Enbridge (ENB) 10-Q 2 Nov 18 2018 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2018	Oct. 26, 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	Sep. 30, 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		1,724,389,606
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q3

CONSOLIDATED STATEMENTS OF EARN

CONSOLIDATED STATEMENTS OF EARNINGS - CAD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Operating revenues
Total operating revenues (Note 3)	$ 11,345	$ 9,227	$ 34,816	$ 31,489
Operating expenses
Operating and administrative	1,652	1,587	4,929	4,784
Depreciation and amortization	799	848	2,452	2,388
Asset impairment (Note 6)	4	0	1,076	0
Goodwill impairment (Note 6)	1,019	0	1,019	0
Total operating expenses	10,491	7,737	31,513	26,957
Operating income	854	1,490	3,303	4,532
Income from equity investments	378	280	1,076	752
Other income/(expense)
Net foreign currency gain/(loss)	57	150	(171)	257
Other	(33)	75	61	182
Interest expense	(696)	(653)	(2,042)	(1,704)
Earnings before income taxes	560	1,342	2,227	4,019
Income tax expense (Note 12)	(347)	(327)	(177)	(818)
Earnings	213	1,015	2,050	3,201
Earnings attributable to noncontrolling interests and redeemable noncontrolling interests	(209)	(168)	(352)	(633)
Earnings attributable to controlling interests	4	847	1,698	2,568
Preference share dividends	(94)	(82)	(272)	(246)
Earnings/(loss) attributable to common shareholders	$ (90)	$ 765	$ 1,426	$ 2,322
Earnings per common share attributable to common shareholders (Note 5) (in Canadian dollars per share)	$ (0.05)	$ 0.47	$ 0.84	$ 1.57
Diluted earnings per common share attributable to common shareholders (Note 5) (in Canadian dollars per share)	$ (0.05)	$ 0.47	$ 0.84	$ 1.56
Commodity sales
Operating revenues
Total operating revenues (Note 3)	$ 6,919	$ 5,012	$ 20,638	$ 18,498
Operating expenses
Cost of goods and services sold	6,905	5,087	20,180	18,126
Gas Distribution Revenue
Operating revenues
Total operating revenues (Note 3)	478	573	3,260	2,783
Operating expenses
Cost of goods and services sold	112	215	1,857	1,659
Transportation and other services revenues
Operating revenues
Total operating revenues (Note 3)	$ 3,948	$ 3,642	$ 10,918	$ 10,208

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - CAD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Statement of Comprehensive Income [Abstract]
Earnings	$ 213	$ 1,015	$ 2,050	$ 3,201
Other comprehensive income/(loss), net of tax
Change in unrealized gain on cash flow hedges	57	97	150	10
Change in unrealized gain/(loss) on net investment hedges	83	285	(200)	505
Other comprehensive income from equity investees	(1)	1	18	9
Reclassification to earnings of (gain)/loss on cash flow hedges	31	(14)	104	93
Reclassification to earnings of pension and other postretirement benefits (OPEB) amounts	5	6	28	13
Foreign currency translation adjustments	(989)	(2,057)	1,637	(3,068)
Other comprehensive income/(loss), net of tax	(814)	(1,682)	1,737	(2,438)
Comprehensive income/(loss)	(601)	(667)	3,787	763
Comprehensive (income)/loss attributable to noncontrolling interests and redeemable noncontrolling interests	(102)	155	(546)	(204)
Comprehensive income/(loss) attributable to controlling interests	(703)	(512)	3,241	559
Preference share dividends	(94)	(82)	(272)	(246)
Comprehensive income/(loss) attributable to common shareholders	$ (797)	$ (594)	$ 2,969	$ 313

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			37,429
Dividend Reinvestment and Share Purchase Plan			889
Options exercised			58	(70)
Stock-based compensation				70
Fair value of outstanding earned stock-based compensation from Merger Transaction				77
Enbridge Energy Company, Inc. common control transaction				78					(331)
Dilution loss on Enbridge Energy Partners, L.P. issuance of Class A units				(522)					832
Dilution gain on Spectra Energy Partners, LP restructuring (Note 10)				0
Dilution gains/(losses) and other				62
Sale of noncontrolling interests in subsidiaries (Note 10)				0					0
Earnings attributable to controlling interests	$ 2,568				2,568
Preference share dividends					(246)
Common share dividends declared					(2,552)
Dividends paid to reciprocal shareholder					22
Redemption value adjustment attributable to redeemable noncontrolling interests					232
Adjustment for the recognition of unutilized tax deductions for stock-based compensation expense					41
Other comprehensive income/(loss) attributable to common shareholders, net of tax						(2,009)
Earnings attributable to noncontrolling interests									452
Change in unrealized gain/(loss) on cash flow hedges									(13)
Foreign currency translation adjustments									(446)
Reclassification to earnings of loss on cash flow hedges									29
Other comprehensive income/(loss) attributable to noncontrolling interests, net of tax									(430)
Comprehensive income attributable to noncontrolling interests									22
Noncontrolling interests resulting from Merger Transaction									8,877
Spectra Energy Partners, LP restructuring (Note 10)									0
Distributions									(634)
Contributions									498
Deconsolidation of Sabal Trail Transmission, LLC									(2,318)
Disposition of Olympic Pipeline									(24)
Other									(16)
Balance at Sep. 30, 2017	$ 64,996	7,255	48,868	3,094	(651)	(951)	(102)	$ 57,513	7,483
Increase (Decrease) in Stockholders' Equity
Dividends paid per common share (in Canadian dollars per share)	$ 1.803
Modified 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			1,181
Options exercised			26	(14)
Stock-based compensation				40
Fair value of outstanding earned stock-based compensation from Merger Transaction				0
Enbridge Energy Company, Inc. common control transaction				0					0
Dilution loss on Enbridge Energy Partners, L.P. issuance of Class A units				0					0
Dilution gain on Spectra Energy Partners, LP restructuring (Note 10)				1,136
Dilution gains/(losses) and other				(89)
Sale of noncontrolling interests in subsidiaries (Note 10)				79					(1,183)
Earnings attributable to controlling interests	1,698				1,698
Preference share dividends					(272)
Common share dividends declared					(2,297)
Dividends paid to reciprocal shareholder					25
Redemption value adjustment attributable to redeemable noncontrolling interests					(318)
Adjustment for the recognition of unutilized tax deductions for stock-based compensation expense					0
Other comprehensive income/(loss) attributable to common shareholders, net of tax						1,543
Earnings attributable to noncontrolling interests									248
Change in unrealized gain/(loss) on cash flow hedges									8
Foreign currency translation adjustments									140
Reclassification to earnings of loss on cash flow hedges									23
Other comprehensive income/(loss) attributable to noncontrolling interests, net of tax									171
Comprehensive income attributable to noncontrolling interests									419
Noncontrolling interests resulting from Merger Transaction									0
Spectra Energy Partners, LP restructuring (Note 10)									(1,486)
Distributions									(637)
Contributions									23
Deconsolidation of Sabal Trail Transmission, LLC									0
Disposition of Olympic Pipeline									0
Other									12
Balance at Sep. 30, 2018	$ 67,898	$ 7,747	$ 51,944	$ 4,346	(3,718)	$ 570	$ (102)	$ 60,787	$ 7,111
Increase (Decrease) in Stockholders' Equity
Dividends paid per common share (in Canadian dollars per share)	$ 2.013
Modified retrospective adoption of accounting standard (Note 2)					$ (86)

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - CAD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Operating activities
Earnings	$ 2,050	$ 3,201
Adjustments to reconcile earnings to net cash provided by operating activities:
Depreciation and amortization	2,452	2,388
Deferred income tax (recovery)/expense	(51)	725
Changes in unrealized (gain)/loss on derivative instruments, net (Note 11)	319	(1,243)
Earnings from equity investments	(1,076)	(752)
Distributions from equity investments	1,090	859
Asset impairment	1,076	0
Goodwill impairment	1,019	0
(Gain)/loss on dispositions	76	(116)
Other	101	132
Changes in operating assets and liabilities	943	121
Net cash provided by operating activities	7,999	5,315
Investing activities
Capital expenditures	(4,584)	(5,868)
Long-term investments	(1,051)	(3,012)
Distributions from equity investments in excess of cumulative earnings (Note 7)	1,243	62
Additions to intangible assets	(491)	(668)
Cash acquired in Merger Transaction	0	681
Proceeds from dispositions	1,913	622
Reimbursement of capital expenditures	0	212
Other	(102)	(63)
Net cash used in investing activities	(3,072)	(8,034)
Financing activities
Net change in short-term borrowings	(196)	705
Net change in commercial paper and credit facility draws	(2,358)	956
Debenture and term note issues, net of issue costs	3,537	7,176
Debenture and term note repayments	(3,757)	(4,446)
Sale of noncontrolling interest in subsidiaries	1,289	0
Purchase of interest in consolidated subsidiary	0	(227)
Contributions from noncontrolling interests	23	498
Distributions to noncontrolling interests	(637)	(714)
Contributions from redeemable noncontrolling interests	62	614
Distributions to redeemable noncontrolling interests	(264)	(180)
Common shares issued	17	22
Preference share dividends	(268)	(246)
Common share dividends	(2,254)	(2,077)
Other	(5)	0
Net cash provided by/(used in) financing activities	(4,811)	2,081
Effect of translation of foreign denominated cash and cash equivalents and restricted cash	23	(77)
Net increase/(decrease) in cash and cash equivalents and restricted cash	139	(715)
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	$ 726	$ 847

CONSOLIDATED STATEMENTS OF FINA

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION - CAD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Current assets
Cash and cash equivalents	$ 643	$ 480
Restricted cash	83	107
Accounts receivable and other	5,668	7,053
Accounts receivable from affiliates	75	47
Inventory	1,362	1,528
Total current assets	7,831	9,215
Property, plant and equipment, net	90,679	90,711
Long-term investments	15,983	16,911
Deferred amounts and other assets	10,638	6,442
Intangible assets, net	3,273	3,267
Goodwill	33,477	34,457
Deferred income taxes	1,342	1,090
Total assets	163,223	162,093
Current liabilities
Short-term borrowings	1,251	1,444
Accounts payable and other	7,599	9,518
Accounts payable to affiliates	190	157
Interest payable	611	634
Current portion of long-term debt	3,516	2,871
Total current liabilities	13,167	14,624
Long-term debt	58,707	60,865
Other long-term liabilities	9,090	7,510
Deferred income taxes	10,040	9,295
Total liabilities	91,004	92,294
Contingencies (Note 14)
Redeemable noncontrolling interests	4,321	4,067
Share capital
Preference shares	7,747	7,747
Common shares (1,794 and 1,695 outstanding at September 30, 2018 and December 31, 2017, respectively)	51,944	50,737
Additional paid-in capital	4,346	3,194
Deficit	(3,718)	(2,468)
Accumulated other comprehensive income/(loss) (Note 9)	570	(973)
Reciprocal shareholding	(102)	(102)
Total Enbridge Inc. shareholders’ equity	60,787	58,135
Noncontrolling interests	7,111	7,597
Total equity	67,898	65,732
Total liabilities and equity	$ 163,223	$ 162,093

CONSOLIDATED STATEMENTS OF FI_2

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION (Parenthetical) - shares shares in Millions	Sep. 30, 2018	Dec. 31, 2017
Statement of Financial Position [Abstract]
Common shares, outstanding (in shares)	1,794	1,695

BASIS OF PRESENTATION

BASIS OF PRESENTATION	9 Months Ended
	Sep. 30, 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. ("we", "our", "us" and "Enbridge") 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 included in our Annual Report on Form 10-K, except for the adoption of new standards (Note 2) . 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. Certain comparative figures in our Consolidated Statement of Cash Flows have been reclassified to conform to the current year's presentation. In addition, activities for the nine months ended September 30, 2017 relating to distributions to noncontrolling interests in relation to the stock-for-stock merger transaction on February 27, 2017 between Enbridge and Spectra Energy Corp (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	9 Months Ended
	Sep. 30, 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 or United States Tax Reform) enacted by the United States federal government on December 22, 2017. The amendments in this accounting update allowed a reclassification from accumulated other comprehensive income (AOCI) to retained earnings for stranded tax effects resulting from the TCJA. The amendments eliminated the stranded tax effects recognized as a result of the reduction of the historical United States federal corporate income tax rate to the newly enacted United States federal corporate income tax rate. The adoption of this accounting update did not have a material impact on our consolidated financial statements. Clarifying Guidance on the Application of Modification Accounting on Stock Compensation Effective January 1, 2018, we adopted ASU 2017-09 and applied the standard on a prospective basis. The new standard was issued to clarify the scope of modification accounting. Under the new guidance, modification accounting is required for all changes to share-based payment awards, unless all of the following conditions are met: 1) there is no change to the fair value of the award, 2) the vesting conditions have not changed, and 3) the classification of the award as an equity instrument or a debt instrument has not changed. The adoption of this accounting update did not, and is not expected to have a material impact on our consolidated financial statements. Improving the Presentation of Net Periodic Benefit Cost related to Defined Benefit Plans Effective January 1, 2018, we adopted ASU 2017-07 which was issued primarily to improve the income statement presentation of the components of net periodic pension cost and net periodic postretirement benefit cost for an entity’s sponsored defined benefit pension and other postretirement plans. Upon adoption of this accounting update, our Consolidated Statements of Earnings presents the current service cost within Operating and administrative expenses and the other components of net benefit cost within Other income/(expense). Previously, all components of net benefit cost were presented within Operating and administrative expenses. In addition, only the service cost component of net benefit cost will be capitalized on a prospective basis. The adoption of this accounting update did not, and is not expected to have a material impact on our consolidated financial statements. Clarifying Guidance on Derecognition and Partial Sales of Nonfinancial Assets Effective January 1, 2018, we adopted ASU 2017-05 on a modified retrospective basis. The new standard clarifies the scope provisions of nonfinancial assets and how to allocate consideration to each distinct asset, and amends the guidance for derecognition of a distinct nonfinancial asset in partial sale transactions. The adoption of this accounting update did not have a material impact on our consolidated financial statements. Clarifying the Presentation of Restricted Cash in the Statement of Cash Flows Effective January 1, 2018, we adopted ASU 2016-18 on a retrospective basis. The new standard clarifies guidance on the classification and presentation of changes in restricted cash and restricted cash equivalents within the statement of cash flows. The amendments require that changes in restricted cash and restricted cash equivalents be included within cash and cash equivalents when reconciling the opening and closing period amounts shown on the statement of cash flows. For current and comparative periods, we amended the presentation in the Consolidated Statements of Cash Flows to include restricted cash and restricted cash equivalents with cash and cash equivalents. Simplifying Cash Flow Classification Effective January 1, 2018, we adopted ASU 2016-15 on a retrospective basis. The new standard reduces diversity in practice of how certain cash receipts and cash payments are classified in the Consolidated Statements of Cash Flows. The new guidance addresses eight specific presentation issues. We assessed each of the eight specific presentation issues and the adoption of this ASU did not have a material impact on our consolidated financial statements. Recognition and Measurement of Financial Assets and Liabilities Effective January 1, 2018, we adopted ASU 2016-01 on a prospective basis. The new standard addresses certain aspects of recognition, measurement, presentation and disclosure of financial assets and liabilities. Investments in equity securities, excluding equity method and consolidated investments, are no longer classified as trading or available-for-sale securities. All investments in equity securities with readily determinable fair values are classified as investments at fair value through net income. Investments in equity securities without readily determinable fair values are measured using the fair value measurement alternative and are recorded at cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for an identical or similar investment of the same issuer. Investments in equity securities measured using the fair value measurement alternative are reviewed for indicators of impairment each reporting period. Fair value of financial assets and liabilities is measured using the exit price notion. The adoption of this accounting update did not have a material impact on our consolidated financial statements. Revenue from Contracts with Customers Effective January 1, 2018, we adopted ASU 2014-09 on a modified retrospective basis to contracts that were not complete at the date of initial application. The new standard was issued with the intent of significantly enhancing consistency and comparability of revenue recognition practices across entities and industries. The new standard establishes a single, principles-based five-step model to be applied to all contracts with customers and introduces new and enhanced disclosure requirements. It also requires the use of more estimates and judgments than the previous standards . In adopting Accounting Standards Codification (ASC) 606, we applied the practical expedient for contract modifications whereby contracts that were modified before January 1, 2018 were not retrospectively restated. Instead, the aggregate effect of all contract modifications occurring before that time has been reflected when identifying satisfied and unsatisfied performance obligations, determining the transaction price and allocating the transaction price to satisfied and unsatisfied performance obligations. Revenue was previously recognized for a certain contract within the Liquids Pipelines business unit using a formula-based method. Under the new revenue standard, revenue is recognized on a straight-line basis over the term of the agreement in order to reflect the fulfillment of our performance obligation to provide up to a specified volume of pipeline capacity throughout the term of the contract. Certain payments received from customers to offset the cost of constructing assets required to provide services to those customers, referred to as Contributions in Aid of Construction (CIACs) were previously recorded as reductions of property, plant and equipment regardless of whether the amounts were imposed by regulation or arose from negotiations with customers. Under the new revenue standard, CIACs which are negotiated as part of an agreement to provide transportation and other services to a customer are deemed to be advance payments for future services and are recognized as revenue when those future services are provided. Accordingly, negotiated CIACs are accounted for as deferred revenue and recognized as revenue over the term of the associated revenue contract. Amounts which are required to be collected from the customer based on requirements of the regulator continue to be accounted for as reductions of property, plant and equipment. The below table presents the cumulative, immaterial effect of the adoption of ASC 606 on our Consolidated Statement of Financial Position as at January 1, 2018 on each affected financial statement line item. For the three and nine months ended September 30, 2018 , the effect of the adoption of ASC 606 on our Consolidated Statement of Earnings was not material. Balance at December 31, 2017 Adjustments Due to ASC 606 Balance at January 1, 2018 (millions of Canadian dollars) Assets Deferred amounts and other assets 6,442 (170 ) 6,272 Property, plant and equipment, net 90,711 112 90,823 Liabilities and equity Accounts payable and other 9,478 62 9,540 Other long-term liabilities 7,510 66 7,576 Deferred income taxes 9,295 (62 ) 9,233 Redeemable noncontrolling interests 4,067 (38 ) 4,029 Deficit (2,468 ) (86 ) (2,554 ) FUTURE ACCOUNTING POLICY CHANGES Amended Guidance on Cloud Computing Arrangements In August 2018, ASU 2018-15 was issued to provide guidance on the accounting for implementation costs incurred in a cloud computing arrangement (CCA) that is a service contract. The amendment aligns the accounting for costs incurred to implement a CCA that is a service arrangement with the guidance on capitalizing costs associated with developing or obtaining internal-use software. Additionally, ASU 2018-15 specifies that an entity would apply ASC 350-40, Internal-use software, to determine which implementation costs related to a hosting arrangement that is a service contract should be capitalized and which should be expensed. Furthermore, the amendments in the update require capitalized costs be amortized on a straight-line basis generally over the term of the arrangement and presented in the same income statement line as fees paid for the hosting service. The new standard also requires that the balance sheet presentation of capitalized implementation costs to be the same as that of the prepayment of fees related to the hosting arrangement, as well as similar consistency in classifications from a cash flow statement perspective. ASU 2018-15 is effective January 1, 2020 and early adoption is permitted. We are currently assessing the impact of the new standard on our consolidated financial statements. Disclosure Effectiveness In August 2018, the Financial Accounting Standards Board issued two amendments as a part of its disclosure framework project aimed to improve the effectiveness of disclosures in the notes to financial statements. ASU 2018-14 was issued in August 2018 to improve disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. The amendment modifies the current guidance by adding and removing several disclosure requirements while also clarifying the guidance on current disclosure requirements. ASU 2018-14 is effective January 1, 2021 and entities are permitted to adopt the standard early. We are currently assessing the impact of the new standard on our consolidated financial statements. ASU 2018-13 was issued to improve the disclosure requirements for fair value measurements by eliminating and modifying some disclosures, while also adding new disclosures. This update is effective January 1, 2020, however entities are permitted to early adopt the eliminated or modified disclosures. We are currently assessing the impact of the new standard on our consolidated financial statements. Improvements to Accounting for Hedging Activities ASU 2017-12 was issued in August 2017 with the objective of better aligning a company’s risk management activities and the resulting hedge accounting reflected in the financial statements. The amendments allow cash flow hedging of contractually specified components in financial and non-financial items. Under the new guidance, hedge ineffectiveness is no longer required to be measured and hedging instruments’ fair value changes will be recorded in the same income statement line as the hedged item. The ASU also allows the initial quantitative hedge effectiveness assessment to be performed at any time before the end of the quarter in which the hedge is designated. After initial quantitative testing is performed, an ongoing qualitative effectiveness assessment is permitted. The accounting update is effective January 1, 2019, with early adoption permitted, and is to be applied on a modified retrospective basis. 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 will adopt the new standard on January 1, 2019 and we intend to apply the transition practical expedients offered in connection with this update. The election to apply the package of practical expedients allows an entity to not apply the new lease standard to the prior year comparative periods in the year of adoption. Application of the package of practical expedients also permits entities not to reassess a) whether any expired or existing contracts contain leases in accordance with the new guidance, b) lease classifications, and c) whether initial direct costs capitalized under current guidance continue to meet the definition of initial direct costs under the new guidance. 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. In July 2018, ASU 2018-11 was issued to address additional stakeholder concerns regarding the unanticipated costs and complexities associated with the modified retrospective transition method as well as the requirement for lessors to separate components of a contract. Under the new guidance, entities are provided with an additional transition method which allows entities to apply the new standard at the date of adoption and to elect not to recast comparative periods presented. This amendment also provides a practical expedient which allows lessors to combine associated lease and nonlease components within a contract when certain conditions are met. We intend to adopt the new transition option in connection with the adoption of the new lease requirements; however we continue to evaluate the lessor practical expedient to combine lease and nonlease components. We have substantially completed the process of identifying existing lease contracts and are currently performing detailed evaluations of our leases under the new accounting requirements. We believe the most significant change to our financial statements will be the recognition of lease liabilities and right-of-use assets in our statement of financial position for operating leases. We continue to assess the necessary changes to accounting and business processes in order to implement the recognition and disclosure requirements of the new lease standard.

REVENUE

REVENUE	9 Months Ended
	Sep. 30, 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 2,190 979 97 — — — 3,266 Storage and other revenue 31 53 55 — — — 139 Gas gathering and processing revenue — 200 — — — — 200 Gas distribution revenue — — 478 — — — 478 Electricity and transmission revenue — — — 115 — — 115 Commodity sales — 298 — — — — 298 Total revenue from contracts with customers 2,221 1,530 630 115 — — 4,496 Commodity sales — — — — 6,621 — 6,621 Other revenue 1 222 (6 ) 11 2 — (1 ) 228 Intersegment revenue 86 4 4 — 25 (119 ) — Total revenue 2,529 1,528 645 117 6,646 (120 ) 11,345 Liquids Pipelines Gas Transmission and Midstream Gas Distribution Green Power and Transmission Energy Services Eliminations and Other Consolidated Nine months ended (millions of Canadian dollars) Transportation revenue 6,327 2,889 487 — — — 9,703 Storage and other revenue 113 164 173 — — — 450 Gas gathering and processing revenue — 636 — — — — 636 Gas distribution revenue — — 3,260 — — — 3,260 Electricity and transmission revenue — — — 417 — — 417 Commodity sales — 1,630 — — — — 1,630 Total revenue from contracts with customers 6,440 5,319 3,920 417 — — 16,096 Commodity sales — — — — 19,008 — 19,008 Other revenue 1 (308 ) 2 22 6 — (10 ) (288 ) Intersegment revenue 256 8 10 — 106 (380 ) — Total revenue 6,388 5,329 3,952 423 19,114 (390 ) 34,816 1 Includes mark-to-market gains/(losses) from our hedging program. We disaggregate revenue into categories which represent our principal performance obligations within each business segment because these revenue categories represent the most significant revenue streams in each segment and consequently are considered to be the most relevant revenue information for management to consider in evaluating performance. Contract Balances Receivables Contract Assets Contract Liabilities (millions of Canadian dollars) Balance as at January 1, 2018 2,475 290 992 Balance as at September 30, 2018 1,625 267 1,203 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 three and nine months ended September 30, 2018 included in contract liabilities at the beginning of the period is $19 million and $143 million , respectively. Increases in contract liabilities from cash received, net of amounts recognized as revenue during the three and nine months ended September 30, 2018 were $147 million and $345 million , respectively. Performance Obligations Segment Nature of Performance Obligation Liquids Pipelines • Transportation and storage of crude oil 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 • Transportation of NGLs Gas Distribution • Supply and delivery of natural gas • Transportation of natural gas • Storage of natural gas Green Power and Transmission • Generation and transmission of electricity • Delivery of electricity from renewable energy generation facilities There was no material revenue recognized in the three and nine months ended September 30, 2018 from performance obligations satisfied in previous periods. Payment Terms Payments are received monthly from customers under long-term transportation, commodity sales, and gas gathering and processing contracts. Payments from Gas Distribution customers are received on a continuous basis based on established billing cycles. Certain contracts in the United States offshore business provide for us to receive a series of fixed monthly payments (FMPs) for a specified period which is less than the period during which the performance obligations are satisfied. As a result, a portion of the FMPs is recorded as a contract liability. The FMPs are not considered to be a financing arrangement because the payments are scheduled to match the production profiles of offshore oil and gas fields, which generate greater revenue in the initial years of their productive lives. Revenue to be Recognized from Unfulfilled Performance Obligations Total revenue from performance obligations expected to be fulfilled in future periods is $64.7 billion , of which $1.7 billion and $5.8 billion is expected to be recognized during the three months ending December 31, 2018 , and the 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 and are excluded from the amounts for revenue to be recognized in the future from unfulfilled performance obligations above. Variable consideration is excluded from the amounts above due to the uncertainty of the associated consideration, which is generally resolved when actual volumes and prices are determined. For example, we consider interruptible transportation service revenues to be variable revenues since volumes cannot be estimated. Additionally, the effect of escalation on certain tolls which are contractually escalated for inflation has not been reflected in the amounts above as it is not possible to reliably estimate future inflation rates. Revenues for periods extending beyond the current rate settlement term for regulated contracts where the tolls are periodically reset by the regulator are excluded from the amounts above since future tolls remain unknown. Finally, revenues from contracts with customers which have an original expected duration of one year or less are excluded from the amounts above. SIGNIFICANT JUDGMENTS MADE IN RECOGNIZING REVENUE Long-Term Transportation Agreements For long-term transportation agreements, significant judgments pertain to the period over which revenue is recognized and whether the agreement provides for make-up rights for the shippers. Transportation revenue earned from firm contracted capacity arrangements is recognized ratably over the contract period. Transportation revenue from interruptible or volumetric-based arrangements is recognized when services are performed. Estimates of Variable Consideration Revenue from arrangements subject to variable consideration is recognized only to the extent that it is probable that a significant reversal in the amount of cumulative revenue recognized will not occur when the uncertainty associated with the variable consideration is subsequently resolved. Uncertainties associated with variable consideration relate principally to differences between estimated and actual volumes and prices. These uncertainties are resolved each month when actual volumes are sold or transported and actual tolls and prices are determined. Recognition and Measurement of Revenue Liquids Pipelines Gas Transmission and Midstream Gas Distribution Green Power and Transmission Energy Services Consolidated Three months ended (millions of Canadian dollars) Revenue from products transferred at a point in time 1 — 298 20 — — 318 Revenue from products and services transferred over time 2 2,221 1,232 610 115 — 4,178 Total revenue from contracts with customers 2,221 1,530 630 115 — 4,496 Liquids Pipelines Gas Transmission and Midstream Gas Distribution Green Power and Transmission Energy Services Consolidated Nine months ended (millions of Canadian dollars) Revenue from products transferred at a point in time 1 — 1,630 65 — — 1,695 Revenue from products and services transferred over time 2 6,440 3,689 3,855 417 — 14,401 Total revenue from contracts with customers 6,440 5,319 3,920 417 — 16,096 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	9 Months Ended
	Sep. 30, 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 tables have 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 2,529 1,528 645 117 6,646 (120 ) 11,345 Commodity and gas distribution costs (5 ) (270 ) (137 ) — (6,726 ) 121 (7,017 ) Operating and administrative (790 ) (519 ) (263 ) (38 ) (17 ) (25 ) (1,652 ) Asset impairment — — — (4 ) — — (4 ) Goodwill impairment — (1,019 ) — — — — (1,019 ) Income/(loss) from equity investments 131 262 (12 ) (6 ) 3 — 378 Other income/(expense) 10 (42 ) 23 (18 ) (2 ) 53 24 Earnings/(loss) before interest, income taxes, and depreciation and amortization 1,875 (60 ) 256 51 (96 ) 29 2,055 Depreciation and amortization (799 ) Interest expense (696 ) Income tax expense (347 ) Earnings 213 Capital expenditures 1 651 413 311 6 — (19 ) 1,362 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 2,324 1,862 716 109 4,284 (68 ) 9,227 Commodity and gas distribution costs (5 ) (703 ) (242 ) 1 (4,421 ) 68 (5,302 ) Operating and administrative (770 ) (498 ) (246 ) (42 ) (11 ) (20 ) (1,587 ) Income/(loss) from equity investments 118 162 (3 ) — 3 — 280 Other income/(expense) 36 33 15 — (5 ) 146 225 Earnings/(loss) before interest, income taxes, and depreciation and amortization 1,703 856 240 68 (150 ) 126 2,843 Depreciation and amortization (848 ) Interest expense (653 ) Income tax expense (327 ) Earnings 1,015 Capital expenditures 1 529 1,052 302 64 — 22 1,969 Liquids Pipelines Gas Transmission and Midstream Gas Distribution Green Power and Transmission Energy Services Eliminations and Other Consolidated Nine months ended (millions of Canadian dollars) Revenues 6,388 5,329 3,952 423 19,114 (390 ) 34,816 Commodity and gas distribution costs (14 ) (1,481 ) (1,969 ) — (18,965 ) 392 (22,037 ) Operating and administrative (2,251 ) (1,560 ) (782 ) (104 ) (50 ) (182 ) (4,929 ) Asset impairment (154 ) (913 ) — (4 ) — (5 ) (1,076 ) Goodwill impairment — (1,019 ) — — — — (1,019 ) Income/(loss) from equity investments 399 699 (5 ) (27 ) 10 — 1,076 Other income/(expense) (15 ) 25 66 (2 ) (1 ) (183 ) (110 ) Earnings/(loss) before interest, income taxes, and depreciation and amortization 4,353 1,080 1,262 286 108 (368 ) 6,721 Depreciation and amortization (2,452 ) Interest expense (2,042 ) Income tax expense (177 ) Earnings 2,050 Capital expenditures 1 1,776 2,105 733 30 — (11 ) 4,633 Liquids Pipelines Gas Transmission and Midstream Gas Distribution Green Power and Transmission Energy Services Eliminations and Other Consolidated Nine months ended (millions of Canadian dollars) Revenues 6,722 5,051 3,322 386 16,272 (264 ) 31,489 Commodity and gas distribution costs (13 ) (2,053 ) (1,740 ) 4 (16,251 ) 268 (19,785 ) Operating and administrative (2,214 ) (1,305 ) (676 ) (123 ) (34 ) (432 ) (4,784 ) Income from equity investments 312 427 10 2 5 (4 ) 752 Other income/(expense) 33 143 21 1 (3 ) 244 439 Earnings/(loss) before interest, income taxes, and depreciation and amortization 4,840 2,263 937 270 (11 ) (188 ) 8,111 Depreciation and amortization (2,388 ) Interest expense (1,704 ) Income tax expense (818 ) Earnings 3,201 Capital expenditures 1 1,723 3,081 794 293 1 90 5,982 1 Includes allowance for equity funds used during construction.

EARNINGS PER COMMON SHARE

EARNINGS PER COMMON SHARE	9 Months Ended
	Sep. 30, 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 and nine months ended September 30, 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 Nine months ended 2018 2017 2018 2017 (number of common shares in millions) Weighted average shares outstanding 1,705 1,635 1,695 1,482 Effect of dilutive options 3 7 4 8 Diluted weighted average shares outstanding 1,708 1,642 1,699 1,490 For the three months ended September 30, 2018 and 2017 , 21,081,642 and 12,917,175 , respectively, anti-dilutive stock options with a weighted average exercise price of $52.17 and $56.79 , respectively, were excluded from the diluted earnings per common share calculation. For the nine months ended September 30, 2018 and 2017 , 27,069,810 and 13,293,044 , respectively, anti-dilutive stock options with a weighted average exercise price of $50.37 and $57.50 , respectively, were excluded from the diluted earnings per common share calculation.

AQUISITIONS AND DISPOSITIONS

AQUISITIONS AND DISPOSITIONS	9 Months Ended
	Sep. 30, 2018
Discontinued Operations and Disposal Groups [Abstract]
AQUISITIONS AND DISPOSITIONS	ACQUISITIONS AND DISPOSITIONS ASSETS HELD FOR SALE Canadian Natural Gas Gathering and Processing Businesses On July 4, 2018 , we entered into agreements to sell our Canadian natural gas gathering and processing businesses to Brookfield Infrastructure Partners L.P. and its institutional partners for a cash purchase price of approximately $4.3 billion , subject to customary closing adjustments. Separate agreements were entered into for those facilities currently governed by provincial regulations and those governed by federal regulations (collectively, Canadian Natural Gas Gathering and Processing Businesses assets) . On October 1, 2018, we closed t he sale of the provincially regulated facilities for proceeds of approximately $2.5 billion . These assets were included within our Gas Transmission and Midstream segment. The sale of the federally regulated facilities is expected to close in mid-2019 for proceeds of approximately $1.8 billion . During the third quarter of 2018, we classified the Canadian Natural Gas Gathering and Processing Businesses assets as held for sale. As these assets represented a portion of a reporting unit, we allocated a portion of the goodwill of the reporting unit to these assets using a relative fair value approach. As a result of the goodwill allocation, the carrying value of Canadian Natural Gas Gathering and Processing Businesses assets is greater than the sale price consideration less the cost to sell. Therefore, we recorded a goodwill impairment of $1,019 million on the Consolidated Statements of Earnings for the three and nine months ended September 30, 2018 . Further, the held for sale classification represented a triggering event and required us to perform a goodwill impairment test for the related reporting unit. The results of the test did not indicate any additional goodwill impairment. Line 10 Crude Oil Pipeline In the first quarter of 2018, we satisfied the condition as set out in our agreements for the sale of our Line 10 crude oil pipeline (Line 10), which originates near Hamilton, Ontario and terminates at West Seneca, New York. Our subsidiaries, Enbridge Pipelines Inc. and Enbridge Energy Partners, L.P. (EEP), own the Canadian and United States portions of Line 10, respectively, and the related assets are included in our Liquids Pipeline segment. We expect to close the sale of Line 10 within one year, subject to regulatory approval and certain closing conditions. As such, during the first quarter of 2018, we classified Line 10 assets as held for sale and measured them at the lower of their carrying value or fair value less costs to sell, which resulted in a loss of $154 million ( $95 million after-tax attributable to us) included within Asset impairment on the Consolidated Statements of Earnings for the nine months ended September 30, 2018 . The table below summarizes the presentation of net assets held for sale in our Consolidated Statements of Financial Position: September 30, 2018 December 31, 2017 (millions of Canadian dollars) Accounts receivable and other (current assets held for sale) 154 424 Deferred amounts and other assets (long-term assets held for sale) 1 4,841 1,190 Accounts payable and other (current liabilities held for sale) (70 ) (315 ) Other long-term liabilities (long-term liabilities held for sale) 2 (430 ) (34 ) Net assets held for sale 4,495 1,265 1 Included within Deferred amounts and other assets at September 30, 2018, is property, plant and equipment of $4.1 billion and goodwill of $482 million . Included within Deferred amounts and other assets at December 31, 2017, is property, plant and equipment of $1.1 billion . 2 Included within Other long-term liabilities at September 30, 2018 are deferred tax liabilities of $329 million . DISPOSITIONS Renewable Assets On August 1, 2018, we closed the sale of a 49% interest in all of our Canadian renewable assets , a 49% interest in two United States renewable assets and 49% of our interest in the Hohe See Offshore wind farm and its subsequent expansion, both concurrently under construction in Germany, (collectively, the Renewable Assets) to the Canada Pension Plan Investment Board (CPPIB). Total cash proceeds from the transaction were $1.75 billion . In addition, CPPIB will fund their pro-rata share of the remaining capital expenditures on the Hohe See Offshore wind project. We will maintain a 51% interest in the Renewable Assets and will continue to manage, operate and provide administrative services for these assets. A loss on disposal of $20 million ( €14 million ) was included in Other income/(expense) in the Consolidated Statements of Earnings for the sale of 49% of our interest in the Hohe See Offshore wind farm and its subsequent expansion. Subsequent to the sale, the remaining interests in these assets continue to be accounted for as an equity method investment, and are a part of our Green Power and Transmission segment. Gains of $62 million and $17 million ( US$13 million ) were included in Additional paid-in capital in the Consolidated Statements of Financial Position for the sale of 49% interest in the Canadian and United States renewable assets, respectively. Subsequent to the sale, because we maintained a controlling interest, these assets continue to be consolidated and are a part of our Green Power and Transmission segment. In addition, we recognized noncontrolling interests in our Consolidated Statements of Financial Position as at September 30, 2018 to reflect the interests that we do not hold (Note 10) . Also, a deferred income tax recovery of $267 million ( $196 million attributable to us) was recorded in the nine months ended September 30, 2018 as a result of the agreement entered into during the second quarter of 2018 for the Renewable Assets (Note 12) . In connection with our sale of the Renewable Assets, we have new consolidated and unconsolidated variable interest entities (VIEs) (Note 7) . Midcoast Operating, L.P. On August 1, 2018, our indirect subsidiary, Enbridge (U.S.) Inc. closed the sale of Midcoast Operating, L.P. and its subsidiaries (collectively, MOLP) to AL Midcoast Holdings, LLC (an affiliate of ArcLight Capital Partners, LLC) for total cash proceeds of $1.4 billion ( US$1.1 billion ) . A loss on disposal of $74 million ( US$57 million ) was included in Other income/(expense) in the Consolidated Statements of Earnings. MOLP conducted our United States natural gas and natural gas liquids gathering, processing, transportation and marketing businesses, and was a part of our Gas Transmission and Midstream segment. Upon closing of the sale, we also recorded a liability of $387 million (US $298 million) for future volume commitments retained by us. The associated loss is included in the loss on disposal of $74 million discussed above. As at September 30, 2018 , $ 75 million (US $58 million) and $306 million (US $237 million) were included in Accounts payable and other and Other long-term liabilities, respectively, on the Consolidated Statements of Financial Position. In the second quarter of 2018, our equity method investment in the Texas Express NGL pipeline system, together with the MOLP assets that have been held for sale since December 31, 2017, also met the conditions for assets held for sale. The $447 million carrying value of Texas Express NGL pipeline system equity investment and an allocated goodwill of $262 million , were included within the disposal group as at June 30, 2018 and subsequently disposed on August 1, 2018. In the first quarter of 2018, as a result of entering into a definitive sales agreement, the fair value of the assets held for sale as at March 31, 2018 were revised based on the sale price. Accordingly, we recorded a loss of $913 million ( $701 million after-tax). This loss has been included within Asset impairment on the Consolidated Statements of Earnings for the nine months ended September 30, 2018 .

VARIABLE INTEREST ENTITIES

VARIABLE INTEREST ENTITIES	9 Months Ended
	Sep. 30, 2018
VARIABLE INTEREST ENTITIES
VARIABLE INTEREST ENTITIES	VARIABLE INTEREST ENTITIES In connection with our sale of the Renewable Assets (Note 6) , we have new consolidated and unconsolidated VIEs. CONSOLIDATED VARIABLE INTEREST ENTITY Enbridge Canadian Renewable LP (ECRLP) To facilitate the sale on August 1, 2018, we and our subsidiaries transferred our Canadian renewable assets to a newly formed partnership, ECRLP. Subsequently, a 49% interest in ECRLP was sold to CPPIB. ECRLP is a VIE as its limited partners do not have substantive kick-out rights or participating rights. Because we have the power to direct the activities of ECRLP, we are exposed to potential losses, and we have the right to receive benefits from ECRLP, we are considered the primary beneficiary. We consolidate the VIE because of our indirect controlling financial interest in the VIE. As at September 30, 2018 , the carrying amounts of total assets and liabilities of ECRLP on our Consolidated Statements of Financial Position were $2.1 billion and $45 million , respectively. The creditors of the VIE do not have recourse to our general credit, other than through nominal assets of the holding company with the general partnership interest. We did not provide any additional financial support to ECRLP during the nine months ended September 30, 2018 . UNCONSOLIDATED VARIABLE INTEREST ENTITY Enbridge Renewable Infrastructure Investments S.a.r.l. (ERII) To facilitate the sale on August 1, 2018, we transferred our interest in the Hohe See Offshore wind farm and its subsequent expansion to a newly formed partnership, ERII. Subsequently, a 49% interest in ERII was sold to CPPIB. ERII is a VIE due to insufficient equity at risk to finance its activities. We are not the primary beneficiary of ERII since the power to direct the activities of ERII that most significantly impact its economic performance is shared. We account for ERII by using the equity method as we retain significant influence through a 51% voting interest in substantive decisions. ERII has a carrying value of $118 million ( €79 million ) at September 30, 2018 , within Long-term investments in our Consolidated Statements of Financial Position. Included within Deferred amounts and other assets in our Consolidated Statements of Financial Position at September 30, 2018 , is a long-term receivable of $416 million ( €277 million ) relating to our loan to a consolidated subsidiary of ERII. The maximum exposure to loss as a result of our involvement with ERII is $534 million ( €356 million ), which is equal to the long-term investment carrying value plus the outstanding receivable discussed above. OTHER Sabal Trail Transmission, LLC Spectra Energy Partners, LP (SEP) owns a 50% interest in Sabal Trail Transmission, LLC (Sabal Trail), a joint venture that operates a pipeline originating in Alabama that transports natural gas to Florida and has been classified as a variable interest entity. On April 30, 2018, Sabal Trail issued US$500 million in aggregate principal amount of 4.246% senior notes due in 2028 , US$600 million in aggregate principal amount of 4.682% senior notes due in 2038 and US$400 million in aggregate principal amount of 4.832% senior notes due in 2048. Sabal Trail distributed net proceeds from the offering to the members as a partial reimbursement of construction and development costs incurred by the members. The net distribution made to SEP was US$744 million and was used to pay down indebtedness and is included within Distributions from equity investments in excess of cumulative earnings on the Consolidated Statement of Cash Flows for the nine months ended September 30, 2018 . These events triggered reconsideration and as a result, it was concluded that Sabal Trail was no longer a VIE as at June 30, 2018 due to sufficient equity at risk to finance its activities.

DEBT

DEBT	9 Months Ended
	Sep. 30, 2018
Debt Disclosure [Abstract]
DEBT	DEBT CREDIT FACILITIES The following table provides details of our committed credit facilities as at September 30, 2018 : September 30, 2018 Maturity Total Facilities Draws 1 Available (millions of Canadian dollars) Enbridge Inc. 2019-2023 5,602 2,330 3,272 Enbridge (U.S.) Inc. 2019 1,829 — 1,829 Enbridge Energy Partners, L.P. 2 2019-2022 3,167 2,210 957 Enbridge Gas Distribution Inc. (EGD) 2019-2020 1,017 779 238 Enbridge Income Fund 2020 1,500 9 1,491 Enbridge Pipelines Inc. 2020 3,000 1,214 1,786 Spectra Energy Partners, LP 3 2022 3,232 2,153 1,079 Union Gas Limited (Union Gas) 2021 700 481 219 Total committed credit facilities 20,047 9,176 10,871 1 Includes facility draws, letters of credit and commercial paper issuances that are back-stopped by credit facilities. 2 Includes $239 million (US $185 million ) of commitments that expire in 2020. 3 Includes $435 million (US $336 million ) of commitments that expire in 2021. During the second quarter of 2018, Enbridge (U.S.) Inc. terminated a US$500 million credit facility, which was scheduled to mature in 2019, and repaid drawn amounts. In addition, an unutilized Enbridge US$100 million credit facility expired. During the first quarter of 2018, Enbridge terminated a US$650 million credit facility, which was scheduled to mature in 2019, and repaid drawn amounts. In addition, Enbridge (U.S.) Inc. terminated an unutilized US$950 million credit facility, which was scheduled 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 acquired in conjunction with the Merger Transaction and was scheduled to mature in 2021. In addition to the committed credit facilities noted above, we maintain $790 million of uncommitted demand credit facilities, of which $564 million were unutilized as at September 30, 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 scheduled to mature from 2019 to 2023. As at September 30, 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 $7,534 million and $10,055 million , respectively, were 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 nine months ended September 30, 2018 , we completed the following long-term debt issuances: Company Issue Date Principal Amount (millions of Canadian dollars, unless otherwise stated) Enbridge Inc. March 2018 Fixed-to-floating rate subordinated notes due 2078 1 US$850 April 2018 Fixed-to-floating rate subordinated notes due 2078 2 $750 April 2018 Fixed-to-floating rate subordinated notes due 2078 3 US$600 Spectra Energy Partners, LP 4 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 Notes mature in 60 years and are callable on or after year 10 . For the initial 10 years, the notes carry a fixed interest rate of 6.625% . Subsequently, the interest rate will be set to equal the Canadian Dollar Offered Rate plus a margin of 432 basis points from years 10 to 30 , and a margin of 507 basis points from years 30 to 60 . 3 Notes mature in 60 years and are callable on or after year five . For the initial five years, the notes carry a fixed interest rate of 6.375% . Subsequently, the interest rate will be set to equal the three-month LIBOR plus a margin of 359 basis points from years five to 10 , a margin of 384 basis points from years 10 to 25 , and a margin of 459 basis points from years 25 to 60 . 4 Issued through Texas Eastern Transmission, LP, a wholly-owned operating subsidiary of SEP. LONG-TERM DEBT REPAYMENTS During the nine months ended September 30, 2018 , we completed the following long-term debt repayments : Company Retirement/Repayment Date Principal Amount Cash Consideration 1 (millions of Canadian dollars, unless otherwise stated) Enbridge Energy Partners, L.P. April 2018 6.50% senior notes US$400 Enbridge Pipelines (Southern Lights) L.L.C June 2018 3.98% medium-term notes due June 2040 US$20 Enbridge Southern Lights LP January 2018 4.01% medium-term notes due June 2040 $9 July 2018 4.01% medium-term notes due June 2040 $8 Midcoast Energy Partners, L.P. Redemption 2 July 2018 3.56% senior notes due September 2019 US$75 US$76 July 2018 4.04% senior notes due September 2021 US$175 US$182 July 2018 4.42% senior notes due September 2024 US$150 US$161 Spectra Energy Capital, LLC Repurchase via Tender Offer 2 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 2 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 Repayment April 2018 6.20% senior notes US$272 July 2018 6.75% senior notes US$118 Spectra Energy Partners, LP September 2018 2.95% senior notes US$500 Union Gas Limited April 2018 5.35% medium-term notes $200 August 2018 8.75% debenture $125 Westcoast Energy Inc. May 2018 6.90% senior secured notes $13 May 2018 4.34% senior secured notes $4 September 2018 8.50% debenture $150 1 Cash consideration disclosed for repayments where the cash paid differs from the principal amount. 2 The loss on debt extinguishment of $64 million ( US$50 million ), net of a fair value adjustment recorded upon completion of the Merger Transaction , was reported within Interest expense in the Consolidated Statements of Earnings. SUBORDINATED TERM NOTES As at September 30, 2018 and December 31, 2017 , our fixed-to-floating subordinated term notes had a principal value of $7,053 million and $4,344 million, respectively. FAIR VALUE ADJUSTMENT As at September 30, 2018 , the net fair value adjustment for total debt assumed in the Merger Transaction was $975 million . During the three and nine months ended September 30, 2018 , the amortization of the fair value adjustment, recorded as a reduction to Interest expense in the Consolidated Statements of Earnings, was $23 million and $112 million , respectively. 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 September 30, 2018 , we were in compliance with all debt covenants.

COMPONENTS OF ACCUMULATED OTHER

COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME	9 Months Ended
	Sep. 30, 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 AOCI attributable to our common shareholders for the nine months ended September 30, 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 as at January 1, 2018 (644 ) (139 ) 77 10 (277 ) (973 ) Other comprehensive income/(loss) retained in AOCI 167 (232 ) 1,495 (8 ) — 1,422 Other comprehensive (income)/loss reclassified to earnings Interest rate contracts 1 92 — — — — 92 Commodity contracts 2 (1 ) — — — — (1 ) Foreign exchange contracts 3 6 — — — — 6 Other contracts 4 10 — — — — 10 Amortization of pension and OPEB actuarial loss and prior service costs 5 — — — — 36 36 274 (232 ) 1,495 (8 ) 36 1,565 Tax impact Income tax on amounts retained in AOCI (26 ) 32 — 9 — 15 Income tax on amounts reclassified to earnings (29 ) — — — (8 ) (37 ) (55 ) 32 — 9 (8 ) (22 ) Balance as at September 30, 2018 (425 ) (339 ) 1,572 11 (249 ) 570 Cash Flow Hedges Net Investment Hedges Cumulative Translation Adjustment Equity Investees Pension and OPEB Adjustment Total (millions of Canadian dollars) Balance as at January 1, 2017 (746 ) (629 ) 2,700 37 (304 ) 1,058 Other comprehensive income/(loss) retained in AOCI 29 496 (2,616 ) (4 ) — (2,095 ) Other comprehensive (income)/loss reclassified to earnings Interest rate contracts 1 104 — — — — 104 Commodity contracts 2 (5 ) — — — — (5 ) Foreign exchange contracts 3 (2 ) — — — — (2 ) Other contracts 4 (3 ) — — — — (3 ) Amortization of pension and OPEB actuarial loss and prior service costs 5 — — — — 21 21 123 496 (2,616 ) (4 ) 21 (1,980 ) Tax impact Income tax on amounts retained in AOCI (9 ) 9 — 13 — 13 Income tax on amounts reclassified to earnings (34 ) — — — (8 ) (42 ) (43 ) 9 — 13 (8 ) (29 ) Balance as at September 30, 2017 (666 ) (124 ) 84 46 (291 ) (951 ) 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	9 Months Ended
	Sep. 30, 2018
Noncontrolling Interest [Abstract]
NONCONTROLLING INTERESTS	NONCONTROLLING INTERESTS Renewable Assets On August 1, 2018, we closed the sale of a 49% interest in all of our Canadian renewable assets and a 49% interest in two United States renewable assets to CPPIB (Note 6) . As a result, we recorded an increase in Noncontrolling interests, Additional paid-in capital and Deferred income tax liabilities of $1,183 million , $79 million and $27 million , respectively, for the nine months ended September 30, 2018 . For the three months ended September 30, 2018 , CPPIB's distributions and allocation of earnings were not proportionate to its ownership. SEP Incentive Distribution Rights As at December 31, 2017, we collectively owned a 75% ownership interest in SEP, together with 100% of SEP's incentive distribution rights (IDRs). On January 22, 2018, Enbridge and SEP announced the execution of a definitive agreement, resulting in us converting all of our IDRs and general partner economic interests in SEP into 172.5 million newly issued SEP common units. As part of the transaction, all of the IDRs were eliminated. We now hold a non-economic general partner interest in SEP and own approximately 403 million SEP common units, representing approximately 83% of SEP's outstanding common units. As a result of this restructuring, we recorded a decrease in Noncontrolling interests of $1.5 billion and increases in Additional paid-in capital and Deferred income tax liabilities of $1.1 billion and $333 million , respectively, for the nine months ended September 30, 2018 .

RISK MANAGEMENT AND FINANCIAL I

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS	9 Months Ended
	Sep. 30, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS	RISK MANAGEMENT AND FINANCIAL INSTRUMENTS MARKET RISKS 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 risks). Formal risk management policies, processes and systems have been designed to mitigate these risks. The following summarizes the types of market risks to which we are exposed and the risk management instruments used to mitigate them. We use a combination of qualifying and non-qualifying derivative instruments to manage the risks noted below. Foreign Exchange Risk We generate certain revenues, incur expenses, and hold a number of investments and subsidiaries that are denominated in currencies other than Canadian dollars. As a result, our earnings, cash flows and OCI are exposed to fluctuations resulting from foreign exchange rate variability. We employ financial derivative instruments to hedge foreign currency denominated earnings exposure. A combination of qualifying and non-qualifying derivative instruments are used to hedge anticipated foreign currency denominated revenues and expenses, and to manage variability in cash flows. We hedge certain net investments in United States dollar denominated investments and subsidiaries using foreign currency derivatives and United States dollar denominated debt. Interest Rate Risk Our earnings and cash flows are exposed to short-term interest rate variability due to the regular repricing of our variable rate debt, primarily commercial paper. Pay fixed-receive floating interest rate swaps are used to hedge against the effect of future interest rate movements. We have implemented a program to significantly mitigate the impact of short-term interest rate volatility on interest expense via execution of floating to fixed interest rate swaps with an average swap rate of 2.6% . As a result of the Merger Transaction, we are exposed to changes in the fair value of fixed rate debt that arise as a result of the changes in market interest rates. Pay floating-receive fixed interest rate swaps are used to hedge against future changes to the fair value of fixed rate debt. We have assumed a program within our subsidiaries to mitigate the impact of fluctuations in the fair value of fixed rate debt via execution of fixed to floating interest rate swaps with an average swap rate of 2.2% . Our earnings and cash flows are also exposed to variability in longer term interest rates ahead of anticipated fixed rate term debt issuances. Forward starting interest rate swaps are used to hedge against the effect of future interest rate movements. We have assumed a program within some of our subsidiaries to mitigate our exposure to long-term interest rate variability on select forecast term debt issuances via execution of floating to fixed interest rate swaps with an average swap rate of 3.1% . We also monitor our debt portfolio mix of fixed and variable rate debt instruments to 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 has been required to purchase for itself and most of its customers to meet greenhouse gas compliance obligations under the Ontario Cap and Trade program. 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 amounts in the event of these specific circumstances. All amounts are presented gross in the Consolidated Statements of Financial Position. September 30, 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 — 1 — 66 67 (49 ) 18 Interest rate contracts 49 — — — 49 (3 ) 46 Commodity contracts 1 — — 119 120 (85 ) 35 50 1 — 185 236 (137 ) 99 Deferred amounts and other assets Foreign exchange contracts 4 — — 39 43 (29 ) 14 Interest rate contracts 42 — — — 42 (1 ) 41 Commodity contracts 18 — — 12 30 (25 ) 5 Other contracts — — — — — — — 64 — — 51 115 (55 ) 60 Accounts payable and other Foreign exchange contracts (5 ) — — (371 ) (376 ) 49 (327 ) Interest rate contracts (50 ) — (9 ) (179 ) (238 ) 3 (235 ) Commodity contracts — — — (411 ) (411 ) 85 (326 ) Other contracts (1 ) — — (8 ) (9 ) — (9 ) (56 ) — (9 ) (969 ) (1,034 ) 137 (897 ) Other long-term liabilities Foreign exchange contracts — (11 ) — (1,420 ) (1,431 ) 29 (1,402 ) Interest rate contracts (6 ) — (3 ) — (9 ) 1 (8 ) Commodity contracts — — — (153 ) (153 ) 25 (128 ) Other contracts (3 ) — — (4 ) (7 ) — (7 ) (9 ) (11 ) (3 ) (1,577 ) (1,600 ) 55 (1,545 ) Total net derivative asset/(liability) Foreign exchange contracts (1 ) (10 ) — (1,686 ) (1,697 ) — (1,697 ) Interest rate contracts 35 — (12 ) (179 ) (156 ) — (156 ) Commodity contracts 19 — — (433 ) (414 ) — (414 ) Other contracts (4 ) — — (12 ) (16 ) — (16 ) 49 (10 ) (12 ) (2,310 ) (2,283 ) — (2,283 ) 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. September 30, 2018 2018 2019 2020 2021 2022 Thereafter 1 Foreign exchange contracts - United States dollar forwards - purchase (millions of United States dollars) 591 3 1 — — — Foreign exchange contracts - United States dollar forwards - sell (millions of United States dollars) 1,592 3,262 3,258 1,689 1,676 3,489 Foreign exchange contracts - British pound (GBP) forwards - sell (millions of GBP) — 89 25 27 28 149 Foreign exchange contracts - Euro forwards - purchase (millions of Euro) 42 208 — — — — Foreign exchange contracts - Euro forwards - sell (millions of Euro) — — 23 94 94 698 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) 1,251 3,590 1,093 121 93 203 Interest rate contracts - long-term receive fixed rate (millions of Canadian dollars) 145 582 555 188 102 — Interest rate contracts - long-term debt pay fixed rate (millions of Canadian dollars) 1,894 600 573 — — — Equity contracts (millions of Canadian dollars) 40 35 20 — — — Commodity contracts - natural gas (billions of cubic feet) (7 ) (58 ) (18 ) (5 ) 8 1 Commodity contracts - crude oil (millions of barrels) 4 4 — — — — Commodity contracts - NGL (millions of barrels) (1 ) — — — — — Commodity contracts - power (megawatt per hour) (MW/H)) 57 64 66 (3 ) (43 ) (43 ) 1 As at September 30, 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 Nine months ended 2018 2017 2018 2017 (millions of Canadian dollars) Amount of unrealized gain/(loss) recognized in OCI Cash flow hedges Foreign exchange contracts (16 ) (2 ) 2 (1 ) Interest rate contracts 69 83 186 28 Commodity contracts 4 — 1 12 Other contracts (10 ) 16 (12 ) 1 Net investment hedges Foreign exchange contracts 25 148 36 221 72 245 213 261 Amount of (gain)/loss reclassified from AOCI to earnings (effective portion) Foreign exchange contracts 1 7 (3 ) 4 (104 ) Interest rate contracts 2 40 50 124 134 Commodity contracts 3 — — (1 ) (4 ) Other contracts 4 7 (11 ) 10 2 54 36 137 28 Amount of (gain)/loss reclassified from AOCI to earnings (ineffective portion and amount excluded from effectiveness testing) Interest rate contracts 2 (2 ) (1 ) 8 5 (2 ) (1 ) 8 5 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 $1 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 27 months as at September 30, 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. The difference in the amounts, if any, represents hedge ineffectiveness. Three months ended Nine months ended 2018 2017 2018 2017 (millions of Canadian dollars) Unrealized gain/(loss) on derivative 3 — (9 ) (1 ) Unrealized gain/(loss) on hedged item (3 ) 1 8 2 Realized gain/(loss) on derivative (3 ) 2 (4 ) 2 Realized gain/(loss) on hedged item 3 (2 ) 4 (2 ) Non-Qualifying Derivatives The following table presents the unrealized gains and losses associated with changes in the fair value of our non-qualifying derivatives: Three months ended Nine months ended 2018 2017 2018 2017 (millions of Canadian dollars) Foreign exchange contracts 1 345 503 (356 ) 1,210 Interest rate contracts 2 6 (1 ) 4 13 Commodity contracts 3 (113 ) (160 ) 43 22 Other contracts 4 (8 ) 3 (10 ) (2 ) Total unrealized derivative fair value gain/(loss), net 230 345 (319 ) 1,243 1 For the respective nine months ended periods, reported within Transportation and other services revenues ( 2018 - $346 million loss ; 2017 - $726 million gain ) and Other income/(expense) ( 2018 - $10 million loss ; 2017 - $484 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 nine months ended periods, reported within Transportation and other services revenues ( 2018 - $16 million loss ; 2017 - $85 million loss ), Commodity sales ( 2018 - $42 million loss ; 2017 - $67 million gain ), Commodity costs ( 2018 - $90 million gain ; 2017 - $22 million gain ) and Operating and administrative expense ( 2018 - $11 million gain ; 2017 - $18 million gain ) 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 September 30, 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: September 30, December 31, (millions of Canadian dollars) Canadian financial institutions 28 82 United States financial institutions 44 19 European financial institutions 79 145 Asian financial institutions 31 2 Other 1 86 137 268 385 1 Other is comprised of commodity clearing house and physical natural gas and crude oil counterparties. As at September 30, 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 September 30, 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: September 30, 2018 Level 1 Level 2 Level 3 Total Gross Derivative Instruments (millions of Canadian dollars) Financial assets Current derivative assets Foreign exchange contracts — 67 — 67 Interest rate contracts — 49 — 49 Commodity contracts 1 9 110 120 1 125 110 236 Long-term derivative assets Foreign exchange contracts — 43 — 43 Interest rate contracts — 42 — 42 Commodity contracts — 5 25 30 Other contracts — — — — — 90 25 115 Financial liabilities Current derivative liabilities Foreign exchange contracts — (376 ) — (376 ) Interest rate contracts — (238 ) — (238 ) Commodity contracts (11 ) (37 ) (363 ) (411 ) Other contracts — (9 ) — (9 ) (11 ) (660 ) (363 ) (1,034 ) Long-term derivative liabilities Foreign exchange contracts — (1,431 ) — (1,431 ) Interest rate contracts — (9 ) — (9 ) Commodity contracts — (11 ) (142 ) (153 ) Other contracts — (7 ) — (7 ) — (1,458 ) (142 ) (1,600 ) Total net financial liabilities Foreign exchange contracts — (1,697 ) — (1,697 ) Interest rate contracts — (156 ) — (156 ) Commodity contracts (10 ) (34 ) (370 ) (414 ) Other contracts — (16 ) — (16 ) (10 ) (1,903 ) (370 ) (2,283 ) 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: September 30, 2018 Fair Value Unobservable Input Minimum Price Maximum Price Weighted Average Price Unit of Measurement (fair value in millions of Canadian dollars) Commodity contracts - financial 1 Natural gas (6 ) Forward gas price 2.34 4.93 3.36 $/mmbtu 2 Crude (38 ) Forward crude price 51.62 178.33 76.45 $/barrel NGL (2 ) Forward NGL price 1.39 1.67 1.58 $/gallon Power (93 ) Forward power price 26.01 72.42 47.74 $/MW/H Commodity contracts - physical 1 Natural gas (83 ) Forward gas price 1.08 6.24 2.75 $/mmbtu 2 Crude (141 ) Forward crude price 29.79 123.22 81.29 $/barrel NGL (7 ) Forward NGL price 0.71 2.16 1.13 $/gallon (370 ) 1 Financial and physical forward commodity contracts are valued using a market approach valuation technique. 2 One million British thermal units (mmbtu). If adjusted, the significant unobservable inputs disclosed in the table above would have a direct impact on the fair value of our Level 3 derivative instruments. The significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments include forward commodity prices and, for option contracts, price volatility. Changes in forward commodity prices could result in significantly different fair values for our Level 3 derivatives. Changes in price volatility would change the value of the option contracts. Generally, a change in the estimate of forward commodity prices is unrelated to a change in the estimate of price volatility. Changes in net fair value of derivative assets and liabilities classified as Level 3 in the fair value hierarchy were as follows: Nine 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 (146 ) 1 Included in OCI — 11 Settlements 163 83 Level 3 net derivative liability at end of period (370 ) (200 ) 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 September 30, 2018 or 2017 . FAIR VALUE OF OTHER FINANCIAL INSTRUMENTS Our other long-term investments in other entities with no actively quoted prices are classified as Fair Value Measurement Alternative (FVMA) investments and are recorded at cost less impairment. The carrying value of FVMA other long-term investments totaled $100 million and $99 million as at September 30, 2018 and December 31, 2017 , respectively. We have Restricted long-term investments held in trust totaling $307 million and $267 million as at September 30, 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 $370 million and $371 million as at September 30, 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 September 30, 2018 and December 31, 2017 , the fair value of this preferred share investment approximates its face value of $580 million . As at September 30, 2018 and December 31, 2017 , our long-term debt had a carrying value of $62.5 billion and $64.0 billion , respectively, before debt issuance costs and a fair value of $63.8 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 September 30, 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 nine months ended September 30, 2018 and 2017 , we recognized an unrealized foreign exchange loss of $209 million and a gain of $350 million , respectively, on the translation of United States dollar denominated debt and an unrealized gain on the change in fair value of our outstanding foreign exchange forward contracts of $36 million and $222 million , respectively, in OCI. During the nine months ended September 30, 2018 and 2017 , we recognized realized losses of $46 million and $128 million , respectively, in OCI associated with the settlement of foreign exchange forward contracts and recognized a realized loss of $13 million and a realized gain of $52 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 nine months ended September 30, 2018 and 2017 .

INCOME TAXES

INCOME TAXES	9 Months Ended
	Sep. 30, 2018
Income Tax Disclosure [Abstract]
INCOME TAXES	INCOME TAXES The effective income tax rates for the three months ended September 30, 2018 and 2017 were an expense of 62.0% and 24.4% , respectively, and for the nine months ended September 30, 2018 and 2017 were an expense of 7.9% and 20.4% , respectively. The period-over-period change in the effective income tax rate is due to the effects of rate-regulated accounting for income taxes, the goodwill impairment recorded in the third quarter of 2018, and other permanent items relative to the decrease in earnings for the three and nine months ended September 30, 2018 , the impact of the United States federal corporate income tax rate reduction enacted in 2017, and a recovery in the second quarter of 2018 related to a change in assertion for the investment in Canadian renewable assets due to the sale which resulted in the recognition of previously unrecognized tax basis. Refer to Note 6. Acquisitions and Dispositions - Dispositions - Renewable Assets for further discussion of the transaction. 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 for the three and nine months ended September 30, 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	9 Months Ended
	Sep. 30, 2018
Retirement Benefits [Abstract]
PENSION AND OTHER POSTRETIREMENT BENEFITS	PENSION AND OTHER POSTRETIREMENT BENEFITS Three months ended Nine months ended 2018 2017 2018 2017 (millions of Canadian dollars) Service cost 46 65 162 181 Interest cost 39 46 126 125 Expected return on plan assets (72 ) (71 ) (234 ) (195 ) Amortization of actuarial loss 6 11 21 28 Plan curtailments — — 2 — Amortization of prior service costs — (1 ) (1 ) (1 ) Net periodic benefit costs 19 50 76 138

CONTINGENCIES

CONTINGENCIES	9 Months Ended
	Sep. 30, 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. SIMPLIFICATION OF CORPORATE STRUCTURE During the third quarter of 2018, we entered into definitive agreements with SEP, EEP, EEM and Enbridge Income Fund Holdings Inc. (ENF) under which we will acquire all of the outstanding public securities of the respective sponsored vehicles. The security holders of SEP, EEP, EEM and ENF will be entitled to receive 1.111 , 0.335 , 0.335 and 0.735 of our common shares for each of their own outstanding public securities, respectively. In addition, ENF shareholders will also receive cash payment of no less than $0.45 for each outstanding public common share of ENF, which amounts to approximately $63 million in the minimum. Closing of the transactions is subject to security holder approvals, customary closing conditions and other conditions, as applicable to the specific sponsored vehicle.

SUBSEQUENT EVENTS

SUBSEQUENT EVENTS	9 Months Ended
	Sep. 30, 2018
Subsequent Events [Abstract]
SUBSEQUENT EVENTS	SUBSEQUENT EVENTS On October 1, 2018, we closed t he sale of the provincially regulated facilities of our Canadian natural gas gathering and processing businesses for proceeds of approximately $2.5 billion . Refer to Note 6. Acquisitions and Dispositions for further discussion of the transaction. The BC Pipeline T-South System moves natural gas into the Pacific Northwest region and is comprised of two pipelines that run parallel to each other. On October 9, 2018, a rupture occurred on one of the natural gas transmission pipelines within this system and ignited at the site. Both pipelines were shut down following the rupture. Following various assessments and National Energy Board approval, both of the pipelines were returned to service at a lower operating pressure. We are cooperating and working with the Transportation Safety Board in its investigation to determine the cause of the incident.

CHANGES IN ACCOUNTING POLICIES

CHANGES IN ACCOUNTING POLICIES (Policies)	9 Months Ended
	Sep. 30, 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 or United States Tax Reform) enacted by the United States federal government on December 22, 2017. The amendments in this accounting update allowed a reclassification from accumulated other comprehensive income (AOCI) to retained earnings for stranded tax effects resulting from the TCJA. The amendments eliminated the stranded tax effects recognized as a result of the reduction of the historical United States federal corporate income tax rate to the newly enacted United States federal corporate income tax rate. The adoption of this accounting update did not have a material impact on our consolidated financial statements. Clarifying Guidance on the Application of Modification Accounting on Stock Compensation Effective January 1, 2018, we adopted ASU 2017-09 and applied the standard on a prospective basis. The new standard was issued to clarify the scope of modification accounting. Under the new guidance, modification accounting is required for all changes to share-based payment awards, unless all of the following conditions are met: 1) there is no change to the fair value of the award, 2) the vesting conditions have not changed, and 3) the classification of the award as an equity instrument or a debt instrument has not changed. The adoption of this accounting update did not, and is not expected to have a material impact on our consolidated financial statements. Improving the Presentation of Net Periodic Benefit Cost related to Defined Benefit Plans Effective January 1, 2018, we adopted ASU 2017-07 which was issued primarily to improve the income statement presentation of the components of net periodic pension cost and net periodic postretirement benefit cost for an entity’s sponsored defined benefit pension and other postretirement plans. Upon adoption of this accounting update, our Consolidated Statements of Earnings presents the current service cost within Operating and administrative expenses and the other components of net benefit cost within Other income/(expense). Previously, all components of net benefit cost were presented within Operating and administrative expenses. In addition, only the service cost component of net benefit cost will be capitalized on a prospective basis. The adoption of this accounting update did not, and is not expected to have a material impact on our consolidated financial statements. Clarifying Guidance on Derecognition and Partial Sales of Nonfinancial Assets Effective January 1, 2018, we adopted ASU 2017-05 on a modified retrospective basis. The new standard clarifies the scope provisions of nonfinancial assets and how to allocate consideration to each distinct asset, and amends the guidance for derecognition of a distinct nonfinancial asset in partial sale transactions. The adoption of this accounting update did not have a material impact on our consolidated financial statements. Clarifying the Presentation of Restricted Cash in the Statement of Cash Flows Effective January 1, 2018, we adopted ASU 2016-18 on a retrospective basis. The new standard clarifies guidance on the classification and presentation of changes in restricted cash and restricted cash equivalents within the statement of cash flows. The amendments require that changes in restricted cash and restricted cash equivalents be included within cash and cash equivalents when reconciling the opening and closing period amounts shown on the statement of cash flows. For current and comparative periods, we amended the presentation in the Consolidated Statements of Cash Flows to include restricted cash and restricted cash equivalents with cash and cash equivalents. Simplifying Cash Flow Classification Effective January 1, 2018, we adopted ASU 2016-15 on a retrospective basis. The new standard reduces diversity in practice of how certain cash receipts and cash payments are classified in the Consolidated Statements of Cash Flows. The new guidance addresses eight specific presentation issues. We assessed each of the eight specific presentation issues and the adoption of this ASU did not have a material impact on our consolidated financial statements. Recognition and Measurement of Financial Assets and Liabilities Effective January 1, 2018, we adopted ASU 2016-01 on a prospective basis. The new standard addresses certain aspects of recognition, measurement, presentation and disclosure of financial assets and liabilities. Investments in equity securities, excluding equity method and consolidated investments, are no longer classified as trading or available-for-sale securities. All investments in equity securities with readily determinable fair values are classified as investments at fair value through net income. Investments in equity securities without readily determinable fair values are measured using the fair value measurement alternative and are recorded at cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for an identical or similar investment of the same issuer. Investments in equity securities measured using the fair value measurement alternative are reviewed for indicators of impairment each reporting period. Fair value of financial assets and liabilities is measured using the exit price notion. The adoption of this accounting update did not have a material impact on our consolidated financial statements. Revenue from Contracts with Customers Effective January 1, 2018, we adopted ASU 2014-09 on a modified retrospective basis to contracts that were not complete at the date of initial application. The new standard was issued with the intent of significantly enhancing consistency and comparability of revenue recognition practices across entities and industries. The new standard establishes a single, principles-based five-step model to be applied to all contracts with customers and introduces new and enhanced disclosure requirements. It also requires the use of more estimates and judgments than the previous standards . In adopting Accounting Standards Codification (ASC) 606, we applied the practical expedient for contract modifications whereby contracts that were modified before January 1, 2018 were not retrospectively restated. Instead, the aggregate effect of all contract modifications occurring before that time has been reflected when identifying satisfied and unsatisfied performance obligations, determining the transaction price and allocating the transaction price to satisfied and unsatisfied performance obligations. Revenue was previously recognized for a certain contract within the Liquids Pipelines business unit using a formula-based method. Under the new revenue standard, revenue is recognized on a straight-line basis over the term of the agreement in order to reflect the fulfillment of our performance obligation to provide up to a specified volume of pipeline capacity throughout the term of the contract. Certain payments received from customers to offset the cost of constructing assets required to provide services to those customers, referred to as Contributions in Aid of Construction (CIACs) were previously recorded as reductions of property, plant and equipment regardless of whether the amounts were imposed by regulation or arose from negotiations with customers. Under the new revenue standard, CIACs which are negotiated as part of an agreement to provide transportation and other services to a customer are deemed to be advance payments for future services and are recognized as revenue when those future services are provided. Accordingly, negotiated CIACs are accounted for as deferred revenue and recognized as revenue over the term of the associated revenue contract. Amounts which are required to be collected from the customer based on requirements of the regulator continue to be accounted for as reductions of property, plant and equipment. The below table presents the cumulative, immaterial effect of the adoption of ASC 606 on our Consolidated Statement of Financial Position as at January 1, 2018 on each affected financial statement line item. For the three and nine months ended September 30, 2018 , the effect of the adoption of ASC 606 on our Consolidated Statement of Earnings was not material. Balance at December 31, 2017 Adjustments Due to ASC 606 Balance at January 1, 2018 (millions of Canadian dollars) Assets Deferred amounts and other assets 6,442 (170 ) 6,272 Property, plant and equipment, net 90,711 112 90,823 Liabilities and equity Accounts payable and other 9,478 62 9,540 Other long-term liabilities 7,510 66 7,576 Deferred income taxes 9,295 (62 ) 9,233 Redeemable noncontrolling interests 4,067 (38 ) 4,029 Deficit (2,468 ) (86 ) (2,554 ) FUTURE ACCOUNTING POLICY CHANGES Amended Guidance on Cloud Computing Arrangements In August 2018, ASU 2018-15 was issued to provide guidance on the accounting for implementation costs incurred in a cloud computing arrangement (CCA) that is a service contract. The amendment aligns the accounting for costs incurred to implement a CCA that is a service arrangement with the guidance on capitalizing costs associated with developing or obtaining internal-use software. Additionally, ASU 2018-15 specifies that an entity would apply ASC 350-40, Internal-use software, to determine which implementation costs related to a hosting arrangement that is a service contract should be capitalized and which should be expensed. Furthermore, the amendments in the update require capitalized costs be amortized on a straight-line basis generally over the term of the arrangement and presented in the same income statement line as fees paid for the hosting service. The new standard also requires that the balance sheet presentation of capitalized implementation costs to be the same as that of the prepayment of fees related to the hosting arrangement, as well as similar consistency in classifications from a cash flow statement perspective. ASU 2018-15 is effective January 1, 2020 and early adoption is permitted. We are currently assessing the impact of the new standard on our consolidated financial statements. Disclosure Effectiveness In August 2018, the Financial Accounting Standards Board issued two amendments as a part of its disclosure framework project aimed to improve the effectiveness of disclosures in the notes to financial statements. ASU 2018-14 was issued in August 2018 to improve disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. The amendment modifies the current guidance by adding and removing several disclosure requirements while also clarifying the guidance on current disclosure requirements. ASU 2018-14 is effective January 1, 2021 and entities are permitted to adopt the standard early. We are currently assessing the impact of the new standard on our consolidated financial statements. ASU 2018-13 was issued to improve the disclosure requirements for fair value measurements by eliminating and modifying some disclosures, while also adding new disclosures. This update is effective January 1, 2020, however entities are permitted to early adopt the eliminated or modified disclosures. We are currently assessing the impact of the new standard on our consolidated financial statements. Improvements to Accounting for Hedging Activities ASU 2017-12 was issued in August 2017 with the objective of better aligning a company’s risk management activities and the resulting hedge accounting reflected in the financial statements. The amendments allow cash flow hedging of contractually specified components in financial and non-financial items. Under the new guidance, hedge ineffectiveness is no longer required to be measured and hedging instruments’ fair value changes will be recorded in the same income statement line as the hedged item. The ASU also allows the initial quantitative hedge effectiveness assessment to be performed at any time before the end of the quarter in which the hedge is designated. After initial quantitative testing is performed, an ongoing qualitative effectiveness assessment is permitted. The accounting update is effective January 1, 2019, with early adoption permitted, and is to be applied on a modified retrospective basis. 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 will adopt the new standard on January 1, 2019 and we intend to apply the transition practical expedients offered in connection with this update. The election to apply the package of practical expedients allows an entity to not apply the new lease standard to the prior year comparative periods in the year of adoption. Application of the package of practical expedients also permits entities not to reassess a) whether any expired or existing contracts contain leases in accordance with the new guidance, b) lease classifications, and c) whether initial direct costs capitalized under current guidance continue to meet the definition of initial direct costs under the new guidance. 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. In July 2018, ASU 2018-11 was issued to address additional stakeholder concerns regarding the unanticipated costs and complexities associated with the modified retrospective transition method as well as the requirement for lessors to separate components of a contract. Under the new guidance, entities are provided with an additional transition method which allows entities to apply the new standard at the date of adoption and to elect not to recast comparative periods presented. This amendment also provides a practical expedient which allows lessors to combine associated lease and nonlease components within a contract when certain conditions are met. We intend to adopt the new transition option in connection with the adoption of the new lease requirements; however we continue to evaluate the lessor practical expedient to combine lease and nonlease components. We have substantially completed the process of identifying existing lease contracts and are currently performing detailed evaluations of our leases under the new accounting requirements. We believe the most significant change to our financial statements will be the recognition of lease liabilities and right-of-use assets in our statement of financial position for operating leases. We continue to assess the necessary changes to accounting and business processes in order to implement the recognition and disclosure requirements of the new lease standard.

CHANGES IN ACCOUNTING POLICIE_2

CHANGES IN ACCOUNTING POLICIES (Tables)	9 Months Ended
	Sep. 30, 2018
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
Schedule of New Accounting Pronouncements and Changes in Accounting Principles	The below table presents the cumulative, immaterial effect of the adoption of ASC 606 on our Consolidated Statement of Financial Position as at January 1, 2018 on each affected financial statement line item. For the three and nine months ended September 30, 2018 , the effect of the adoption of ASC 606 on our Consolidated Statement of Earnings was not material. Balance at December 31, 2017 Adjustments Due to ASC 606 Balance at January 1, 2018 (millions of Canadian dollars) Assets Deferred amounts and other assets 6,442 (170 ) 6,272 Property, plant and equipment, net 90,711 112 90,823 Liabilities and equity Accounts payable and other 9,478 62 9,540 Other long-term liabilities 7,510 66 7,576 Deferred income taxes 9,295 (62 ) 9,233 Redeemable noncontrolling interests 4,067 (38 ) 4,029 Deficit (2,468 ) (86 ) (2,554 ) Liquids Pipelines Gas Transmission and Midstream Gas Distribution Green Power and Transmission Energy Services Consolidated Three months ended (millions of Canadian dollars) Revenue from products transferred at a point in time 1 — 298 20 — — 318 Revenue from products and services transferred over time 2 2,221 1,232 610 115 — 4,178 Total revenue from contracts with customers 2,221 1,530 630 115 — 4,496 Liquids Pipelines Gas Transmission and Midstream Gas Distribution Green Power and Transmission Energy Services Consolidated Nine months ended (millions of Canadian dollars) Revenue from products transferred at a point in time 1 — 1,630 65 — — 1,695 Revenue from products and services transferred over time 2 6,440 3,689 3,855 417 — 14,401 Total revenue from contracts with customers 6,440 5,319 3,920 417 — 16,096 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)	9 Months Ended
	Sep. 30, 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 2,190 979 97 — — — 3,266 Storage and other revenue 31 53 55 — — — 139 Gas gathering and processing revenue — 200 — — — — 200 Gas distribution revenue — — 478 — — — 478 Electricity and transmission revenue — — — 115 — — 115 Commodity sales — 298 — — — — 298 Total revenue from contracts with customers 2,221 1,530 630 115 — — 4,496 Commodity sales — — — — 6,621 — 6,621 Other revenue 1 222 (6 ) 11 2 — (1 ) 228 Intersegment revenue 86 4 4 — 25 (119 ) — Total revenue 2,529 1,528 645 117 6,646 (120 ) 11,345 Liquids Pipelines Gas Transmission and Midstream Gas Distribution Green Power and Transmission Energy Services Eliminations and Other Consolidated Nine months ended (millions of Canadian dollars) Transportation revenue 6,327 2,889 487 — — — 9,703 Storage and other revenue 113 164 173 — — — 450 Gas gathering and processing revenue — 636 — — — — 636 Gas distribution revenue — — 3,260 — — — 3,260 Electricity and transmission revenue — — — 417 — — 417 Commodity sales — 1,630 — — — — 1,630 Total revenue from contracts with customers 6,440 5,319 3,920 417 — — 16,096 Commodity sales — — — — 19,008 — 19,008 Other revenue 1 (308 ) 2 22 6 — (10 ) (288 ) Intersegment revenue 256 8 10 — 106 (380 ) — Total revenue 6,388 5,329 3,952 423 19,114 (390 ) 34,816 1 Includes mark-to-market gains/(losses) from our hedging program.
Contract with Customer, Asset and Liability	Receivables Contract Assets Contract Liabilities (millions of Canadian dollars) Balance as at January 1, 2018 2,475 290 992 Balance as at September 30, 2018 1,625 267 1,203
Schedule of New Accounting Pronouncements and Changes in Accounting Principles	The below table presents the cumulative, immaterial effect of the adoption of ASC 606 on our Consolidated Statement of Financial Position as at January 1, 2018 on each affected financial statement line item. For the three and nine months ended September 30, 2018 , the effect of the adoption of ASC 606 on our Consolidated Statement of Earnings was not material. Balance at December 31, 2017 Adjustments Due to ASC 606 Balance at January 1, 2018 (millions of Canadian dollars) Assets Deferred amounts and other assets 6,442 (170 ) 6,272 Property, plant and equipment, net 90,711 112 90,823 Liabilities and equity Accounts payable and other 9,478 62 9,540 Other long-term liabilities 7,510 66 7,576 Deferred income taxes 9,295 (62 ) 9,233 Redeemable noncontrolling interests 4,067 (38 ) 4,029 Deficit (2,468 ) (86 ) (2,554 ) Liquids Pipelines Gas Transmission and Midstream Gas Distribution Green Power and Transmission Energy Services Consolidated Three months ended (millions of Canadian dollars) Revenue from products transferred at a point in time 1 — 298 20 — — 318 Revenue from products and services transferred over time 2 2,221 1,232 610 115 — 4,178 Total revenue from contracts with customers 2,221 1,530 630 115 — 4,496 Liquids Pipelines Gas Transmission and Midstream Gas Distribution Green Power and Transmission Energy Services Consolidated Nine months ended (millions of Canadian dollars) Revenue from products transferred at a point in time 1 — 1,630 65 — — 1,695 Revenue from products and services transferred over time 2 6,440 3,689 3,855 417 — 14,401 Total revenue from contracts with customers 6,440 5,319 3,920 417 — 16,096 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)	9 Months Ended
	Sep. 30, 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 2,529 1,528 645 117 6,646 (120 ) 11,345 Commodity and gas distribution costs (5 ) (270 ) (137 ) — (6,726 ) 121 (7,017 ) Operating and administrative (790 ) (519 ) (263 ) (38 ) (17 ) (25 ) (1,652 ) Asset impairment — — — (4 ) — — (4 ) Goodwill impairment — (1,019 ) — — — — (1,019 ) Income/(loss) from equity investments 131 262 (12 ) (6 ) 3 — 378 Other income/(expense) 10 (42 ) 23 (18 ) (2 ) 53 24 Earnings/(loss) before interest, income taxes, and depreciation and amortization 1,875 (60 ) 256 51 (96 ) 29 2,055 Depreciation and amortization (799 ) Interest expense (696 ) Income tax expense (347 ) Earnings 213 Capital expenditures 1 651 413 311 6 — (19 ) 1,362 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 2,324 1,862 716 109 4,284 (68 ) 9,227 Commodity and gas distribution costs (5 ) (703 ) (242 ) 1 (4,421 ) 68 (5,302 ) Operating and administrative (770 ) (498 ) (246 ) (42 ) (11 ) (20 ) (1,587 ) Income/(loss) from equity investments 118 162 (3 ) — 3 — 280 Other income/(expense) 36 33 15 — (5 ) 146 225 Earnings/(loss) before interest, income taxes, and depreciation and amortization 1,703 856 240 68 (150 ) 126 2,843 Depreciation and amortization (848 ) Interest expense (653 ) Income tax expense (327 ) Earnings 1,015 Capital expenditures 1 529 1,052 302 64 — 22 1,969 Liquids Pipelines Gas Transmission and Midstream Gas Distribution Green Power and Transmission Energy Services Eliminations and Other Consolidated Nine months ended (millions of Canadian dollars) Revenues 6,388 5,329 3,952 423 19,114 (390 ) 34,816 Commodity and gas distribution costs (14 ) (1,481 ) (1,969 ) — (18,965 ) 392 (22,037 ) Operating and administrative (2,251 ) (1,560 ) (782 ) (104 ) (50 ) (182 ) (4,929 ) Asset impairment (154 ) (913 ) — (4 ) — (5 ) (1,076 ) Goodwill impairment — (1,019 ) — — — — (1,019 ) Income/(loss) from equity investments 399 699 (5 ) (27 ) 10 — 1,076 Other income/(expense) (15 ) 25 66 (2 ) (1 ) (183 ) (110 ) Earnings/(loss) before interest, income taxes, and depreciation and amortization 4,353 1,080 1,262 286 108 (368 ) 6,721 Depreciation and amortization (2,452 ) Interest expense (2,042 ) Income tax expense (177 ) Earnings 2,050 Capital expenditures 1 1,776 2,105 733 30 — (11 ) 4,633 Liquids Pipelines Gas Transmission and Midstream Gas Distribution Green Power and Transmission Energy Services Eliminations and Other Consolidated Nine months ended (millions of Canadian dollars) Revenues 6,722 5,051 3,322 386 16,272 (264 ) 31,489 Commodity and gas distribution costs (13 ) (2,053 ) (1,740 ) 4 (16,251 ) 268 (19,785 ) Operating and administrative (2,214 ) (1,305 ) (676 ) (123 ) (34 ) (432 ) (4,784 ) Income from equity investments 312 427 10 2 5 (4 ) 752 Other income/(expense) 33 143 21 1 (3 ) 244 439 Earnings/(loss) before interest, income taxes, and depreciation and amortization 4,840 2,263 937 270 (11 ) (188 ) 8,111 Depreciation and amortization (2,388 ) Interest expense (1,704 ) Income tax expense (818 ) Earnings 3,201 Capital expenditures 1 1,723 3,081 794 293 1 90 5,982 1 Includes allowance for equity funds used during construction.

EARNINGS PER COMMON SHARE (Tabl

EARNINGS PER COMMON SHARE (Tables)	9 Months Ended
	Sep. 30, 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 Nine months ended 2018 2017 2018 2017 (number of common shares in millions) Weighted average shares outstanding 1,705 1,635 1,695 1,482 Effect of dilutive options 3 7 4 8 Diluted weighted average shares outstanding 1,708 1,642 1,699 1,490

AQUISITIONS AND DISPOSITIONS (T

AQUISITIONS AND DISPOSITIONS (Tables)	9 Months Ended
	Sep. 30, 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: September 30, 2018 December 31, 2017 (millions of Canadian dollars) Accounts receivable and other (current assets held for sale) 154 424 Deferred amounts and other assets (long-term assets held for sale) 1 4,841 1,190 Accounts payable and other (current liabilities held for sale) (70 ) (315 ) Other long-term liabilities (long-term liabilities held for sale) 2 (430 ) (34 ) Net assets held for sale 4,495 1,265 1 Included within Deferred amounts and other assets at September 30, 2018, is property, plant and equipment of $4.1 billion and goodwill of $482 million . Included within Deferred amounts and other assets at December 31, 2017, is property, plant and equipment of $1.1 billion . 2 Included within Other long-term liabilities at September 30, 2018 are deferred tax liabilities of $329 million .

DEBT (Tables)

DEBT (Tables)	9 Months Ended
	Sep. 30, 2018
Debt Disclosure [Abstract]
Schedule of credit facilities	The following table provides details of our committed credit facilities as at September 30, 2018 : September 30, 2018 Maturity Total Facilities Draws 1 Available (millions of Canadian dollars) Enbridge Inc. 2019-2023 5,602 2,330 3,272 Enbridge (U.S.) Inc. 2019 1,829 — 1,829 Enbridge Energy Partners, L.P. 2 2019-2022 3,167 2,210 957 Enbridge Gas Distribution Inc. (EGD) 2019-2020 1,017 779 238 Enbridge Income Fund 2020 1,500 9 1,491 Enbridge Pipelines Inc. 2020 3,000 1,214 1,786 Spectra Energy Partners, LP 3 2022 3,232 2,153 1,079 Union Gas Limited (Union Gas) 2021 700 481 219 Total committed credit facilities 20,047 9,176 10,871 1 Includes facility draws, letters of credit and commercial paper issuances that are back-stopped by credit facilities. 2 Includes $239 million (US $185 million ) of commitments that expire in 2020. 3 Includes $435 million (US $336 million ) of commitments that expire in 2021.
Schedule of Long-term Debt Instruments	During the nine months ended September 30, 2018 , we completed the following long-term debt issuances: Company Issue Date Principal Amount (millions of Canadian dollars, unless otherwise stated) Enbridge Inc. March 2018 Fixed-to-floating rate subordinated notes due 2078 1 US$850 April 2018 Fixed-to-floating rate subordinated notes due 2078 2 $750 April 2018 Fixed-to-floating rate subordinated notes due 2078 3 US$600 Spectra Energy Partners, LP 4 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 Notes mature in 60 years and are callable on or after year 10 . For the initial 10 years, the notes carry a fixed interest rate of 6.625% . Subsequently, the interest rate will be set to equal the Canadian Dollar Offered Rate plus a margin of 432 basis points from years 10 to 30 , and a margin of 507 basis points from years 30 to 60 . 3 Notes mature in 60 years and are callable on or after year five . For the initial five years, the notes carry a fixed interest rate of 6.375% . Subsequently, the interest rate will be set to equal the three-month LIBOR plus a margin of 359 basis points from years five to 10 , a margin of 384 basis points from years 10 to 25 , and a margin of 459 basis points from years 25 to 60 . 4 Issued through Texas Eastern Transmission, LP, a wholly-owned operating subsidiary of SEP.
Schedule of Repayment of Debt	During the nine months ended September 30, 2018 , we completed the following long-term debt repayments : Company Retirement/Repayment Date Principal Amount Cash Consideration 1 (millions of Canadian dollars, unless otherwise stated) Enbridge Energy Partners, L.P. April 2018 6.50% senior notes US$400 Enbridge Pipelines (Southern Lights) L.L.C June 2018 3.98% medium-term notes due June 2040 US$20 Enbridge Southern Lights LP January 2018 4.01% medium-term notes due June 2040 $9 July 2018 4.01% medium-term notes due June 2040 $8 Midcoast Energy Partners, L.P. Redemption 2 July 2018 3.56% senior notes due September 2019 US$75 US$76 July 2018 4.04% senior notes due September 2021 US$175 US$182 July 2018 4.42% senior notes due September 2024 US$150 US$161 Spectra Energy Capital, LLC Repurchase via Tender Offer 2 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 2 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 Repayment April 2018 6.20% senior notes US$272 July 2018 6.75% senior notes US$118 Spectra Energy Partners, LP September 2018 2.95% senior notes US$500 Union Gas Limited April 2018 5.35% medium-term notes $200 August 2018 8.75% debenture $125 Westcoast Energy Inc. May 2018 6.90% senior secured notes $13 May 2018 4.34% senior secured notes $4 September 2018 8.50% debenture $150 1 Cash consideration disclosed for repayments where the cash paid differs from the principal amount. 2 The loss on debt extinguishment of $64 million ( US$50 million ), net of a fair value adjustment recorded upon completion of the Merger Transaction , was reported within Interest expense in the Consolidated Statements of Earnings.

COMPONENTS OF ACCUMULATED OTH_2

COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME (Tables)	9 Months Ended
	Sep. 30, 2018
Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]
Schedule of changes in AOCI attributable to Enbridge Inc. common shareholders	Changes in AOCI attributable to our common shareholders for the nine months ended September 30, 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 as at January 1, 2018 (644 ) (139 ) 77 10 (277 ) (973 ) Other comprehensive income/(loss) retained in AOCI 167 (232 ) 1,495 (8 ) — 1,422 Other comprehensive (income)/loss reclassified to earnings Interest rate contracts 1 92 — — — — 92 Commodity contracts 2 (1 ) — — — — (1 ) Foreign exchange contracts 3 6 — — — — 6 Other contracts 4 10 — — — — 10 Amortization of pension and OPEB actuarial loss and prior service costs 5 — — — — 36 36 274 (232 ) 1,495 (8 ) 36 1,565 Tax impact Income tax on amounts retained in AOCI (26 ) 32 — 9 — 15 Income tax on amounts reclassified to earnings (29 ) — — — (8 ) (37 ) (55 ) 32 — 9 (8 ) (22 ) Balance as at September 30, 2018 (425 ) (339 ) 1,572 11 (249 ) 570 Cash Flow Hedges Net Investment Hedges Cumulative Translation Adjustment Equity Investees Pension and OPEB Adjustment Total (millions of Canadian dollars) Balance as at January 1, 2017 (746 ) (629 ) 2,700 37 (304 ) 1,058 Other comprehensive income/(loss) retained in AOCI 29 496 (2,616 ) (4 ) — (2,095 ) Other comprehensive (income)/loss reclassified to earnings Interest rate contracts 1 104 — — — — 104 Commodity contracts 2 (5 ) — — — — (5 ) Foreign exchange contracts 3 (2 ) — — — — (2 ) Other contracts 4 (3 ) — — — — (3 ) Amortization of pension and OPEB actuarial loss and prior service costs 5 — — — — 21 21 123 496 (2,616 ) (4 ) 21 (1,980 ) Tax impact Income tax on amounts retained in AOCI (9 ) 9 — 13 — 13 Income tax on amounts reclassified to earnings (34 ) — — — (8 ) (42 ) (43 ) 9 — 13 (8 ) (29 ) Balance as at September 30, 2017 (666 ) (124 ) 84 46 (291 ) (951 ) 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 FINANCIAL_2

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (Tables)	9 Months Ended
	Sep. 30, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Summary of the Consolidated Statements of Financial Position location and carrying value of derivative instruments	The following table summarizes the maximum potential settlement amounts in the event of these specific circumstances. All amounts are presented gross in the Consolidated Statements of Financial Position. September 30, 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 — 1 — 66 67 (49 ) 18 Interest rate contracts 49 — — — 49 (3 ) 46 Commodity contracts 1 — — 119 120 (85 ) 35 50 1 — 185 236 (137 ) 99 Deferred amounts and other assets Foreign exchange contracts 4 — — 39 43 (29 ) 14 Interest rate contracts 42 — — — 42 (1 ) 41 Commodity contracts 18 — — 12 30 (25 ) 5 Other contracts — — — — — — — 64 — — 51 115 (55 ) 60 Accounts payable and other Foreign exchange contracts (5 ) — — (371 ) (376 ) 49 (327 ) Interest rate contracts (50 ) — (9 ) (179 ) (238 ) 3 (235 ) Commodity contracts — — — (411 ) (411 ) 85 (326 ) Other contracts (1 ) — — (8 ) (9 ) — (9 ) (56 ) — (9 ) (969 ) (1,034 ) 137 (897 ) Other long-term liabilities Foreign exchange contracts — (11 ) — (1,420 ) (1,431 ) 29 (1,402 ) Interest rate contracts (6 ) — (3 ) — (9 ) 1 (8 ) Commodity contracts — — — (153 ) (153 ) 25 (128 ) Other contracts (3 ) — — (4 ) (7 ) — (7 ) (9 ) (11 ) (3 ) (1,577 ) (1,600 ) 55 (1,545 ) Total net derivative asset/(liability) Foreign exchange contracts (1 ) (10 ) — (1,686 ) (1,697 ) — (1,697 ) Interest rate contracts 35 — (12 ) (179 ) (156 ) — (156 ) Commodity contracts 19 — — (433 ) (414 ) — (414 ) Other contracts (4 ) — — (12 ) (16 ) — (16 ) 49 (10 ) (12 ) (2,310 ) (2,283 ) — (2,283 ) 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. September 30, 2018 2018 2019 2020 2021 2022 Thereafter 1 Foreign exchange contracts - United States dollar forwards - purchase (millions of United States dollars) 591 3 1 — — — Foreign exchange contracts - United States dollar forwards - sell (millions of United States dollars) 1,592 3,262 3,258 1,689 1,676 3,489 Foreign exchange contracts - British pound (GBP) forwards - sell (millions of GBP) — 89 25 27 28 149 Foreign exchange contracts - Euro forwards - purchase (millions of Euro) 42 208 — — — — Foreign exchange contracts - Euro forwards - sell (millions of Euro) — — 23 94 94 698 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) 1,251 3,590 1,093 121 93 203 Interest rate contracts - long-term receive fixed rate (millions of Canadian dollars) 145 582 555 188 102 — Interest rate contracts - long-term debt pay fixed rate (millions of Canadian dollars) 1,894 600 573 — — — Equity contracts (millions of Canadian dollars) 40 35 20 — — — Commodity contracts - natural gas (billions of cubic feet) (7 ) (58 ) (18 ) (5 ) 8 1 Commodity contracts - crude oil (millions of barrels) 4 4 — — — — Commodity contracts - NGL (millions of barrels) (1 ) — — — — — Commodity contracts - power (megawatt per hour) (MW/H)) 57 64 66 (3 ) (43 ) (43 ) 1 As at September 30, 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 difference in the amounts, if any, represents hedge ineffectiveness. Three months ended Nine months ended 2018 2017 2018 2017 (millions of Canadian dollars) Unrealized gain/(loss) on derivative 3 — (9 ) (1 ) Unrealized gain/(loss) on hedged item (3 ) 1 8 2 Realized gain/(loss) on derivative (3 ) 2 (4 ) 2 Realized gain/(loss) on hedged item 3 (2 ) 4 (2 ) 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 Nine months ended 2018 2017 2018 2017 (millions of Canadian dollars) Amount of unrealized gain/(loss) recognized in OCI Cash flow hedges Foreign exchange contracts (16 ) (2 ) 2 (1 ) Interest rate contracts 69 83 186 28 Commodity contracts 4 — 1 12 Other contracts (10 ) 16 (12 ) 1 Net investment hedges Foreign exchange contracts 25 148 36 221 72 245 213 261 Amount of (gain)/loss reclassified from AOCI to earnings (effective portion) Foreign exchange contracts 1 7 (3 ) 4 (104 ) Interest rate contracts 2 40 50 124 134 Commodity contracts 3 — — (1 ) (4 ) Other contracts 4 7 (11 ) 10 2 54 36 137 28 Amount of (gain)/loss reclassified from AOCI to earnings (ineffective portion and amount excluded from effectiveness testing) Interest rate contracts 2 (2 ) (1 ) 8 5 (2 ) (1 ) 8 5 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 Nine months ended 2018 2017 2018 2017 (millions of Canadian dollars) Foreign exchange contracts 1 345 503 (356 ) 1,210 Interest rate contracts 2 6 (1 ) 4 13 Commodity contracts 3 (113 ) (160 ) 43 22 Other contracts 4 (8 ) 3 (10 ) (2 ) Total unrealized derivative fair value gain/(loss), net 230 345 (319 ) 1,243 1 For the respective nine months ended periods, reported within Transportation and other services revenues ( 2018 - $346 million loss ; 2017 - $726 million gain ) and Other income/(expense) ( 2018 - $10 million loss ; 2017 - $484 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 nine months ended periods, reported within Transportation and other services revenues ( 2018 - $16 million loss ; 2017 - $85 million loss ), Commodity sales ( 2018 - $42 million loss ; 2017 - $67 million gain ), Commodity costs ( 2018 - $90 million gain ; 2017 - $22 million gain ) and Operating and administrative expense ( 2018 - $11 million gain ; 2017 - $18 million gain ) 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: September 30, December 31, (millions of Canadian dollars) Canadian financial institutions 28 82 United States financial institutions 44 19 European financial institutions 79 145 Asian financial institutions 31 2 Other 1 86 137 268 385 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: September 30, 2018 Level 1 Level 2 Level 3 Total Gross Derivative Instruments (millions of Canadian dollars) Financial assets Current derivative assets Foreign exchange contracts — 67 — 67 Interest rate contracts — 49 — 49 Commodity contracts 1 9 110 120 1 125 110 236 Long-term derivative assets Foreign exchange contracts — 43 — 43 Interest rate contracts — 42 — 42 Commodity contracts — 5 25 30 Other contracts — — — — — 90 25 115 Financial liabilities Current derivative liabilities Foreign exchange contracts — (376 ) — (376 ) Interest rate contracts — (238 ) — (238 ) Commodity contracts (11 ) (37 ) (363 ) (411 ) Other contracts — (9 ) — (9 ) (11 ) (660 ) (363 ) (1,034 ) Long-term derivative liabilities Foreign exchange contracts — (1,431 ) — (1,431 ) Interest rate contracts — (9 ) — (9 ) Commodity contracts — (11 ) (142 ) (153 ) Other contracts — (7 ) — (7 ) — (1,458 ) (142 ) (1,600 ) Total net financial liabilities Foreign exchange contracts — (1,697 ) — (1,697 ) Interest rate contracts — (156 ) — (156 ) Commodity contracts (10 ) (34 ) (370 ) (414 ) Other contracts — (16 ) — (16 ) (10 ) (1,903 ) (370 ) (2,283 ) 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: September 30, 2018 Fair Value Unobservable Input Minimum Price Maximum Price Weighted Average Price Unit of Measurement (fair value in millions of Canadian dollars) Commodity contracts - financial 1 Natural gas (6 ) Forward gas price 2.34 4.93 3.36 $/mmbtu 2 Crude (38 ) Forward crude price 51.62 178.33 76.45 $/barrel NGL (2 ) Forward NGL price 1.39 1.67 1.58 $/gallon Power (93 ) Forward power price 26.01 72.42 47.74 $/MW/H Commodity contracts - physical 1 Natural gas (83 ) Forward gas price 1.08 6.24 2.75 $/mmbtu 2 Crude (141 ) Forward crude price 29.79 123.22 81.29 $/barrel NGL (7 ) Forward NGL price 0.71 2.16 1.13 $/gallon (370 ) 1 Financial and physical forward commodity contracts are valued using a market approach valuation technique. 2 One million British thermal units (mmbtu).
Schedule of changes in net fair value of derivative assets and liabilities classified as Level 3 in the fair value hierarchy	Changes in net fair value of derivative assets and liabilities classified as Level 3 in the fair value hierarchy were as follows: Nine 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 (146 ) 1 Included in OCI — 11 Settlements 163 83 Level 3 net derivative liability at end of period (370 ) (200 ) 1 Reported within Transportation and other services revenues, Commodity costs and Operating and administrative expense in the Consolidated Statements of Earnings.

PENSION AND OTHER POSTRETIREM_2

PENSION AND OTHER POSTRETIREMENT BENEFITS (Tables)	9 Months Ended
	Sep. 30, 2018
Retirement Benefits [Abstract]
Schedule of net benefit costs recognized	Three months ended Nine months ended 2018 2017 2018 2017 (millions of Canadian dollars) Service cost 46 65 162 181 Interest cost 39 46 126 125 Expected return on plan assets (72 ) (71 ) (234 ) (195 ) Amortization of actuarial loss 6 11 21 28 Plan curtailments — — 2 — Amortization of prior service costs — (1 ) (1 ) (1 ) Net periodic benefit costs 19 50 76 138

BASIS OF PRESENTATION - Narrati

BASIS OF PRESENTATION - Narrative (Details) - CAD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Net cash used in investing activities	$ (3,072)	$ (8,034)
Increase (reduction) to net cash provided by financing activities	$ 4,811	(2,081)
Merger Transaction | Scenario, Adjustment
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Net cash used in investing activities		67
Increase (reduction) to net cash provided by financing activities		$ 67

CHANGES IN ACCOUNTING POLICIE_3

CHANGES IN ACCOUNTING POLICIES (Details) - CAD ($) $ in Millions	Sep. 30, 2018	Jan. 01, 2018	Dec. 31, 2017
Assets
Deferred amounts and other assets	$ 10,638	$ 6,272	$ 6,442
Property, plant and equipment, net	90,679	90,823	90,711
Liabilities and equity
Accounts payable and other	7,599	9,540	9,518
Other long-term liabilities	9,090	7,576	7,510
Deferred income taxes	10,040	9,233	9,295
Redeemable noncontrolling interests	4,321	4,029	4,067
Retained deficit	$ (3,718)	(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			9 Months Ended
	Sep. 30, 2018CAD ($)	Sep. 30, 2018USD ($)	Sep. 30, 2017CAD ($)	Sep. 30, 2018CAD ($)	Sep. 30, 2018USD ($)	Sep. 30, 2017CAD ($)
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	$ 4,496			$ 16,096
Revenues	11,345		$ 9,227	34,816		$ 31,489
Transferred at Point in Time
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	318			1,695
Transferred over Time
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	4,178			14,401
Transportation revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	3,266			9,703
Storage and Other Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	139			450
Gas Gathering and Processing Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	200			636
Gas Distribution Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	478			3,260
Revenues	478		573	3,260		2,783
Electricity and Transmission Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	115			417
Commodity sales
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	298			1,630
Revenue not from contract with customers	6,621			19,008
Revenues	6,919		5,012	20,638		18,498
Other Revenue
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers	228			(288)
Liquids Pipelines
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	2,221			6,440
Liquids Pipelines | Transferred at Point in Time
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0			0
Liquids Pipelines | Transferred over Time
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	2,221			6,440
Gas Transmission and Midstream
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	1,530			5,319
Gas Transmission and Midstream | Transferred at Point in Time
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	298			1,630
Gas Transmission and Midstream | Transferred over Time
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	1,232			3,689
Gas Distribution
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	630			3,920
Gas Distribution | Transferred at Point in Time
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	20			65
Gas Distribution | Transferred over Time
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	610			3,855
Green Power and Transmission
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	115			417
Green Power and Transmission | Transferred at Point in Time
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0			0
Green Power and Transmission | Transferred over Time
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	115			417
Energy Services
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0			0
Energy Services | Transferred at Point in Time
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0			0
Energy Services | Transferred over Time
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0			0
Business segments | Liquids Pipelines
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	2,221			6,440
Revenues	2,529		2,324	6,388		6,722
Business segments | Liquids Pipelines | Transportation revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	2,190			6,327
Business segments | Liquids Pipelines | Storage and Other Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	31			113
Business segments | Liquids Pipelines | Gas Gathering and Processing Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0			0
Business segments | Liquids Pipelines | Gas Distribution Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0			0
Business segments | Liquids Pipelines | Electricity and Transmission Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0			0
Business segments | Liquids Pipelines | Commodity sales
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0			0
Revenue not from contract with customers	0			0
Business segments | Liquids Pipelines | Other Revenue
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers	222			(308)
Business segments | Gas Transmission and Midstream
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	1,530			5,319
Revenues	1,528		1,862	5,329		5,051
Business segments | Gas Transmission and Midstream | Transportation revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	979			2,889
Business segments | Gas Transmission and Midstream | Storage and Other Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	53			164
Business segments | Gas Transmission and Midstream | Gas Gathering and Processing Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	200			636
Business segments | Gas Transmission and Midstream | Gas Distribution Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0			0
Business segments | Gas Transmission and Midstream | Electricity and Transmission Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0			0
Business segments | Gas Transmission and Midstream | Commodity sales
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	298			1,630
Revenue not from contract with customers	0			0
Business segments | Gas Transmission and Midstream | Other Revenue
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers	(6)			2
Business segments | Gas Distribution
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	630			3,920
Revenues	645			3,952
Business segments | Gas Distribution | Transportation revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	97			487
Business segments | Gas Distribution | Storage and Other Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	55			173
Business segments | Gas Distribution | Gas Gathering and Processing Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0			0
Business segments | Gas Distribution | Gas Distribution Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	478			3,260
Business segments | Gas Distribution | Electricity and Transmission Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0			0
Business segments | Gas Distribution | Commodity sales
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0			0
Revenue not from contract with customers	0			0
Business segments | Gas Distribution | Other Revenue
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers	11			22
Business segments | Green Power and Transmission
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	115			417
Revenues	117		109	423		386
Business segments | Green Power and Transmission | Transportation revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0			0
Business segments | Green Power and Transmission | Storage and Other Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0			0
Business segments | Green Power and Transmission | Gas Gathering and Processing Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0			0
Business segments | Green Power and Transmission | Gas Distribution Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0			0
Business segments | Green Power and Transmission | Electricity and Transmission Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	115			417
Business segments | Green Power and Transmission | Commodity sales
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0			0
Revenue not from contract with customers	0			0
Business segments | Green Power and Transmission | Other Revenue
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers	2			6
Business segments | Energy Services
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0			0
Revenues	6,646			19,114
Business segments | Energy Services | Transportation revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0			0
Business segments | Energy Services | Storage and Other Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0			0
Business segments | Energy Services | Gas Gathering and Processing Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0			0
Business segments | Energy Services | Gas Distribution Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0			0
Business segments | Energy Services | Electricity and Transmission Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0			0
Business segments | Energy Services | Commodity sales
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0			0
Revenue not from contract with customers	6,621			19,008
Business segments | Energy Services | Other Revenue
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers	0			0
Intersegment Eliminations
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers	(119)	$ 0		(380)	$ 0
Intersegment Eliminations | Liquids Pipelines
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers	86			256
Intersegment Eliminations | Gas Transmission and Midstream
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers	4			8
Intersegment Eliminations | Gas Distribution
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers	4			10
Intersegment Eliminations | Green Power and Transmission
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers	0			0
Intersegment Eliminations | Energy Services
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers	25			106
Consolidation, Eliminations
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0			0
Revenues	(120)		$ (68)	(390)		$ (264)
Consolidation, Eliminations | Transportation revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0			0
Consolidation, Eliminations | Storage and Other Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0			0
Consolidation, Eliminations | Gas Gathering and Processing Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0			0
Consolidation, Eliminations | Gas Distribution Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0			0
Consolidation, Eliminations | Electricity and Transmission Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0			0
Consolidation, Eliminations | Commodity sales
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0			0
Revenue not from contract with customers	0			0
Consolidation, Eliminations | Other Revenue
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers	$ (1)			$ (10)

REVENUE - Contract Balances (De

REVENUE - Contract Balances (Details) - CAD ($) $ in Millions	Sep. 30, 2018	Jan. 01, 2018
Revenue from Contract with Customer [Abstract]
Accounts receivable, net	$ 1,625	$ 2,475
Contract with customer, asset	267	290
Contract with customer, liability	$ 1,203	$ 992

REVENUE - Narrative (Details)

REVENUE - Narrative (Details) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2018CAD ($)	Sep. 30, 2018CAD ($)
Revenue from Contract with Customer [Abstract]
Revenue recognized	$ 19	$ 143
Increase (decrease) in contract with customers, liability	147	345
Remaining performance obligation	64,700	64,700
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2018-10-01
Revenue from Contract with Customer [Abstract]
Remaining performance obligation	1,700	$ 1,700
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligation, period		1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-10-01
Revenue from Contract with Customer [Abstract]
Remaining performance obligation	$ 5,800	$ 5,800

SEGMENTED INFORMATION (Details)

SEGMENTED INFORMATION (Details) - CAD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Segmented Information
Revenues	$ 11,345	$ 9,227	$ 34,816	$ 31,489
Commodity and gas distribution costs	(7,017)	(5,302)	(22,037)	(19,785)
Operating and administrative	(1,652)	(1,587)	(4,929)	(4,784)
Asset impairment	(4)	0	(1,076)	0
Goodwill impairment (Note 6)	(1,019)	0	(1,019)	0
Income/(loss) from equity investments	378	280	1,076	752
Other	24	225	(110)	439
Earnings/(loss) before interest and income taxes	2,055	2,843	6,721	8,111
Depreciation and amortization	(799)	(848)	(2,452)	(2,388)
Interest expense	(696)	(653)	(2,042)	(1,704)
Income tax recovery/(expense)	(347)	(327)	(177)	(818)
Earnings	213	1,015	2,050	3,201
Capital expenditures	1,362	1,969	4,633	5,982
Consolidation, Eliminations
Segmented Information
Revenues	(120)	(68)	(390)	(264)
Commodity and gas distribution costs	121	68	392	268
Operating and administrative	(25)	(20)	(182)	(432)
Asset impairment	0		(5)
Goodwill impairment (Note 6)	0		0
Income/(loss) from equity investments	0	0	0	(4)
Other	53	146	(183)	244
Earnings/(loss) before interest and income taxes	29	126	(368)	(188)
Capital expenditures	(19)	22	(11)	90
Liquids Pipelines | Business segments
Segmented Information
Revenues	2,529	2,324	6,388	6,722
Commodity and gas distribution costs	(5)	(5)	(14)	(13)
Operating and administrative	(790)	(770)	(2,251)	(2,214)
Asset impairment	0		(154)
Goodwill impairment (Note 6)	0		0
Income/(loss) from equity investments	131	118	399	312
Other	10	36	(15)	33
Earnings/(loss) before interest and income taxes	1,875	1,703	4,353	4,840
Capital expenditures	651	529	1,776	1,723
Gas Transmission and Midstream | Business segments
Segmented Information
Revenues	1,528	1,862	5,329	5,051
Commodity and gas distribution costs	(270)	(703)	(1,481)	(2,053)
Operating and administrative	(519)	(498)	(1,560)	(1,305)
Asset impairment	0		(913)
Goodwill impairment (Note 6)	(1,019)		(1,019)
Income/(loss) from equity investments	262	162	699	427
Other	(42)	33	25	143
Earnings/(loss) before interest and income taxes	(60)	856	1,080	2,263
Capital expenditures	413	1,052	2,105	3,081
Gas Distribution | Business segments
Segmented Information
Revenues	645	716	3,952	3,322
Commodity and gas distribution costs	(137)	(242)	(1,969)	(1,740)
Operating and administrative	(263)	(246)	(782)	(676)
Asset impairment	0		0
Goodwill impairment (Note 6)	0		0
Income/(loss) from equity investments	(12)	(3)	(5)	10
Other	23	15	66	21
Earnings/(loss) before interest and income taxes	256	240	1,262	937
Capital expenditures	311	302	733	794
Green Power and Transmission | Business segments
Segmented Information
Revenues	117	109	423	386
Commodity and gas distribution costs	0	1	0	4
Operating and administrative	(38)	(42)	(104)	(123)
Asset impairment	(4)		(4)
Goodwill impairment (Note 6)	0		0
Income/(loss) from equity investments	(6)	0	(27)	2
Other	(18)	0	(2)	1
Earnings/(loss) before interest and income taxes	51	68	286	270
Capital expenditures	6	64	30	293
Energy Services | Business segments
Segmented Information
Revenues	6,646	4,284	19,114	16,272
Commodity and gas distribution costs	(6,726)	(4,421)	(18,965)	(16,251)
Operating and administrative	(17)	(11)	(50)	(34)
Asset impairment	0		0
Goodwill impairment (Note 6)	0		0
Income/(loss) from equity investments	3	3	10	5
Other	(2)	(5)	(1)	(3)
Earnings/(loss) before interest and income taxes	(96)	(150)	108	(11)
Capital expenditures	$ 0	$ 0	$ 0	$ 1

EARNINGS PER COMMON SHARE - BAS

EARNINGS PER COMMON SHARE - BASIC (Details) - shares shares in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Earnings Per Share [Abstract]
Prorata weighted average interest in entity's own common shares	13	13	13	13

EARNINGS PER COMMON SHARE - DIL

EARNINGS PER COMMON SHARE - DILUTED (Details) - $ / shares	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Weighted average number of common shares outstanding diluted
Weighted average common shares outstanding (in shares)	1,705,000,000	1,635,000,000	1,695,000,000	1,482,000,000
Effect of dilutive options (in shares)	3,000,000	7,000,000	4,000,000	8,000,000
Diluted weighted average common shares outstanding (in shares)	1,708,000,000	1,642,000,000	1,699,000,000	1,490,000,000
Stock options
Weighted average number of common shares outstanding diluted
Antidilutive securities excluded from the diluted earnings per common share calculation (in shares)	21,081,642	12,917,175	27,069,810	13,293,044
Weighted average exercise price of antidilutive securities (in Canadian dollars per share)	$ 52.17	$ 56.79	$ 50.37	$ 57.50

AQUISITIONS AND DISPOSITIONS (D

AQUISITIONS AND DISPOSITIONS (Details) € in Millions, $ in Millions, $ in Millions

Aug. 01, 2018CAD ($)

Aug. 01, 2018USD ($)

Aug. 01, 2018EUR (€)

Sep. 30, 2018CAD ($)

Sep. 30, 2017CAD ($)

Sep. 30, 2018CAD ($)

Sep. 30, 2017CAD ($)

Jun. 30, 2019CAD ($)

Sep. 30, 2018USD ($)

Aug. 01, 2018USD ($)

Jul. 04, 2018CAD ($)

Jun. 30, 2018CAD ($)

Dec. 31, 2017CAD ($)

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Goodwill impairment

$ 1,019

$ 0

$ 1,019

$ 0

Deferred income tax recovery

51

$ (725)

Goodwill

33,477

33,477

$ 34,457

Disposal Group, Held-for-sale, Not Discontinued Operations

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Liabilities

430

430

$ 34

Disposal Group, Held-for-sale, Not Discontinued Operations | Canadian Natural Gas Gathering and Processing Business

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Disposal group, consideration

$ 4,300

Disposal Group, Held-for-sale, Not Discontinued Operations | Texas Express NGL System

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Carrying amount of investment

$ 447

Goodwill

$ 262

Disposed of by sale, not discontinued operations | Canadian Renewable Assets

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Gain (loss) on disposal

$ 62

Disposed of by sale, not discontinued operations | United States Renewable Assets

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Gain (loss) on disposal

17

$ 13

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

154

Provision for loss (gain) on disposal, net of tax

95

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

Other Nonoperating Income (Expense) | Disposed of by sale, not discontinued operations | Hohe See Offshore Wind Project

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Gain (loss) on disposal

20

€ 14

Enbridge (U.S.) Inc. | Disposed of by sale, not discontinued operations | Midcoast Operating L.P.

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Disposal group, consideration

1,400

$ 1,100

Gain (loss) on disposal

74

$ 57

Liabilities

$ 387

$ 298

Scenario, Forecast | Disposed of by sale, not discontinued operations | Canadian Natural Gas Gathering and Processing Business

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Disposal group, consideration

$ 1,800

Hohe See Offshore Wind Project | Discontinued Operations, Disposed of by Sale

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Ownership interest in equity investment (as a percent)

49.00%

49.00%

The Assets

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Proceeds from sale of equity method investments

$ 1,750

Deferred income tax recovery

196

The Assets | Renewable Energy Assets

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Deferred income tax recovery

267

Canadian Renewable Assets | Discontinued Operations, Disposed of by Sale

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Noncontrolling interest, ownership percentage by parent

49.00%

49.00%

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

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Noncontrolling interest, ownership percentage by parent

49.00%

49.00%

Renewable Energy Assets | The Assets

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Noncontrolling interest, ownership percentage by parent

51.00%

51.00%

Accounts payable and other | Enbridge (U.S.) Inc. | Disposed of by sale, not discontinued operations | Midcoast Operating L.P.

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Liabilities

75

75

$ 58

Other Long-Term Liabilities | Enbridge (U.S.) Inc. | Disposed of by sale, not discontinued operations | Midcoast Operating L.P.

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Liabilities

$ 306

$ 306

$ 237

AQUISITIONS AND DISPOSITIONS -

AQUISITIONS AND DISPOSITIONS - ASEETS HELD FOR SALE (Details) - Disposal Group, Held-for-sale, Not Discontinued Operations - CAD ($) $ in Millions	Sep. 30, 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)	$ 154	$ 424
Deferred amounts and other assets (long-term assets held for sale)1	4,841	1,190
Accounts payable and other (current liabilities held for sale)	(70)	(315)
Other long-term liabilities (long-term liabilities held for sale)2	(430)	(34)
Net assets held for sale	4,495	1,265
Property, plant and equipment, noncurrent	4,100	$ 1,100
Goodwill, noncurrent	482
Deferred tax liabilities, noncurrent	$ 329

VARIABLE INTEREST ENTITIES - NA

VARIABLE INTEREST ENTITIES - NARRATIVE (Details) € in Millions, $ in Millions	2 Months Ended	9 Months Ended
	Sep. 30, 2018CAD ($)	Sep. 30, 2018USD ($)	Sep. 30, 2018EUR (€)	Aug. 01, 2018	Apr. 30, 2018USD ($)
Enbridge Canadian Renewable LP (ECRLP)
Variable Interest Entity, Not Primary Beneficiary
VIE, carrying amount, assets	$ 2,100
VEI, carrying amount, liabilities	45
Enbridge Renewable Infrastructure Investments S.a.r.l. (ERII)
Variable Interest Entity, Not Primary Beneficiary
VEI, maximum loss exposure, amount	$ 534		€ 356
Sabal Trail Transmission L L C
Variable Interest Entity, Not Primary Beneficiary
Ownership interest in VIE (as a percent)		50.00%
Canada Pension Plan Investment Board (CPPIB) | Enbridge Canadian Renewable LP (ECRLP)
Variable Interest Entity, Not Primary Beneficiary
Ownership interest in VIE (as a percent)	49.00%
Canada Pension Plan Investment Board (CPPIB) | Enbridge Renewable Infrastructure Investments S.a.r.l. (ERII)
Variable Interest Entity, Not Primary Beneficiary
Ownership interest in VIE (as a percent)	49.00%
Spectra Energy Partners, LP | Sabal Trail Transmission L L C
Variable Interest Entity, Not Primary Beneficiary
Proceeds from issuance of debt		$ 744,000,000
4.246% Senior Notes Due In 2028 | Spectra Energy Partners, LP | Sabal Trail Transmission L L C
Variable Interest Entity, Not Primary Beneficiary
Face amount of notes issued					$ 500,000,000
Interest rate (as a percent)					4.246%
4.682% Senior Notes Due in 2038 | Spectra Energy Partners, LP | Sabal Trail Transmission L L C
Variable Interest Entity, Not Primary Beneficiary
Face amount of notes issued					$ 600,000,000
Interest rate (as a percent)					4.682%
4.832% Senior Notes Due In 2048 | Spectra Energy Partners, LP | Sabal Trail Transmission L L C
Variable Interest Entity, Not Primary Beneficiary
Face amount of notes issued					$ 400,000,000
Interest rate (as a percent)					4.832%
Enbridge Renewable Infrastructure Investments S.a.r.l. (ERII)
Variable Interest Entity, Not Primary Beneficiary
Ownership interest in equity investment (as a percent)				51.00%
Long Term Investment | Enbridge Renewable Infrastructure Investments S.a.r.l. (ERII)
Variable Interest Entity, Not Primary Beneficiary
Carrying amount of investment	$ 118		79
Long Term Receivable | Enbridge Renewable Infrastructure Investments S.a.r.l. (ERII)
Variable Interest Entity, Not Primary Beneficiary
Due from related parties	$ 416		€ 277

DEBT - CREDIT FACILITIES (Detai

DEBT - CREDIT FACILITIES (Details) - Sep. 30, 2018 - Committed credit facilities $ in Millions, $ in Millions	CAD ($)	USD ($)
CREDIT FACILITIES
Total Facilities	$ 20,047
Draws	9,176
Available	10,871
Enbridge Inc.
CREDIT FACILITIES
Total Facilities	5,602
Draws	2,330
Available	3,272
Enbridge (U.S.) Inc.
CREDIT FACILITIES
Total Facilities	1,829
Draws	0
Available	1,829
Enbridge Energy Partners, L.P.
CREDIT FACILITIES
Total Facilities	3,167
Draws	2,210
Available	957
Repayments of principal in next twelve months	239	$ 185
Enbridge Gas Distribution Inc.
CREDIT FACILITIES
Total Facilities	1,017
Draws	779
Available	238
Enbridge Income Fund
CREDIT FACILITIES
Total Facilities	1,500
Draws	9
Available	1,491
Enbridge Pipelines Inc.
CREDIT FACILITIES
Total Facilities	3,000
Draws	1,214
Available	1,786
Spectra Energy Partners, LP
CREDIT FACILITIES
Total Facilities	3,232
Draws	2,153
Available	1,079
Repayments of principal in year four	435	$ 336
Union Gas Limited
CREDIT FACILITIES
Total Facilities	700
Draws	481
Available	$ 219

DEBT - NARRATIVE (Details)

DEBT - NARRATIVE (Details) $ in Millions	3 Months Ended				9 Months Ended
	Sep. 30, 2018CAD ($)	Jun. 30, 2018USD ($)	Mar. 31, 2018CAD ($)	Mar. 31, 2018USD ($)	Sep. 30, 2018CAD ($)	Dec. 31, 2017CAD ($)
Line of Credit Facility [Line Items]
Commitment fee percentage					0.20%
Long-term debt	$ 58,707,000,000				$ 58,707,000,000	$ 60,865,000,000
Long-term debt, fair value adjustment					975,000,000
Amortization of fair value adjustment	23,000,000				112,000,000
Uncommitted demand credit facilities
Line of Credit Facility [Line Items]
Amount of credit facility	790,000,000				790,000,000	792,000,000
Unutilized amount of facility	564,000,000				564,000,000	518,000,000
Commercial paper and credit facility draws
Line of Credit Facility [Line Items]
Long-term debt	7,534,000,000				7,534,000,000	10,055,000,000
Enbridge (U.S.) Inc.
Line of Credit Facility [Line Items]
Extinguishment of debt		$ 500		$ 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		$ 100		$ 650
Subordinated Debt | Fixed To Floating Subordinated Term Notes
Line of Credit Facility [Line Items]
Subordinated debt	$ 7,053,000,000				$ 7,053,000,000	$ 4,344,000,000

DEBT - LONG TERM DEBT ISSUANCE

DEBT - LONG TERM DEBT ISSUANCE (Details)	1 Months Ended
	Apr. 30, 2018CAD ($)	Mar. 31, 2018USD ($)	Apr. 30, 2018USD ($)	Jan. 31, 2018USD ($)
3.50% Senior Notes Due 2028 | Spectra Energy Partners, LP
DEBT
Face amount of notes issued				$ 400,000,000
Interest rate (as a percent)				3.50%
4.15% Senior Notes Due 2048 | Spectra Energy Partners, LP
DEBT
Face amount of notes issued				$ 400,000,000
Interest rate (as a percent)				4.15%
Enbridge Inc. | Fixed to Floating Rate Notes Due 2078
DEBT
Face amount of notes issued		$ 850,000,000
Interest rate (as a percent)		6.25%
Maturity period of debt		60 years
Callable period		10 years
Term of fixed interest rate		10 years
Enbridge Inc. | Fixed to Floating Rate Notes Due 2078, Issued April 2018
DEBT
Face amount of notes issued	$ 750,000,000
Interest rate (as a percent)	6.625%		6.625%
Maturity period of debt	60 years
Callable period	10 years
Term of fixed interest rate	10 years
Enbridge Inc. | Fixed to Floating Rate Notes Due 2078, US Based Issued April 2018
DEBT
Face amount of notes issued			$ 600,000,000
Interest rate (as a percent)	6.375%		6.375%
Maturity period of debt	60 years
Callable period	5 years
Debt Instrument, Redemption, Period One | Enbridge Inc. | Fixed to Floating Rate Notes Due 2078
DEBT
Basis spread on variable rate (as a percent)		3.64%
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 One | Enbridge Inc. | Fixed to Floating Rate Notes Due 2078, Issued April 2018
DEBT
Basis spread on variable rate (as a percent)	4.32%
Debt Instrument, Redemption, Period One | Enbridge Inc. | Fixed to Floating Rate Notes Due 2078, Issued April 2018 | 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, Issued April 2018 | Maximum
DEBT
Variable rate period subsequent to fixed rate period	30 years
Debt Instrument, Redemption, Period One | Enbridge Inc. | Fixed to Floating Rate Notes Due 2078, US Based Issued April 2018
DEBT
Basis spread on variable rate (as a percent)	3.59%
Debt Instrument, Redemption, Period One | Enbridge Inc. | Fixed to Floating Rate Notes Due 2078, US Based Issued April 2018 | Minimum
DEBT
Variable rate period subsequent to fixed rate period	5 years
Debt Instrument, Redemption, Period One | Enbridge Inc. | Fixed to Floating Rate Notes Due 2078, US Based Issued April 2018 | Maximum
DEBT
Variable rate period subsequent to fixed rate period	10 years
Debt Instrument, Redemption, Period Two | Enbridge Inc. | Fixed to Floating Rate Notes Due 2078
DEBT
Basis spread on variable rate (as a percent)		4.39%
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 Instrument, Redemption, Period Two | Enbridge Inc. | Fixed to Floating Rate Notes Due 2078, Issued April 2018
DEBT
Basis spread on variable rate (as a percent)	5.07%
Debt Instrument, Redemption, Period Two | Enbridge Inc. | Fixed to Floating Rate Notes Due 2078, Issued April 2018 | 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, Issued April 2018 | Maximum
DEBT
Variable rate period subsequent to fixed rate period	60 years
Debt Instrument, Redemption, Period Two | Enbridge Inc. | Fixed to Floating Rate Notes Due 2078, US Based Issued April 2018
DEBT
Basis spread on variable rate (as a percent)	3.84%
Debt Instrument, Redemption, Period Two | Enbridge Inc. | Fixed to Floating Rate Notes Due 2078, US Based Issued April 2018 | Minimum
DEBT
Variable rate period subsequent to fixed rate period	10 years
Debt Instrument, Redemption, Period Two | Enbridge Inc. | Fixed to Floating Rate Notes Due 2078, US Based Issued April 2018 | Maximum
DEBT
Variable rate period subsequent to fixed rate period	25 years
Debt Instrument, Redemption, Period Three | Enbridge Inc. | Fixed to Floating Rate Notes Due 2078, US Based Issued April 2018
DEBT
Basis spread on variable rate (as a percent)	4.59%
Debt Instrument, Redemption, Period Three | Enbridge Inc. | Fixed to Floating Rate Notes Due 2078, US Based Issued April 2018 | Minimum
DEBT
Variable rate period subsequent to fixed rate period	25 years
Debt Instrument, Redemption, Period Three | Enbridge Inc. | Fixed to Floating Rate Notes Due 2078, US Based Issued April 2018 | Maximum
DEBT
Variable rate period subsequent to fixed rate period	60 years

DEBT - LONG TERM DEBT REPAYMENT

DEBT - LONG TERM DEBT REPAYMENTS (Details)

1 Months Ended

9 Months Ended

Jul. 31, 2018USD ($)

Mar. 31, 2018USD ($)

Sep. 30, 2018CAD ($)

Sep. 30, 2018USD ($)

Sep. 30, 2018USD ($)

Aug. 31, 2018

Aug. 30, 2018CAD ($)

Jul. 31, 2018CAD ($)

Jul. 31, 2018USD ($)

Jun. 30, 2018USD ($)

May 31, 2018CAD ($)

Apr. 30, 2018CAD ($)

Apr. 30, 2018USD ($)

Jan. 31, 2018CAD ($)

Enbridge Energy Partners, L.P. | 6.50% Senior Notes

DEBT

Face amount of notes issued

$ 400,000,000

Interest rate (as a percent)

6.50%

6.50%

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

DEBT

Face amount of notes issued

$ 20,000,000

Interest rate (as a percent)

3.98%

Enbridge Southern Lights L P | 4.014% medium-term note due June 2040

DEBT

Face amount of notes issued

$ 8,000,000

$ 9,000,000

Interest rate (as a percent)

4.01%

4.01%

4.01%

Midcoast Energy Partners, L.P. | 3.56% Senior Notes Due June 2019

DEBT

Face amount of notes issued

$ 75,000,000

Interest rate (as a percent)

3.56%

3.56%

Repayments of debt

$ 76,000,000

Midcoast Energy Partners, L.P. | 4.04% Senior Notes Due June 2021

DEBT

Face amount of notes issued

$ 175,000,000

Interest rate (as a percent)

4.04%

4.04%

Repayments of debt

182,000,000

Midcoast Energy Partners, L.P. | 4.42% Senior Notes Due June 2024

DEBT

Face amount of notes issued

$ 150,000,000

Interest rate (as a percent)

4.42%

4.42%

Repayments of debt

$ 161,000,000

Spectra Energy Capitals, LLC

DEBT

Gain (loss) on extinguishment of debt

$ 64,000,000

$ 50,000,000

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

DEBT

Face amount of notes issued

$ 64,000,000

Interest rate (as a percent)

6.75%

Repayments of debt

$ 80,000,000

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

DEBT

Face amount of notes issued

$ 43,000,000

Interest rate (as a percent)

7.50%

Repayments of debt

$ 59,000,000

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

DEBT

Face amount of notes issued

$ 163,000,000

Interest rate (as a percent)

5.65%

Repayments of debt

$ 172,000,000

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

DEBT

Face amount of notes issued

$ 498,000,000

Interest rate (as a percent)

3.30%

Repayments of debt

$ 508,000,000

Spectra Energy Capitals, LLC | 6.20% Senior Notes

DEBT

Face amount of notes issued

$ 272,000,000

Interest rate (as a percent)

6.20%

6.20%

Spectra Energy Capitals, LLC | 6.75% Senior Notes

DEBT

Face amount of notes issued

$ 118,000,000

Interest rate (as a percent)

6.75%

6.75%

Spectra Energy Partners, LP | 2.95% Senior Notes

DEBT

Face amount of notes issued

$ 500,000,000

Interest rate (as a percent)

2.95%

2.95%

Union Gas Limited | 5.35% Medium-Term Notes

DEBT

Face amount of notes issued

$ 200,000,000

Interest rate (as a percent)

5.35%

5.35%

Union Gas Limited | 8.75% Debenture

DEBT

Face amount of notes issued

$ 125,000,000

Interest rate (as a percent)

8750000.00%

Westcoast Energy Inc | 6.9% senior secured notes

DEBT

Face amount of notes issued

$ 13,000,000

Interest rate (as a percent)

6.90%

Westcoast Energy Inc | 4.34% senior secured notes

DEBT

Face amount of notes issued

$ 4,000,000

Interest rate (as a percent)

4.34%

Westcoast Energy Inc | 8.50% Debenture

DEBT

Face amount of notes issued

$ 150,000,000

Interest rate (as a percent)

8500000.00%

8500000.00%

COMPONENTS OF ACCUMULATED OTH_3

COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME (Details) - CAD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Changes in AOCI
Balance at the beginning of the period	$ 58,135
Balance at the end of the period	60,787
Accumulated other comprehensive income
Changes in AOCI
Balance at the beginning of the period	(973)	$ 1,058
Other comprehensive income/(loss) retained in AOCI	1,422	(2,095)
Other comprehensive (income)/loss reclassified to earnings, Pension and OPEB	36	21
Total before tax impact	1,565	(1,980)
Income tax on amounts retained in AOCI	15	13
Income tax on amounts reclassified to earnings	(37)	(42)
Tax impact	(22)	(29)
Balance at the end of the period	570	(951)
Accumulated other comprehensive income | Interest rate contracts
Changes in AOCI
Other comprehensive (income)/loss reclassified to earnings, Cash Flow Hedges	92	104
Accumulated other comprehensive income | Commodity contracts
Changes in AOCI
Other comprehensive (income)/loss reclassified to earnings, Cash Flow Hedges	(1)	(5)
Accumulated other comprehensive income | Foreign exchange contracts
Changes in AOCI
Other comprehensive (income)/loss reclassified to earnings, Cash Flow Hedges	6	(2)
Accumulated other comprehensive income | Other contracts
Changes in AOCI
Other comprehensive (income)/loss reclassified to earnings, Cash Flow Hedges	10	(3)
Cash Flow Hedges
Changes in AOCI
Balance at the beginning of the period	(644)	(746)
Other comprehensive income/(loss) retained in AOCI	167	29
Total before tax impact	274	123
Income tax on amounts retained in AOCI	(26)	(9)
Income tax on amounts reclassified to earnings	(29)	(34)
Tax impact	(55)	(43)
Balance at the end of the period	(425)	(666)
Cash Flow Hedges | Interest rate contracts
Changes in AOCI
Other comprehensive (income)/loss reclassified to earnings	92	104
Cash Flow Hedges | Commodity contracts
Changes in AOCI
Other comprehensive (income)/loss reclassified to earnings	(1)	(5)
Cash Flow Hedges | Foreign exchange contracts
Changes in AOCI
Other comprehensive (income)/loss reclassified to earnings	6	(2)
Cash Flow Hedges | Other contracts
Changes in AOCI
Other comprehensive (income)/loss reclassified to earnings	10	(3)
Net Investment Hedges
Changes in AOCI
Balance at the beginning of the period	(139)	(629)
Other comprehensive income/(loss) retained in AOCI	(232)	496
Total before tax impact	(232)	496
Income tax on amounts retained in AOCI	32	9
Tax impact	32	9
Balance at the end of the period	(339)	(124)
Cumulative Translation Adjustment
Changes in AOCI
Balance at the beginning of the period	77	2,700
Other comprehensive income/(loss) retained in AOCI	1,495	(2,616)
Total before tax impact	1,495	(2,616)
Balance at the end of the period	1,572	84
Equity Investees
Changes in AOCI
Balance at the beginning of the period	10	37
Other comprehensive income/(loss) retained in AOCI	(8)	(4)
Total before tax impact	(8)	(4)
Income tax on amounts retained in AOCI	9	13
Tax impact	9	13
Balance at the end of the period	11	46
Pension and OPEB Adjustment
Changes in AOCI
Balance at the beginning of the period	(277)	(304)
Other comprehensive (income)/loss reclassified to earnings	36	21
Total before tax impact	36	21
Income tax on amounts reclassified to earnings	(8)	(8)
Tax impact	(8)	(8)
Balance at the end of the period	$ (249)	$ (291)

NONCONTROLLING INTERESTS - REDE

NONCONTROLLING INTERESTS - REDEEMABLE NONCONTROLLING INFORMATION (Details) - CAD ($) shares in Millions, $ in Millions	Jan. 22, 2018	Sep. 30, 2018	Sep. 30, 2017	Aug. 01, 2018	Dec. 31, 2017
Noncontrolling interests
Noncontrolling Interest [Line Items]
Sale of noncontrolling interests in subsidiaries (Note 10)		$ (1,183)	$ 0
Spectra Energy Partners, LP restructuring (Note 9)		1,486	0
Additional paid-in capital
Noncontrolling Interest [Line Items]
Sale of noncontrolling interests in subsidiaries (Note 10)		79	0
Dilution gain on Spectra Energy Partners, LP restructuring (Note 10)		1,136	$ 0
Deferred Income Tax Liability
Noncontrolling Interest [Line Items]
Sale of noncontrolling interests in subsidiaries (Note 10)		27
Spectra Energy Partners, LP
Noncontrolling Interest [Line Items]
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
Spectra Energy Partners, LP
Noncontrolling Interest [Line Items]
Noncontrolling interest, ownership percentage by parent					75.00%
Incentive Distribution Rights | Spectra Energy Partners, LP
Noncontrolling Interest [Line Items]
Noncontrolling interest, ownership percentage by parent					100.00%
Discontinued Operations, Disposed of by Sale | Canadian Renewable Assets
Noncontrolling Interest [Line Items]
Noncontrolling interest, ownership percentage by parent				49.00%
Discontinued Operations, Disposed of by Sale | United States Renewable Assets
Noncontrolling Interest [Line Items]
Noncontrolling interest, ownership percentage by parent				49.00%

RISK MANAGEMENT AND FINANCIAL_3

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - MARKET RISK (Details)	9 Months Ended
	Sep. 30, 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)	2.20%
Interest rate contracts - long-term debt
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
Average swap rate, fixed (as a percent)	3.10%
Equity contracts
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
Number of forms of stock-based compensation with equity price risk	1

RISK MANAGEMENT AND FINANCIAL_4

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - TOTAL DERIVATIVE INSTRUMENTS (Details) - CAD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	$ (2,283)	$ (2,192)
Derivative liabilities, Total Net Derivative Instruments	(2,283)	(2,192)
Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(2,310)	(1,991)
Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	49	(155)
Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(10)	(46)
Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(12)
Accounts receivable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Gross Derivative Instruments as Presented	236	296
Derivative assets, Amounts Available for Offset	(137)	(150)
Derivative assets, Total Net Derivative Instruments	99	146
Accounts receivable and other | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Gross Derivative Instruments as Presented	185	281
Accounts receivable and other | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Gross Derivative Instruments as Presented	50	9
Accounts receivable and other | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Gross Derivative Instruments as Presented	1	4
Accounts receivable and other | Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Gross Derivative Instruments as Presented		2
Deferred amounts and other assets
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Gross Derivative Instruments as Presented	115	181
Derivative assets, Amounts Available for Offset	(55)	(146)
Derivative assets, Total Net Derivative Instruments	60	35
Deferred amounts and other assets | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Gross Derivative Instruments as Presented	51	149
Deferred amounts and other assets | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Gross Derivative Instruments as Presented	64	25
Deferred amounts and other assets | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Gross Derivative Instruments as Presented		1
Deferred amounts and other assets | Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Gross Derivative Instruments as Presented		6
Accounts payable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Gross Derivative Instruments as Presented	(1,034)	(1,130)
Derivative liabilities, Amounts Available for Offset	137	150
Derivative liabilities, Total Net Derivative Instruments	(897)	(980)
Accounts payable and other | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Gross Derivative Instruments as Presented	(969)	(936)
Accounts payable and other | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Gross Derivative Instruments as Presented	(56)	(146)
Accounts payable and other | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Gross Derivative Instruments as Presented	0	(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	(1,600)	(1,539)
Derivative liabilities, Amounts Available for Offset	55	146
Derivative liabilities, Total Net Derivative Instruments	(1,545)	(1,393)
Other long-term liabilities | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Gross Derivative Instruments as Presented	(1,577)	(1,485)
Other long-term liabilities | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Gross Derivative Instruments as Presented	(9)	(43)
Other long-term liabilities | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Gross Derivative Instruments as Presented	(11)	(9)
Other long-term liabilities | Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Gross Derivative Instruments as Presented	(3)	(2)
Foreign exchange contracts
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(1,697)	(1,383)
Derivative liabilities, Total Net Derivative Instruments	(1,697)	(1,383)
Foreign exchange contracts | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(1,686)	(1,330)
Foreign exchange contracts | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(1)	(7)
Foreign exchange contracts | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(10)	(46)
Foreign exchange contracts | Accounts receivable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Gross Derivative Instruments as Presented	67	143
Derivative assets, Amounts Available for Offset	(49)	(83)
Derivative assets, Total Net Derivative Instruments	18	60
Foreign exchange contracts | Accounts receivable and other | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Gross Derivative Instruments as Presented	66	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		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	1	4
Foreign exchange contracts | Deferred amounts and other assets
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Gross Derivative Instruments as Presented	43	145
Derivative assets, Amounts Available for Offset	(29)	(125)
Derivative assets, Total Net Derivative Instruments	14	20
Foreign exchange contracts | Deferred amounts and other assets | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Gross Derivative Instruments as Presented	39	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	4	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		1
Foreign exchange contracts | Accounts payable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Gross Derivative Instruments as Presented	(376)	(359)
Derivative liabilities, Amounts Available for Offset	49	83
Derivative liabilities, Total Net Derivative Instruments	(327)	(276)
Foreign exchange contracts | Accounts payable and other | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Gross Derivative Instruments as Presented	(371)	(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	0	(42)
Foreign exchange contracts | Other long-term liabilities
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Gross Derivative Instruments as Presented	(1,431)	(1,312)
Derivative liabilities, Amounts Available for Offset	29	125
Derivative liabilities, Total Net Derivative Instruments	(1,402)	(1,187)
Foreign exchange contracts | Other long-term liabilities | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Gross Derivative Instruments as Presented	(1,420)	(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	(11)	(9)
Interest rate contracts
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(156)	(348)
Derivative liabilities, Total Net Derivative Instruments	(156)	(348)
Interest rate contracts | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(179)	(183)
Interest rate contracts | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	35	(165)
Interest rate contracts | Fair Value Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(12)
Interest rate contracts | Accounts receivable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Gross Derivative Instruments as Presented	49	8
Derivative assets, Amounts Available for Offset	(3)	(3)
Derivative assets, Total Net Derivative Instruments	46	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	49	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		2
Interest rate contracts | Deferred amounts and other assets
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Gross Derivative Instruments as Presented	42	13
Derivative assets, Amounts Available for Offset	(1)	(2)
Derivative assets, Total Net Derivative Instruments	41	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	42	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		6
Interest rate contracts | Accounts payable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Gross Derivative Instruments as Presented	(238)	(329)
Derivative liabilities, Amounts Available for Offset	3	3
Derivative liabilities, Total Net Derivative Instruments	(235)	(326)
Interest rate contracts | Accounts payable and other | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Gross Derivative Instruments as Presented	(179)	(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	(50)	(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	(9)	(40)
Derivative liabilities, Amounts Available for Offset	1	2
Derivative liabilities, Total Net Derivative Instruments	(8)	(38)
Interest rate contracts | Other long-term liabilities | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Gross Derivative Instruments as Presented	(6)	(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	(3)	(2)
Commodity contracts
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(414)	(457)
Derivative liabilities, Total Net Derivative Instruments	(414)	(457)
Commodity contracts | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(433)	(476)
Commodity contracts | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	19	19
Commodity contracts | Accounts receivable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Gross Derivative Instruments as Presented	120	145
Derivative assets, Amounts Available for Offset	(85)	(64)
Derivative assets, Total Net Derivative Instruments	35	81
Commodity contracts | Accounts receivable and other | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Gross Derivative Instruments as Presented	119	143
Commodity contracts | Accounts receivable and other | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Gross Derivative Instruments as Presented	1	2
Commodity contracts | Deferred amounts and other assets
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Gross Derivative Instruments as Presented	30	23
Derivative assets, Amounts Available for Offset	(25)	(19)
Derivative assets, Total Net Derivative Instruments	5	4
Commodity contracts | Deferred amounts and other assets | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Gross Derivative Instruments as Presented	12	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	18	17
Commodity contracts | Accounts payable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Gross Derivative Instruments as Presented	(411)	(439)
Derivative liabilities, Amounts Available for Offset	85	64
Derivative liabilities, Total Net Derivative Instruments	(326)	(375)
Commodity contracts | Accounts payable and other | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Gross Derivative Instruments as Presented	(411)	(439)
Commodity contracts | Other long-term liabilities
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Gross Derivative Instruments as Presented	(153)	(186)
Derivative liabilities, Amounts Available for Offset	25	19
Derivative liabilities, Total Net Derivative Instruments	(128)	(167)
Commodity contracts | Other long-term liabilities | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Gross Derivative Instruments as Presented	(153)	(186)
Other contracts
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(16)	(4)
Derivative liabilities, Total Net Derivative Instruments	(16)	(4)
Other contracts | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(12)	(2)
Other contracts | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(4)	(2)
Other contracts | Deferred amounts and other assets
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Gross Derivative Instruments as Presented	0
Derivative assets, Amounts Available for Offset	0
Derivative assets, Total Net Derivative Instruments	0
Other contracts | Deferred amounts and other assets | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets, Gross Derivative Instruments as Presented	0
Other contracts | Accounts payable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Gross Derivative Instruments as Presented	(9)	(3)
Derivative liabilities, Total Net Derivative Instruments	(9)	(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	(1)	(1)
Other contracts | Other long-term liabilities
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Gross Derivative Instruments as Presented	(7)	(1)
Derivative liabilities, Amounts Available for Offset	0
Derivative liabilities, Total Net Derivative Instruments	(7)	(1)
Other contracts | Other long-term liabilities | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Gross Derivative Instruments as Presented	(4)
Other contracts | Other long-term liabilities | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities, Gross Derivative Instruments as Presented	$ (3)	$ (1)

RISK MANAGEMENT AND FINANCIAL_5

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - NOTIONAL PRINCIPAL OR QUANTITY INFORMATION (Details) - Sep. 30, 2018 € in Millions, ¥ in Millions, £ in Millions, MMBbls 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 | €				€ 23
Foreign exchange contracts - forwards - purchase | United States dollar
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2,018		$ 591
2,019		3
2,020		1
Foreign exchange contracts - forwards - purchase | Euro
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2018 | €				42
2019 | €				208
Foreign exchange contracts - forwards - purchase | Japanese yen
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2019 | ¥					¥ 32,662
2022 | ¥					¥ 20,000
Foreign exchange contracts - forwards - sell | United States dollar
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2,018		1,592
2,019		3,262
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 | €				94
2022 | €				94
Thereafter | €				€ 698
Interest rate contracts - short-term borrowings
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2,018	$ 1,251
2,019	3,590
2,020	1,093
2,021	121
2,022	93
Thereafter	203
Interest rate contracts - long-term receive fixed rate
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2,018	145
2,019	582
2,020	555
2,021	188
2,022	102
Interest rate contracts - long-term debt pay fixed rate
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2,018	1,894
2,019	600
2,020	573
Equity contracts
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2,018	40
2,019	35
2,020	$ 20
Commodity contracts | Natural gas
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2018 | Bcf	(7)	(7)	(7)	(7)	(7)
2019 | Bcf	(58)	(58)	(58)	(58)	(58)
2020 | Bcf	(18)	(18)	(18)	(18)	(18)
2021 | Bcf	(5)	(5)	(5)	(5)	(5)
2022 | Bcf	8	8	8	8	8
Thereafter | Bcf	1	1	1	1	1
Commodity contracts | Crude oil
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2018 | MMBbls	4	4	4	4	4
2019 | MMBbls	4	4	4	4	4
Commodity contracts | NGL
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2018 | MMBbls	(1)	(1)	(1)	(1)	(1)
Commodity contracts | Power
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2018 | MWh	57	57	57	57	57
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 FINANCIAL_6

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - EARNINGS AND COMPREHENSIVE INCOME (Details) - CAD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Gain (loss) recognized in Other Comprehensive Income (Loss)	$ 72	$ 245	$ 213	$ 261
Amount of (gain)/loss reclassified from AOCI to earnings (effective portion)	54	36	137	28
Amount of (gain)/loss reclassified from AOCI to earnings (ineffective portion and amount excluded from effectiveness testing)	(2)	(1)	8	5
Estimated gain of AOCI related to cash flow hedges reclassified to earnings in the next 12 months			$ 1
Period to hedge exposures to the variability of cash flows for all forecasted transactions			27 months
Unrealized gain/(loss) on derivative	3	0	$ (9)	(1)
Unrealized gain/(loss) on hedged item	(3)	1	8	2
Realized gain/(loss) on derivative	(3)	2	(4)	2
Realized gain/(loss) on hedged item	3	(2)	4	(2)
Unrealized gain (loss) on derivatives			(319)	1,243
Non-Qualifying Derivative Instruments
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain (loss) on derivatives	230	345	(319)	1,243
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)	7	(3)	4	(104)
Foreign exchange contracts | Non-Qualifying Derivative Instruments
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain (loss) on derivatives	345	503	(356)	1,210
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
Unrealized gain (loss) on derivatives			346	726
Foreign exchange contracts | Non-Qualifying Derivative Instruments | Other income/(expense)
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain (loss) on derivatives			(10)	484
Foreign exchange contracts | Cash Flow Hedges
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Gain (loss) recognized in Other Comprehensive Income (Loss)	(16)	(2)	2	(1)
Foreign exchange contracts | Net Investment Hedges
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Gain (loss) recognized in Other Comprehensive Income (Loss)	25	148	36	221
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)	40	50	124	134
Amount of (gain)/loss reclassified from AOCI to earnings (ineffective portion and amount excluded from effectiveness testing)	(2)	(1)	8	5
Interest rate contracts | Non-Qualifying Derivative Instruments
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain (loss) on derivatives	6	(1)	4	13
Interest rate contracts | Cash Flow Hedges
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Gain (loss) recognized in Other Comprehensive Income (Loss)	69	83	186	28
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)	0	0	(1)	(4)
Commodity contracts | Non-Qualifying Derivative Instruments
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain (loss) on derivatives	(113)	(160)	43	22
Commodity contracts | Non-Qualifying Derivative Instruments | Transportation and other services revenues
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain (loss) on derivatives			16	(85)
Commodity contracts | Non-Qualifying Derivative Instruments | Commodity sales
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain (loss) on derivatives			42	67
Commodity contracts | Non-Qualifying Derivative Instruments | Commodity costs
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain (loss) on derivatives			90	22
Commodity contracts | Non-Qualifying Derivative Instruments | Operating and administrative expense
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain (loss) on derivatives			11	18
Commodity contracts | Cash Flow Hedges
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Gain (loss) recognized in Other Comprehensive Income (Loss)	4	0	1	12
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)	7	(11)	10	2
Other contracts | Non-Qualifying Derivative Instruments
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain (loss) on derivatives	(8)	3	(10)	(2)
Other contracts | Cash Flow Hedges
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Gain (loss) recognized in Other Comprehensive Income (Loss)	$ (10)	$ 16	$ (12)	$ 1

RISK MANAGEMENT AND FINANCIAL_7

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - LIQUIDITY AND CREDIT RISK (Details) - CAD ($)	9 Months Ended	12 Months Ended
	Sep. 30, 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	$ 268,000,000	$ 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	28,000,000	82,000,000
Derivative instruments | United States financial institutions
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	44,000,000	19,000,000
Derivative instruments | European financial institutions
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	79,000,000	145,000,000
Derivative instruments | Asian financial institutions
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	31,000,000	2,000,000
Derivative instruments | Other
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	$ 86,000,000	$ 137,000,000

RISK MANAGEMENT AND FINANCIAL_8

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - FAIR VALUE OF DERIVATIVES (Details) - CAD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Fair Value of Derivatives
Total net derivative asset/(liability)	$ (2,283)	$ (2,192)
Foreign exchange contracts
Fair Value of Derivatives
Total net derivative asset/(liability)	(1,697)	(1,383)
Interest rate contracts
Fair Value of Derivatives
Total net derivative asset/(liability)	(156)	(348)
Commodity contracts
Fair Value of Derivatives
Total net derivative asset/(liability)	(414)	(457)
Other contracts
Fair Value of Derivatives
Total net derivative asset/(liability)	(16)	(4)
Recurring basis
Fair Value of Derivatives
Current derivative assets	236	296
Long-term derivative assets	115	181
Current derivative liabilities	(1,034)	(1,130)
Long-term derivative liabilities	(1,600)	(1,539)
Total net derivative asset/(liability)	(2,283)	(2,192)
Recurring basis | Foreign exchange contracts
Fair Value of Derivatives
Current derivative assets	67	143
Long-term derivative assets	43	145
Current derivative liabilities	(376)	(359)
Long-term derivative liabilities	(1,431)	(1,312)
Total net derivative asset/(liability)	(1,697)	(1,383)
Recurring basis | Interest rate contracts
Fair Value of Derivatives
Current derivative assets	49	8
Long-term derivative assets	42	13
Current derivative liabilities	(238)	(329)
Long-term derivative liabilities	(9)	(40)
Total net derivative asset/(liability)	(156)	(348)
Recurring basis | Commodity contracts
Fair Value of Derivatives
Current derivative assets	120	145
Long-term derivative assets	30	23
Current derivative liabilities	(411)	(439)
Long-term derivative liabilities	(153)	(186)
Total net derivative asset/(liability)	(414)	(457)
Recurring basis | Other contracts
Fair Value of Derivatives
Long-term derivative assets	0
Current derivative liabilities	(9)	(3)
Long-term derivative liabilities	(7)	(1)
Total net derivative asset/(liability)	(16)	(4)
Level 1 | Recurring basis
Fair Value of Derivatives
Current derivative assets	1	1
Current derivative liabilities	(11)	(13)
Total net derivative asset/(liability)	(10)	(12)
Level 1 | Recurring basis | Commodity contracts
Fair Value of Derivatives
Current derivative assets	1	1
Current derivative liabilities	(11)	(13)
Total net derivative asset/(liability)	(10)	(12)
Level 2 | Recurring basis
Fair Value of Derivatives
Current derivative assets	125	181
Long-term derivative assets	90	160
Current derivative liabilities	(660)	(778)
Long-term derivative liabilities	(1,458)	(1,356)
Total net derivative asset/(liability)	(1,903)	(1,793)
Level 2 | Recurring basis | Foreign exchange contracts
Fair Value of Derivatives
Current derivative assets	67	143
Long-term derivative assets	43	145
Current derivative liabilities	(376)	(359)
Long-term derivative liabilities	(1,431)	(1,312)
Total net derivative asset/(liability)	(1,697)	(1,383)
Level 2 | Recurring basis | Interest rate contracts
Fair Value of Derivatives
Current derivative assets	49	8
Long-term derivative assets	42	13
Current derivative liabilities	(238)	(329)
Long-term derivative liabilities	(9)	(40)
Total net derivative asset/(liability)	(156)	(348)
Level 2 | Recurring basis | Commodity contracts
Fair Value of Derivatives
Current derivative assets	9	30
Long-term derivative assets	5	2
Current derivative liabilities	(37)	(87)
Long-term derivative liabilities	(11)	(3)
Total net derivative asset/(liability)	(34)	(58)
Level 2 | Recurring basis | Other contracts
Fair Value of Derivatives
Long-term derivative assets	0
Current derivative liabilities	(9)	(3)
Long-term derivative liabilities	(7)	(1)
Total net derivative asset/(liability)	(16)	(4)
Level 3 | Recurring basis
Fair Value of Derivatives
Current derivative assets	110	114
Long-term derivative assets	25	21
Current derivative liabilities	(363)	(339)
Long-term derivative liabilities	(142)	(183)
Total net derivative asset/(liability)	(370)	(387)
Level 3 | Recurring basis | Commodity contracts
Fair Value of Derivatives
Current derivative assets	110	114
Long-term derivative assets	25	21
Current derivative liabilities	(363)	(339)
Long-term derivative liabilities	(142)	(183)
Total net derivative asset/(liability)	$ (370)	$ (387)

RISK MANAGEMENT AND FINANCIAL_9

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - LEVEL 3 INPUTS (Details) $ in Millions	Sep. 30, 2018CAD ($)$ / bbl$ / Gallon-gal$ / MWh$ / MillionsofBTU-MMBTU	Dec. 31, 2017CAD ($)
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	$ (2,283)	$ (2,192)
Recurring basis
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	(2,283)	(2,192)
Level 3 | Recurring basis
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	(370)	$ (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	$ (2)
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	2.34
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	4.93
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	3.36
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	51.62
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	178.33
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	76.45
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	1.39
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	1.67
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	1.58
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	26.01
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	72.42
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	47.74
Market approach valuation technique | Level 3 | Commodity Contracts - Physical | Natural gas | Minimum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | $ / MillionsofBTU-MMBTU	1.08
Market approach valuation technique | Level 3 | Commodity Contracts - Physical | Natural gas | Maximum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | $ / MillionsofBTU-MMBTU	6.24
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	2.75
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	29.79
Market approach valuation technique | Level 3 | Commodity Contracts - Physical | Crude oil | Maximum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | $ / bbl	123.22
Market approach valuation technique | Level 3 | Commodity Contracts - Physical | Crude oil | Weighted Average
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | $ / bbl	81.29
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	0.71
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	2.16
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	1.13
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	$ (6)
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	(38)
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	(93)
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	(83)
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	(141)
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	$ (7)

RISK MANAGEMENT AND FINANCIA_10

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - CHANGES IN LEVEL 3 (Details) - CAD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Sep. 30, 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	(146)	1
Included in OCI	0	11
Settlements	163	83
Level 3 net derivative liability at end of period	$ (370)	$ (200)

RISK MANAGEMENT AND FINANCIA_11

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - OTHER FINANCIAL INSTRUMENTS (Details) - CAD ($)	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Fair Value of Other Financial Instruments
FMVA investments	$ 100,000,000		$ 99,000,000
Long-term debt, carrying value	62,500,000,000		64,000,000,000
Long-term debt	63,800,000,000		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	(209,000,000)	$ 350,000,000
Unrealized gain (loss) on change in fair value of outstanding forward exchange forward contracts	36,000,000	222,000,000
Realized gain (loss) associated with the settlement of foreign exchange forward contracts	(46,000,000)	(128,000,000)
Realized gain (loss) associated with the settlement of United Stated dollar denominated debt that matured	(13,000,000)	(52,000,000)
Amount of ineffectiveness	0	$ 0
Preferred share investment
Fair Value of Other Financial Instruments
Held to maturity investment at amortized cost	$ 370,000,000		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		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	307,000,000		267,000,000
Noncurrent notes receivable	$ 92,000,000		$ 89,000,000

INCOME TAXES (Details)

INCOME TAXES (Details) - CAD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Income Tax Disclosure [Abstract]
Effective income tax rate (as a percent)	62.00%	24.40%	7.90%	20.40%
Provisional tax expense	$ 0		$ 0

RETIREMENT AND POSTRETIREMENT B

RETIREMENT AND POSTRETIREMENT BENEFITS - NET BENEFITS COSTS RECOGNIZED (Details) - CAD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	$ 46	$ 65	$ 162	$ 181
Interest cost	39	46	126	125
Expected return on plan assets	(72)	(71)	(234)	(195)
Amortization of actuarial loss	6	11	21	28
Plan curtailments	0	0	2	0
Amortization of prior service costs	0	(1)	(1)	(1)
Net periodic benefit costs	$ 19	$ 50	$ 76	$ 138

CONTINGENCIES (Details)

CONTINGENCIES (Details) $ / shares in Units, $ in Millions	3 Months Ended
	Sep. 30, 2018CAD ($)$ / shares
Spectra Energy Partners, LP
CONTINGENCIES
Security shareholders entitlement share ratio	1.111
Enbridge Energy Partners, L.P.
CONTINGENCIES
Security shareholders entitlement share ratio	0.335
Enbridge Energy Management, LLC
CONTINGENCIES
Security shareholders entitlement share ratio	0.335
Enbridge Income Fund Holdings Inc
CONTINGENCIES
Security shareholders entitlement share ratio	0.735
Shareholder entitlement cash payment per share | $ / shares	$ 0.45
Shareholder entitlement cash payment | $	$ 63

SUBSEQUENT EVENTS (Details)

SUBSEQUENT EVENTS (Details) $ in Billions	Oct. 01, 2018CAD ($)
Canadian Natural Gas Gathering and Processing Business | Disposed of by sale, not discontinued operations | Subsequent Event
SUBSEQUENT EVENTS
Disposal group, consideration	$ 2.5