial loss (11 ) (14 ) (14 ) (7 ) (9 ) (6 ) Amortization/curtailment of prior service cost — — — (3 ) — — Net actuarial loss arising during the year 112 38 28 28 — 16 Total amount recognized in OCI 101 24 14 18 (9 ) 10 Total amount recognized in Comprehensive income 171 135 124 42 42 34 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, 2018 2017 2016 2018 2017 2016 (millions of Canadian dollars) Service cost 8 7 4 3 5 4 Interest cost 10 10 6 10 10 5 Expected return on plan assets — — — (12 ) (10 ) (6 ) Amortization/settlement of net actuarial gain — — — (1 ) — — Amortization/curtailment of prior service (credit)/cost — 1 — (4 ) — — Net benefit cost recognized in Earnings 18 18 10 (4 ) 5 3 Amount recognized in OCI: Amortization/settlement of net actuarial gain/(loss) — (1 ) (1 ) 1 1 (1 ) Amortization/curtailment of prior service credit — — — 4 — — Net actuarial (gain)/loss arising during the year (46 ) (8 ) 2 (1 ) (42 ) 12 Prior service (credit)/cost — (3 ) — (8 ) 1 (12 ) Total amount recognized in OCI (46 ) (12 ) 1 (4 ) (40 ) (1 ) Total amount recognized in Comprehensive income (28 ) 6 11 (8 ) (35 ) 2
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 2018 2017 2016 2018 2017 2016 Accumulated postretirement benefit obligations Discount rate 3.8 % 3.6 % 4.0 % 4.0 % 3.5 % 3.6 % Net OPEB cost Discount rate 3.6 % 4.0 % 4.2 % 3.3 % 4.0 % 3.8 % Rate of return on plan assets N/A N/A N/A 5.7 % 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 2018 2017 2016 2018 2017 2016 Projected benefit obligations Discount rate 3.8 % 3.6 % 4.0 % 3.9 % 3.5 % 4.0 % Rate of salary increase 3.2 % 3.2 % 3.7 % 2.8 % 3.1 % 3.3 % Net benefit cost Discount rate 3.6 % 4.0 % 4.2 % 3.4 % 4.0 % 4.1 % Rate of return on plan assets 6.8 % 6.5 % 6.5 % 7.4 % 7.2 % 7.2 % Rate of salary increase 3.2 % 3.7 % 3.6 % 2.9 % 3.3 % 3.2 %
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 defined benefit OPEB plans: Canada United States December 31, 2018 2017 2018 2017 (millions of Canadian dollars) Change in accumulated postretirement benefit obligation Accumulated postretirement benefit obligation at beginning of year 321 179 337 133 Service cost 8 7 3 5 Interest cost 10 10 10 10 Participant contributions — — 6 4 Actuarial gain (45 ) (8 ) (25 ) (34 ) Benefits paid (11 ) (10 ) (29 ) (19 ) Plan amendments — (3 ) (8 ) 1 Acquired in Merger Transaction — 146 — 254 Foreign currency exchange rate changes — — 27 (17 ) Other (1 ) — (16 ) — Accumulated postretirement benefit obligation at end of year 282 321 305 337 Change in plan assets Fair value of plan assets at beginning of year — — 213 115 Actual return/(loss) on plan assets — — (13 ) 21 Employer contributions 11 10 8 1 Participant contributions — — 6 4 Benefits paid (11 ) (10 ) (29 ) (19 ) Acquired in Merger Transaction — — — 102 Foreign currency exchange rate changes — — 16 (11 ) Other — — (20 ) — Fair value of plan assets at end of year — — 181 213 Underfunded status at end of year (282 ) (321 ) (124 ) (124 ) Presented as follows: Deferred amounts and other assets — — 2 7 Accounts payable and other (12 ) (12 ) (7 ) (7 ) Other long-term liabilities (270 ) (309 ) (119 ) (124 ) (282 ) (321 ) (124 ) (124 )
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 2018 2017 2018 2017 Health care cost trend rate assumed for next year 5.6 % 5.5 % 7.4 % 7.4 % Rate to which the cost trend is assumed to decline (the ultimate trend rate) 4.4 % 4.4 % 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, 2018 : Canada United States 1% Increase 1% Decrease 1% Increase 1% Decrease (millions of Canadian dollars) Effect on total service and interest costs 1 (1 ) 1 (1 ) Effect on accumulated postretirement benefit obligation 20 (16 ) 18 (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 2018 2017 Allocation 2018 2017 Equity securities 40.0 - 70.0% 45.8 % 52.0 % 52.5 - 70.0% 51.7 % 47.1 % Fixed income securities 27.5 - 60.0% 33.4 % 34.2 % 27.5 - 30.0% 32.9 % 47.7 % Other 0.0 - 20.0% 20.7 % 13.8 % 0.0 - 20.0% 15.4 % 5.2 %
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: Pension Canada United States December 31, 2018 2017 2018 2017 (millions of Canadian dollars) Balance at beginning of year 340 281 56 40 Unrealized and realized gains 77 26 9 5 Purchases and settlements, net 145 33 65 11 Balance at end of year 562 340 130 56 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, 2018 Cash and cash equivalents 246 — — 246 56 — — 56 Equity securities Canada 623 — — 623 1 — — 1 United States (1 ) — — (1 ) 50 — — 50 Global 993 — — 993 489 — — 489 Fixed income securities Government 661 — — 661 265 — — 265 Corporate 457 — 60 517 54 — 25 79 Infrastructure and real estate 4 — — 502 502 — — 105 105 Forward currency contracts — (18 ) — (18 ) — — — — Total pension plan assets at fair value 2,979 (18 ) 562 3,523 915 — 130 1,045 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 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, 2018 Cash and cash equivalents — — — — 7 — — 7 Equity securities United States — — — — 63 — — 63 Global — — — — 35 — — 35 Fixed income securities Government — — — — 68 — — 68 Corporate — — — — 3 — 2 5 Infrastructure and real estate — — — — — — 3 3 Total OPEB plan assets at fair value — — — — 176 — 5 181 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 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, 2019 2020 2021 2022 2023 2023-2027 (millions of Canadian dollars) Pension Canada 174 180 187 194 201 1,104 United States 124 96 97 98 95 438 OPEB Canada 13 12 13 13 13 39 United States 26 26 25 24 23 98

CHANGES IN OPERATING ASSETS A_2

CHANGES IN OPERATING ASSETS AND LIABILITIES (Tables)	12 Months Ended
	Dec. 31, 2018
CHANGES IN OPERATING ASSETS AND LIABILITIES
Schedule of changes in operating assets and liabilities	Year ended December 31, 2018 2017 2016 (millions of Canadian dollars) Accounts receivable and other 857 (783 ) (437 ) Accounts receivable from affiliates 54 24 (7 ) Inventory 164 (289 ) (371 ) Deferred amounts and other assets 226 (138 ) (183 ) Accounts payable and other (151 ) 277 386 Accounts payable to affiliates (122 ) (62 ) 71 Interest payable 25 124 20 Other long-term liabilities (138 ) 509 153 915 (338 ) (368 )

COMMITMENTS AND CONTINGENCIES (

COMMITMENTS AND CONTINGENCIES (Tables)	12 Months Ended
	Dec. 31, 2018
Commitments and Contingencies Disclosure [Abstract]
Schedule of commitments	At December 31, 2018 , 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 62,967 3,255 9,262 2,389 4,571 5,963 37,527 Interest obligations 2 30,236 2,459 2,279 2,103 2,022 1,883 19,490 Purchase of services, pipe and other materials, including transportation 3,4 11,084 3,833 1,473 1,225 1,025 501 3,027 Operating leases 1,079 132 134 100 98 93 522 Capital leases 23 7 — — 2 2 12 Maintenance agreements 477 52 51 51 50 22 251 Land lease commitments 651 21 21 21 21 22 545 Total 106,517 9,759 13,220 5,889 7,789 8,486 61,374 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 Includes debentures and term notes bearing interest at fixed, floating and fixed-to-floating rates. 3 Includes capital and operating commitments. 4 Consists primarily of gas transportation and storage contracts, firm capacity payments and gas purchase commitments, transportation, service and product purchase obligations, and power commitments.

QUARTERLY FINANCIAL DATA (Table

QUARTERLY FINANCIAL DATA (Tables)	12 Months Ended
	Dec. 31, 2018
Quarterly Financial Information Disclosure [Abstract]
Quarterly Financial Information	Q1 Q2 Q3 Q4 Total (unaudited; millions of Canadian dollars, except per share amounts) 2018 Operating revenues 12,726 10,745 11,345 11,562 46,378 Operating income 878 1,571 854 1,513 4,816 Earnings 510 1,327 213 1,283 3,333 Earnings attributable to controlling interests 534 1,160 4 1,184 2,882 Earnings/(loss) attributable to common shareholders 445 1,071 (90 ) 1,089 2,515 Earnings/(loss) per common share Basic 0.26 0.63 (0.05 ) 0.60 1.46 Diluted 0.26 0.63 (0.05 ) 0.60 1.46 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/(loss) 945 1,241 1,015 65 3,266 Earnings/(loss) attributable to controlling interests 721 1,000 847 291 2,859 Earnings/(loss) attributable to common shareholders 638 919 765 207 2,529 Earnings/(loss) 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 1 The 2017 quarterly financial data reflects the effect of the Merger Transaction closed on February 27, 2017 (Note 8) .

BUSINESS OVERVIEW (Details)

BUSINESS OVERVIEW (Details) $ in Millions	Feb. 27, 2017CAD ($)shares	Dec. 31, 2018operating_segment
Business Acquisition [Line Items]
Number of operating segments | operating_segment		5
Spectra Energy Corp
Business Acquisition [Line Items]
Purchase price | $	$ 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%

SIGNIFICANT ACCOUNTING POLICI_3

SIGNIFICANT ACCOUNTING POLICIES (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018CAD ($)reporting_unit	Dec. 31, 2017CAD ($)	Dec. 31, 2016CAD ($)
Cash and Cash Equivalents [Line Items]
Net cash (used in) provided by financing activities	$ (7,503)	$ 3,476	$ 840
Number of reporting units | reporting_unit	2
Restatement Adjustment
Cash and Cash Equivalents [Line Items]
Net cash (used in) provided by financing activities			$ 300

SIGNIFICANT ACCOUNTING POLICI_4

SIGNIFICANT ACCOUNTING POLICIES - REGULATION (Details)	Dec. 31, 2018CAD ($)
Deferral for Depreciation for Phase-In Plans under U.S. GAAP Guidance
REGULATION
Regulatory assets	$ 0

SIGNIFICANT ACCOUNTING POLICI_5

SIGNIFICANT ACCOUNTING POLICIES - REVENUE RECOGNITION (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Disaggregation of Revenue [Line Items]
Revenue recognized	$ 183
Transportation revenue
Disaggregation of Revenue [Line Items]
Revenue recognized	$ 208	$ 196	$ 249

SIGNIFICANT ACCOUNTING POLICI_6

SIGNIFICANT ACCOUNTING POLICIES - PROPERTY, PLANT AND EQUIPMENT (Details)	12 Months Ended
	Dec. 31, 2018number_of_primary_method_of_depreciation
Accounting Policies [Abstract]
Number of primary methods of depreciation which are utilized	2

SIGNIFICANT ACCOUNTING POLICI_7

SIGNIFICANT ACCOUNTING POLICIES - STOCK-BASED COMPENSATION (Details)	12 Months Ended
	Dec. 31, 2018
Restricted Stock Units (RSU)
STOCK-BASED COMPENSATION
Vesting period	35 months

CHANGES IN ACCOUNTING POLICIE_2

CHANGES IN ACCOUNTING POLICIES - Schedule of Impact from Adoption of ASC 606 (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Jan. 01, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Assets
Deferred amounts and other assets	$ 8,558	$ 6,272	$ 6,442
Property, plant and equipment, net	94,540	90,823	90,711
Liabilities and equity
Accounts payable and other	9,836	9,540	9,478
Other long-term liabilities	8,834	7,576	7,510
Deferred income taxes	9,454	9,233	9,295
Redeemable noncontrolling interests	0	4,029	4,067	$ 3,392	$ 2,141
Deficit	$ (5,538)	(2,554)	(2,468)
Calculated under Revenue Guidance in Effect before Topic 606
Assets
Deferred amounts and other assets			6,442
Property, plant and equipment, net			90,711
Liabilities and equity
Accounts payable and other			9,478
Other long-term liabilities			7,510
Deferred income taxes			9,295
Redeemable noncontrolling interests			4,067
Deficit			$ (2,468)
Accounting Standards Update 2014-09 | Difference between revenue guidance in effect before and after Topic 606
Assets
Deferred amounts and other assets		(170)
Property, plant and equipment, net		112
Liabilities and equity
Accounts payable and other		62
Other long-term liabilities		66
Deferred income taxes		(62)
Redeemable noncontrolling interests		(38)
Deficit		$ (86)

CHANGES IN ACCOUNTING POLICIE_3

CHANGES IN ACCOUNTING POLICIES (Details) - Accounting Standards Update 2016-02 - Scenario, Forecast $ in Millions	Jan. 01, 2019CAD ($)
Minimum
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operating lease, liability	$ 750
Maximum
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operating lease, liability	$ 900

REVENUE (Details)

REVENUE (Details) - CAD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									$ 21,150
Total operating revenues (Note 4)	$ 11,562	$ 11,345	$ 10,745	$ 12,726	$ 12,889	$ 9,227	$ 11,116	$ 11,146	46,378	$ 44,378	$ 34,560
Transferred at Point in Time
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									1,658
Transferred over Time
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									19,492
Transportation revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									13,291
Storage and Other Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									519
Gas Gathering and Processing Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									815
Gas distribution sales
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									4,376
Total operating revenues (Note 4)									4,360	4,215	2,486
Electricity and Transmission Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									559
Commodity sales
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									1,590
Revenue not from contract with customers									26,070
Total operating revenues (Note 4)									27,660	26,286	22,816
Other Revenue
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									(842)
Liquids Pipelines
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									8,589
Liquids Pipelines | Transferred at Point in Time
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									0
Liquids Pipelines | Transferred over Time
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									8,589
Gas Transmission and Midstream
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									6,555
Gas Transmission and Midstream | Transferred at Point in Time
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									1,590
Gas Transmission and Midstream | Transferred over Time
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									4,965
Gas Distribution
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									5,447
Gas Distribution | Transferred at Point in Time
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									68
Gas Distribution | Transferred over Time
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									5,379
Green Power and Transmission
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									559
Green Power and Transmission | Transferred at Point in Time
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									0
Green Power and Transmission | Transferred over Time
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									559
Energy Services
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									0
Energy Services | Transferred at Point in Time
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									0
Energy Services | Transferred over Time
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									0
Business segments | Liquids Pipelines
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									8,589
Total operating revenues (Note 4)									8,079	8,913	8,176
Business segments | Liquids Pipelines | Transportation revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									8,488
Business segments | Liquids Pipelines | Storage and Other Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									101
Business segments | Liquids Pipelines | Gas Gathering and Processing Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									0
Business segments | Liquids Pipelines | Gas distribution sales
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									0
Business segments | Liquids Pipelines | Electricity and Transmission Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									0
Business segments | Liquids Pipelines | Commodity sales
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									0
Revenue not from contract with customers									0
Business segments | Liquids Pipelines | Other Revenue
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									(894)
Business segments | Gas Transmission and Midstream
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									6,555
Total operating revenues (Note 4)									6,571
Business segments | Gas Transmission and Midstream | Transportation revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									3,928
Business segments | Gas Transmission and Midstream | Storage and Other Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									222
Business segments | Gas Transmission and Midstream | Gas Gathering and Processing Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									815
Business segments | Gas Transmission and Midstream | Gas distribution sales
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									0
Business segments | Gas Transmission and Midstream | Electricity and Transmission Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									0
Business segments | Gas Transmission and Midstream | Commodity sales
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									1,590
Revenue not from contract with customers									0
Business segments | Gas Transmission and Midstream | Other Revenue
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									6
Business segments | Gas Distribution
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									5,447
Total operating revenues (Note 4)									5,470
Business segments | Gas Distribution | Transportation revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									875
Business segments | Gas Distribution | Storage and Other Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									196
Business segments | Gas Distribution | Gas Gathering and Processing Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									0
Business segments | Gas Distribution | Gas distribution sales
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									4,376
Business segments | Gas Distribution | Electricity and Transmission Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									0
Business segments | Gas Distribution | Commodity sales
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									0
Revenue not from contract with customers									0
Business segments | Gas Distribution | Other Revenue
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									9
Business segments | Green Power and Transmission
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									559
Total operating revenues (Note 4)									567	534	502
Business segments | Green Power and Transmission | Transportation revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									0
Business segments | Green Power and Transmission | Storage and Other Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									0
Business segments | Green Power and Transmission | Gas Gathering and Processing Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									0
Business segments | Green Power and Transmission | Gas distribution sales
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									0
Business segments | Green Power and Transmission | Electricity and Transmission Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									559
Business segments | Green Power and Transmission | Commodity sales
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									0
Revenue not from contract with customers									0
Business segments | Green Power and Transmission | Other Revenue
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									8
Business segments | Energy Services
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									0
Total operating revenues (Note 4)									26,228
Business segments | Energy Services | Transportation revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									0
Business segments | Energy Services | Storage and Other Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									0
Business segments | Energy Services | Gas Gathering and Processing Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									0
Business segments | Energy Services | Gas distribution sales
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									0
Business segments | Energy Services | Electricity and Transmission Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									0
Business segments | Energy Services | Commodity sales
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									0
Revenue not from contract with customers									26,070
Business segments | Energy Services | Other Revenue
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									4
Intersegment Eliminations
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									(562)
Total operating revenues (Note 4)									(537)	$ (410)	$ (335)
Intersegment Eliminations | Liquids Pipelines
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									384
Intersegment Eliminations | Gas Transmission and Midstream
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									10
Intersegment Eliminations | Gas Distribution
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									14
Intersegment Eliminations | Green Power and Transmission
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									0
Intersegment Eliminations | Energy Services
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									154
Consolidation, Eliminations
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									0
Total operating revenues (Note 4)									(537)
Consolidation, Eliminations | Transportation revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									0
Consolidation, Eliminations | Storage and Other Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									0
Consolidation, Eliminations | Gas Gathering and Processing Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									0
Consolidation, Eliminations | Gas distribution sales
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									0
Consolidation, Eliminations | Electricity and Transmission Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									0
Consolidation, Eliminations | Commodity sales
Disaggregation of Revenue [Line Items]
Revenue from contract with customer									0
Revenue not from contract with customers									0
Consolidation, Eliminations | Other Revenue
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers									$ 25

REVENUE - Contract Balances (De

REVENUE - Contract Balances (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Jan. 01, 2018
Revenue from Contract with Customer [Abstract]
Accounts receivable, net	$ 1,929	$ 2,475
Contract with customer, asset	191	290
Contract with customer, liability	$ 1,245	$ 992

REVENUE - Narrative (Details)

REVENUE - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018CAD ($)
Revenue from Contract with Customer [Abstract]
Revenue recognized	$ 183
Increase (decrease) in contract with customers, liability	449
Remaining performance obligation	67,400
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01
Revenue from Contract with Customer [Abstract]
Remaining performance obligation	$ 7,100
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligation, period	1 year

SEGMENTED INFORMATION (Details)

SEGMENTED INFORMATION (Details) - CAD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Segmented Information
Total operating revenues (Note 4)	$ 11,562	$ 11,345	$ 10,745	$ 12,726	$ 12,889	$ 9,227	$ 11,116	$ 11,146	$ 46,378	$ 44,378	$ 34,560
Commodity and gas distribution costs									(29,401)	(28,637)	(24,005)
Operating and administrative									(6,792)	(6,442)	(4,358)
Impairment of property, plant and equipment									(1,104)	(4,463)	(1,376)
Goodwill impairment									(1,019)	(102)	0
Income/(loss) from equity investments									1,509	1,102	428
Other income/(expense)									(52)	452	1,032
Earnings/(loss) before interest and income taxes									9,519	6,288	6,281
Depreciation and amortization									(3,246)	(3,163)	(2,240)
Interest expense									(2,703)	(2,556)	(1,590)
Income taxes									(237)	2,697	(142)
Earnings/(loss)									3,333	3,266	2,309
Capital expenditures									6,872	8,422	5,129
Total assets	166,905				162,093				166,905	162,093
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
Business segments | Liquids Pipelines
Segmented Information
Total operating revenues (Note 4)									8,079	8,913	8,176
Commodity and gas distribution costs									(16)	(18)	(12)
Operating and administrative									(3,124)	(2,949)	(2,908)
Impairment of property, plant and equipment									(180)	0	(1,365)
Goodwill impairment									0	0
Income/(loss) from equity investments									577	416	194
Other income/(expense)									(5)	33	841
Earnings/(loss) before interest and income taxes									5,331	6,395	4,926
Capital expenditures									3,102	2,799	3,957
Total assets	68,798				63,881				68,798	63,881
Business segments | Gas Transmission and Midstream
Segmented Information
Total operating revenues (Note 4)									6,571	7,067	2,877
Commodity and gas distribution costs									(1,481)	(2,834)	(2,206)
Operating and administrative									(2,102)	(1,756)	(446)
Impairment of property, plant and equipment									(914)	(4,463)	(11)
Goodwill impairment									(1,019)	(102)
Income/(loss) from equity investments									930	653	223
Other income/(expense)									349	166	27
Earnings/(loss) before interest and income taxes									2,334	(1,269)	464
Capital expenditures									2,644	4,016	176
Total assets	60,559				60,745				60,559	60,745
Business segments | Gas Distribution
Segmented Information
Total operating revenues (Note 4)									5,470	4,992	2,976
Commodity and gas distribution costs									(2,748)	(2,689)	(1,653)
Operating and administrative									(1,111)	(960)	(553)
Impairment of property, plant and equipment									0	0	0
Goodwill impairment									0	0
Income/(loss) from equity investments									11	23	12
Other income/(expense)									89	24	49
Earnings/(loss) before interest and income taxes									1,711	1,390	831
Capital expenditures									1,066	1,177	713
Total assets	25,748				25,956				25,748	25,956
Business segments | Green Power and Transmission
Segmented Information
Total operating revenues (Note 4)									567	534	502
Commodity and gas distribution costs									(7)	0	5
Operating and administrative									(157)	(163)	(173)
Impairment of property, plant and equipment									(4)	0	0
Goodwill impairment									0	0
Income/(loss) from equity investments									(28)	6	2
Other income/(expense)									(2)	(5)	8
Earnings/(loss) before interest and income taxes									369	372	344
Capital expenditures									33	321	251
Total assets	5,716				6,289				5,716	6,289
Business segments | Energy Services
Segmented Information
Total operating revenues (Note 4)									26,228	23,282	20,364
Commodity and gas distribution costs									(25,689)	(23,508)	(20,473)
Operating and administrative									(73)	(47)	(63)
Impairment of property, plant and equipment									0	0	0
Goodwill impairment									0	0
Income/(loss) from equity investments									18	8	(3)
Other income/(expense)									(2)	2	(8)
Earnings/(loss) before interest and income taxes									482	(263)	(183)
Capital expenditures									0	1	0
Total assets	1,042				2,514				1,042	2,514
Intersegment Eliminations
Segmented Information
Total operating revenues (Note 4)									(537)	(410)	(335)
Commodity and gas distribution costs									540	412	334
Operating and administrative									(225)	(567)	(215)
Impairment of property, plant and equipment									(6)	0	0
Goodwill impairment									0	0
Income/(loss) from equity investments									1	(4)	0
Other income/(expense)									(481)	232	115
Earnings/(loss) before interest and income taxes									(708)	(337)	(101)
Capital expenditures									27	108	$ 32
Total assets	$ 5,042				$ 2,708				$ 5,042	$ 2,708
Customer Concentration Risk | Sales Revenue, Net | Largest Non-Affiliated Customer
Out of period adjustments
Concentration risk, percentage										11.80%	18.00%
Customer Concentration Risk | Sales Revenue, Net | Second Largest Customer
Out of period adjustments
Concentration risk, percentage											10.40%

SEGMENTED INFORMATION - GEOGRAP

SEGMENTED INFORMATION - GEOGRAPHIC INFORMATION (Details) - CAD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Jan. 01, 2018
Geographic Information
Total operating revenues (Note 4)	$ 11,562	$ 11,345	$ 10,745	$ 12,726	$ 12,889	$ 9,227	$ 11,116	$ 11,146	$ 46,378	$ 44,378	$ 34,560
Property, plant and equipment, net	94,540				90,711				94,540	90,711		$ 90,823
Canada
Geographic Information
Total operating revenues (Note 4)									19,023	18,076	12,470
Property, plant and equipment, net	44,716				46,025				44,716	46,025
United States
Geographic Information
Total operating revenues (Note 4)									27,355	26,302	$ 22,090
Property, plant and equipment, net	$ 49,824				$ 44,686				$ 49,824	$ 44,686

EARNINGS PER COMMON SHARE (Deta

EARNINGS PER COMMON SHARE (Details) - $ / shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Earnings Per Share [Abstract]
Weighted average basic shares outstanding, pro forma (in shares)	12,000,000	13,000,000	13,000,000
Weighted average shares outstanding (in shares)	1,724,000,000	1,525,000,000	911,000,000
Effect of dilutive options (in shares)	3,000,000	7,000,000	7,000,000
Diluted weighted average shares outstanding (in shares)	1,727,000,000	1,532,000,000	918,000,000
Anti-dilutive stock options excluded from diluted earnings per common share calculation (in shares)	26,837,822	14,271,615	10,803,672
Weighted average exercise price of anti-dilutive stock options (in CAD per share)	$ 50.38	$ 56.71	$ 52.92

REGULATORY MATTERS - Liquids Pi

REGULATORY MATTERS - Liquids Pipelines (Narrative) (Details)	12 Months Ended
	Dec. 31, 2018
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, 2018	Dec. 31, 2017
Public Utilities, General Disclosures [Line Items]
Approved deferred rebasing period	5 years
Maximum allowable rate of return on equity not requiring an earnings sharing mechanism	1.50%
After-tax rate of return on common equity embedded in rates (as a percent)	9.00%	8.80%
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, 2018
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 ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Liquids Pipelines | Tolling deferrals
Regulatory Liabilities [Line Items]
Regulatory (liabilities)	$ (28)	$ (34)
Liquids Pipelines | Pipeline future abandonment costs
Regulatory Liabilities [Line Items]
Regulatory (liabilities)	(201)	(141)
Liquids Pipelines | Deferred income taxes
Regulatory Assets [Line Items]
Regulatory assets	1,673	1,492
Liquids Pipelines | Recoverable income taxes
Regulatory Assets [Line Items]
Regulatory assets	27	46
Gas Transmission and Midstream | Regulatory liability related to income taxes2
Regulatory Liabilities [Line Items]
Regulatory (liabilities)	(912)	(1,078)
Gas Transmission and Midstream | Other
Regulatory Liabilities [Line Items]
Regulatory (liabilities)		(16)
Gas Transmission and Midstream | Deferred income taxes
Regulatory Assets [Line Items]
Regulatory assets	826	717
Gas Transmission and Midstream | Other
Regulatory Assets [Line Items]
Regulatory assets	94
Gas Distribution | Future removal and site restoration reserves5
Regulatory Liabilities [Line Items]
Regulatory (liabilities)	(1,107)	(1,066)
Gas Distribution | Site restoration clearance adjustment
Regulatory Liabilities [Line Items]
Regulatory (liabilities)	0	(31)
Gas Distribution | Other
Regulatory Liabilities [Line Items]
Regulatory (liabilities)	(4)
Gas Distribution | Deferred income taxes
Regulatory Assets [Line Items]
Regulatory assets	1,132	1,000
Gas Distribution | Purchased gas variance
Regulatory Assets [Line Items]
Regulatory assets	197	51
Gas Distribution | Pension plans and OPEB
Regulatory Assets [Line Items]
Regulatory assets	118	102
Gas Distribution | Constant dollar net salvage adjustment
Regulatory Assets [Line Items]
Regulatory assets	$ 6	38
Gas Distribution | Other
Regulatory Assets [Line Items]
Regulatory assets		$ 31

REGULATORY MATTERS - Operating

REGULATORY MATTERS - Operating Cost Capitalization (Narrative) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Costs capitalized to Property, plant and equipment, net | Enbridge Gas Distribution
Schedule of Capitalization [Line Items]
Net book value of capitalized costs	$ 110	$ 118

ACQUISITIONS AND DISPOSITIONS -

ACQUISITIONS AND DISPOSITIONS - Acquisitions (Narrative) (Details) $ in Millions	Feb. 27, 2017CAD ($)shares	Apr. 01, 2016CAD ($)	Dec. 31, 2016CAD ($)	Dec. 31, 2017CAD ($)	Dec. 31, 2018CAD ($)reporting_unit	Dec. 31, 2017CAD ($)	Dec. 31, 2016CAD ($)	Feb. 27, 2017$ / shares
Business Acquisition [Line Items]
Number of reporting units | reporting_unit					2
Cash consideration					$ 0	$ 0	$ 644
Spectra Energy
Business Acquisition [Line Items]
Purchase price	$ 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	$ 3
Acquisition-related expenses/transaction costs incurred					$ 231
Costs incurred						180	51
Revenues generated by acquiree				$ 5,740
Earnings generated by acquiree				$ 2,574
Cash consideration	$ 3
Pro forma revenues						$ 45,669	40,934
Tupper Main and Tupper West
Business Acquisition [Line Items]
Acquisition-related expenses/transaction costs incurred		$ 1
Revenues generated by acquiree			$ 33
Cash consideration		$ 539
Earnings before interest and income taxes of acquiree			$ 22
Pro forma revenues							44
Pro forma earnings before interest and income taxes							$ 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	$ 37,429
Share options | Spectra Energy
Business Acquisition [Line Items]
Shares paid as consideration (in shares) | shares	3,500,000
Value of shares issued	$ 77
Gas Transmission and Midstream
Business Acquisition [Line Items]
Number of reporting units | reporting_unit					2

ACQUISITIONS AND DISPOSITIONS_2

ACQUISITIONS AND DISPOSITIONS - Summary of Estimated Fair Values Assigned to Net Assets (Details) shares in Millions, $ in Millions	Feb. 27, 2017CAD ($)shares	Dec. 31, 2017CAD ($)	Dec. 31, 2018CAD ($)	Dec. 31, 2017CAD ($)	Dec. 31, 2016CAD ($)	Feb. 27, 2017$ / shares
Fair value of net assets acquired:
Goodwill (Note 16)		$ 34,457	$ 34,459	$ 34,457
Purchase price:
Cash			0	0	$ 644
Fair value adjustment to long-term debt related to rate-regulated entities		1,114	964	1,114
Decrease to deferred amounts and other assets			$ 226	$ (138)	$ (183)
Spectra Energy
Fair value of net assets acquired:
Current assets	$ 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 16)	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	$ 77
Spectra Energy | Spectra Energy Partners, LP
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	$ 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	$ 1,824

ACQUISITIONS AND DISPOSITIONS_3

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

ACQUISITIONS AND DISPOSITIONS_4

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

ACQUISITIONS AND DISPOSITIONS_5

ACQUISITIONS AND DISPOSITIONS - Schedule of Final Purchase Price Allocation (Details) - CAD ($) $ in Millions	Apr. 01, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Purchase price:
Cash		$ 0	$ 0	$ 644
Tupper Main and Tupper West
Fair value of net assets acquired:
Property, plant and equipment	$ 288
Intangible assets	251
Fair value of net assets acquired	539
Purchase price:
Cash	$ 539

ACQUISITIONS AND DISPOSITIONS_6

ACQUISITIONS AND DISPOSITIONS - Other Acquisitions (Narrative) (Details) $ in Millions	Nov. 02, 2016USD ($)	Nov. 02, 2016CAD ($)	Sep. 09, 2016USD ($)MW	Sep. 09, 2016CAD ($)MW	Feb. 27, 2015USD ($)	Feb. 27, 2015CAD ($)	Nov. 30, 2015USD ($)MW	Nov. 30, 2015CAD ($)MW	Dec. 31, 2018CAD ($)	Dec. 31, 2017CAD ($)	Dec. 31, 2016CAD ($)	Nov. 02, 2016CAD ($)	Sep. 09, 2016CAD ($)	Nov. 30, 2015CAD ($)	Feb. 27, 2015CAD ($)
Business Acquisition [Line Items]
Cash consideration | $									$ 0	$ 0	$ 644,000,000
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	$ 30	$ 40,000,000	$ 50	$ 65,000,000
Purchase price allocated to property, plant and equipment	$ 17		$ 48									$ 23,000,000	$ 62,000,000
Pro forma effect on earnings | $		$ 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							$ 36	$ 48,000,000
Purchase price allocated to property, plant and equipment							$ 26							$ 35,000,000
Midstream Business
Business Acquisition [Line Items]
Cash consideration					$ 85	$ 106,000,000
Purchase price allocated to property, plant and equipment					55										$ 69,000,000
Contingent future payment (up to)					$ 17										$ 21,000,000

ACQUISITIONS AND DISPOSITIONS_7

ACQUISITIONS AND DISPOSITIONS - Assets Held for Sale (Narrative) (Details) $ in Millions, $ in Millions	1 Months Ended		12 Months Ended
	Aug. 31, 2017USD ($)	Aug. 31, 2017CAD ($)	Dec. 31, 2018CAD ($)	Dec. 31, 2017CAD ($)	Dec. 31, 2016CAD ($)	Jun. 30, 2019CAD ($)	Oct. 01, 2018CAD ($)	Jul. 04, 2018CAD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Goodwill (Note 16)			$ 34,459	$ 34,457
Goodwill impairment			1,019	$ 102	$ 0
Disposal group, held-for-sale, not discontinued operations | Enbridge Gas New Brunswick
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal group, consideration			331
Goodwill (Note 16)			133
Disposal group, held-for-sale, not discontinued operations | Canadian Natural Gas Gathering and Processing Business
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal group, consideration								$ 4,300
Goodwill (Note 16)			55
Goodwill impairment			1,019
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Canadian Natural Gas Gathering and Processing Business
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal group, consideration							$ 2,500
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	$ 70	$ 96
Scenario, Forecast | Disposal Group, Disposed of by Sale, Not Discontinued Operations | Canadian Natural Gas Gathering and Processing Business
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal group, consideration						$ 1,800
Asset Impairment | Disposal group, held-for-sale, not discontinued operations | Line 10 Crude Oil
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Discontinued operation, provision for loss (gain) on disposal, before income tax			154
Discontinued operation, provision for loss (gain) on disposal, net of tax			$ 95

ACQUISITIONS AND DISPOSITIONS_8

ACQUISITIONS AND DISPOSITIONS - Schedule of Net Assets Held for Sale (Details) - Disposal group, held-for-sale, not discontinued operations - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Accounts receivable and other (current assets held for sale)	$ 117	$ 424
Deferred amounts and other assets (long-term assets held for sale)	2,383	1,190
Accounts payable and other (current liabilities held for sale)	(63)	(315)
Other long-term liabilities (long-term liabilities held for sale)	(96)	(34)
Net assets held for sale	2,341	1,265
Disposal group, property, plant and equipment, noncurrent	$ 2,100	$ 1,100

ACQUISITIONS AND DISPOSITIONS_9

ACQUISITIONS AND DISPOSITIONS - Dispositions (Narrative) (Details) € in Millions, $ in Millions, $ in Millions	Oct. 01, 2018CAD ($)	Aug. 01, 2018USD ($)	Aug. 01, 2018CAD ($)	Aug. 01, 2018EUR (€)	Jul. 31, 2017USD ($)	Jul. 31, 2017CAD ($)	Mar. 01, 2017USD ($)	Mar. 01, 2017CAD ($)	Dec. 01, 2016CAD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2018CAD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2017CAD ($)	Dec. 31, 2016CAD ($)	Dec. 31, 2018CAD ($)	Aug. 01, 2018CAD ($)	Jul. 04, 2018CAD ($)	Jun. 30, 2018CAD ($)	Feb. 08, 2017
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Deferred income tax (recovery)/expense											$ (148)		$ (2,877)	$ 43
Goodwill													34,457		$ 34,459
Impairment loss											1,104		4,463	1,376
Goodwill impairment											1,019		102	0
Gain on disposal of assets											(8)		120	$ 848
Gas Transmission and Midstream
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Goodwill													20,997		20,777
Impairment loss													4,400
Impairment loss, after-tax													2,800
Goodwill impairment											1,019		102
Liquids Pipelines
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Goodwill													7,786		8,324
Goodwill impairment											0		0
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Canadian Natural Gas Gathering and Processing Business
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal group, consideration	$ 2,500
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Canadian Renewable Assets
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain on disposal of interest			$ 62
Disposal Group, Disposed of by Sale, Not Discontinued Operations | United States Renewable Assets
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain on disposal of interest		$ 13	17
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Liquids Pipelines | Sandpiper
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash proceeds from sale of assets										$ 30	38	$ 111	148
Gain on disposal of assets										22	29	$ 63	83
Disposal Group, Disposed of by Sale, Not Discontinued Operations | 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					$ 160	$ 203
Disposal Group, Disposed of by Sale, Not Discontinued Operations | 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							$ 220	$ 294
Gain on disposal of assets							$ 10	$ 14
Disposal Group, Disposed of by Sale, Not Discontinued Operations | 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									$ 1,100
Disposal group, held-for-sale, not discontinued operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Other long-term liabilities (long-term liabilities held for sale)													$ 34		96
Disposal group, held-for-sale, not discontinued operations | Canadian Natural Gas Gathering and Processing Business
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal group, consideration																	$ 4,300
Goodwill															55
Goodwill impairment											1,019
Disposal group, held-for-sale, not discontinued operations | Texas Express Ngl System
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Equity investment																$ 447		$ 447
Goodwill																		$ 262
Other income/(expense) | Disposal Group, Disposed of by Sale, Not Discontinued Operations | Canadian Natural Gas Gathering and Processing Business
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain on disposal of interest	$ 34
Other income/(expense) | Disposal Group, Disposed of by Sale, Not Discontinued Operations | Hohe See Offshore Wind Project
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain on disposal of interest			20	€ 14
Other income/(expense) | Disposal Group, Disposed of by Sale, Not Discontinued Operations | Liquids Pipelines | Olympic Pipeline
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain on disposal of interest					$ 21	$ 27
Other income/(expense) | Disposal Group, Disposed of by Sale, Not Discontinued Operations | 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									$ 850
Asset Impairment | Disposal group, held-for-sale, not discontinued operations | Midcoast Operating L.P.
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Discontinued operation, provision for loss (gain) on disposal, before income tax											913
Discontinued operation, provision for loss (gain) on disposal, net of tax											701
Canadian Renewable Assets | Discontinued Operations, Disposed of by Sale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Noncontrolling interest, ownership percentage by parent		49.00%														49.00%
United States Renewable Assets | Discontinued Operations, Disposed of by Sale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Noncontrolling interest, ownership percentage by parent		49.00%														49.00%
Hohe See Offshore Wind Project
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Ownership interest of equity method investment (as a percent)																			50.00%
Hohe See Offshore Wind Project | Discontinued Operations, Disposed of by Sale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Ownership interest of equity method investment (as a percent)		49.00%														49.00%
The Assets [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale of equity method investments			1,750
Deferred income tax (recovery)/expense											(196)
The Assets [Member] | Renewable energy assets
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Noncontrolling interest, ownership percentage by parent		51.00%														51.00%
Renewable energy assets | The Assets [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Deferred income tax (recovery)/expense											$ (267)
Enbridge (U.S.) Inc. | Disposal Group, Disposed of by Sale, Not Discontinued Operations | Midcoast Operating L.P.
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal group, consideration		$ 1,100														$ 1,400
Gain on disposal of interest		32	$ 41
Other long-term liabilities (long-term liabilities held for sale)		$ 298														$ 387
Accounts payable and other | Enbridge (U.S.) Inc. | Disposal Group, Disposed of by Sale, Not Discontinued Operations | Midcoast Operating L.P.
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Other long-term liabilities (long-term liabilities held for sale)										58					79
Other Long-Term Liabilities [Member] | Enbridge (U.S.) Inc. | Disposal Group, Disposed of by Sale, Not Discontinued Operations | Midcoast Operating L.P.
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Other long-term liabilities (long-term liabilities held for sale)										$ 216					$ 296

ACQUISITIONS AND DISPOSITION_10

ACQUISITIONS AND DISPOSITIONS - Other Disposition (Narrative) (Details) $ in Millions	1 Months Ended
	Dec. 31, 2016CAD ($)
Other miscellaneous non-core assets | Disposal Group, Disposed of by Sale, Not Discontinued Operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash proceeds	$ 286

ACCOUNTS RECEIVABLE AND OTHER_2

ACCOUNTS RECEIVABLE AND OTHER (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Receivables [Abstract]
Trade receivables and unbilled revenues	$ 4,711	$ 5,325
Short-term portion of derivative assets	498	296
Other	1,308	1,432
Accounts receivable and other	6,517	7,053
Allowance for doubtful accounts receivable	$ 64	$ 50

INVENTORY (Details)

INVENTORY (Details) - CAD ($)	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Inventory Disclosure [Abstract]
Natural gas	$ 776,000,000	$ 695,000,000
Crude oil	482,000,000	744,000,000
Other commodities	81,000,000	89,000,000
Total	1,339,000,000	1,528,000,000
Inventory adjustments	$ 93,000,000	$ 0	$ 0

PROPERTY, PLANT AND EQUIPMENT -

PROPERTY, PLANT AND EQUIPMENT - Schedule of Property, Plant and Equipment (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Jan. 01, 2018	Dec. 31, 2017
PROPERTY, PLANT AND EQUIPMENT
Total property, plant and equipment	$ 112,184		$ 105,813
Total accumulated depreciation	(17,644)		(15,102)
Property, plant and equipment, net	$ 94,540	$ 90,823	90,711
Pipelines
PROPERTY, PLANT AND EQUIPMENT
Weighted Average Depreciation Rate	2.60%
Total property, plant and equipment	$ 50,078		47,720
Pumping equipment, buildings, tanks and other
PROPERTY, PLANT AND EQUIPMENT
Weighted Average Depreciation Rate	3.00%
Total property, plant and equipment	$ 16,935		16,610
Land and right-of-way1
PROPERTY, PLANT AND EQUIPMENT
Weighted Average Depreciation Rate	2.70%
Total property, plant and equipment	$ 2,603		2,538
Gas mains, services and other
PROPERTY, PLANT AND EQUIPMENT
Weighted Average Depreciation Rate	3.20%
Total property, plant and equipment	$ 17,474		17,026
Compressors, meters and other operating equipment
PROPERTY, PLANT AND EQUIPMENT
Weighted Average Depreciation Rate	1.70%
Total property, plant and equipment	$ 5,893		5,774
Processing and treating plants
PROPERTY, PLANT AND EQUIPMENT
Weighted Average Depreciation Rate	1.50%
Total property, plant and equipment	$ 1,634		1,440
Storage
PROPERTY, PLANT AND EQUIPMENT
Weighted Average Depreciation Rate	1.90%
Total property, plant and equipment	$ 1,713		1,545
Wind turbines, solar panels and other
PROPERTY, PLANT AND EQUIPMENT
Weighted Average Depreciation Rate	4.20%
Total property, plant and equipment	$ 5,063		4,804
Power transmission
PROPERTY, PLANT AND EQUIPMENT
Weighted Average Depreciation Rate	2.60%
Total property, plant and equipment	$ 383		365
Vehicles, office furniture, equipment and other buildings and improvements
PROPERTY, PLANT AND EQUIPMENT
Weighted Average Depreciation Rate	5.90%
Total property, plant and equipment	$ 630		390
Under construction
PROPERTY, PLANT AND EQUIPMENT
Weighted Average Depreciation Rate	0.00%
Total property, plant and equipment	$ 9,778		$ 7,601

PROPERTY, PLANT AND EQUIPMENT_2

PROPERTY, PLANT AND EQUIPMENT - Narrative (Details) - CAD ($) $ in Millions	Nov. 29, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
PROPERTY, PLANT AND EQUIPMENT
Depreciation expense		$ 2,900	$ 2,900	$ 2,000
Impairment loss		$ 1,104	$ 4,463	1,376
Northern Gateway Project
PROPERTY, PLANT AND EQUIPMENT
Impairment loss	$ 373
Impairment loss, after-tax	$ 272
Sandpiper Project
PROPERTY, PLANT AND EQUIPMENT
Impairment loss				992
Impairment loss, after-tax				81
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				$ 11

VARIABLE INTEREST ENTITIES - CO

VARIABLE INTEREST ENTITIES - CONSOLIDATED VARIABLE INTEREST ENTITIES (Narrative) (Details)	Aug. 01, 2018	Dec. 31, 2018	Dec. 31, 2017
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%
Enbridge Canadian Renewable LP (ECRLP) | Canada Pension Plan Investment Board (CPPIB)
Schedule of Equity Method Investments [Line Items]
Direct common interest (as a percent)	49.00%
EEP
Schedule of Equity Method Investments [Line Items]
Economic interest (as a percent)		100.00%	34.60%
Enbridge Income Fund
Schedule of Equity Method Investments [Line Items]
Direct common interest (as a percent)			29.40%
Economic interest (as a percent)		100.00%	82.50%
EIPLP
Schedule of Equity Method Investments [Line Items]
Direct common interest (as a percent)			53.10%
Economic interest (as a percent)		100.00%	73.50%
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%
Spectra Energy Partners, LP
Schedule of Equity Method Investments [Line Items]
Direct common interest (as a percent)		100.00%	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 ($) $ in Millions	Dec. 31, 2018	Jan. 01, 2018	Dec. 31, 2017
Assets
Cash and cash equivalents	$ 518		$ 480
Restricted cash	119		107
Accounts receivable and other	6,517		7,053
Accounts receivable from affiliates	79		47
Inventory	1,339		1,528
Total Current assets	8,572		9,215
Property, plant and equipment, net	94,540	$ 90,823	90,711
Long-term investments	16,707		16,644
Restricted long-term investments	323		267
Deferred amounts and other assets	8,558	6,272	6,442
Intangible assets, net	2,372		3,267
Goodwill	34,459		34,457
Deferred income taxes	1,374		1,090
Total assets	166,905		162,093
Liabilities
Short-term borrowings	1,024		1,444
Accounts payable and other	9,836	9,540	9,478
Accounts payable to affiliates	40		157
Interest payable	669		634
Environmental liabilities	27		40
Current portion of long-term debt	3,259		2,871
Total Current liabilities	14,855		14,624
Long-term debt	60,327		60,865
Other long-term liabilities	8,834	$ 7,576	7,510
Deferred income taxes	8,080		8,205
Total Liabilities	93,470		92,294
Variable Interest Entity, Primary Beneficiary
Assets
Cash and cash equivalents	506		368
Restricted cash	27		0
Accounts receivable and other	2,073		2,132
Accounts receivable from affiliates	5		3
Inventory	244		220
Total Current assets	2,855		2,723
Property, plant and equipment, net	72,737		68,685
Long-term investments	6,481		6,258
Restricted long-term investments	244		206
Deferred amounts and other assets	3,156		2,921
Intangible assets, net	317		296
Goodwill	29		29
Deferred income taxes	131		145
Total assets	85,950		81,263
Liabilities
Short-term borrowings	275		485
Accounts payable and other	2,925		2,859
Accounts payable to affiliates	4		131
Interest payable	303		312
Environmental liabilities	22		35
Current portion of long-term debt	1,034		2,129
Total Current liabilities	4,563		5,951
Long-term debt	29,577		31,469
Other long-term liabilities	5,074		4,301
Deferred income taxes	6,911		3,010
Total Liabilities	46,125		44,731
Net assets before noncontrolling interests	$ 39,825		$ 36,532

VARIABLE INTEREST ENTITIES - UN

VARIABLE INTEREST ENTITIES - UNCONSOLIDATED VARIABLE INTEREST ENTITIES (Narrative) (Details) - USD ($)	Aug. 01, 2018	Dec. 31, 2018	Apr. 30, 2018
Sabal Trail
Variable Interest Entity [Line Items]
Direct common interest (as a percent)		50.00%
Canada Pension Plan Investment Board (CPPIB) | Enbridge Renewable Infrastructure Investments S.a.r.l. (ERII)
Variable Interest Entity [Line Items]
Direct common interest (as a percent)	49.00%
Spectra Energy Partners, LP | Sabal Trail
Variable Interest Entity [Line Items]
Proceeds from issuance of debt		$ 744,000,000
Enbridge Renewable Infrastructure Investments S.a.r.l. (ERII)
Variable Interest Entity [Line Items]
Ownership interest of equity method investment (as a percent)	51.00%
4.246% Senior Notes Due In 2028 | Spectra Energy Partners, LP | Sabal Trail
Variable Interest Entity [Line Items]
Principal Amount			$ 500,000,000
Fixed interest rate (as a percent)			4.25%
4.682% Senior Notes Due in 2038 | Spectra Energy Partners, LP | Sabal Trail
Variable Interest Entity [Line Items]
Principal Amount			$ 600,000,000
Fixed interest rate (as a percent)			4.68%
4.832% Senior Notes Due In 2048 | Spectra Energy Partners, LP | Sabal Trail
Variable Interest Entity [Line Items]
Principal Amount			$ 400,000,000
Fixed interest rate (as a percent)			4.83%

VARIABLE INTEREST ENTITIES - _2

VARIABLE INTEREST ENTITIES - Schedule of the Carrying Amount of Interest in VIEs (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Variable Interest Entity, Not Primary Beneficiary
VARIABLE INTEREST ENTITY
Carrying Amount of Investment in VIE	$ 3,947	$ 5,821
Maximum Exposure to Loss	9,162	9,815
Aux Sable Liquid Products L.P.
VARIABLE INTEREST ENTITY
Carrying Amount of Investment in VIE	311	300
Maximum Exposure to Loss	375	361
Eolien Maritime France SAS
VARIABLE INTEREST ENTITY
Carrying Amount of Investment in VIE	68	69
Maximum Exposure to Loss	784	754
Affiliate loan receivable	202
Enbridge Renewable Infrastructure Investments S.a.r.l. (ERII)
VARIABLE INTEREST ENTITY
Carrying Amount of Investment in VIE	127
Maximum Exposure to Loss	3,250
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	724	686
Maximum Exposure to Loss	724	686
Nexus Gas Transmission, LLC
VARIABLE INTEREST ENTITY
Carrying Amount of Investment in VIE	1,757	834
Maximum Exposure to Loss	2,668	1,678
PennEast Pipeline Company, LLC
VARIABLE INTEREST ENTITY
Carrying Amount of Investment in VIE	97	69
Maximum Exposure to Loss	385	345
Rampion Offshore Wind Limited
VARIABLE INTEREST ENTITY
Carrying Amount of Investment in VIE	638	555
Maximum Exposure to Loss	648	679
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	198	169
Maximum Exposure to Loss	301	278
Affiliate loan receivable	102
Other
VARIABLE INTEREST ENTITY
Carrying Amount of Investment in VIE	27	21
Maximum Exposure to Loss	$ 27	$ 21

LONG-TERM INVESTMENTS - Schedul

LONG-TERM INVESTMENTS - Schedule of Long-Term Investments (Details) $ in Millions, $ in Billions	Aug. 01, 2018CAD ($)	Dec. 31, 2018CAD ($)	Jun. 30, 2018CAD ($)	Dec. 31, 2017CAD ($)	Apr. 27, 2017	Feb. 15, 2017USD ($)	Feb. 15, 2017CAD ($)	Feb. 08, 2017
LONG-TERM INVESTMENTS
Total long-term investments		$ 16,707		$ 16,644
Disposal group, held-for-sale, not discontinued operations | Texas Express Ngl System
LONG-TERM INVESTMENTS
EQUITY INVESTMENTS	$ 447		$ 447
Enbridge Renewable Infrastructure Investments S.a.r.l. (ERII) | Canada Pension Plan Investment Board (CPPIB)
LONG-TERM INVESTMENTS
Direct common interest (as a percent)	49.00%
Noverco | Common shares
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)		38.90%		38.90%
Noverco | Gas Distribution | Common shares
LONG-TERM INVESTMENTS
EQUITY INVESTMENTS		$ 0		$ 0
Noverco | Gas Distribution | Preference shares
LONG-TERM INVESTMENTS
OTHER LONG-TERM INVESTMENTS		$ 478		371
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						$ 1.5	$ 2,000
Bakken Pipeline System | Liquids Pipelines
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)		27.60%
EQUITY INVESTMENTS		$ 2,039		1,938
Seaway | Liquids Pipelines
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)		50.00%
EQUITY INVESTMENTS		$ 3,113		2,882
Illinois Extension Pipeline Company, L.L.C.2 | Liquids Pipelines
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)		65.00%
EQUITY INVESTMENTS		$ 724		686
Alliance Pipeline | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)		50.00%
EQUITY INVESTMENTS		$ 368		375
Aux Sable | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
EQUITY INVESTMENTS		$ 311		300
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		$ 2,368		2,143
Gulfstream Natural Gas System, L.L.C. | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)		50.00%
EQUITY INVESTMENTS		$ 1,289		1,205
Nexus Gas Transmission, LLC | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)		50.00%
EQUITY INVESTMENTS		$ 1,757		834
Offshore - various joint ventures | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
EQUITY INVESTMENTS		$ 400		389
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		$ 97		69
Sabal Trail Transmission, LLC | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)		50.00%
EQUITY INVESTMENTS		$ 1,586		2,355
Southeast Supply Header L.L.C. | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)		50.00%
EQUITY INVESTMENTS		$ 519		486
Steckman Ridge LP | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)		49.50%
EQUITY INVESTMENTS		$ 237		221
Texas Express Pipeline6 | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)		35.00%
EQUITY INVESTMENTS		$ 0		430
Vector Pipeline L.P. | Gas Transmission and Midstream
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)		60.00%
EQUITY INVESTMENTS		$ 198		169
Eolien Maritime France SAS | Green Power and Transmission
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)		50.00%
EQUITY INVESTMENTS		$ 68		69
Enbridge Renewable Infrastructure Investments S.a.r.l. (ERII) | Green Power and Transmission
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)		25.50%
EQUITY INVESTMENTS		$ 127		763
Rampion Offshore Wind Project | Green Power and Transmission
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)		24.90%
EQUITY INVESTMENTS		$ 638		555
Emerging Technologies and Other | Green Power and Transmission
LONG-TERM INVESTMENTS
OTHER LONG-TERM INVESTMENTS		80		80
Other equity investments | Liquids Pipelines
LONG-TERM INVESTMENTS
EQUITY INVESTMENTS		$ 97		87
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		$ 6		34
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)		50.00%
Other equity investments | Gas Distribution | Common shares
LONG-TERM INVESTMENTS
Ownership Interest (as a percent)		50.00%
EQUITY INVESTMENTS		$ 15		15
Other equity investments | Green Power and Transmission
LONG-TERM INVESTMENTS
EQUITY INVESTMENTS		$ 72		95
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		$ 10		26
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 long-term investments | Eliminations and Other
LONG-TERM INVESTMENTS
OTHER LONG-TERM INVESTMENTS		$ 110		$ 67

LONG-TERM INVESTMENTS - Summary

LONG-TERM INVESTMENTS - Summary of Combined Financial Information (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income statement information
Operating revenues	$ 19,217	$ 16,213	$ 4,102
Operating expenses	15,634	13,197	3,344
Earnings/(loss)	2,954	2,728	641
Earnings attributable to controlling interests	1,382	1,262	469
Balance sheet information
Current assets	3,289	3,538
Non-current assets	49,116	45,026
Current liabilities	5,536	3,454
Non-current liabilities	15,875	13,595
Noncontrolling interests	3,479	3,191
Seaway
Income statement information
Operating revenues	966	959	938
Operating expenses	212	286	293
Earnings/(loss)	646	672	643
Earnings attributable to controlling interests	323	336	322
Balance sheet information
Current assets	113	106
Non-current assets	3,585	3,329
Current liabilities	123	143
Non-current liabilities	16	13
Noncontrolling interests	0	0
Other
Income statement information
Operating revenues	18,251	15,254	3,164
Operating expenses	15,422	12,911	3,051
Earnings/(loss)	2,308	2,056	(2)
Earnings attributable to controlling interests	1,059	926	$ 147
Balance sheet information
Current assets	3,176	3,432
Non-current assets	45,531	41,697
Current liabilities	5,413	3,311
Non-current liabilities	15,859	13,582
Noncontrolling interests	$ 3,479	$ 3,191

LONG-TERM INVESTMENTS - Narrati

LONG-TERM INVESTMENTS - Narrative (Details) shares in Millions, $ in Millions, $ in Billions	1 Months Ended		12 Months Ended
	Dec. 31, 2018CAD ($)shares	Feb. 29, 2016shares	Dec. 31, 2018CAD ($)	Dec. 31, 2017CAD ($)	Dec. 31, 2016CAD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2017CAD ($)
Schedule of Equity Method Investments [Line Items]
Goodwill of investee	$ 2,200		$ 2,200				$ 2,000
Amortizable assets of investee	$ 706		706				643
Dividends received from equity investments			$ 2,800	$ 1,400	$ 825
Gas Transmission and Midstream | Sabal Trail
Schedule of Equity Method Investments [Line Items]
Ownership interest (as a percent)	50.00%		50.00%
Equity Method Investments, fair value						$ 1.9	$ 2,300
Common shares | Noverco
Schedule of Equity Method Investments [Line Items]
Ownership interest (as a percent)	38.90%		38.90%			38.90%	38.90%
Reciprocal shareholding (as a percent)	1.40%		1.40%			1.90%	1.90%
Equity Method Investment, number of shares sold (in shares) | shares	4.4
Equity Method Investment, number of shares purchased (in shares) | shares		1.2
Indirect pro-rata interest (as a percent)	0.50%		0.50%			0.70%	0.70%
Reduction from reciprocal shareholding			$ 88	$ 102
Preference shares | Noverco
Schedule of Equity Method Investments [Line Items]
Maturity period			10 years
Margin (as a percent)	4.38%		4.38%

RESTRICTED LONG-TERM INVESTME_2

RESTRICTED LONG-TERM INVESTMENTS (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Assets Held-in-trust [Abstract]
Restricted long-term investments	$ 323	$ 267
Future abandonment costs	$ 212	$ 151

INTANGIBLE ASSETS (Details)

INTANGIBLE ASSETS (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
INTANGIBLE ASSETS
Cost	$ 3,357	$ 4,138
Accumulated Amortization	985	871
Net	2,372	3,267
Amortization expenses
Amortization expense for intangible assets	281	$ 280	$ 177
Expected amortization expense for intangible assets
2,019	278
2,020	251
2,021	227
2,022	205
2,023	$ 186
Customer relationships
INTANGIBLE ASSETS
Weighted Average Amortization Rate (as a percent)	5.00%	3.50%
Cost	$ 762	$ 967
Accumulated Amortization	70	41
Net	$ 692	$ 926
Power purchase agreements
INTANGIBLE ASSETS
Weighted Average Amortization Rate (as a percent)	4.40%	3.50%
Cost	$ 96	$ 99
Accumulated Amortization	21	17
Net	$ 75	$ 82
Project agreement
INTANGIBLE ASSETS
Weighted Average Amortization Rate (as a percent)	4.00%	4.00%
Cost	$ 164	$ 150
Accumulated Amortization	10	3
Net	$ 154	$ 147
Software
INTANGIBLE ASSETS
Weighted Average Amortization Rate (as a percent)	11.40%	11.30%
Cost	$ 1,827	$ 1,760
Accumulated Amortization	814	714
Net	$ 1,013	$ 1,046
Other intangible assets
INTANGIBLE ASSETS
Weighted Average Amortization Rate (as a percent)	4.10%	4.40%
Cost	$ 508	$ 1,162
Accumulated Amortization	70	96
Net	$ 438	$ 1,066

GOODWILL (Details)

GOODWILL (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Gross Cost
Goodwill, gross at beginning of period	$ 35,019	$ 538
Acquired in Merger Transaction (Note 7)		36,656
Sabal Trail deconsolidation (Note 12)		(966)
Disposition	(628)	(29)
Allocation to assets held for sale	(188)
Foreign exchange and other	1,837	(1,180)
Goodwill, gross at end of period	36,040	35,019	$ 538
Accumulated Impairment
Goodwill, impaired, accumulated impairment loss at beginning of period	(562)	(460)
Impairment	(1,019)	(102)	0
Goodwill, impaired, accumulated impairment loss at end of period	(1,581)	(562)	(460)
Goodwill	34,459	34,457
Consolidation, Eliminations
Gross Cost
Goodwill, gross at beginning of period	13	13
Acquired in Merger Transaction (Note 7)		0
Sabal Trail deconsolidation (Note 12)		0
Disposition	0	0
Allocation to assets held for sale	0
Foreign exchange and other	0	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	7,786	59
Acquired in Merger Transaction (Note 7)		8,070
Sabal Trail deconsolidation (Note 12)		0
Disposition	0	(29)
Allocation to assets held for sale	0
Foreign exchange and other	538	(314)
Goodwill, gross at end of period	8,324	7,786	59
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	8,324	7,786
Gas Transmission & Midstream
Gross Cost
Goodwill, gross at beginning of period	21,539	457
Acquired in Merger Transaction (Note 7)		22,914
Sabal Trail deconsolidation (Note 12)		(966)
Disposition	(628)	0
Allocation to assets held for sale	(55)
Foreign exchange and other	1,482	(866)
Goodwill, gross at end of period	22,338	21,539	457
Accumulated Impairment
Goodwill, impaired, accumulated impairment loss at beginning of period	(542)	(440)
Impairment	(1,019)	(102)
Goodwill, impaired, accumulated impairment loss at end of period	(1,561)	(542)	(440)
Goodwill	20,777	20,997
Gas Distribution
Gross Cost
Goodwill, gross at beginning of period	5,679	7
Acquired in Merger Transaction (Note 7)		5,672
Sabal Trail deconsolidation (Note 12)		0
Disposition	0	0
Allocation to assets held for sale	(133)
Foreign exchange and other	(183)	0
Goodwill, gross at end of period	5,363	5,679	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	5,356	5,672
Green Power and Transmission
Gross Cost
Goodwill, gross at beginning of period	0	0
Acquired in Merger Transaction (Note 7)		0
Sabal Trail deconsolidation (Note 12)		0
Disposition	0	0
Allocation to assets held for sale	0
Foreign exchange and other	0	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
Acquired in Merger Transaction (Note 7)		0
Sabal Trail deconsolidation (Note 12)		0
Disposition	0	0
Allocation to assets held for sale	0
Foreign exchange and other	0	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	$ 0
Goodwill	$ 2	$ 2

GOODWILL GOODWILL - NARRATIVE (

GOODWILL GOODWILL - NARRATIVE (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Feb. 27, 2017
GOODWILL
Goodwill impairment	$ 1,019	$ 102	$ 0
Goodwill, write of due to deconsolidation		966
Goodwill, written off related to sale of business unit	628	29
Goodwill	34,459	34,457
Spectra Energy Corp
GOODWILL
Goodwill				$ 36,656
Gas Transmission and Midstream
GOODWILL
Goodwill impairment	1,019	102
Goodwill, write of due to deconsolidation		966
Goodwill, written off related to sale of business unit	628	0
Goodwill	20,777	20,997
Liquids Pipelines
GOODWILL
Goodwill impairment	0	0
Goodwill, write of due to deconsolidation		0
Goodwill, written off related to sale of business unit	0	29
Goodwill	8,324	$ 7,786
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Midcoast Operating L.P.
GOODWILL
Goodwill, write of due to deconsolidation	262
Disposal Group, Disposed of by Sale, Not Discontinued Operations | Canadian Natural Gas Gathering and Processing Business
GOODWILL
Goodwill, write of due to deconsolidation	366
Disposal group, held-for-sale, not discontinued operations | Canadian Natural Gas Gathering and Processing Business
GOODWILL
Goodwill impairment	1,019
Goodwill	55
Disposal group, held-for-sale, not discontinued operations | Enbridge Gas New Brunswick
GOODWILL
Goodwill	$ 133

ACCOUNTS PAYABLE AND OTHER (Det

ACCOUNTS PAYABLE AND OTHER (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Jan. 01, 2018	Dec. 31, 2017
Payables and Accruals [Abstract]
Trade payables and operating accrued liabilities	$ 4,604		$ 5,135
Construction payables and contractor holdbacks	804		706
Current derivative liabilities	1,234		1,130
Dividends payable	1,539		1,169
Taxes payable	801		522
Other	854		816
Accounts payable and other liabilities	$ 9,836	$ 9,540	$ 9,478

DEBT - Schedule of Debt (Detail

DEBT - Schedule of Debt (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)	Dec. 31, 2018CAD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2017CAD ($)
DEBT
Total debt		$ 64,610		$ 65,180
Fair value adjustment - Spectra Energy acquisition		964		1,114
Other		(348)		(312)
Current maturities		(3,259)		(2,871)
Short-term borrowings		(1,024)		(1,444)
Long-term debt		$ 60,327		$ 60,865
Weighted average interest rate (as a percent)	2.30%	2.30%	1.40%	1.40%
United States dollar term notes | Enbridge Inc.
DEBT
Weighted Average Interest Rate	4.10%	4.10%
Total debt	$ 4,700	$ 6,419	$ 4,700	$ 5,889
Medium-term notes | Enbridge Inc.
DEBT
Weighted Average Interest Rate	4.30%	4.30%
Total debt		$ 7,323		5,698
Medium-term notes | Enbridge Gas Distribution Inc.
DEBT
Weighted Average Interest Rate	4.50%	4.50%
Total debt		$ 3,695		3,695
Medium-term notes | Enbridge Income Fund
DEBT
Total debt		$ 0		1,750
Medium-term notes | Enbridge Pipelines Inc.
DEBT
Weighted Average Interest Rate	4.30%	4.30%
Total debt		$ 4,225		4,525
Carrying value		$ 100
Medium-term notes | Union Gas Limited
DEBT
Weighted Average Interest Rate	4.10%	4.10%
Total debt		$ 3,290		3,490
Medium-term notes | Westcoast Energy Inc.
DEBT
Weighted Average Interest Rate	4.70%	4.70%
Total debt		$ 2,175		2,177
Fixed-to-floating subordinated term notes | Enbridge Inc.
DEBT
Weighted Average Interest Rate	5.90%	5.90%
Total debt	$ 3,200	$ 6,771	1,750	3,843
Term of fixed rate	10 years
Carrying value		2,400		1,650
Floating rate notes | Enbridge Inc.
DEBT
Total debt		2,389		2,254
Carrying value	$ 1,200	750	1,200	750
Floating rate notes | Spectra Energy Partners, LP
DEBT
Total debt	$ 400	546	400	501
Commercial paper and credit facility draws
DEBT
Long-term debt		$ 7,967		10,055
Commercial paper and credit facility draws | Enbridge Inc.
DEBT
Weighted Average Interest Rate	2.20%	2.20%
Total debt		$ 1,999		2,729
Carrying value	$ 69		907
Long-term Line of Credit		$ 1,906		1,593
Commercial paper and credit facility draws | Enbridge (U.S.) Inc.
DEBT
Weighted Average Interest Rate	3.50%	3.50%
Total debt	$ 780	$ 1,065	391	490
Commercial paper and credit facility draws | Enbridge Energy Partners, L.P.
DEBT
Weighted Average Interest Rate	3.30%	3.30%
Total debt	$ 764	$ 1,044	1,453	1,820
Commercial paper and credit facility draws | Enbridge Gas Distribution Inc.
DEBT
Weighted Average Interest Rate	2.30%	2.30%
Total debt		$ 750		960
Commercial paper and credit facility draws | Enbridge Income Fund
DEBT
Total debt		$ 0		755
Commercial paper and credit facility draws | Enbridge Pipelines Inc.
DEBT
Weighted Average Interest Rate	2.40%	2.40%
Total debt	$ 216	$ 2,200	286	1,438
Long-term Line of Credit		$ 1,905		1,080
Commercial paper and credit facility draws | Spectra Energy Partners, LP
DEBT
Weighted Average Interest Rate	3.20%	3.20%
Total debt	$ 1,512	$ 2,065	2,254	2,824
Commercial paper and credit facility draws | Union Gas Limited
DEBT
Weighted Average Interest Rate	2.30%	2.30%
Total debt		$ 275		485
Other | Enbridge Inc.
DEBT
Total debt		0		3
Other | Enbridge Pipelines Inc.
DEBT
Total debt		$ 4		4
Senior notes | Enbridge Energy Partners, L.P.
DEBT
Weighted Average Interest Rate	6.20%	6.20%
Total debt	$ 4,550	$ 6,214	5,050	6,328
Senior notes | Enbridge Pipelines (Southern Lights) L.L.C.
DEBT
Weighted Average Interest Rate	4.00%	4.00%
Total debt	$ 920	$ 1,257	963	1,207
Senior notes | Enbridge Southern Lights LP
DEBT
Weighted Average Interest Rate	4.00%	4.00%
Total debt		$ 289		315
Senior notes | Midcoast Energy Partners, L.P.
DEBT
Total debt		$ 0	400	501
Senior notes | Spectra Energy
DEBT
Weighted Average Interest Rate	7.10%	7.10%
Total debt	$ 173	$ 236	1,329	1,665
Senior notes | Spectra Energy Partners, LP
DEBT
Weighted Average Interest Rate	4.30%	4.30%
Total debt	$ 6,040	$ 8,249	5,740	7,192
Junior subordinated notes | Enbridge Energy Partners, L.P.
DEBT
Total debt	$ 400	$ 546	400	501
Debentures | Enbridge Gas Distribution Inc.
DEBT
Weighted Average Interest Rate	9.90%	9.90%
Total debt		$ 85		85
Debentures | Enbridge Pipelines Inc.
DEBT
Weighted Average Interest Rate	8.20%	8.20%
Total debt		$ 200		200
Debentures | Union Gas Limited
DEBT
Weighted Average Interest Rate	8.70%	8.70%
Total debt		$ 125		250
Debentures | Westcoast Energy Inc.
DEBT
Weighted Average Interest Rate	8.60%	8.60%
Total debt		$ 375		525
Senior secured notes | Spectra Energy Partners, LP
DEBT
Weighted Average Interest Rate	6.10%	6.10%
Total debt	$ 110	$ 150	$ 110	138
Senior secured notes | Westcoast Energy Inc.
DEBT
Weighted Average Interest Rate	6.20%	6.20%
Total debt		$ 33		66
Senior debentures | Union Gas Limited
DEBT
Total debt		$ 0		$ 75
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) $ in Millions	Dec. 31, 2018CAD ($)
Debt Disclosure [Abstract]
Senior secured notes	$ 183

DEBT - Schedule of Committed Cr

DEBT - Schedule of Committed Credit Facilities (Details) - Dec. 31, 2018 $ in Millions, $ in Millions	USD ($)	CAD ($)
DEBT
Commitments that expire in 2020		$ 9,262
Commitments that expire in 2021		2,389
Committed credit facilities
DEBT
Total Facilities		18,308
Draws		9,417
Available		8,891
Enbridge (U.S.) Inc. | Committed credit facilities
DEBT
Total Facilities		1,932
Draws		1,065
Available		867
Enbridge Energy Partners, L.P. | Committed credit facilities
DEBT
Total Facilities		2,493
Draws		1,044
Available		1,449
Commitments that expire in 2020	$ 185	253
Enbridge Gas Distribution Inc. | Committed credit facilities
DEBT
Total Facilities		1,018
Draws		760
Available		258
Enbridge Pipelines Inc. | Committed credit facilities
DEBT
Total Facilities		3,000
Draws		2,200
Available		800
Spectra Energy Partners, LP | Committed credit facilities
DEBT
Total Facilities		3,414
Draws		2,065
Available		1,349
Commitments that expire in 2021	$ 336	421
Union Gas Limited | Committed credit facilities
DEBT
Total Facilities		700
Draws		275
Available		425
Enbridge Inc. | Committed credit facilities
DEBT
Total Facilities		5,751
Draws		2,008
Available		$ 3,743

DEBT - Credit Facilities (Narra

DEBT - Credit Facilities (Narrative) (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)	Dec. 31, 2018CAD ($)	Dec. 31, 2017CAD ($)
Line of Credit Facility [Line Items]
Line of credit facility, increase (decrease)		$ 390
Weighted average standby fee (as a percent)	0.20%	0.20%
Long-term debt		$ 60,327	$ 60,865
Uncommitted credit facilities
Line of Credit Facility [Line Items]
Term credit facility		807	792
Unutilized credit facility		548	518
Commercial paper and credit facility draws
Line of Credit Facility [Line Items]
Long-term debt		7,967	10,055
Enbridge Inc. | Credit Facility Maturing ind 2019
Line of Credit Facility [Line Items]
Extinguishment of debt	$ 650
Enbridge Inc. | Unutilized Enbridge Credit Facility
Line of Credit Facility [Line Items]
Extinguishment of debt	100
Enbridge (U.S.) Inc. | Credit Facility Maturing ind 2019
Line of Credit Facility [Line Items]
Extinguishment of debt	500
Enbridge (U.S.) Inc. | Unutilized Credit Facility Maturing in 2019
Line of Credit Facility [Line Items]
Extinguishment of debt	950
Enbridge Energy Partners, L.P.
Line of Credit Facility [Line Items]
Extinguishment of debt	$ 625
Enbridge Income Fund
Line of Credit Facility [Line Items]
Term credit facility			$ 1,500
Westcoast Energy Inc.
Line of Credit Facility [Line Items]
Extinguishment of debt		$ 400

DEBT - Schedule of Long-term De

DEBT - Schedule of Long-term Debt Issuances (Details)

1 Months Ended

Apr. 30, 2018USD ($)

Mar. 31, 2018USD ($)

Oct. 31, 2017USD ($)

Sep. 30, 2017CAD ($)

Jul. 31, 2017USD ($)

Jun. 30, 2017CAD ($)

May 31, 2017CAD ($)

Jun. 30, 2018USD ($)

Apr. 30, 2018CAD ($)

Jan. 31, 2018USD ($)

Nov. 30, 2017CAD ($)

Oct. 31, 2017CAD ($)

Enbridge Gas Distribution Inc. | 3.51% medium-term notes due November 2047

Debt Instrument [Line Items]

Principal Amount

$ 300,000,000

Fixed interest rate (as a percent)

3.51%

Spectra Energy Partners, LP | Floating rate notes due June 2020

Debt Instrument [Line Items]

Principal Amount

$ 400,000,000

Basis spread on variable rate (as a percent)

0.70%

Spectra Energy Partners, LP | 3.50% Senior Notes Due 2028 [Member]

Debt Instrument [Line Items]

Principal Amount

$ 400,000,000

Fixed interest rate (as a percent)

3.50%

Spectra Energy Partners, LP | 4.15% Senior Notes Due 2048 [Member]

Debt Instrument [Line Items]

Principal Amount

$ 400,000,000

Fixed interest rate (as a percent)

4.15%

Union Gas Limited | 2.88% medium-term notes due November 2027

Debt Instrument [Line Items]

Principal Amount

$ 250,000,000

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

$ 250,000,000

Fixed interest rate (as a percent)

3.59%

Enbridge Inc. | Fixed to Floating Rate Notes Due 2078

Debt Instrument [Line Items]

Principal Amount

$ 850,000,000

Term of credit facility

60 years

Callable period

10 years

Term of fixed rate

10 years

Fixed interest rate (as a percent)

6.25%

Enbridge Inc. | Fixed to Floating Rate Notes Due 2078, Issued April 2018

Debt Instrument [Line Items]

Principal Amount

$ 750,000,000

Term of credit facility

60 years

Callable period

10 years

Term of fixed rate

10 years

Fixed interest rate (as a percent)

6.625%

6.625%

Enbridge Inc. | Fixed to Floating Rate Notes Due 2078, US Based Issued April 2018

Debt Instrument [Line Items]

Principal Amount

$ 600,000,000

Term of credit facility

60 years

Callable period

5 years

Fixed interest rate (as a percent)

6.375%

6.375%

Enbridge Inc. | Floating rate notes due May 2019

Debt Instrument [Line Items]

Principal Amount

$ 750,000,000

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

$ 450,000,000

Fixed interest rate (as a percent)

3.19%

Enbridge Inc. | 3.20% medium-term notes due June 2027

Debt Instrument [Line Items]

Principal Amount

$ 450,000,000

Fixed interest rate (as a percent)

3.20%

Enbridge Inc. | 4.57% medium-term notes due March 2044

Debt Instrument [Line Items]

Principal Amount

$ 300,000,000

Fixed interest rate (as a percent)

4.57%

Enbridge Inc. | Floating rate notes due June 2020

Debt Instrument [Line Items]

Principal Amount

$ 500,000,000

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

$ 700,000,000

Fixed interest rate (as a percent)

2.90%

Enbridge Inc. | 3.70% senior notes due July 2027

Debt Instrument [Line Items]

Principal Amount

$ 700,000,000

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

$ 1,000,000,000

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

$ 1,000,000,000

$ 650,000,000

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

$ 700,000,000

Basis spread on variable rate (as a percent)

0.40%

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%

Debt Instrument, Redemption, Period One | Enbridge Inc. | Fixed to Floating Rate Notes Due 2078

Debt Instrument [Line Items]

Basis spread on variable rate (as a percent)

3.64%

Debt Instrument, Redemption, Period One | Enbridge Inc. | Fixed to Floating Rate Notes Due 2078, Issued April 2018

Debt Instrument [Line Items]

Basis spread on variable rate (as a percent)

4.32%

Debt Instrument, Redemption, Period One | Enbridge Inc. | Fixed to Floating Rate Notes Due 2078, US Based Issued April 2018

Debt Instrument [Line Items]

Basis spread on variable rate (as a percent)

3.59%

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 | Minimum | Enbridge Inc. | Fixed to Floating Rate Notes Due 2078

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 Notes Due 2078, Issued April 2018

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 Notes Due 2078, US Based Issued April 2018

Debt Instrument [Line Items]

Period when the notes carry a variable interest rate

5 years

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 | Maximum | Enbridge Inc. | Fixed to Floating Rate Notes Due 2078

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 Notes Due 2078, Issued April 2018

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 Notes Due 2078, US Based Issued April 2018

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 Two | Enbridge Inc. | Fixed to Floating Rate Notes Due 2078

Debt Instrument [Line Items]

Basis spread on variable rate (as a percent)

4.39%

Debt Instrument, Redemption, Period Two | Enbridge Inc. | Fixed to Floating Rate Notes Due 2078, Issued April 2018

Debt Instrument [Line Items]

Basis spread on variable rate (as a percent)

5.07%

Debt Instrument, Redemption, Period Two | Enbridge Inc. | Fixed to Floating Rate Notes Due 2078, US Based Issued April 2018

Debt Instrument [Line Items]

Basis spread on variable rate (as a percent)

3.84%

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 | Minimum | Enbridge Inc. | Fixed to Floating Rate Notes Due 2078

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 Notes Due 2078, Issued April 2018

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 Notes Due 2078, US Based Issued April 2018

Debt Instrument [Line Items]

Period when the notes carry a variable interest rate

10 years

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 | Maximum | Enbridge Inc. | Fixed to Floating Rate Notes Due 2078

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 Notes Due 2078, Issued April 2018

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 Notes Due 2078, US Based Issued April 2018

Debt Instrument [Line Items]

Period when the notes carry a variable interest rate

25 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 Three | Enbridge Inc. | Fixed to Floating Rate Notes Due 2078, US Based Issued April 2018

Debt Instrument [Line Items]

Basis spread on variable rate (as a percent)

4.59%

Debt Instrument, Redemption, Period Three | Minimum | Enbridge Inc. | Fixed to Floating Rate Notes Due 2078, US Based Issued April 2018

Debt Instrument [Line Items]

Period when the notes carry a variable interest rate

25 years

Debt Instrument, Redemption, Period Three | Maximum | Enbridge Inc. | Fixed to Floating Rate Notes Due 2078, US Based Issued April 2018

Debt Instrument [Line Items]

Period when the notes carry a variable interest rate

60 years

DEBT - Schedule of Long-Term _2

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

1 Months Ended

3 Months Ended

7 Months Ended

12 Months Ended

Dec. 31, 2018CAD ($)

Nov. 30, 2018CAD ($)

Oct. 31, 2018USD ($)

Oct. 31, 2018CAD ($)

Sep. 30, 2018USD ($)

Sep. 30, 2018CAD ($)

Aug. 31, 2018CAD ($)

Jul. 31, 2018USD ($)

Apr. 30, 2018USD ($)

Apr. 30, 2018CAD ($)

Mar. 31, 2018USD ($)

Dec. 31, 2017CAD ($)

Nov. 30, 2017CAD ($)

Sep. 30, 2017USD ($)

Jul. 31, 2017USD ($)

Jun. 30, 2017USD ($)

Jun. 30, 2017CAD ($)

Apr. 30, 2017USD ($)

Apr. 30, 2017CAD ($)

Mar. 31, 2017CAD ($)

Sep. 30, 2017USD ($)

Dec. 31, 2018USD ($)

Nov. 30, 2018CAD ($)

Dec. 31, 2017USD ($)

Nov. 30, 2017CAD ($)

Dec. 31, 2018USD ($)

Dec. 31, 2018CAD ($)

Dec. 31, 2017USD ($)

Dec. 31, 2017CAD ($)

Jun. 30, 2018

May 31, 2018

Jan. 31, 2018

Enbridge Energy Partners, L.P.

Debt Instrument [Line Items]

Extinguishment of debt

$ 625

Enbridge Energy Partners, L.P. | 6.50% senior notes

Debt Instrument [Line Items]

Extinguishment of debt

$ 400

Interest rate

6.50%

6.50%

Enbridge Energy Partners, L.P. | 7.00% Senior Notes [Member]

Debt Instrument [Line Items]

Extinguishment of debt

$ 100

Interest rate

7.00%

7.00%

7.00%

7.00%

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

Debt Instrument [Line Items]

Extinguishment of debt

$ 300

Interest rate

1.85%

1.85%

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

Debt Instrument [Line Items]

Extinguishment of debt

$ 200

Interest rate

5.16%

5.16%

5.16%

5.16%

Enbridge Income Fund | 4.00% Medium-Term Notes [Member]

Debt Instrument [Line Items]

Extinguishment of debt

$ 125

Interest rate

4.00%

4.00%

4.00%

4.00%

Enbridge Income Fund | 5.00% medium-term notes

Debt Instrument [Line Items]

Extinguishment of debt

$ 100

Interest rate

5.00%

5.00%

Enbridge Income Fund | 2.92% medium-term notes

Debt Instrument [Line Items]

Extinguishment of debt

$ 225

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]

Extinguishment of debt

$ 43

$ 37

Interest rate

3.98%

3.98%

3.98%

3.98%

3.98%

Enbridge Pipelines Inc. | 6.62% Medium-Term Notes

Debt Instrument [Line Items]

Extinguishment of debt

$ 170

Interest rate

6.62%

6.62%

Enbridge Pipelines Inc. | 6.62% Medium-Term Notes

Debt Instrument [Line Items]

Extinguishment of debt

$ 130

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

Debt Instrument [Line Items]

Extinguishment of debt

$ 7

$ 27

Interest rate

4.01%

4.01%

4.01%

Midcoast Energy Partner L.P. [Member] | 3.56% Senior Notes Due June 2019

Debt Instrument [Line Items]

Extinguishment of debt

$ 75

Cash Consideration

$ 76

Interest rate

3.56%

Midcoast Energy Partner L.P. [Member] | 4.04% Senior Notes Due June 2021

Debt Instrument [Line Items]

Extinguishment of debt

$ 175

Cash Consideration

$ 182

Interest rate

4.04%

Midcoast Energy Partner L.P. [Member] | 4.42% Senior Notes Due June 2024

Debt Instrument [Line Items]

Extinguishment of debt

$ 150

Cash Consideration

$ 161

Interest rate

4.42%

Spectra Energy Capital, LLC

Debt Instrument [Line Items]

Loss on extinguishment of debt

$ 50

64

$ 38

$ 50

Spectra Energy Capital, LLC | 6.75% Senior Unsecured Notes Due 2032

Debt Instrument [Line Items]

Extinguishment of debt

$ 64

Cash Consideration

$ 80

Interest rate

6.75%

Spectra Energy Capital, LLC | 7.50% Senior Unsecured Notes Due 2038

Debt Instrument [Line Items]

Extinguishment of debt

$ 43

Cash Consideration

$ 59

Interest rate

7.50%

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

Debt Instrument [Line Items]

Extinguishment of debt

$ 761

Cash Consideration

$ 857

Spectra Energy Capital, LLC | 5.65% Senior Unsecured Notes Due 2020

Debt Instrument [Line Items]

Extinguishment of debt

$ 163

Cash Consideration

$ 172

Interest rate

5.65%

Spectra Energy Capital, LLC | 3.30% Senior Unsecured Notes Due 2023

Debt Instrument [Line Items]

Extinguishment of debt

$ 498

Cash Consideration

$ 508

Interest rate

3.30%

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

Debt Instrument [Line Items]

Extinguishment of debt

$ 500

Cash Consideration

$ 581

Interest rate

8.00%

8.00%

Spectra Energy Capital, LLC | 6.20% Senior Notes

Debt Instrument [Line Items]

Extinguishment of debt

$ 272

Interest rate

6.20%

6.20%

Spectra Energy Capital, LLC | 6.75% Senior Notes

Debt Instrument [Line Items]

Extinguishment of debt

$ 118

Interest rate

6.75%

Spectra Energy Partners, LP | 2.95% Senior Notes

Debt Instrument [Line Items]

Extinguishment of debt

$ 500

Interest rate

2.95%

2.95%

Spectra Energy Partners, LP | 6.00% senior notes

Debt Instrument [Line Items]

Extinguishment of debt

$ 400

Interest rate

6.00%

6.00%

Spectra Energy Partners, LP | 7.39% subordinated secured notes

Debt Instrument [Line Items]

Extinguishment of debt

$ 12

Interest rate

7.39%

7.39%

7.39%

7.39%

Union Gas Limited | 5.35% Medium-Term Notes

Debt Instrument [Line Items]

Extinguishment of debt

$ 200

Interest rate

5.35%

5.35%

Union Gas Limited | 8.75% Debenture

Debt Instrument [Line Items]

Extinguishment of debt

$ 125

Interest rate

8.75%

Union Gas Limited | 8.65% Senior Debentures

Debt Instrument [Line Items]

Extinguishment of debt

$ 75

Interest rate

8.68%

8.68%

Union Gas Limited | 9.70% debentures

Debt Instrument [Line Items]

Extinguishment of debt

$ 125

Interest rate

9.70%

9.70%

Westcoast Energy Inc.

Debt Instrument [Line Items]

Extinguishment of debt

$ 400

Westcoast Energy Inc. | 6.90% senior secured notes due 2019

Debt Instrument [Line Items]

Extinguishment of debt

$ 26

$ 26

Interest rate

6.90%

6.90%

6.90%

Westcoast Energy Inc. | 4.34% senior secured notes due 2019

Debt Instrument [Line Items]

Extinguishment of debt

$ 9

$ 24

Interest rate

4.34%

4.34%

4.34%

Westcoast Energy Inc. | 8.50% Debenture

Debt Instrument [Line Items]

Extinguishment of debt

$ 150

Interest rate

8.50%

8.50%

Enbridge Inc. | Floating rate note

Debt Instrument [Line Items]

Extinguishment of debt

$ 500

$ 500

Enbridge Inc. | 5.60% medium-term notes

Debt Instrument [Line Items]

Extinguishment of debt

$ 400

Interest rate

5.60%

5.60%

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

Debt Instrument [Line Items]

Interest rate

3.30%

Maximum

Debt Instrument [Line Items]

Interest rate

7.50%

DEBT - Debt Exchange (Details)

DEBT - Debt Exchange (Details)	Dec. 21, 2018CAD ($)
Enbridge Inc. | 4.10% Medium-Term Notes Due February 2019
Debt Instrument [Line Items]
Principal Amount	$ 300,000,000
Fixed interest rate (as a percent)	4.10%
Enbridge Inc. | 4.85% Medium-Term Note Due November 2020
Debt Instrument [Line Items]
Principal Amount	$ 100,000,000
Fixed interest rate (as a percent)	4.85%
Enbridge Inc. | 4.85% Medium-Term Notes Due February 2022
Debt Instrument [Line Items]
Principal Amount	$ 200,000,000
Fixed interest rate (as a percent)	4.85%
Enbridge Inc. | 3.94% Medium-Term Notes Due January 2023
Debt Instrument [Line Items]
Principal Amount	$ 275,000,000
Fixed interest rate (as a percent)	3.94%
Enbridge Inc. | 3.95% Medium-Term Notes Due November 2024
Debt Instrument [Line Items]
Principal Amount	$ 500,000,000
Fixed interest rate (as a percent)	3.95%
Enbridge Inc. | 4.87% Medium-Term Notes Due November 2044
Debt Instrument [Line Items]
Principal Amount	$ 250,000,000
Fixed interest rate (as a percent)	4.87%
Enbridge Income Fund | 4.10% Medium-Term Notes Due February 2019
Debt Instrument [Line Items]
Fixed interest rate (as a percent)	4.10%
Enbridge Income Fund | 4.85% Medium-Term Note Due November 2020
Debt Instrument [Line Items]
Fixed interest rate (as a percent)	4.85%
Enbridge Income Fund | 4.85% Medium-Term Notes Due February 2022
Debt Instrument [Line Items]
Fixed interest rate (as a percent)	4.85%
Enbridge Income Fund | 3.94% Medium-Term Notes Due January 2023
Debt Instrument [Line Items]
Fixed interest rate (as a percent)	3.94%
Enbridge Income Fund | 3.95% Medium-Term Notes Due November 2024
Debt Instrument [Line Items]
Fixed interest rate (as a percent)	3.95%
Enbridge Income Fund | 4.87% Medium-Term Notes Due November 2044
Debt Instrument [Line Items]
Fixed interest rate (as a percent)	4.87%

DEBT - Schedule of Interest Exp

DEBT - Schedule of Interest Expense (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
DEBT
Capitalized	$ (348)	$ (391)	$ (321)
Total interest expense	2,703	2,556	1,590
Spectra Energy
DEBT
Amortization of fair value adjustment - Spectra Energy acquisition	(131)	(270)	0
Debentures and term notes
DEBT
Interest expense on debt	3,011	3,011	1,714
Commercial paper and credit facility draws
DEBT
Interest expense on debt	$ 171	$ 206	$ 197

ASSET RETIREMENT OBLIGATIONS (D

ASSET RETIREMENT OBLIGATIONS (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2017
Reconciliation of movements in the Company's ARO
Obligations at beginning of year	$ 793	$ 232
Liabilities acquired	0	546
Liabilities disposed	(13)	0
Liabilities incurred	145	0
Liabilities settled	(21)	(22)
Change in estimate	29	18
Foreign currency translation adjustment	22	(12)
Accretion expense	34	31
Obligations at end of year	989	793
Accounts payable and other			$ 6	$ 2
Other long-term liabilities			983	791
Asset retirement obligations	$ 793	$ 232	$ 989	$ 793
Minimum
Asset Retirement Obligations [Line Items]
Discount rate (as a percent)	1.80%
Maximum
Asset Retirement Obligations [Line Items]
Discount rate (as a percent)	9.00%

NONCONTROLLING INTERESTS - NONC

NONCONTROLLING INTERESTS - NONCONTROLLING (Details) - CAD ($) shares in Millions, $ in Millions	Nov. 29, 2018	Dec. 31, 2018	Aug. 01, 2018	Dec. 31, 2017
NONCONTROLLING INTERESTS
Noncontrolling interests		$ 3,965		$ 7,597
Algonquin Gas Transmission LLC
NONCONTROLLING INTERESTS
Noncontrolling interests		518		476
Enbridge Energy Management, L.L.C. (EEM)
NONCONTROLLING INTERESTS
Noncontrolling interests		0		34
Enbridge Energy Partners, L.P.
NONCONTROLLING INTERESTS
Noncontrolling interests		0		138
Enbridge Gas Distribution Inc.
NONCONTROLLING INTERESTS
Noncontrolling interests		0		100
Enbridge Gas Distribution Inc. | Preference shares
NONCONTROLLING INTERESTS
Stock redeemed during period (in shares)	4
Maritimes and Northeast Pipeline
NONCONTROLLING INTERESTS
Noncontrolling interests		613		572
Renewable energy assets
NONCONTROLLING INTERESTS
Noncontrolling interests		1,961		806
Spectra Energy
NONCONTROLLING INTERESTS
Noncontrolling interests		0		4,335
Union Gas Limited
NONCONTROLLING INTERESTS
Noncontrolling interests		0		110
Union Gas Limited | Preference shares
NONCONTROLLING INTERESTS
Stock redeemed during period (in shares)	4
Westcoast Energy Inc.
NONCONTROLLING INTERESTS
Noncontrolling interests		$ 841		$ 1,005
Westcoast Energy Inc. | Preference shares
NONCONTROLLING INTERESTS
Number of redeemable preferred shares held by noncontrolling owners (in shares)		16.6
Number of first preferred shares held by noncontrolling owners (in shares)				12
Other Non Controlling Interest
NONCONTROLLING INTERESTS
Noncontrolling interests		$ 32		$ 21
Enbridge Energy Management, L.L.C. (EEM)
NONCONTROLLING INTERESTS
Ownership interest percentage held by noncontrolling owners				88.30%
Enbridge Energy Partners, L.P.
NONCONTROLLING INTERESTS
Ownership interest percentage held by noncontrolling owners				68.20%
Canadian Renewable Assets | Discontinued Operations, Disposed of by Sale
NONCONTROLLING INTERESTS
Noncontrolling interest, ownership percentage by parent			49.00%
Magic Valley
NONCONTROLLING INTERESTS
Ownership interest percentage held by noncontrolling owners		20.00%		20.00%
Spectra Energy | Spectra Energy
NONCONTROLLING INTERESTS
Ownership interest percentage held by noncontrolling owners				25.70%
Maritimes and Northeast Pipeline
NONCONTROLLING INTERESTS
Ownership interest percentage held by noncontrolling owners		22.00%
Wildcat
NONCONTROLLING INTERESTS
Ownership interest percentage held by noncontrolling owners		20.00%		20.00%

NONCONTROLLING INTERESTS - NO_2

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

Sep. 17, 2018$ / shares

Jan. 22, 2018shares

Jun. 28, 2017USD ($)

Apr. 28, 2017CAD ($)

Apr. 27, 2017USD ($)$ / sharesshares

Sep. 30, 2018CAD ($)

Sep. 30, 2018CAD ($)

Dec. 31, 2018CAD ($)

Dec. 31, 2017CAD ($)

Dec. 31, 2016CAD ($)

Aug. 01, 2018

Apr. 28, 2017$ / shares

Feb. 15, 2017

NONCONTROLLING INTERESTS

Noncontrolling interest, decrease from purchase of interests

$ 4,469,000,000

$ 0

$ 0

Noncontrolling interests

3,965,000,000

7,597,000,000

Enbridge Gas Distribution Inc.

NONCONTROLLING INTERESTS

Noncontrolling interests

$ 0

100,000,000

Spectra Energy Partners, LP

NONCONTROLLING INTERESTS

Security shareholders entitlement share ratio

1.111

Stock issued during period, shares, conversion of units (in shares) | shares

172,500,000

Enbridge Energy Partners, L.P.

NONCONTROLLING INTERESTS

Security shareholders entitlement share ratio

0.335

Noncontrolling interests

$ 0

138,000,000

Common units, quarterly distribution per unit | $ / shares

$ 0.583

$ 0.35

Enbridge Energy Management, L.L.C. (EEM)

NONCONTROLLING INTERESTS

Security shareholders entitlement share ratio

0.335

Noncontrolling interests

$ 0

34,000,000

Enbridge Income Fund Holdings Inc

NONCONTROLLING INTERESTS

Security shareholders entitlement share ratio

0.735

Shareholder entitlement cash payment per share | $ / shares

$ 0.45

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

NONCONTROLLING INTERESTS

Increase to additional paid in capital

$ 421,000,000

Increase (decrease) to deferred income taxes

253,000,000

Increase (decrease) in noncontrolling interest

$ 458,000,000

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

NONCONTROLLING INTERESTS

Repayments of related party debt

$ 1,500

Enbridge Energy Partners and Enbridge Energy Management

NONCONTROLLING INTERESTS

Increase to additional paid in capital

3,700,000,000

Increase (decrease) to deferred income taxes

(707,000,000)

Increase (decrease) in noncontrolling interest

185,000,000

Spectra Energy Partners, LP

NONCONTROLLING INTERESTS

Noncontrolling interest, decrease from purchase of interests

3,000,000,000

Increase to additional paid in capital

642,000,000

Increase (decrease) to deferred income taxes

(167,000,000)

Midcoast Energy Partners, L.P.

NONCONTROLLING INTERESTS

Total ownership interest (as a percent)

100.00%

Midcoast Energy Partners, L.P. | Midcoast Public Unitholders

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

Enbridge Income Fund

NONCONTROLLING INTERESTS

Noncontrolling interest, decrease from purchase of interests

4,500,000,000

Increase to additional paid in capital

25,000,000

Increase (decrease) to deferred income taxes

0

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

NONCONTROLLING INTERESTS

Partners' capital account, redemptions

$ 1,200

Common Units Class A | 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%

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%

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%

Ownership interest (as a percent)

27.60%

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

NONCONTROLLING INTERESTS

Joint funding arrangement, ownership percentage

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%

Common shares

NONCONTROLLING INTERESTS

Common shares issued in acquisition, amount

12,727,000,000

Common shares | Enbridge Energy Partners, L.P.

NONCONTROLLING INTERESTS

Common shares issued in acquisition, amount

3,042,000,000

0

0

Common shares | Enbridge Energy Management, L.L.C. (EEM)

NONCONTROLLING INTERESTS

Common shares issued in acquisition, amount

1,267,000,000

0

0

Common shares | Spectra Energy Partners, LP

NONCONTROLLING INTERESTS

Common shares issued in acquisition, amount

3,888,000,000

0

0

Common shares | Enbridge Income Fund

NONCONTROLLING INTERESTS

Common shares issued in acquisition, amount

4,530,000,000

$ 0

$ 0

Noncontrolling Interest

NONCONTROLLING INTERESTS

Noncontrolling interest, decrease from purchase of interests

2,657,000,000

Sale of noncontrolling interest in subsidiaries

$ (1,183,000,000)

1,183,000,000

Noncontrolling interest, restructuring

$ 1,500,000,000

1,486,000,000

Additional paid-in capital

NONCONTROLLING INTERESTS

Sale of noncontrolling interest in subsidiaries

79,000,000

79,000,000

Dilution gain on Spectra Energy Partners, LP restructuring (Note 20)

1,100,000,000

$ 1,136,000,000

Deferred Income Tax Liability

NONCONTROLLING INTERESTS

Sale of noncontrolling interest in subsidiaries

$ 27,000,000

Canadian Renewable Assets | Discontinued Operations, Disposed of by Sale

NONCONTROLLING INTERESTS

Noncontrolling interest, ownership percentage by parent

49.00%

United States Renewable Assets | Discontinued Operations, Disposed of by Sale

NONCONTROLLING INTERESTS

Noncontrolling interest, ownership percentage by parent

49.00%

Spectra Energy Partners, LP

NONCONTROLLING INTERESTS

Noncontrolling interest, ownership percentage by parent

75.00%

Incentive Distribution Rights | Spectra Energy Partners, LP

NONCONTROLLING INTERESTS

Noncontrolling interest, ownership percentage by parent

100.00%

Enbridge Income Fund

NONCONTROLLING INTERESTS

Ownership interest percentage held by noncontrolling owners

56.50%

45.60%

Variable Interest Entity, Primary Beneficiary

NONCONTROLLING INTERESTS

Shares owned (in shares) | shares

403,000,000

Direct common interest (as a percent)

83.00%

Other Restructuring | Spectra Energy Partners, LP

NONCONTROLLING INTERESTS

Increase (decrease) to deferred income taxes

$ 333,000,000

NONCONTROLLING INTERESTS - REDE

NONCONTROLLING INTERESTS - REDEEMABLE NONCONTROLLING INFORMATION (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
REDEEMABLE NONCONTROLLING INTERESTS
Balance at beginning of year	$ 4,067	$ 3,392	$ 2,141
Earnings attributable to redeemable noncontrolling interests	117	175	268
Change in unrealized loss on cash flow hedges	3	(21)	(17)
Other comprehensive loss from equity investees	14	0	0
Reclassification to earnings of loss on cash flow hedges	0	57	9
Foreign currency translation adjustments	4	(6)	(3)
Other comprehensive income/(loss)	21	30	(11)
Distributions to unitholders	(300)	(247)	(202)
Contributions from unitholders	70	1,178	591
Modified retrospective adoption of ASC 606 Revenue from Contracts with Customers (Note 3)	(38)	0	0
Dilution gain/(loss) for redeemable noncontrolling interests	76	(169)	(81)
Redemption value adjustment	456	(292)	686
Sponsored vehicle buy-in	(4,469)	0	0
Balance at end of year	$ 0	$ 4,067	$ 3,392

SHARE CAPITAL - COMMON SHARES (

SHARE CAPITAL - COMMON SHARES (Details) $ / shares in Units, shares in Millions, $ in Billions	12 Months Ended
	Dec. 31, 2018USD ($)shares	Dec. 31, 2018CAD ($)$ / sharesshares	Dec. 31, 2017CAD ($)shares	Dec. 31, 2016CAD ($)shares
Share Capital
Common shares par value (in dollars per share) | $ / shares		$ 0
Common Shares
Balance at beginning of period (in shares) | shares	1,695	1,695
Balance at end of period (in shares) | shares	2,022	2,022	1,695
Gross proceeds	$ 0	$ 21,000,000	$ 1,549,000,000	$ 2,260,000,000
Issuance costs | $		$ 0	$ 0	$ 59,000,000
Common shares
Common Shares
Balance at beginning of period (in shares) | shares	1,695	1,695	943	868
Balance at beginning of period, Amount | $		$ 50,737,000,000	$ 10,492,000,000	$ 7,391,000,000
Common shares issued (in shares) | shares	0	0	33	56
Common shares issued, Amount | $		$ 0	$ 1,500,000,000	$ 2,241,000,000
Common shares issued in acquisition, amount | $		$ 12,727,000,000
Dividend Reinvestment and Share Purchase Plan (in shares) | shares	28	28	25	16
Dividend Reinvestment and Share Purchase Plan | $		$ 1,181,000,000	$ 1,226,000,000	$ 795,000,000
Shares issued on exercise of stock options (in shares) | shares	2	2	3	3
Shares issued on exercise of stock options, Amount | $		$ 32,000,000	$ 90,000,000	$ 65,000,000
Balance at end of period (in shares) | shares	2,022	2,022	1,695	943
Balance at end of period, Amount | $		$ 64,677,000,000	$ 50,737,000,000	$ 10,492,000,000
Merger Transaction | Common shares
Common Shares
Common shares issued in acquisition (in shares) | shares	0	0	691	0
Common shares issued in acquisition, amount | $		$ 0	$ 37,429,000,000	$ 0
Spectra Energy Partners, LP | Common shares
Common Shares
Common shares issued in acquisition (in shares) | shares	91	91	0	0
Common shares issued in acquisition, amount | $		$ 3,888,000,000	$ 0	$ 0
Enbridge Energy Partners, L.P. | Common shares
Common Shares
Common shares issued in acquisition (in shares) | shares	72	72	0	0
Common shares issued in acquisition, amount | $		$ 3,042,000,000	$ 0	$ 0
Enbridge Energy Management, L.L.C. (EEM) | Common shares
Common Shares
Common shares issued in acquisition (in shares) | shares	30	30	0	0
Common shares issued in acquisition, amount | $		$ 1,267,000,000	$ 0	$ 0
Enbridge Income Fund | Common shares
Common Shares
Common shares issued in acquisition (in shares) | shares	104	104	0	0
Common shares issued in acquisition, amount | $		$ 4,530,000,000	$ 0	$ 0

SHARE CAPITAL - PREFERRED SHARE

SHARE CAPITAL - PREFERRED SHARES (Details) $ / shares in Units, shares in Millions	Dec. 01, 2018$ / shares	Nov. 30, 2018$ / shares	Sep. 01, 2018$ / shares	Aug. 31, 2018$ / shares	Jun. 01, 2018$ / shares	Jun. 01, 2018$ / shares	May 31, 2018$ / shares	May 31, 2018$ / shares	Mar. 01, 2018$ / shares	Feb. 28, 2018$ / shares	Dec. 31, 2018CAD ($)$ / sharesshares	Dec. 31, 2018CAD ($)$ / shares$ / sharesshares	Dec. 31, 2017CAD ($)shares	Dec. 31, 2016CAD ($)shares	Dec. 31, 2018$ / shares
Preference Shares
Issuance costs | $											$ 0		$ 0	$ (59,000,000)
Preference Shares, Series C
Preference Shares
Yearly dividend per share (in dollars per share)	$ 0.25459	$ 0.23934	$ 0.23934	$ 0.22748	$ 0.22748		$ 0.22685		$ 0.22685	$ 0.20342
Preference Shares, Series D, F, H, N and 1
Preference Shares
Yearly dividend per share (in dollars per share) | (per share)	$ 0.31788	$ 0.25000	$ 0.27350	$ 0.25000	$ 0.29306	$ 0.37182	$ 0.25000	$ 0.25000	$ 0.27875	$ 0.25000
Preference shares
Preference Shares
Preferred stock, value, outstanding | $											7,747,000,000	$ 7,747,000,000	7,747,000,000	7,255,000,000
Issuance costs | $											$ (155,000,000)		$ (155,000,000)	$ (147,000,000)
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)											$ 25	$ 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	5	5	5
Preferred stock, value, outstanding | $											$ 125,000,000	$ 125,000,000	$ 125,000,000	$ 125,000,000
Initial Yield (as a percent)											5.50%
Yearly dividend per share (in dollars per share)											$ 1.37500
Per Share Base Redemption Value (in dollars per shares)											$ 25	$ 25
Preference shares | Preference Shares, Series B
Preference Shares
Preferred stock, shares outstanding (in shares) | shares											18	18	18	20
Preferred stock, value, outstanding | $											$ 457,000,000	$ 457,000,000	$ 457,000,000	$ 500,000,000
Initial Yield (as a percent)											3.415%
Yearly dividend per share (in dollars per share)											$ 0.85360
Per Share Base Redemption Value (in dollars per shares)											$ 25	$ 25
Preference shares | Preference Shares, Series C
Preference Shares
Preferred stock, shares outstanding (in shares) | shares											2	2	2	0
Preferred stock, value, outstanding | $											$ 43,000,000	$ 43,000,000	$ 43,000,000	$ 0
Initial Yield (as a percent)											2.40%
Yearly dividend per share (in dollars per share)											$ 0
Per Share Base Redemption Value (in dollars per shares)											$ 25	$ 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	18	18	18
Preferred stock, value, outstanding | $											$ 450,000,000	$ 450,000,000	$ 450,000,000	$ 450,000,000
Initial Yield (as a percent)											4.46%
Yearly dividend per share (in dollars per share)											$ 1.11500
Per Share Base Redemption Value (in dollars per shares)											$ 25	$ 25
Preference shares | Preference Shares, Series F
Preference Shares
Preferred stock, shares outstanding (in shares) | shares											20	20	20	20
Preferred stock, value, outstanding | $											$ 500,000,000	$ 500,000,000	$ 500,000,000	$ 500,000,000
Initial Yield (as a percent)											4.689%
Yearly dividend per share (in dollars per share)											$ 1.17225
Per Share Base Redemption Value (in dollars per shares)											$ 25	$ 25
Preference shares | Preference Shares, Series H
Preference Shares
Preferred stock, shares outstanding (in shares) | shares											14	14	14	14
Preferred stock, value, outstanding | $											$ 350,000,000	$ 350,000,000	$ 350,000,000	$ 350,000,000
Initial Yield (as a percent)											4.376%
Yearly dividend per share (in dollars per share)											$ 1.09400
Per Share Base Redemption Value (in dollars per shares)											$ 25	$ 25
Preference shares | Preference Shares, Series J
Preference Shares
Preferred stock, shares outstanding (in shares) | shares											8	8	8	8
Preferred stock, value, outstanding | $											$ 199,000,000	$ 199,000,000	$ 199,000,000	$ 199,000,000
Initial Yield (as a percent)											4.887%
Yearly dividend per share (in dollars per share)												$ 1.22160
Per Share Base Redemption Value (in dollars per shares)															$ 25
Preference shares | Preference Shares, Series L
Preference Shares
Preferred stock, shares outstanding (in shares) | shares											16	16	16	16
Preferred stock, value, outstanding | $											$ 411,000,000	$ 411,000,000	$ 411,000,000	$ 411,000,000
Initial Yield (as a percent)											4.959%
Yearly dividend per share (in dollars per share)												$ 1.23972
Per Share Base Redemption Value (in dollars per shares)															25
Preference shares | Preference Shares, Series N
Preference Shares
Preferred stock, shares outstanding (in shares) | shares											18	18	18	18
Preferred stock, value, outstanding | $											$ 450,000,000	$ 450,000,000	$ 450,000,000	$ 450,000,000
Initial Yield (as a percent)											5.086%
Yearly dividend per share (in dollars per share)											$ 1.27150
Per Share Base Redemption Value (in dollars per shares)											$ 25	$ 25
Preference shares | Preference Shares, Series P
Preference Shares
Preferred stock, shares outstanding (in shares) | shares											16	16	16	16
Preferred stock, value, outstanding | $											$ 400,000,000	$ 400,000,000	$ 400,000,000	$ 400,000,000
Initial Yield (as a percent)											4.00%
Yearly dividend per share (in dollars per share)											$ 1
Per Share Base Redemption Value (in dollars per shares)											$ 25	$ 25
Preference shares | Preference Shares, Series R
Preference Shares
Preferred stock, shares outstanding (in shares) | shares											16	16	16	16
Preferred stock, value, outstanding | $											$ 400,000,000	$ 400,000,000	$ 400,000,000	$ 400,000,000
Initial Yield (as a percent)											4.00%
Yearly dividend per share (in dollars per share)											$ 1
Per Share Base Redemption Value (in dollars per shares)											$ 25	$ 25
Preference shares | Preference Shares, Series 1
Preference Shares
Preferred stock, shares outstanding (in shares) | shares											16	16	16	16
Preferred stock, value, outstanding | $											$ 411,000,000	$ 411,000,000	$ 411,000,000	$ 411,000,000
Initial Yield (as a percent)											5.9491%
Yearly dividend per share (in dollars per share)												$ 1.487275
Per Share Base Redemption Value (in dollars per shares)															25
Preference shares | Preference Shares, Series 3
Preference Shares
Preferred stock, shares outstanding (in shares) | shares											24	24	24	24
Preferred stock, value, outstanding | $											$ 600,000,000	$ 600,000,000	$ 600,000,000	$ 600,000,000
Initial Yield (as a percent)											4.00%
Yearly dividend per share (in dollars per share)											$ 1
Per Share Base Redemption Value (in dollars per shares)											$ 25	$ 25
Preference shares | Preference Shares, Series 5
Preference Shares
Preferred stock, shares outstanding (in shares) | shares											8	8	8	8
Preferred stock, value, outstanding | $											$ 206,000,000	$ 206,000,000	$ 206,000,000	$ 206,000,000
Initial Yield (as a percent)											4.40%
Yearly dividend per share (in dollars per share)												$ 1.100
Per Share Base Redemption Value (in dollars per shares)															$ 25
Preference shares | Preference Shares, Series 7
Preference Shares
Preferred stock, shares outstanding (in shares) | shares											10	10	10	10
Preferred stock, value, outstanding | $											$ 250,000,000	$ 250,000,000	$ 250,000,000	$ 250,000,000
Initial Yield (as a percent)											4.40%
Yearly dividend per share (in dollars per share)											$ 1.10000
Per Share Base Redemption Value (in dollars per shares)											$ 25	$ 25
Preference shares | Preference Shares, Series 9
Preference Shares
Preferred stock, shares outstanding (in shares) | shares											11	11	11	11
Preferred stock, value, outstanding | $											$ 275,000,000	$ 275,000,000	$ 275,000,000	$ 275,000,000
Initial Yield (as a percent)											4.40%
Yearly dividend per share (in dollars per share)											$ 1.10000
Per Share Base Redemption Value (in dollars per shares)											$ 25	$ 25
Preference shares | Preference Shares, Series 11
Preference Shares
Preferred stock, shares outstanding (in shares) | shares											20	20	20	20
Preferred stock, value, outstanding | $											$ 500,000,000	$ 500,000,000	$ 500,000,000	$ 500,000,000
Initial Yield (as a percent)											4.40%
Yearly dividend per share (in dollars per share)											$ 1.10000
Per Share Base Redemption Value (in dollars per shares)											$ 25	$ 25
Preference shares | Preference Shares, Series 13
Preference Shares
Preferred stock, shares outstanding (in shares) | shares											14	14	14	14
Preferred stock, value, outstanding | $											$ 350,000,000	$ 350,000,000	$ 350,000,000	$ 350,000,000
Initial Yield (as a percent)											4.40%
Yearly dividend per share (in dollars per share)											$ 1.10000
Per Share Base Redemption Value (in dollars per shares)											$ 25	$ 25
Preference shares | Preference Shares, Series 15
Preference Shares
Preferred stock, shares outstanding (in shares) | shares											11	11	11	11
Preferred stock, value, outstanding | $											$ 275,000,000	$ 275,000,000	$ 275,000,000	$ 275,000,000
Initial Yield (as a percent)											4.40%
Yearly dividend per share (in dollars per share)											$ 1.10000
Per Share Base Redemption Value (in dollars per shares)											$ 25	$ 25
Preference shares | Preference Shares, Series 17
Preference Shares
Preferred stock, shares outstanding (in shares) | shares											30	30	30	30
Preferred stock, value, outstanding | $											$ 750,000,000	$ 750,000,000	$ 750,000,000	$ 750,000,000
Initial Yield (as a percent)											5.15%
Yearly dividend per share (in dollars per share)											$ 1.28750
Per Share Base Redemption Value (in dollars per shares)											$ 25	$ 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	20	20	0
Preferred stock, value, outstanding | $											$ 500,000,000	$ 500,000,000	$ 500,000,000	$ 0
Initial Yield (as a percent)											4.90%
Yearly dividend per share (in dollars per share)											$ 1.22500
Per Share Base Redemption Value (in dollars per shares)											$ 25	$ 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%

SHARE CAPITAL - PLANS (Details)

SHARE CAPITAL - PLANS (Details)	Dec. 31, 2018	Nov. 01, 2018
Equity [Abstract]
Discount on the purchase of common shares with reinvested dividends (as a percent)		2.00%
Minimum outstanding common shares required to be acquired to exercise the Shareholder Rights Plan (as a percent)	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%

STOCK OPTION AND STOCK UNIT P_3

STOCK OPTION AND STOCK UNIT PLANS - INCENTIVE PLANS (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018CAD ($)compensation_planshares	Dec. 31, 2017CAD ($)	Dec. 31, 2016CAD ($)
STOCK OPTION AND STOCK UNIT PLANS
Number of long-term incentive compensation plans | compensation_plan	4
Compensation expense | $	$ 106	$ 165	$ 130
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)	17,000,000
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 P_4

STOCK OPTION AND STOCK UNIT PLANS - STOCK OPTION ACTIVITY (Details) - INCENTIVE STOCK OPTIONS - CAD ($) $ / shares in Units, shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
STOCK OPTION AND STOCK UNIT PLANS
Vesting period	4 years
Expiration term	10 years
Number
Options outstanding at beginning of year (in shares)	34,366
Options granted (in shares)	5,775
Options exercised (in shares)	(2,519)
Options cancelled or expired (in shares)	(3,235)
Options outstanding at end of year (in shares)	34,387	34,366
Options vested at end of year (in shares)	21,064
Weighted Average Exercise Price
Options outstanding at beginning of year (in dollars per share)	$ 45.41
Options granted (in dollars per share)	32.32
Options exercised (in dollars per share)	27.11
Options cancelled or expired (in dollars per share)	44.11
Options outstanding at end of year (in dollars per share)	43.47	$ 45.41
Options vested at end of year (in dollars per share)	$ 43.48
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	$ 108
Options vested at end of year	84
Stock options, additional disclosures
Total intrinsic value of awards exercised	42	$ 62	$ 123
Cash received on exercise of awards	15	17	37
Total fair value of options vested	$ 36	$ 44	$ 36

STOCK OPTION AND STOCK UNIT P_5

STOCK OPTION AND STOCK UNIT PLANS - WEIGHTED AVERAGE ASSUMPTIONS (Details) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2018CAD ($)$ / shares	Dec. 31, 2017CAD ($)$ / shares	Dec. 31, 2016CAD ($)$ / shares	Dec. 31, 2018$ / shares	Dec. 31, 2017$ / shares	Dec. 31, 2016$ / shares
Weighted average assumptions used to determine the fair value of options
Compensation expense | $	$ 106	$ 165	$ 130
INCENTIVE STOCK OPTIONS
Weighted average assumptions used to determine the fair value of options
Fair value per option (in dollars per share) | $ / shares	$ 3.86	$ 6	$ 7.37
Expected option term (in years)	5 years	5 years	5 years
Expected volatility (as a percent)	21.90%	20.40%	25.10%
Expected dividend yield (as a percent)	6.40%	4.40%	4.40%
Risk-free interest rate (as a percent)	2.20%	1.20%	0.80%
Expected option term based on historical practice	6 years
Expected option term based on historical practice for retirement eligible employees	3 years
Compensation expense | $	$ 28	$ 40	$ 43
Unrecognized compensation cost related to non-vested share-based compensation arrangements granted | $	$ 23
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) | $ / shares	$ 3.75	$ 5.66	$ 7.01
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				$ 3.30	$ 5.72	$ 6.60

STOCK OPTION AND STOCK UNIT P_6

STOCK OPTION AND STOCK UNIT PLANS - PSUs AND RSUs (Details) - CAD ($) shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Stock units, additional disclosures
Compensation expense	$ 106	$ 165	$ 130
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)	1,693
Units granted (in shares)	542
Units cancelled (in shares)	(191)
Units matured (in shares)	(971)
Dividend reinvestment (in shares)	140
Units outstanding at end of year (in shares)	1,213	1,693
Weighted Average Remaining Contractual Life (years)
Units outstanding at end of year	1 year 3 months 19 days
Aggregate Intrinsic Value
Units outstanding at end of year	$ 52
Stock units, additional disclosures
Total amount paid	41	$ 39	56
Compensation expense	32	$ 46	$ 51
Unrecognized compensation expense related to non-vested units granted	$ 26
Weighted average period over which compensation cost is expected to be recognized	2 years

COMPONENTS OF ACCUMULATED OTH_3

COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS) (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Changes in AOCI
Balance at the beginning of the period	$ 58,135
Balance at the end of the period	69,470	$ 58,135
Accumulated other comprehensive income/(loss)
Changes in AOCI
Balance at the beginning of the period	(973)	1,058	$ 1,632
Other comprehensive income/(loss) retained in AOCI	3,479	(2,137)	(760)
Other comprehensive (income)/loss reclassified to earnings, Pension and OPEB	16	41	21
Total before tax impact	3,680	(1,908)	(620)
Income tax on amounts retained in AOCI	148	(30)	102
Income tax on amounts reclassified to earnings	(41)	(93)	(56)
Tax impact	107	(123)	46
Sponsored Vehicle buy-in	(142)
Balance at the end of the period	2,672	(973)	1,058
Accumulated other comprehensive income/(loss) | Interest rate contracts
Changes in AOCI
Other comprehensive (income)/loss reclassified to earnings, Cash Flow Hedges	157	207	147
Accumulated other comprehensive income/(loss) | Commodity contracts
Changes in AOCI
Other comprehensive (income)/loss reclassified to earnings, Cash Flow Hedges	(1)	(7)	(11)
Accumulated other comprehensive income/(loss) | Forward currency contracts
Changes in AOCI
Other comprehensive (income)/loss reclassified to earnings, Cash Flow Hedges	7	(6)	1
Accumulated other comprehensive income/(loss) | Other contracts
Changes in AOCI
Other comprehensive (income)/loss reclassified to earnings, Cash Flow Hedges	22	(6)	(18)
Cash Flow Hedges
Changes in AOCI
Balance at the beginning of the period	(644)	(746)	(688)
Other comprehensive income/(loss) retained in AOCI	(244)	1	(216)
Total before tax impact	(59)	189	(97)
Income tax on amounts retained in AOCI	57	(16)	91
Income tax on amounts reclassified to earnings	(37)	(71)	(52)
Tax impact	20	(87)	39
Sponsored Vehicle buy-in	(87)
Balance at the end of the period	(770)	(644)	(746)
Cash Flow Hedges | Interest rate contracts
Changes in AOCI
Other comprehensive (income)/loss reclassified to earnings	157	207	147
Cash Flow Hedges | Commodity contracts
Changes in AOCI
Other comprehensive (income)/loss reclassified to earnings	(1)	(7)	(11)
Cash Flow Hedges | Forward currency contracts
Changes in AOCI
Other comprehensive (income)/loss reclassified to earnings	7	(6)	1
Cash Flow Hedges | Other contracts
Changes in AOCI
Other comprehensive (income)/loss reclassified to earnings	22	(6)	(18)
Net Investment Hedges
Changes in AOCI
Balance at the beginning of the period	(139)	(629)	(795)
Other comprehensive income/(loss) retained in AOCI	(509)	478	171
Total before tax impact	(509)	478	171
Income tax on amounts retained in AOCI	50	12	(5)
Tax impact	50	12	(5)
Balance at the end of the period	(598)	(139)	(629)
Cumulative Translation Adjustment
Changes in AOCI
Balance at the beginning of the period	77	2,700	3,365
Other comprehensive income/(loss) retained in AOCI	4,301	(2,623)	(665)
Total before tax impact	4,301	(2,623)	(665)
Tax impact	0	0	0
Balance at the end of the period	4,323	77	2,700
Equity Investees
Changes in AOCI
Balance at the beginning of the period	10	37	37
Other comprehensive income/(loss) retained in AOCI	16	(11)	(5)
Total before tax impact	16	(11)	(5)
Income tax on amounts retained in AOCI	8	(16)	5
Tax impact	8	(16)	5
Balance at the end of the period	34	10	37
Pension and OPEB Adjustment
Changes in AOCI
Balance at the beginning of the period	(277)	(304)	(287)
Other comprehensive income/(loss) retained in AOCI	(85)	18	(45)
Other comprehensive (income)/loss reclassified to earnings, Pension and OPEB	16	41	21
Total before tax impact	(69)	59	(24)
Income tax on amounts retained in AOCI	33	(10)	11
Income tax on amounts reclassified to earnings	(4)	(22)	(4)
Tax impact	29	(32)	7
Balance at the end of the period	$ (317)	$ (277)	$ (304)

RISK MANAGEMENT AND FINANCIAL_3

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - MARKET RISK (Details)	1 Months Ended	12 Months Ended
	Feb. 01, 2018	Dec. 31, 2018CAD ($)Number_of_equity	Dec. 31, 2017CAD ($)
Fair Value Hedges
Outstanding fair value hedges | $		$ 0	$ 0
Maximum
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
Floating Rate Debt as Target Percentage of Total Debt Outstanding	30.00%	30.00%
Interest rate contracts - short-term borrowings
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
Average swap rate (as a percent)		2.80%
Interest rate contracts - long-term debt
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
Average swap rate (as a percent)		3.20%
Equity contracts
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
Number of forms of stock-based compensation with equity price risk | Number_of_equity		1

RISK MANAGEMENT AND FINANCIAL_4

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - TOTAL DERIVATIVE INSTRUMENTS (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	$ (3,210)	$ (2,192)
Total Net Derivative Instruments	(3,210)	(2,192)
Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(2,894)	(1,991)
Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(301)	(155)
Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(15)	(46)
Accounts receivable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	498	296
Derivative assets, Amounts Available for Offset	(153)	(150)
Derivative assets, Total Net Derivative Instruments	345	146
Accounts receivable and other | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	474	281
Accounts receivable and other | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	24	9
Accounts receivable and other | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented		4
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	119	181
Derivative assets, Amounts Available for Offset	(60)	(146)
Derivative assets, Total Net Derivative Instruments	59	35
Deferred amounts and other assets | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	72	149
Deferred amounts and other assets | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	47	25
Deferred amounts and other assets | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented		1
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	(1,234)	(1,130)
Derivative liabilities, Amounts Available for Offset	153	150
Derivative liabilities, Total Net Derivative Instruments	(1,081)	(980)
Accounts payable and other | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(1,065)	(936)
Accounts payable and other | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(169)	(146)
Accounts payable and other | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented		(42)
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	(2,593)	(1,539)
Derivative liabilities, Amounts Available for Offset	60	146
Derivative liabilities, Total Net Derivative Instruments	(2,533)	(1,393)
Other long-term liabilities | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(2,375)	(1,485)
Other long-term liabilities | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(203)	(43)
Other long-term liabilities | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(15)	(9)
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)	(2,718)	(1,383)
Total Net Derivative Instruments	(2,718)	(1,383)
Forward currency contracts | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(2,720)	(1,330)
Forward currency contracts | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	17	(7)
Forward currency contracts | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(15)	(46)
Forward currency contracts | Accounts receivable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	47	143
Derivative assets, Amounts Available for Offset	(37)	(83)
Derivative assets, Total Net Derivative Instruments	10	60
Forward currency contracts | Accounts receivable and other | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	47	138
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
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
Forward currency contracts | Deferred amounts and other assets
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	62	145
Derivative assets, Amounts Available for Offset	(39)	(125)
Derivative assets, Total Net Derivative Instruments	23	20
Forward currency contracts | Deferred amounts and other assets | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	39	143
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	23	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
Forward currency contracts | Accounts payable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(615)	(359)
Derivative liabilities, Amounts Available for Offset	37	83
Derivative liabilities, Total Net Derivative Instruments	(578)	(276)
Forward currency contracts | Accounts payable and other | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(610)	(312)
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)	(5)
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)
Forward currency contracts | Other long-term liabilities
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(2,212)	(1,312)
Derivative liabilities, Amounts Available for Offset	39	125
Derivative liabilities, Total Net Derivative Instruments	(2,173)	(1,187)
Forward currency contracts | Other long-term liabilities | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(2,196)	(1,299)
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	(1)	(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	(15)	(9)
Interest rate contracts
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(515)	(348)
Total Net Derivative Instruments	(515)	(348)
Interest rate contracts | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(178)	(183)
Interest rate contracts | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(337)	(165)
Interest rate contracts | Accounts receivable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	22	8
Derivative assets, Amounts Available for Offset	(2)	(3)
Derivative assets, Total Net Derivative Instruments	20	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	22	6
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	5	13
Derivative assets, Amounts Available for Offset		(2)
Derivative assets, Total Net Derivative Instruments	5	11
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	5	7
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	(341)	(329)
Derivative liabilities, Amounts Available for Offset	2	3
Derivative liabilities, Total Net Derivative Instruments	(339)	(326)
Interest rate contracts | Accounts payable and other | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(178)	(183)
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	(163)	(140)
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	(201)	(40)
Derivative liabilities, Amounts Available for Offset		2
Derivative liabilities, Total Net Derivative Instruments	(201)	(38)
Interest rate contracts | Other long-term liabilities | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented		0
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	(201)	(38)
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)	30	(457)
Total Net Derivative Instruments	30	(457)
Commodity contracts | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	9	(476)
Commodity contracts | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	21	19
Commodity contracts | Accounts receivable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	429	145
Derivative assets, Amounts Available for Offset	(114)	(64)
Derivative assets, Total Net Derivative Instruments	315	81
Commodity contracts | Accounts receivable and other | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	427	143
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	2
Commodity contracts | Deferred amounts and other assets
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	52	23
Derivative assets, Amounts Available for Offset	(21)	(19)
Derivative assets, Total Net Derivative Instruments	31	4
Commodity contracts | Deferred amounts and other assets | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Total Gross Derivative Instruments as Presented	33	6
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	19	17
Commodity contracts | Accounts payable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(273)	(439)
Derivative liabilities, Amounts Available for Offset	114	64
Derivative liabilities, Total Net Derivative Instruments	(159)	(375)
Commodity contracts | Accounts payable and other | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(273)	(439)
Commodity contracts | Other long-term liabilities
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(178)	(186)
Derivative liabilities, Amounts Available for Offset	21	19
Derivative liabilities, Total Net Derivative Instruments	(157)	(167)
Commodity contracts | Other long-term liabilities | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(178)	(186)
Other contracts
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(7)	(4)
Total Net Derivative Instruments	(7)	(4)
Other contracts | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(5)	(2)
Other contracts | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(2)	(2)
Other contracts | Accounts payable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(5)	(3)
Derivative liabilities, Total Net Derivative Instruments	(5)	(3)
Other contracts | Accounts payable and other | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(4)	(2)
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)	(1)
Other contracts | Other long-term liabilities
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(2)	(1)
Derivative liabilities, Total Net Derivative Instruments	(2)	(1)
Other contracts | Other long-term liabilities | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Total Gross Derivative Instruments as Presented	(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	$ (1)	$ (1)

RISK MANAGEMENT AND FINANCIAL_5

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - NOTIONAL PRINCIPAL OR QUANTITY INFORMATION (Details) € in Millions, ¥ in Millions, £ in Millions, MWh in Millions, MMBbls in Millions, Bcf in Millions, $ in Millions, $ in Millions	Dec. 31, 2018USD ($)MWhBcfMMBbls	Dec. 31, 2018CAD ($)MWhBcfMMBbls	Dec. 31, 2018EUR (€)MWhBcfMMBbls	Dec. 31, 2018JPY (¥)MWhBcfMMBbls	Dec. 31, 2018GBP (£)MWhBcfMMBbls	Dec. 31, 2017USD ($)MWhBcfMMBbls	Dec. 31, 2017CAD ($)MWhBcfMMBbls	Dec. 31, 2017EUR (€)MWhBcfMMBbls	Dec. 31, 2017JPY (¥)MWhBcfMMBbls	Dec. 31, 2017GBP (£)MWhBcfMMBbls
Foreign exchange contracts - United States dollar or GBP or Japanese yen forwards - purchase
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2019 Notional Amount	$ 925		€ 226	¥ 32,662	£ 0
2020 Notional Amount	1		0	0	0
2021 Notional Amount	0		0	0	0
2022 Notional Amount	0		0	20,000	0
2023 Notional amount	0		0	0	0
Thereafter	0		0	¥ 0	0
Total Notional Amount Outstanding						$ 759		€ 655	¥ 52,662	£ 18
Foreign exchange contracts - United States dollar or GBP forwards - sell
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2019 Notional Amount	4,969		0		89
2020 Notional Amount	4,893		23		25
2021 Notional Amount	3,608		94		27
2022 Notional Amount	1,944		94		28
2023 Notional amount	1,804		92		29
Thereafter	$ 1,857		€ 606		£ 120
Total Notional Amount Outstanding						$ 16,167		€ 1,262		£ 318
Interest rate contracts - short-term borrowings
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2019 Notional Amount		$ 8,616
2020 Notional Amount		6,243
2021 Notional Amount		4,188
2022 Notional Amount		412
2023 Notional amount		49
Thereafter		156
Total Notional Amount Outstanding							$ 7,138
Interest rate contracts - long-term debt
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2019 Notional Amount		0
2020 Notional Amount		0
2021 Notional Amount		0
2022 Notional Amount		0
2023 Notional amount		0
Thereafter		0
Total Notional Amount Outstanding							4,196
Interest rate contract - long term debt - Pay Fixed Rate
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2019 Notional Amount		3,777
2020 Notional Amount		3,185
2021 Notional Amount		1,596
2022 Notional Amount		0
2023 Notional amount		0
Thereafter		0
Total Notional Amount Outstanding							5,402
Equity contracts
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2019 Notional Amount		35
2020 Notional Amount		20
2021 Notional Amount		0
2022 Notional Amount		0
2023 Notional amount		0
Thereafter		$ 0
Total Notional Amount Outstanding							$ 90
Commodity contracts | Natural gas
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2019 Nonmonetary Notional Amount | Bcf	(141)	(141)	(141)	(141)	(141)
2020 Nonmonetary Notional Amount | Bcf	(16)	(16)	(16)	(16)	(16)
2021 Nonmonetary Notional Amount | Bcf	(6)	(6)	(6)	(6)	(6)
2022 Nonmonetary Notional amount | Bcf	(4)	(4)	(4)	(4)	(4)
2023 Nonmonetary Notional Amount | Bcf	0	0	0	0	0
Thereafter | Bcf	0	0	0	0	0
Derivative Nonmonetary Notional Amount Outstanding | Bcf						(159)	(159)	(159)	(159)	(159)
Commodity contracts | Crude oil
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2019 Nonmonetary Notional Amount | MMBbls	4	4	4	4	4
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
2023 Nonmonetary Notional Amount | MMBbls	0	0	0	0	0
Thereafter | MMBbls	0	0	0	0	0
Derivative Nonmonetary Notional Amount Outstanding | MMBbls						(3)	(3)	(3)	(3)	(3)
Commodity contracts | NGL
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
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
2023 Nonmonetary Notional Amount | MMBbls	0	0	0	0	0
Thereafter | MMBbls	0	0	0	0	0
Derivative Nonmonetary Notional Amount Outstanding | MMBbls						(12)	(12)	(12)	(12)	(12)
Commodity contracts | Power
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2019 | MWh	64	64	64	64	64
2020 | MWh	66	66	66	66	66
2021 | MWh	(3)	(3)	(3)	(3)	(3)
2022 | MWh	(43)	(43)	(43)	(43)	(43)
2023 | MWh	(43)	(43)	(43)	(43)	(43)
Thereafter | MWh	(43)	(43)	(43)	(43)	(43)
Derivative Nonmonetary Rate Notional Amount Outstanding | MWh						(43)	(43)	(43)	(43)	(43)

RISK MANAGEMENT AND FINANCIAL_6

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - EFFECTS ON EARNINGS AND COMPREHENSIVE INCOME (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of unrealized gains/(loss) recognized in OCI	$ (141)	$ 297	$ (34)
Amount of (gains)/loss reclassified from AOCI to earnings (effective portion)	168	283	106
Amount of (gains)/loss reclassified from AOCI to earnings (ineffective portion and amount excluded from effectiveness testing)	23	(4)	61
Unrealized gain/(loss) on derivative	7	(10)
Unrealized gain/(loss) on hedged item	1	11
Realized gain/(loss) on derivative	(8)	2
Realized gain/(loss) on hedged item	(1)	(2)
Total unrealized derivative fair value gains/(loss), net	(903)	1,242	509
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	$ 18
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)	$ 5	(104)	2
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	(1,390)	1,284	935
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	(1,108)	800	497
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	(282)	484	438
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	19	(5)	(19)
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	31	284	22
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)	161	388	145
Amount of (gains)/loss reclassified from AOCI to earnings (ineffective portion and amount excluded from effectiveness testing)	23	(4)	61
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	5	157	73
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	(190)	6	(90)
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)	(1)	(9)	(12)
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	485	(199)	(508)
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	66	(104)	(52)
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	599	90	(474)
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	(193)	(223)	38
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	13	38	(20)
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	2	11	14
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)	3	8	(29)
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	(3)	0	9
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	(3)	$ 1	$ 39
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)	$ 296

RISK MANAGEMENT AND FINANCIAL_7

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - LIQUIDITY AND CREDIT RISK (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
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	30 days
Derivative instruments
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	$ 562	$ 385
Derivative instruments | Canadian financial institutions
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	28	82
Derivative instruments | United States financial institutions
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	107	19
Derivative instruments | European financial institutions
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	84	145
Derivative instruments | Asian financial institutions
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	6	2
Derivative instruments | Other
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	$ 337	$ 137

RISK MANAGEMENT AND FINANCIAL_8

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - FAIR VALUE OF DERIVATIVES (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Fair Value of Derivatives
Short-term portion of derivative assets	$ 498	$ 296
Current derivative liabilities	(1,234)	(1,130)
Fair Value	(3,210)	(2,192)
Forward currency contracts
Fair Value of Derivatives
Fair Value	(2,718)	(1,383)
Interest rate contracts
Fair Value of Derivatives
Fair Value	(515)	(348)
Commodity contracts
Fair Value of Derivatives
Fair Value	30	(457)
Other contracts
Fair Value of Derivatives
Fair Value	(7)	(4)
Fair Value
Fair Value of Derivatives
Short-term portion of derivative assets	498	296
Long-term derivative assets	119	181
Current derivative liabilities	(1,234)	(1,130)
Long-term derivative liabilities	(2,593)	(1,539)
Fair Value	(3,210)	(2,192)
Fair Value | Forward currency contracts
Fair Value of Derivatives
Short-term portion of derivative assets	47	143
Long-term derivative assets	62	145
Current derivative liabilities	(615)	(359)
Long-term derivative liabilities	(2,212)	(1,312)
Fair Value	(2,718)	(1,383)
Fair Value | Interest rate contracts
Fair Value of Derivatives
Short-term portion of derivative assets	22	8
Long-term derivative assets	5	13
Current derivative liabilities	(341)	(329)
Long-term derivative liabilities	(201)	(40)
Fair Value	(515)	(348)
Fair Value | Commodity contracts
Fair Value of Derivatives
Short-term portion of derivative assets	429	145
Long-term derivative assets	52	23
Current derivative liabilities	(273)	(439)
Long-term derivative liabilities	(178)	(186)
Fair Value	30	(457)
Fair Value | Other contracts
Fair Value of Derivatives
Current derivative liabilities	(5)	(3)
Long-term derivative liabilities	(2)	(1)
Fair Value		(4)
Level 1 | Fair Value
Fair Value of Derivatives
Short-term portion of derivative assets	24	1
Current derivative liabilities	(7)	(13)
Fair Value	17	(12)
Level 1 | Fair Value | Commodity contracts
Fair Value of Derivatives
Short-term portion of derivative assets	24	1
Current derivative liabilities	(7)	(13)
Fair Value	17	(12)
Level 2 | Fair Value
Fair Value of Derivatives
Short-term portion of derivative assets	114	181
Long-term derivative assets	97	160
Current derivative liabilities	(989)	(778)
Long-term derivative liabilities	(2,438)	(1,356)
Fair Value	(3,216)	(1,793)
Level 2 | Fair Value | Forward currency contracts
Fair Value of Derivatives
Short-term portion of derivative assets	47	143
Long-term derivative assets	62	145
Current derivative liabilities	(615)	(359)
Long-term derivative liabilities	(2,212)	(1,312)
Fair Value	(2,718)	(1,383)
Level 2 | Fair Value | Interest rate contracts
Fair Value of Derivatives
Short-term portion of derivative assets	22	8
Long-term derivative assets	5	13
Current derivative liabilities	(341)	(329)
Long-term derivative liabilities	(201)	(40)
Fair Value	(515)	(348)
Level 2 | Fair Value | Commodity contracts
Fair Value of Derivatives
Short-term portion of derivative assets	45	30
Long-term derivative assets	30	2
Current derivative liabilities	(28)	(87)
Long-term derivative liabilities	(23)	(3)
Fair Value	24	(58)
Level 2 | Fair Value | Other contracts
Fair Value of Derivatives
Current derivative liabilities	(5)	(3)
Long-term derivative liabilities	(2)	(1)
Fair Value	(7)	(4)
Level 3 | Fair Value
Fair Value of Derivatives
Short-term portion of derivative assets	360	114
Long-term derivative assets	22	21
Current derivative liabilities	(238)	(339)
Long-term derivative liabilities	(155)	(183)
Fair Value	(11)	(387)
Level 3 | Fair Value | Commodity contracts
Fair Value of Derivatives
Short-term portion of derivative assets	360	114
Long-term derivative assets	22
Current derivative liabilities	(238)	(339)
Long-term derivative liabilities	(155)	(183)
Fair Value	$ (11)	(387)
Level 3 | Fair Value | Other contracts
Fair Value of Derivatives
Long-term derivative liabilities		$ 0

RISK MANAGEMENT AND FINANCIAL_9

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - LEVEL 3 INPUTS (Details) $ in Millions	Dec. 31, 2018CAD ($)$ / bbl$ / MWh$ / MillionsofBTU-MMBTU$ / Gallon-gal	Dec. 31, 2017CAD ($)
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	$ (3,210)	$ (2,192)
Fair Value
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	(3,210)	(2,192)
Level 3 | Fair Value
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	$ (11)	$ (387)
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 | $ / MillionsofBTU-MMBTU	2.54
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 | $ / MillionsofBTU-MMBTU	6.37
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 | $ / MillionsofBTU-MMBTU	3.58
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 | $ / bbl	27.50
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 | $ / bbl	123.20
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 | $ / bbl	59.32
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 | $ / Gallon-gal	0
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 | $ / Gallon-gal	0
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 | $ / Gallon-gal	0
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 | $ / MWh	16.21
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 | $ / MWh	96.72
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 | $ / MWh	48.33
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 | $ / MillionsofBTU-MMBTU	1.09
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 | $ / MillionsofBTU-MMBTU	6.95
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 | $ / MillionsofBTU-MMBTU	1.51
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 | $ / bbl	16.45
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 | $ / bbl	123.22
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 | $ / bbl	59.22
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 | $ / Gallon-gal	0.13
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 | $ / Gallon-gal	1.40
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 | $ / Gallon-gal	0.59
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	$ (9)
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	28
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	0
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	(91)
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	(119)
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	186
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	$ (6)

RISK MANAGEMENT AND FINANCIA_10

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - CHANGES IN LEVEL 3 (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Changes in net fair value of derivative assets and liabilities classified as Level 3
Level 3 net derivative asset at beginning of period	$ (387)	$ (295)
Total gains/(loss)
Included in earnings	206	(184)
Included in OCI	2	4
Settlements	168	88
Level 3 net derivative asset at end of period	(11)	(387)
Amount of transfer of fair value of assets between levels	0	0
Amount of transfer of fair value of liabilities between levels	$ 0	$ 0

RISK MANAGEMENT AND FINANCIA_11

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - OTHER FINANCIAL INSTRUMENTS (Details) - CAD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Fair Value of Other Financial Instruments
Equity investments at carrying value	$ 102,000,000	$ 99,000,000
Restricted long-term investments (Note 14)	323,000,000	267,000,000
Long-term debt	64,400,000,000	67,400,000,000
Notes receivable, noncurrent	97,000,000	89,000,000
Notes receivable, fair value	97,000,000	89,000,000
Net Investment Hedges
Fair Value of Other Financial Instruments
Unrealized foreign exchange gain (loss) on translation of United States dollar denominated debt	479,000,000	367,000,000
Unrealized gain (loss) on change in fair value of outstanding forward exchange forward contracts	30,000,000	286,000,000
Realized loss associated with the settlement of foreign exchange forward contracts	45,000,000	198,000,000
Realized gain (loss) associated with the settlement of United Stated dollar denominated debt that matured	14,000,000	23,000,000
Amount of ineffectiveness	0	0
Carrying value
Fair Value of Other Financial Instruments
Long-term debt	63,900,000,000	64,000,000,000
Preference shares
Fair Value of Other Financial Instruments
Held-to-maturity securities	$ 478,000,000	371,000,000
Cumulative dividends based on average yield of Government of Canada bonds, maturity period of bonds	10 years
Held to maturity preferred share investment	$ 580,000,000	$ 580,000,000
Noverco | Preference shares
Fair Value of Other Financial Instruments
Cumulative dividends based on average yield of Government of Canada bonds, spread over reference rate (as a percent)	4.38%

INCOME TAXES - RATE RECONCILIAT

INCOME TAXES - RATE RECONCILIATION (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
INCOME TAX RATE RECONCILIATION
Earnings before income taxes and discontinued operation	$ 3,570	$ 569	$ 2,451
Canadian federal statutory income tax rate	15.00%	15.00%	15.00%
Expected federal taxes at statutory rate	$ 536	$ 85	$ 368
Increase/(decrease) resulting from:
Provincial and state income taxes	(24)	133	34
Foreign and other statutory rate differentials	94	(601)	(56)
Impact of United States tax reform	(2)	(2,045)	0
Effects of rate-regulated accounting	(163)	(189)	(116)
Foreign allowable interest deductions	(134)	(124)	(107)
Part VI.1 tax, net of federal Part I deduction	76	68	56
Goodwill write-down	192	15	0
Intercompany sale of investment	0	0	6
United States BEAT tax	43	0	0
Non-taxable portion of gain on sale of investment to unrelated party	31	0	(61)
Valuation allowance	(172)	(17)	22
Effective Income Tax Rate Reconciliation, Intercorporate Investments, Amount	(149)	77	0
Noncontrolling interests	(47)	(80)	(15)
Other	(44)	(19)	11
Income taxes on earnings before discontinued operations	$ 237	$ (2,697)	$ 142
Effective income tax rate (as a percent)	6.60%	(474.00%)	5.80%

INCOME TAXES - COMPONENTS (Deta

INCOME TAXES - COMPONENTS (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Earnings/(loss) before income taxes and discontinued operations
Earnings before income taxes	$ 3,570	$ 569	$ 2,451
Current income taxes
Total current income taxes	385	180	99
Deferred income taxes
Total deferred income taxes	(148)	(2,877)	43
Income taxes on earnings before discontinued operations	237	(2,697)	142
Canada
Earnings/(loss) before income taxes and discontinued operations
Domestic	118	2,200	2,034
Current income taxes
Domestic	311	129	74
Deferred income taxes
Domestic	(598)	299	188
United States
Earnings/(loss) before income taxes and discontinued operations
Foreign	2,582	(2,431)	(333)
Current income taxes
Foreign	66	46	21
Deferred income taxes
Foreign	439	(3,160)	(151)
Other
Earnings/(loss) before income taxes and discontinued operations
Foreign	870	800	750
Current income taxes
Foreign	8	5	4
Deferred income taxes
Foreign	$ 11	$ (16)	$ 6

INCOME TAXES - DEFERRED INCOME

INCOME TAXES - DEFERRED INCOME TAXES (Details) - CAD ($)	Dec. 31, 2018	Jan. 01, 2018	Dec. 31, 2017
Deferred income tax liabilities
Property, plant and equipment	$ (7,018,000,000)		$ (4,089,000,000)
Investments	(4,441,000,000)		(6,596,000,000)
Regulatory assets	(756,000,000)		(977,000,000)
Other	(192,000,000)		(50,000,000)
Total deferred income tax liabilities	(12,407,000,000)		(11,712,000,000)
Deferred income tax assets
Financial instruments	1,103,000,000		697,000,000
Pension and OPEB plans	181,000,000		258,000,000
Loss carryforwards	1,820,000,000		1,781,000,000
Other	1,274,000,000		1,057,000,000
Total deferred income tax assets	4,378,000,000		3,793,000,000
Less valuation allowance	(51,000,000)		(286,000,000)
Total deferred income tax assets, net	4,327,000,000		3,507,000,000
Net deferred income tax liabilities	(8,080,000,000)		(8,205,000,000)
Total deferred income tax assets	1,374,000,000		1,090,000,000
Total deferred income tax liabilities	(9,454,000,000)	$ (9,233,000,000)	(9,295,000,000)
Deferred taxes on unremitted earnings and currency translation adjustment	0		0
Foreign subsidiaries' undistributed earnings on which deferred income taxes has not been provided	5,800,000,000		2,100,000,000
Canada
Deferred income tax assets
Benefit of unused tax loss carryforwards recognized	3,400,000,000		3,800,000,000
Capital loss carryforwards	0		143,000,000
United States
Deferred income tax assets
Benefit of unused tax loss carryforwards recognized	3,400,000,000		2,100,000,000
Capital loss carryforwards	$ 0		$ 20,000,000

INCOME TAXES - UNITED STATES TA

INCOME TAXES - UNITED STATES TAX REFROM (Details) - CAD ($) $ in Millions	3 Months Ended		12 Months Ended
	Dec. 31, 2018	Mar. 31, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Provisional tax expense	$ 223	$ 30		$ 34
United States BEAT tax			$ 43	0	$ 0
Impact of United States tax reform			$ 2	2,045	0
Deferred income tax provision				3,100
Deferred income tax asset benefit				$ 1,100
Reduction in tax amount					$ 200

INCOME TAXES - UNRECOGNIZED TAX

INCOME TAXES - UNRECOGNIZED TAX BENEFITS (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
UNRECOGNIZED TAX BENEFITS
Unrecognized tax benefits at beginning of year	$ 150	$ 84
Gross increases for tax positions of current year	2	15
Gross increases for tax positions of prior year	0	65
Gross decreases for tax positions of prior year	(12)	0
Change in translation of foreign currency	3	(2)
Lapses of statute of limitations	(3)	(8)
Settlements	(1)	(4)
Unrecognized tax benefits at end of year	139	150
Interest and penalties expense (recovery) related to unrecognized tax benefits	5	3
Accrued interest and penalties related to unrecognized tax benefits	$ 12	$ 8

PENSION AND OTHER POSTRETIREM_3

PENSION AND OTHER POSTRETIREMENT BENEFITS - BENEFIT OBLIGATION, PLAN ASSETS AND FUNDED STATUS (Details) - CAD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Canada
Change in plan assets
Employer contributions	$ 13,000,000	$ 14,000,000	$ 0
Canada | Pension
Change in projected benefit obligation
Benefit obligation at beginning of year	4,033,000,000	2,270,000,000
Service cost	149,000,000	156,000,000	129,000,000
Interest cost	130,000,000	116,000,000	73,000,000
Participant contributions	25,000,000	6,000,000
Actuarial (gain)/loss	(146,000,000)	145,000,000
Benefits paid	(184,000,000)	(165,000,000)
Plan settlements	0	0
Transfer out	(10,000,000)	0
Acquired in Merger Transaction	0	1,505,000,000
Foreign currency exchange rate changes	0	0
Other	0	0
Benefit obligation at beginning of year	3,997,000,000	4,033,000,000	2,270,000,000
Change in plan assets
Fair value of plan assets at beginning of year	3,619,000,000	2,019,000,000
Actual return/(loss) on plan assets	(42,000,000)	308,000,000
Employer contributions	113,000,000	161,000,000
Participant contributions	25,000,000	6,000,000
Benefits paid	(184,000,000)	(165,000,000)
Plan settlements	0	0
Transfer out	(8,000,000)	0
Acquired in Merger Transaction	0	1,290,000,000
Foreign currency exchange rate changes	0	0
Other	0	0
Fair value of plan assets at end of year	3,523,000,000	3,619,000,000	2,019,000,000
Underfunded status at end of year	(474,000,000)	(414,000,000)
Presented as follows:
Deferred amounts and other assets	29,000,000	38,000,000
Accounts payable and other	(9,000,000)	(60,000,000)
Other long-term liabilities	(494,000,000)	(392,000,000)
Amount recognized in balance sheet	(474,000,000)	(414,000,000)
Accumulated benefit obligation	3,700,000,000	3,700,000,000
Canada | Supplemental Employee Retirement Plan
Presented as follows:
Deferred amounts and other assets	7,000,000	9,000,000
Canada | OPEB
Change in projected benefit obligation
Benefit obligation at beginning of year	321,000,000	179,000,000
Service cost	8,000,000	7,000,000	4,000,000
Interest cost	10,000,000	10,000,000	6,000,000
Participant contributions	0	0
Actuarial (gain)/loss	(45,000,000)	(8,000,000)
Benefits paid	(11,000,000)	(10,000,000)
Plan settlements	0	(3,000,000)
Acquired in Merger Transaction	0	146,000,000
Foreign currency exchange rate changes	0	0
Other	(1,000,000)	0
Benefit obligation at beginning of year	282,000,000	321,000,000	179,000,000
Change in plan assets
Fair value of plan assets at beginning of year	0	0
Actual return/(loss) on plan assets	0	0
Employer contributions	11,000,000	10,000,000
Participant contributions	0	0
Benefits paid	(11,000,000)	(10,000,000)
Acquired in Merger Transaction	0	0
Foreign currency exchange rate changes	0	0
Other	0	0
Fair value of plan assets at end of year	0	0	0
Underfunded status at end of year	(282,000,000)	(321,000,000)
Presented as follows:
Deferred amounts and other assets	0	0
Accounts payable and other	(12,000,000)	(12,000,000)
Other long-term liabilities	(270,000,000)	(309,000,000)
Amount recognized in balance sheet	(282,000,000)	(321,000,000)
United States
Change in plan assets
Employer contributions	27,000,000	31,000,000	13,000,000
United States | Pension
Change in projected benefit obligation
Benefit obligation at beginning of year	1,279,000,000	508,000,000
Service cost	45,000,000	48,000,000	26,000,000
Interest cost	38,000,000	35,000,000	16,000,000
Participant contributions	0	0
Actuarial (gain)/loss	(103,000,000)	57,000,000
Benefits paid	(60,000,000)	(42,000,000)
Plan settlements	(65,000,000)	(59,000,000)
Transfer out	0	0
Acquired in Merger Transaction	0	811,000,000
Foreign currency exchange rate changes	105,000,000	(63,000,000)
Other	(25,000,000)	(16,000,000)
Benefit obligation at beginning of year	1,214,000,000	1,279,000,000	508,000,000
Change in plan assets
Fair value of plan assets at beginning of year	1,097,000,000	361,000,000
Actual return/(loss) on plan assets	(48,000,000)	113,000,000
Employer contributions	40,000,000	57,000,000
Participant contributions	0	0
Benefits paid	(60,000,000)	(42,000,000)
Plan settlements	(65,000,000)	(59,000,000)
Transfer out	0	0
Acquired in Merger Transaction		731,000,000
Foreign currency exchange rate changes	(91,000,000)	51,000,000
Other	(10,000,000)	(13,000,000)
Fair value of plan assets at end of year	1,045,000,000	1,097,000,000	361,000,000
Underfunded status at end of year	(169,000,000)	(182,000,000)
Presented as follows:
Deferred amounts and other assets	0	0
Accounts payable and other	(4,000,000)	(3,000,000)
Other long-term liabilities	(165,000,000)	(179,000,000)
Amount recognized in balance sheet	(169,000,000)	(182,000,000)
Accumulated benefit obligation	1,200,000,000	1,200,000,000
United States | Supplemental Employee Retirement Plan
Presented as follows:
Deferred amounts and other assets	39,000,000	40,000,000
United States | OPEB
Change in projected benefit obligation
Benefit obligation at beginning of year	337,000,000	133,000,000
Service cost	3,000,000	5,000,000	4,000,000
Interest cost	10,000,000	10,000,000	5,000,000
Participant contributions	6,000,000	4,000,000
Actuarial (gain)/loss	(25,000,000)	(34,000,000)
Benefits paid	(29,000,000)	(19,000,000)
Plan settlements	(8,000,000)	1,000,000
Acquired in Merger Transaction	0	254,000,000
Foreign currency exchange rate changes	27,000,000	(17,000,000)
Other	(16,000,000)	0
Benefit obligation at beginning of year	305,000,000	337,000,000	133,000,000
Change in plan assets
Fair value of plan assets at beginning of year	213,000,000	115,000,000
Actual return/(loss) on plan assets	(13,000,000)	21,000,000
Employer contributions	8,000,000	1,000,000
Participant contributions	6,000,000	4,000,000
Benefits paid	(29,000,000)	(19,000,000)
Acquired in Merger Transaction	0	102,000,000
Foreign currency exchange rate changes	16,000,000	(11,000,000)
Other	(20,000,000)	0
Fair value of plan assets at end of year	181,000,000	213,000,000	$ 115,000,000
Underfunded status at end of year	(124,000,000)	(124,000,000)
Presented as follows:
Deferred amounts and other assets	2,000,000	7,000,000
Accounts payable and other	(7,000,000)	(7,000,000)
Other long-term liabilities	(119,000,000)	(124,000,000)
Amount recognized in balance sheet	$ (124,000,000)	$ (124,000,000)

PENSION AND OTHER POSTRETIREM_4

PENSION AND OTHER POSTRETIREMENT BENEFITS PENSION AND OTHER POSTRETIREMENT BENEFITS - AMOUNT RECOGNIZED IN EXCESS OF ACCUMULATED OTHER COMPREHENSIVE INCOME (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Canada
Pension and Other Postretirement Benefit Disclosures
Projected benefit obligations	$ 1,422	$ 1,444
Accumulated benefit obligations	1,299	1,306
Fair value of plan assets	1,064	1,131
United States
Pension and Other Postretirement Benefit Disclosures
Projected benefit obligations	1,214	1,280
Accumulated benefit obligations	1,179	1,217
Fair value of plan assets	$ 1,045	$ 1,098

PENSION AND OTHER POSTRETIREM_5

PENSION AND OTHER POSTRETIREMENT BENEFITS - AMOUNT RECOGNIZED IN ACCUMULATED OTHER COMPREHENSIVE INCOME (Details) - CAD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Canada | Pension
Amount included in AOCI
Net actuarial loss	$ 435	$ 334
Prior service credit	0	0
Total amount recognized in AOCI	435	334
Canada | OPEB
Amount included in AOCI
Net actuarial loss	(29)	17
Prior service credit	(2)	(2)
Total amount recognized in AOCI	(31)	15
United States | Pension
Amount included in AOCI
Net actuarial loss	133	112
Prior service credit	(3)	0
Total amount recognized in AOCI	130	112
United States | OPEB
Amount included in AOCI
Net actuarial loss	(15)	(15)
Prior service credit	(15)	(11)
Total amount recognized in AOCI	$ (30)	$ (26)

PENSION AND OTHER POSTRETIREM_6

PENSION AND OTHER POSTRETIREMENT BENEFITS - NET BENEFIT COSTS RECOGNIZED (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Pension | Canada
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	$ 149	$ 156	$ 129
Interest cost	130	116	73
Expected return on plan assets	(245)	(201)	(127)
Amortization/settlement of net actuarial loss	25	29	32
Amortization/curtailment of prior service cost	0	0	0
Net defined benefit costs	59	100	107
Defined contribution benefit costs	11	11	3
Net benefit cost recognized in Earnings	70	111	110
Amount recognized in OCI:
Amortization/settlement of net actuarial loss	(11)	(14)	(14)
Amortization/curtailment of prior service cost	0	0	0
Net actuarial loss arising during the year	112	38	28
Total amount recognized in OCI	101	24	14
Total amount recognized in Comprehensive income	171	135	124
Expected amortization, next fiscal year	32
Pension | United States
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	45	48	26
Interest cost	38	35	16
Expected return on plan assets	(88)	(57)	(21)
Amortization/settlement of net actuarial loss	7	10	3
Amortization/curtailment of prior service cost	3	0	0
Net defined benefit costs	5	36	24
Defined contribution benefit costs	19	15	0
Net benefit cost recognized in Earnings	24	51	24
Amount recognized in OCI:
Amortization/settlement of net actuarial loss	(7)	(9)	(6)
Amortization/curtailment of prior service cost	(3)	0	0
Net actuarial loss arising during the year	28	0	16
Total amount recognized in OCI	18	(9)	10
Total amount recognized in Comprehensive income	42	42	34
Expected amortization, next fiscal year	0
OPEB | Canada
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	8	7	4
Interest cost	10	10	6
Expected return on plan assets	0	0	0
Amortization/settlement of net actuarial loss	0	0	0
Amortization/curtailment of prior service cost	0	1	0
Net benefit cost recognized in Earnings	18	18	10
Amount recognized in OCI:
Amortization/settlement of net actuarial loss	0	(1)	(1)
Amortization/curtailment of prior service cost	0	0	0
Net actuarial loss arising during the year	(46)	(8)	2
Prior service (credit)/cost	0	(3)	0
Total amount recognized in OCI	(46)	(12)	1
Total amount recognized in Comprehensive income	(28)	6	11
Expected amortization, next fiscal year	0
OPEB | United States
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	3	5	4
Interest cost	10	10	5
Expected return on plan assets	(12)	(10)	(6)
Amortization/settlement of net actuarial loss	(1)	0	0
Amortization/curtailment of prior service cost	(4)	0	0
Net benefit cost recognized in Earnings	(4)	5	3
Amount recognized in OCI:
Amortization/settlement of net actuarial loss	1	1	(1)
Amortization/curtailment of prior service cost	4	0	0
Net actuarial loss arising during the year	(1)	(42)	12
Prior service (credit)/cost	(8)	1	(12)
Total amount recognized in OCI	(4)	(40)	(1)
Total amount recognized in Comprehensive income	(8)	$ (35)	$ 2
Expected amortization, next fiscal year	$ 2

PENSION AND OTHER POSTRETIREM_7

PENSION AND OTHER POSTRETIREMENT BENEFITS - ACTUARIAL ASSUMPTIONS (Details)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Pension | Canada
Projected benefit obligations
Discount rate	3.80%	3.60%	4.00%
Rate of salary increase	3.20%	3.20%	3.70%
Net benefit cost
Discount rate	3.60%	4.00%	4.20%
Rate of return on plan assets	6.80%	6.50%	6.50%
Rate of salary increase	3.20%	3.70%	3.60%
Pension | United States
Projected benefit obligations
Discount rate	3.90%	3.50%	4.00%
Rate of salary increase	2.80%	3.10%	3.30%
Net benefit cost
Discount rate	3.40%	4.00%	4.10%
Rate of return on plan assets	7.40%	7.20%	7.20%
Rate of salary increase	2.90%	3.30%	3.20%
OPEB | Canada
Projected benefit obligations
Discount rate	3.80%	3.60%	4.00%
Net benefit cost
Discount rate	3.60%	4.00%	4.20%
OPEB | United States
Projected benefit obligations
Discount rate	4.00%	3.50%	3.60%
Net benefit cost
Discount rate	3.30%	4.00%	3.80%
Rate of return on plan assets	5.70%	6.00%	6.00%

PENSION AND OTHER POSTRETIREM_8

PENSION AND OTHER POSTRETIREMENT BENEFITS - ASSUMED HEALTH CARE COST TREND RATES (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Canada
MEDICAL COST TRENDS
Health care cost trend rate assumed for next year	5.60%	5.50%
Rate to which the cost trend is assumed to decline (the ultimate trend rate)	4.40%	4.40%
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	$ 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	$ (16)
United States
MEDICAL COST TRENDS
Health care cost trend rate assumed for next year	7.40%	7.40%
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	$ 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	18
Decrease in benefit obligation due to 1% decrease in the assumed medical care trend rate	$ (17)

PENSION AND OTHER POSTRETIREM_9

PENSION AND OTHER POSTRETIREMENT BENEFITS - PLAN ASSETS (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Pension | Equity Securities, US | 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
Pension | Equity Securities, US | 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 | Equity securities
Pension and Other Postretirement Benefit Disclosures
Plan asset allocations	45800000.00%	52.00%
Canada | Fixed income securities
Pension and Other Postretirement Benefit Disclosures
Plan asset allocations	33400000.00%	34.20%
Canada | Other
Pension and Other Postretirement Benefit Disclosures
Plan asset allocations	20700000.00%	13.80%
Canada | Pension
Change in plan assets
Fair value of plan assets at beginning of year	$ 3,619	$ 2,019
Fair value of plan assets at end of year	3,523	3,619
Canada | Pension | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	2,861
Fair value of plan assets at end of year	2,979	2,861
Canada | Pension | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	418
Fair value of plan assets at end of year	(18)	418
Canada | Pension | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	340	281
Unrealized and realized gains	77	26
Purchases and settlements, net	145	33
Fair value of plan assets at end of year	562	340
Canada | Pension | Cash and Cash Equivalents | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	169
Fair value of plan assets at end of year	246	169
Canada | Pension | Cash and Cash Equivalents | Level 1 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	169
Fair value of plan assets at end of year	246	169
Canada | Pension | Equity Securities, Non-US
Change in plan assets
Fair value of plan assets at beginning of year	1,267
Fair value of plan assets at end of year	623	1,267
Canada | Pension | Equity Securities, Non-US | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	842
Fair value of plan assets at end of year	623	842
Canada | Pension | Equity Securities, Non-US | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	425
Fair value of plan assets at end of year	0	425
Canada | Pension | Equity Securities, Non-US | 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, US
Change in plan assets
Fair value of plan assets at beginning of year	427
Fair value of plan assets at end of year	(1)	427
Canada | Pension | Equity Securities, US | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	427
Fair value of plan assets at end of year	(1)	427
Canada | Pension | Equity Securities, Global
Change in plan assets
Fair value of plan assets at beginning of year	189
Fair value of plan assets at end of year	993	189
Canada | Pension | Equity Securities, Global | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	189
Fair value of plan assets at end of year	993	189
Canada | Pension | 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 | 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 | Government | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	933
Fair value of plan assets at end of year	661	933
Canada | Pension | Government | Level 1 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	933
Fair value of plan assets at end of year	661	933
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	304
Fair value of plan assets at end of year	517	304
Canada | Pension | Corporate | Level 1 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	301
Fair value of plan assets at end of year	457	301
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	0	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	60	0
Canada | Pension | Infrastructure and real estate | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	340
Fair value of plan assets at end of year	502	340
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	340
Fair value of plan assets at end of year	502	340
Canada | Pension | Forward currency contracts | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	(10)
Fair value of plan assets at end of year	(18)	(10)
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	(10)
Fair value of plan assets at end of year	(18)	(10)
Canada | Pension | Forward currency contracts | 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
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
Change in plan assets
Fair value of plan assets at beginning of year	0	0
Unrealized and realized gains	0	0
Purchases and settlements, net	0	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 | 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 | Equity Securities, US
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, US | 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, US | 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, US | 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 | 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
Canada | OPEB | 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 | OPEB | 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 | OPEB | Corporate | Fair Value
Change in plan assets
Fair value of plan assets at end of year	0
Canada | OPEB | Corporate | Level 1 | Fair Value
Change in plan assets
Fair value of plan assets at end of year	0
Canada | OPEB | Corporate | Level 2 | Fair Value
Change in plan assets
Fair value of plan assets at end of year	0
Canada | OPEB | Corporate | Level 3 | Fair Value
Change in plan assets
Fair value of plan assets at end of year	0
Canada | OPEB | Infrastructure and real estate | Fair Value
Change in plan assets
Fair value of plan assets at end of year	0
Canada | OPEB | Infrastructure and real estate | Level 1 | Fair Value
Change in plan assets
Fair value of plan assets at end of year	0
Canada | OPEB | Infrastructure and real estate | Level 2 | Fair Value
Change in plan assets
Fair value of plan assets at end of year	0
Canada | OPEB | Infrastructure and real estate | Level 3 | Fair Value
Change in plan assets
Fair value of plan assets at end of year	$ 0
United States | Equity securities
Pension and Other Postretirement Benefit Disclosures
Plan asset allocations	51.70%	47.10%
United States | Fixed income securities
Pension and Other Postretirement Benefit Disclosures
Plan asset allocations	32.90%	47.70%
United States | Other
Pension and Other Postretirement Benefit Disclosures
Plan asset allocations	15.40%	5.20%
United States | Pension
Change in plan assets
Fair value of plan assets at beginning of year	$ 1,097	$ 361
Fair value of plan assets at end of year	1,045	1,097
United States | Pension | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	989
Fair value of plan assets at end of year	915	989
United States | Pension | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	52
Fair value of plan assets at end of year	0	52
United States | Pension | Level 3
Change in plan assets
Fair value of plan assets at beginning of year	56	40
Unrealized and realized gains	9	5
Purchases and settlements, net	65	11
Fair value of plan assets at end of year	130	56
United States | Pension | Cash and Cash Equivalents | 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	56	2
United States | Pension | Cash and Cash Equivalents | Level 1 | 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	56	2
United States | Pension | Equity Securities, Non-US
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 | Equity Securities, Non-US | 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	1	0
United States | Pension | Equity Securities, Non-US | 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, Non-US | 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, US
Change in plan assets
Fair value of plan assets at beginning of year	343
Fair value of plan assets at end of year	50	343
United States | Pension | Equity Securities, US | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	343
Fair value of plan assets at end of year	50	343
United States | Pension | Equity Securities, Global
Change in plan assets
Fair value of plan assets at beginning of year	174
Fair value of plan assets at end of year	489	174
United States | Pension | Equity Securities, Global | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	122
Fair value of plan assets at end of year	489	122
United States | Pension | Equity Securities, Global | Level 2
Change in plan assets
Fair value of plan assets at beginning of year	52
Fair value of plan assets at end of year	0	52
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 | 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	265	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	265	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	523
Fair value of plan assets at end of year	79	523
United States | Pension | Corporate | Level 1 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	522
Fair value of plan assets at end of year	54	522
United States | Pension | Corporate | Level 2 | 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	0	1
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	25	0
United States | Pension | Infrastructure and real estate | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	56
Fair value of plan assets at end of year	105	56
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	56
Fair value of plan assets at end of year	105	56
United States | Pension | Forward currency contracts | 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	0	(1)
United States | 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
United States | Pension | Forward currency contracts | Level 2 | 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	0	(1)
United States | Pension | Forward currency contracts | 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
Change in plan assets
Fair value of plan assets at beginning of year	213	115
Fair value of plan assets at end of year	181	213
United States | OPEB | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	213
Fair value of plan assets at end of year	181	213
United States | OPEB | Level 1 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	213
Fair value of plan assets at end of year	176	213
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
Change in plan assets
Fair value of plan assets at beginning of year	0	0
Unrealized and realized gains	0	0
Purchases and settlements, net	5	0
Fair value of plan assets at end of year	5	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	5	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	7	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	7	1
United States | OPEB | Equity Securities, US
Change in plan assets
Fair value of plan assets at beginning of year	80
Fair value of plan assets at end of year	63	80
United States | OPEB | Equity Securities, US | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	80
Fair value of plan assets at end of year	63	80
United States | OPEB | Equity Securities, US | 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, US | 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	36
Fair value of plan assets at end of year	35	36
United States | OPEB | Equity Securities, Global | Level 1
Change in plan assets
Fair value of plan assets at beginning of year	36
Fair value of plan assets at end of year	35	36
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 | Government | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	96
Fair value of plan assets at end of year	68	96
United States | OPEB | Government | Level 1 | Fair Value
Change in plan assets
Fair value of plan assets at beginning of year	96
Fair value of plan assets at end of year	68	96
United States | OPEB | 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 | OPEB | 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 | OPEB | Corporate | Fair Value
Change in plan assets
Fair value of plan assets at end of year	5
United States | OPEB | Corporate | Level 1 | Fair Value
Change in plan assets
Fair value of plan assets at end of year	3
United States | OPEB | Corporate | Level 2 | Fair Value
Change in plan assets
Fair value of plan assets at end of year	0
United States | OPEB | Corporate | Level 3 | Fair Value
Change in plan assets
Fair value of plan assets at end of year	2
United States | OPEB | Infrastructure and real estate | Fair Value
Change in plan assets
Fair value of plan assets at end of year	3
United States | OPEB | Infrastructure and real estate | Level 1 | Fair Value
Change in plan assets
Fair value of plan assets at end of year	0
United States | OPEB | Infrastructure and real estate | Level 2 | Fair Value
Change in plan assets
Fair value of plan assets at end of year	0
United States | OPEB | Infrastructure and real estate | Level 3 | Fair Value
Change in plan assets
Fair value of plan assets at end of year	$ 3
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 POSTRETIRE_10

PENSION AND OTHER POSTRETIREMENT BENEFITS - EXPECTED BENEFIT PAYMENTS AND EMPLOYER CONTRIBUTIONS (Details) $ in Millions	Dec. 31, 2018CAD ($)
Canada | Pension
Benefits Expected to be Paid by the Company
Expected future benefit payments for 2019	$ 174
Expected future benefit payments for 2020	180
Expected future benefit payments for 2021	187
Expected future benefit payments for 2022	194
Expected future benefit payments for 2023	201
Expected future benefit payments for 2023-2027	1,104
Contributions expected to be paid in next fiscal year	47
Canada | OPEB
Benefits Expected to be Paid by the Company
Expected future benefit payments for 2019	13
Expected future benefit payments for 2020	12
Expected future benefit payments for 2021	13
Expected future benefit payments for 2022	13
Expected future benefit payments for 2023	13
Expected future benefit payments for 2023-2027	39
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 2019	124
Expected future benefit payments for 2020	96
Expected future benefit payments for 2021	97
Expected future benefit payments for 2022	98
Expected future benefit payments for 2023	95
Expected future benefit payments for 2023-2027	438
Contributions expected to be paid in next fiscal year	114
United States | OPEB
Benefits Expected to be Paid by the Company
Expected future benefit payments for 2019	26
Expected future benefit payments for 2020	26
Expected future benefit payments for 2021	25
Expected future benefit payments for 2022	24
Expected future benefit payments for 2023	23
Expected future benefit payments for 2023-2027	98
Contributions expected to be paid in next fiscal year	$ 13

PENSION AND OTHER POSTRETIRE_11

PENSION AND OTHER POSTRETIREMENT BENEFITS - RETIREMENT SAVINGS PLAN (Details) - CAD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Canada
Pension and Other Postretirement Benefit Disclosures
Percent of match	5.00%
Total contributions by the Company	$ 13,000,000	$ 14,000,000	$ 0
United States
Pension and Other Postretirement Benefit Disclosures
Percent of match	6.00%
Total contributions by the Company	$ 27,000,000	$ 31,000,000	$ 13,000,000

CHANGES IN OPERATING ASSETS A_3

CHANGES IN OPERATING ASSETS AND LIABILITIES (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
CHANGES IN OPERATING ASSETS AND LIABILITIES
Accounts receivable and other	$ 857	$ (783)	$ (437)
Accounts receivable from affiliates	54	24	(7)
Inventory	164	(289)	(371)
Deferred amounts and other assets	226	(138)	(183)
Accounts payable and other	(151)	277	386
Accounts payable to affiliates	(122)	(62)	71
Interest payable	25	124	20
Other long-term liabilities	(138)	509	153
Changes in operating assets and liabilities	$ 915	$ (338)	$ (368)

RELATED PARTY TRANSACTIONS (Det

RELATED PARTY TRANSACTIONS (Details) $ in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)	Dec. 31, 2018CAD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2017CAD ($)	Dec. 31, 2016CAD ($)
RELATED PARTY TRANSACTIONS
Amounts charged to the Company for transportation services		$ 572		$ 721	$ 644
Purchase of natural gas by wholly owned subsidiaries		322		142	98
Sale of natural gas by wholly owned subsidiaries		122		60	49
Revenue from contract with customer		$ 21,150
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)	8.00%	8.00%
Cost Recoveries
RELATED PARTY TRANSACTIONS
Revenue from related parties	$ 80	$ 104	$ 68	88
Vector Pipeline joint venture
RELATED PARTY TRANSACTIONS
Revenue from related parties		7		14	$ 7
Spectra Energy Corp | Reimbursed Maintenance Expenses
RELATED PARTY TRANSACTIONS
Revenue from related parties	22	28	8	10
Other affiliates
RELATED PARTY TRANSACTIONS
Amounts receivable from affiliates		769		275
Natural Gas, Midstream | DCP Midstream, LLC
RELATED PARTY TRANSACTIONS
Revenue from contract with customer	40	52	36	47
Natural Gas, Storage | DCP Midstream, LLC
RELATED PARTY TRANSACTIONS
Revenue from contract with customer	$ 11	$ 14	$ 3	$ 4

COMMITMENTS AND CONTINGENCIES -

COMMITMENTS AND CONTINGENCIES - COMMITMENTS (Details) $ in Millions	Dec. 31, 2018CAD ($)
Annual debt maturities
Total	$ 62,967
Less than 1 year	3,255
2 years	9,262
3 years	2,389
4 years	4,571
5 years	5,963
Thereafter	37,527
Interest obligations
Total	30,236
Less than 1 year	2,459
2 years	2,279
3 years	2,103
4 years	2,022
5 years	1,883
Thereafter	19,490
Purchase of services, pipe and other materials, including transportation
Total	11,084
Less than 1 year	3,833
2 years	1,473
3 years	1,225
4 years	1,025
5 years	501
Thereafter	3,027
Operating leases
Total	1,079
Less than 1 year	132
2 years	134
3 years	100
4 years	98
5 years	93
Thereafter	522
Capital leases
Total	23
Less than 1 year	7
2 years	0
3 years	0
4 years	2
5 years	2
Thereafter	12
Maintenance agreements
Total	477
Less than 1 year	52
2 years	51
3 years	51
4 years	50
5 years	22
Thereafter	251
Land lease commitments
Total	651
Less than 1 year	21
2 years	21
3 years	21
4 years	21
5 years	22
Thereafter	545
Total
Total	106,517
Total Less than 1 year	9,759
Total 2 years	13,220
Total 3 years	5,889
Total 4 years	7,789
Total 5 years	8,486
Total thereafter	$ 61,374

COMMITMENTS AND CONTINGENCIES_2

COMMITMENTS AND CONTINGENCIES - ENVIRONMENTAL (Details) - CAD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Operating leases, rent expense	$ 91	$ 108	$ 79

SUBSEQUENT EVENTS (Details)

SUBSEQUENT EVENTS (Details) $ in Millions	Jan. 15, 2019CAD ($)	Dec. 31, 2018CAD ($)	Dec. 31, 2017CAD ($)	Dec. 31, 2016CAD ($)	Jan. 08, 2019$ / CAD_dollar_per_principal
SUBSEQUENT EVENTS
Payments to acquire property, plant, and equipment		$ 6,806	$ 8,287	$ 5,128
Subsequent Event
SUBSEQUENT EVENTS
Percentage of assets acquired	100.00%
Payments to acquire property, plant, and equipment	$ 265
Enbridge Energy Partners and Spectra Energy Partners | Subsequent Event
SUBSEQUENT EVENTS
Notes payable, cash payment per $1,000 principal amount | $ / CAD_dollar_per_principal					1

QUARTERLY FINANCIAL DATA (Detai

QUARTERLY FINANCIAL DATA (Details) - CAD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Total operating revenues (Note 4)	$ 11,562	$ 11,345	$ 10,745	$ 12,726	$ 12,889	$ 9,227	$ 11,116	$ 11,146	$ 46,378	$ 44,378	$ 34,560
Operating income	1,513	854	1,571	878	(2,961)	1,490	1,684	1,358	4,816	1,571	2,581
Earnings	1,283	213	1,327	510	65	1,015	1,241	945	3,333	3,266	2,309
Earnings attributable to controlling interests	1,184	4	1,160	534	291	847	1,000	721	2,882	2,859	2,069
Earnings/(loss) attributable to common shareholders	$ 1,089	$ (90)	$ 1,071	$ 445	$ 207	$ 765	$ 919	$ 638	$ 2,515	$ 2,529	$ 1,776
Earnings/(loss) per common share
Basic (in dollars per share)	$ 0.60	$ (0.05)	$ 0.63	$ 0.26	$ 0.13	$ 0.47	$ 0.56	$ 0.54	$ 1.46	$ 1.66	$ 1.95
Diluted (in dollars per share)	$ 0.60	$ (0.05)	$ 0.63	$ 0.26	$ 0.12	$ 0.47	$ 0.56	$ 0.54	$ 1.46	$ 1.65	$ 1.93