Enbridge (ENB) 10-Q 10 May 18 2018 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2018	May 04, 2018
Document And Entity Information [Abstract]
Entity Registrant Name	ENBRIDGE INC
Entity Central Index Key	895,728
Document Type	10-Q
Document Period End Date	Mar. 31, 2018
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		1,704,740,177
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q1

CONSOLIDATED STATEMENTS OF EARN

CONSOLIDATED STATEMENTS OF EARNINGS - CAD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Operating revenues
Commodity sales	$ 7,268	$ 6,866
Gas distribution sales	1,926	1,363
Transportation and other services	3,532	2,917
Total operating revenues (Note 3)	12,726	11,146
Operating expenses
Commodity costs	6,997	6,550
Gas distribution costs	1,324	1,015
Operating and administrative	1,641	1,551
Depreciation and amortization	824	672
Asset impairment (Note 6)	1,062	0
Total operating expenses	11,848	9,788
Operating income	878	1,358
Income from equity investments	335	236
Other income/(expense)
Net foreign currency loss	(185)	(5)
Other	65	40
Interest expense	(656)	(486)
Earnings before income taxes	437	1,143
Income tax recovery/(expense) (Note 11)	73	(198)
Earnings	510	945
(Earnings)/loss attributable to noncontrolling interests and redeemable noncontrolling interests	24	(224)
Earnings attributable to controlling interests	534	721
Preference share dividends	(89)	(83)
Earnings attributable to common shareholders	$ 445	$ 638
Earnings per common share attributable to common shareholders (Note 5) (in Canadian dollars per share)	$ 0.26	$ 0.54
Diluted earnings per common share attributable to common shareholders (Note 5) (in Canadian dollars per share)	$ 0.26	$ 0.54

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - CAD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Statement of Comprehensive Income [Abstract]
Earnings	$ 510	$ 945
Other comprehensive income/(loss), net of tax
Change in unrealized gain/(loss) on cash flow hedges	66	(2)
Change in unrealized gain/(loss) on net investment hedges	(184)	49
Other comprehensive income from equity investees	14	6
Reclassification to earnings of loss on cash flow hedges	37	41
Reclassification to earnings of pension and other postretirement benefits (OPEB) amounts	(39)	4
Foreign currency translation adjustments	1,579	432
Other comprehensive income, net of tax	1,473	530
Comprehensive income	1,983	1,475
Comprehensive income attributable to noncontrolling interests and redeemable noncontrolling interests	(147)	(374)
Comprehensive income attributable to controlling interests	1,836	1,101
Preference share dividends	(89)	(83)
Comprehensive income attributable to common shareholders	$ 1,747	$ 1,018

CONSOLIDATED STATEMENTS OF CHAN

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY - CAD ($) $ in Millions	Total	Preferred share investment	Common shares	Additional paid-in capital	Retained earnings/(deficit)	Accumulated other comprehensive income	Reciprocal shareholding	Total Enbridge Inc. shareholders' equity	Noncontrolling interests
Balance at Dec. 31, 2016		$ 7,255	$ 10,492	$ 3,399	$ (716)	$ 1,058	$ (102)		$ 577
Increase (Decrease) in Stockholders' Equity
Common shares issued in Merger Transaction			37,428
Dividend Reinvestment and Share Purchase Plan			194
Stock-based compensation				35
Fair value of outstanding earned stock-based compensation from Merger Transaction				77
Options exercised			33	(49)
Dilution gain on Spectra Energy Partners, LP restructuring (Note 9)				0
Dilution loss and other				(36)
Earnings attributable to controlling interests	$ 721				721
Preference share dividends					(83)
Common share dividends declared					(548)
Dividends paid to reciprocal shareholder					7
Redemption value adjustment attributable to redeemable noncontrolling interests					152
Adjustment for the recognition of unutilized tax deductions for stock-based compensation expense					41
Other									3
Other comprehensive income attributable to common shareholders, net of tax						380
Earnings attributable to noncontrolling interests									192
Change in unrealized gain/(loss) on cash flow hedges									(1)
Foreign currency translation adjustments									141
Reclassification to earnings of loss on cash flow hedges									10
Other comprehensive income/(loss) attributable to noncontrolling interests, net of tax									150
Comprehensive income attributable to noncontrolling interests									342
Noncontrolling interests resulting from Merger Transaction									8,792
Enbridge Energy Company, Inc. common control transaction									43
Distributions									(191)
Contributions									215
Spectra Energy Partners, LP restructuring (Note 9)									0
Balance at Mar. 31, 2017	$ 69,519	7,255	48,147	3,426	(426)	1,438	(102)	$ 59,738	9,781
Increase (Decrease) in Stockholders' Equity
Dividends paid per common share (in Canadian dollars per share)	$ 0.583
Retrospective adoption of accounting standard (Note 2)					0
Balance at Dec. 31, 2017	$ 65,732	7,747	50,737	3,194	(2,468)	(973)	(102)		7,597
Increase (Decrease) in Stockholders' Equity
Common shares issued in Merger Transaction			0
Dividend Reinvestment and Share Purchase Plan			374
Stock-based compensation				17
Fair value of outstanding earned stock-based compensation from Merger Transaction				0
Options exercised			16	(6)
Dilution gain on Spectra Energy Partners, LP restructuring (Note 9)				1,136
Dilution loss and other				(28)
Earnings attributable to controlling interests	534				534
Preference share dividends					(89)
Common share dividends declared					0
Dividends paid to reciprocal shareholder					7
Redemption value adjustment attributable to redeemable noncontrolling interests					120
Adjustment for the recognition of unutilized tax deductions for stock-based compensation expense					0
Other									(15)
Other comprehensive income attributable to common shareholders, net of tax						1,302
Earnings attributable to noncontrolling interests									23
Change in unrealized gain/(loss) on cash flow hedges									4
Foreign currency translation adjustments									152
Reclassification to earnings of loss on cash flow hedges									8
Other comprehensive income/(loss) attributable to noncontrolling interests, net of tax									164
Comprehensive income attributable to noncontrolling interests									187
Noncontrolling interests resulting from Merger Transaction									0
Enbridge Energy Company, Inc. common control transaction									0
Distributions									(209)
Contributions									8
Spectra Energy Partners, LP restructuring (Note 9)									(1,486)
Balance at Mar. 31, 2018	$ 67,514	$ 7,747	$ 51,127	$ 4,313	(1,982)	$ 329	$ (102)	$ 61,432	$ 6,082
Increase (Decrease) in Stockholders' Equity
Dividends paid per common share (in Canadian dollars per share)	$ 0.671
Retrospective adoption of accounting standard (Note 2)					$ (86)

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - CAD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Operating activities
Earnings	$ 510	$ 945
Adjustments to reconcile earnings to net cash provided by operating activities:
Depreciation and amortization	824	672
Deferred income tax expense	(147)	161
Changes in unrealized (gain)/loss on derivative instruments, net (Note 10)	260	(418)
Earnings from equity investments	(335)	(236)
Distributions from equity investments	320	214
Asset impairment	1,062	0
Gain on dispositions	0	(14)
Other	78	112
Changes in operating assets and liabilities	622	340
Net cash provided by operating activities	3,194	1,776
Investing activities
Capital expenditures	(1,635)	(1,642)
Long-term investments	(209)	(2,537)
Distributions from equity investments in excess of cumulative earnings	57	11
Restricted long-term investments	(13)	(15)
Additions to intangible assets	(258)	(233)
Cash acquired in Merger Transaction	0	681
Proceeds from dispositions	0	289
Affiliate loans, net	(10)	(2)
Net cash used in investing activities	(2,068)	(3,448)
Financing activities
Net change in short-term borrowings	(443)	110
Net change in commercial paper and credit facility draws	(465)	2,662
Debenture and term note issues, net of issue costs	2,061	0
Debenture and term note repayments	(996)	(513)
Debt extinguishment costs	(63)	0
Contributions from noncontrolling interests	8	215
Distributions to noncontrolling interests	(209)	(271)
Contributions from redeemable noncontrolling interests	20	11
Distributions to redeemable noncontrolling interests	(84)	(54)
Common shares issued	13	4
Preference share dividends	(87)	(83)
Common share dividends	(764)	(768)
Net cash provided by/(used in) financing activities	(1,009)	1,313
Effect of translation of foreign denominated cash and cash equivalents and restricted cash	19	(9)
Net increase/(decrease) in cash and cash equivalents and restricted cash	136	(368)
Cash and cash equivalents and restricted cash at beginning of period	587	1,562
Cash and cash equivalents and restricted cash at end of period	723	1,194
Supplementary cash flow information
Property, plant and equipment non-cash accruals	$ 754	$ 1,019

CONSOLIDATED STATEMENTS OF FINA

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION - CAD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Current assets
Cash and cash equivalents	$ 610	$ 480
Restricted cash	113	107
Accounts receivable and other	6,271	7,053
Accounts receivable from affiliates	48	47
Inventory	872	1,528
Total current assets	7,914	9,215
Property, plant and equipment, net	92,521	90,711
Long-term investments	17,360	16,644
Restricted long-term investments	280	267
Deferred amounts and other assets	5,614	6,442
Intangible assets, net	3,455	3,267
Goodwill	35,168	34,457
Deferred income taxes	1,182	1,090
Total assets	163,494	162,093
Current liabilities
Short-term borrowings	1,004	1,444
Accounts payable and other	6,823	9,478
Accounts payable to affiliates	168	157
Interest payable	592	634
Environmental liabilities	33	40
Current portion of long-term debt	4,152	2,871
Total current liabilities	12,772	14,624
Long-term debt	61,191	60,865
Other long-term liabilities	8,390	7,510
Deferred income taxes	9,812	9,295
Total liabilities	92,165	92,294
Contingencies (Note 13)
Redeemable noncontrolling interests	3,815	4,067
Share capital
Preference shares	7,747	7,747
Common shares (1,705 and 1,695 outstanding at March 31, 2018 and December 31, 2017, respectively)	51,127	50,737
Additional paid-in capital	4,313	3,194
Deficit	(1,982)	(2,468)
Accumulated other comprehensive income/(loss) (Note 8)	329	(973)
Reciprocal shareholding	(102)	(102)
Total Enbridge Inc. shareholders’ equity	61,432	58,135
Noncontrolling interests	6,082	7,597
Total equity	67,514	65,732
Total liabilities and equity	$ 163,494	$ 162,093

CONSOLIDATED STATEMENTS OF FIN7

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION (Parenthetical) - shares shares in Millions	Mar. 31, 2018	Dec. 31, 2017
Statement of Financial Position [Abstract]
Common shares, outstanding (in shares)	1,705	1,695

BASIS OF PRESENTATION

BASIS OF PRESENTATION	3 Months Ended
	Mar. 31, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
BASIS OF PRESENTATION	BASIS OF PRESENTATION The accompanying unaudited interim consolidated financial statements of Enbridge Inc. have been prepared in accordance with generally accepted accounting principles in the United States of America (U.S. GAAP) and Regulation S-X for interim consolidated financial information. They do not include all of the information and notes required by U.S. GAAP for annual consolidated financial statements and should therefore be read in conjunction with our audited consolidated financial statements and notes for the year ended December 31, 2017 included in our Annual Report on Form 10-K. In the opinion of management, the interim consolidated financial statements contain all normal recurring adjustments necessary to present fairly our financial position, results of operations and cash flows for the interim periods reported. These interim consolidated financial statements follow the same significant accounting policies as those included in our annual consolidated financial statements for the year ended December 31, 2017 , except for the adoption of new standards (Note 2) and the presentation of Cash and cash equivalents to include Bank indebtedness, as discussed below. Amounts are stated in Canadian dollars unless otherwise noted. Our operations and earnings for interim periods can be affected by seasonal fluctuations within the gas distribution utility businesses, as well as other factors such as the supply of and demand for crude oil and natural gas, and may not be indicative of annual results. Effective September 30, 2017, we combined Cash and cash equivalents and amounts previously presented as Bank indebtedness where the corresponding bank accounts are subject to cash pooling arrangements. As at March 31, 2018 and December 31, 2017 , $0.9 billion and $0.6 billion of Bank indebtedness has been combined within Cash and cash equivalents in our Consolidated Statements of Financial Position, respectively. Net cash provided by financing activities in our Consolidated Statements of Cash Flows for the three months period ended March 31, 2017 have been reduced by $0.2 billion to reflect this change. Certain comparative figures in our Consolidated Statement of Cash Flows have been reclassified to conform with the current year's presentation. In addition, activities for the three months ended March 31, 2017 relating to distributions to noncontrolling interests in relation to the Merger Transaction have been reclassified, resulting in an increase to investing activities of $67 million and a decrease to financing activities of $67 million .

CHANGES IN ACCOUNTING POLICIES

CHANGES IN ACCOUNTING POLICIES	3 Months Ended
	Mar. 31, 2018
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
CHANGES IN ACCOUNTING POLICIES	CHANGES IN ACCOUNTING POLICIES ADOPTION OF NEW 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) enacted by the United States federal government on December 22, 2017. The amendments in this accounting update allow a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the TCJA. The amendments will eliminate the stranded tax effects 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 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 statement 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 Statement 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 Statement 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 instruments for disclosure purposes is measured using exit price. 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 obligations. 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 along with explanations of those effects. For the three months ended March 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 1,2 6,442 (170 ) 6,272 Property, plant and equipment, net 2 90,711 112 90,823 Liabilities and equity Accounts payable and other 1,2 9,478 62 9,540 Other long-term liabilities 2 7,510 66 7,576 Deferred income taxes 1,2 9,295 (62 ) 9,233 Redeemable noncontrolling interests 1,2 4,067 (38 ) 4,029 Deficit 1,2 (2,468 ) (86 ) (2,554 ) 1 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. 2 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. FUTURE ACCOUNTING POLICY CHANGES Improvements to Accounting for Hedging Activities ASU 2017-12 was issued in August 2017 with the objective of better aligning a company’s risk management activities and the resulting hedge accounting reflected in the financial statements. The amendments allow cash flow hedging of contractually specified components in financial and non-financial items. Under the new guidance, hedge ineffectiveness is no longer required to be measured and hedging instruments’ fair value changes will be recorded in the same income statement line as the hedged item. The ASU also allows the initial quantitative hedge effectiveness assessment to be performed at any time before the end of the quarter in which the hedge is designated. After initial quantitative testing is performed, an ongoing qualitative effectiveness assessment is permitted. The accounting update is effective January 1, 2019, with early adoption permitted, and is to be applied on a modified retrospective basis. We are currently assessing the impact of the new standard on our consolidated financial statements. Amending the Amortization Period for Certain Callable Debt Securities Purchased at a Premium ASU 2017-08 was issued in March 2017 with the intent of shortening the amortization period to the earliest call date for certain callable debt securities held at a premium. The accounting update is effective January 1, 2019 and will be applied on a modified retrospective basis. We are currently assessing the impact of the new standard on our consolidated financial statements. Accounting for Credit Losses ASU 2016-13 was issued in June 2016 with the intent of providing financial statement users with more useful information about the expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity at each reporting date. Current treatment uses the incurred loss methodology for recognizing credit losses that delays the recognition until it is probable a loss has been incurred. The accounting update adds a new impairment model, known as the current expected credit loss model, which is based on expected losses rather than incurred losses. Under the new guidance, an entity will recognize as an allowance its estimate of expected credit losses, which the Financial Accounting Standards Board believes will result in more timely recognition of such losses. The accounting update is effective January 1, 2020. We are currently assessing the impact of the new standard on our consolidated financial statements. Recognition of Leases ASU 2016-02 was issued in February 2016 with the intent to increase transparency and comparability among organizations. It requires lessees of operating lease arrangements to recognize lease assets and lease liabilities on the statement of financial position and disclose additional key information about lease agreements. The accounting update also replaces the current definition of a lease and requires that an arrangement be recognized as a lease when a customer has the right to obtain substantially all of the economic benefits from the use of an asset, as well as the right to direct the use of the asset. We are currently gathering a complete inventory of our lease contracts in order to assess the impact of the new standard on our consolidated financial statements. We will adopt the new standard on January 1, 2019 and we are currently evaluating options with respect to the transition practical expedients offered in connection with this update. Further, ASU 2018-01 was issued in January 2018 to address stakeholder concerns about the costs and complexity of complying with the transition provisions of the new lease requirements as they relate to land easements. The amendments provide an optional transition practical expedient to not evaluate existing or expired land easements that were not previously accounted for as leases under existing guidance. We intend to elect this practical expedient in connection with the adoption of the new lease requirements.

REVENUE

REVENUE	3 Months Ended
	Mar. 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 Three months ended (millions of Canadian dollars) Transportation revenue 2,058 952 239 — — — 3,249 Storage and other revenue 40 60 66 — — — 166 Gas gathering and processing revenue — 205 — — — — 205 Gas distribution revenue — — 1,926 — — — 1,926 Electricity and transmission revenue — — — 154 — — 154 Commodity sales — 693 — — — — 693 Total revenue from contracts with customers 2,098 1,910 2,231 154 — — 6,393 Commodity sales — — — — 6,575 — 6,575 Other revenue 1 (269 ) 25 2 3 — (3 ) (242 ) Intersegment revenue 80 2 4 — 57 (143 ) — Total revenue 1,909 1,937 2,237 157 6,632 (146 ) 12,726 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 at adoption date 2,475 290 992 Balance at reporting date 2,533 290 1,008 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 current period included in contract liabilities at the beginning of the period is $95 million . Increases in contract liabilities from cash received, net of amounts recognized as revenue during the three months ended March 31, 2018 , were $96 million during the period. Performance Obligations Business Unit Nature of Performance Obligation Transportation services - pipelines • Transportation and storage of crude oil, natural gas and natural gas liquids (NGL) Gas Transmission and Midstream • Sale of crude oil, natural gas and NGLs • Transportation, storage, gathering, compression and treating of natural gas 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 current period 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 $63.8 billion , of which $5.7 billion and $5.9 billion is expected to be recognized during the nine months ending December 31, 2018 and year ending December 31, 2019 , respectively. 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. Those revenues are not included in 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. Additionally, the effect of escalation on certain tolls which are contractually escalated for inflation has not been reflected in the amounts above as it is not possible to reliably estimate future inflation rates. Finally, revenues from contracts with customers which have an original expected duration of one year or less are excluded from the amounts above. 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 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 Three months ended (millions of Canadian dollars) Revenue from products transferred at a point in time 1 — 693 25 — — 718 Revenue from products and services transferred over time 2 2,098 1,217 2,206 154 — 5,675 Total revenue from contracts with customers 2,098 1,910 2,231 154 — 6,393 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 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	3 Months Ended
	Mar. 31, 2018
Segment Reporting [Abstract]
SEGMENTED INFORMATION	SEGMENTED INFORMATION Effective December 31, 2017, we changed our segment-level profit measure to Earnings before interest, income taxes and depreciation and amortization from the previous measure of Earnings before interest and income taxes. We also renamed the Gas Pipelines and Processing segment to Gas Transmission and Midstream. The presentation of the prior year table has been revised in order to align with the current presentation. Liquids Pipelines Gas Transmission and Midstream Gas Distribution Green Power and Transmission Energy Services Eliminations and Other Consolidated Three months ended (millions of Canadian dollars) Revenues 1,909 1,937 2,237 157 6,632 (146 ) 12,726 Commodity and gas distribution costs (4 ) (620 ) (1,388 ) — (6,455 ) 146 (8,321 ) Operating and administrative (747 ) (507 ) (248 ) (30 ) (12 ) (97 ) (1,641 ) Asset impairment (144 ) (913 ) — — — (5 ) (1,062 ) Income/(loss) from equity investments 131 208 17 (25 ) 4 — 335 Other income/(expense) 11 21 18 7 — (177 ) (120 ) Earnings/(loss) before interest, income taxes, and depreciation and amortization 1,156 126 636 109 169 (279 ) 1,917 Depreciation and amortization (824 ) Interest expense (656 ) Income tax recovery 73 Earnings 510 Capital expenditures 1 615 825 183 14 — 6 1,643 Liquids Pipelines Gas Transmission and Midstream Gas Distribution Green Power and Transmission Energy Services Eliminations and Other Consolidated Three months ended (millions of Canadian dollars) Revenues 2,155 1,235 1,584 137 6,133 (98 ) 11,146 Commodity and gas distribution costs (3 ) (647 ) (1,046 ) 1 (5,968 ) 98 (7,565 ) Operating and administrative (760 ) (254 ) (189 ) (40 ) (12 ) (296 ) (1,551 ) Income from equity investments 86 110 36 2 2 — 236 Other income/(expense) 2 31 2 1 1 (2 ) 35 Earnings/(loss) before interest, income taxes, and depreciation and amortization 1,480 475 387 101 156 (298 ) 2,301 Depreciation and amortization (672 ) Interest expense (486 ) Income tax expense (198 ) Earnings 945 Capital expenditures 1 654 655 183 114 — 59 1,665 1 Includes allowance for equity funds used during construction. TOTAL ASSETS March 31, 2018 December 31, 2017 (millions of Canadian dollars) Liquids Pipelines 64,842 63,881 Gas Transmission and Midstream 61,880 60,745 Gas Distribution 25,784 25,956 Green Power and Transmission 6,466 6,289 Energy Services 1,628 2,514 Eliminations and Other 2,894 2,708 163,494 162,093

EARNINGS PER COMMON SHARE

EARNINGS PER COMMON SHARE	3 Months Ended
	Mar. 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 13 million for the three months ended March 31, 2018 and 2017 , resulting from our reciprocal investment in Noverco Inc. 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: Three months ended 2018 2017 (number of common shares in millions) Weighted average shares outstanding 1,685 1,177 Effect of dilutive options 4 10 Diluted weighted average shares outstanding 1,689 1,187 For the three months ended March 31, 2018 and 2017 , 29,882,142 and 13,545,193 , respectively, of anti-dilutive stock options with a weighted average exercise price of $49.80 and $57.71 , respectively, were excluded from the diluted earnings per common share calculation.

ASSETS HELD FOR SALE

ASSETS HELD FOR SALE	3 Months Ended
	Mar. 31, 2018
Discontinued Operations and Disposal Groups [Abstract]
ASSET HELD FOR SALE	ASSETS HELD FOR SALE Midcoast Operating, L.P. On May 9, 2018 our indirect subsidiary, Enbridge (U.S.) Inc. entered into a definitive agreement to sell Midcoast Operating, L.P. and its subsidiaries (Sales Agreement), which conducts our United States natural gas and NGL gathering, processing, transportation and marketing businesses, to AL Midcoast Holdings, LLC (an affiliate of ArcLight Capital Partners, LLC) for a cash purchase price of US $1.1 billion , subject to customary closing adjustments. The transaction is expected to close in the third quarter of 2018, subject to receipt of customary regulatory approvals and satisfaction of other customary closing conditions. These assets, excluding our equity method investment in the Texas Express NGL pipeline system, were classified as held for sale and were measured at the lower of their carrying value or fair value less costs to sell as at December 31, 2017. As a result of entering into the 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 attributable to us). This loss has been included within Asset impairment on the Consolidated Statements of Earnings for the three months ended March 31, 2018. Line 10 Crude Oil Pipeline At March 31, 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 Enbridge Energy Partners, L.P., own the Canadian and United States portion 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, 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 $144 million ( $85 million after-tax attributable to us) included within Asset impairment on the Consolidated Statements of Earnings for the three months ended March 31, 2018 . The table below summarizes the presentation of net assets held for sale in our Consolidated Statements of Financial Position: March 31, 2018 December 31, 2017 (millions of Canadian dollars) Accounts receivable and other (current assets held for sale) 305 424 Deferred amounts and other assets (long-term assets held for sale) 422 1,190 Accounts payable and other (current liabilities held for sale) (233 ) (315 ) Other long-term liabilities (long-term liabilities held for sale) (37 ) (34 ) Net assets held for sale 457 1,265

DEBT

DEBT	3 Months Ended
	Mar. 31, 2018
Debt Disclosure [Abstract]
DEBT	DEBT CREDIT FACILITIES The following table provides details of our committed credit facilities at March 31, 2018 : March 31, 2018 Maturity Total Facilities Draws 1 Available (millions of Canadian dollars) Enbridge Inc. 2 2019-2022 6,644 2,616 4,028 Enbridge (U.S.) Inc. 2019 2,469 1,142 1,327 Enbridge Energy Partners, L.P. 3 2019-2022 3,385 1,660 1,725 Enbridge Gas Distribution Inc. (EGD) 2019 1,017 884 133 Enbridge Income Fund 2020 1,500 566 934 Enbridge Pipelines Inc. 2019 3,000 1,730 1,270 Spectra Energy Partners, LP 4 2022 3,223 2,135 1,088 Union Gas Limited (Union Gas) 2021 700 130 570 Total committed credit facilities 21,938 10,863 11,075 1 Includes facility draws, letters of credit and commercial paper issuances that are back-stopped by the credit facility. 2 Includes $135 million , $161 million (US $125 million ) and $150 million of commitments that expire in 2018, 2018 and 2020, respectively. 3 Includes $226 million (US $175 million ) and $239 million (US $185 million ) of commitments that expire in 2018 and 2020, respectively. 4 Includes $434 million (US $336 million ) of commitments that expire in 2021. During the first quarter of 2018, Enbridge terminated a US$650 million credit facility, which was set to mature in 2019, and repaid drawn amounts. In addition, Enbridge (U.S.) Inc. terminated an unutilized US$950 million credit facility, which was set to mature in 2019. During the first quarter of 2018, Westcoast Energy Inc. terminated an unutilized $400 million credit facility with a syndicate of banks. The facility was set to mature in 2021. In addition to the committed credit facilities noted above, we have $790 million of uncommitted demand credit facilities, of which $511 million were unutilized as at March 31, 2018 . As at December 31, 2017, we had $792 million of uncommitted credit facilities, of which $518 million were unutilized. Our credit facilities carry a weighted average standby fee of 0.2% per annum on the unused portion and draws bear interest at market rates. Certain credit facilities serve as a back-stop to the commercial paper programs and we have the option to extend such facilities, which are currently set to mature from 2019 to 2022. As at March 31, 2018 and December 31, 2017 , commercial paper and credit facility draws, net of short-term borrowings and non-revolving credit facilities that mature within one year of $9,832 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 During the first quarter of 2018, we completed the following long-term debt issuances: Company Issue Date Principal Amount (millions of dollars) Enbridge Inc. March 2018 Fixed-to-floating rate notes due 2078 1 US$850 Spectra Energy Partners, LP 2 January 2018 3.50% senior notes due 2028 US$400 January 2018 4.15% senior notes due 2048 US$400 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 London Interbank Offered Rate (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 Issued through Texas Eastern Transmission, LP, a wholly-owned operating subsidiary of Spectra Energy Partners, LP (SEP). LONG-TERM DEBT REPAYMENTS During the first quarter of 2018, we completed the following long-term debt repayments : Company Retirement/Repayment Date Principal Amount Cash Consideration (millions of Canadian dollars unless otherwise stated) Enbridge Southern Lights LP January 2018 4.01% medium-term notes due June 2040 9 Spectra Energy Capital, LLC 1 Repurchase via Tender Offer March 2018 6.75% senior unsecured notes due 2032 US$64 US$80 March 2018 7.50% senior unsecured notes due 2038 US$43 US$59 Redemption March 2018 5.65% senior unsecured notes due 2020 US$163 US$172 March 2018 3.30% senior unsecured notes due 2023 US$498 US$508 1 The loss on debt extinguishment of $37 million ( US$29 million ), net of the fair value adjustment recorded upon completion of the stock-for-stock merger transaction on February 27, 2017 between Enbridge and Spectra Energy Corp ( the Merger Transaction ) , was reported within Interest expense in the Consolidated Statements of Earnings. DEBT COVENANTS Our credit facility agreements and term debt indentures include standard events of default and covenant provisions whereby accelerated repayment and/or termination of the agreements may result if we were to default on payment or violate certain covenants. As at March 31, 2018 , we were in compliance with all debt covenants.

COMPONENTS OF ACCUMULATED OTHER

COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME	3 Months Ended
	Mar. 31, 2018
Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]
COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME	COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME Changes in Accumulated other comprehensive income (AOCI) attributable to our common shareholders for the three months ended March 31, 2018 and 2017 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 70 (213 ) 1,425 2 — 1,284 Other comprehensive (income)/loss reclassified to earnings Interest rate contracts 1 28 — — — — 28 Commodity contracts 2 (1 ) — — — — (1 ) Foreign exchange contracts 3 4 — — — — 4 Other contracts 4 9 — — — — 9 Amortization of pension and OPEB actuarial loss and prior service costs 5 — — — — (38 ) (38 ) 110 (213 ) 1,425 2 (38 ) 1,286 Tax impact Income tax on amounts retained in AOCI (9 ) 29 — 8 — 28 Income tax on amounts reclassified to earnings (11 ) — — — (1 ) (12 ) (20 ) 29 — 8 (1 ) 16 Balance at March 31, 2018 (554 ) (323 ) 1,502 20 (316 ) 329 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 ) 50 293 5 — 347 Other comprehensive (income)/loss reclassified to earnings Interest rate contracts 1 31 — — — — 31 Commodity contracts 2 (2 ) — — — — (2 ) Other contracts 4 9 — — — — 9 Amortization of pension and OPEB actuarial loss and prior service costs 5 — — — — 6 6 37 50 293 5 6 391 Tax impact Income tax on amounts retained in AOCI (1 ) (1 ) — 1 — (1 ) Income tax on amounts reclassified to earnings (8 ) — — — (2 ) (10 ) (9 ) (1 ) — 1 (2 ) (11 ) Balance at March 31, 2017 (718 ) (580 ) 2,993 43 (300 ) 1,438 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 periodic benefit costs and are reported within Other income/(expense) in the Consolidated Statements of Earnings.

NONCONTROLLING INTERESTS

NONCONTROLLING INTERESTS	3 Months Ended
	Mar. 31, 2018
Noncontrolling Interest [Abstract]
NONCONTROLLING INTERESTS	NONCONTROLLING INTERESTS 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 have been eliminated. We now hold a non-economic general partner interest in SEP and own approximately 403 million of SEP common units, representing 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 taxes of $1.1 billion and $333 million , respectively, for the three months ended March 31, 2018 .

RISK MANAGEMENT AND FINANCIAL I

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS	3 Months Ended
	Mar. 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 other comprehensive income (OCI) are subject to movements in foreign exchange rates, interest rates, commodity prices and our share price (collectively, market risk). Formal risk management policies, processes and systems have been designed to mitigate these risks. The following summarizes the types of market risks to which we are exposed and the risk management instruments used to mitigate them. We use a combination of qualifying and non-qualifying derivative instruments to manage the risks noted below. Foreign Exchange Risk We generate certain revenues, incur expenses, and hold a number of investments and subsidiaries that are denominated in currencies other than Canadian dollars. As a result, our earnings, cash flows and OCI are exposed to fluctuations resulting from foreign exchange rate variability. We employ financial derivative instruments to hedge foreign currency denominated earnings exposure. A combination of qualifying and non-qualifying derivative instruments are used to hedge anticipated foreign currency denominated revenues and expenses, and to manage variability in cash flows. We hedge certain net investments in United States dollar denominated investments and subsidiaries using foreign currency derivatives and United States dollar denominated debt. Interest Rate Risk Our earnings and cash flows are exposed to short-term interest rate variability due to the regular repricing of our variable rate debt, primarily commercial paper. Pay fixed-receive floating interest rate swaps are used to hedge against the effect of future interest rate movements. We have implemented a program to significantly mitigate the impact of short-term interest rate volatility on interest expense via execution of floating to fixed interest rate swaps with an average swap rate of 2.6% . As a result of the Merger Transaction, we are exposed to changes in the fair value of fixed rate debt that arise as a result of the changes in market interest rates. Pay floating-receive fixed interest rate swaps are used to hedge against future changes to the fair value of fixed rate debt. We have assumed a program within our subsidiaries to mitigate the impact of fluctuations in the fair value of fixed rate debt via execution of fixed to floating interest rate swaps with an average swap rate of 2.1% . Our earnings and cash flows are also exposed to variability in longer term interest rates ahead of anticipated fixed rate term debt issuances. Forward starting interest rate swaps are used to hedge against the effect of future interest rate movements. We have assumed a program within some of our subsidiaries to mitigate our exposure to long-term interest rate variability on select forecast term debt issuances via execution of floating to fixed interest rate swaps with an average swap rate of 3.4% . We also monitor our debt portfolio mix of fixed and variable rate debt instruments to manage a consolidated portfolio 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. Emission Allowance Price Risk Emission allowance price risk is the risk of gain or loss due to changes in the market price of emission allowances that our gas distribution business is required to purchase for itself and most of its customers to meet greenhouse gas compliance obligations under the Ontario Cap and Trade framework. Similar to the gas supply procurement framework, the Ontario Energy Board's (OEB) framework for emission allowance procurement allows recovery of fluctuations in emission allowance prices in customer rates, subject to OEB approval. Equity Price Risk Equity price risk is the risk of earnings fluctuations due to changes in our share price. We have exposure to our own common share price through the issuance of various forms of stock-based compensation, which affect earnings through revaluation of the outstanding units every period. We use equity derivatives to manage the earnings volatility derived from one form of stock-based compensation, restricted share units. We use a combination of qualifying and non-qualifying derivative instruments to manage equity price risk. TOTAL DERIVATIVE INSTRUMENTS The following table summarizes the Consolidated Statements of Financial Position location and carrying value of our derivative instruments. We generally have a policy of entering into individual International Swaps and Derivatives Association, Inc. agreements, or other similar derivative agreements, with the majority of our financial derivative counterparties. These agreements provide for the net settlement of derivative instruments outstanding with specific counterparties in the event of bankruptcy or other significant credit events, and reduces our credit risk exposure on financial derivative asset positions outstanding with the counterparties in those circumstances. The following table summarizes the maximum potential settlement in the event of these specific circumstances. All amounts are presented gross in the Consolidated Statements of Financial Position. March 31, 2018 Derivative Instruments Used as Cash Flow Hedges Derivative Instruments Used as Net Investment Hedges Derivative Instruments Used as Fair Value Hedges 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 — 3 — 131 134 (70 ) 64 Interest rate contracts 27 — — — 27 (5 ) 22 Commodity contracts — — — 100 100 (34 ) 66 27 3 — 231 261 (109 ) 152 Deferred amounts and other assets Foreign exchange contracts 18 — — 92 110 (58 ) 52 Interest rate contracts 15 — — — 15 — 15 Commodity contracts 19 — — 3 22 (19 ) 3 Other contracts — — — — — — — 52 — — 95 147 (77 ) 70 Accounts payable and other Foreign exchange contracts (5 ) (23 ) — (327 ) (355 ) 70 (285 ) Interest rate contracts (112 ) — (9 ) (185 ) (306 ) 5 (301 ) Commodity contracts (2 ) — — (244 ) (246 ) 34 (212 ) Other contracts (2 ) — — (8 ) (10 ) — (10 ) (121 ) (23 ) (9 ) (764 ) (917 ) 109 (808 ) Other long-term liabilities Foreign exchange contracts — (10 ) — (1,650 ) (1,660 ) 58 (1,602 ) Interest rate contracts (20 ) — (2 ) — (22 ) — (22 ) Commodity contracts — — — (160 ) (160 ) 19 (141 ) Other contracts (5 ) — — (3 ) (8 ) — (8 ) (25 ) (10 ) (2 ) (1,813 ) (1,850 ) 77 (1,773 ) Total net derivative asset/(liability) Foreign exchange contracts 13 (30 ) — (1,754 ) (1,771 ) — (1,771 ) Interest rate contracts (90 ) — (11 ) (185 ) (286 ) — (286 ) Commodity contracts 17 — — (301 ) (284 ) — (284 ) Other contracts (7 ) — — (11 ) (18 ) — (18 ) (67 ) (30 ) (11 ) (2,251 ) (2,359 ) — (2,359 ) December 31, 2017 Derivative Instruments Used as Cash Flow Hedges Derivative Instruments Used as Net Investment Hedges Derivative Instruments Used as Fair Value Hedges Non- Qualifying Derivative Instruments Total Gross Derivative Instruments as Presented Amounts Available for Offset Total Net Derivative Instruments (millions of Canadian dollars) Accounts receivable and other Foreign exchange contracts 1 4 — 138 143 (83 ) 60 Interest rate contracts 6 — 2 — 8 (3 ) 5 Commodity contracts 2 — — 143 145 (64 ) 81 9 4 2 281 296 (150 ) 146 Deferred amounts and other assets 2 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) -2 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. March 31, 2018 2018 2019 2020 2021 2022 Thereafter 1 Foreign exchange contracts - United States dollar forwards - purchase (millions of United States dollars) 544 2 1 — — — Foreign exchange contracts - United States dollar forwards - sell (millions of United States dollars) 3,215 3,247 3,258 1,689 1,676 3,489 Foreign exchange contracts - British pound (GBP) forwards - purchase (millions of GBP) — — — — — — Foreign exchange contracts - GBP forwards - sell (millions of GBP) — 89 25 27 28 149 Foreign exchange contracts - Euro forwards - purchase (millions of Euro) 264 375 — — — — Foreign exchange contracts - Euro forwards - sell (millions of Euro) — — 35 169 169 889 Foreign exchange contracts - Japanese yen forwards - purchase (millions of yen) — 32,662 — — 20,000 — Interest rate contracts - short-term pay fixed rate (millions of Canadian dollars) 3,749 2,100 527 109 93 203 Interest rate contracts - long-term receive fixed rate (millions of Canadian dollars) 728 580 553 188 102 — Interest rate contracts - long-term debt pay fixed rate (millions of Canadian dollars) 2,242 800 447 — — — Equity contracts (millions of Canadian dollars) 40 37 8 — — — Commodity contracts - natural gas (billions of cubic feet) (16 ) (57 ) (23 ) (2 ) 14 2 Commodity contracts - crude oil (millions of barrels) 1 2 — — — — Commodity contracts - NGL (millions of barrels) (10 ) (1 ) — — — — Commodity contracts - power (megawatt per hour) (MW/H)) 60 64 66 (3 ) (43 ) (43 ) 1 As at March 31, 2018 , 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: Three months ended 2018 2017 (millions of Canadian dollars) Amount of unrealized gain/(loss) recognized in OCI Cash flow hedges Foreign exchange contracts 21 (2 ) Interest rate contracts 100 (14 ) Commodity contracts (2 ) 21 Other contracts (14 ) (9 ) Net investment hedges Foreign exchange contracts 16 8 121 4 Amount of (gain)/loss reclassified from AOCI to earnings (effective portion) Foreign exchange contracts 1 (1 ) 1 Interest rate contracts 2 41 48 Commodity contracts 3 (1 ) (2 ) Other contracts 4 9 9 48 56 Amount of (gain)/loss reclassified from AOCI to earnings (ineffective portion and amount excluded from effectiveness testing) Interest rate contracts 2 (1 ) 2 (1 ) 2 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 Reported within Transportation and other services revenues, Commodity sales revenues, Commodity costs and Operating and administrative expense in the Consolidated Statements of Earnings. 4 Reported within Operating and administrative expense in the Consolidated Statements of Earnings. We estimate that a loss of $22 million of 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 33 months as at March 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. During the three months ended March 31, 2018 and 2017 , we recognized an unrealized loss of $8 million and $2 million , respectively, on the derivative and an unrealized gain of $8 million and $2 million , respectively, on the hedged item in earnings. During the three months ended March 31, 2018 and 2017 , we recognized a realized loss of $3 million and nil , respectively, on the derivative and a realized gain of $3 million and nil , respectively, on the hedged item in earnings. The difference in the amounts, if any, represents hedge ineffectiveness. Non-Qualifying Derivatives The following table presents the unrealized gains and losses associated with changes in the fair value of our non-qualifying derivatives: Three months ended 2018 2017 (millions of Canadian dollars) Foreign exchange contracts 1 (424 ) 273 Interest rate contracts 2 (2 ) (18 ) Commodity contracts 3 175 163 Other contracts 4 (9 ) — Total unrealized derivative fair value gain/(loss), net (260 ) 418 1 For the respective three months ended periods, reported within Transportation and other services revenues ( 2018 - $297 million loss ; 2017 - $159 million gain ) and Other income/(expense) ( 2018 - $127 million loss ; 2017 - $114 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 three months ended periods, reported within Transportation and other services revenues ( 2018 - $1 million loss ; 2017 - $22 million loss ), Commodity sales ( 2018 - $82 million gain ; 2017 - $187 million gain ), Commodity costs ( 2018 - $84 million gain ; 2017 - $5 million gain ) and Operating and administrative expense ( 2018 - $10 million gain ; 2017 - $7 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 March 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 investment grade credit ratings. Credit risk relating to derivative counterparties is mitigated by credit exposure limits and contractual requirements, netting arrangements, and ongoing monitoring of counterparty credit exposure using external credit rating services and other analytical tools. We have credit concentrations and credit exposure, with respect to derivative instruments, in the following counterparty segments: March 31, December 31, (millions of Canadian dollars) Canadian financial institutions 49 82 United States financial institutions 29 19 European financial institutions 143 145 Asian financial institutions 15 2 Other 1 72 137 308 385 1 Other is comprised of commodity clearing house and physical natural gas and crude oil counterparties. As at March 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 March 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: March 31, 2018 Level 1 Level 2 Level 3 Total Gross Derivative Instruments (millions of Canadian dollars) Financial assets Current derivative assets Foreign exchange contracts — 134 — 134 Interest rate contracts — 27 — 27 Commodity contracts — 18 82 100 — 179 82 261 Long-term derivative assets Foreign exchange contracts — 110 — 110 Interest rate contracts — 15 — 15 Commodity contracts — 1 21 22 Other contracts — — — — — 126 21 147 Financial liabilities Current derivative liabilities Foreign exchange contracts — (355 ) — (355 ) Interest rate contracts — (306 ) — (306 ) Commodity contracts (6 ) (88 ) (152 ) (246 ) Other contracts — (10 ) — (10 ) (6 ) (759 ) (152 ) (917 ) Long-term derivative liabilities Foreign exchange contracts — (1,660 ) — (1,660 ) Interest rate contracts — (22 ) — (22 ) Commodity contracts — (4 ) (156 ) (160 ) Other contracts — (8 ) — (8 ) — (1,694 ) (156 ) (1,850 ) Total net financial liabilities Foreign exchange contracts — (1,771 ) — (1,771 ) Interest rate contracts — (286 ) — (286 ) Commodity contracts (6 ) (73 ) (205 ) (284 ) Other contracts — (18 ) — (18 ) (6 ) (2,148 ) (205 ) (2,359 ) 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 liabilities 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: March 31, 2018 Fair Value Unobservable Input Minimum Price/Volatility Maximum Price/Volatility Weighted Average Price Unit of Measurement (fair value in millions of Canadian dollars) Commodity contracts - financial 1 Natural gas 9 Forward gas price 2.49 4.25 3.20 $/mmbtu 3 Crude (4 ) Forward crude price 48.92 63.73 53.07 $/barrel NGL (4 ) Forward NGL price 0.34 1.83 1.29 $/gallon Power (100 ) Forward power price 14.30 76.27 52.00 $/MW/H Commodity contracts - physical 1 Natural gas (81 ) Forward gas price 0.78 4.91 2.57 $/mmbtu 3 Crude (29 ) Forward crude price 38.01 91.27 75.29 $/barrel NGL 5 Forward NGL price 0.34 1.88 0.86 $/gallon Commodity options 2 Crude (1 ) Option volatility 22 % 24 % 23 % NGL — Option volatility — % — % — % Power — Option volatility 23 % 26 % 24 % (205 ) 1 Financial and physical forward commodity contracts are valued using a market approach valuation technique. 2 Commodity options contracts are valued using an option model valuation technique. 3 One million British thermal units (mmbtu). If adjusted, the significant unobservable inputs disclosed in the table above would have a direct impact on the fair value of our Level 3 derivative instruments. The significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments include forward commodity prices and, for option contracts, price volatility. Changes in forward commodity prices could result in significantly different fair values for our Level 3 derivatives. Changes in price volatility would change the value of the option contracts. Generally, a change in the estimate of forward commodity prices is unrelated to a change in the estimate of price volatility. Changes in net fair value of derivative assets and liabilities classified as Level 3 in the fair value hierarchy were as follows: Three months ended 2018 2017 (millions of Canadian dollars) Level 3 net derivative liability at beginning of period (387 ) (295 ) Total gain/(loss) Included in earnings 1 31 83 Included in OCI (3 ) 19 Settlements 154 70 Level 3 net derivative liability at end of period (205 ) (123 ) 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 March 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 (FMVA) investments and are recorded at cost less impairment. The carrying value of FMVA other long-term investments totaled $100 million and $99 million as at March 31, 2018 and December 31, 2017 , respectively. We have Restricted long-term investments held in trust totaling $280 million and $267 million as at March 31, 2018 and December 31, 2017 , respectively, which are recognized at fair value. We have a held to maturity preferred share investment carried at its amortized cost of $382 million and $371 million as at March 31, 2018 and December 31, 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 4.50% . As at March 31, 2018 and December 31, 2017 , the fair value of this preferred share investment approximates its face value of $580 million . As at March 31, 2018 and December 31, 2017 , our long-term debt had a carrying value of $65.6 billion and $64.0 billion , respectively, before debt issuance costs and a fair value of $68.0 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 March 31, 2018 and December 31, 2017 , the noncurrent notes receivable has a carrying value of $92 million and $89 million , respectively, and a fair value of $92 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 three months ended March 31, 2018 and 2017 , we recognized an unrealized foreign exchange loss of $194 million on the translation of United States dollar denominated debt and a gain of $20 million , respectively, and an unrealized gain on the change in fair value of our outstanding foreign exchange forward contracts of $15 million and $9 million , respectively, in OCI. During the three months ended March 31, 2018 and 2017 , we recognized a realized loss of $23 million and gain of $1 million , respectively, in OCI associated with the settlement of foreign exchange forward contracts and recognized a realized loss of $11 million and gain of $20 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 three months ended March 31, 2018 and 2017 .

INCOME TAXES

INCOME TAXES	3 Months Ended
	Mar. 31, 2018
Income Tax Disclosure [Abstract]
INCOME TAXES	INCOME TAXES The effective income tax rates for the three months ended March 31, 2018 and 2017 were (16.7)% and 17.3% , respectively. The period-over-period decrease in the effective income tax rate is primarily due to the effects of rate-regulated accounting for income taxes and other permanent items relative to the decrease in earnings for the three months ended March 31, 2018 as well as the impact of the United States federal corporate income tax rate reduction enacted in 2017. On December 22, 2017, the United States enacted the TCJA and we made reasonable estimates for the measurement and accounting of certain effects of the TCJA in our consolidated financial statements for the year ended December 31, 2017. We recorded a nil provision in the first quarter of 2018, based on existing guidance and legislation, for the remaining effects of the TCJA including the Global Intangible Low Taxed Income tax and the Base Erosion and Anti-abuse tax.

PENSION AND OTHER POSTRETIREMEN

PENSION AND OTHER POSTRETIREMENT BENEFITS	3 Months Ended
	Mar. 31, 2018
Retirement Benefits [Abstract]
PENSION AND OTHER POSTRETIREMENT BENEFITS	PENSION AND OTHER POSTRETIREMENT BENEFITS Three months ended 2018 2017 (millions of Canadian dollars) Service cost 65 54 Interest cost 45 32 Expected return on plan assets (82 ) (51 ) Amortization of prior service costs (1 ) — Amortization of actuarial loss 7 9 Net periodic benefit costs 34 44

CONTINGENCIES

CONTINGENCIES	3 Months Ended
	Mar. 31, 2018
Loss Contingency [Abstract]
CONTINGENCIES	CONTINGENCIES We are involved in 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 interim consolidated financial position or results of operations. TAX MATTERS We maintain tax liabilities related to uncertain tax positions. While fully supportable in our view, these tax positions, if challenged by tax authorities, may not be fully sustained on review.

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS	3 Months Ended
	Mar. 31, 2018
Subsequent Events [Abstract]
SUBSEQUENT EVENTS	SUBSEQUENT EVENTS On April 12, 2018, we completed an offering of $750 million of fixed-to-floating rate subordinated notes that 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% . After the initial 10 years , 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 . On April 12, 2018, we completed an offering of US$600 million of fixed-to-floating rate subordinated notes that mature in 60 years and are callable on or after year 5 . For the initial 5 years , the notes carry a fixed interest rate of 6.375% . After the initial 5 years , the interest rate will be set to equal the three-month LIBOR plus a margin of 359 basis points from years 5 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 . On April 30, 2018, Sabal Trail Transmission, LLC (Sabal Trail), a joint venture in which SEP owns a 50% interest, issued US $500 million in aggregate principal amount of 4.246% senior notes due in 2028, US $600 million in aggregate principal amount of 4.682% due in 2038 and US $400 million in aggregate principle amount of 4.832% due in 2048. Sabal Trail distributed net proceeds from the offering to the partners as a partial reimbursement of construction and development costs incurred by the partners. The net contribution made to SEP was approximately US $750 million to be used to pay down indebtedness. On May 9, 2018 we entered into agreements with the Canadian Pension Plan Investment Board to sell a 49% interest in all of our Canadian renewable energy generation assets, 49% of two large United States renewable assets and 49% of our interest in the Hohe See Offshore wind farm and its subsequent expansion, both concurrently under construction in Germany (collectively, the Assets). Initial proceeds from the transaction are $1.75 billion . In addition, our partner will fund their pro-rata share of the remaining capital on the Hohe See Offshore wind project. We will maintain a 51% interest in the Assets and continue to manage, operate and provide administrative services for the Assets. The transaction is subject to closing adjustments and conditions customary in transactions of this nature. Closing is expected to occur during the third quarter of 2018 subject to the receipt of all necessary regulatory approvals and consents. On May 9, 2018 our indirect subsidiary, Enbridge (U.S.) Inc. entered into a definitive agreement to sell Midcoast Operating, L.P. and its subsidiaries (Sales Agreement), which conducts our United States natural gas and NGL gathering, processing, transportation and marketing businesses, to AL Midcoast Holdings, LLC (an affiliate of ArcLight Capital Partners, LLC) for a cash purchase price of US$ 1.1 billion , subject to customary closing adjustments. The transaction is expected to close in the third quarter of 2018, subject to receipt of customary regulatory approvals and satisfaction of other customary closing conditions.

CHANGES IN ACCOUNTING POLICIES

CHANGES IN ACCOUNTING POLICIES (Policies)	3 Months Ended
	Mar. 31, 2018
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
ADOPTION OF NEW STANDARDS and FUTURE ACCOUNTING POLICY CHANGES	ADOPTION OF NEW 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) enacted by the United States federal government on December 22, 2017. The amendments in this accounting update allow a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the TCJA. The amendments will eliminate the stranded tax effects 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 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 statement 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 Statement 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 Statement 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 instruments for disclosure purposes is measured using exit price. 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 obligations. 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 along with explanations of those effects. For the three months ended March 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 1,2 6,442 (170 ) 6,272 Property, plant and equipment, net 2 90,711 112 90,823 Liabilities and equity Accounts payable and other 1,2 9,478 62 9,540 Other long-term liabilities 2 7,510 66 7,576 Deferred income taxes 1,2 9,295 (62 ) 9,233 Redeemable noncontrolling interests 1,2 4,067 (38 ) 4,029 Deficit 1,2 (2,468 ) (86 ) (2,554 ) 1 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. 2 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. FUTURE ACCOUNTING POLICY CHANGES Improvements to Accounting for Hedging Activities ASU 2017-12 was issued in August 2017 with the objective of better aligning a company’s risk management activities and the resulting hedge accounting reflected in the financial statements. The amendments allow cash flow hedging of contractually specified components in financial and non-financial items. Under the new guidance, hedge ineffectiveness is no longer required to be measured and hedging instruments’ fair value changes will be recorded in the same income statement line as the hedged item. The ASU also allows the initial quantitative hedge effectiveness assessment to be performed at any time before the end of the quarter in which the hedge is designated. After initial quantitative testing is performed, an ongoing qualitative effectiveness assessment is permitted. The accounting update is effective January 1, 2019, with early adoption permitted, and is to be applied on a modified retrospective basis. We are currently assessing the impact of the new standard on our consolidated financial statements. Amending the Amortization Period for Certain Callable Debt Securities Purchased at a Premium ASU 2017-08 was issued in March 2017 with the intent of shortening the amortization period to the earliest call date for certain callable debt securities held at a premium. The accounting update is effective January 1, 2019 and will be applied on a modified retrospective basis. We are currently assessing the impact of the new standard on our consolidated financial statements. Accounting for Credit Losses ASU 2016-13 was issued in June 2016 with the intent of providing financial statement users with more useful information about the expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity at each reporting date. Current treatment uses the incurred loss methodology for recognizing credit losses that delays the recognition until it is probable a loss has been incurred. The accounting update adds a new impairment model, known as the current expected credit loss model, which is based on expected losses rather than incurred losses. Under the new guidance, an entity will recognize as an allowance its estimate of expected credit losses, which the Financial Accounting Standards Board believes will result in more timely recognition of such losses. The accounting update is effective January 1, 2020. We are currently assessing the impact of the new standard on our consolidated financial statements. Recognition of Leases ASU 2016-02 was issued in February 2016 with the intent to increase transparency and comparability among organizations. It requires lessees of operating lease arrangements to recognize lease assets and lease liabilities on the statement of financial position and disclose additional key information about lease agreements. The accounting update also replaces the current definition of a lease and requires that an arrangement be recognized as a lease when a customer has the right to obtain substantially all of the economic benefits from the use of an asset, as well as the right to direct the use of the asset. We are currently gathering a complete inventory of our lease contracts in order to assess the impact of the new standard on our consolidated financial statements. We will adopt the new standard on January 1, 2019 and we are currently evaluating options with respect to the transition practical expedients offered in connection with this update. Further, ASU 2018-01 was issued in January 2018 to address stakeholder concerns about the costs and complexity of complying with the transition provisions of the new lease requirements as they relate to land easements. The amendments provide an optional transition practical expedient to not evaluate existing or expired land easements that were not previously accounted for as leases under existing guidance. We intend to elect this practical expedient in connection with the adoption of the new lease requirements.

CHANGES IN ACCOUNTING POLICIE23

CHANGES IN ACCOUNTING POLICIES (Tables)	3 Months Ended
	Mar. 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 along with explanations of those effects. For the three months ended March 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 1,2 6,442 (170 ) 6,272 Property, plant and equipment, net 2 90,711 112 90,823 Liabilities and equity Accounts payable and other 1,2 9,478 62 9,540 Other long-term liabilities 2 7,510 66 7,576 Deferred income taxes 1,2 9,295 (62 ) 9,233 Redeemable noncontrolling interests 1,2 4,067 (38 ) 4,029 Deficit 1,2 (2,468 ) (86 ) (2,554 ) 1 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. 2 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. Liquids Pipelines Gas Transmission and Midstream Gas Distribution Green Power and Transmission Energy Services Consolidated Three months ended (millions of Canadian dollars) Revenue from products transferred at a point in time 1 — 693 25 — — 718 Revenue from products and services transferred over time 2 2,098 1,217 2,206 154 — 5,675 Total revenue from contracts with customers 2,098 1,910 2,231 154 — 6,393 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)	3 Months Ended
	Mar. 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 Three months ended (millions of Canadian dollars) Transportation revenue 2,058 952 239 — — — 3,249 Storage and other revenue 40 60 66 — — — 166 Gas gathering and processing revenue — 205 — — — — 205 Gas distribution revenue — — 1,926 — — — 1,926 Electricity and transmission revenue — — — 154 — — 154 Commodity sales — 693 — — — — 693 Total revenue from contracts with customers 2,098 1,910 2,231 154 — — 6,393 Commodity sales — — — — 6,575 — 6,575 Other revenue 1 (269 ) 25 2 3 — (3 ) (242 ) Intersegment revenue 80 2 4 — 57 (143 ) — Total revenue 1,909 1,937 2,237 157 6,632 (146 ) 12,726 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 at adoption date 2,475 290 992 Balance at reporting date 2,533 290 1,008
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 along with explanations of those effects. For the three months ended March 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 1,2 6,442 (170 ) 6,272 Property, plant and equipment, net 2 90,711 112 90,823 Liabilities and equity Accounts payable and other 1,2 9,478 62 9,540 Other long-term liabilities 2 7,510 66 7,576 Deferred income taxes 1,2 9,295 (62 ) 9,233 Redeemable noncontrolling interests 1,2 4,067 (38 ) 4,029 Deficit 1,2 (2,468 ) (86 ) (2,554 ) 1 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. 2 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. Liquids Pipelines Gas Transmission and Midstream Gas Distribution Green Power and Transmission Energy Services Consolidated Three months ended (millions of Canadian dollars) Revenue from products transferred at a point in time 1 — 693 25 — — 718 Revenue from products and services transferred over time 2 2,098 1,217 2,206 154 — 5,675 Total revenue from contracts with customers 2,098 1,910 2,231 154 — 6,393 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)	3 Months Ended
	Mar. 31, 2018
Segment Reporting [Abstract]
Schedule of reporting information by segment	Liquids Pipelines Gas Transmission and Midstream Gas Distribution Green Power and Transmission Energy Services Eliminations and Other Consolidated Three months ended (millions of Canadian dollars) Revenues 1,909 1,937 2,237 157 6,632 (146 ) 12,726 Commodity and gas distribution costs (4 ) (620 ) (1,388 ) — (6,455 ) 146 (8,321 ) Operating and administrative (747 ) (507 ) (248 ) (30 ) (12 ) (97 ) (1,641 ) Asset impairment (144 ) (913 ) — — — (5 ) (1,062 ) Income/(loss) from equity investments 131 208 17 (25 ) 4 — 335 Other income/(expense) 11 21 18 7 — (177 ) (120 ) Earnings/(loss) before interest, income taxes, and depreciation and amortization 1,156 126 636 109 169 (279 ) 1,917 Depreciation and amortization (824 ) Interest expense (656 ) Income tax recovery 73 Earnings 510 Capital expenditures 1 615 825 183 14 — 6 1,643 Liquids Pipelines Gas Transmission and Midstream Gas Distribution Green Power and Transmission Energy Services Eliminations and Other Consolidated Three months ended (millions of Canadian dollars) Revenues 2,155 1,235 1,584 137 6,133 (98 ) 11,146 Commodity and gas distribution costs (3 ) (647 ) (1,046 ) 1 (5,968 ) 98 (7,565 ) Operating and administrative (760 ) (254 ) (189 ) (40 ) (12 ) (296 ) (1,551 ) Income from equity investments 86 110 36 2 2 — 236 Other income/(expense) 2 31 2 1 1 (2 ) 35 Earnings/(loss) before interest, income taxes, and depreciation and amortization 1,480 475 387 101 156 (298 ) 2,301 Depreciation and amortization (672 ) Interest expense (486 ) Income tax expense (198 ) Earnings 945 Capital expenditures 1 654 655 183 114 — 59 1,665 1 Includes allowance for equity funds used during construction.
Schedule of total assets by segment	March 31, 2018 December 31, 2017 (millions of Canadian dollars) Liquids Pipelines 64,842 63,881 Gas Transmission and Midstream 61,880 60,745 Gas Distribution 25,784 25,956 Green Power and Transmission 6,466 6,289 Energy Services 1,628 2,514 Eliminations and Other 2,894 2,708 163,494 162,093

EARNINGS PER COMMON SHARE (Tabl

EARNINGS PER COMMON SHARE (Tables)	3 Months Ended
	Mar. 31, 2018
Earnings Per Share [Abstract]
Schedule of weighted average shares outstanding used to calculate basic and diluted earnings per common share	Weighted average shares outstanding used to calculate basic and diluted earnings per share are as follows: Three months ended 2018 2017 (number of common shares in millions) Weighted average shares outstanding 1,685 1,177 Effect of dilutive options 4 10 Diluted weighted average shares outstanding 1,689 1,187

ASSETS HELD FOR SALE (Tables)

ASSETS HELD FOR SALE (Tables)	3 Months Ended
	Mar. 31, 2018
Discontinued Operations and Disposal Groups [Abstract]
Disposal Groups, Including Discontinued Operations	The table below summarizes the presentation of net assets held for sale in our Consolidated Statements of Financial Position: March 31, 2018 December 31, 2017 (millions of Canadian dollars) Accounts receivable and other (current assets held for sale) 305 424 Deferred amounts and other assets (long-term assets held for sale) 422 1,190 Accounts payable and other (current liabilities held for sale) (233 ) (315 ) Other long-term liabilities (long-term liabilities held for sale) (37 ) (34 ) Net assets held for sale 457 1,265

DEBT (Tables)

DEBT (Tables)	3 Months Ended
	Mar. 31, 2018
Debt Disclosure [Abstract]
Schedule of credit facilities	The following table provides details of our committed credit facilities at March 31, 2018 : March 31, 2018 Maturity Total Facilities Draws 1 Available (millions of Canadian dollars) Enbridge Inc. 2 2019-2022 6,644 2,616 4,028 Enbridge (U.S.) Inc. 2019 2,469 1,142 1,327 Enbridge Energy Partners, L.P. 3 2019-2022 3,385 1,660 1,725 Enbridge Gas Distribution Inc. (EGD) 2019 1,017 884 133 Enbridge Income Fund 2020 1,500 566 934 Enbridge Pipelines Inc. 2019 3,000 1,730 1,270 Spectra Energy Partners, LP 4 2022 3,223 2,135 1,088 Union Gas Limited (Union Gas) 2021 700 130 570 Total committed credit facilities 21,938 10,863 11,075 1 Includes facility draws, letters of credit and commercial paper issuances that are back-stopped by the credit facility. 2 Includes $135 million , $161 million (US $125 million ) and $150 million of commitments that expire in 2018, 2018 and 2020, respectively. 3 Includes $226 million (US $175 million ) and $239 million (US $185 million ) of commitments that expire in 2018 and 2020, respectively. 4 Includes $434 million (US $336 million ) of commitments that expire in 2021.
Schedule of Long-term Debt Instruments	During the first quarter of 2018, we completed the following long-term debt issuances: Company Issue Date Principal Amount (millions of dollars) Enbridge Inc. March 2018 Fixed-to-floating rate notes due 2078 1 US$850 Spectra Energy Partners, LP 2 January 2018 3.50% senior notes due 2028 US$400 January 2018 4.15% senior notes due 2048 US$400 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 London Interbank Offered Rate (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 Issued through Texas Eastern Transmission, LP, a wholly-owned operating subsidiary of Spectra Energy Partners, LP (SEP).
Schedule of Repayment of Debt	During the first quarter of 2018, we completed the following long-term debt repayments : Company Retirement/Repayment Date Principal Amount Cash Consideration (millions of Canadian dollars unless otherwise stated) Enbridge Southern Lights LP January 2018 4.01% medium-term notes due June 2040 9 Spectra Energy Capital, LLC 1 Repurchase via Tender Offer March 2018 6.75% senior unsecured notes due 2032 US$64 US$80 March 2018 7.50% senior unsecured notes due 2038 US$43 US$59 Redemption March 2018 5.65% senior unsecured notes due 2020 US$163 US$172 March 2018 3.30% senior unsecured notes due 2023 US$498 US$508 1 The loss on debt extinguishment of $37 million ( US$29 million ), net of the fair value adjustment recorded upon completion of the stock-for-stock merger transaction on February 27, 2017 between Enbridge and Spectra Energy Corp ( the Merger Transaction ) , was reported within Interest expense in the Consolidated Statements of Earnings.

COMPONENTS OF ACCUMULATED OTH29

COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME (Tables)	3 Months Ended
	Mar. 31, 2018
Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]
Schedule of changes in AOCI attributable to Enbridge Inc. common shareholders	Changes in Accumulated other comprehensive income (AOCI) attributable to our common shareholders for the three months ended March 31, 2018 and 2017 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 70 (213 ) 1,425 2 — 1,284 Other comprehensive (income)/loss reclassified to earnings Interest rate contracts 1 28 — — — — 28 Commodity contracts 2 (1 ) — — — — (1 ) Foreign exchange contracts 3 4 — — — — 4 Other contracts 4 9 — — — — 9 Amortization of pension and OPEB actuarial loss and prior service costs 5 — — — — (38 ) (38 ) 110 (213 ) 1,425 2 (38 ) 1,286 Tax impact Income tax on amounts retained in AOCI (9 ) 29 — 8 — 28 Income tax on amounts reclassified to earnings (11 ) — — — (1 ) (12 ) (20 ) 29 — 8 (1 ) 16 Balance at March 31, 2018 (554 ) (323 ) 1,502 20 (316 ) 329 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 ) 50 293 5 — 347 Other comprehensive (income)/loss reclassified to earnings Interest rate contracts 1 31 — — — — 31 Commodity contracts 2 (2 ) — — — — (2 ) Other contracts 4 9 — — — — 9 Amortization of pension and OPEB actuarial loss and prior service costs 5 — — — — 6 6 37 50 293 5 6 391 Tax impact Income tax on amounts retained in AOCI (1 ) (1 ) — 1 — (1 ) Income tax on amounts reclassified to earnings (8 ) — — — (2 ) (10 ) (9 ) (1 ) — 1 (2 ) (11 ) Balance at March 31, 2017 (718 ) (580 ) 2,993 43 (300 ) 1,438 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 periodic benefit costs and are reported within Other income/(expense) in the Consolidated Statements of Earnings.

RISK MANAGEMENT AND FINANCIAL30

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (Tables)	3 Months Ended
	Mar. 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 in the event of these specific circumstances. All amounts are presented gross in the Consolidated Statements of Financial Position. March 31, 2018 Derivative Instruments Used as Cash Flow Hedges Derivative Instruments Used as Net Investment Hedges Derivative Instruments Used as Fair Value Hedges 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 — 3 — 131 134 (70 ) 64 Interest rate contracts 27 — — — 27 (5 ) 22 Commodity contracts — — — 100 100 (34 ) 66 27 3 — 231 261 (109 ) 152 Deferred amounts and other assets Foreign exchange contracts 18 — — 92 110 (58 ) 52 Interest rate contracts 15 — — — 15 — 15 Commodity contracts 19 — — 3 22 (19 ) 3 Other contracts — — — — — — — 52 — — 95 147 (77 ) 70 Accounts payable and other Foreign exchange contracts (5 ) (23 ) — (327 ) (355 ) 70 (285 ) Interest rate contracts (112 ) — (9 ) (185 ) (306 ) 5 (301 ) Commodity contracts (2 ) — — (244 ) (246 ) 34 (212 ) Other contracts (2 ) — — (8 ) (10 ) — (10 ) (121 ) (23 ) (9 ) (764 ) (917 ) 109 (808 ) Other long-term liabilities Foreign exchange contracts — (10 ) — (1,650 ) (1,660 ) 58 (1,602 ) Interest rate contracts (20 ) — (2 ) — (22 ) — (22 ) Commodity contracts — — — (160 ) (160 ) 19 (141 ) Other contracts (5 ) — — (3 ) (8 ) — (8 ) (25 ) (10 ) (2 ) (1,813 ) (1,850 ) 77 (1,773 ) Total net derivative asset/(liability) Foreign exchange contracts 13 (30 ) — (1,754 ) (1,771 ) — (1,771 ) Interest rate contracts (90 ) — (11 ) (185 ) (286 ) — (286 ) Commodity contracts 17 — — (301 ) (284 ) — (284 ) Other contracts (7 ) — — (11 ) (18 ) — (18 ) (67 ) (30 ) (11 ) (2,251 ) (2,359 ) — (2,359 ) December 31, 2017 Derivative Instruments Used as Cash Flow Hedges Derivative Instruments Used as Net Investment Hedges Derivative Instruments Used as Fair Value Hedges Non- Qualifying Derivative Instruments Total Gross Derivative Instruments as Presented Amounts Available for Offset Total Net Derivative Instruments (millions of Canadian dollars) Accounts receivable and other Foreign exchange contracts 1 4 — 138 143 (83 ) 60 Interest rate contracts 6 — 2 — 8 (3 ) 5 Commodity contracts 2 — — 143 145 (64 ) 81 9 4 2 281 296 (150 ) 146 Deferred amounts and other assets 2 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) -2 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. March 31, 2018 2018 2019 2020 2021 2022 Thereafter 1 Foreign exchange contracts - United States dollar forwards - purchase (millions of United States dollars) 544 2 1 — — — Foreign exchange contracts - United States dollar forwards - sell (millions of United States dollars) 3,215 3,247 3,258 1,689 1,676 3,489 Foreign exchange contracts - British pound (GBP) forwards - purchase (millions of GBP) — — — — — — Foreign exchange contracts - GBP forwards - sell (millions of GBP) — 89 25 27 28 149 Foreign exchange contracts - Euro forwards - purchase (millions of Euro) 264 375 — — — — Foreign exchange contracts - Euro forwards - sell (millions of Euro) — — 35 169 169 889 Foreign exchange contracts - Japanese yen forwards - purchase (millions of yen) — 32,662 — — 20,000 — Interest rate contracts - short-term pay fixed rate (millions of Canadian dollars) 3,749 2,100 527 109 93 203 Interest rate contracts - long-term receive fixed rate (millions of Canadian dollars) 728 580 553 188 102 — Interest rate contracts - long-term debt pay fixed rate (millions of Canadian dollars) 2,242 800 447 — — — Equity contracts (millions of Canadian dollars) 40 37 8 — — — Commodity contracts - natural gas (billions of cubic feet) (16 ) (57 ) (23 ) (2 ) 14 2 Commodity contracts - crude oil (millions of barrels) 1 2 — — — — Commodity contracts - NGL (millions of barrels) (10 ) (1 ) — — — — Commodity contracts - power (megawatt per hour) (MW/H)) 60 64 66 (3 ) (43 ) (43 ) 1 As at March 31, 2018 , 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: Three months ended 2018 2017 (millions of Canadian dollars) Amount of unrealized gain/(loss) recognized in OCI Cash flow hedges Foreign exchange contracts 21 (2 ) Interest rate contracts 100 (14 ) Commodity contracts (2 ) 21 Other contracts (14 ) (9 ) Net investment hedges Foreign exchange contracts 16 8 121 4 Amount of (gain)/loss reclassified from AOCI to earnings (effective portion) Foreign exchange contracts 1 (1 ) 1 Interest rate contracts 2 41 48 Commodity contracts 3 (1 ) (2 ) Other contracts 4 9 9 48 56 Amount of (gain)/loss reclassified from AOCI to earnings (ineffective portion and amount excluded from effectiveness testing) Interest rate contracts 2 (1 ) 2 (1 ) 2 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 Reported within Transportation and other services revenues, Commodity sales revenues, Commodity costs and Operating and administrative expense in the Consolidated Statements of Earnings. 4 Reported within Operating and administrative expense in the Consolidated Statements of Earnings.
Schedule of unrealized gains and losses associated with changes in the fair value of non-qualifying derivatives	The following table presents the unrealized gains and losses associated with changes in the fair value of our non-qualifying derivatives: Three months ended 2018 2017 (millions of Canadian dollars) Foreign exchange contracts 1 (424 ) 273 Interest rate contracts 2 (2 ) (18 ) Commodity contracts 3 175 163 Other contracts 4 (9 ) — Total unrealized derivative fair value gain/(loss), net (260 ) 418 1 For the respective three months ended periods, reported within Transportation and other services revenues ( 2018 - $297 million loss ; 2017 - $159 million gain ) and Other income/(expense) ( 2018 - $127 million loss ; 2017 - $114 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 three months ended periods, reported within Transportation and other services revenues ( 2018 - $1 million loss ; 2017 - $22 million loss ), Commodity sales ( 2018 - $82 million gain ; 2017 - $187 million gain ), Commodity costs ( 2018 - $84 million gain ; 2017 - $5 million gain ) and Operating and administrative expense ( 2018 - $10 million gain ; 2017 - $7 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: March 31, December 31, (millions of Canadian dollars) Canadian financial institutions 49 82 United States financial institutions 29 19 European financial institutions 143 145 Asian financial institutions 15 2 Other 1 72 137 308 385 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: March 31, 2018 Level 1 Level 2 Level 3 Total Gross Derivative Instruments (millions of Canadian dollars) Financial assets Current derivative assets Foreign exchange contracts — 134 — 134 Interest rate contracts — 27 — 27 Commodity contracts — 18 82 100 — 179 82 261 Long-term derivative assets Foreign exchange contracts — 110 — 110 Interest rate contracts — 15 — 15 Commodity contracts — 1 21 22 Other contracts — — — — — 126 21 147 Financial liabilities Current derivative liabilities Foreign exchange contracts — (355 ) — (355 ) Interest rate contracts — (306 ) — (306 ) Commodity contracts (6 ) (88 ) (152 ) (246 ) Other contracts — (10 ) — (10 ) (6 ) (759 ) (152 ) (917 ) Long-term derivative liabilities Foreign exchange contracts — (1,660 ) — (1,660 ) Interest rate contracts — (22 ) — (22 ) Commodity contracts — (4 ) (156 ) (160 ) Other contracts — (8 ) — (8 ) — (1,694 ) (156 ) (1,850 ) Total net financial liabilities Foreign exchange contracts — (1,771 ) — (1,771 ) Interest rate contracts — (286 ) — (286 ) Commodity contracts (6 ) (73 ) (205 ) (284 ) Other contracts — (18 ) — (18 ) (6 ) (2,148 ) (205 ) (2,359 ) 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 liabilities 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: March 31, 2018 Fair Value Unobservable Input Minimum Price/Volatility Maximum Price/Volatility Weighted Average Price Unit of Measurement (fair value in millions of Canadian dollars) Commodity contracts - financial 1 Natural gas 9 Forward gas price 2.49 4.25 3.20 $/mmbtu 3 Crude (4 ) Forward crude price 48.92 63.73 53.07 $/barrel NGL (4 ) Forward NGL price 0.34 1.83 1.29 $/gallon Power (100 ) Forward power price 14.30 76.27 52.00 $/MW/H Commodity contracts - physical 1 Natural gas (81 ) Forward gas price 0.78 4.91 2.57 $/mmbtu 3 Crude (29 ) Forward crude price 38.01 91.27 75.29 $/barrel NGL 5 Forward NGL price 0.34 1.88 0.86 $/gallon Commodity options 2 Crude (1 ) Option volatility 22 % 24 % 23 % NGL — Option volatility — % — % — % Power — Option volatility 23 % 26 % 24 % (205 ) 1 Financial and physical forward commodity contracts are valued using a market approach valuation technique. 2 Commodity options contracts are valued using an option model valuation technique. 3 One million British thermal units (mmbtu).
Schedule of changes in net fair value of derivative assets and liabilities classified as Level 3 in the fair value hierarchy	Changes in net fair value of derivative assets and liabilities classified as Level 3 in the fair value hierarchy were as follows: Three months ended 2018 2017 (millions of Canadian dollars) Level 3 net derivative liability at beginning of period (387 ) (295 ) Total gain/(loss) Included in earnings 1 31 83 Included in OCI (3 ) 19 Settlements 154 70 Level 3 net derivative liability at end of period (205 ) (123 ) 1 Reported within Transportation and other services revenues, Commodity costs and Operating and administrative expense in the Consolidated Statements of Earnings.

PENSION AND OTHER POSTRETIREM31

PENSION AND OTHER POSTRETIREMENT BENEFITS (Tables)	3 Months Ended
	Mar. 31, 2018
Retirement Benefits [Abstract]
Schedule of net benefit costs recognized	Three months ended 2018 2017 (millions of Canadian dollars) Service cost 65 54 Interest cost 45 32 Expected return on plan assets (82 ) (51 ) Amortization of prior service costs (1 ) — Amortization of actuarial loss 7 9 Net periodic benefit costs 34 44

BASIS OF PRESENTATION - Narrati

BASIS OF PRESENTATION - Narrative (Details) - CAD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Cash and cash equivalents	$ 610		$ 480
Increase (reduction) to net cash provided by financing activities	(1,009)	$ 1,313
Net cash used in investing activities	(2,068)	(3,448)
Scenario, Adjustment
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Cash and cash equivalents	900		$ 600
Increase (reduction) to net cash provided by financing activities		$ (200)
Merger Transaction | Scenario, Adjustment
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Increase (reduction) to net cash provided by financing activities	(67)
Net cash used in investing activities	$ 67

CHANGES IN ACCOUNTING POLICIE33

CHANGES IN ACCOUNTING POLICIES (Details) - CAD ($) $ in Millions	Mar. 31, 2018	Jan. 01, 2018	Dec. 31, 2017
Assets
Deferred amounts and other assets	$ 5,614	$ 6,272	$ 6,442
Property, plant and equipment, net	92,521	90,823	90,711
Liabilities and equity
Accounts payable and other	6,823	9,540	9,478
Other long-term liabilities	8,390	7,576	7,510
Deferred income taxes	9,812	9,233	9,295
Redeemable noncontrolling interests	3,815	4,029	4,067
Retained deficit	$ (1,982)	(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
Retained 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)
Retained deficit		$ (86)

REVENUE (Details)

REVENUE (Details) $ in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2018CAD ($)	Mar. 31, 2018USD ($)	Mar. 31, 2017CAD ($)
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	$ 6,393
Revenues	12,726		$ 11,146
Transferred at Point in Time
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	718
Transferred over Time
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	5,675
Transportation revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	3,249
Storage and Other Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	166
Gas Gathering and Processing Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	205
Gas Distribution Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	1,926
Electricity and Transmission Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	154
Commodity sales
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	693
Revenues	6,575
Other Revenue
Disaggregation of Revenue [Line Items]
Revenues	(242)
Liquids Pipelines
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	2,098
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	2,098
Gas Transmission and Midstream
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	1,910
Gas Transmission and Midstream | Transferred at Point in Time
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	693
Gas Transmission and Midstream | Transferred over Time
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	1,217
Gas Distribution
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	2,231
Gas Distribution | Transferred at Point in Time
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	25
Gas Distribution | Transferred over Time
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	2,206
Green Power and Transmission
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	154
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	154
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	2,098
Revenues	1,909		2,155
Business segments | Liquids Pipelines | Transportation revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	2,058
Business segments | Liquids Pipelines | Storage and Other Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	40
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 Revenue
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
Revenues	0
Business segments | Liquids Pipelines | Other Revenue
Disaggregation of Revenue [Line Items]
Revenues	(269)
Business segments | Gas Transmission and Midstream
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	1,910
Revenues	1,937
Business segments | Gas Transmission and Midstream | Transportation revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	952
Business segments | Gas Transmission and Midstream | Storage and Other Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	60
Business segments | Gas Transmission and Midstream | Gas Gathering and Processing Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	205
Business segments | Gas Transmission and Midstream | Gas Distribution Revenue
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	693
Revenues	0
Business segments | Gas Transmission and Midstream | Other Revenue
Disaggregation of Revenue [Line Items]
Revenues	25
Business segments | Gas Distribution
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	2,231
Revenues	2,237
Business segments | Gas Distribution | Transportation revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	239
Business segments | Gas Distribution | Storage and Other Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	66
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 Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	1,926
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
Revenues	0
Business segments | Gas Distribution | Other Revenue
Disaggregation of Revenue [Line Items]
Revenues	2
Business segments | Green Power and Transmission
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	154
Revenues	157		137
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 Revenue
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	154
Business segments | Green Power and Transmission | Commodity sales
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0
Revenues	0
Business segments | Green Power and Transmission | Other Revenue
Disaggregation of Revenue [Line Items]
Revenues	3
Business segments | Energy Services
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0
Revenues	6,632
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 Revenue
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
Revenues	6,575
Business segments | Energy Services | Other Revenue
Disaggregation of Revenue [Line Items]
Revenues	0
Intersegment Eliminations
Disaggregation of Revenue [Line Items]
Revenues	(143)	$ 0
Intersegment Eliminations | Liquids Pipelines
Disaggregation of Revenue [Line Items]
Revenues	80
Intersegment Eliminations | Gas Transmission and Midstream
Disaggregation of Revenue [Line Items]
Revenues	2
Intersegment Eliminations | Gas Distribution
Disaggregation of Revenue [Line Items]
Revenues	4
Intersegment Eliminations | Green Power and Transmission
Disaggregation of Revenue [Line Items]
Revenues	0
Intersegment Eliminations | Energy Services
Disaggregation of Revenue [Line Items]
Revenues	57
Consolidation, Eliminations
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0
Revenues	(146)		$ (98)
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 Revenue
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
Revenues	0
Consolidation, Eliminations | Other Revenue
Disaggregation of Revenue [Line Items]
Revenues	$ (3)

REVENUE - Contract Balances (De

REVENUE - Contract Balances (Details) - CAD ($) $ in Millions	Mar. 31, 2018	Jan. 01, 2018
Revenue from Contract with Customer [Abstract]
Accounts receivable, net	$ 2,533	$ 2,475
Contract with customer, asset	290	290
Contract with customer, liability	$ 1,008	$ 992

REVENUE - Narrative (Details)

REVENUE - Narrative (Details) - 3 months ended Mar. 31, 2018 $ in Millions, $ in Millions	CAD ($)	USD ($)
Revenue from Contract with Customer [Abstract]
Revenue recognized	$ 95
Increase (Decrease) in Contract with Customers, Liability		$ 96
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-04-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligation	5,700
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-04-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligation	5,900
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligation	$ 63,800

SEGMENTED INFORMATION (Details)

SEGMENTED INFORMATION (Details) - CAD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Segmented Information
Revenues	$ 12,726	$ 11,146
Commodity and gas distribution costs	(8,321)	(7,565)
Operating and administrative	(1,641)	(1,551)
Asset impairment	(1,062)	0
Income/(loss) from equity investments	335	236
Other	(120)	35
Earnings/(loss) before interest and income taxes	1,917	2,301
Depreciation and amortization	(824)	(672)
Interest expense	(656)	(486)
Income tax recovery/(expense)	73	(198)
Earnings	510	945
Capital expenditures	1,643	1,665
Assets	163,494		$ 162,093
Assets, excluding goodwill from Merger Transaction	163,494		162,093
Consolidation, Eliminations
Segmented Information
Revenues	(146)	(98)
Commodity and gas distribution costs	146	98
Operating and administrative	(97)	(296)
Asset impairment	(5)
Income/(loss) from equity investments	0	0
Other	(177)	(2)
Earnings/(loss) before interest and income taxes	(279)	(298)
Capital expenditures	6	59
Assets	2,894		2,708
Liquids Pipelines | Business segments
Segmented Information
Revenues	1,909	2,155
Commodity and gas distribution costs	(4)	(3)
Operating and administrative	(747)	(760)
Asset impairment	(144)
Income/(loss) from equity investments	131	86
Other	11	2
Earnings/(loss) before interest and income taxes	1,156	1,480
Capital expenditures	615	654
Assets	64,842		63,881
Gas Transmission and Midstream | Business segments
Segmented Information
Revenues	1,937
Commodity and gas distribution costs	(620)
Operating and administrative	(507)
Asset impairment	(913)
Income/(loss) from equity investments	208
Other	21
Earnings/(loss) before interest and income taxes	126
Capital expenditures	825
Gas Pipelines and Processing | Business segments
Segmented Information
Revenues		1,235
Commodity and gas distribution costs		(647)
Operating and administrative		(254)
Income/(loss) from equity investments		110
Other		31
Earnings/(loss) before interest and income taxes		475
Capital expenditures		655
Assets	61,880		60,745
Gas Distribution | Business segments
Segmented Information
Revenues	2,237	1,584
Commodity and gas distribution costs	(1,388)	(1,046)
Operating and administrative	(248)	(189)
Asset impairment	0
Income/(loss) from equity investments	17	36
Other	18	2
Earnings/(loss) before interest and income taxes	636	387
Capital expenditures	183	183
Assets	25,784		25,956
Green Power and Transmission | Business segments
Segmented Information
Revenues	157	137
Commodity and gas distribution costs	0	1
Operating and administrative	(30)	(40)
Asset impairment	0
Income/(loss) from equity investments	(25)	2
Other	7	1
Earnings/(loss) before interest and income taxes	109	101
Capital expenditures	14	114
Assets	6,466		6,289
Energy Services | Business segments
Segmented Information
Revenues	6,632	6,133
Commodity and gas distribution costs	(6,455)	(5,968)
Operating and administrative	(12)	(12)
Asset impairment	0
Income/(loss) from equity investments	4	2
Other	0	1
Earnings/(loss) before interest and income taxes	169	156
Capital expenditures	0	$ 0
Assets	$ 1,628		$ 2,514

EARNINGS PER COMMON SHARE - BAS

EARNINGS PER COMMON SHARE - BASIC (Details) - shares shares in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Earnings Per Share [Abstract]
Prorata weighted average interest in entity's own common shares	13	13

EARNINGS PER COMMON SHARE - DIL

EARNINGS PER COMMON SHARE - DILUTED (Details) - $ / shares	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Weighted average number of common shares outstanding diluted
Weighted average common shares outstanding (in shares)	1,685,000,000	1,177,000,000
Effect of dilutive options (in shares)	4,000,000	10,000,000
Diluted weighted average common shares outstanding (in shares)	1,689,000,000	1,187,000,000
Stock options
Weighted average number of common shares outstanding diluted
Antidilutive securities excluded from the diluted earnings per common share calculation (in shares)	29,882,142	13,545,193
Weighted average exercise price of antidilutive securities (in Canadian dollars per share)	$ 49.80	$ 57.71

ASSETS HELD FOR SALE (Details)

ASSETS HELD FOR SALE (Details) $ in Millions, $ in Billions	3 Months Ended
	Mar. 31, 2018CAD ($)	May 09, 2018USD ($)
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]
Provision for loss (gain) on disposal, before income tax	$ 913
Provision for loss (gain) on disposal, net of tax	701
Asset Impairment | Disposal Group, Held-for-sale, Not Discontinued Operations | Line 10 Crude Oil Pipeline
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Provision for loss (gain) on disposal, before income tax	144
Provision for loss (gain) on disposal, net of tax	$ 85
Subsequent Event | Enbridge (U.S.) Inc. | Midcoast Operating L.P.
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal group, consideration		$ 1.1

ASSETS HELD FOR SALE - ASEETS H

ASSETS HELD FOR SALE - ASEETS HELD FOR SALE (Details) - Disposal Group, Held-for-sale, Not Discontinued Operations - CAD ($) $ in Millions	Mar. 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)	$ 305	$ 424
Deferred amounts and other assets (long-term assets held for sale)	422	1,190
Accounts payable and other (current liabilities held for sale)	(233)	(315)
Other long-term liabilities (long-term liabilities held for sale)	(37)	(34)
Net assets held for sale	$ 457	$ 1,265

DEBT - CREDIT FACILITIES (Detai

DEBT - CREDIT FACILITIES (Details) - Mar. 31, 2018 - Committed credit facilities $ in Millions, $ in Millions	CAD ($)	USD ($)
CREDIT FACILITIES
Total Facilities	$ 21,938
Draws	10,863
Available	11,075
Enbridge Inc.
CREDIT FACILITIES
Total Facilities	6,644
Draws	2,616
Available	4,028
Repayments of principal in next twelve months		$ 125
Repayments of principal in year three	150
Enbridge Inc. | Debt Instrument, Redemption, Period One
CREDIT FACILITIES
Repayments of principal in next twelve months	135
Enbridge Inc. | Debt Instrument, Redemption, Period Two
CREDIT FACILITIES
Repayments of principal in next twelve months	161
Enbridge (U.S.) Inc.
CREDIT FACILITIES
Total Facilities	2,469
Draws	1,142
Available	1,327
Enbridge Energy Partners, L.P.
CREDIT FACILITIES
Total Facilities	3,385
Draws	1,660
Available	1,725
Repayments of principal in next twelve months	226	175
Repayments of principal in year three	239	185
Enbridge Gas Distribution Inc.
CREDIT FACILITIES
Total Facilities	1,017
Draws	884
Available	133
Enbridge Income Fund
CREDIT FACILITIES
Total Facilities	1,500
Draws	566
Available	934
Enbridge Pipelines Inc.
CREDIT FACILITIES
Total Facilities	3,000
Draws	1,730
Available	1,270
Spectra Energy Partners, LP
CREDIT FACILITIES
Total Facilities	3,223
Draws	2,135
Available	1,088
Repayments of principal in year four	434	$ 336
Union Gas Limited
CREDIT FACILITIES
Total Facilities	700
Draws	130
Available	$ 570

DEBT - NARRATIVE (Details)

DEBT - NARRATIVE (Details) $ in Millions	3 Months Ended
	Mar. 31, 2018CAD ($)	Mar. 31, 2018USD ($)	Dec. 31, 2017CAD ($)
Line of Credit Facility [Line Items]
Commitment fee percentage	0.20%	0.20%
Long-term debt	$ 61,191,000,000		$ 60,865,000,000
Uncommitted demand credit facilities
Line of Credit Facility [Line Items]
Amount of credit facility	790,000,000		792,000,000
Unutilized amount of facility	511,000,000		518,000,000
Commercial paper and credit facility draws
Line of Credit Facility [Line Items]
Long-term debt	9,832,000,000		$ 10,055,000,000
Enbridge (U.S.) Inc.
Line of Credit Facility [Line Items]
Extinguishment of debt		$ 950
Westcoast Energy Inc
Line of Credit Facility [Line Items]
Extinguishment of debt	$ 400,000,000
Enbridge Inc.
Line of Credit Facility [Line Items]
Extinguishment of debt		$ 650

DEBT - LONG TERM DEBT ISSUANCE

DEBT - LONG TERM DEBT ISSUANCE (Details) - USD ($) $ in Millions	1 Months Ended
	Mar. 31, 2018	Jan. 31, 2018
3.50% Senior Notes Due 2028 | Spectra Energy Partners, LP
DEBT
Face amount of notes issued		$ 400
Interest rate (as a percent)		3.50%
4.15% Senior Notes Due 2048 | Spectra Energy Partners, LP
DEBT
Face amount of notes issued		$ 400
Interest rate (as a percent)		4.15%
Enbridge Inc. | Fixed to Floating Rate Notes Due 2078
DEBT
Face amount of notes issued	$ 850
Interest rate (as a percent)	6.25%
Maturity period of debt	60 years
Callable period	10 years
Term of fixed interest rate	10 years
Debt Instrument, Redemption, Period One | Enbridge Inc. | Fixed to Floating Rate Notes Due 2078
DEBT
Basis spread on variable rate (as a percent)	364.10%
Debt Instrument, Redemption, Period One | Enbridge Inc. | Fixed to Floating Rate Notes Due 2078 | Minimum
DEBT
Variable rate period subsequent to fixed rate period	10 years
Debt Instrument, Redemption, Period One | Enbridge Inc. | Fixed to Floating Rate Notes Due 2078 | Maximum
DEBT
Variable rate period subsequent to fixed rate period	30 years
Debt Instrument, Redemption, Period Two | Enbridge Inc. | Fixed to Floating Rate Notes Due 2078
DEBT
Basis spread on variable rate (as a percent)	439.10%
Debt Instrument, Redemption, Period Two | Enbridge Inc. | Fixed to Floating Rate Notes Due 2078 | Minimum
DEBT
Variable rate period subsequent to fixed rate period	30 years
Debt Instrument, Redemption, Period Two | Enbridge Inc. | Fixed to Floating Rate Notes Due 2078 | Maximum
DEBT
Variable rate period subsequent to fixed rate period	60 years

DEBT - LONG TERM DEBT REPAYMENT

DEBT - LONG TERM DEBT REPAYMENTS (Details) $ in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2018CAD ($)	Mar. 31, 2018USD ($)	Jan. 31, 2018CAD ($)
Enbridge Southern Lights L P | 4.014% medium-term note due June 2040
DEBT
Face amount of notes issued			$ 9
Interest rate (as a percent)			4.01%
Spectra Energy Capitals, LLC
DEBT
Gain (loss) on extinguishment of debt	$ 37	$ 29
Spectra Energy Capitals, LLC | 6.75% Senior Unsecured Notes Due 2032
DEBT
Face amount of notes issued		$ 64
Interest rate (as a percent)		6.75%
Repayments of debt		$ 80
Spectra Energy Capitals, LLC | 7.50% Senior Unsecured Notes Due 2038
DEBT
Face amount of notes issued		$ 43
Interest rate (as a percent)		7.50%
Repayments of debt		$ 59
Spectra Energy Capitals, LLC | 5.65% Senior Unsecured Notes Due 2020
DEBT
Face amount of notes issued		$ 163
Interest rate (as a percent)		5.65%
Repayments of debt		$ 172
Spectra Energy Capitals, LLC | 3.30% Senior Unsecured Notes Due 2023
DEBT
Face amount of notes issued		$ 498
Interest rate (as a percent)		3.30%
Repayments of debt		$ 508

COMPONENTS OF ACCUMULATED OTH46

COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME (Details) - CAD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Changes in AOCI
Balance at the beginning of the period	$ 58,135
Balance at the end of the period	61,432
Accumulated other comprehensive income
Changes in AOCI
Balance at the beginning of the period	(973)	$ 1,058
Other comprehensive income/(loss) retained in AOCI	1,284	347
Other comprehensive (income)/loss reclassified to earnings, Pension and OPEB	(38)	6
Total before tax impact	1,286	391
Income tax on amounts retained in AOCI	28	(1)
Income tax on amounts reclassified to earnings	(12)	(10)
Tax impact	16	(11)
Balance at the end of the period	329	1,438
Accumulated other comprehensive income | Interest rate contracts
Changes in AOCI
Other comprehensive (income)/loss reclassified to earnings, Cash Flow Hedges	28	31
Accumulated other comprehensive income | Commodity contracts
Changes in AOCI
Other comprehensive (income)/loss reclassified to earnings, Cash Flow Hedges	(1)	(2)
Accumulated other comprehensive income | Foreign exchange contracts
Changes in AOCI
Other comprehensive (income)/loss reclassified to earnings, Cash Flow Hedges	4
Accumulated other comprehensive income | Other contracts
Changes in AOCI
Other comprehensive (income)/loss reclassified to earnings, Cash Flow Hedges	9	9
Cash Flow Hedges
Changes in AOCI
Balance at the beginning of the period	(644)	(746)
Other comprehensive income/(loss) retained in AOCI	70	(1)
Total before tax impact	110	37
Income tax on amounts retained in AOCI	(9)	(1)
Income tax on amounts reclassified to earnings	(11)	(8)
Tax impact	(20)	(9)
Balance at the end of the period	(554)	(718)
Cash Flow Hedges | Interest rate contracts
Changes in AOCI
Other comprehensive (income)/loss reclassified to earnings	28	31
Cash Flow Hedges | Commodity contracts
Changes in AOCI
Other comprehensive (income)/loss reclassified to earnings	(1)	(2)
Cash Flow Hedges | Foreign exchange contracts
Changes in AOCI
Other comprehensive (income)/loss reclassified to earnings	4
Cash Flow Hedges | Other contracts
Changes in AOCI
Other comprehensive (income)/loss reclassified to earnings	9	9
Net Investment Hedges
Changes in AOCI
Balance at the beginning of the period	(139)	(629)
Other comprehensive income/(loss) retained in AOCI	(213)	50
Total before tax impact	(213)	50
Income tax on amounts retained in AOCI	29	(1)
Tax impact	29	(1)
Balance at the end of the period	(323)	(580)
Cumulative Translation Adjustment
Changes in AOCI
Balance at the beginning of the period	77	2,700
Other comprehensive income/(loss) retained in AOCI	1,425	293
Total before tax impact	1,425	293
Balance at the end of the period	1,502	2,993
Equity Investees
Changes in AOCI
Balance at the beginning of the period	10	37
Other comprehensive income/(loss) retained in AOCI	2	5
Total before tax impact	2	5
Income tax on amounts retained in AOCI	8	1
Tax impact	8	1
Balance at the end of the period	20	43
Pension and OPEB Adjustment
Changes in AOCI
Balance at the beginning of the period	(277)	(304)
Other comprehensive (income)/loss reclassified to earnings	(38)	6
Total before tax impact	(38)	6
Income tax on amounts reclassified to earnings	(1)	(2)
Tax impact	(1)	(2)
Balance at the end of the period	$ (316)	$ (300)

NONCONTROLLING INTERESTS - REDE

NONCONTROLLING INTERESTS - REDEEMABLE NONCONTROLLING INFORMATION (Details) - CAD ($) shares in Millions, $ in Millions	Jan. 22, 2018	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Noncontrolling interests
Noncontrolling Interest [Line Items]
Spectra Energy Partners, LP restructuring (Note 9)		$ 1,486	$ 0
Additional paid-in capital
Noncontrolling Interest [Line Items]
Dilution gain on Spectra Energy Partners, LP restructuring (Note 9)		1,136	$ 0
Spectra Energy Partners, LP
Noncontrolling Interest [Line Items]
Noncontrolling interest, ownership percentage by parent				75.00%
Stock issued during period, shares, conversion of units (in shares)	172.5
Variable Interest Entity, Primary Beneficiary
Noncontrolling Interest [Line Items]
Variable interest ntity, ownership, shares (in shares)	403
Ownership interest in VIE (as a percent)	83.00%
Other Restructuring | Spectra Energy Partners, LP
Noncontrolling Interest [Line Items]
Deferred tax liabilities, net		$ 333
Incentive Distribution Rights | Spectra Energy Partners, LP
Noncontrolling Interest [Line Items]
Noncontrolling interest, ownership percentage by parent				100.00%

RISK MANAGEMENT AND FINANCIAL48

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - MARKET RISK (Details)	3 Months Ended
	Mar. 31, 2018item
Interest rate contracts - short-term borrowings
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
Average swap rate, fixed (as a percent)	2.60%
Average swap rate, variable (as a percent)	2.10%
Interest rate contracts - long-term debt
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
Average swap rate, fixed (as a percent)	3.40%
Equity contracts
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
Number of forms of stock-based compensation with equity price risk	1

RISK MANAGEMENT AND FINANCIAL49

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - TOTAL DERIVATIVE INSTRUMENTS (Details) - CAD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	$ (2,359)	$ (2,192)
Derivative liabilities, Total Net Derivative Instruments	(2,359)	(2,192)
Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(2,251)	(1,991)
Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(67)	(155)
Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(30)	(46)
Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(11)
Accounts receivable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Gross Derivative Instruments as Presented	261	296
Derivative assets, Amounts Available for Offset	(109)	(150)
Derivative assets, Total Net Derivative Instruments	152	146
Accounts receivable and other | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Gross Derivative Instruments as Presented	231	281
Accounts receivable and other | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Gross Derivative Instruments as Presented	27	9
Accounts receivable and other | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Gross Derivative Instruments as Presented	3	4
Accounts receivable and other | Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Gross Derivative Instruments as Presented	0	2
Deferred amounts and other assets
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Gross Derivative Instruments as Presented	147	181
Derivative assets, Amounts Available for Offset	(77)	(146)
Derivative assets, Total Net Derivative Instruments	70	35
Deferred amounts and other assets | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Gross Derivative Instruments as Presented	95	149
Deferred amounts and other assets | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Gross Derivative Instruments as Presented	52	25
Deferred amounts and other assets | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Gross Derivative Instruments as Presented	0	1
Deferred amounts and other assets | Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Gross Derivative Instruments as Presented	0	6
Accounts payable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Gross Derivative Instruments as Presented	(917)	(1,130)
Derivative liabilities, Amounts Available for Offset	109	150
Derivative liabilities, Total Net Derivative Instruments	(808)	(980)
Accounts payable and other | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Gross Derivative Instruments as Presented	(764)	(936)
Accounts payable and other | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Gross Derivative Instruments as Presented	(121)	(146)
Accounts payable and other | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Gross Derivative Instruments as Presented	(23)	(42)
Accounts payable and other | Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Gross Derivative Instruments as Presented	(9)	(6)
Other long-term liabilities
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Gross Derivative Instruments as Presented	(1,850)	(1,539)
Derivative liabilities, Amounts Available for Offset	77	146
Derivative liabilities, Total Net Derivative Instruments	(1,773)	(1,393)
Other long-term liabilities | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Gross Derivative Instruments as Presented	(1,813)	(1,485)
Other long-term liabilities | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Gross Derivative Instruments as Presented	(25)	(43)
Other long-term liabilities | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Gross Derivative Instruments as Presented	(10)	(9)
Other long-term liabilities | Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Gross Derivative Instruments as Presented	(2)	(2)
Foreign exchange contracts
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(1,771)	(1,383)
Derivative liabilities, Total Net Derivative Instruments	(1,771)	(1,383)
Foreign exchange contracts | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(1,754)	(1,330)
Foreign exchange contracts | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	13	(7)
Foreign exchange contracts | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(30)	(46)
Foreign exchange contracts | Accounts receivable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Gross Derivative Instruments as Presented	134	143
Derivative assets, Amounts Available for Offset	(70)	(83)
Derivative assets, Total Net Derivative Instruments	64	60
Foreign exchange contracts | Accounts receivable and other | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Gross Derivative Instruments as Presented	131	138
Foreign exchange contracts | Accounts receivable and other | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Gross Derivative Instruments as Presented	0	1
Foreign exchange contracts | Accounts receivable and other | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Gross Derivative Instruments as Presented	3	4
Foreign exchange contracts | Deferred amounts and other assets
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Gross Derivative Instruments as Presented	110	145
Derivative assets, Amounts Available for Offset	(58)	(125)
Derivative assets, Total Net Derivative Instruments	52	20
Foreign exchange contracts | Deferred amounts and other assets | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Gross Derivative Instruments as Presented	92	143
Foreign exchange contracts | Deferred amounts and other assets | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Gross Derivative Instruments as Presented	18	1
Foreign exchange contracts | Deferred amounts and other assets | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Gross Derivative Instruments as Presented	0	1
Foreign exchange contracts | Accounts payable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Gross Derivative Instruments as Presented	(355)	(359)
Derivative liabilities, Amounts Available for Offset	70	83
Derivative liabilities, Total Net Derivative Instruments	(285)	(276)
Foreign exchange contracts | Accounts payable and other | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Gross Derivative Instruments as Presented	(327)	(312)
Foreign exchange contracts | Accounts payable and other | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Gross Derivative Instruments as Presented	(5)	(5)
Foreign exchange contracts | Accounts payable and other | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Gross Derivative Instruments as Presented	(23)	(42)
Foreign exchange contracts | Other long-term liabilities
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Gross Derivative Instruments as Presented	(1,660)	(1,312)
Derivative liabilities, Amounts Available for Offset	58	125
Derivative liabilities, Total Net Derivative Instruments	(1,602)	(1,187)
Foreign exchange contracts | Other long-term liabilities | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Gross Derivative Instruments as Presented	(1,650)	(1,299)
Foreign exchange contracts | Other long-term liabilities | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Gross Derivative Instruments as Presented		(4)
Foreign exchange contracts | Other long-term liabilities | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Gross Derivative Instruments as Presented	(10)	(9)
Interest rate contracts
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(286)	(348)
Derivative liabilities, Total Net Derivative Instruments	(286)	(348)
Interest rate contracts | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(185)	(183)
Interest rate contracts | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(90)	(165)
Interest rate contracts | Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(11)
Interest rate contracts | Accounts receivable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Gross Derivative Instruments as Presented	27	8
Derivative assets, Amounts Available for Offset	(5)	(3)
Derivative assets, Total Net Derivative Instruments	22	5
Interest rate contracts | Accounts receivable and other | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Gross Derivative Instruments as Presented	27	6
Interest rate contracts | Accounts receivable and other | Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Gross Derivative Instruments as Presented	0	2
Interest rate contracts | Deferred amounts and other assets
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Gross Derivative Instruments as Presented	15	13
Derivative assets, Amounts Available for Offset	0	(2)
Derivative assets, Total Net Derivative Instruments	15	11
Interest rate contracts | Deferred amounts and other assets | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Gross Derivative Instruments as Presented	15	7
Interest rate contracts | Deferred amounts and other assets | Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Gross Derivative Instruments as Presented	0	6
Interest rate contracts | Accounts payable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Gross Derivative Instruments as Presented	(306)	(329)
Derivative liabilities, Amounts Available for Offset	5	3
Derivative liabilities, Total Net Derivative Instruments	(301)	(326)
Interest rate contracts | Accounts payable and other | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Gross Derivative Instruments as Presented	(185)	(183)
Interest rate contracts | Accounts payable and other | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Gross Derivative Instruments as Presented	(112)	(140)
Interest rate contracts | Accounts payable and other | Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Gross Derivative Instruments as Presented	(9)	(6)
Interest rate contracts | Other long-term liabilities
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Gross Derivative Instruments as Presented	(22)	(40)
Derivative liabilities, Amounts Available for Offset	0	2
Derivative liabilities, Total Net Derivative Instruments	(22)	(38)
Interest rate contracts | Other long-term liabilities | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Gross Derivative Instruments as Presented	0	0
Interest rate contracts | Other long-term liabilities | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Gross Derivative Instruments as Presented	(20)	(38)
Interest rate contracts | Other long-term liabilities | Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Gross Derivative Instruments as Presented	(2)	(2)
Commodity contracts
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(284)	(457)
Derivative liabilities, Total Net Derivative Instruments	(284)	(457)
Commodity contracts | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(301)	(476)
Commodity contracts | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	17	19
Commodity contracts | Accounts receivable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Gross Derivative Instruments as Presented	100	145
Derivative assets, Amounts Available for Offset	(34)	(64)
Derivative assets, Total Net Derivative Instruments	66	81
Commodity contracts | Accounts receivable and other | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Gross Derivative Instruments as Presented	100	143
Commodity contracts | Accounts receivable and other | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Gross Derivative Instruments as Presented	0	2
Commodity contracts | Deferred amounts and other assets
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Gross Derivative Instruments as Presented	22	23
Derivative assets, Amounts Available for Offset	(19)	(19)
Derivative assets, Total Net Derivative Instruments	3	4
Commodity contracts | Deferred amounts and other assets | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Gross Derivative Instruments as Presented	3	6
Commodity contracts | Deferred amounts and other assets | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Gross Derivative Instruments as Presented	19	17
Commodity contracts | Accounts payable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Gross Derivative Instruments as Presented	(246)	(439)
Derivative liabilities, Amounts Available for Offset	34	64
Derivative liabilities, Total Net Derivative Instruments	(212)	(375)
Commodity contracts | Accounts payable and other | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Gross Derivative Instruments as Presented	(244)	(439)
Commodity contracts | Accounts payable and other | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Gross Derivative Instruments as Presented	(2)
Commodity contracts | Other long-term liabilities
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Gross Derivative Instruments as Presented	(160)	(186)
Derivative liabilities, Amounts Available for Offset	19	19
Derivative liabilities, Total Net Derivative Instruments	(141)	(167)
Commodity contracts | Other long-term liabilities | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Gross Derivative Instruments as Presented	(160)	(186)
Other contracts
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(18)	(4)
Derivative liabilities, Total Net Derivative Instruments	(18)	(4)
Other contracts | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(11)	(2)
Other contracts | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(7)	(2)
Other contracts | Accounts payable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Gross Derivative Instruments as Presented	(10)	(3)
Derivative liabilities, Total Net Derivative Instruments	(10)	(3)
Other contracts | Accounts payable and other | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Gross Derivative Instruments as Presented	(8)	(2)
Other contracts | Accounts payable and other | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Gross Derivative Instruments as Presented	(2)	(1)
Other contracts | Other long-term liabilities
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Gross Derivative Instruments as Presented	(8)	(1)
Derivative liabilities, Total Net Derivative Instruments	(8)	(1)
Other contracts | Other long-term liabilities | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Gross Derivative Instruments as Presented	(3)
Other contracts | Other long-term liabilities | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Gross Derivative Instruments as Presented	$ (5)	$ (1)

RISK MANAGEMENT AND FINANCIAL50

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - NOTIONAL PRINCIPAL OR QUANTITY INFORMATION (Details) - Mar. 31, 2018 € in Millions, ¥ in Millions, £ in Millions, $ in Millions, $ in Millions, Bcf in Billions	CAD ($)MWhBcfMMBbls	USD ($)MWhBcfMMBbls	GBP (£)MWhBcfMMBbls	EUR (€)MWhBcfMMBbls	JPY (¥)MWhBcfMMBbls
Euro
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2020 | €				€ 35
Foreign exchange contracts - forwards - purchase | United States dollar
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2,018		$ 544
2,019		2
2,020		1
2,021		0
Foreign exchange contracts - forwards - purchase | GBP
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2018 | £			£ 0
2019 | £			0
Foreign exchange contracts - forwards - purchase | Euro
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2018 | €				264
2019 | €				375
2020 | €				0
Foreign exchange contracts - forwards - purchase | Japanese yen
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2019 | ¥					¥ 32,662
2020 | ¥					0
2022 | ¥					20,000
Thereafter | ¥					¥ 0
Foreign exchange contracts - forwards - sell | United States dollar
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2,018		3,215
2,019		3,247
2,020		3,258
2,021		1,689
2,022		1,676
Thereafter		$ 3,489
Foreign exchange contracts - forwards - sell | GBP
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2019 | £			89
2020 | £			25
2021 | £			27
2022 | £			28
Thereafter | £			£ 149
Foreign exchange contracts - forwards - sell | Euro
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2021 | €				169
2022 | €				169
Thereafter | €				€ 889
Interest rate contracts - short-term borrowings
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2,018	$ 3,749
2,019	2,100
2,020	527
2,021	109
2,022	93
Thereafter	203
Interest rate contracts - long-term receive fixed rate
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2,018	728
2,019	580
2,020	553
2,021	188
2,022	102
Thereafter	0
Interest rate contracts - long-term debt pay fixed rate
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2,018	2,242
2,019	800
2,020	447
Equity contracts
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2,018	40
2,019	37
2,020	$ 8
Commodity contracts | Natural gas
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2018 | Bcf	(16)	(16)	(16)	(16)	(16)
2019 | Bcf	(57)	(57)	(57)	(57)	(57)
2020 | Bcf	(23)	(23)	(23)	(23)	(23)
2021 | Bcf	(2)	(2)	(2)	(2)	(2)
2022 | Bcf	14	14	14	14	14
Thereafter | Bcf	2	2	2	2	2
Commodity contracts | Crude oil
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2018 | MMBbls	1	1	1	1	1
2019 | MMBbls	2	2	2	2	2
Commodity contracts | NGL
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2018 | MMBbls	(10)	(10)	(10)	(10)	(10)
2019 | MMBbls	(1)	(1)	(1)	(1)	(1)
Commodity contracts | Power
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2018 | MWh	60	60	60	60	60
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)
Thereafter | MWh	(43)	(43)	(43)	(43)	(43)

RISK MANAGEMENT AND FINANCIAL51

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - EARNINGS AND COMPREHENSIVE INCOME (Details) - CAD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of unrealized gain/(loss) recognized in OCI	$ 121	$ 4
Amount of (gain)/loss reclassified from AOCI to earnings (effective portion)	48	56
Amount of (gain)/loss reclassified from AOCI to earnings (ineffective portion and amount excluded from effectiveness testing)	(1)	2
Estimated gain of AOCI related to cash flow hedges reclassified to earnings in the next 12 months	$ 22
Period to hedge exposures to the variability of cash flows for all forecasted transactions	33 months
Unrealized loss on derivative in fair value hedge	$ 8	2
Unrealized gain on hedged item in fair value hedge	8	2
Total unrealized derivative fair value gain/(loss), net	(260)	418
Gain (loss) on derivative, net	3	0
Non-Qualifying Derivative Instruments
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Total unrealized derivative fair value gain/(loss), net	(260)	418
Gain (loss) on derivative, net	(3)	0
Foreign exchange contracts
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of (gain)/loss reclassified from AOCI to earnings (effective portion)	(1)	1
Foreign exchange contracts | Non-Qualifying Derivative Instruments
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Total unrealized derivative fair value gain/(loss), net	(424)	273
Foreign exchange 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 gain/(loss), net	297	159
Foreign exchange 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 gain/(loss), net	(127)	114
Foreign exchange contracts | Cash Flow Hedges
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of unrealized gain/(loss) recognized in OCI	21	(2)
Foreign exchange contracts | Net Investment Hedges
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of unrealized gain/(loss) recognized in OCI	16	8
Interest rate contracts | Interest expense
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of (gain)/loss reclassified from AOCI to earnings (effective portion)	41	48
Amount of (gain)/loss reclassified from AOCI to earnings (ineffective portion and amount excluded from effectiveness testing)	(1)	2
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 gain/(loss), net	(2)	(18)
Interest rate contracts | Cash Flow Hedges
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of unrealized gain/(loss) recognized in OCI	100	(14)
Commodity contracts
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of (gain)/loss reclassified from AOCI to earnings (effective portion)	(1)	(2)
Commodity contracts | Non-Qualifying Derivative Instruments
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Total unrealized derivative fair value gain/(loss), net	175	163
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 gain/(loss), net	(1)	(22)
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 gain/(loss), net	82	187
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 gain/(loss), net	84	5
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 gain/(loss), net	10	(7)
Commodity contracts | Cash Flow Hedges
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of unrealized gain/(loss) recognized in OCI	(2)	21
Other contracts | Operating and administrative expense
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of (gain)/loss reclassified from AOCI to earnings (effective portion)	9	9
Other contracts | Non-Qualifying Derivative Instruments
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Total unrealized derivative fair value gain/(loss), net	(9)	0
Other contracts | Cash Flow Hedges
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of unrealized gain/(loss) recognized in OCI	$ (14)	$ (9)

RISK MANAGEMENT AND FINANCIAL52

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - LIQUIDITY AND CREDIT RISK (Details) - CAD ($)	3 Months Ended	12 Months Ended
	Mar. 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	$ 308,000,000	$ 385,000,000
Cash collateral on asset exposure	0	0
Derivative instruments | Canadian financial institutions
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	49,000,000	82,000,000
Derivative instruments | United States financial institutions
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	29,000,000	19,000,000
Derivative instruments | European financial institutions
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	143,000,000	145,000,000
Derivative instruments | Asian financial institutions
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	15,000,000	2,000,000
Derivative instruments | Other
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	$ 72,000,000	$ 137,000,000

RISK MANAGEMENT AND FINANCIAL53

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - FAIR VALUE OF DERIVATIVES (Details) - CAD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Fair Value of Derivatives
Total net derivative asset/(liability)	$ (2,359)	$ (2,192)
Foreign exchange contracts
Fair Value of Derivatives
Total net derivative asset/(liability)	(1,771)	(1,383)
Interest rate contracts
Fair Value of Derivatives
Total net derivative asset/(liability)	(286)	(348)
Commodity contracts
Fair Value of Derivatives
Total net derivative asset/(liability)	(284)	(457)
Other contracts
Fair Value of Derivatives
Total net derivative asset/(liability)	(18)	(4)
Recurring basis
Fair Value of Derivatives
Current derivative assets	261	296
Long-term derivative assets	147	181
Current derivative liabilities	(917)	(1,130)
Long-term derivative liabilities	(1,850)	(1,539)
Total net derivative asset/(liability)	(2,359)	(2,192)
Recurring basis | Foreign exchange contracts
Fair Value of Derivatives
Current derivative assets	134	143
Long-term derivative assets	110	145
Current derivative liabilities	(355)	(359)
Long-term derivative liabilities	(1,660)	(1,312)
Total net derivative asset/(liability)	(1,771)	(1,383)
Recurring basis | Interest rate contracts
Fair Value of Derivatives
Current derivative assets	27	8
Long-term derivative assets	15	13
Current derivative liabilities	(306)	(329)
Long-term derivative liabilities	(22)	(40)
Total net derivative asset/(liability)	(286)	(348)
Recurring basis | Commodity contracts
Fair Value of Derivatives
Current derivative assets	100	145
Long-term derivative assets	22	23
Current derivative liabilities	(246)	(439)
Long-term derivative liabilities	(160)	(186)
Total net derivative asset/(liability)	(284)	(457)
Recurring basis | Other contracts
Fair Value of Derivatives
Current derivative liabilities	(10)	(3)
Long-term derivative liabilities	(8)	(1)
Total net derivative asset/(liability)	(18)	(4)
Level 1 | Recurring basis
Fair Value of Derivatives
Current derivative assets	0	1
Current derivative liabilities	(6)	(13)
Total net derivative asset/(liability)	(6)	(12)
Level 1 | Recurring basis | Commodity contracts
Fair Value of Derivatives
Current derivative assets	0	1
Current derivative liabilities	(6)	(13)
Total net derivative asset/(liability)	(6)	(12)
Level 2 | Recurring basis
Fair Value of Derivatives
Current derivative assets	179	181
Long-term derivative assets	126	160
Current derivative liabilities	(759)	(778)
Long-term derivative liabilities	(1,694)	(1,356)
Total net derivative asset/(liability)	(2,148)	(1,793)
Level 2 | Recurring basis | Foreign exchange contracts
Fair Value of Derivatives
Current derivative assets	134	143
Long-term derivative assets	110	145
Current derivative liabilities	(355)	(359)
Long-term derivative liabilities	(1,660)	(1,312)
Total net derivative asset/(liability)	(1,771)	(1,383)
Level 2 | Recurring basis | Interest rate contracts
Fair Value of Derivatives
Current derivative assets	27	8
Long-term derivative assets	15	13
Current derivative liabilities	(306)	(329)
Long-term derivative liabilities	(22)	(40)
Total net derivative asset/(liability)	(286)	(348)
Level 2 | Recurring basis | Commodity contracts
Fair Value of Derivatives
Current derivative assets	18	30
Long-term derivative assets	1	2
Current derivative liabilities	(88)	(87)
Long-term derivative liabilities	(4)	(3)
Total net derivative asset/(liability)	(73)	(58)
Level 2 | Recurring basis | Other contracts
Fair Value of Derivatives
Current derivative liabilities	(10)	(3)
Long-term derivative liabilities	(8)	(1)
Total net derivative asset/(liability)	(18)	(4)
Level 3 | Recurring basis
Fair Value of Derivatives
Current derivative assets	82	114
Long-term derivative assets	21	21
Current derivative liabilities	(152)	(339)
Long-term derivative liabilities	(156)	(183)
Total net derivative asset/(liability)	(205)	(387)
Level 3 | Recurring basis | Commodity contracts
Fair Value of Derivatives
Current derivative assets	82	114
Long-term derivative assets	21	21
Current derivative liabilities	(152)	(339)
Long-term derivative liabilities	(156)	(183)
Total net derivative asset/(liability)	$ (205)	$ (387)

RISK MANAGEMENT AND FINANCIAL54

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - LEVEL 3 INPUTS (Details) $ in Millions	3 Months Ended
	Mar. 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	$ (2,359)	$ (2,192)
Recurring basis
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	(2,359)	(2,192)
Level 3 | Recurring basis
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	(205)	$ (387)
Market approach valuation technique | Recurring basis | Commodity Contracts - Financial | NGL
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	$ (4)
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	2.49
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	4.25
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	3.20
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	48.92
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	63.73
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	53.07
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	0.34
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	1.83
Market approach valuation technique | Level 3 | Commodity Contracts - Financial | NGL | Weighted Average
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | $ / Gallon-gal	1.29
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	14.30
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	76.27
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	52
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	0.78
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	4.91
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	2.57
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	38.01
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	91.27
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	75.29
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	0.34
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	1.88
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	0.86
Market approach valuation technique | Level 3 | Recurring basis | 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 | Recurring basis | Commodity Contracts - Financial | Crude oil
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	(4)
Market approach valuation technique | Level 3 | Recurring basis | Commodity Contracts - Financial | Power
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	(100)
Market approach valuation technique | Level 3 | Recurring basis | Commodity Contracts - Physical | Natural gas
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	(81)
Market approach valuation technique | Level 3 | Recurring basis | Commodity Contracts - Physical | Crude oil
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	(29)
Market approach valuation technique | Level 3 | Recurring basis | Commodity Contracts - Physical | NGL
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	$ 5
Option model valuation technique | Level 3 | Commodity Options | Crude oil | Minimum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Option Volatility (as a percent)	22.00%
Option model valuation technique | Level 3 | Commodity Options | Crude oil | Maximum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Option Volatility (as a percent)	24.00%
Option model valuation technique | Level 3 | Commodity Options | Crude oil | Weighted Average
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Option Volatility (as a percent)	23.00%
Option model valuation technique | Level 3 | Commodity Options | NGL | Minimum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Option Volatility (as a percent)	0.00%
Option model valuation technique | Level 3 | Commodity Options | NGL | Maximum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Option Volatility (as a percent)	0.00%
Option model valuation technique | Level 3 | Commodity Options | NGL | Weighted Average
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Option Volatility (as a percent)	0.00%
Option model valuation technique | Level 3 | Commodity Options | Power | Minimum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Option Volatility (as a percent)	23.00%
Option model valuation technique | Level 3 | Commodity Options | Power | Maximum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Option Volatility (as a percent)	26.00%
Option model valuation technique | Level 3 | Commodity Options | Power | Weighted Average
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Option Volatility (as a percent)	24.00%
Option model valuation technique | Level 3 | Recurring basis | Commodity Options | Crude oil
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	$ (1)
Option model valuation technique | Level 3 | Recurring basis | Commodity Options | Power
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	$ 0

RISK MANAGEMENT AND FINANCIAL55

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - CHANGES IN LEVEL 3 (Details) - CAD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Changes in net fair value of derivative assets and liabilities classified as Level 3
Level 3 net derivative asset/(liability) at beginning of period	$ (387)	$ (295)
Total gain/(loss)
Included in earnings	31	83
Included in OCI	(3)	19
Settlements	154	70
Level 3 net derivative liability at end of period	$ (205)	$ (123)

RISK MANAGEMENT AND FINANCIAL56

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - OTHER FINANCIAL INSTRUMENTS (Details) - CAD ($)	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Fair Value of Other Financial Instruments
FMVA investments	$ 100,000,000		$ 99,000,000
Long-term debt, carrying value	65,600,000,000		64,000,000,000
Long-term debt	68,000,000,000		67,400,000,000
Net Investment Hedges
Fair Value of Other Financial Instruments
Unrealized foreign exchange gain (loss) on translation of United States dollar denominated debt	194,000,000	$ 20,000,000
Unrealized gain (loss) on change in fair value of outstanding forward exchange forward contracts	15,000,000	9,000,000
Realized gain (loss) associated with the settlement of foreign exchange forward contracts	23,000,000	1,000,000
Realized gain (loss) associated with the settlement of United Stated dollar denominated debt that matured	11,000,000	20,000,000
Amount of ineffectiveness	0	$ 0
Preferred share investment
Fair Value of Other Financial Instruments
Held to maturity investment at amortized cost	$ 382,000,000		371,000,000
Cumulative dividends based on average yield of Government of Canada bonds, maturity period of bonds	10 years
Cumulative dividends based on average yield of Government of Canada bonds, spread over reference rate (as a percent)	4.50%
Held to maturity investment, fair value			580,000,000
Carrying value
Fair Value of Other Financial Instruments
Noncurrent notes receivable	$ 92,000,000		89,000,000
Fair Value
Fair Value of Other Financial Instruments
Restricted long-term investments held in trust	280,000,000		267,000,000
Noncurrent notes receivable	$ 92,000,000		$ 89,000,000

INCOME TAXES (Details)

INCOME TAXES (Details) - CAD ($)	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Income Tax Disclosure [Abstract]
Effective income tax rate (as a percent)	(16.70%)	17.30%
Provisional tax expense	$ 0

RETIREMENT AND POSTRETIREMENT B

RETIREMENT AND POSTRETIREMENT BENEFITS - NET BENEFITS COSTS RECOGNIZED (Details) - CAD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	$ 65	$ 54
Interest cost	45	32
Expected return on plan assets	(82)	(51)
Amortization of prior service costs	(1)	0
Amortization of actuarial loss	7	9
Net periodic benefit costs	$ 34	$ 44

SUBSEQUENT EVENTS (Details)

SUBSEQUENT EVENTS (Details) $ in Millions, $ in Millions	May 09, 2018CAD ($)	Apr. 30, 2018USD ($)	Apr. 12, 2018CAD ($)	May 09, 2018USD ($)	Apr. 12, 2018USD ($)	Dec. 31, 2017
Spectra Energy Partners, LP
SUBSEQUENT EVENTS
Noncontrolling interest, ownership percentage by parent						75.00%
Subsequent Event | Enbridge Inc. | Fixed to Floating Rate Subordinated Notes, 6.625%
SUBSEQUENT EVENTS
Face amount of notes issued			$ 750
Maturity period of debt			60 years
Callable period			10 years
Term of fixed interest rate			10 years
Interest rate (as a percent)			6.625%		6.625%
Subsequent Event | Enbridge Inc. | Fixed to Floating Rate Subordinated Notes, 6.375%
SUBSEQUENT EVENTS
Face amount of notes issued					$ 600
Maturity period of debt			60 years
Callable period			5 years
Term of fixed interest rate			5 years
Interest rate (as a percent)			6.375%		6.375%
Subsequent Event | Minimum | Enbridge Inc. | Fixed to Floating Rate Subordinated Notes, 6.625%
SUBSEQUENT EVENTS
Variable rate period subsequent to fixed rate period			10 years
Subsequent Event | Minimum | Enbridge Inc. | Fixed to Floating Rate Subordinated Notes, 6.375%
SUBSEQUENT EVENTS
Variable rate period subsequent to fixed rate period			5 years
Subsequent Event | Minimum | Debt Instrument, Redemption, Period Two | Enbridge Inc. | Fixed to Floating Rate Subordinated Notes, 6.625%
SUBSEQUENT EVENTS
Variable rate period subsequent to fixed rate period			30 years
Subsequent Event | Minimum | Debt Instrument, Redemption, Period Two | Enbridge Inc. | Fixed to Floating Rate Subordinated Notes, 6.375%
SUBSEQUENT EVENTS
Variable rate period subsequent to fixed rate period			10 years
Subsequent Event | Minimum | Debt Instrument, Redemption, Period Three | Enbridge Inc. | Fixed to Floating Rate Subordinated Notes, 6.375%
SUBSEQUENT EVENTS
Variable rate period subsequent to fixed rate period			25 years
Subsequent Event | Maximum | Debt Instrument, Redemption, Period One | Enbridge Inc. | Fixed to Floating Rate Subordinated Notes, 6.625%
SUBSEQUENT EVENTS
Variable rate period subsequent to fixed rate period			30 years
Subsequent Event | Maximum | Debt Instrument, Redemption, Period One | Enbridge Inc. | Fixed to Floating Rate Subordinated Notes, 6.375%
SUBSEQUENT EVENTS
Variable rate period subsequent to fixed rate period			10 years
Subsequent Event | Maximum | Debt Instrument, Redemption, Period Two | Enbridge Inc. | Fixed to Floating Rate Subordinated Notes, 6.625%
SUBSEQUENT EVENTS
Variable rate period subsequent to fixed rate period			60 years
Subsequent Event | Maximum | Debt Instrument, Redemption, Period Two | Enbridge Inc. | Fixed to Floating Rate Subordinated Notes, 6.375%
SUBSEQUENT EVENTS
Variable rate period subsequent to fixed rate period			25 years
Subsequent Event | Maximum | Debt Instrument, Redemption, Period Three | Enbridge Inc. | Fixed to Floating Rate Subordinated Notes, 6.375%
SUBSEQUENT EVENTS
Variable rate period subsequent to fixed rate period			60 years
Subsequent Event | Canadian Dollar Offered Rate | Debt Instrument, Redemption, Period One | Enbridge Inc. | Fixed to Floating Rate Subordinated Notes, 6.625%
SUBSEQUENT EVENTS
Basis spread on variable rate (as a percent)			4.32%
Subsequent Event | Canadian Dollar Offered Rate | Debt Instrument, Redemption, Period Two | Enbridge Inc. | Fixed to Floating Rate Subordinated Notes, 6.625%
SUBSEQUENT EVENTS
Basis spread on variable rate (as a percent)			5.07%
Subsequent Event | London Interbank Offered Rate (LIBOR) | Debt Instrument, Redemption, Period One | Enbridge Inc. | Fixed to Floating Rate Subordinated Notes, 6.625%
SUBSEQUENT EVENTS
Basis spread on variable rate (as a percent)			3.59%
Subsequent Event | London Interbank Offered Rate (LIBOR) | Debt Instrument, Redemption, Period Two | Enbridge Inc. | Fixed to Floating Rate Subordinated Notes, 6.625%
SUBSEQUENT EVENTS
Basis spread on variable rate (as a percent)			3.84%
Subsequent Event | London Interbank Offered Rate (LIBOR) | Debt Instrument, Redemption, Period Three | Enbridge Inc. | Fixed to Floating Rate Subordinated Notes, 6.625%
SUBSEQUENT EVENTS
Basis spread on variable rate (as a percent)			4.59%
Subsequent Event | Spectra Energy Partners, LP | Sabal Trail Transmission L L C
SUBSEQUENT EVENTS
Face amount of notes issued		$ 750
Ownership interest in VIE (as a percent)		50.00%
Subsequent Event | Spectra Energy Partners, LP | Sabal Trail Transmission L L C | 4.246% Senior Notes Due In 2028
SUBSEQUENT EVENTS
Face amount of notes issued		$ 500
Interest rate (as a percent)		4.246%
Subsequent Event | Spectra Energy Partners, LP | Sabal Trail Transmission L L C | 4.682% Senior Notes Due in 2038
SUBSEQUENT EVENTS
Face amount of notes issued		$ 600
Interest rate (as a percent)		4.682%
Subsequent Event | Spectra Energy Partners, LP | Sabal Trail Transmission L L C | 4.832% Senior Notes Due In 2048
SUBSEQUENT EVENTS
Face amount of notes issued		$ 400
Interest rate (as a percent)		4.832%
CANADA | Discontinued Operations, Disposed of by Sale | Subsequent Event | Renewable Energy Assets
SUBSEQUENT EVENTS
Noncontrolling interest, ownership percentage by parent				49.00%
UNITED STATES | Discontinued Operations, Disposed of by Sale | Subsequent Event | Renewable Energy Assets
SUBSEQUENT EVENTS
Noncontrolling interest, ownership percentage by parent				49.00%
Hohe See Offshore Wind Project | Discontinued Operations, Disposed of by Sale | Subsequent Event
SUBSEQUENT EVENTS
Ownership interest in equity investment (as a percent)				49.00%
The Assets | Subsequent Event
SUBSEQUENT EVENTS
Noncontrolling interest, ownership percentage by parent				51.00%
Proceeds from sale of equity method investments	$ 1,750
Midcoast Operating L.P. | Subsequent Event | Enbridge (U.S.) Inc.
SUBSEQUENT EVENTS
Disposal group, consideration				$ 1,100