10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2019

OR

o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from            to           

Commission file number 1-10934

ENBRIDGE INC. (Exact Name of Registrant as Specified in Its Charter)

Canada	98-0377957
(State or Other Jurisdiction of Incorporation or Organization)	(I.R.S. Employer Identification No.)

200, 425 - 1st Street S.W.

Calgary, Alberta, Canada T2P 3L8

(Address of Principal Executive Offices) (Zip Code)

(403) 231-3900

(Registrant’s Telephone Number, Including Area Code)

_______________________________

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Shares	ENB	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer x	Accelerated filer o
Non-accelerated filer o	Smaller reporting company o
Emerging growth company o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x

The registrant had 2,023,709,816 common shares outstanding as at May 3, 2019.

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		Page
	PART I
Item 1.	Financial Statements	7
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	48
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	61
Item 4.	Controls and Procedures	61
	PART II
Item 1.	Legal Proceedings	62
Item 1A.	Risk Factors	62
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	62
Item 3.	Defaults Upon Senior Securities	62
Item 4.	Mine Safety Disclosures	62
Item 5.	Other Information	62
Item 6.	Exhibits	64
	Signatures	66

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GLOSSARY

AOCI	Accumulated other comprehensive income/(loss)
Army Corps	United States Army Corps of Engineers
ASC	Accounting Standards Codification
ASU	Accounting Standards Update
EBITDA	Earnings before interest, income taxes and depreciation and amortization
Eddystone Rail	Eddystone Rail Company, LLC
EEP	Enbridge Energy Partners, L.P.
Enbridge	Enbridge Inc.
kbpd	thousands of barrels per day
Market Risk	Movements in foreign exchange rates, interest rates, commodity prices and the Company's share price.
NGL	Natural gas liquids
OCI	Other comprehensive income/(loss)
SEP	Spectra Energy Partners, LP
the Court	United States District Court for the Eastern District of Pennsylvania
U.S. L3R Program	United States Line 3 Replacement Program
VIE	Variable Interest Entity

3

CONVENTIONS

The terms "we", "our", "us" and "Enbridge" as used in this report refer collectively to Enbridge Inc. unless the context suggests otherwise. These terms are used for convenience only and are not intended as a precise description of any separate legal entity within Enbridge.

Unless otherwise specified, all dollar amounts are expressed in Canadian dollars, all references to “dollars”, “$” or “C$” are to Canadian dollars and all references to “US$” are to United States dollars. All amounts are provided on a before tax basis, unless otherwise stated.

FORWARD-LOOKING INFORMATION

Forward-looking information, or forward-looking statements, have been included in this quarterly report on Form 10-Q to provide information about us and our subsidiaries and affiliates, including management’s assessment of our and our subsidiaries’ future plans and operations. This information may not be appropriate for other purposes. Forward-looking statements are typically identified by words such as ‘‘anticipate”, “believe”, “estimate”, “expect”, “forecast”, “intend”, “likely”, “plan”, “project”, “target” and similar words suggesting future outcomes or statements regarding an outlook. Forward-looking information or statements included or incorporated by reference in this document include, but are not limited to, statements with respect to the following: expected earnings before interest, income taxes and depreciation and amortization (EBITDA); expected earnings/(loss); expected earnings/(loss) per share; expected future cash flows; expected performance of the Liquids Pipelines, Gas Transmission and Midstream, Gas Distribution, Renewable Power Generation and Transmission, and Energy Services businesses; financial strength and flexibility; expectations on sources of liquidity and sufficiency of financial resources; expected costs related to announced projects and projects under construction; expected in-service dates for announced projects and projects under construction; expected capital expenditures; expected equity funding requirements for our commercially secured growth program; expected future growth and expansion opportunities; expectations about our joint venture partners’ ability to complete and finance projects under construction; expected closing of acquisitions and dispositions and expected timing thereof; estimated future dividends; expected future actions of regulators; expected costs related to leak remediation and potential insurance recoveries; expectations regarding commodity prices; supply forecasts; expectations regarding the impact of the stock-for-stock merger transaction completed on February 27, 2017 between Enbridge and Spectra Energy Corp (the Merger Transaction) including our combined scale, financial flexibility, growth program, future business prospects and performance; United States Line 3 Replacement Program (U.S. L3R Program); expected impact of the Federal Energy Regulatory Commission (FERC) policy on treatment of income taxes; the transactions undertaken to simplify our corporate structure; our dividend payout policy; dividend growth and dividend payout expectation; expectations on impact of our hedging program; and expectations resulting from the successful execution of our 2018-2020 Strategic Plan.

Although we believe these forward-looking statements are reasonable based on the information available on the date such statements are made and processes used to prepare the information, such statements are not guarantees of future performance and readers are cautioned against placing undue reliance on forward-looking statements. By their nature, these statements involve a variety of assumptions, known and unknown risks and uncertainties and other factors, which may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Material assumptions include assumptions about the following: the expected supply of and demand for crude oil, natural gas, natural gas liquids (NGL) and renewable energy; prices of crude oil, natural gas, NGL and renewable energy; exchange rates; inflation; interest rates; availability and price of labor and construction materials; operational reliability; customer and regulatory approvals; maintenance of support and regulatory approvals for our projects; anticipated in-service dates; weather; the timing and closing of dispositions; the realization of anticipated benefits and synergies of the Merger Transaction; governmental legislation; acquisitions and the timing thereof; the success of integration plans; impact of the dividend policy on our future cash flows; credit ratings; capital project funding; expected EBITDA; expected earnings/(loss); expected earnings/(loss) per share; expected future cash flows and estimated future dividends. Assumptions regarding the expected supply of and demand for crude oil, natural gas, NGL and renewable energy, and the prices of these commodities, are material to and underlie all forward-looking statements, as they may impact current and future levels of demand for our services. Similarly, exchange rates, inflation and interest rates impact the economies and business environments in which we operate and may impact levels of demand for our services and cost of inputs, and are therefore inherent in all forward-looking statements. Due to the interdependencies and correlation of these macroeconomic factors, the impact of any one assumption on a forward-looking statement cannot be determined with certainty, particularly with

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respect to the impact of the Merger Transaction on us, expected EBITDA, expected earnings/(loss), expected earnings/(loss) per share, or estimated future dividends. The most relevant assumptions associated with forward-looking statements regarding announced projects and projects under construction, including estimated completion dates and expected capital expenditures, include the following: the availability and price of labor and construction materials; the effects of inflation and foreign exchange rates on labor and material costs; the effects of interest rates on borrowing costs; the impact of weather and customer, government and regulatory approvals on construction and in-service schedules and cost recovery regimes.

Our forward-looking statements are subject to risks and uncertainties pertaining to the realization of anticipated benefits and synergies of the Merger Transaction, operating performance, regulatory parameters, changes in regulations applicable to our business, dispositions, the transactions undertaken to simplify our corporate structure, our dividend policy, project approval and support, renewals of rights-of-way, weather, economic and competitive conditions, public opinion, changes in tax laws and tax rates, changes in trade agreements, exchange rates, interest rates, commodity prices, political decisions and supply of and demand for commodities, including but not limited to those risks and uncertainties discussed in this quarterly report on Form 10-Q and in our other filings with Canadian and United States securities regulators. The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these are interdependent and our future course of action depends on management’s assessment of all information available at the relevant time. Except to the extent required by applicable law, Enbridge Inc. assumes no obligation to publicly update or revise any forward-looking statements made in this quarterly report on Form 10-Q or otherwise, whether as a result of new information, future events or otherwise. All forward-looking statements, whether written or oral, attributable to us or persons acting on our behalf, are expressly qualified in their entirety by these cautionary statements.

5

PART I - FINANCIAL INFORMATION

6

ITEM 1. FINANCIAL STATEMENTS

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF EARNINGS

	Three months ended March 31,
	2019		2018
(unaudited; millions of Canadian dollars, except per share amounts)
Operating revenues
Commodity sales	6,632		7,268
Gas distribution sales	1,876		1,926
Transportation and other services	4,348		3,532
Total operating revenues (Note 3)	12,856		12,726
Operating expenses
Commodity costs	6,565		6,997
Gas distribution costs	1,207		1,324
Operating and administrative	1,625		1,641
Depreciation and amortization	840		824
Impairment of long-lived assets	—		1,062
Total operating expenses	10,237		11,848
Operating income	2,619		878
Income from equity investments	413		335
Other income/(expense)
Net foreign currency gain/(loss)	214		(185	)
Other	46		65
Interest expense	(685	)	(656	)
Earnings before income taxes	2,607		437
Income tax (expense)/recovery (Note 12)	(584	)	73
Earnings	2,023		510
(Earnings)/loss attributable to noncontrolling interests and redeemable noncontrolling interests	(37	)	24
Earnings attributable to controlling interests	1,986		534
Preference share dividends	(95	)	(89	)
Earnings attributable to common shareholders	1,891		445
Earnings per common share attributable to common shareholders (Note 5)	0.94		0.26
Diluted earnings per common share attributable to common shareholders (Note 5)	0.94		0.26

 See accompanying notes to the interim consolidated financial statements.

7

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	Three months ended March 31,
	2019		2018
(unaudited; millions of Canadian dollars)
Earnings	2,023		510
Other comprehensive income/(loss), net of tax
Change in unrealized gain/(loss) on cash flow hedges	(192	)	66
Change in unrealized gain/(loss) on net investment hedges	94		(184	)
Other comprehensive income from equity investees	12		14
Reclassification to earnings of (gain)/loss on cash flow hedges	11		37
Reclassification to earnings of pension and other postretirement benefits (OPEB) amounts	38		(39	)
Foreign currency translation adjustments	(1,291	)	1,579
Other comprehensive income/(loss), net of tax	(1,328	)	1,473
Comprehensive income	695		1,983
Comprehensive (income)/loss attributable to noncontrolling interests and redeemable noncontrolling interests	13		(147	)
Comprehensive income attributable to controlling interests	708		1,836
Preference share dividends	(95	)	(89	)
Comprehensive income attributable to common shareholders	613		1,747

See accompanying notes to the interim consolidated financial statements.

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ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

	Three months ended March 31,
	2019		2018
(unaudited; millions of Canadian dollars, except per share amounts)
Preference shares (Note 5)
Balance at beginning and end of period	7,747		7,747
Common shares (Note 5)
Balance at beginning of period	64,677		50,737
Dividend Reinvestment and Share Purchase Plan	—		374
Shares issued on exercise of stock options	51		16
Balance at end of period	64,728		51,127
Additional paid-in capital
Balance at beginning of period	—		3,194
Stock-based compensation	4		17
Options exercised	(43	)	(6	)
Dilution gain on Spectra Energy Partners, LP restructuring	—		1,136
Change in reciprocal interest	109		—
Dilution loss and other	2		(28	)
Balance at end of period	72		4,313
Deficit
Balance at beginning of period	(5,538	)	(2,468	)
Earnings attributable to controlling interests	1,986		534
Preference share dividends	(95	)	(89	)
Dividends paid to reciprocal shareholder	5		7
Modified retrospective adoption of ASC 606 Revenue from Contracts with Customers	—		(86	)
Redemption value adjustment attributable to redeemable noncontrolling interests	—		120
Other	2		—
Balance at end of period	(3,640	)	(1,982	)
Accumulated other comprehensive income/(loss) (Note 9)
Balance at beginning of period	2,672		(973	)
Other comprehensive income/(loss) attributable to common shareholders, net of tax	(1,278	)	1,302
Other	55		—
Balance at end of period	1,449		329
Reciprocal shareholding
Balance at beginning of period	(88	)	(102	)
Change in reciprocal interest	37		—
Balance at end of period	(51	)	(102	)
Total Enbridge Inc. shareholders’ equity	70,305		61,432
Noncontrolling interests
Balance at beginning of period	3,965		7,597
Earnings attributable to noncontrolling interests	37		23
Other comprehensive income/(loss) attributable to noncontrolling interests, net of tax
Change in unrealized gain/(loss) on cash flow hedges	(1	)	4
Foreign currency translation adjustments	(49	)	152
Reclassification to earnings of loss on cash flow hedges	—		8
	(50	)	164
Comprehensive income attributable to noncontrolling interests	(13	)	187
Spectra Energy Partners, LP restructuring	—		(1,486	)
Contributions	3		8
Distributions	(46	)	(209	)
Redemption of preferred shares held by subsidiary (Note 10)	(300	)	—
Other	5		(15	)
Balance at end of period	3,614		6,082
Total equity	73,919		67,514
Dividends paid per common share	0.738		0.671
Earnings per common share attributable to common shareholders (Note 5)	0.94		0.26
Diluted earnings per common share attributable to common shareholders (Note 5)	0.94		0.26

See accompanying notes to the interim consolidated financial statements.

9

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Three months ended March 31,
	2019		2018
(unaudited; millions of Canadian dollars)
Operating activities
Earnings	2,023		510
Adjustments to reconcile earnings to net cash provided by operating activities:
Depreciation and amortization	840		824
Deferred income tax (recovery)/expense	435		(147	)
Changes in unrealized (gain)/loss on derivative instruments, net (Note 11)	(538	)	260
Earnings from equity investments	(413	)	(335	)
Distributions from equity investments	466		320
Impairment of long-lived assets	—		1,062
Other	30		78
Changes in operating assets and liabilities	(667	)	622
Net cash provided by operating activities	2,176		3,194
Investing activities
Capital expenditures	(1,612	)	(1,635	)
Long-term investments and restricted long-term investments	(565	)	(222	)
Distributions from equity investments in excess of cumulative earnings	139		57
Additions to intangible assets	(26	)	(258	)
Affiliate loans, net	(84	)	(10	)
Net cash used in investing activities	(2,148	)	(2,068	)
Financing activities
Net change in short-term borrowings	(154	)	(443	)
Net change in commercial paper and credit facility draws	2,773		(465	)
Debenture and term note issues, net of issue costs	1,195		2,061
Debenture and term note repayments	(1,789	)	(996	)
Debt extinguishment costs	—		(63	)
Contributions from noncontrolling interests	3		8
Distributions to noncontrolling interests	(46	)	(209	)
Contributions from redeemable noncontrolling interests	—		20
Distributions to redeemable noncontrolling interests	—		(84	)
Common shares issued	18		13
Preference share dividends	(90	)	(87	)
Common share dividends	(1,486	)	(764	)
Redemption of preferred shares held by subsidiary (Note 10)	(300	)	—
Other	(25	)	—
Net cash provided by/(used in) financing activities	99		(1,009	)
Effect of translation of foreign denominated cash and cash equivalents and restricted cash	(7	)	19
Net increase in cash and cash equivalents and restricted cash	120		136
Cash and cash equivalents and restricted cash at beginning of period	637		587
Cash and cash equivalents and restricted cash at end of period	757		723

See accompanying notes to the interim consolidated financial statements.

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ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

	March 31, 2019		December 31, 2018
(unaudited; millions of Canadian dollars; number of shares in millions)
Assets
Current assets
Cash and cash equivalents	702		518
Restricted cash	55		119
Accounts receivable and other	6,486		6,517
Accounts receivable from affiliates	92		79
Inventory	1,047		1,339
	8,382		8,572
Property, plant and equipment, net	93,875		94,540
Long-term investments	16,902		16,707
Restricted long-term investments	356		323
Deferred amounts and other assets	9,505		8,558
Intangible assets, net	2,301		2,372
Goodwill	33,895		34,459
Deferred income taxes	1,292		1,374
Total assets	166,508		166,905
Liabilities and equity
Current liabilities
Short-term borrowings	870		1,024
Accounts payable and other	7,331		9,863
Accounts payable to affiliates	30		40
Interest payable	573		669
Current portion of long-term debt	4,321		3,259
	13,125		14,855
Long-term debt	60,680		60,327
Other long-term liabilities	9,044		8,834
Deferred income taxes	9,740		9,454
	92,589		93,470
Contingencies (Note 15)
Equity
Share capital
Preference shares	7,747		7,747
Common shares (2,024 and 2,022 outstanding at March 31, 2019 and December 31, 2018, respectively)	64,728		64,677
Additional paid-in capital	72		—
Deficit	(3,640	)	(5,538	)
Accumulated other comprehensive income (Note 9)	1,449		2,672
Reciprocal shareholding	(51	)	(88	)
Total Enbridge Inc. shareholders’ equity	70,305		69,470
Noncontrolling interests	3,614		3,965
	73,919		73,435
Total liabilities and equity	166,508		166,905

See accompanying notes to the interim consolidated financial statements.

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NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

1. 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 updated consolidated financial statements and notes for the year ended December 31, 2018, as filed on Form 8-K with the Securities and Exchange Commission on May 10, 2019. 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 audited updated consolidated financial statements for the year ended December 31, 2018, 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.

2. CHANGES IN ACCOUNTING POLICIES

ADOPTION OF NEW STANDARDS

Cloud Computing Arrangements

Effective January 1, 2019, we adopted Accounting Standards Update (ASU) 2018-15 on a prospective basis. The new standard was issued to provide guidance on the accounting for implementation costs incurred in a cloud computing arrangement (CCA) that is a service contract. The ASU specifies that an entity would apply Accounting Standards Codification (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. The amendments in the update also require that the 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, in addition to specifying that the capitalized costs must be presented on the same balance sheet line as the prepayment of fees related to the hosting arrangement. The ASU requires similar consistency in classifications from a cash flow statement perspective. The adoption of this ASU did not have a material impact on our consolidated financial statements.

Improvements to Accounting for Hedging Activities

Effective January 1, 2019, we adopted ASU 2017-12 on a modified retrospective basis. The new standard was issued 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. As a result of the new standard, hedge ineffectiveness will no longer be measured or recorded, and hedging instruments’ fair value changes will be recorded in the same income statement line as the hedged item. The adoption of this accounting update did not have a material impact on our consolidated financial statements.

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Amending the Amortization Period for Certain Callable Debt Securities Purchased at a Premium

Effective January 1, 2019, we adopted ASU 2017-08 on a modified retrospective basis. The new standard was issued with the intent of shortening the amortization period to the earliest call date for certain callable debt securities held at a premium. The adoption of this accounting update did not have a material impact on our consolidated financial statements.

Recognition of Leases

Effective January 1, 2019 we adopted ASU 2016-02 Leases (Topic 842) using the modified retrospective approach.

We recognize an arrangement 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 recognize right-of-use (ROU) assets and the related lease liabilities on the statement of financial position for operating lease arrangements with a term of 12 months or longer. We do not separate non-lease components from the associated lease components of our lessee contracts and account for both components as a single lease component. We combine lease and non-lease components within a contract for operating lessor leases when certain conditions are met. ROU assets are assessed for impairment using the same approach as is applied for other long-lived assets, as described under the Impairment section of the Significant Accounting Policies Note 2 in the annual consolidated financial statements.

Lease liabilities and ROU assets require the use of judgment and estimates, which are applied in determining the term of a lease, appropriate discount rates, whether an arrangement contains a lease, whether there are any indicators of impairment for ROU assets and whether any ROU assets should be grouped with other long-lived assets for impairment testing.

In adopting Topic 842, we elected the package of practical expedients permitted under the transition guidance. 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. The application of the package of practical expedients also permits entities not to reassess whether any expired or existing contracts contain leases in accordance with the new guidance, lease classifications, and whether initial direct costs capitalized under current guidance continue to meet the definition of initial direct costs under the new guidance. We also elected the practical expedient related to land easements, allowing us to carry forward our accounting treatment for land easements on existing agreements that had commenced prior to January 1, 2019.

On January 1, 2019, ROU assets and corresponding lease liabilities of $771 million were recorded in connection with the adoption of Topic 842. When added to the $85 million of pre-existing liabilities relating to operating leases for which we no longer utilize the leased assets, total lease liabilities at January 1, 2019 were $856 million. All lease liabilities were measured using a weighted average discount rate of 4.32%. The adoption of this standard had no impact to the Consolidated Statements of Earnings, Comprehensive Income, Changes in Equity or Cash Flows during the period.

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FUTURE ACCOUNTING POLICY CHANGES

Clarifying Interaction between Collaborative Arrangements and Revenue from Contracts with Customers

In November 2018, ASU 2018-18 was issued to provide clarity on when transactions between entities in a collaborative arrangement should be accounted for under the new revenue standard, ASC 606. In determining whether transactions in collaborative arrangements should be accounted under the revenue standard, the update specifies that entities shall apply unit of account guidance to identify distinct goods or services and whether such goods and services are separately identifiable from other promises in the contract. ASU 2018-18 also precludes entities from presenting transactions with a collaborative partner which are not in scope of the new revenue standard together with revenue from contracts with customers. The accounting update is effective January 1, 2020 and early adoption is permitted. We are currently assessing the impact of the new standard on our consolidated financial statements.

Improvements to Related Party Guidance for Variable Interest Entities

ASU 2018-17 was issued in October 2018 to improve the related party guidance on determining whether fees paid to decision makers and service providers (“decision-maker fees”) are variable interests. Under the new guidance, reporting entities must consider indirect interests held through related parties in common control arrangements on a proportionate basis, rather than as the equivalent of a direct interest in its entirety, when determining if a decision maker’s fees constitute a variable interest. The accounting update is effective January 1, 2020 and must be applied on a retrospective basis. We are currently assessing the impact of the new standard on our consolidated financial statements.

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.

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 delay the recognition until it is probable a loss has been incurred. The accounting update adds a new impairment model, known as the current expected credit loss model, which is based on expected losses rather than incurred losses. Under the new guidance, an entity will recognize as an allowance its estimate of expected credit losses, which the Financial Accounting Standards Board believes will result in more timely recognition of such losses.

Further, ASU 2018-19 was issued in November 2018 to clarify that operating lease receivables should be accounted for under the new leases standard, ASC 842, and are not within the scope of ASC 326, Financial Instruments - Credit Losses. Both accounting updates are effective January 1, 2020. We are currently assessing the impact of the new standard on our consolidated financial statements.

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3. REVENUES

Effective January 1, 2019, we renamed the Green Power and Transmission segment to Renewable Power Generation and Transmission. The presentation of the prior years' tables has been revised in order to align with the current presentation.

REVENUE FROM CONTRACTS WITH CUSTOMERS

Major Products and Services

	Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution	Renewable Power Generation and Transmission	Energy Services	Eliminations and Other		Consolidated
Three months ended March 31, 2019
(millions of Canadian dollars)
Transportation revenues	2,214	1,137	249	—	—	—		3,600
Storage and other revenues	27	53	54	—	—	—		134
Gas gathering and processing revenues	—	116	—	—	—	—		116
Gas distribution revenue	—	—	1,856	—	—	—		1,856
Electricity and transmission revenues	—	—	—	50	—	—		50
Total revenue from contracts with customers	2,241	1,306	2,159	50	—	—		5,756
Commodity sales	—	—	—	—	6,632	—		6,632
Other revenues1,2	340	10	29	102	6	(19	)	468
Intersegment revenues	77	2	3	—	35	(117	)	—
Total revenues	2,658	1,318	2,191	152	6,673	(136	)	12,856

	Liquids Pipelines		Gas Transmission and Midstream	Gas Distribution	Renewable Power Generation and Transmission	Energy Services	Eliminations and Other		Consolidated
Three months ended March 31, 2018
(millions of Canadian dollars)
Transportation revenues	2,058		952	239	—	—	—		3,249
Storage and other revenues	40		60	66	—	—	—		166
Gas gathering and processing revenues	—		205	—	—	—	—		205
Gas distribution revenues	—		—	1,926	—	—	—		1,926
Electricity and transmission revenues	—		—	—	57	—	—		57
Commodity sales	—		693	—	—	—	—		693
Total revenue from contracts with customers	2,098		1,910	2,231	57	—	—		6,296
Commodity sales	—		—	—	—	6,575	—		6,575
Other revenues1, 2	(269	)	25	2	100	—	(3	)	(145	)
Intersegment revenues	80		2	4	—	57	(143	)	—
Total revenues	1,909		1,937	2,237	157	6,632	(146	)	12,726

1  Includes mark-to-market gains/(losses) from our hedging program.

2 Includes revenues from lease contracts, refer to Note 14 Leases.

We disaggregate revenues into categories which represent our principal performance obligations within each business segment because these revenues categories represent the most significant revenue streams in each segment and consequently are considered to be the most relevant revenues information for management to consider in evaluating performance.

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Contract Balances

	Receivables	Contract Assets	Contract Liabilities
(millions of Canadian dollars)
Balance as at December 31, 2018	1,929	191	1,297
Balance as at March 31, 2019	2,338	191	1,262

Contract receivables represent the amount of receivables derived from contracts with customers. Contract assets represent the amount of revenues 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 revenues. Revenues recognized during the three months ended March 31, 2019 included in contract liabilities at the beginning of the period is $92 million. Increases in contract liabilities from cash received, net of amounts recognized as revenues during the three months ended March 31, 2019 were $74 million.

Performance Obligations

There was no material revenues recognized in the three months ended March 31, 2019 from performance obligations satisfied in previous periods.

Revenues to be Recognized from Unfulfilled Performance Obligations

Total revenues from performance obligations expected to be fulfilled in future periods is $66.7 billion, of which $5.3 billion and $5.8 billion is expected to be recognized during the nine months ending December 31, 2019, and the year ending December 31, 2020, 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 revenues 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.

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Recognition and Measurement of Revenues

	Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution	Renewable Power Generation and Transmission	Energy Services	Consolidated
Three months ended March 31, 2019
(millions of Canadian dollars)
Revenues from products transferred at a point in time1	—	—	17	—	—	17
Revenues from products and services transferred over time2	2,241	1,306	2,142	50	—	5,739
Total revenue from contracts with customers	2,241	1,306	2,159	50	—	5,756

	Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution	Renewable Power Generation and Transmission	Energy Services	Consolidated
Three months ended March 31, 2018
(millions of Canadian dollars)
Revenues from products transferred at a point in time1	—	693	25	—	—	718
Revenues from products and services transferred over time2	2,098	1,217	2,206	57	—	5,578
Total revenue from contracts with customers	2,098	1,910	2,231	57	—	6,296

1  Revenues from sales of crude oil, natural gas and NGLs.

2  Revenues 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.

4. SEGMENTED INFORMATION

	Liquids Pipelines		Gas Transmission and Midstream		Gas Distribution		Renewable Power Generation and Transmission		Energy Services		Eliminations and Other		Consolidated
Three months ended March 31, 2019
(millions of Canadian dollars)
Revenues	2,658		1,318		2,191		152		6,673		(136	)	12,856
Commodity and gas distribution costs	(6	)	—		(1,264	)	(1	)	(6,629	)	128		(7,772	)
Operating and administrative	(801	)	(513	)	(294	)	(42	)	(33	)	58		(1,625	)
Income/(loss) from equity investments	197		197		11		14		(7	)	1		413
Other income	24		18		18		1		2		197		260
Earnings before interest, income taxes, and depreciation and amortization	2,072		1,020		662		124		6		248		4,132
Depreciation and amortization													(840	)
Interest expense													(685	)
Income tax expense													(584	)
Earnings													2,023
Capital expenditures1	1,020		394		173		14		1		25		1,627

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	Liquids Pipelines		Gas Transmission and Midstream		Gas Distribution		Renewable Power Generation and Transmission		Energy Services		Eliminations and Other		Consolidated
Three months ended March 31, 2018
(millions of Canadian dollars)
Revenues	1,909		1,937		2,237		157		6,632		(146	)	12,726
Commodity and gas distribution costs	(4	)	(620	)	(1,388	)	—		(6,455	)	146		(8,321	)
Operating and administrative	(747	)	(507	)	(248	)	(30	)	(12	)	(97	)	(1,641	)
Impairment of long-lived assets	(144	)	(913	)	—		—		—		(5	)	(1,062	)
Income from equity investments	131		208		17		(25	)	4		—		335
Other income/(expense)	11		21		18		7		—		(177	)	(120	)
Earnings/(loss) before interest, income taxes, and depreciation and amortization	1,156		126		636		109		169		(279	)	1,917
Depreciation and amortization													(824	)
Interest expense													(656	)
Income tax recovery													73
Earnings													510
Capital expenditures1	615		825		183		14		—		6		1,643

1  Includes allowance for equity funds used during construction.

5. EARNINGS PER COMMON SHARE AND DIVIDENDS PER 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 6 million and 13 million for the three months ended March 31, 2019 and 2018, 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 March 31,
	2019	2018
(number of common shares in millions)
Weighted average shares outstanding	2,016	1,685
Effect of dilutive options	3	4
Diluted weighted average shares outstanding	2,019	1,689

For the three months ended March 31, 2019 and 2018, 10,495,198 and 29,882,142, respectively, anti-dilutive stock options with a weighted average exercise price of $55.32 and $49.80, respectively, were excluded from the diluted earnings per common share calculation.

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DIVIDENDS PER SHARE

On April 23, 2019, our Board of Directors declared the following quarterly dividends. All dividends are payable on June 1, 2019, to shareholders of record on May 15, 2019.

	Dividend per share
Common Shares		$0.73800
Preference Shares, Series A		$0.34375
Preference Shares, Series B		$0.21340
Preference Shares, Series C1		$0.25395
Preference Shares, Series D		$0.27875
Preference Shares, Series F		$0.29306
Preference Shares, Series H		$0.27350
Preference Shares, Series J		US$0.30540
Preference Shares, Series L		US$0.30993
Preference Shares, Series N		$0.31788
Preference Shares, Series P2		$0.27369
Preference Shares, Series R		$0.25000
Preference Shares, Series 1		US$0.37182
Preference Shares, Series 3		$0.25000
Preference Shares, Series 53		US$0.33596
Preference Shares, Series 74		$0.27806
Preference Shares, Series 9		$0.27500
Preference Shares, Series 11		$0.27500
Preference Shares, Series 13		$0.27500
Preference Shares, Series 15		$0.27500
Preference Shares, Series 17		$0.32188
Preference Shares, Series 19		$0.30625

1 The quarterly dividend per share paid on Series C was decreased to $0.25395 from $0.25459 on March 1, 2019, due to reset on a quarterly basis following the date of issuance of the Series C Preference Shares.

2 The quarterly dividend per share paid on Series P was increased to $0.27369 from $0.25000 on March 1, 2019, due to reset of the annual dividend on March 1, 2019, and every five years thereafter.

3 The quarterly dividend per share paid on Series 5 was increased to US$0.33596 from US$0.27500 on March 1, 2019, due to reset of the annual dividend on March 1, 2019, and every five years thereafter.

4 The quarterly dividend per share paid on Series 7 was increased to $0.27806 from $0.27500 on March 1, 2019, due to reset of the annual dividend on March 1, 2019, and every five years thereafter.

6. ACQUISITIONS AND DISPOSITIONS

ACQUISITIONS

In January 2019, through our wholly-owned subsidiary Enbridge Pipelines (Athabasca) Inc., we acquired 75 kilometers of existing pipeline and tankage infrastructure (collectively, the Cheecham Assets) from Athabasca Oil Corporation for cash consideration of approximately $265 million, all of which was allocated to property, plant and equipment. The Cheecham Assets are a part of our Liquids Pipelines segment. The cash consideration is included in capital expenditures on our Consolidated Statements of Cash Flows for the three months ended March 31, 2019.

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ASSETS HELD FOR SALE

Enbridge Gas New Brunswick

In December 2018, we entered into an agreement for the sale of Enbridge Gas New Brunswick Limited Partnership and Enbridge Gas New Brunswick Inc. (collectively, EGNB) to Liberty Utilities (Canada) LP, a wholly-owned subsidiary of Algonquin Power and Utilities Corp., for a cash purchase price of $331 million, subject to customary closing adjustments. EGNB operates and maintains natural gas distribution pipelines in southern New Brunswick, and its related assets are included in our Gas Distribution segment. Subject to certain regulatory approvals and customary closing conditions, the transaction is expected to close in 2019.

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. On October 1, 2018, we closed the sale of the provincially regulated facilities for proceeds of approximately $2.5 billion. Subject to certain regulatory approvals and customary closing conditions, the sale of the federally regulated facilities is expected to close in mid-2019 for proceeds of approximately $1.8 billion.

Line 10 Crude Oil Pipeline

In the first quarter of 2018, we satisfied the conditions 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 wholly-owned subsidiaries, Enbridge Pipelines Inc. and Enbridge Energy Partners, L.P. (EEP), own the Canadian and United States portions of Line 10. Subject to certain regulatory approvals and customary closing conditions, the transaction is expected to close in 2019.

St. Lawrence Gas Company, Inc.

In August 2017, we entered into an agreement to sell the issued and outstanding shares of St. Lawrence Gas Company, Inc. for cash proceeds of approximately $94 million (US$70 million). Subject to regulatory approval and certain pre-closing conditions, the transaction is expected to close in 2019.

The table below summarizes the presentation of net assets held for sale in our Consolidated Statements of Financial Position:

	March 31, 2019		December 31, 2018
(millions of Canadian dollars)
Accounts receivable and other (current assets held for sale)	101		117
Deferred amounts and other assets (long-term assets held for sale)1	2,415		2,383
Accounts payable and other (current liabilities held for sale)	(55	)	(63	)
Other long-term liabilities (long-term liabilities held for sale)	(99	)	(96	)
Net assets held for sale	2,362		2,341

1 Included within Deferred amounts and other assets at March 31, 2019 and December 31, 2018 respectively is property, plant and equipment of $2.2 billion and $2.1 billion.

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7. VARIABLE INTEREST ENTITIES

Gray Oak Holdings LLC

In December 2018, Enbridge acquired an effective 22.8% interest in the Gray Oak crude oil pipeline through acquisition of a 35% membership interest in Gray Oak Holdings LLC (Gray Oak Holdings), which will construct and operate the Gray Oak crude oil pipeline from Texas to the Gulf coast of the United States.

Gray Oak Holdings is a variable interest entity (VIE) as it does not have sufficient equity at risk to finance its activities and requires subordinated financial support from Enbridge and other partners. We have determined that we do not have the power to direct the activities of Gray Oak Holdings that most significantly impact the VIE’s economic performance. Specifically, the power to direct the activities of the VIE is shared amongst the partners. Each partner has representatives that make up an executive committee that makes the significant decisions for the VIE and none of the partners may make major decisions unilaterally. Therefore, the VIE is accounted for as an unconsolidated VIE.

As at March 31, 2019 and December 31, 2018, the carrying amount of the investment in Gray Oak Holdings was $455 million and nil, respectively. Enbridge's maximum exposure to loss as at March 31, 2019 was approximately $931 million and primarily consists of our portion of the project construction costs.

On March 29, 2019, we and our partners of the Gray Oak Holdings investment executed a loan agreement to loan up to a maximum of US$1,230 million to the investment to finance the construction of the Gray Oak crude oil pipeline. The amount committed by us is US$280 million, which is proportionate to our effective ownership interest. Loans under this agreement are due on March 31, 2022, with early repayment permitted.

8. DEBT

On January 22, 2019, Enbridge entered into supplemental indentures with its wholly-owned subsidiaries, Spectra Energy Partners, LP (SEP) and EEP (together, the Partnerships), pursuant to which Enbridge fully and unconditionally guaranteed, on a senior unsecured basis, the payment obligations of the Partnerships with respect to the outstanding series of notes issued under the respective indentures of the Partnerships. Concurrently, the Partnerships entered into a subsidiary guarantee agreement pursuant to which they guaranteed, on a senior unsecured basis, the outstanding series of senior notes of Enbridge. See Note 16 - Condensed Consolidating Financial Information for further discussion.

CREDIT FACILITIES

The following table provides details of our committed credit facilities as at March 31, 2019:

	Maturity	Total Facilities	Draws1	Available
(millions of Canadian dollars)
Enbridge Inc.	2019-2024	6,137	4,319	1,818
Enbridge (U.S.) Inc.	2021-2024	7,348	5,252	2,096
Enbridge Pipelines Inc.	2020	3,000	1,513	1,487
Enbridge Gas Inc.	2019-2021	2,017	879	1,138
Total committed credit facilities		18,502	11,963	6,539

1    Includes facility draws and commercial paper issuances that are back-stopped by credit facilities.

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On February 7, 2019 and February 8, 2019, we terminated certain Canadian and United States dollar credit facilities, including facilities held by Enbridge, EGI, EEP and SEP. We also increased existing facilities or obtained new facilities to replace the terminated ones under Enbridge, Enbridge (U.S.) Inc. and EGI. As a result, our total credit facility availability increased by approximately $444 million.

In addition to the committed credit facilities noted above, we maintain $800 million of uncommitted demand credit facilities, of which $516 million were unutilized as at March 31, 2019. As at December 31, 2018, we had $807 million of uncommitted credit facilities, of which $548 million were unutilized.

Our credit facilities carry a weighted average standby fee of 0.1% 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 2020 to 2024.

As at March 31, 2019 and December 31, 2018, commercial paper and credit facility draws, net of short-term borrowings and non-revolving credit facilities that mature within one year of $10,689 million and $7,967 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 three months ended March 31, 2019, we completed the following long-term debt issuances:

Company	Issue Date		Principal Amount
(millions of Canadian dollars)
Enbridge Pipelines Inc.
	February 2019	3.52% medium-term notes due February 2029	$600
	February 2019	4.33% medium-term notes due February 2049	$600

LONG-TERM DEBT REPAYMENTS

During the three months ended March 31, 2019, we completed the following long-term debt repayments:

Company	Retirement/ Repayment Date		Principal Amount
(millions of Canadian dollars, unless otherwise stated)
Enbridge Inc.
Repayment
	February 2019	4.10% medium-term notes	$300
Enbridge Energy Partners, L.P.
Redemption
	February 2019	8.05% fixed/floating rate junior subordinated notes due 2067	US$400
Repayment
	March 2019	9.88% senior notes	US$500
Westcoast Energy Inc.
Repayment
	January 2019	5.60% medium-term notes	$250
	January 2019	5.60% medium-term notes	$50

SUBORDINATED TERM NOTES

As at March 31, 2019 and December 31, 2018, our fixed-to-floating subordinated term notes had a principal value of $6,675 million and $7,317 million, respectively.

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FAIR VALUE ADJUSTMENT

As at March 31, 2019, the net fair value adjustment for total debt assumed in the Spectra Energy merger transaction was $930 million. During the three months ended March 31, 2019, the amortization of the fair value adjustment, recorded as a reduction to Interest expense in the Consolidated Statements of Earnings, was $17 million.

DEBT COVENANTS

Our credit facility agreements and term debt indentures include standard events of default and covenant provisions whereby accelerated repayment and/or termination of the agreements may result if we were to default on payment or violate certain covenants. As at March 31, 2019, we were in compliance with all debt covenants.

9. COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME

Changes in Accumulated Other Comprehensive Income (AOCI) attributable to our common shareholders for the three months ended March 31, 2019 and 2018 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, 2019	(770	)	(598	)	4,323		34	(317	)	2,672
Other comprehensive income/(loss) retained in AOCI	(312	)	109		(1,242	)	8	—		(1,437	)
Other comprehensive (income)/loss reclassified to earnings
Interest rate contracts1	32		—		—		—	—		32
Foreign exchange contracts3	2		—		—		—	—		2
Other contracts4	(9	)	—		—		—	—		(9	)
Amortization of pension and OPEB actuarial loss and prior service costs5	—		—		—		—	53		53
	(287	)	109		(1,242	)	8	53		(1,359	)
Tax impact
Income tax on amounts retained in AOCI	121		(15	)	—		4	—		110
Income tax on amounts reclassified to earnings	(14	)	—		—		—	(15	)	(29	)
	107		(15	)	—		4	(15	)	81
Other	—		—		—		—	55		55
Balance as at March 31, 2019	(950	)	(504	)	3,081		46	(224	)	1,449

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	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	70		(213	)	1,425	2	—		1,284
Other comprehensive (income)/loss reclassified to earnings
Interest rate contracts1	28		—		—	—	—		28
Commodity contracts2	(1	)	—		—	—	—		(1	)
Foreign exchange contracts3	4		—		—	—	—		4
Other contracts4	9		—		—	—	—		9
Amortization of pension and OPEB actuarial loss and prior service costs5	—		—		—	—	(38	)	(38	)
	110		(213	)	1,425	2	(38	)	1,286
Tax impact
Income tax on amounts retained in AOCI	(9	)	29		—	8	—		28
Income tax on amounts reclassified to earnings	(11	)	—		—	—	(1	)	(12	)
	(20	)	29		—	8	(1	)	16
Balance as at March 31, 2018	(554	)	(323	)	1,502	20	(316	)	329

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.

10. NONCONTROLLING INTERESTS

Preferred Shares Redemption

On March 20, 2019, Westcoast Energy Inc. exercised its right to redeem all of its outstanding 5.5% Cumulative Redeemable First Preferred Shares, Series 7 ("Series 7 Shares") and all of its outstanding 5.6% Cumulative Redeemable First Preferred Shares, Series 8 ("Series 8 Shares") at a price of $25.00 per Series 7 Share and $25.00 per Series 8 Share, respectively, for a total payment of $300 million. In addition, payment of $4 million was made for all accrued and unpaid dividends. As a result, we recorded a $300 million decrease in Noncontrolling interests.

11. RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

MARKET RISK

Our earnings, cash flows and Other Comprehensive Income (OCI) are subject to movements in foreign exchange rates, interest rates, commodity prices and our share price (collectively, market 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 is used to hedge anticipated foreign currency denominated revenues and expenses, and to manage variability in cash flows. We hedge

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certain net investments in United States dollar denominated investments and subsidiaries using foreign currency derivatives and United States dollar denominated debt.

Interest Rate Risk

Our earnings and cash flows are exposed to short-term interest rate variability due to the regular repricing of our variable rate debt, primarily commercial paper. Pay fixed-receive floating interest rate swaps may be used to hedge against the effect of future interest rate movements. We have implemented a program to significantly mitigate the impact of short-term interest rate volatility on interest expense via execution of floating to fixed interest rate swaps with an average swap rate of 2.8%.

We are exposed to changes in the fair value of fixed rate debt that arise as a result of the changes in market interest rates. Pay floating-receive fixed interest rate swaps are used, when applicable, to hedge against future changes to the fair value of fixed rate debt which mitigates the impact of fluctuations in the fair value of fixed rate debt via execution of fixed to floating interest rate swaps. As at March 31, 2019, we do not have any pay floating-receive fixed interest rate swaps outstanding.

Our earnings and cash flows are also exposed to variability in longer term interest rates ahead of anticipated fixed rate term debt issuances. Forward starting interest rate swaps are used to hedge against the effect of future interest rate movements. We have established a program within some of our subsidiaries to mitigate our exposure to long-term interest rate variability on select forecast term debt issuances via execution of floating to fixed interest rate swaps with an average swap rate of 3%.

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We also monitor our debt portfolio mix of fixed and variable rate debt instruments to manage a consolidated portfolio of floating rate debt within the Board of Directors approved policy limit of a maximum of 30% of floating rate debt as a percentage of total debt outstanding. We primarily use qualifying derivative instruments to manage interest rate risk.

Commodity Price Risk

Our earnings and cash flows are exposed to changes in commodity prices as a result of our ownership interests in certain assets and investments, as well as through the activities of our energy services subsidiaries. These commodities include natural gas, crude oil, power and NGL. We employ financial and physical derivative instruments to fix a portion of the variable price exposures that arise from physical transactions involving these commodities. We use primarily non-qualifying derivative instruments to manage commodity price risk.

Equity Price Risk

Equity price risk is the risk of earnings fluctuations due to changes in our share price. We have exposure to our own common share price through the issuance of various forms of stock-based compensation, which affect earnings through revaluation of the outstanding units every period. We use equity derivatives to manage the earnings volatility derived from one form of stock-based compensation, restricted share units. We use a combination of qualifying and non-qualifying derivative instruments to manage equity price risk.

TOTAL DERIVATIVE INSTRUMENTS

The following table summarizes the Consolidated Statements of Financial Position location and carrying value of our derivative instruments.

We generally have a policy of entering into individual International Swaps and Derivatives Association, Inc. agreements, or other similar derivative agreements, with the majority of our financial derivative counterparties. These agreements provide for the net settlement of derivative instruments outstanding with specific counterparties in the event of bankruptcy or other significant credit events, and reduce 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.

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March 31, 2019	Derivative Instruments Used as Cash Flow Hedges		Derivative Instruments Used as Net Investment 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	—		—		26		26		(26	)	—
Interest rate contracts	7		—		—		7		—		7
Commodity contracts	1		—		171		172		(77	)	95
	8		—		197		205		(103	)	102
Deferred amounts and other assets
Foreign exchange contracts	13		—		37		50		(36	)	14
Interest rate contracts	—		—		—		—		—		—
Commodity contracts	17		—		18		35		(22	)	13
Other contracts	1		—		1		2		—		2
	31		—		56		87		(58	)	29
Accounts payable and other
Foreign exchange contracts	(5	)	—		(501	)	(506	)	26		(480	)
Interest rate contracts	(150	)	—		—		(150	)	—		(150	)
Commodity contracts	—		—		(289	)	(289	)	77		(212	)
Other contracts	—		—		(1	)	(1	)	—		(1	)
	(155	)	—		(791	)	(946	)	103		(843	)
Other long-term liabilities
Foreign exchange contracts	—		(14	)	(1,666	)	(1,680	)	36		(1,644	)
Interest rate contracts	(374	)	—		—		(374	)	—		(374	)
Commodity contracts	—		—		(152	)	(152	)	22		(130	)
Other contracts	—		—		—		—		—		—
	(374	)	(14	)	(1,818	)	(2,206	)	58		(2,148	)
Total net derivative asset/(liability)
Foreign exchange contracts	8		(14	)	(2,104	)	(2,110	)	—		(2,110	)
Interest rate contracts	(517	)	—		—		(517	)	—		(517	)
Commodity contracts	18		—		(252	)	(234	)	—		(234	)
Other contracts	1		—		—		1		—		1
	(490	)	(14	)	(2,356	)	(2,860	)	—		(2,860	)

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December 31, 2018	Derivative Instruments Used as Cash Flow Hedges		Derivative Instruments Used as Net Investment 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	—		—		47		47		(37	)	10
Interest rate contracts	22		—		—		22		(2	)	20
Commodity contracts	2		—		427		429		(114	)	315
	24		—		474		498		(153	)	345
Deferred amounts and other assets
Foreign exchange contracts	23		—		39		62		(39	)	23
Interest rate contracts	5		—		—		5		—		5
Commodity contracts	19		—		33		52		(21	)	31
	47		—		72		119		(60	)	59
Accounts payable and other
Foreign exchange contracts	(5	)	—		(610	)	(615	)	37		(578	)
Interest rate contracts	(163	)	—		(178	)	(341	)	2		(339	)
Commodity contracts	—		—		(273	)	(273	)	114		(159	)
Other contracts	(1	)	—		(4	)	(5	)	—		(5	)
	(169	)	—		(1,065	)	(1,234	)	153		(1,081	)
Other long-term liabilities
Foreign exchange contracts	(1	)	(15	)	(2,196	)	(2,212	)	39		(2,173	)
Interest rate contracts	(201	)	—		—		(201	)	—		(201	)
Commodity contracts	—		—		(178	)	(178	)	21		(157	)
Other contracts	(1	)	—		(1	)	(2	)	—		(2	)
	(203	)	(15	)	(2,375	)	(2,593	)	60		(2,533	)
Total net derivative asset/(liability)
Foreign exchange contracts	17		(15	)	(2,720	)	(2,718	)	—		(2,718	)
Interest rate contracts	(337	)	—		(178	)	(515	)	—		(515	)
Commodity contracts	21		—		9		30		—		30
Other contracts	(2	)	—		(5	)	(7	)	—		(7	)
	(301	)	(15	)	(2,894	)	(3,210	)	—		(3,210	)

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The following table summarizes the maturity and notional principal or quantity outstanding related to our derivative instruments.

March 31, 2019	2019		2020		2021		2022		2023		Thereafter1
Foreign exchange contracts - United States dollar forwards - purchase (millions of United States dollars)	895		1		—		—		—		—
Foreign exchange contracts - United States dollar forwards - sell (millions of United States dollars)	3,839		4,893		3,608		1,944		1,804		1,856
Foreign exchange contracts - British pound (GBP) forwards - sell (millions of GBP)	86		25		27		28		29		120
Foreign exchange contracts - Euro forwards - purchase (millions of Euro)	168		—		—		—		—		—
Foreign exchange contracts - Euro forwards - sell (millions of Euro)	—		23		94		94		92		606
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)	6,629		6,178		4,142		407		48		156
Interest rate contracts - long-term receive fixed rate (millions of Canadian dollars)	—		—		—		—		—		—
Interest rate contracts - long-term debt pay fixed rate (millions of Canadian dollars)	2,537		3,142		1,584		—		—		—
Equity contracts (millions of Canadian dollars)	32		20		—		—		—		—
Commodity contracts - natural gas (billions of cubic feet)	(75	)	(15	)	—		(84	)	1		—
Commodity contracts - crude oil (millions of barrels)	4		(2	)	—		—		—		—
Commodity contracts - NGL (millions of barrels)	1		—		—		—		—		—
Commodity contracts - power (megawatt per hour) (MW/H))	98		80		(3	)	(43	)	(43	)	(43	)

1 As at March 31, 2019, thereafter includes an average net purchase/(sell) of power of (43) MW/H for 2024 through 2025.

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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 March 31,
	2019		2018
(millions of Canadian dollars)
Amount of unrealized gain/(loss) recognized in OCI
Cash flow hedges
Foreign exchange contracts	(10	)	21
Interest rate contracts	(296	)	100
Commodity contracts	(3	)	(2	)
Other contracts	12		(14	)
Net investment hedges
Foreign exchange contracts	1		16
	(296	)	121
Amount of (gain)/loss reclassified from AOCI to earnings
Foreign exchange contracts1	2		(1	)
Interest rate contracts2	32		40
Commodity contracts3	—		(1	)
Other contracts4	(9	)	9
	25		47

1 Reported within Transportation and other services revenues and Net foreign currency gain/(loss) in the Consolidated Statements of Earnings.

2 Reported within Interest expense in the Consolidated Statements of Earnings. Effective January 1, 2019 hedge ineffectiveness will no longer be measured or recorded. See Note 2 Changes in Accounting Policies.

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 $36 million of AOCI related to unrealized cash flow hedges will be reclassified to earnings in the next 12 months. Actual amounts reclassified to earnings depend on the foreign exchange rates, interest rates and commodity prices in effect when derivative contracts that are currently outstanding mature. For all forecasted transactions, the maximum term over which we are hedging exposures to the variability of cash flows is 33 months as at March 31, 2019.

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.

	Three months ended March 31,
	20191	2018
(millions of Canadian dollars)
Unrealized gain/(loss) on derivative	—	(8	)
Unrealized gain/(loss) on hedged item	—	8
Realized gain/(loss) on derivative	—	(3	)
Realized gain/(loss) on hedged item	—	3

1. For the three months ended March 31, 2019, there are no outstanding fair value hedges.

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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 March 31,
	2019		2018
(millions of Canadian dollars)
Foreign exchange contracts1	616		(424	)
Interest rate contracts2	178		(2	)
Commodity contracts3	(261	)	175
Other contracts4	5		(9	)
Total unrealized derivative fair value gain/(loss), net	538		(260	)

1 For the respective three months ended periods, reported within Transportation and other services revenues (2019 - $352 million gain; 2018 - $297 million loss) and Net foreign currency gain/(loss) (2019 - $264 million gain; 2018 - $127 million loss) in the Consolidated Statements of Earnings.

2 Reported as an (increase)/decrease within Interest expense in the Consolidated Statements of Earnings.

3 For the respective three months ended periods, reported within Transportation and other services revenues (2019 - $26 million loss; 2018 - $1 million loss), Commodity sales (2019 - $642 million loss; 2018 - $82 million gain), Commodity costs (2019 - $398 million gain; 2018 - $84 million gain) and Operating and administrative expense (2019 - $9 million gain; 2018 - $10 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 March 31, 2019. As a result, all credit facilities are available to us and the banks are obligated to fund and have been funding us under the terms of the facilities.

CREDIT RISK

Entering into derivative instruments may result in exposure to credit risk from the possibility that a counterparty will default on its contractual obligations. In order to mitigate this risk, we enter into risk management transactions primarily with institutions that possess strong investment grade credit ratings. Credit risk relating to derivative counterparties is mitigated through maintenance and monitoring of credit exposure limits and contractual requirements, netting arrangements, and ongoing monitoring of counterparty credit exposure using external credit rating services and other analytical tools.

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We have credit concentrations and credit exposure, with respect to derivative instruments, in the following counterparty segments:

	March 31, 2019	December 31, 2018
(millions of Canadian dollars)
Canadian financial institutions	21	28
United States financial institutions	51	107
European financial institutions	58	84
Asian financial institutions	—	6
Other1	132	337
	262	562

1 Other is comprised of commodity clearing house and physical natural gas and crude oil counterparties.

As at March 31, 2019, we provided letters of credit totaling nil in lieu of providing cash collateral to our counterparties pursuant to the terms of the relevant International Swaps and Derivatives Association (ISDA) agreements. We held no cash collateral on derivative asset exposures as at March 31, 2019 and December 31, 2018.

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 EGI, 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.

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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.

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We have categorized our derivative assets and liabilities measured at fair value as follows:

March 31, 2019	Level 1		Level 2		Level 3		Total Gross Derivative Instruments
(millions of Canadian dollars)
Financial assets
Current derivative assets
Foreign exchange contracts	—		26		—		26
Interest rate contracts	—		7		—		7
Commodity contracts	3		10		159		172
	3		43		159		205
Long-term derivative assets
Foreign exchange contracts	—		50		—		50
Commodity contracts	—		13		22		35
Other contracts	—		2		—		2
	—		65		22		87
Financial liabilities
Current derivative liabilities
Foreign exchange contracts	—		(506	)	—		(506	)
Interest rate contracts	—		(150	)	—		(150	)
Commodity contracts	(7	)	(16	)	(266	)	(289	)
Other contracts	—		(1	)	—		(1	)
	(7	)	(673	)	(266	)	(946	)
Long-term derivative liabilities
Foreign exchange contracts	—		(1,680	)	—		(1,680	)
Interest rate contracts	—		(374	)	—		(374	)
Commodity contracts	—		(15	)	(137	)	(152	)
	—		(2,069	)	(137	)	(2,206	)
Total net financial liabilities
Foreign exchange contracts	—		(2,110	)	—		(2,110	)
Interest rate contracts	—		(517	)	—		(517	)
Commodity contracts	(4	)	(8	)	(222	)	(234	)
Other contracts	—		1		—		1
	(4	)	(2,634	)	(222	)	(2,860	)

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December 31, 2018	Level 1		Level 2		Level 3		Total Gross Derivative Instruments
(millions of Canadian dollars)
Financial assets
Current derivative assets
Foreign exchange contracts	—		47		—		47
Interest rate contracts	—		22		—		22
Commodity contracts	24		45		360		429
	24		114		360		498
Long-term derivative assets
Foreign exchange contracts	—		62		—		62
Interest rate contracts	—		5		—		5
Commodity contracts	—		30		22		52
	—		97		22		119
Financial liabilities
Current derivative liabilities
Foreign exchange contracts	—		(615	)	—		(615	)
Interest rate contracts	—		(341	)	—		(341	)
Commodity contracts	(7	)	(28	)	(238	)	(273	)
Other contracts	—		(5	)	—		(5	)
	(7	)	(989	)	(238	)	(1,234	)
Long-term derivative liabilities
Foreign exchange contracts	—		(2,212	)	—		(2,212	)
Interest rate contracts	—		(201	)	—		(201	)
Commodity contracts	—		(23	)	(155	)	(178	)
Other contracts	—		(2	)	—		(2	)
	—		(2,438	)	(155	)	(2,593	)
Total net financial liabilities
Foreign exchange contracts	—		(2,718	)	—		(2,718	)
Interest rate contracts	—		(515	)	—		(515	)
Commodity contracts	17		24		(11	)	30
Other contracts	—		(7	)	—		(7	)
	17		(3,216	)	(11	)	(3,210	)

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The significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments were as follows:

March 31, 2019	Fair Value		Unobservable Input	Minimum Price	Maximum Price	Weighted Average Price	Unit of Measurement
(fair value in millions of Canadian dollars)
Commodity contracts - financial1
Natural gas	(18	)	Forward gas price	2.55	5.17	3.47	$/mmbtu2
Crude	38		Forward crude price	42.96	166.19	69.21	$/barrel
Power	(82	)	Forward power price	30.79	71.28	50.21	$/MW/H
Commodity contracts - physical1
Natural gas	(125	)	Forward gas price	1.22	5.17	2.25	$/mmbtu2
Crude	(37	)	Forward crude price	33.12	127.36	76.83	$/barrel
NGL	2		Forward NGL price	0.17	1.11	0.37	$/gallon
	(222	)

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:

	Three months ended March 31,
	2019		2018
(millions of Canadian dollars)
Level 3 net derivative liability at beginning of period	(11	)	(387	)
Total gain/(loss)
Included in earnings1	(52	)	31
Included in OCI	(3	)	(3	)
Settlements	(156	)	154
Level 3 net derivative liability at end of period	(222	)	(205	)

1 Reported within Transportation and other services revenues, Commodity costs and Operating and administrative expense in the Consolidated Statements of Earnings.

Our policy is to recognize transfers as at the last day of the reporting period. There were no transfers between levels as at March 31, 2019 or December 31, 2018.

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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 (if any), plus or minus changes resulting from observable price changes in orderly transactions for an identical or similar investment of the same issuer. The carrying value of FVMA other long-term investments totaled $101 million and $102 million as at March 31, 2019 and December 31, 2018, respectively.

We have Restricted long-term investments held in trust totaling $356 million and $323 million as at March 31, 2019 and December 31, 2018, respectively, which are recognized at fair value.

We have a held to maturity preferred share investment carried at its amortized cost of $582 million and $478 million as at March 31, 2019 and December 31, 2018, respectively. These preferred shares are entitled to a cumulative preferred dividend based on the yield of 10-year Government of Canada bonds plus a margin of 4.38%. The fair value of this preferred share investment approximates its face value of $582 million and $580 million as at March 31, 2019 and December 31, 2018 respectively.

As at March 31, 2019 and December 31, 2018, our long-term debt had a carrying value of $65.3 billion and $63.9 billion, respectively, before debt issuance costs and a fair value of $68.9 billion and $64.4 billion, respectively. We also have noncurrent notes receivable carried at book value recorded in Deferred amounts and other assets in the Consolidated Statements of Financial Position. As at March 31, 2019 and December 31, 2018, the noncurrent notes receivable had a carrying value of $95 million and $97 million, respectively, and a fair value of $95 million and $97 million, respectively.

The fair value of other financial assets and liabilities other than derivative instruments, other long-term investments, restricted long-term investments, long-term debt and non-current notes receivable described above approximate their cost due to the short period to maturity.

NET INVESTMENT HEDGES

We have designated a portion of our United States dollar denominated debt, as well as a portfolio of foreign exchange forward contracts, as a hedge of our net investment in United States dollar denominated investments and subsidiaries.

During the three months ended March 31, 2019 and 2018, we recognized an unrealized foreign exchange gain of $108 million and an unrealized foreign exchange loss of $194 million, respectively, on the translation of United States dollar denominated debt and unrealized gains of $1 million and $15 million, respectively, on the change in fair value of our outstanding foreign exchange forward contracts in OCI. During the three months ended March 31, 2019 and 2018, we recognized realized losses of nil and $23 million, respectively, in OCI associated with the settlement of foreign exchange forward contracts and recognized realized losses of nil and $11 million, respectively, in OCI associated with the settlement of United States dollar denominated debt that had matured during the period. There was no ineffectiveness during the three months ended March 31, 2019 and 2018.

12. INCOME TAXES

The effective income tax rates for the three months ended March 31, 2019 and 2018 were 22.4% and (16.7)%, respectively. The period-over-period increase in the effective income tax rate is due to the effects of rate-regulated accounting for income taxes and other permanent items relative to the increase in earnings for the three months ended March 31, 2019. Also contributing to the period-over-period increase in the effective income tax rate was the buy-in of our United States sponsored vehicles which results in Enbridge being taxed on all of our United States sponsored vehicle earnings rather than on just our proportionate share.

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13. PENSION AND OTHER POSTRETIREMENT BENEFITS

	Three months ended March 31,
	2019		2018
(millions of Canadian dollars)
Service cost	51		65
Interest cost	51		45
Expected return on plan assets	(84	)	(82	)
Amortization of actuarial loss	8		7
Amortization of prior service costs	(1	)	(1	)
Net periodic benefit costs	25		34

14. LEASES

We incur operating lease expense related primarily to real estate, pipelines, storage and equipment. Our operating leases have remaining lease terms of one month to 29 years.

For the three months ended March 31, 2019, we incurred operating lease expenses of $28 million. Operating lease expenses are reported under Operating and administrative expenses on the Consolidated Statements of Earnings.

For the three months ended March 31, 2019, operating lease payments to settle lease liabilities were $31 million. Operating lease payments are reported under operating activities in the Consolidated Statements of Cash Flows.

Supplemental Statements of Financial Position Information

	March 31, 2019		January 1, 2019
(millions of Canadian dollars, except lease term and discount rate)
Operating leases
Operating lease right-of-use assets, net1	745		771
Operating lease liabilities - current2	67		86
Operating lease liabilities - long-term3	757		770
Total operating lease liabilities	824		856
Weighted average remaining lease term
Operating leases	14 years		14 years
Weighted average discount rate
Operating leases	4.3	%	4.3	%

1 Right-of-use assets are reported under Deferred amounts and other assets in the Consolidated Statements of Financial Position.

2 Current lease liabilities are reported under Accounts payable and other in the Consolidated Statements of Financial Position.

3 Long-term lease liabilities are reported under Other long-term liabilities in the Consolidated Statements of Financial Position.

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As at March 31, 2019, we have operating lease commitments as detailed below:

	Operating leases
(millions of Canadian dollars)
20191	83
2020	116
2021	94
2022	89
2023	79
Thereafter	663
Total undiscounted lease payments	1,124
Less imputed interest	(300	)
Total operating lease commitments	824

1 For the nine months remaining in the 2019 fiscal year.

LESSOR

We have operating leases primarily related to natural gas and crude oil storage and processing facilities, rail cars, and wind power generation assets. Our leases have remaining lease terms of 9 months to 24 years.

	Three months ended March 31, 2019
(millions of Canadian dollars)
Operating lease income	64
Variable lease income	100
Total lease income	164

The following table sets out future minimum lease payments expected to be received under lease contracts where we are the lessor:

	Operating leases
(millions of Canadian dollars)
20191	192
2020	216
2021	189
2022	186
2023	178
Thereafter	2,395
Total undiscounted lease payments	3,356

1 For the nine months remaining in the 2019 fiscal year.

15. CONTINGENCIES

We and our subsidiaries 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.

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TAX MATTERS

We and our subsidiaries maintain tax liabilities related to uncertain tax positions. While fully supportable in our view, these tax positions, if challenged by tax authorities, may not be fully sustained on review.

16. CONDENSED CONSOLIDATING FINANCIAL INFORMATION

On January 22, 2019, Enbridge entered into supplemental indentures with its wholly-owned subsidiaries, the Partnerships, pursuant to which Enbridge fully and unconditionally guaranteed, on a senior unsecured basis, the payment obligations of the Partnerships with respect to the outstanding series of notes issued under the respective indentures of the Partnerships. Concurrently, the Partnerships entered into a subsidiary guarantee agreement pursuant to which they guaranteed, on a senior unsecured basis, the outstanding series of senior notes of Enbridge. As a result of the guarantees, holders of any of the outstanding guaranteed notes of the Partnerships are in the same position with respect to the net assets, income and cash flows of Enbridge as holders of Enbridge's outstanding guaranteed notes, and vice versa. Other than the Partnerships, Enbridge subsidiaries (including the subsidiaries of the Partnerships, collectively, the Subsidiary Non-Guarantors), are not parties to the subsidiary guarantee agreement and have not otherwise guaranteed any of Enbridge's outstanding series of senior notes.

Consenting SEP notes and EEP notes under Guarantee

SEP Notes1	EEP Notes2
Floating Rate Senior Notes due 2020	5.200% Notes due 2020
4.600% Senior Notes due 2021	4.375% Notes due 2020
4.750% Senior Notes due 2024	4.200% Notes due 2021
3.500% Senior Notes due 2025	5.875% Notes due 2025
3.375% Senior Notes due 2026	5.950% Notes due 2033
5.950% Senior Notes due 2043	6.300% Notes due 2034
4.500% Senior Notes due 2045	7.500% Notes due 2038
	5.500% Notes due 2040
	7.375% Notes due 2045

1 As at March 31, 2019, the aggregate outstanding principal amount of SEP notes was approximately US$3.9 billion.

2 As at March 31, 2019, the aggregate outstanding principal amount of EEP notes was approximately US$4.0 billion.

40

Enbridge Notes under Guarantees

USD Denominated1	CAD Denominated2
Senior Floating Rate Notes due 2020	Senior Floating Rate Notes due 2019
Senior Floating Rate Notes due 2020	4.770% Senior Notes due 2019
2.900% Senior Notes due 2022	4.530% Senior Notes due 2020
4.000% Senior Notes due 2023	4.850% Senior Notes due 2020
3.500% Senior Notes due 2024	4.260% Senior Notes due 2021
4.250% Senior Notes due 2026	3.160% Senior Notes due 2021
3.700% Senior Notes due 2027	4.850% Senior Notes due 2022
4.500% Senior Notes due 2044	3.190% Senior Notes due 2022
5.500% Senior Notes due 2046	3.940% Senior Notes due 2023
	3.940% Senior Notes due 2023
	3.950% Senior Notes due 2024
	3.200% Senior Notes due 2027
	6.100% Senior Notes due 2028
	7.220% Senior Notes due 2030
	7.200% Senior Notes due 2032
	5.570% Senior Notes due 2035
	5.750% Senior Notes due 2039
	5.120% Senior Notes due 2040
	4.240% Senior Notes due 2042
	4.570% Senior Notes due 2044
	4.870% Senior Notes due 2044
	4.560% Senior Notes due 2064

1 As at March 31, 2019, the aggregate outstanding principal amount of the Enbridge United States dollar denominated notes was approximately US$5.9 billion.

2 As at March 31, 2019, the aggregate outstanding principal amount of the Enbridge Canadian dollar denominated notes was approximately $7.8 billion.

In accordance with Rule 3-10 of the SEC's Regulation S-X, which provides an exemption from the reporting requirements of the Securities Exchange Act of 1934 for subsidiary issuers of guaranteed securities and subsidiary guarantors, in lieu of filing separate financial statements for each of the Partnerships, we have included the accompanying condensed consolidating financial information with separate columns representing the following:

1. Enbridge Inc., the Parent Issuer and Guarantor;

2. SEP, a Subsidiary Issuer and Guarantor;

3. EEP, a Subsidiary Issuer and Guarantor;

4. Subsidiary Non-Guarantors, as defined herein;

5. Consolidating and elimination entries required to consolidate the Parent Issuer and Guarantor and its subsidiaries, including the Subsidiary Issuers and Guarantors, and

6. Enbridge Inc. and subsidiaries on a consolidated basis.

For the purposes of the condensed consolidating financial information only, investments in subsidiaries are accounted for under the equity method. In addition, the Condensed Consolidating Statements of Cash Flows present the intercompany loan and distribution activity, as well as cash collection and payments made on behalf of our subsidiaries, as cash activities. These intercompany investments and related activities eliminate on consolidation and are presented separately only for the purpose of the accompanying Condensed Consolidating Statements.

41

Condensed Consolidating Statements of Earnings and Comprehensive Income for the three months ended March 31, 2019

	Parent Issuer and Guarantor		Subsidiary Issuer and Guarantor - SEP		Subsidiary Issuer and Guarantor - EEP		Subsidiary Non-Guarantors		Consolidating and elimination adjustments		Consolidated - Enbridge
(millions of Canadian dollars)
Operating revenues
Commodity sales	—		—		—		6,632		—		6,632
Gas distribution sales	—		—		—		1,876		—		1,876
Transportation and other services	—		—		—		4,348		—		4,348
Total operating revenues	—		—		—		12,856		—		12,856
Operating Expenses
Commodity costs	—		—		—		6,565		—		6,565
Gas distribution costs	—		—		—		1,207		—		1,207
Operating and administrative	(34	)	2		1		1,656		—		1,625
Depreciation and amortization	15		—		—		825		—		840
Total operating expenses	(19	)	2		1		10,253		—		10,237
Operating income/(loss)	19		(2	)	(1	)	2,603		—		2,619
Income/(loss) from equity investments	59		31		—		382		(59	)	413
Equity earnings from consolidated subsidiaries	774		398		263		493		(1,928	)	—
Other
Net foreign currency gain/(loss)	1,221		—		—		(103	)	(904	)	214
Other, including other income from affiliates	330		—		41		123		(448	)	46
Interest expense	(308	)	(94	)	(158	)	(583	)	458		(685	)
Earnings before income taxes	2,095		333		145		2,915		(2,881	)	2,607
Income tax expense	(109	)	15		—		(596	)	106		(584	)
Earnings	1,986		348		145		2,319		(2,775	)	2,023
Earnings attributable to noncontrolling interests and redeemable noncontrolling interests	—		—		—		—		(37	)	(37	)
Earnings attributable to controlling interests	1,986		348		145		2,319		(2,812	)	1,986
Preference share dividends	(95	)	—		—		—		—		(95	)
Earnings attributable to common shareholders	1,891		348		145		2,319		(2,812	)	1,891
Earnings	1,986		348		145		2,319		(2,775	)	2,023
Total other comprehensive income/(loss)	(1,278	)	(16	)	15		(720	)	671		(1,328	)
Comprehensive income	708		332		160		1,599		(2,104	)	695
Comprehensive loss attributable to noncontrolling interests	—		—		—		—		13		13
Comprehensive income attributable to controlling interests	708		332		160		1,599		(2,091	)	708

42

Condensed Consolidating Statements of Earnings and Comprehensive Income for the three months ended March 31, 2018

	Parent Issuer and Guarantor		Subsidiary Issuer and Guarantor - SEP		Subsidiary Issuer and Guarantor - EEP		Subsidiary Non-Guarantors		Consolidating and elimination adjustments		Consolidated - Enbridge
(millions of Canadian dollars)
Operating revenues
Commodity sales	—		—		—		7,268		—		7,268
Gas distribution sales	—		—		—		1,926		—		1,926
Transportation and other services	—		—		—		3,532		—		3,532
Total operating revenues	—		—		—		12,726		—		12,726
Operating Expenses
Commodity costs	—		—		—		6,997		—		6,997
Gas distribution costs	—		—		—		1,324		—		1,324
Operating and administrative	67		1		4		1,569		—		1,641
Depreciation and amortization	14		—		—		810		—		824
Impairment of long-lived assets	—		—		—		1,062		—		1,062
Total operating expenses	81		1		4		11,762		—		11,848
Operating income/(loss)	(81	)	(1	)	(4	)	964		—		878
Income from equity investments	17		34		—		300		(16	)	335
Equity earnings from consolidated subsidiaries	707		551		203		608		(2,069	)	—
Other
Net foreign currency gain/(loss)	(199	)	2		—		(58	)	70		(185	)
Other, including other income/(expense) from affiliates	246		1		30		39		(251	)	65
Interest expense	(243	)	(72	)	(136	)	(479	)	274		(656	)
Earnings before income taxes	447		515		93		1,374		(1,992	)	437
Income tax recovery/(expense)	87		—		—		(23	)	9		73
Earnings	534		515		93		1,351		(1,983	)	510
Earnings attributable to noncontrolling interests and redeemable noncontrolling interests	—		—		—		—		24		24
Earnings attributable to controlling interests	534		515		93		1,351		(1,959	)	534
Preference share dividends	(89	)	—		—		—		—		(89	)
Earnings attributable to common shareholders	445		515		93		1,351		(1,959	)	445
Earnings	534		515		93		1,351		(1,983	)	510
Total other comprehensive income	1,302		19		8		253		(109	)	1,473
Comprehensive income	1,836		534		101		1,604		(2,092	)	1,983
Comprehensive income attributable to noncontrolling interests	—		—		—		—		(147	)	(147	)
Comprehensive income attributable to controlling interests	1,836		534		101		1,604		(2,239	)	1,836

43

Condensed Consolidating Statements of Financial Position as at March 31, 2019

	Parent Issuer and Guarantor	Subsidiary Issuer and Guarantor - SEP	Subsidiary Issuer and Guarantor - EEP	Subsidiary Non-Guarantors		Consolidating and elimination adjustments		Consolidated - Enbridge
(millions of Canadian dollars)
Assets
Current assets
Cash and cash equivalents	—	5	7	690		—		702
Restricted cash	9	—	—	46		—		55
Accounts receivable and other	283	1	—	6,202		—		6,486
Accounts receivable from affiliates	586	—	31	79		(604	)	92
Short-term loans receivable from affiliates	3,527	—	3,838	5,871		(13,236	)	—
Inventory	—	—	—	1,047		—		1,047
	4,405	6	3,876	13,935		(13,840	)	8,382
Property, plant and equipment, net	166	—	—	93,709		—		93,875
Long-term loans receivable from affiliates	26,504	73	2,472	15,524		(44,573	)	—
Investments in subsidiaries	78,271	19,741	6,209	15,032		(119,253	)	—
Long-term investments	4,619	961	—	14,890		(3,568	)	16,902
Restricted long-term investments	—	—	—	356		—		356
Deferred amounts and other assets	1,491	1	8	9,412		(1,407	)	9,505
Intangible assets, net	219	—	—	2,082		—		2,301
Goodwill	—	—	—	33,895		—		33,895
Deferred income taxes	744	—	—	220		328		1,292
Total assets	116,419	20,782	12,565	199,055		(182,313	)	166,508
Liabilities and equity
Current liabilities
Short-term borrowings	—	—	—	870		—		870
Accounts payable and other	756	19	14	6,552		(10	)	7,331
Accounts payable to affiliates	935	509	80	(891	)	(603	)	30
Interest payable	227	25	92	229		—		573
Short-term loans payable to affiliates	426	2,985	2,458	7,367		(13,236	)	—
Current portion of long-term debt	2,979	—	668	674		—		4,321
	5,323	3,538	3,312	14,801		(13,849	)	13,125
Long-term debt	23,519	5,095	4,565	27,501		—		60,680
Other long-term liabilities	2,145	8	22	8,276		(1,407	)	9,044
Long-term loans payable to affiliates	15,076	—	1,470	28,027		(44,573	)	—
Deferred income taxes	—	304	—	13,821		(4,385	)	9,740
	46,063	8,945	9,369	92,426		(64,214	)	92,589
Equity
Controlling interests1	70,356	11,837	3,196	106,629		(121,713	)	70,305
Noncontrolling interests	—	—	—	—		3,614		3,614
	70,356	11,837	3,196	106,629		(118,099	)	73,919
Total liabilities and equity	116,419	20,782	12,565	199,055		(182,313	)	166,508

1 Equity attributable to controlling interests for parent issuer and guarantor excludes reciprocal shareholding balance included within consolidating and elimination adjustments.

44

Condensed Consolidating Statements of Financial Position as at December 31, 2018

	Parent Issuer and Guarantor	Subsidiary Issuer and Guarantor - SEP	Subsidiary Issuer and Guarantor - EEP	Subsidiary Non-Guarantors		Consolidating and elimination adjustments		Consolidated - Enbridge
(millions of Canadian dollars)
Assets
Current assets
Cash and cash equivalents	—	16	—	502		—		518
Restricted cash	9	—	—	110		—		119
Accounts receivable and other	283	15	8	6,211		—		6,517
Accounts receivable from affiliates	726	—	13	(142	)	(518	)	79
Short-term loans receivable from affiliates	3,943	—	3,689	653		(8,285	)	—
Inventory	—	—	—	1,339		—		1,339
	4,961	31	3,710	8,673		(8,803	)	8,572
Property, plant and equipment, net	140	—	—	94,400		—		94,540
Long-term loans receivable from affiliates	10,318	73	2,539	1,344		(14,274	)	—
Investments in subsidiaries	78,474	19,777	6,363	15,567		(120,181	)	—
Long-term investments	4,561	987	—	14,841		(3,682	)	16,707
Restricted long-term investments	—	—	—	323		—		323
Deferred amounts and other assets	1,700	9	17	8,558		(1,726	)	8,558
Intangible assets, net	234	—	—	2,138		—		2,372
Goodwill	—	—	—	34,459		—		34,459
Deferred income taxes	817	—	—	229		328		1,374
Total assets	101,205	20,877	12,629	180,532		(148,338	)	166,905
Liabilities and equity
Current liabilities
Short-term borrowings	—	—	—	1,024		—		1,024
Accounts payable and other	2,742	7	34	7,086		(6	)	9,863
Accounts payable to affiliates	946	233	56	(677	)	(518	)	40
Interest payable	283	56	105	225		—		669
Short-term loans payable to affiliates	426	682	—	7,177		(8,285	)	—
Current portion of long-term debt	1,853	—	683	723		—		3,259
	6,250	978	878	15,558		(8,809	)	14,855
Long-term debt	22,893	7,276	6,943	23,215		—		60,327
Other long-term liabilities	2,428	2	30	8,100		(1,726	)	8,834
Long-term loans payable to affiliates	76	—	1,502	12,696		(14,274	)	—
Deferred income taxes	—	331	—	13,523		(4,400	)	9,454
	31,647	8,587	9,353	73,092		(29,209	)	93,470
Equity
Controlling interests1	69,558	12,290	3,276	107,440		(123,094	)	69,470
Noncontrolling interests	—	—	—	—		3,965		3,965
	69,558	12,290	3,276	107,440		(119,129	)	73,435
Total liabilities and equity	101,205	20,877	12,629	180,532		(148,338	)	166,905

1 Equity attributable to controlling interests for parent issuer and guarantor excludes reciprocal shareholding balance included within consolidating and elimination adjustments.

45

Condensed Consolidating Statements of Cash Flows for the three months ended March 31, 2019

	Parent Issuer and Guarantor		Subsidiary Issuer and Guarantor - SEP		Subsidiary Issuer and Guarantor - EEP		Subsidiary Non-Guarantors		Consolidating and elimination adjustments		Consolidated - Enbridge
(millions of Canadian dollars)
Net cash provided by/(used in) operating activities	(415	)	232		(1,418	)	4,566		(789	)	2,176
Investing activities
Capital expenditures	(24	)	—		—		(1,588	)	—		(1,612	)
Long-term investments and restricted long-term investments	—		(2	)	—		(563	)	—		(565	)
Distributions from equity investments in excess of cumulative earnings	—		7		536		132		(536	)	139
Additions to intangible assets	(16	)	—		—		(10	)	—		(26	)
Affiliate loans, net	—		—		—		(84	)	—		(84	)
Contributions to subsidiaries	(2,331	)	—		—		—		2,331		—
Return of share capital from subsidiaries	3,121		—		—		—		(3,121	)	—
Advances to affiliates	(19,908	)	—		(618	)	(21,542	)	42,068		—
Repayment of advances to affiliates	3,996		—		382		1,638		(6,016	)	—
Net cash provided by/(used in) investing activities	(15,162	)	5		300		(22,017	)	34,726		(2,148	)
Financing activities
Net change in short-term borrowings	—		—		—		(154	)	—		(154	)
Net change in commercial paper and credit facility draws	2,312		(2,010	)	—		2,471		—		2,773
Debenture and term note issues, net of issue costs	—		—		—		1,195		—		1,195
Debenture and term note repayments	(300	)	—		(1,189	)	(300	)	—		(1,789	)
Contributions from noncontrolling interests	—		—		—		—		3		3
Distributions to noncontrolling interests	—		—		—		—		(46	)	(46	)
Contributions from parents	—		—		—		2,331		(2,331	)	—
Distributions to parents	—		(505	)	(162	)	(3,822	)	4,489		—
Redemption of preferred shares	—		—		—		(300	)	—		(300	)
Common shares issued	18		—		—		—		—		18
Preference share dividends	(90	)	—		—		—		—		(90	)
Common share dividends	(1,513	)	—		—		27		—		(1,486	)
Advances from affiliates	15,150		3,498		2,894		20,526		(42,068	)	—
Repayment of advances from affiliates	—		(1,226	)	(412	)	(4,378	)	6,016		—
Other	—		(5	)	(6	)	(14	)	—		(25	)
Net cash (used in)/provided by financing activities	15,577		(248	)	1,125		17,582		(33,937	)	99
Effect of translation of foreign denominated cash and cash equivalents and restricted cash	—		—		—		(7	)	—		(7	)
Net increase/(decrease) in cash and cash equivalents and restricted cash	—		(11	)	7		124		—		120
Cash and cash equivalents and restricted cash at beginning of period	9		16		—		612		—		637
Cash and cash equivalents and restricted cash at end of period	9		5		7		736		—		757

46

Condensed Consolidating Statements of Cash Flows for the three months ended March 31, 2018

	Parent Issuer and Guarantor		Subsidiary Issuer and Guarantor - SEP		Subsidiary Issuer and Guarantor - EEP		Subsidiary Non-Guarantors		Consolidating and elimination adjustments		Consolidated - Enbridge
(millions of Canadian dollars)
Net cash (used in)/provided by operating activities	(135	)	803		(331	)	3,224		(367	)	3,194
Investing activities
Capital expenditures	(5	)	—		—		(1,630	)	—		(1,635	)
Long-term investments and restricted long-term investments	(16	)	(5	)	—		(217	)	16		(222	)
Distributions from equity investments in excess of cumulative earnings	336		15		488		42		(824	)	57
Additions to intangible assets	(6	)	—		—		(252	)	—		(258	)
Affiliate loans, net	—		—		—		(10	)	—		(10	)
Contributions to subsidiaries	(69	)	(77	)	(5	)	—		151		—
Advances to affiliates	(401	)	—		(496	)	(2,233	)	3,130		—
Repayment of advances to affiliates	—		506		548		1,890		(2,944	)	—
Net cash (used in)/provided by investing activities	(161	)	439		535		(2,410	)	(471	)	(2,068	)
Financing activities
Net change in short-term borrowings	—		—		—		(443	)	—		(443	)
Net change in commercial paper and credit facility draws	(105	)	(756	)	(218	)	614		—		(465	)
Debenture and term note issues, net of issue costs	1,080		—		—		981		—		2,061
Debenture and term note repayments	—		—		—		(996	)	—		(996	)
Debt extinguishment costs	—		—		—		(63	)	—		(63	)
Contributions from noncontrolling interests	—		—		—		—		8		8
Distributions to noncontrolling interests	—		—		—		—		(209	)	(209	)
Contributions from redeemable noncontrolling interests	—		—		—		—		20		20
Distributions to redeemable noncontrolling interests	—		—		—		—		(84	)	(84	)
Contributions from parents	—		—		—		151		(151	)	—
Distributions to parents	—		(453	)	(163	)	(824	)	1,440		—
Common shares issued	13		—		—		—		—		13
Preference share dividends	(87	)	—		—		—		—		(87	)
Common share dividends	(764	)	—		—		—		—		(764	)
Advances from affiliates	209		—		2,024		897		(3,130	)	—
Repayment of advances from affiliates	(43	)	—		(1,847	)	(1,054	)	2,944		—
Net cash provided by/(used in) financing activities	303		(1,209	)	(204	)	(737	)	838		(1,009	)
Effect of translation of foreign denominated cash and cash equivalents and restricted cash	—		—		—		19		—		19
Net increase in cash and cash equivalents and restricted cash	7		33		—		96		—		136
Cash and cash equivalents and restricted cash at beginning of period	2		14		—		571		—		587
Cash and cash equivalents and restricted cash at end of period	9		47		—		667		—		723

47

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

INTRODUCTION

The following discussion and analysis of our financial condition and results of operations is based on and should be read in conjunction with our consolidated financial statements and the accompanying notes included in Part 1. Item 1. Financial Statements of this report, our Annual Report on Form 10-K for the year ended December 31, 2018, as filed with the Securities and Exchange Commission (SEC) on February 15, 2019, and our audited updated consolidated financial statements and accompanying footnotes for the year ended December 31, 2018, as filed on Form 8-K with the SEC on May 10, 2019.

RECENT DEVELOPMENT - STATE OF MINNESOTA PERMITTING TIMELINE FOR U.S. LINE 3 REPLACEMENT PROGRAM

On March 1, 2019 we announced that the State of Minnesota provided the permitting timelines for its agencies' remaining environmental permits for the U.S. L3R Program. The permitting timeline indicates that the certifications on all remaining State of Minnesota permits will be provided by November 2019. We anticipate that the remaining Federal permits will be finalized approximately 30 to 60 days thereafter. In light of this updated permitting timeline, we are developing a revised construction schedule and related cost estimates for the U.S. L3R Program, and now expect an in-service date during the second half of 2020. For further details refer to Growth Projects - Regulatory Matters - United States Line 3 Replacement Program.

RESULTS OF OPERATIONS

	Three months ended March 31,
	2019		2018
(millions of Canadian dollars, except per share amounts)
Segment earnings/(loss) before interest, income taxes and depreciation and amortization
Liquids Pipelines	2,072		1,156
Gas Transmission and Midstream	1,020		126
Gas Distribution	662		636
Renewable Power Generation and Transmission	124		109
Energy Services	6		169
Eliminations and Other	248		(279	)
Depreciation and amortization	(840	)	(824	)
Interest expense	(685	)	(656	)
Income tax (expense)/recovery	(584	)	73
(Earnings)/loss attributable to noncontrolling interests and redeemable noncontrolling interests	(37	)	24
Preference share dividends	(95	)	(89	)
Earnings attributable to common shareholders	1,891		445
Earnings per common share	0.94		0.26
Diluted earnings per common share	0.94		0.26

48

EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS

Three months ended March 31, 2019, compared with the three months ended March 31, 2018

Earnings Attributable to Common Shareholders were positively impacted by $1,181 million due to certain unusual, infrequent or other factors, primarily explained by the following:

• the absence in 2019 of a loss of $913 million ($701 million after-tax attributable to us) in 2018 on Midcoast Operating, L.P. and its subsidiaries (MOLP) resulting from a revision to the fair value of the assets held for sale based on the sale price;

• the absence in 2019 of a loss of $144 million ($85 million after-tax attributable to us) in 2018 related to the Line 10 crude oil pipeline, which is a component of our mainline system, resulting from its classification as an asset held for sale and the subsequent measurement at the lower of carrying value or fair value less costs to sell;

• a non-cash, unrealized derivative fair value gain of $436 million ($317 million after-tax attributable to us) in 2019, compared with a loss of $277 million ($146 million after-tax attributable to us) in the corresponding 2018 period, reflecting net fair value gains and losses arising from changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity prices risks; and

• employee severance, transition and transformation costs of $44 million ($42 million after-tax attributable to us) in 2019, compared with $97 million ($96 million after-tax attributable to us) in the corresponding 2018 period; partially offset by

• the absence in 2019 of a gain of $63 million after-tax in 2018 that resulted from the impact of the Tax Cuts and Jobs Act on our United States Renewable Power Generation and Transmission assets.

The non-cash, unrealized derivative fair value gains and losses discussed above generally arise as a result of a comprehensive long-term economic hedging program to mitigate interest rate, foreign exchange and commodity price risks. This program creates volatility in reported short-term earnings through the recognition of unrealized non-cash gains and losses on financial derivative instruments used to hedge these risks. Over the long-term, we believe our hedging program supports the reliable cash flows and dividend growth upon which our investor value proposition is based.

After taking into consideration the factors above, the remaining $265 million increase in Earnings Attributable to Common Shareholders is primarily explained by the following significant business factors:

• stronger contributions from our Liquids Pipelines segment due to a higher International Joint Tariff (IJT) Benchmark Toll and higher throughput driven by an increase in supply and continuous capacity optimization;

• contributions from new gas transmission assets placed into service in 2018;

• increased earnings from our Gas Distribution segment due to colder weather experienced in our franchise areas, higher distribution rates and customer base, and the absence of forecasted earnings sharing in 2019;

• increased earnings from our Energy Services segment due to the widening of certain location differentials during the second half of 2018, which increased opportunities to generate profitable margins that were realized during the first quarter of 2019; and

• the net favorable effect of translating United States dollar EBITDA at a higher Canadian to United States dollar average exchange rate (Average Exchange Rate) of $1.33 in 2019 compared with $1.26 in 2018, partially offset by realized losses arising from our foreign exchange risk management program.

The positive business factors above were partially offset by the following:

• the absence in 2019 of earnings from MOLP and the provincially regulated portion of our Canadian gas gathering and processing businesses which were sold in 2018; and

• higher income tax expense driven by higher earnings and a higher effective income tax rate partly due to the buy-in of our United States sponsored vehicles in the fourth quarter of 2018.

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BUSINESS SEGMENTS

LIQUIDS PIPELINES

	Three months ended March 31,
	2019	2018
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization	2,072	1,156

Three months ended March 31, 2019, compared with the three months ended March 31, 2018

EBITDA was positively impacted by $814 million due to certain unusual, infrequent or other factors, primarily explained by the following:

• a non-cash, unrealized gain of $343 million in 2019 compared with a loss of $298 million in 2018 reflecting net fair value gains and losses arising from changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity price risks; and

• the absence in 2019 of a loss of $144 million in 2018 related to Line 10, which is a component of our mainline system, resulting from its classification as an asset held for sale and the subsequent measurement at the lower of carrying value or fair value less costs to sell.

After taking into consideration the factors above, the remaining $102 million increase is primarily explained by the following significant business factors:

• a higher IJT Benchmark Toll of US$4.15 in 2019 compared with US$4.07 in 2018;

• higher Mainline System ex-Gretna throughput of 2,717 thousands of barrels per day (kbpd) in 2019 compared with 2,625 kbpd in 2018 driven by an increase in supply and continuous capacity optimization;

• higher Flanagan South Pipeline and Seaway Crude Pipeline System throughput period-over-period partially driven by the redirection of throughput to the Gulf Coast resulting from refinery outages;

• higher Bakken Pipeline System throughput period-over-period driven by strong production; and

• the net favorable effect of translating United States dollar EBITDA at a higher Average Exchange Rate of $1.33 in 2019 compared with $1.26 in 2018.

GAS TRANSMISSION AND MIDSTREAM

	Three months ended March 31,
	2019	2018
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization	1,020	126

Three months ended March 31, 2019, compared with the three months ended March 31, 2018

EBITDA was positively impacted by $900 million primarily due to the absence in 2019 of a loss of $913 million in 2018 on MOLP resulting from a revision to the fair value of the assets held for sale based on the sale price.

After taking into consideration the factor above, the remaining $6 million decrease is primarily explained by the absence in 2019 of earnings from MOLP and the provincially regulated portion of our Canadian gas gathering and processing businesses which were sold in 2018.

The absence of earnings from assets sold in the prior year was partially offset by:

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• contributions from Valley Crossing Pipeline and certain other Offshore assets that were placed into service during 2018; and

• the net favorable effect of translating United States dollar EBITDA at a higher Average Exchange Rate of $1.33 in 2019 compared with $1.26 in 2018.

GAS DISTRIBUTION

	Three months ended March 31,
	2019	2018
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization	662	636

Enbridge Gas Distribution Inc. (EGD) and Union Gas Limited (Union Gas) were amalgamated on January 1, 2019. The amalgamated company has been renamed Enbridge Gas Inc. (EGI). Post amalgamation the financial results of EGI reflect the combined performance of EGD and Union Gas.

Three months ended March 31, 2019, compared with the three months ended March 31, 2018

EBITDA was negatively impacted by $21 million primarily due to employee severance costs of $35 million in 2019 related to the amalgamation of EGD and Union Gas. This negative factor was partially offset by the absence in 2019 of a negative equity earnings adjustment of $9 million in 2018 at our equity investee, Noverco Inc., arising from the Tax Cuts and Jobs Act.

After taking into consideration the factors above, the remaining $47 million increase is primarily explained by the following significant business factors:

• increased earnings of $38 million period-over-period resulting from colder weather experienced in our franchise service areas when compared to the corresponding period in 2018;

• higher earnings from higher distribution charges primarily resulting from increases in distribution rates and customer base; and

• the absence in 2019 of forecasted earnings sharing which was recorded in 2018 under EGD's previous incentive rate structure.

RENEWABLE POWER GENERATION AND TRANSMISSION

	Three months ended March 31,
	2019	2018
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization	124	109

Three months ended March 31, 2019, compared with the three months ended March 31, 2018

EBITDA was positively impacted by $31 million due to certain unusual, infrequent and other factors, primarily explained by the following:

• the absence in 2019 of an asset impairment charge of $22 million in 2018 from our equity investment in NRGreen Power Limited Partnership related to the Chickadee Creek waste heat recovery facility in Alberta; and

▪ the absence in 2019 of a loss of $11 million in 2018 representing our share of losses incurred by our equity investee, Rampion Offshore Wind Limited, primarily due to the repair and restoration of damaged power transmission cables, for which we are seeking reimbursement.

After taking into consideration the factors above, the remaining $16 million decrease is primarily explained by the following significant business factors:

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• weaker wind resources at United States wind facilities; and

• the absence in 2019 of $11 million in 2018 from a positive arbitration settlement related to our Canadian wind facilities.

The negative business factors above were partially offset by the following:

• stronger wind resources at Canadian wind facilities; and

• contributions from the Rampion Offshore Wind Project in 2019 which reached full operating capacity in the second quarter of 2018.

ENERGY SERVICES

	Three months ended March 31,
	2019	2018
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization	6	169

EBITDA from Energy Services is dependent on market conditions and results achieved in one period may not be indicative of results to be achieved in future periods.

Three months ended March 31, 2019, compared with the three months ended March 31, 2018

EBITDA decreased by $317 million primarily due to a non-cash, unrealized loss of $164 million in 2019 compared with a gain of $147 million in 2018 reflecting the revaluation of financial derivatives used to manage the profitability of transportation and storage transactions and manage the exposure to movements in commodity prices.

After taking into consideration the factor above, the remaining $154 million increase is primarily due to increased earnings from Energy Services' crude operations due to the widening of certain location and quality differentials during the second half of 2018, which increased opportunities to generate profitable margins that were realized during the first quarter of 2019.

ELIMINATIONS AND OTHER

	Three months ended March 31,
	2019	2018
(millions of Canadian dollars)
Earnings/(loss) before interest, income taxes and depreciation and amortization	248	(279	)

Eliminations and Other includes operating and administrative costs and the impact of foreign exchange hedge settlements, which are not allocated to business segments. Eliminations and Other also includes the impact of new business development activities and corporate investments.

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Three months ended March 31, 2019, compared with the three months ended March 31, 2018

EBITDA was positively impacted by $445 million due to certain unusual, infrequent and other factors, primarily explained by the following:

• a non-cash, unrealized gain of $252 million in 2019 compared with a loss of $136 million in 2018 reflecting net fair value gains and losses arising from the change in the mark-to-market value of derivative financial instruments used to manage foreign exchange risk; and

• employee severance, transition and transformation costs of $9 million in 2019 compared with $62 million in 2018.

After taking into consideration the factors above, the remaining $82 million increase is primarily explained by lower operating and administrative costs in the first quarter of 2019 and the timing of the recovery of certain operating and administrative costs allocated to the business segments, which were more heavily weighted to the second half of 2018.

The positive business factor above was partially offset by a realized loss of $55 million in 2019 compared with a loss of $42 million in 2018 related to settlements under our foreign exchange risk management program, which partially offset the positive impact of a strengthening United States dollar on our United States business segments.

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GROWTH PROJECTS – COMMERCIALLY SECURED PROJECTS

The following table summarizes the status of our commercially secured projects, organized by business segment:

		Enbridge's Ownership Interest		Estimated Capital Cost1	Expenditures to Date2	Status	Expected In-Service Date
(Canadian dollars, unless stated otherwise)
LIQUIDS PIPELINES
1.	Canadian Line 3 Replacement Program	100	%	$5.3 billion	$4.4 billion	Under construction	2H - 2020
2.	U.S. Line 3 Replacement Program	100	%	US$2.9 billion	US$1.1 billion	Pre-construction	2H - 2020
3.	Gray Oak Pipeline Project	22.8	%	US$0.7 billion	US$0.3 billion	Under construction	Q4 - 2019
4.	Other - United States3	100	%	US$0.4 billion	US$0.4 billion	Substantially complete	2H - 2020
5.	Other - Canada4	100	%	$0.3 billion	$0.3 billion	Complete	In service
GAS TRANSMISSION AND MIDSTREAM
6.	Atlantic Bridge	100	%	US$0.6 billion	US$0.5 billion	Under construction	1H - 2020
7.	Spruce Ridge Project	100	%	$0.5 billion	$0.1 billion	Pre-construction	2H - 2021
8.	T-South Expansion Program	100	%	$1.0 billion	$0.2 billion	Pre-construction	2H - 2021
9.	Other - United States	100	%	US$1.1 billion	US$0.3 billion	Various stages	2019 - 2023
GAS DISTRIBUTION
10.	Dawn-Parkway Expansion	100	%	$0.2 billion	No significant expenditures to date	Pre-construction	2H - 2021
RENEWABLE POWER GENERATION AND TRANSMISSION
11.	Hohe See Offshore Wind Project and Expansion	25	%	$1.1 billion	$0.6 billion	Under construction	2H - 2019
				(€0.67 billion)	(€0.4 billion)
12.	Other - Canada	25	%	$0.2 billion	No significant expenditures to date	Pre-construction	2H - 2021

1 These amounts are estimates and are subject to upward or downward adjustment based on various factors. Where appropriate, the amounts reflect our share of joint venture projects.

2 Expenditures to date reflect total cumulative expenditures incurred from inception of the project up to March 31, 2019.

3 Includes the Lakehead System Mainline Expansion - Line 61. Estimated in-service date will be adjusted to coincide with the in-service date of the U.S. L3R Program.

4 Athabasca Oil Corporation Lateral Acquisition placed into service in the first quarter of 2019.

A full description of each of our projects is provided in our Annual Report on Form 10-K, as filed with the Securities and Exchange Commission on February 15, 2019. Significant updates that have occurred since the date of filing are discussed below.

LIQUIDS PIPELINES

• Gray Oak Pipeline Project - a crude oil pipeline project connecting West Texas to destinations in the Corpus Christi and Sweeny/Freeport markets. The pipeline is a joint development with Phillips 66 and could have an ultimate capacity of approximately 900,000 bpd, subject to additional shipper commitments. Project execution forecasts were revised to reflect updated construction cost estimates and timing, with an expected in-service date in the fourth quarter of 2019.

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GAS TRANSMISSION AND MIDSTREAM

• Atlantic Bridge - expansion of the Algonquin Gas Transmission systems to transport 133 mmcf/d of natural gas to the New England Region. The expansion primarily consists of various meter station additions, the replacement of a natural gas pipeline in Connecticut and Massachusetts, compression additions in Connecticut, and a new compressor station in Massachusetts. The meter stations were placed into service in 2017 and 2018. The Connecticut portion of the project was placed into service in the fourth quarter of 2017. The New York portion of the project achieved partial in-service in November 2018 and the revised expected full in-service date is the third quarter of 2019, upon which we will begin earning incremental revenues. The final Massachusetts portion of the project is expected to be in service in the first half of 2020.

• Spruce Ridge Project- a natural gas pipeline expansion of Westcoast Energy Inc.'s BC Pipeline in northern BC. The project will provide additional capacity of up to 402 million cubic feet per day (mmcf/d) with a revised in-service date in the second half of 2021.

GAS DISTRIBUTION

• Dawn-Parkway Expansion - the expansion of the existing Dawn to Parkway gas transmission system, which provides transportation service from Dawn to the Greater Toronto Area. The project will provide additional capacity of approximately 75 mmcf/d with an expected in-service date in the second half of 2021.

GROWTH PROJECTS - REGULATORY MATTERS

United States Line 3 Replacement Program

The Minnesota Public Utilities Commission has finalized all of its written orders and has denied all petitions to reconsider its regulatory decisions. The permitting process is under way with all relevant federal and state agencies, and other local government agencies in Minnesota. During the first quarter of 2019, the State of Minnesota provided timelines for issuing their environmental permitting by November 2019. We anticipate that the remaining Federal permits will be finalized approximately 30 to 60 days thereafter.

This new permitting schedule updates our prior expectation for the receipt of final State of Minnesota permits in the second quarter of 2019. In light of this new permitting timeline, we are developing a revised construction schedule and related cost estimates for the U.S. L3R Program, and expect an in-service date during the second half of 2020.

Construction costs for the Line 3 Replacement Program are tracking below budget in Canada and above budget in the United States due to permitting delays in Minnesota. Depending on the final in service date, there is a risk that the project will exceed our total cost estimate of $9 billion.

OTHER ANNOUNCED PROJECTS UNDER DEVELOPMENT

The following projects have been announced by us, but have not yet met our criteria to be classified as commercially secured:

LIQUIDS PIPELINES

• Texas COLT Offshore Loading Project - the Texas COLT Offshore Loading Project will facilitate the direct loading of very large crude carriers from Freeport, Texas. The project consists of a terminal, a 42-inch offshore pipeline, platform and two single point mooring systems with connectivity to all key North American supply basins. During the first quarter of 2019 we acquired the position previously

55

held by Kinder Morgan Inc. We now hold an 80 percent interest in the project and Oiltanking holds the remaining 20 percent interest. The project is expected to be in service by 2022.

We also have a large portfolio of additional projects under development that have not yet progressed to the point of public announcement.

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LIQUIDITY AND CAPITAL RESOURCES

The maintenance of financial strength and flexibility is fundamental to our growth strategy, particularly in light of the significant number and size of capital projects currently secured or under development. Access to timely funding from capital markets could be limited by factors outside our control, including but not limited to financial market volatility resulting from economic and political events both inside and outside North America. To mitigate such risks, we actively manage financial plans and strategies to ensure we maintain sufficient liquidity to meet routine operating and future capital requirements. In the near term, we generally expect to utilize cash from operations together with commercial paper issuance and/or credit facility draws and the proceeds of capital market offerings to fund liabilities as they become due, finance capital expenditures, fund debt retirements and pay common and preference share dividends. We target to maintain sufficient liquidity through securement of committed credit facilities with a diversified group of banks and financial institutions to enable us to fund all anticipated requirements for approximately one year without accessing the capital markets.

Our financing plan is regularly updated to reflect evolving capital requirements and financial market conditions and identifies a variety of potential sources of debt and equity funding alternatives.

CAPITAL MARKET ACCESS

We ensure ready access to capital markets, subject to market conditions, through maintenance of shelf prospectuses that allow for issuance of long-term debt, equity and other forms of long-term capital when market conditions are attractive.

Credit Facilities and Liquidity

To ensure ongoing liquidity and to mitigate the risk of capital market disruption, we maintain ready access to funds through committed bank credit facilities and actively manage our bank funding sources to optimize pricing and other terms. The following table provides details of our committed credit facilities as at March 31, 2019:

	Maturity Dates	Total Facilities	Draws1	Available
(millions of Canadian dollars)
Enbridge Inc.	2019-2024	6,137	4,319	1,818
Enbridge (U.S.) Inc.	2021-2024	7,348	5,252	2,096
Enbridge Pipelines Inc.	2020	3,000	1,513	1,487
Enbridge Gas Inc.	2019-2021	2,017	879	1,138
Total committed credit facilities		18,502	11,963	6,539

1    Includes facility draws and commercial paper issuances that are back-stopped by credit facilities.

On February 7, 2019 and February 8, 2019, we terminated certain Canadian and United States dollar credit facilities, including facilities held by Enbridge, EGI, EEP and SEP. We also increased existing facilities or obtained new facilities for Enbridge, Enbridge (U.S.) Inc. and EGI to substantially replace the terminated facilities. As a result, our total credit facility availability increased by approximately $444 million Canadian dollar equivalent.

In addition to the committed credit facilities noted above, we maintain $800 million of uncommitted demand credit facilities, of which $516 million were unutilized as at March 31, 2019. As at December 31, 2018, we had $807 million of uncommitted credit facilities, of which $548 million were unutilized.

Our net available liquidity of $7,241 million as at March 31, 2019, was inclusive of $702 million of unrestricted cash and cash equivalents as reported in the Consolidated Statements of Financial Position.

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Our credit facility agreements and term debt indentures include standard events of default and covenant provisions whereby accelerated repayment and/or termination of the agreements may result if we were to default on payment or violate certain covenants. As at March 31, 2019, we were in compliance with all debt covenants and we expect to continue to comply with such covenants.

LONG-TERM DEBT ISSUANCES

During the three months ended March 31, 2019, we completed the following long-term debt issuances:

Company	Issue Date		Principal Amount
(millions of Canadian dollars)
Enbridge Pipelines Inc.
	February 2019	3.52% medium-term notes due February 2029	$600
	February 2019	4.33% medium-term notes due February 2049	$600

LONG-TERM DEBT REPAYMENTS

During the three months ended March 31, 2019, we completed the following long-term debt repayments:

Company	Retirement/ Repayment Date		Principal Amount
(millions of Canadian dollars, unless otherwise stated)
Enbridge Inc.
Repayment
	February 2019	4.10% medium-term notes	$300
Enbridge Energy Partners, L.P.
Redemption
	February 2019	8.05% fixed/floating rate junior subordinated notes due 2067	US$400
Repayment
	March 2019	9.88% senior notes	US$500
Westcoast Energy Inc.
Repayment
	January 2019	5.60% medium-term notes	$250
	January 2019	5.60% medium-term notes	$50

Strong growth in internal cash flow, ready access to liquidity from diversified sources and a stable business model support our strong credit profile. We actively monitor and manage key financial metrics with the objective of sustaining investment grade credit ratings from the major credit rating agencies and ongoing access to bank funding and term debt capital on attractive terms. Key measures of financial strength that are closely managed include the ability to service debt obligations from operating cash flow and the ratio of debt to total capital. As at March 31, 2019, our debt capitalization ratio was 47.1%, compared with 46.8% as at December 31, 2018.

There are no material restrictions on our cash. Total restricted cash of $55 million, as reported on the Consolidated Statements of Financial Position, includes EGI's receipt of cash from the Government of Ontario to fund its Green Investment Fund program. In addition, our restricted cash includes cash collateral and amounts received in respect of specific shipper commitments. Cash and cash equivalents held by certain subsidiaries may not be readily accessible for alternative uses by us.

Excluding current maturities of long-term debt, we had a negative working capital position as at March 31, 2019. The major contributing factor to the negative working capital position was the ongoing funding of our growth capital program.

To address this negative working capital position, we maintain significant liquidity in the form of committed credit facilities and other sources as previously discussed, which enable the funding of liabilities as they become due. As at March 31, 2019 and December 31, 2018, our net available liquidity totaled $7,241 million and $9,409 million, respectively.

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SOURCES AND USES OF CASH

	Three months ended March 31,
	2019		2018
(millions of Canadian dollars)
Operating activities	2,176		3,194
Investing activities	(2,148	)	(2,068	)
Financing activities	99		(1,009	)
Effect of translation of foreign denominated cash and cash equivalents and restricted cash	(7	)	19
Increase in cash and cash equivalents and restricted cash	120		136

Significant sources and uses of cash for the three months ended March 31, 2019 and March 31, 2018 are summarized below:

Operating Activities

• The decrease in cash flow provided by operations during the first quarter of 2019 was primarily driven by changes in operating assets and liabilities. Our operating assets and liabilities fluctuate in the normal course due to various factors, including the impact of fluctuations in commodity prices and activity levels on working capital within the Energy Services and Gas Distribution segments, the timing of tax payments, as well as timing of cash receipts and payments generally.

• The factor above was partially offset by stronger contributions from our operating segments and contributions from new assets placed into service as discussed under Results of Operations.

Investing Activities

• The increase in cash used in investing activities during the first quarter 2019 was attributable to activity in 2019 that was not present in 2018, primarily relating to contributions to the Gray Oak Holdings LLC equity investment starting in January 2019.

• We are continuing with the execution of our growth capital program which is further described in Growth Projects - Commercially Secured Projects. The timing of project approval, construction and in-service dates impacts the timing of cash requirements.

Financing Activities

• The decrease in cash used in financing activities during the first quarter of 2019 was primarily attributable to a net increase in commercial paper and credit facility draws, partially offset by higher repayments of maturing long-term debt and a decrease of long-term debt issued in 2019 when compared to the same period in 2018.

• Our common share dividend payments increased quarter-over-quarter primarily due to the increase in the common share dividend rate and an increase in the number of common shares outstanding in connection with the buy-in of our sponsored vehicles in the fourth quarter of 2018. These factors were partially offset by the suspension of our Dividend Reinvestment and Share Purchase Plan in the fourth quarter of 2018. In addition, in March 2019, Westcoast Energy Inc. redeemed all of its outstanding Series 7 and Series 8 preference shares for a total payment of $300 million.

• Distributions to noncontrolling interests and redeemable noncontrolling interests decreased as a result of the buy-in of our sponsored vehicles in the fourth quarter 2018.

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LEGAL AND OTHER UPDATES

LIQUIDS PIPELINES

Eddystone Rail Legal Matter

In February 2017, our subsidiary Eddystone Rail Company, LLC (Eddystone Rail) filed an action against several defendants in the United States District Court for the Eastern District of Pennsylvania (the Court). Eddystone Rail alleges that the defendants transferred valuable assets from Eddystone Rail’s counterparty in a maritime contract, so as to avoid outstanding obligations to Eddystone Rail. Eddystone Rail is seeking payment of compensatory and punitive damages in excess of US$140 million. On July 19, 2017, the defendants’ initial motions to dismiss Eddystone Rail’s claims were denied. Defendants have filed Answers and Counterclaims which, together with subsequent amendments, seek damages from Eddystone Rail in excess of US$32 million. Eddystone Rail filed a motion to dismiss the counterclaims and defendants amended their Answer and Counterclaims on September 21, 2017. On October 12, 2017 Eddystone Rail moved to dismiss the latest version of defendants’ counterclaims. On February 6, 2018, the Court denied without prejudice Eddystone Rail's motion to dismiss the defendants' counterclaims. The defendants’ chances of success on their counterclaims cannot be predicted at this time. On September 7, 2018, the Court granted Eddystone Rail's motion to amend its complaint to add several affiliates of the corporate defendants as additional defendants. Motions to dismiss Eddystone Rail’s amended complaint were subsequently denied by the Court. On January 25, 2019, defendants moved to dismiss Eddystone Rail’s claims from the Court based on lack of subject matter jurisdiction, which motion was denied by the Court on March 26, 2019.

Dakota Access Pipeline

In February 2017, the Standing Rock Sioux Tribe and the Cheyenne River Sioux Tribe filed motions with the Court contesting the validity of the process used by the United States Army Corps of Engineers (Army Corps) to permit the Dakota Access Pipeline (DAPL). The plaintiffs requested the Court order the operator to shut down the pipeline until the appropriate regulatory process is completed. The Oglala Sioux and Yankton Sioux Tribes also filed claims in the case to challenge the Army Corp permit and environmental review process.

On June 14, 2017, the Court ruled that the Army Corps did not sufficiently weigh the degree to which the project's effects would be highly controversial and the Army Corps failed to adequately consider the impact of an oil spill on the hunting and fishing rights of the Tribes and on environmental justice (the June 2017 Order). The Court ordered the Army Corps to reconsider those components of its environmental analysis. On October 11, 2017, the Court issued an order that allows DAPL to continue operating while the Army Corps completes the additional environmental review required by the June 2017 Order. The Court additionally ordered DAPL to implement certain interim measures pending the Army Corps' supplemental analysis. The Army Corps issued its decision on August 31, 2018, and found that no supplemental environmental analysis is required. All four Tribes amended their complaints to include claims challenging the adequacy of the Army Corps’ supplemental environmental analysis.

On February 4, 2019, the Army Corps produced its administrative record, which includes all documents pertaining to its remand process. On February 27, 2019, a plaintiff filed a motion challenging the completeness of the Army Corps’ administrative record, arguing that relevant documents had been improperly excluded. The Army Corps and DAPL opposed that motion on March 11, 2019, and the plaintiff filed a reply brief on March 18, 2019. Briefing on the administrative record challenge is now complete and a decision by the court is pending. A schedule for filing summary judgment briefs on the merits of the plaintiff Tribes’ remaining claims will be established following resolution of the administrative record challenge.

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Line 5 Dual Pipelines

In December 2018, Michigan law PA 359 was enacted which created the Mackinac Straits Corridor Authority (Corridor Authority) and authorized an agreement between us and the Corridor Authority for the construction of a tunnel under the Straits of Mackinac (Straits) to house a replacement for the Line 5 Dual Pipelines that currently cross the Straits. On December 19, 2018, we entered into a tunnel project agreement with the Government of Michigan under the administration of former Governor Snyder. On March 28, 2019, the new Michigan Attorney General issued an opinion finding the Michigan law PA 359 unconstitutional. Immediately following the Attorney General’s opinion that the Michigan law was unconstitutional, the new Michigan Governor Whitmer issued a directive to Michigan agencies to cease any action implementing the statute. We are currently in discussions with Governor Whitmer’s office about how to collaboratively advance the tunnel project.

OTHER LITIGATION

We and our subsidiaries 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 consolidated financial position or results of operations.

CAPITAL EXPENDITURE COMMITMENTS

We have signed contracts for the purchase of services, pipe and other materials totaling approximately $2.1 billion which are expected to be paid over the next five years.

TAX MATTERS

We and our subsidiaries maintain tax liabilities related to uncertain tax positions. While fully supportable in our view, these tax positions, if challenged by tax authorities, may not be fully sustained on review.

CHANGES IN ACCOUNTING POLICIES

Refer to Item 1. Financial Statements - Note 2. Changes in Accounting Policies.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our exposure to market risk is described in Part II. Item 7A. Quantitative and Qualitative Disclosures About Market Risk of our Annual Report on Form 10-K for the year ended December 31, 2018, as filed with the SEC on February 15, 2019. We believe our exposure to market risk has not changed materially since then.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Disclosure controls and procedures are controls and other procedures that are designed to ensure that information required to be disclosed by us in the reports we file or submit under the Securities Exchange Act of 1934 (Exchange Act) is recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to provide reasonable assurance that information required to be disclosed by us in the reports we file or submit under the Exchange Act is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

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Under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, we have evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as at March 31, 2019, and based upon this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that these controls and procedures are effective in ensuring that information required to be disclosed by us in reports that we file with or submit to the SEC and the Canadian Securities Administrators is recorded, processed, summarized and reported within the time periods required.

Changes in Internal Control over Financial Reporting

Under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, we have evaluated changes in internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the fiscal quarter ended March 31, 2019 and found no change that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

We are involved in various legal and regulatory actions and proceedings which arise in the ordinary course of business. While the final outcome of such actions and proceedings cannot be predicted with certainty, management believes that the resolution of such actions and proceedings will not have a material impact on our consolidated financial position or results of operations. Refer to Part I. Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations - Legal and Other Updates for discussion of other legal proceedings.

ITEM 1A. RISK FACTORS

In addition to the other information set forth in this report, careful consideration should be given to the factors discussed in Part I. Item 1A. Risk Factors of our Annual Report on Form 10-K for the year ended December 31, 2018, which could materially affect our financial condition or future results. There have been no material modifications to those risk factors.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

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The information set forth in this Item 5 is included herein for the purpose of providing the disclosure required under Item 5.02(b), (c) and (e) of Form 8-K.

On May 8, 2019, the Board of Directors (the Board) of Enbridge Inc. (Enbridge) appointed Colin K. Gruending as Executive Vice President & Chief Financial Officer and Mark A. Maki as Senior Vice President & Chief Accounting Officer, with each such appointment effective as of June 1, 2019 (the Effective Date).

Mr. Gruending will succeed John K. Whelen, Enbridge’s current Executive Vice President & Chief Financial Officer who, as of the Effective Date, will become Enbridge’s Executive Vice President & Chief Development Officer. As of the Effective Date, Mr. Maki will succeed Allen C. Capps, Enbridge’s current Senior Vice President & Chief Accounting Officer who will become Enbridge’s Senior Vice President, Corporate Development & Investment Review.

Mr. Gruending, 49, previously served as Senior Vice President, Corporate Development & Investment Review from 2018 to 2019, as Vice President, Corporate Development & Investment Review from 2017 to 2018, as Vice President, Corporate Development from 2016 to 2017 and as Vice President, Corporate Development & Planning from 2014 to 2016. Prior to that, Mr. Gruending served as Vice President, Treasury & Tax from 2011 to 2014 and as Vice President & Controller from 2005 to 2011. There is no arrangement or understanding between Mr. Gruending and any other person pursuant to which he was appointed and there are no family relationships between Mr. Gruending and any director or executive officer of Enbridge. Mr. Gruending has no direct or indirect material interest in any transaction required to be disclosed pursuant to Item 404(a) of Regulation S-K.

Mr. Maki, 54, previously served as Senior Vice President, Corporate Planning & Sponsored Vehicles from 2018 to 2019, as Senior Vice President, Finance Business Partners from 2017 to 2018 and as Senior Vice President, Finance from 2016 to 2017. Mr. Maki has also served as President & Principal Executive Officer of Enbridge Energy Management, L.L.C. and the General Partner, Enbridge Energy Company, Inc., since 2014. He served as President of Enbridge Energy Management, L.L.C. and as Senior Vice President of the General Partner from 2010 to 2014. There is no arrangement or understanding between Mr. Maki and any other person pursuant to which he was appointed and there are no family relationships between Mr. Maki and any director or executive officer of Enbridge. Mr. Maki has no direct or indirect material interest in any transaction required to be disclosed pursuant to Item 404(a) of Regulation S-K.

In connection with his appointment, starting on the Effective Date, Mr. Gruending will receive a base salary of C$525,000 and will be eligible to earn an annual discretionary bonus under Enbridge’s Short Term Incentive Plan, with a target of 80% of his base salary. On the Effective Date, Mr. Gruending will be granted performance stock units with grant value of C$656,000 under Enbridge’s 2019 Long-Term Incentive Plan (the 2019 LTIP) in respect of an increase to his 2019 long-term incentive target. These performance stock units will be subject to the terms and conditions of the form of award agreement set forth in Exhibit 10.5 to this Form 10-Q, which information is incorporated herein by reference.

On May 8, 2019, the Board also awarded William T. Yardley, Executive Vice President & President, Gas Transmission & Midstream restricted stock units under the 2019 LTIP having a grant value of US$1.5 million. The restricted stock units will vest as to 20% of the award on each of the first and second anniversaries of grant, with the remainder of such award vesting on the third anniversary of grant, in each case, subject to Mr. Yardley’s continued employment with Enbridge.

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ITEM 6. EXHIBITS

Each exhibit identified below is included as a part of this quarterly report. Exhibits included in this filing are designated by an asterisk (“*”); all exhibits not so designated are incorporated by reference to a prior filing as indicated.

Exhibit No.	Description
2.1	Agreement and Plan of Merger, dated as of September 5, 2016, by and among Spectra Energy Corp, Enbridge Inc. and Sand Merger Sub, Inc. (incorporated by reference to Exhibit 2.1 to Enbridge’s Registration Statement on Form F-4 filed September 23, 2017)
2.2	Agreement and Plan of Merger, dated as of August 24, 2018, by and among Spectra Energy Partners, LP, Spectra Energy Partners (DE) GP, LP, Enbridge Inc., Enbridge (U.S.) Inc., Autumn Acquisition Sub, LLC, and solely for the purposes of Articles I, II and XI, Enbridge US Holdings Inc., Spectra Energy Corp, Spectra Energy Capital, LLC and Spectra Energy Transmission, LLC. (incorporated by reference to Exhibit 2.1 to Enbridge’s Form 8-K filed August 24, 2018)
2.3	Agreement and Plan of Merger, dated as of September 17, 2018, by and among Enbridge Energy Partners, L.P., Enbridge Energy Company, Inc., Enbridge Energy Management, L.L.C., Enbridge Inc., Enbridge (U.S.) Inc., Winter Acquisition Sub II, LLC, and solely for the purposes of Articles I, II and XI, Enbridge US Holdings Inc. (incorporated by reference to Exhibit 2.1 to Enbridge’s Form 8-K filed September 18, 2018)
2.4	Agreement and Plan of Merger, dated as of September 17, 2018, by and among Enbridge Energy Management, L.L.C., Enbridge Inc., Winter Acquisition Sub I, Inc., and solely for the purposes of Article I, Section 2.4 and Article X, Enbridge Energy Company, Inc. (incorporated by reference to Exhibit 2.2 to Enbridge’s Form 8-K filed September 18, 2018)
2.5	Arrangement Agreement, dated as of September 17, 2018, by and between Enbridge Inc. and Enbridge Income Fund Holdings Inc. (incorporated by reference to Exhibit 2.3 to Enbridge’s Form 8-K filed September 18, 2018)
10.1*	Enbridge Inc. Short Term Incentive Plan (As Amended and Restated Effective January 1, 2019)
10.2*	Enbridge Inc. Directors’ Compensation Plan dated February 14, 2018 Amended Effective February 12, 2019
10.3	Enbridge Inc. 2019 Long Term Incentive Plan (incorporated by reference to Appendix A to Enbridge’s Proxy Statement on Schedule 14A for Enbridge’s Annual Meeting of Shareholders (File No. 001-15254) filed March 27, 2019)
10.4*	Form of Enbridge Inc. 2019 Long Term Incentive Plan Stock Option Grant Notice and Stock Option Award Agreement
10.5*	Form of Enbridge Inc. 2019 Long Term Incentive Plan Performance Stock Unit Grant Notice and Performance Stock Unit Award Agreement
10.6*	Form of Enbridge Inc. 2019 Long Term Incentive Plan Restricted Stock Unit Grant Notice and Restricted Stock Unit Award Agreement
10.7*	Form of Enbridge Inc. 2019 Long Term Incentive Plan Restricted Stock Unit - Energy Marketers Grant Notice and Restricted Stock Unit Award Agreement
31.1*	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*	Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

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32.1*	Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*	Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*	XBRL Instance Document.
101.SCH*	XBRL Taxonomy Extension Schema Document.
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF*	XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB*	XBRL Taxonomy Extension Label Linkbase Document.
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase Document.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

			ENBRIDGE INC.
			(Registrant)
Date:	May 10, 2019	By:	/s/ Al Monaco
			Al Monaco President and Chief Executive Officer
Date:	May 10, 2019	By:	/s/ John K. Whelen
			John K. Whelen Executive Vice President and Chief Financial Officer (Principal Financial Officer)

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EX-10.1

EXHIBIT 10.1

ENBRIDGE INC.

SHORT TERM INCENTIVE PLAN

(As Amended and Restated Effective January 1, 2019)

1. PURPOSE

The purpose of the Short Term Incentive Plan (the “Plan”) is to:

(a) create employee engagement in the understanding and achievement of annual business plans;

(b) focus employee performance on the achievement of objectives at the corporate, business unit and individual levels;

(c) assist in attracting, retaining and engaging employees who develop and execute the business plans of the Corporation and its subsidiaries; and

(d) tie competitive total cash compensation levels to the achievement of objectives at all levels.

2. DEFINED TERMS

In this Plan (including any schedules to this Plan):

(a) “affiliate” has the meaning ascribed to that term in the Securities Act (Alberta);

(b) “Base Salary” means the base salary of a Participant;

(c) “Board” means the Board of Directors of the Corporation;

(d) “CEO” means the Chief Executive Officer of the Corporation;

(e) “Changeof Control” means:

(i) the sale to a person or acquisition by a person not affiliated with the Corporation or its Subsidiaries of assets of the Corporation or its Subsidiaries having a value greater than 50% of the fair market value of the assets of the Corporation and its Subsidiaries determined on a consolidated basis prior to such sale whether such sale or acquisition occurs by way of reconstruction, reorganization, recapitalization, consolidation, amalgamation, arrangement, merger, transfer, sale or otherwise;

(ii) any change in the holding, direct or indirect, of shares of the Corporation by a person not affiliated with the Corporation as a result of which such person, or a group of persons, or persons acting in concert, or persons associated or affiliated with any such person or group within the meaning of the Securities Act (Alberta), are in a position to exercise effective control of the Corporation whether such change in the holding of such shares occurs by way of takeover bid, reconstruction, reorganization, recapitalization, consolidation, amalgamation, arrangement, merger, transfer, sale or otherwise; and for the purposes of this Plan, a person or group of persons holding shares or other securities in excess of the number which, directly or following conversion thereof, would entitle the holders thereof to cast 20% or more of the votes attaching to all shares of the Corporation which, directly or following conversion of the convertible securities forming part of the holdings of the person or group of persons noted above, may be cast to elect directors of the Corporation shall be deemed, other than a person holding such shares or other securities in the ordinary course of business as an investment manager who is not using such holding to exercise effective control, to be in a position to exercise effective control of the Corporation;

(iii) any reconstruction, reorganization, recapitalization, consolidation, amalgamation, arrangement, merger, transfer, sale or other transaction involving the Corporation where shareholders of the Corporation immediately prior to such reconstruction, reorganization, recapitalization, consolidation, amalgamation, arrangement, merger, transfer, sale or other transaction hold less than 50% of the shares of the Corporation or of the continuing corporation following completion of such reconstruction, reorganization, recapitalization, consolidation, amalgamation, arrangement, transfer, sale or other transaction;

(iv) the Corporation ceases to be a distributing corporation as that term is defined in the Canada Business Corporations Act;

(v) any event or transaction which the Board, in its discretion, deems to be a Change of Control; or

(vi) Incumbent Directors ceasing to be a majority of the Board;

provided that:

(vii) any transaction whereby shares held by shareholders of the Corporation are transferred or exchanged for units or securities of a trust, partnership or other entity which trust, partnership or other entity continues to own directly or indirectly all of the shares of the Corporation previously owned by the shareholders of the Corporation and the former shareholders of the Corporation continue to be beneficial holders of such units or securities in

the same proportions following the transaction as they were beneficial holders of shares of the Corporation prior to the transaction will be deemed not to constitute a change of control; and

(viii) any change of control initiated or commenced by the Board (and whether or not such transaction was initiated or commenced by the Board shall be conclusively determined by the Board) will not constitute a change of control for purposes of this Plan;

(f) “Code” means the United States Internal Revenue Code of 1986, as amended;

(g) “constructive dismissal” means, unless consented to by the Participant, any action that constitutes constructive dismissal of the Participant at common law, including without limiting the generality of the foregoing:

(i) where the Participant ceases to be an officer of the Corporation, unless the Participant is appointed as an officer of a successor to a material portion of the assets of the Corporation;

(ii) a material decrease in the title, position, responsibilities, powers or reporting relationships of the Participant;

(iii) a reduction in the Base Salary (excluding any annual incentive bonus) of the Participant; or

(iv) any material reduction in the value of the Participant’s employee benefits, plans and programs (other than any annual incentive bonus);

Notwithstanding the above, for a Participant who is (A) subject to the employment laws of any state of the United States and (B) not subject to the application of “constructive dismissal” under Canadian employment law, the term “constructive dismissal” hereunder means, unless consented to by such Participant, any action that constitutes pursuant to the law of the applicable state (including the common law) constructive discharge of the Participant; and, for all purposes of the Plan with respect to such Participant, “constructive dismissal” shall also include each of the actions described in clauses (i) through (iv) above.

(h) “Corporation” means Enbridge Inc., and includes any successor entity thereto;

(i) “Direct Reports” means executives of the Corporation or its Subsidiaries that report directly to the CEO;

(j) “Director” means a director of the Corporation;

(k) “Double Trigger Date” has the meaning given to it in subsection 8(i);

(l) “For Cause” includes “just cause” as defined in the common law and also includes any circumstance in which the Participant shall have been convicted of a criminal act of dishonesty resulting or intending to result directly or indirectly in gain or personal enrichment of the Participant;

(m) “HRC Committee” means the Human Resources and Compensation Committee of the Board, established and duly authorized to act by the Board;

(n) “Incumbent Director” means any member of the Board who was a member of the Board immediately prior to the occurrence of the transaction, elections or appointments giving rise to a Change of Control and any successor to an Incumbent Director who was recommended for election at a meeting of shareholders of the Corporation, or elected or appointed to succeed any Incumbent Director, by the affirmative vote of the directors, which affirmative vote includes a majority of the Incumbent Directors then on the Board;

(o) “Maximum Award” means, subject to Section 6(c), the maximum amount of compensation payable to a Participant under the Plan, being twice the Target Award;

(p) “Notice Period” means the notice period for termination of employment agreed to between the Corporation (or its Subsidiary) and the Participant, or, in the absence of any such agreement, the minimum statutory notice period that may be required under applicable employment standards legislation;

(q) “Participant” means an individual who becomes a participant of the Plan in accordance with Section 4;

(r) “Plan” means the Enbridge Inc. Short Term Incentive Plan, as amended and restated effective January 1, 2019 of the Corporation described in this document, and as the same may be duly amended or varied from time to time in accordance with the provisions of this Plan;

(s) “Retirement Plan” means a pension plan of the Corporation established or in effect from time to time which applies when an employee retires from the employment of the Corporation or its Subsidiaries;

(t) “STIP Payment” means the amount payable under the Plan to Participants upon the achievement of certain performance measures, calculated in accordance with Section 6;

(u) “Subsidiary” means

(i) any corporation that is a subsidiary (as such term is defined in the Canada Business Corporations Act) of the Corporation, as such provision is from time to time amended, varied or re-enacted;

(ii) any partnership or limited partnership that is controlled by the Corporation (the Corporation will be deemed to control a partnership or limited partnership if the Corporation possesses, directly or indirectly, the power to direct or cause the direction of the management or policies of such partnership or limited partnership, whether through the ownership of voting securities, by contract or otherwise); and

(iii) subject to regulatory approval, any corporation, partnership, limited partnership, trust, limited liability company or other form of business entity that the HRC Committee determines ought to be treated as a subsidiary for purposes of the Plan, provided that the HRC Committee shall have the sole discretion to determine that any such entity has ceased to be a subsidiary for purposes of the Plan;

(v) “Target Award” means the target amount of compensation payable to a Participant under the Plan, calculated as a percentage of the Participant’s annual Base Salary;

(w) “Term” means a period of one fiscal year of the Corporation or as otherwise determined by the HRC Committee; and

(x) “U.S. Taxpayer” means an individual whose income is subject to U.S. federal income taxation.

3. GOVERNANCE

(a) Subject to any determinations or approvals required to be made by the Board, the HRC Committee will administer the Plan in its sole discretion. The HRC Committee shall have the full power and sole responsibility to interpret the provisions of the Plan and to make regulations and formulate administrative provisions for its implementation, and to make such changes in the regulations and administrative procedures as, from time to time, the HRC Committee deems proper and in the best interests of the Corporation. Such regulations and provisions may include the delegation to any Director or Directors or any officer or officers of the Corporation or its Subsidiaries of such administrative duties and powers of the HRC Committee as it may, in its sole discretion, deem fit. The HRC Committee may amend the Plan to correct, remedy or reconcile any errors, inconsistencies or ambiguities in this Plan. The determinations of the HRC Committee in the administration of the Plan shall be final and conclusive.

(b) The HRC Committee shall have the authority to exercise discretion in the approval of STIP Payments, including without limitation the authority at any time to waive, amend or otherwise vary eligibility criteria, performance measures and the levels of Target and Maximum Awards under the Plan where in the opinion of the HRC Committee it is reasonable to do so and it does not materially prejudice

the rights of a Participant under the Plan and it does not cause the Participant to be subject to adverse tax treatment under Code Section 409A.

(c) Subject to any determinations or approvals required to be made by the HRC Committee under the Plan, the CEO shall have authority to administer the Plan.

4. PARTICIPATION AND TARGET AWARDS

(a) The CEO shall determine employees, other than his Direct Reports, eligible to participate in the Plan. The CEO shall recommend to the HRC Committee for its approval the participation in the Plan of his Direct Reports. The CEO shall also recommend to the HRC Committee for its approval the Target and Maximum Award for each Participant, other than the CEO.

(b) The CEO shall recommend to the HRC Committee for its approval the weighting for Corporation, business unit and individual performance measures of his Direct Reports.

(c) The HRC Committee will determine and recommend to the Board for its approval the Target and Maximum Award for the CEO.

(d) Directors who are not full-time employees of the Corporation or a Subsidiary shall not be eligible to become Participants.

(e) A designated employee shall have the right not to participate in the Plan, and any decision not to participate shall not affect his or her employment with the Corporation or a Subsidiary. Participation in the Plan does not confer upon the Participant any right to continued employment with the Corporation or a Subsidiary.

5. PERFORMANCE MEASURES

(a) At the start of each fiscal year the HRC Committee shall approve the Corporation performance measures, the target for the fiscal year and the levels of performance required to be achieved to receive a STIP Payment, and shall also approve any amendments to these measures and levels.

(b) The CEO shall establish:

(i) the weighting for Corporation, business unit and individual performance measures for all Participants, other than Direct Reports;

(ii) the financial targets and range of performance measures for each business unit;

(iii) any other scorecard performance measures, targets and range of performance measures for each business unit.

(c) The HRC Committee shall review and recommend to the Board for its approval the performance measures for the CEO.

(d) A copy of all performance measures that have been adopted under the Plan shall be appended to the minutes of the meeting at which such performances measures have been reviewed or approved, as applicable.

6. STIP PAYMENTS

(a) Except as otherwise provided herein, the amount of the STIP Payment for each Participant for a particular Term shall be based upon the achievement of the Corporation, business unit and individual performance measures established for the Participant under Section 5, the Base Salary of the Participant during the applicable Term, and if applicable, proration based on active service as defined in Section 8.

(b) Following receipt of the Corporation and business unit financial performance for the fiscal year and the receipt from the CEO of his recommendations on other performance measures, the HRC Committee will review and determine the extent to which the performance relative to targets has been achieved and shall approve the STIP Payments for all Participants except the CEO. The HRC Committee shall review and recommend to the Board for approval the CEO’s STIP Payment.

(c) Notwithstanding the foregoing, no STIP Payment payable to a Participant shall exceed an amount equal to two times the Target Award for the Participant for the Term unless approved by the CEO or, in the case of Direct Reports, unless approved by the HRC Committee. The CEO shall report to the HRC Committee by way of information, the Participants who are to receive a STIP Payment in excess of two times the Target Award.

(d) Notwithstanding the foregoing, no STIP Payment payable to a Participant designated as a “front office” employee within the energy marketing group shall exceed an amount equal to three times the Target Award for the Participant for the Term unless approved by the CEO. The CEO shall report to the HRC Committee by way of information, the “front office” Participants, other than energy marketing group employees, who are to receive a STIP Payment in excess of three times the Target Award. This Section 6(d) will become effective on January 1, 2014.

7. PAYMENTS

(a) Timing of Payment

Except as otherwise provided herein, the STIP Payment payable to a Participant hereunder in respect of a Term shall be paid to the Participant only upon approval by the Chair of the Audit, Finance and Risk Committee of the Corporation of

preliminary financial information and subsequent approval of the HRC Committee. In any event, payments shall be made no later than two and one-half months after the end of the Term.

(b) Form of Payment

Except where otherwise determined by the HRC Committee, all STIP Payments hereunder shall be paid in cash and shall be subject to applicable withholding taxes as required by applicable legislation.

8. TERMINATION

(a) Voluntary Termination

Except as otherwise provided in this Section 8, if a Participant voluntarily terminates his or her employment with the Corporation or a Subsidiary prior to the payment date for a STIP Payment as described in Section 7, such Participant shall not be entitled to receive the STIP Payment and the Participant’s eligibility for any STIP Payment shall be immediately cancelled upon the Participant’s voluntary termination of employment. For this purpose, a transfer of employment under which the Participant transfers his or her employment to the Corporation or to another Subsidiary shall not be considered a termination of employment under this Plan.

(b) Involuntary Termination Not For Cause

If the employment of a Participant with the Corporation or a Subsidiary is terminated by the Corporation (or its Subsidiary) for any reason other than For Cause, then the STIP Payment for the Participant for the Term shall be prorated based on the number of days of active employment of the Participant during the Term to the total number of days in the Term (and for this purpose the Notice Period shall be counted as active employment) and paid not later than the date specified in Section 7. For this purpose, the amount of STIP Payment shall be determined using Corporation, business unit and individual performance each at target (1x multiplier).

Any unpaid STIP Payment payable to the Participant in respect of a Term that has ended prior to the date of the Participant’s termination shall be paid in accordance with Section 7.

For the purposes of this subsection 8(b): (i) if a Participant’s employment terminates due to the constructive dismissal of the Participant; or (ii) if a Participant ceases to be employed by a Subsidiary of the Corporation because such Participant’s employer ceases to be a Subsidiary of the Corporation; then each such termination or cessation of being employed by a Subsidiary shall be

treated as an involuntary termination by the Corporation or a Subsidiary other than For Cause.

(c) Involuntary Termination For Cause

If the employment of a Participant is terminated by the Corporation or a Subsidiary For Cause, then all unpaid STIP Payments and all Target Awards in respect of such Participant shall be cancelled as of the Participant’s last day of employment with the Corporation (or its Subsidiary).

(d) Death

If the employment of a Participant with the Corporation or a Subsidiary is terminated as a result of the death of such Participant, the STIP Payment for the Participant for the Term shall be prorated based on the number of days of active employment of the Participant during the applicable Term to the total number of days in the Term. Such payment shall be made automatically without the requirement of pre-approval from the HRC Committee and shall be paid not later than two and one-half months from the date of death. For this purpose, the amount of STIP Payment shall be determined using Corporation, business unit and individual performance each at target (1x multiplier).

Any unpaid STIP Payment payable to the Participant in respect of a Term that has ended prior to the date of the Participant’s death shall be paid in accordance with Section 7.

(e) Retirement

If a Participant has attained the age of 55 and retires from his or her employment with the Corporation or a Subsidiary pursuant to a Retirement Plan, then the STIP Payment for the Participant for the Term shall be prorated based on the number of days of active employment of the Participant during the applicable Term to the total number of days in the Term and such amount shall be paid not later than the date specified in Section 7.

Any unpaid STIP Payment payable to the Participant in respect of a Term that has ended prior to date of the Participant’s retirement shall be paid in accordance with Section 7.

Notwithstanding the foregoing, should a Participant qualify for retirement under the definition provided within this subsection 8(e), and should the employment of such Participant with the Corporation or a Subsidiary be terminated by the Corporation (or its Subsidiary) for any reason other than For Cause, the provisions of subsection 8(b) will apply.

(f) Disability

If the employment of the Participant is terminated due to the “disability” of the Participant, the STIP Payment for the Participant for the Term shall be prorated based on the number of days of active employment of the Participant during the applicable Term to the total number of days in the Term and such amount shall be paid not later than the date specified in Section 7. For this purpose, the amount of STIP Payment shall be determined using Corporation, business unit and individual performance each at target (1x multiplier).

Any unpaid STIP Payment payable to the Participant in respect of a Term that has ended prior to date of the Participant’s disability shall be paid in accordance with Section 7.

For purposes of this subsection 8(f), a Participant is said to be suffering from a “disability” if he or she is eligible for benefits under a Corporation-sponsored long term disability benefits plan.

(g) Leaves of Absence

If a Participant commences a voluntary leave (including a parental or adoption leave) or other leave approved by the Corporation or any of its Subsidiaries, then the STIP Payment for the Participant for the Term shall be prorated based on the number of days of active employment of the Participant during the applicable Term to the total number of days in the Term.

Any unpaid STIP Payment payable to the Participant in respect of a Term that has ended prior to date of the Participant’s leave of absence shall be paid in accordance with Section 7.

(h) Secondments

If a Participant is seconded to an entity other than a Subsidiary, the HRC Committee (in the case of Participants that are Direct Reports) and the CEO (in the case of all other Participants) shall determine the treatment of Target Awards in respect of the Participant under the Plan; provided that no such Target Awards shall be treated in a manner that would cause the Participant to be subject to adverse tax treatment under Code Section 409A.

Notwithstanding the foregoing, any unpaid STIP Payment payable to the Participant in respect of a Term that has ended prior to date of the Participant’s secondment shall be paid in accordance with Section 7.

(i) Double Trigger Change of Control

If the employment of a Participant with the Corporation or a Subsidiary is terminated by the Corporation (or its Subsidiary) other than For Cause (including

if a Participant’s employment terminates due to the constructive dismissal of the Participant) within 2 years after the Change of Control, such Participant’s date of termination of employment being the “Double Trigger Date”, then the following provisions of this subsection 8(i) shall apply.

Each Participant shall be entitled to be paid a STIP Payment, unless otherwise determined by the HRC Committee, in an amount determined at the Double Trigger Date and prorated based on the number of days of active employment of the Participant in the Term to the Double Trigger Date to the total number of days in the Term using the following:

(i) Corporation, business unit and individual performance shall each be at target (1x multiplier); and

(ii) recommendations on other performance measures shall be provided by the CEO.

The STIP Payment shall be made within 75 days following the Double Trigger Date.

Any unpaid STIP Payment payable to the Participant in respect of a Term that has ended prior to the Double Trigger Date shall be paid in accordance with Section 7, provided, however, that such payment shall be made within 75 days following the Double Trigger Date.

Notwithstanding the above, with respect to Participants who are U.S. Taxpayers, no payment shall be made under this subsection 8(i) unless such Change of Control also qualifies as a change in the ownership or effective control of the Corporation, or in the ownership of a substantial portion of the assets of the Corporation, within the meaning of Code Section 409A(2)(A)(v). In the case of a Change of Control that does not so qualify, payments to any such Participant shall be made in accordance with Section 7. The payment monies owing to these Participants will be placed in an irrevocable trust which is located in the United States of America and subject to the claims of the general creditors of the Corporation prior to the Change of Control.

(j) No Future Awards

Upon the occurrence of any of the foregoing events listed under subsections 8(a) to (f) in respect of a Participant, such Participant shall not be entitled to receive any further awards under the Plan and, except as set forth herein, shall not be entitled to receive cash payment for the value of any unpaid STIP Payment, vested or unvested, held by the Participant as at the date of occurrence of such event.

9. NEW HIRES

If a Participant commences employment with the Corporation or a Subsidiary in the middle of a Term, then the STIP Payment for the Participant for the Term shall be prorated based on the number of days of active employment of the Participant during the Term to the total number of days in the Term, and paid not later than the date specified in Section 7.

10. FUNDING

For certainty, the Corporation has no obligation during any Term to pay or deposit any money into any account for the benefit of a Participant.

11. TAXES AND REPORTING

Notwithstanding anything else contained herein, each Participant shall be responsible for the payment of all applicable taxes, including, but not limited to, income taxes payable in connection with any payment under the Plan and the Corporation, its employees and agents shall bear no liability in connection with the payment of such taxes. The Corporation shall have the right to deduct from all cash payments made to a Participant any taxes required by law to be withheld with respect to such payments.

12. AMENDMENTS, ETC.

The HRC Committee may at any time recommend to the Board for its approval the revision, suspension or discontinuance of the Plan in whole or in part. No such revision, suspension, or discontinuance shall alter or impair the rights of a Participant in respect of a STIP Payment previously approved by the HRC Committee for such Participant, without the consent of that Participant. In addition, no revision, suspension or discontinuance shall result in adverse taxation under Code Section 409A or cause the Plan to become a “salary deferral arrangement” for the purposes of the Income Tax Act (Canada), unless otherwise determined by the HRC Committee with the consent of the Participant.

13. NO GUARANTEE OF EMPLOYMENT

The existence of the Plan is in no way to be construed as a guarantee of continued employment for any Participant, or of entitlement to any future Plan awards, benefits or payments.

14. CURRENCY

The currency of the STIP Payment for a Term will be the same currency as the Base Salary at the end of the same Term of a Participant.

15. EFFECT OF REORGANIZATION

In the event of any take-over bid or any proposal, offer or agreement for a merger, consolidation, amalgamation, arrangement, recapitalization, liquidation, dissolution or similar transaction or other business combination that is not a Change of Control in which the Corporation is not the surviving or continuing corporation (a “Reorganization”), all obligations of the Corporation to pay to a Participant any STIP Payment arising from an outstanding Target Award hereunder shall be assumed by the surviving or continuing corporation, provided that the HRC Committee or the Board may make appropriate adjustment in the manner and timing in which such payments are to be made prior to such assumption. If, in the event of any such Reorganization, provision for such assumption satisfactory to the HRC Committee or the Board is not made by the surviving or continuing corporation, each Participant shall have paid to him or her, in full satisfaction for any amounts payable to such Participant under the Plan, a STIP Payment in the amount that such Participant would receive if the Reorganization was treated as a Change of Control under Section 8(i), unless otherwise determined by the HRC Committee. Such payment shall be made within 30 days after the date of the Reorganization.

Notwithstanding the above, with respect to Participants who are U.S. Taxpayers, no payment shall be made under this Section 15 unless such Reorganization also qualifies as a change in the ownership or effective control of the Corporation, or in the ownership of a substantial portion of the assets of the Corporation, within the meaning of Code Section 409A(2)(A)(v). In the case of a Reorganization that does not so qualify, payments to any such Participant shall be made in accordance with Section 7. The payment monies owing to these Participants will be placed in an irrevocable trust which is located in the United States of America and subject to the claims of the general creditors of the Corporation prior to the Reorganization.

16. CONFLICT WITH WRITTEN EMPLOYMENT AGREEMENT

In the event of a conflict between the terms of this Plan and the terms of any written employment agreement between a Participant and the Corporation, the terms of the written employment agreement shall prevail.

17. CODE SECTION 409A COMPLIANCE

With respect to any Participant who is a U.S. Taxpayer, the Corporation intends that the Plan shall comply with the applicable provisions of Code Section 409A, or an exemption from the application of Code Section 409A, in order to prevent the inclusion in the gross income of such Participant of any amount in a taxable year that is prior to the taxable year in which such amount would otherwise be paid or made available to such Participant under the terms of the Plan. The Plan shall be construed, interpreted and administered in a manner consistent with such intent. In furtherance of this intent, to the extent that any term of the Plan is ambiguous, such term shall be interpreted to comply with Code Section 409A, or an exemption from the application of Code Section 409A, as determined by the Corporation. In no event may any participant who is a U.S. Taxpayer

designate, directly or indirectly, the calendar year of any payment to be made under the Plan.

18. INCENTIVE COMPENSATION CLAWBACK POLICY

Where applicable, payments made to Participants under this Plan will be governed by the terms of the Corporation’s Incentive Compensation Clawback Policy.

19. EFFECTIVE DATE

The effective date of the Plan, as amended and restated is January 1, 2019.

EX-10.2

EXHIBIT 10.2

ENBRIDGE INC.

DIRECTORS’ COMPENSATION PLAN

February 14, 2018

Amended Effective February 12, 2019

ENBRIDGE INC.

DIRECTORS’ COMPENSATION PLAN

1. DEFINED TERMS

As used herein, the following terms shall have the following meanings, respectively:

“Beneficiary” means any person(s) designated by a Director as indicated on the Designation of Beneficiary Form, to receive any cash amount or Shares under this Plan in the event of the Director’s death;

“Board” means the Board of Directors of the Corporation;

“Bonus Retainer” means a direct grant of DSUs to a Director in addition to such Director’s regular retainer.

“Canadian Election Form” means the election form required to be submitted by the Canadian Taxpayers to the Corporation;

“Canadian Taxpayer” means a Director whose income is subject to Canadian federal income taxation;

“Code” means the U.S. Internal Revenue Code of 1986, as amended;

“Comparator Group” has the meaning set forth in Section 4;

“Compensation” has the meaning set forth in Section 7;

“Corporation” means Enbridge Inc., and includes any successor corporation thereto;

“Deferred Stock Unit Account” has the meaning set forth in Subsection 9(a);

“Deferred Stock Units” or “DSUs” mean units credited to a Director in accordance with Subsection 9(b);

“Designation of Beneficiary Form” means the form attached hereto as Appendix “B”;

“Director” means a director of the Corporation;

“DRS” means the Direct Registration System;

“Dual-Taxed Member” means a Director that is both a U.S. Taxpayer and a Canadian Taxpayer;

“Estate” means the estate of a deceased Director;

“Governance Committee” means the Governance Committee of the Board;

“Market Value”, as of a particular day, means the weighted average of the trading price for one (1) Share on The Toronto Stock Exchange for the five (5) Trading Days immediately preceding that day;

“Payment Date” means the date on which Directors would normally receive payments of Compensation;

“Plan” means this Directors’ Compensation Plan effective January 1, 2018, as the same may be amended or varied from time to time;

“Retirement Date”,in respect of a Director, means the effective date on which the Director ceases to be a Director, for any reason whatsoever;

“Share” means a common share of the Corporation;

“Trading Day” means any day, other than a Saturday or Sunday, on which The Toronto Stock Exchange is open for trading;

“Trustee” means the trustee engaged by the Corporation for purposes of facilitating the payment of Share-based Compensation in accordance with Section 8.

“U.S. Election Form” means the election form required to be submitted by U.S. Taxpayers to the Corporation; and

“U.S. Taxpayer” means a Director whose income is subject to U.S. federal income taxation.

2. PURPOSE AND OBJECTIVES

(a) The purpose of this Plan is to provide a compensation system for Directors. This Plan applies only to the members of the Board and does not apply to board members of affiliate organizations or employees of the Corporation or any of its subsidiaries.

(b) The objectives of this Plan are:

(i) to compensate Directors commensurate with the risks, responsibilities and time commitments assumed by Board members;

(ii) to attract and retain the services of the most qualified individuals to serve on the Board;

(iii) to align the interests of Directors with the Corporation’s shareholders;

(iv) to provide competitive levels of compensation by considering various pay components typically provided to directors; and

(v) to deliver such compensation in a tax effective manner.

(c) The Board provides oversight and stewardship over this Plan through the Governance Committee and has overall responsibility for determining the philosophical framework of the Directors’ compensation program.

3. ADMINISTRATION

The Governance Committee will administer this Plan in its discretion. The Governance Committee shall have the power to interpret the provisions of this Plan and to make regulations and formulate administrative provisions for its implementation, and to make such changes in the regulations and administrative provisions as, from time to time, the Governance Committee deems proper and in the best interests of the Corporation. Such regulations and provisions may include the delegation to any Director(s) or any officer(s) of the Corporation of such administrative duties and powers of the Governance Committee as it may see fit.

4. EXTERNAL BENCHMARKING

(a) The Board supports maintaining a level of compensation for Directors that is competitive with compensation levels paid to directors of comparable public corporations; reflects the risks accompanying Board membership and the time commitments and responsibilities required of Directors, committee members and Board or Committee Chairs; and reflects the size and complexity of the Corporation’s business.

(b) The Governance Committee will, from time to time, with the assistance of qualified external experts in the area of compensation benchmarking, review and determine the appropriate comparable public corporations against which comparisons are made (the “Comparator Group”) with the intention that such Comparator Group be consistent with the periodic evaluation of executive management compensation.

(c) To the extent possible and appropriate, the Governance Committee shall align the Comparator Group with the group used to benchmark executive management compensation practices as approved by the Human Resources & Compensation Committee (refer to Enbridge Inc. senior management compensation policy Compensation Comparators).

5. COMMUNICATION

The Board recognizes that Compensation is an important component of corporate governance and is committed to ensuring that the material terms of the compensation program are properly disclosed to shareholders and regulators.

6. APPLICATION

This Plan applies to each individual while serving as a Director and, subject to Subsections 10(c), (d), (e), (f) and 11(a) (ii) and (iii), (c), (d) and (e), shall cease to apply on the Director’s Retirement Date.

7. DIRECTORS’ COMPENSATION

(a) General

The Board, on the recommendation of the Governance Committee, shall determine from time to time the amount of compensation to be paid to Directors (the “Compensation”) including, without limitation, amounts in respect of retainers (including the retainer for the Chair of the Corporation and Chairs of committees of the Board), Board meeting and committee meeting attendance fees, and any other amounts which the Board in its discretion considers to be appropriate. In addition, the Board shall determine the amount of expenses, if any, for which the Directors will be reimbursed.

(a) Fee Structure and Payment Particulars

(i) Compensation will be made on the basis of a flat fee structure that incorporates all Board, committee, and Chair retainers as determined by the Board. The Board’s policy is to target flat fee levels at the 50^th percentile of total compensation levels paid to directors of the Comparator Group (as defined in Section 4).

(ii) As of January 1, 2018, Compensation shall be as set out in Appendix “A”. Changes to Appendix “A” may be made by the Board following a recommendation of or consultation with the Governance Committee. Upon any such change being approved by the Board, a new Appendix “A” incorporating the changes and effective as of the date established by the Board shall be attached to the Plan and become Appendix “A” for all purposes of the Plan.

(iii) Compensation is paid quarterly, in arrears. All Directors, regardless of country of residency, shall be paid in US dollars.

(iv) A percentage of the Compensation may be withheld in cases where a Director’s attendance at Board meetings or Committee meetings or both, falls below the established minimum. The Governance Committee will review the continuation of the Director on the Board if an inordinate number of meetings are missed.

(v) At any time, the Board, on the recommendation of the Governance Committee, may grant to Directors a Bonus Retainer in the form of a direct grant of DSUs. For U.S. Taxpayers only, DSUs comprising a Bonus Retainer shall be payable on December 31 of the year following the year of the Director’s Retirement Date and no U.S. Taxpayer shall be permitted to elect the form or timing of payment of any portion of a Bonus Retainer.

(b) Forms of Payment

The Board, on the recommendation of the Governance Committee, shall determine the portion(s), if any, of the Compensation that a Director may elect to receive by way of cash, Shares or Deferred Stock Units. Until revised by the Board, each Director and Chair of the Board will, subject to requirements of minimum share ownership criteria, as set out in Appendix “A”, elect to receive Compensation as

cash, Shares or Deferred Stock Units, in whole or in part, in increments of 5% (totalling 100% of the Compensation payable to such Director).

8. COMPENSATION - SHARES

(a) In respect of any amount of Compensation payable to a Director in Shares, funds sufficient for the purchase in the open market of such Shares shall be paid to the Trustee by the Corporation in trust for such Director from time to time, and shall be applied by the Trustee to the purchase of Shares, in the open market on a stock exchange, for that Director.

(b) The Shares to which a Director becomes entitled hereunder shall be calculated on the basis of the Market Value thereof two (2) weeks prior to the Payment Date.

(c) The Trustee shall cause such Shares to be registered in the name of the Director and held in electronic book-entry form through the DRS.

(d) The Trustee shall cause the transfer agent to provide (i) a Direct Registration (DRS) Advice to each Director promptly after each purchase of Shares on such Director’s behalf, which will set out the number of Shares so purchased and the aggregate number of Shares held by such Director in the DRS, and (ii) a Direct Registration (DRS) Statement to each such Director annually. In addition, the Trustee shall promptly provide any other information required by the Director for tax reporting purposes.

9. COMPENSATION - DEFERRED STOCK UNITS

(a) Deferred Stock Unit Account

An account, to be known as a “Deferred Stock Unit Account”, shall be maintained by the Corporation for each Director and will show the number of Deferred Stock Units credited to a Director, to four (4) decimal places, from time to time.

(b) Crediting Deferred Stock Unit Account

In respect of any amount of Compensation payable to a Director in Deferred Stock Units, the number of Deferred Stock Units to be credited to that Director will be calculated by dividing the dollar amount of the quarterly Compensation payable to that Director in Deferred Stock Units on the Payment Date by the Market Value two (2) weeks prior to such date.

(c) Additional Deferred Stock Units From Dividends On Shares

In addition to Subsection 9(b), whenever any cash dividend or other cash distribution is paid on the Shares, additional Deferred Stock Units will be credited to the Director’s Deferred Stock Unit Account. The number of such additional Deferred Stock Units will be calculated by dividing the aggregate dividends that would have been paid to such Director if the Deferred Stock Units in the Director’s Deferred Stock Unit Account had been Shares, by the Market Value of a Share on the date on which the dividends are paid on the Shares, less the amount of any discount then in effect

for the reinvestment of dividends under the Corporation’s Dividend Reinvestment and Share Purchase Plan.

10. CANADIAN TAXPAYER - DEFERRED STOCK UNITS

This Section 10 only applies to Canadian Taxpayers:

(a) Choice of Compensation Mix

(i) The Directors shall elect on or before December 31 of the preceding year in which Compensation will be earned, the portion of such Compensation, excluding any Bonus Retainer, to be received by the Director in cash, Shares or Deferred Stock Units in respect of that calendar year, and, failing such election, the Director shall, subject to any minimum amounts of cash, Shares or Deferred Stock Units as set out in Appendix “A”, be deemed to have elected 100% in cash.

(ii) Where a Director joins the Board after January 1 in any year, such Director shall make his or her compensation mix election within thirty (30) days of his or her election or appointment to the Board.

(iii) In all cases, the Directors’ elections shall be irrevocable and shall remain in force from the date of such election until the date of the next election.

(b) Canadian Election Form

Each Director shall fill out a Canadian Election Form indicating their elected compensation mix and deliver such Canadian Election Form to the Corporation on the dates set out above.

(c) Elected Payment Date – Canadian Taxpayer

Except as provided in Subsection 10(e), the determined value of the Deferred Stock Units credited to the Deferred Stock Unit Account of a Director whose income is subject to Canadian income tax, net of required withholdings, shall be paid to that Director on a date to be agreed upon by that Director and the Corporation, provided that the payment date must be a date subsequent to the Retirement Date and may be no later than December 31 of the first calendar year commencing after that Retirement Date.

(d) No Election Default

If no such payment date agreement is reached, pursuant to Subsection 10(c), the payment date will be December 31 of the first calendar year commencing after that Director’s Retirement Date.

(e) Payment on Death of a Canadian Taxpayer

(i) When a Director dies, the value of the Deferred Stock Units credited to that Director’s Deferred Stock Unit Account, net of applicable withholdings, shall

be paid to his or her Beneficiary as soon as practicable after the Director’s death, provided that the payment shall be made no later than December 31 of the first calendar year commencing after that Director’s Retirement Date.

(ii) Notwithstanding the above, if the Beneficiary of the deceased Director has not been determined within sixty (60) days after the Director’s death, the Corporation shall make such payment to the Estate.

(f) Determining Value for Canadian Taxpayers

To determine the value of Deferred Stock Units for the purposes of a payment to a Director (or, where the Director has died, his or her Beneficiary or Estate, as the case may be) under Subsections 10(c), (d) or (e), a Deferred Stock Unit will be valued equal to the Market Value multiplied by the number of Deferred Stock Units (including fractional Units) credited to a Director’s Deferred Stock Unit Account on the following basis:

(i) for Subsections 10 (c) and (d), the Market Value on the third (3^rd) Trading Day before the elected payment date; and

(ii) for Subsection 10(e), the Market Value on the next Trading Day after the Director’s death.

(g) Effect of Reorganization of the Corporation for Canadian Taxpayers

In the event of any merger, consolidation or other reorganization of the Corporation in which the Corporation is not the surviving or continuing corporation, all Deferred Stock Units granted hereunder and outstanding on the date of such reorganization shall be assumed by the surviving or continuing corporation. If, in the event of any such merger, consolidation or other reorganization, provision for such assumption satisfactory to an owner of a Deferred Stock Unit granted under this Plan is not made by the surviving or continuing corporation, such owner shall have distributed to him or her within sixty (60) days after the reorganization, in full satisfaction, cash in payment of the Market Value on the Trading Day immediately preceding the day of such reorganization.

11. US TAXPAYER- DEFERRED STOCK UNITS

This Section 11 only applies to U.S. Taxpayers:

(a)Choice of Compensation Mix and Election Payment Date

Directors shall elect on or before December 31 of the calendar year immediately preceding the calendar year in which Compensation will be earned:

(i) the portion of such Compensation, excluding any Bonus Retainer, to be received by those Directors in cash, Shares or Deferred Stock Units in respect of that calendar year. If no election is made the Director shall, subject

to any minimum amounts of cash, Shares or Deferred Stock Units as set out in Appendix “A”, be deemed to have elected 100% in cash;

(ii) the date, to be agreed upon by each of the Directors and the Corporation for payment of such Director’s Deferred Stock Unit Account where such date may be any date after that Director’s Retirement Date, provided that the payment date is after that Retirement Date and no later than December 31 of the first calendar year commencing after that Retirement Date. If no such payment date is determined, the Corporation, at its sole discretion, shall pay the amount owing from Director’s Deferred Stock Unit Account within ninety (90) days following that Director’s Retirement Date;

(iii) where a Director joins the Board after January 1 in any year, such Director shall make his or her election for both compensation mix and payment date within thirty (30) days of his or her election or appointment to the Board; and

(iv) in all cases, the Directors’ elections shall be irrevocable and shall remain in force from the date of such election until the Director’s Retirement Date.

(a) U.S. Election Form

Each Director shall fill out a U.S. Election Form indicating their elected compensation mix and payment date of their Deferred Stock Unit Account and deliver such U.S. Election Form to the Corporation. Such form shall be irrevocable.

(b) Specified Employee

Notwithstanding Subsection 11 (a), if the payment of a Director’s Deferred Stock Unit Account would be subject to taxation or penalties under Code Section 409A because the timing of such payment is not delayed as provided in Section 409A for a “specified employee,” then if the Director is (1) a U.S. Taxpayer and (2) a “specified employee” under Code Section 409A, any payment which that Director would otherwise be entitled to receive during the six (6) month period following the Director’s Retirement Date shall be delayed and paid within fifteen (15) days after the date that is six (6) months following the Director’s Retirement Date, or such earlier date upon which such amount can be paid under Code Section 409A without being subject to such taxation, such as upon that Director’s death.

(c) Payment on Death of a U.S. Taxpayer

(i) When a Director dies, the value of the Deferred Stock Unit Account, credited to that Director’s Deferred Stock Unit Account, net of applicable withholdings, shall be paid to his or her Beneficiary not later than by the later of (i) the end of the calendar year of the Director’s Retirement Date, or (ii) ninety (90) days following that Director’s date of death, provided that the Beneficiary shall not be permitted to designate the taxable year in which such payment is made.

(ii) Notwithstanding the above, if the Beneficiary of the deceased Director has not been determined within sixty (60) days after the Director’s death, the Corporation shall make such payment to the Estate.

(e)    Determining Value for U.S. Taxpayers

To determine the value of Deferred Stock Units for the purposes of a payment to a Director (or, where the Director has died, his or her Beneficiary or Estate, as the case may be) under Subsections 11(a)(ii), (iii), (c) or (d), a Deferred Stock Unit will be valued equal to the Market Value multiplied by the number of Deferred Stock Units (including fractional Units) credited to a Director’s Deferred Stock Unit Account on the following basis:

(i) for Subsections 11(a)(ii),(iii) and (c), the Market Value on the third (3^rd) Trading Day before the elected payment date; and

(ii) for Subsection 11(d), the Market Value on the next Trading Day after the Director’s death.

(a) Dual-Taxed Members

In the event that a Director is both a U.S. Taxpayer and a Canadian Taxpayer at the time that the Director’s Deferred Stock Units become payable, the provisions of this Section 11(f) shall apply:

(i) If the Director has made a valid election under Section 11(a) and (b) with regard to payment of the Director’s Deferred Stock Units, payment of such Director’s Deferred Stock Unit Account shall be made in accordance such election, subject to Section 11(c).

(ii) If the Director has not made a valid election under Section 11(a) and (b) with regard to payment of the Director’s Deferred Stock Units, payment of such Director’s Deferred Stock Unit Account shall be made as of a date determined by the Corporation in its discretion, with such payment date to be within ninety (90) days following the Director’s Retirement Date, subject to the following:

a. If the ninety (90) day period begins in one calendar year and ends in the following calendar year, the payment date within such 90-day period shall be determined in the sole discretion of the Corporation, and the Director shall not be permitted to make a payment election under Section 10(c) and (d) of the Plan that applies for a Canadian Taxpayer; or

b. If the ninety (90) day period begins and ends in the same calendar year, the Director shall be permitted to make a payment election under Section 10(c) and (d) of the Plan, but the payment date elected by the Director must fall within the 90-day period following the Director’s Retirement Date.

(g)    Code Section 409A Compliance

With respect to any Director who is a U.S. Taxpayer, the Corporation intends that this Plan shall comply with the applicable provisions of Code Section 409A, or an exemption from the application of Code Section 409A, in order to prevent the inclusion in the gross income of such Director of any deferred amount in a taxable year that is prior to the taxable year in which such amount would otherwise be distributed or made available to such Director under the terms of this Plan. This Plan shall be construed, interpreted and administered in a manner consistent with such intent. In furtherance of this intent, to the extent that any term of this Plan is ambiguous, such term shall be interpreted to comply with Code Section 409A, or an exemption from the application of Code Section 409A, as determined by the Corporation.

(h) Effect of Reorganization of the Corporation for U.S. Taxpayers and Dual-Taxed Members

In the event of any merger, consolidation or other reorganization of the Corporation where the surviving or continuing corporation does not assume all of the Director’s Deferred Stock Units that are outstanding on the date of such reorganization, and such event constitutes a “change in control” of the Corporation within the meaning of Code Section 409A, then the surviving or continuing corporation shall distribute to the Director, within sixty (60) days after the closing date of such event, in complete satisfaction of all the rights of the Director under this Plan, cash in full payment of the Market Value of the Director’s Deferred Stock Units as valued as of the Trading Day immediately preceding the closing date of such event. In the event that the Director is a Dual-Taxed Member, this Section 11(h) shall apply and Section 10(g) shall be inapplicable.

12. BROKERAGE COMMISSIONS

All brokerage commissions and other transaction costs in respect of Share purchases made under Section 8 of this Plan shall be paid by the Corporation.

13. TAXES AND REPORTING

(a) The Corporation shall deduct from all amounts otherwise payable to a Director (or Beneficiary or Estate, as the case may be) all amounts, including applicable taxes, that are required by law to be withheld with respect to amount otherwise payable.

(b) Notwithstanding anything else contained herein, each Director who participates in this Plan shall be responsible for:

(i) the payment of all applicable taxes including, but not limited to, income taxes payable in connection with the acquisition, holding and delivery of Shares for or to a Director pursuant to this Plan and the payment of the value of the Deferred Stock Units, subject to deduction and remittance by the Corporation of applicable withholding taxes; and

(ii) compliance with the continuous disclosure requirements of the applicable securities commissions or similar regulatory authorities in Canada and those exchanges upon which the Corporation’s Shares are traded, including, but not limited to, the preparation and filing of insider trading reports respecting the acquisition of Shares pursuant to this Plan,

and the Corporation, its employees and agents shall bear no liability in connection with the payment of such taxes or the compliance with such disclosure requirements.

14. DILUTION ADJUSTMENTS

In the event that the outstanding Shares of the Corporation shall be increased or decreased, or changed into, or exchanged for a different number or kind of shares or other securities of the Corporation or another corporation, whether through a stock dividend, stock split, consolidation, recapitalization, amalgamation, reorganization, arrangement or other transaction, the Governance Committee or the Board may make appropriate adjustments to the number or kind of shares or securities upon which Deferred Stock Units are based under this Plan, and as regards Deferred Stock Units previously granted or to be granted pursuant to this Plan, in the number or kind of shares or securities upon which Deferred Stock Units are based and the purchase price therefor.

15. OPERATION OF RIGHTS PLAN

The appropriate adjustments in the number of Deferred Stock Units may be made by the Board in its discretion in order to give effect to the adjustments in the number of Shares of the Corporation resulting from the implementation and operation of the Shareholder Rights Plan Agreement originally dated as of November 9, 1995 and as amended from time to time.

16. AMENDMENTS, ETC.

Subject to applicable regulatory approval, the Board may revise, suspend or discontinue this Plan in whole or in part. No such revision, suspension, or discontinuance shall alter or impair the rights of a Director in respect of Deferred Stock Units or Shares previously granted or received under this Plan, without the consent of that Director.

17. PERIODIC REVIEW

The compensation available, and competitiveness of this Plan relative to the Comparator Group, will be reviewed:

(a) by external consultants every second year, commencing in 2015; and

(b) by internal management every second year, commencing in 2014.

18. EFFECTIVE DATE

This Plan is effective as of January 1, 2018, and may be amended from time to time. Commencing January 1, 2018, no new Shares or Deferred Stock Units shall be granted or received under any

previous “Directors’ Compensation Plan” for Enbridge Inc. Any Shares or Deferred Stock Units previously granted or received under such previous compensation plans shall continue without alteration, including any previous elected payment date made by a Director, or impairment of the rights of a Director with respect to such Compensation.

APPENDIX “A”

to the Directors’ Compensation Plan

Retainer and Fees

1. Flat Fee Schedule

The following table establishes the annual fee schedule for Directors and is effective as of January 1, 2018.

		Elective Payment Form1
Compensation Elements	Annual Fee2	Before minimum share ownership			After minimum share ownership
		Cash	Shares	DSUs	Cash3	Shares3	DSUs3
Board Retainer	$260,0004	Up to 50%	Up to 50%	50% to 100%	Up to 65%	Up to 65%	35% to 100%
Additional Board Chair Retainer	$260,000
Additional Committee Chair Retainer: AFRC HRCC S&R GC CSR	$25,000 $20,000 $15,000 $10,000 $10,000

1.    Directors may elect the form of payment in increments of 5% up to the percentage amounts specified in the table.

2. All fees in U.S. dollars.

3. For retainers in 2018, the elective payment form after minimum share ownership remains unchanged at cash up to 75%, shares up to 75% and DSUs 25% to 100%. For retainers in 2019, the revised percentages shown in the table apply, and at least 35% of any retainer payable must be elected in the form of Deferred Stock Units.

4. To be phased in equally over two years in 2018 and 2019, with an increase of $12,500 in 2018 (to be granted entirely in DSUs under section 7(b)(v) of this Plan) for a total of $247,500 and a subsequent increase of $12,500 in 2019 for a total of $260,000 (to be subject to Director elections in the normal course prior to December 31, 2018).

2. Penalty for Non-Attendance

At the end of each year, the Governance Committee will review the record of attendance of Directors at Committee meetings and Board meetings. The Chair of the Governance Committee along with the Board Chair, at their discretion, will recommend to the Board appropriate penalties for non-attendance by Directors at Committee and Board meetings.

3. Travel Fees

A per diem allowance of $1,500 U.S. shall be paid in cash to Directors who travel from their home state or province to a meeting in another state or province.

4. Share Ownership Requirement

Effective January 1, 2016, Directors shall hold a personal investment in Shares and Deferred Stock Units of at least three (3) times the amount of the annual Board Retainer, expressed in Canadian currencyand be required to achieve such investment within five (5) years of joining the Board.

APPENDIX “B”

to the Directors’ Compensation Plan

DESIGNATION OF BENEFICIARY FORM

I, _____________________________________ (Director’s Name) for the purposes of

designating a Beneficiary pursuant to the Directors’ Compensation Plan of Enbridge Inc.

hereby designate _______________________ (insert name of Beneficiary (ies)) as my

Beneficiary of the Compensation owed to me by the Corporation.

At my own discretion, I make an additional designation should my Beneficiary not survive me.

I designate as my contingent Beneficiary _________________________________ (insert

name of contingent Beneficiary) of the Compensation owed to me by the Corporation.

I make this designation on the _____ day of _______, 20____.

________________________

Signature

________________________

Print Name    

Instructions:

This Designation of Beneficiary Form should be completed, signed and delivered to Enbridge Inc. as soon as possible once you have been appointed to the Board of the Corporation. Any changes to the above will require the delivery of an amended form.

In the event that you would like to name a contingent beneficiary, should your primary beneficiary not survive you, please indicate above, a contingent beneficiary.

For questions regarding your Plan or Form, please call Tyler Robinson at (403) 231-5935.

For delivery to Enbridge Inc., please fax your Form to (403) 231-5929.

EX-10.4

EXHIBIT 10.4

ENBRIDGE INC.2019 LONG TERM INCENTIVE PLAN

STOCK OPTION GRANT NOTICE

Pursuant to the Enbridge Inc. 2019 Long Term Incentive Plan (the “Plan”), Enbridge Inc. (the “Company”), has granted to the participant listed below (“Participant”) the stock option (the “Option”) described in this Stock Option Grant Notice (the “Grant Notice”), subject to the terms and conditions of the Plan and the Stock Option Award Agreement, attached hereto as Exhibit A (the “Agreement”), both of which are incorporated into this Grant Notice by reference. Capitalized terms not specifically defined in this Grant Notice shall have the meanings given to them in the Agreement, and if not defined in the Agreement, the meanings given to them in the Plan.

Participant:
Grant Date:
Grant Price per Share:
Shares Subject to the Option:
Final Expiration Date:
Vesting and Exercise Schedule:	See Sections 2.1(a) and 2.4

By Participant’s signature below, Participant agrees to be bound by the terms of this Grant Notice, the Plan and the Agreement effective as of the Grant Date. Participant has reviewed the Plan, this Grant Notice and the Agreement in their entireties, and acknowledges that the Company hereby advises Participant to obtain the advice of counsel prior to executing this Grant Notice. Participant fully understands and accepts all provisions of the Plan, this Grant Notice and the Agreement (including, without limitation, the shareholder approval and ratification requirement set forth in Section 1.2 of the Agreement). Participant hereby agrees to accept as binding, conclusive and final all decisions or interpretations of the Administrator upon any questions arising under the Plan, this Grant Notice or the Agreement. Participant agrees that the Grant Notice, the Agreement and the Plan constitute the entire agreement with respect to the Option.

Enbridge Inc.:                        Participant:

By:    

Name:        Name:

Title:    

Exhibit A

STOCK OPTION AWARD AGREEMENT

ARTICLE I.

GENERAL

1.1Grant of Option. Subject to the terms and conditions of this Agreement (including, without limitation, the shareholder approval and ratification requirement set forth in Section 1.2) and the Plan, the Company has granted to Participant, effective as of the Grant Date set forth in the Grant Notice (the “Grant Date”) an award of Options as set forth in the Grant Notice.

1.2[Shareholder Approval and Ratification Requirement. This Award will be contingent upon and effective as of approval of the Plan and ratification of the Award by the Company’s shareholders at the 2019 Annual Meeting. If the shareholders do not approve the Plan or ratify the Award at the 2019 Annual Meeting, then this Agreement shall be null and void and the Participant shall have no rights or interests of any kind with respect to the Options.]

1.3Nature of Award. The Options granted to Participant pursuant to the Grant Notice and this Agreement are prospective in nature such that the Award is not in respect of service rendered in a year prior to the year that includes the Grant Date.

1.4Incorporation of Terms of Plan. The Option is subject to the terms and conditions set forth in this Agreement and the Plan. The Plan is incorporated herein by reference. In the event of any inconsistency between the Plan and this Agreement, the terms of the Plan will control.

1.5Defined Terms. Capitalized terms not specifically defined in this Agreement shall have the meanings specified in the Grant Notice or, if not defined in the Grant Notice, in the Plan.

ARTICLE II.
VESTING AND EXERCISABILITY

2.1Vesting and Exercisability.

(a)General. Subject to the limitations contained herein and Section 2.1(b), the Option will vest and become exercisable according to the following Vesting Schedule (the “Vesting Schedule”): the total number of Shares subject to the Option shall vest in [twenty-five percent (25%)] increments (rounded down to the next whole number of Shares) on each of the [first, second, third and fourth] anniversaries of the Grant Date.

(b)Accelerated Vesting.

(i)CIC Termination. In the event that Participant has a Termination of Service within two years following a Change in Control, due to (1) involuntary Termination of Service by the Company or a Subsidiary without Cause or (2) Termination of Service by Participant for Good Reason (in each case, a “CIC Termination”), then the unvested portion of the Option will become immediately 100% vested upon the date of such Termination of Service.

(ii)Death. In the event that Participant has a Termination of Service due to the Participant’s death, then the unvested portion of the Option will become immediately 100% vested upon the date of the Participant’s death.

(iii)Disability. In the event that Participant has a Termination of Service due to the Participant’s Disability, then the Option shall continue to vest in accordance with its terms, as specified herein and in the Plan, and subject to the earlier expiration of the Option in accordance with Sections 2.3 and 2.4(b), as if Participant did not have a Termination of Service.

(iv)Retirement. In the event that Participant has a Termination of Service due to the Participant’s Retirement, then the Option shall continue to vest in accordance with its terms, as specified herein and in the Plan, and subject to the earlier expiration of the Option in accordance with Sections 2.3 and 2.4(b), as if the Participant did not have a Termination of Service. Notwithstanding the foregoing, if the Participant is eligible for Retirement at a time when the Participant incurs an involuntary Termination of Service by the Company or a Subsidiary without Cause, then Section 2.1(b)(v) shall apply and govern the vesting and exercise of the Option.

(v)Involuntary Termination Without Cause. In the event that Participant has a Termination of Service due to the Participant’s involuntary Termination of Service by the Company or a Subsidiary without Cause (other than a CIC Termination), then the Option shall continue to vest in accordance with its terms, as specified herein and in the Plan, and subject to the earlier expiration of the Option in accordance with Sections 2.3 and 2.4(b), as if the Participant did not have a Termination of Service. For purposes of this Section 2.3(b), if a Participant’s employment terminates due to the constructive dismissal of the Participant or if a Participant ceases to be employed by a Subsidiary of the Company because such Participant’s employer ceases to be a Subsidiary of the Company, then such termination or cessation of employment shall be treated as an Termination of Service due to the Participant’s involuntary Termination without Cause.

2.2Company’s Obligation. Unless and until the Option vests and is exercised, Participant will have no right to receive Shares under the Option. Prior to actual distribution of Shares pursuant to any vested and exercised Option, such Option will represent an unsecured obligation of the Company.

2.3Duration of Exercisability. Any portion of the Option that vests and becomes exercisable will remain vested and exercisable until the Option expires in accordance with Section 2.4.

2.4Expiration of Option.

(a)Except as otherwise provided in Section 2.1(b), the unvested portion of the Option will terminate and expire automatically without further notice immediately upon the Participant’s Termination of Service.

(b)The Option (to the extent not earlier terminated and expired as provided in Section 2.4(a)) will terminate and expire automatically and without further notice on the earliest of the dates set forth below:

(i) The Final Expiration Date set forth in the Grant Notice;

(ii) The expiration of thirty (30) days from the date of Participant’s Termination of Service (or any longer period that the Administrator may otherwise approve); provided that this Section 2.4(b)(ii) shall not apply if the vesting set forth in Section 2.1(b)(i)-(v) applies;

(iii) One (1) year following the Participant’s Termination of Service due to the Participant’s death;

(iv) Three (3) years following the Participant’s Termination of Service due to the Participant’s Retirement;

(v) The expiration of thirty (30) days from the Participant’s Termination of Service plus any applicable Notice Period for an involuntary Termination of Service by the Company or a Subsidiary without Cause (other than a CIC Termination); and

(vi) Immediately upon the date of Participant’s Termination of Service for Cause.

IT IS PARTICIPANT’S RESPONSIBILITY TO BE AWARE OF THE DATE ON WHICH THE OPTION EXPIRES.

ARTICLE III.
EXERCISE OF OPTION

3.1Persons Eligible to Exercise. During Participant’s lifetime, only Participant may exercise the Option. After Participant’s death, any vested and exercisable portion of the Option may, prior to the time the Option expires, be exercised by Participant’s designated beneficiary as provided in the Plan; provided that, if no beneficiary has been designated by Participant, then the vested and exercisable portion of the Option may be exercised by the personal representative of Participant’s estate, or by the persons to whom the Option is transferred pursuant to Participant’s will or in accordance with the laws of descent and distribution, after receipt and acceptance of proper instructions from the estate by the Administrator.

3.2Partial Exercise. Any exercisable portion of the Option, or the entire Option if then wholly exercisable, may be exercised, in whole or in part, at any time prior to the time the Option or portion thereof expires, except that the Option may only be exercised for whole Shares. Exercising an Option in any manner shall decrease the number of Shares thereafter available for sale under the Option by the number of Shares as to which the Option is exercised.

3.3Procedure for Exercise. Participant may exercise the Option by giving written or electronic notice to the Company, in form and substance satisfactory to the Company (the “Exercise Notice”), which will state the election to exercise the Option, specify the number of Shares for which Participant is exercising the Option and provide such other representations and agreements as the Company may require pursuant to the provisions of the Plan. The Exercise Notice must be accompanied by an amount equal to the Grant Price multiplied by the number of Shares specified in the Exercise Notice. Such payment may be made (a) by certified check, bank draft or money order payable to the order of the Company or (b) by surrendering Shares then issuable upon the Option’s exercise (with the Fair Market Value of such Shares determined as of the exercise date in the sole discretion of the Administrator, in each case, subject to and in accordance with the Company’s policies in effect from time to time concerning Options and other awards granted under the Plan).

3.4Tax Withholding.

(a)No Shares shall be delivered to Participant or any other person until Participant or such other person has made arrangements acceptable to the Administrator for the satisfaction of any non-U.S., U.S.-federal, U.S.-state, or local income and employment tax withholding obligations, including, without limitation, obligations incident to the receipt of Shares. Upon exercise of the Option, the Company shall withhold or collect from Participant an amount sufficient to satisfy such tax obligations, including, but not limited to, by surrender of Shares covered by the Option sufficient to satisfy the withholding obligations. The Company has the right and option, but not the obligation, to treat Participant’s failure to provide timely payment in accordance with the Plan of any withholding tax arising in connection with the Option as Participant’s election to satisfy all or any portion of the withholding tax by requesting the Company retain Shares otherwise issuable under the Option.

(b)Participant acknowledges that Participant is ultimately liable and responsible for all taxes owed in connection with the Option, regardless of any action the Company or any Subsidiary takes with respect to any tax withholding obligations that arise in connection with the Option. Neither the Company nor any Subsidiary makes any representation or undertaking regarding the treatment of any tax withholding in connection with the awarding, vesting or exercise of the Option, or the subsequent sale of Shares. The Company and the Subsidiaries do not commit and are under no obligation to structure the Option to reduce or eliminate Participant’s tax liability.

(c)Participant acknowledges that the Company has advised Participant to obtain independent legal and tax advice regarding the grant and exercise of the Option and the disposition of any Shares acquired thereby.

3.5Issuance of Shares; Rights as Shareholder. The Company shall issue (or cause to be issued) the respective Shares promptly after the Option is exercised and full payment is received. Until the Shares are issued (as evidenced by the appropriate entry on the books of the Company or of a duly authorized transfer agent of the Company) and Participant becomes the record owner of the Shares, no right to vote or receive dividends or any other rights as a shareholder shall exist with respect to the Shares subject to the Option, notwithstanding the exercise of the Option. No adjustment shall be made for a dividend or other right for which the record date is prior to the date Participant becomes the record owner of the Shares. Participant agrees to execute any documents requested by the Company in connection with the issuance of any Shares.

ARTICLE IV.
OTHER PROVISIONS

4.1Adjustments. Participant acknowledges that the Option is subject to adjustment, modification and termination in certain events as provided in this Agreement and the Plan.

4.2Limited Transferability. Except as may be permitted under the Plan in certain circumstances, the Option may not be sold, pledged, assigned, hypothecated, transferred, or disposed of in any manner other than by will or by the laws of descent or distribution.

4.3Regulatory Restrictions on Shares. Notwithstanding the other provisions of this Agreement, if at any time the Administrator determines, in its sole discretion, that the listing, registration or qualification of Shares upon any securities exchange or under any state or federal law, or the consent or approval of any governmental regulatory authority is necessary or desirable as a condition to the issuance of Shares to Participant, such issuance will not occur unless and until such listing, registration, qualification, consent or approval will have been effected or obtained free of any conditions not acceptable to the Company. The Company shall be under no obligation to Participant to (a) register for offering or resale, (b) qualify for exemption under federal securities law, (c) register or qualify under the laws of any state or foreign jurisdiction, any Shares, security or interest in a security paid or issued under, or created by, the Plan, or (d) continue in effect any such registrations or qualifications if made. The inability of the Company to obtain authority from any regulatory body having jurisdiction, which authority is deemed by the Company’s counsel to be necessary or appropriate to the lawful issuance and sale of any Shares hereunder, shall relieve the Company of any liability in respect of the failure to issue or sell such Shares as to which such requisite authority has not been obtained.

4.4Conformity to Applicable Laws. Participant acknowledges that the Plan, the Grant Notice and this Agreement are intended to conform to the extent necessary with all Applicable Laws and, to the extent Applicable Laws permit, will be deemed to be amended to the minimum extent necessary to conform to Applicable Laws. Any determination in this regard that is made by the Administrator will be final, binding, and conclusive on all interested persons. The obligations of the Company and the rights of Participant are subject to compliance with all Applicable Laws.

Notwithstanding any other provision of the Plan or this Agreement, if Participant is subject to Section 16 of the Exchange Act, the Plan, the Grant Notice, this Agreement and the Option will be subject to any additional limitations set forth in any applicable exemptive rule under Section 16 of the Exchange Act (including any amendment to Rule 16b‑3) that are requirements for the application of such exemptive rule. To the extent Applicable Laws permit, this Agreement will be deemed amended as necessary to conform to such applicable exemptive rule.

4.5Successors and Assigns. The Company may assign any of its rights under this Agreement to single or multiple assignees, and this Agreement will inure to the benefit of the successors and assigns of the Company. Subject to the restrictions on transfer set forth in the Plan and herein, this Agreement will be binding upon and inure to the benefit of the heirs, legatees, legal representatives, successors and assigns of the parties hereto.

4.6Notices.

(a)General. Any document relating to participation in the Plan, or any notice required or permitted hereunder, shall be given in writing and shall be deemed effectively given upon personal delivery, electronic delivery at the electronic mail address, if any, provided for Participant by the Company, or, upon deposit in the U.S. Post Office or Canada Post, by registered or certified mail, or with a nationally recognized overnight courier service with postage and fees prepaid, addressed to the Company (c/o Secretary of the Company) at the Company’s principal office, and to Participant at the address appearing on the employment records of the Company, or at such other address as such party may designate in writing from time to time to the other party.

(b)Description of Electronic Delivery. The Plan documents, which may include, but do not necessarily include, the Plan, the Grant Notice, this Agreement, and any prospectus or other report of the Company provided generally to the Company’s shareholders, may be delivered to Participant electronically. In addition, if permitted by the Company, Participant may deliver electronically the Grant Notice to the Company or to such third party involved in administering the Plan as the Company may designate from time to time. Such means of electronic delivery may include, but do not necessarily include, the delivery of a link to a Company intranet or the internet site of a third party involved in administering the Plan, the delivery of the document via electronic mail, or such other means of electronic delivery as may be specified by the Company.

(c)Consent to Electronic Delivery. Participant hereby acknowledges that Participant has read and understands this Section 4.6, and hereby consents to the electronic delivery of any Plan documents as described in Section 4.6(b). Participant may receive from the Company a paper copy of any documents delivered electronically at no cost to Participant by providing written notice of such request to the Company. Participant will be provided with a paper copy of any documents if the attempted electronic delivery of such documents fails. Participant understands and hereby agrees that Participant must provide the Company or any designated third party administrator with a paper copy of any document if the attempted electronic delivery of such documents fails. Participant may change the electronic mail address to which such documents are to be delivered at any time by notifying the Company in writing of such revised electronic mail address.

4.7Administrator Authority; Decisions Conclusive and Binding. Participant hereby acknowledges (a) that a copy of the Plan has been made available for Participant’s review by the Company, (b) represents that Participant is familiar with the terms and provisions thereof, and (c) accepts the Option subject to all the terms and provisions thereof. The Administrator will have the power to (i) interpret this Agreement, the Grant Notice and the Plan, (ii) adopt such rules for the administration, interpretation and application of the Plan as are consistent therewith, and (iii) interpret or revoke any such rules. Participant hereby agrees to accept as binding, conclusive, and final all decisions of the Administrator upon any questions arising under the Plan, this Agreement or the Grant Notice. No employee of the Company who is acting with the requisite authority on behalf of the Administrator will be personally liable for any action, determination or interpretation that is made in good faith with respect to the Plan, this Agreement or the Grant Notice.

4.8Share Ownership Guidelines. If on exercise of any Options the number of Shares held by the Participant is less than the number of Shares to be held by the Participant pursuant to any share ownership guidelines of the Corporation in effect from time to time and applicable to such Participant, then the Participant shall be required to retain Shares acquired on exercise of Options (net of Shares that are required to be sold by the Participant to meet any tax liabilities arising on exercise of the Options) to meet the requirements of such share ownership guidelines.

4.9Entire Agreement. The Plan, the Grant Notice and this Agreement constitute the entire agreement of the parties and supersede in their entirety all prior undertakings and agreements of the Company and Participant with respect to the subject matter hereof. All prior negotiations and agreements between the parties with respect to the subject matter hereof are merged into this Agreement and the Grant Notice. Each party to this Agreement and the Grant Notice acknowledges that (a) no representations, inducements, promises, or agreements, orally or otherwise, have been made by any party, or by anyone acting on behalf of any party, which are not embodied in this Agreement, the Grant Notice or the Plan, and (b) any agreement, statement, or promise that is not contained in this Agreement, the Grant Notice or the Plan shall not be valid or binding or of any force or effect.

4.10Severability. Notwithstanding any contrary provision of the Grant Notice or this Agreement to the contrary, if any one or more of the provisions (or any part thereof) of the Grant Notice or this Agreement shall be held invalid, illegal, or unenforceable in any respect, such provision shall be modified so as to make it valid, legal, and enforceable, and the validity, legality, and enforceability of the remaining provisions (or any part thereof) of the Grant Notice or this Agreement, as applicable, shall not in any way be affected or impaired thereby.

4.11Survival of Certain Provisions. Wherever appropriate to the intention of the parties hereto, the respective rights and obligations of the parties hereunder shall survive any termination or expiration of this Agreement or the Participant’s Termination of Service.

4.12Limitation on Participant’s Rights. Participation in the Plan confers no rights or interests other than as herein provided. This Agreement creates only a contractual obligation on the part of the Company as to amounts payable and may not be construed as creating a trust. Neither the Plan nor any underlying program, in and of itself, has any assets.

4.13Compensation Recoupment. The Option (and all Shares issuable thereunder) are subject to the Company’s ability to recover incentive-based compensation from Participant, as is or may be required by (a) the provisions of the Dodd-Frank Wall Street Reform and Consumer Protection Act or any regulations or rules promulgated thereunder, (b) any other clawback provision required by Applicable Laws or the listing standards of any applicable stock exchange or national market system, (c) any clawback policies adopted by the Company to implement any such requirements, or (d) any other compensation recovery policies as may be adopted from time to time by the Company, all to the extent determined by the Administrator in its discretion to be applicable to Participant.

4.14Construction. Headings in this Agreement are included for convenience and shall not be considered in the interpretation of this Agreement. Reference to any statute, rule, or regulation includes any amendment thereto or any replacement thereof, as well as the authoritative guidance issued thereunder by the appropriate governmental entity. Pronouns shall be construed to include the masculine, feminine, neutral, singular or plural as the identity of the antecedent may require. A reference to any party to this Agreement shall include such party’s successors and permitted assigns. This Agreement shall be construed according to its fair meaning and shall not be strictly construed against the Company.

4.15Counterparts. The Grant Notice may be executed in one or more counterparts, including by way of any electronic signature, subject to Applicable Laws, each of which will be deemed an original and all of which together will constitute one instrument.

4.16Modification. Any modification of this Agreement shall be binding only if evidenced in writing and signed by the Administrator, or its delegate. The Participant’s consent to such modification shall be required unless (i) the action does not materially and adversely affect the Participant’s rights under the Agreement and Grant Notice, or (ii) the change is permitted under Article X or pursuant to Section 12.5 of the Plan.

[End.]

Stock Option Grant Notice –

EX-10.5

EXHIBIT 10.5

ENBRIDGE INC.
2019 LONG TERM INCENTIVE PLAN

PERFORMANCE STOCK UNIT GRANT NOTICE

Pursuant to the Enbridge Inc. 2019 Long Term Incentive Plan (the “Plan”), Enbridge Inc. (the “Company”) has granted to the participant listed below (“Participant”) an award (the “Award”) of Performance Stock Units (the “PSUs”), as described in this Performance Stock Unit Grant Notice (this “Grant Notice”), subject to the terms and conditions of the Plan and the Performance Stock Unit Award Agreement attached hereto as Exhibit A (the “Agreement”), both of which are incorporated into this Grant Notice by reference. Capitalized terms not specifically defined in this Grant Notice will have the meanings given to them in the Agreement, and if not defined in the Agreement, the meanings given to them in the Plan.

Participant:

Grant Date:

Target Number of PSUs:

Performance Period:

By Participant’s signature below, Participant agrees to be bound by the terms of this Grant Notice, the Plan and the Agreement, effective as of the Grant Date. Participant has reviewed the Plan, this Grant Notice and the Agreement in their entireties, and acknowledges that the Company hereby advises Participant to obtain the advice of counsel prior to executing this Grant Notice. Participant fully understands and accepts all provisions of the Plan, this Grant Notice and the Agreement (including, without limitation, the shareholder approval requirement set forth in Section 1.2 of the Agreement). Participant hereby agrees to accept as binding, conclusive and final all decisions or interpretations of the Administrator upon any questions arising under the Plan, this Grant Notice or the Agreement. Participant agrees that the Grant Notice, the Agreement and the Plan constitute the entire agreement with respect to the Award.

Enbridge Inc.:		Participant:
By:
	Signature	Signature
Name:		Name:
Title:

Exhibit APERFORMANCE STOCK UNIT AWARD AGREEMENT

ARTICLE I.
GENERAL

1.1Award of PSUs and Dividend Equivalents Units. (a) Subject to the terms and conditions of this Agreement (including, without limitation, the shareholder approval requirement set forth in Section 1.2) and the Plan, the Company has granted to Participant, effective as of the Grant Date set forth in the Grant Notice (the “Grant Date”), an award of PSUs as set forth in the Grant Notice. Each PSU represents the right to receive a cash amount equal to the Fair Market Value of one Share in accordance with Section 3.3(b), subject to achievement of the Performance Goals over the Performance Period in accordance with Exhibit I hereto. The number of PSUs on the Grant Notice is not necessarily the number of PSUs in respect of which payment will be earned, but is merely the basis for determining the amount (if any) that will be delivered to the Participant; provided, however, that the Participant will have no right to any payment until such time, if ever, that an PSU has vested and become payable hereunder.

(a)In the event that any cash dividend is declared on Shares with a record date that occurs during the Dividend Equivalent Period (as defined below), the Participant will receive dividend equivalent rights in the form of additional PSUs (the “Dividend Equivalent Units”) at the time such dividend is paid to the Company’s shareholders. The number of Dividend Equivalent Units that the Participant will receive at any such time will be equal to (1) the cash dividend amount per Share times (2) the number of PSUs covered by the Participant’s Award (and, unless otherwise determined by the Company, any Dividend Equivalent Units previously credited under the Participant’s Award that have not been previously settled through the delivery of Shares (or cash) prior to, such date), divided by the Fair Market Value of one Share on the applicable dividend payment date; provided, that, in the event the Dividend Reinvestment Plan is then in effect, the number of Dividend Equivalent Units that the Participant will receive shall instead be calculated in accordance with the methodologies (including any discount feature) set forth therein, as determined by the Administrator in its sole discretion. Each Dividend Equivalent Unit will constitute an unfunded and unsecured promise of the Company to deliver (or cause to be delivered) one Share (or, cash equal to the Fair Market Value thereof) in accordance with the Plan, and will vest and be settled or paid at the same time, and subject to the same terms and conditions, as the PSUs on which such Dividend Equivalent Unit was accrued. “Dividend Equivalent Period” means the period commencing on the Grant Date and ending on the last day on which Shares (or cash) are delivered to the Participant with respect to the PSUs.

1.2[Shareholder Approval Requirement. This Award will be contingent upon and effective as of approval of the Plan by the Company’s shareholders at the 2019 Annual Meeting. If the shareholders do not approve the Plan at the 2019 Annual Meeting, then this Agreement shall be null and void and the Participant shall have no rights or interests of any kind with respect to the PSUs or the associated Dividend Equivalent Units.]

1.3Nature of Award. The PSUs granted to Participant pursuant to the Grant Notice and this Award are prospective in nature such that the Award is not in respect of service rendered in a year prior to the year that includes the Grant Date.

1.4Incorporation of Terms of Plan. The PSUs are subject to the terms and conditions set forth in this Agreement and the Plan, which is incorporated herein by reference. In the event of any inconsistency between the Plan and this Agreement, the terms of the Plan will control.

1.5Defined Terms. Capitalized terms not specifically defined in this Agreement will have the meanings specified in the Grant Notice or, if not defined in the Grant Notice, in the Plan.

1.6Unsecured Promise. The PSUs will at all times prior to settlement represent an unsecured Company obligation payable only from the Company’s general assets.

ARTICLE II.
PERFORMANCE GOALS

The number of PSUs earned by the Participant is dependent, and may vary based, on achievement of the applicable Performance Goals over the Performance Period. Promptly following completion of the Performance Period (and no later than two and one-half (2.5) months following the end of the Performance Period), the Administrator will determine (a) whether, and to what extent the applicable Performance Goals for the Performance Period have been achieved and (b) the number of PSUs that the Participant shall earn, if any, subject to the requirements of Article III. All of the Participant’s rights with respect to the PSUs are dependent on the extent to which the applicable Performance Goals are achieved, and any rights to settlement in respect of outstanding PSUs immediately will terminate and no amount will be paid in respect of such PSUs upon the Administrator’s determination, in its sole discretion, that the applicable Performance Goals have not been satisfied to the extent necessary to result in payment in respect of the PSUs. The Administrator’s determination under this Article III shall be final, conclusive, and binding on the Participant, and on all other persons, to the maximum extent permitted by law.

ARTICLE III.
VESTING, FORFEITURE AND SETTLEMENT

3.1Vesting.

(a)The PSUs are subject to forfeiture until they vest. Except as otherwise provided herein, the PSUs shall vest, if at all, on the Maturity Date, when the Administrator certifies the achievement of the Performance Goals in accordance with Section 3.3, provided, that except as otherwise set forth in Section 3.1(b), the Participant must remain an Employee through and including the Maturity Date.

(b)Accelerated Service-Based Vesting.

(i)CIC Termination. Upon a Change in Control the Performance Goals shall be conclusively deemed to have been attained for the Performance Period upon the occurrence of such Change in Control at the target level, or if greater, based on the actual level of attainment of such Performance Goals as of the Change in Control, as determined by the Administrator. In the event that Participant has a Termination of Service within two years following a Change in Control as a result of (1) involuntary Termination of Service by the Company or a Subsidiary without Cause or (2) Termination of Service by the Participant for Good Reason (in each case, a “CIC Termination”), then the PSUs will no longer be subject to any service-based vesting condition and will remain outstanding and will vest in accordance with Section 3.3.

(ii)Death or Disability. In the event that Participant has a Termination of Service due to the Participant’s death or Disability, then then the PSUs will no longer be subject to any service-based vesting condition and will vest in accordance with Section 3.3.

(iii)Retirement. In the event that Participant has a Termination of Service due to the Participant’s Retirement, then a pro rata portion of the PSUs will no longer be subject to any service-based vesting condition and will remain outstanding and will vest, if at all, in accordance with Section 3.3 upon the Administrator’s certification of the achievement of the Performance Goals. The pro rata portion of the PSUs that will no longer be subject to the service-based vesting condition shall be calculated by multiplying the target number of PSUs set forth on the Grant Notice by a fraction, the numerator of which is the number of full calendar days that have elapsed since the beginning of the Performance Period through the date of the Participant’s Termination of Service and the denominator is the total number of full calendar days in the Performance Period. Notwithstanding the foregoing, if the Participant is eligible for Retirement at a time when the Participant incurs an involuntary Termination of Service without Cause, then Section 3.1(b)(iv) shall apply.

(iv)Involuntary Termination Without Cause. In the event that Participant has a Termination of Service due to the Participant’s involuntary Termination of Service by the Company or a Subsidiary without Cause (other than a CIC Termination), then a pro rata portion of the PSUs will no longer be subject to any service-based vesting condition and will remain outstanding and will vest, if at all, in accordance with Section 3.3 upon the Administrator’s certification of the achievement of the Performance Goals. The pro rata portion of the PSUs that will no longer be subject to the service-based vesting condition shall be calculated by multiplying the target number of PSUs set forth on the Grant Notice by a fraction, the numerator of which is the number of full calendar days that have elapsed since the beginning of the Performance Period through the date of the Participant’s Termination of Service plus any applicable Notice Period and the denominator is the total number of full calendar days in the Performance Period. For purposes of this Section 3.1(b)(iv), if a Participant’s employment terminates due to the constructive dismissal of the Participant or if a Participant ceases to be employed by a Subsidiary of the Company because such Participant’s employer ceases to be a Subsidiary of the Company, then such termination or cessation of employment shall be treated as an Termination of Service due to the Participant’s involuntary Termination without Cause.

3.2Forfeiture and Leave of Absence.

(a)Any PSUs for which the service-based vesting condition is not waived in accordance with Section 3.1 above shall immediately and automatically be cancelled and forfeited on the Participant’s Termination of Service for any reason. Notwithstanding anything herein to the contrary, in the event that Participant has an involuntary Termination of Service for Cause, then any PSUs that have not become vested in accordance with Section 3.3 as of the Participant’s Termination of Service shall be immediately forfeited as of the date of the Participant’s Termination of Service (regardless of whether the service-based vesting condition continues to apply at the time of such Termination of Service).

(b)Notwithstanding anything in Section 3.1 to the contrary, in the event that the Participant was on Leave of Absence during the Performance Period, the number of PSUs eligible to vest pursuant to Section 3.1(a) shall be reduced on a pro-rata basis. The number of PSUs that will remain outstanding and will vest, if at all, in accordance with Section 3.3 upon the Administrator’s certification of the achievement of the Performance Goals, is determined by multiplying the target number of PSUs set forth on the Grant Notice by a fraction, the numerator of which is the number of full calendar days during the Performance Period that the Participant was an Employee not on Leave of Absence and the denominator is the total number of full calendar days in the Performance Period

3.3Maturity Date and Settlement. (a) The Administrator shall certify achievement of the Performance Goals and determine the number of PSU that become vested hereunder on a date following the completion of the Performance Period (the “Maturity Date”) in accordance with Exhibit I; provided, that:

(i)in the case of PSUs for which the service-based vesting condition becomes waived under Section 3.1(b)(i), the Maturity Date shall be the date of the Participant’s Termination of Service; and

(ii)in the case of PSUs for which the service-based vesting condition becomes waived under Section 3.1(b)(ii), the Maturity Date shall be the date of the Participant’s Termination of Service and the Performance Period shall be deemed to have been truncated as of the same date, with the Performance Goals deemed achieved with respect to the target number of PSUs set forth on the Grant Notice.

(b)All payments in respect of PSUs shall be made, if at all, within two and one-half months of the Maturity Date and in no case will any payment in respect of a PSU be made after the third year following the year that includes the Grant Date. The amount of cash payable in respect of each PSU that vests on the Maturity Date will equal the Fair Market Value of a Share on the last trading day that immediately precedes the Maturity Date and will be paid in the currency of Canada or the United States, depending on the applicable jurisdiction in which the Participant resides. For purposes of this Section 3.3(b), “Fair Market Value” shall mean means, as of a particular day, the weighted average of the board lot trading prices per Share on the Toronto Stock Exchange, or the New York Stock Exchange, for the last twenty trading days immediately prior to such day

3.4No Rights as Shareholder. Participant will have no rights as a shareholder (including, without limitation, the right to vote and to receive dividends) with respect to any PSUs covered by this Agreement.

ARTICLE IV.
TAXATION AND TAX WITHHOLDING

4.1Tax Withholding. Participant must make arrangements acceptable to the Administrator for the satisfaction of any non-U.S., U.S.-federal, U.S.-state, or local income and employment tax withholding obligations arising in connection with the Award.

(a)Participant acknowledges that Participant is ultimately liable and responsible for all taxes owed in connection with the PSUs, regardless of any action the Company or any Subsidiary takes with respect to any tax withholding obligations that arise in connection with the PSUs. Neither the Company nor any Subsidiary makes any representation or undertaking regarding the treatment of any tax withholding in connection with the awarding, vesting or payment of the PSUs. The Company and the Subsidiaries do not commit to, and are under no obligation to structure this Award to, reduce or eliminate Participant’s tax liability.

(b)Participant acknowledges that the Company has advised Participant to obtain independent legal and tax advice regarding the grant and payment in respect of the PSUs.

4.2Section 409A. The provisions of this Section 4.2 apply to the Participant only if the Participant is a US taxpayer. This Agreement and the Plan provisions that apply to the PSUs are intended and will be construed to comply with Section 409A (including the requirements applicable to, or the conditions for exemption from treatment as, “deferred compensation” as defined in the regulations under Section 409A, whether by reason of short-term deferral treatment or other exceptions or provisions). The Administrator will have full authority to give effect to this intent. To the extent that any portion of the PSUs are intended to satisfy the requirements for short-term deferral treatment under Section 409A, delivery for such portion will occur by the March 15 coinciding with the last day of the applicable “short-term deferral” period described in Reg. 1.409A-1(b)(4) in order for the payment in respect of such RSUs to be within the short-term deferral exception unless, in order to permit all applicable conditions or restrictions on delivery to be satisfied, the Administrator elects, pursuant to Reg. 1.409A-1(b)(4)(i)(D) or otherwise as may be permitted in accordance with Section 409A, to delay payment to a later date within the same calendar year or to such later date as may be permitted under Section 409A. For the avoidance of doubt, if PSUs include a “series of installment payments” as described in Reg. 1.409A-2(b)(2)(iii), the Participant’s right to the series of installment payments will be treated as a right to a series of separate payments and not as a right to a single payment, and if the Participant is a “specified employee” (as defined by the Company in accordance with Section 409A(a)(2)(i)(B) of the Code), payment will occur on the earlier of the date set forth under Section 3.3 or (to the extent required to avoid the imposition of additional tax under Section 409A) the date that is six months after the Participant’s Termination of Service. For purposes of Section 3.3, references in this Agreement to the Participant’s Termination of Service mean a Termination of Service which is also a separation from service (as defined by the Company in accordance with Section 409A). In no event will the Participant be permitted to designate, directly or indirectly, the taxable year of payment.

ARTICLE V.
OTHER PROVISIONS

5.1Adjustments. Participant acknowledges that the PSUs are subject to adjustment, modification and termination in certain events as provided in this Agreement and the Plan.

5.2Limited Transferability. The Award may not be sold, pledged, assigned, hypothecated, transferred, or disposed of in any manner other than by will or by the laws of descent or distribution.

5.3Conformity to Applicable Laws. Participant acknowledges that the Plan, the Grant Notice and this Agreement are intended to conform to the extent necessary with all Applicable Laws and, to the extent Applicable Laws permit, will be deemed to be amended to the minimum extent necessary to conform to Applicable Laws. Any determination in this regard that is made by the Administrator will be final, binding, and conclusive on all interested persons. The obligations of the Company and the rights of Participant are subject to compliance with all Applicable Laws.

Notwithstanding any other provision of the Plan or this Agreement, if Participant is subject to Section 16 of the Exchange Act, the Plan, the Grant Notice, this Agreement, the PSUs will be subject to any additional limitations set forth in any applicable exemptive rule under Section 16 of the Exchange Act (including any amendment to Rule 16b-3) that are requirements for the application of such exemptive rule. To the extent Applicable Laws permit, this Agreement will be deemed amended as necessary to conform to such applicable exemptive rule.

5.4Successors and Assigns. The Company may assign any of its rights under this Agreement to single or multiple assignees, and this Agreement will inure to the benefit of the successors and assigns of the Company. Subject to the restrictions on transfer set forth in the Plan and herein, this Agreement will be binding upon and inure to the benefit of the heirs, legatees, legal representatives, successors and assigns of the parties hereto.

5.5Notices General. Any document relating to participation in the Plan, or any notice required or permitted hereunder, shall be given in writing and shall be deemed effectively given upon personal delivery, electronic delivery at the electronic mail address, if any, provided for Participant by the Company, or, upon deposit in the U.S. Post Office or Canada Post, by registered or certified mail, or with a nationally recognized overnight courier service with postage and fees prepaid, addressed to the Company (c/o Corporate Secretary of the Company) at the Company’s principal office, and to Participant at the address appearing on the employment records of the Company, or at such other address as such party may designate in writing from time to time to the other party.

(a)Description of Electronic Delivery. The Plan documents, which may include, but do not necessarily include, the Plan, the Grant Notice, this Agreement, and any prospectus or other report of the Company provided generally to the Company’s shareholders, may be delivered to Participant electronically. In addition, if permitted by the Company, Participant may deliver electronically the Grant Notice to the Company or to such third party involved in administering the Plan as the Company may designate from time to time. Such means of electronic delivery may include, but do not necessarily include, the delivery of a link to a Company intranet or the internet site of a third party involved in administering the Plan, the delivery of the document via electronic mail, or such other means of electronic delivery as may be specified by the Company.

(b)Consent to Electronic Delivery. Participant hereby acknowledges that Participant has read and understands this Section 5.5, and hereby consents to the electronic delivery of any Plan documents as described in Section 5.5(b). Participant may receive from the Company a paper copy of any documents delivered electronically at no cost to Participant by providing written notice of such request to the Company. Participant will be provided with a paper copy of any documents if the attempted electronic delivery of such documents fails. Participant understands and hereby agrees that Participant must provide the Company or any designated third party administrator with a paper copy of any document if the attempted electronic delivery of such documents fails. Participant may change the electronic mail address to which such documents are to be delivered at any time by notifying the Company in writing of such revised electronic mail address.

5.6Administrator Authority; Decisions Conclusive and Binding. Participant hereby (a) acknowledges that a copy of the Plan has been made available for Participant’s review by the Company, (b) represents that Participant is familiar with the terms and provisions thereof, and (c) accepts the Award subject to all the terms and provisions thereof. The Administrator will have the power to (i) interpret this Agreement, the Grant Notice and the Plan, (ii) adopt such rules for the administration, interpretation and application of the Plan as are consistent therewith, and (iii) interpret or revoke any such rules. Participant hereby agrees to accept as binding, conclusive, and final all decisions of the Administrator upon any questions arising under the Plan, this Agreement or the Grant Notice. No employee of the Company who is acting with the requisite authority on behalf of the Administrator will be personally liable for any action, determination or interpretation that is made in good faith with respect to the Plan, this Agreement or the Grant Notice.

5.7Entire Agreement. The Plan, the Grant Notice and this Agreement constitute the entire agreement of the parties and supersede, in their entirety, all prior undertakings and agreements of the Company and Participant with respect to the subject matter hereof. All prior negotiations and agreements between the parties with respect to the subject matter hereof are merged into this Agreement and the Grant Notice. Each party to this Agreement and the Grant Notice acknowledges that (a) no representations, inducements, promises, or agreements, orally or otherwise, have been made by any party or by anyone acting on behalf of any party, which are not embodied in this Agreement, the Grant Notice or the Plan, and (b) any agreement, statement, or promise that is not contained in this Agreement, the Grant Notice or the Plan will not be valid or binding or of any force or effect.

5.8Severability. Notwithstanding any contrary provision of the Grant Notice or this Agreement to the contrary, if any one or more of the provisions (or any part thereof) of the Grant Notice or this Agreement is held to be invalid, illegal, or unenforceable in any respect, such provision will be modified so as to make it valid, legal, and enforceable, and the validity, legality, and enforceability of the remaining provisions (or any part thereof) of the Grant Notice or this Agreement, as applicable, will not in any way be affected or impaired thereby.

5.9Survival of Certain Provisions. Wherever appropriate to the intention of the parties hereto, the respective rights and obligations of the parties hereunder will survive any termination or expiration of this Agreement or the Participant’s Termination of Service.

5.10Limitation on Participant’s Rights. Participation in the Plan confers no rights or interests other than as herein provided. This Agreement creates only a contractual obligation on the part of the Company as to amounts payable and may not be construed as creating a trust. Neither the Plan nor any underlying program, in and of itself, has any assets. Participant will have only the rights of a general unsecured creditor of the Company with respect to amounts credited and benefits payable, if any, with respect to the PSUs, and rights no greater than the right to receive cash as a general unsecured creditor with respect to the PSUs, as and when settled pursuant to the terms of this Agreement.

5.11Compensation Recoupment. The Award (and the cash issuable thereunder) are subject to the Company’s ability to recover incentive-based compensation from Participant, as is or may be required by (a) the Dodd-Frank Wall Street Reform and Consumer Protection Act, or any regulations or rules promulgated thereunder, (b) any other clawback provision required by Applicable Laws or the listing standards of any applicable stock exchange or national market system, (c) any clawback policies adopted by the Company to implement any such requirements, or (d) any other compensation recovery policies as may be adopted from time to time by the Company, all to the extent that is determined by the Administrator, in its discretion, to be applicable with respect to Participant.

5.12No Effect on Employment or Service Relationship. Nothing in the Plan, the Grant Notice or this Agreement (a) confers upon Participant any right to continue as an Employee of the Company or any Subsidiary or (b) interferes with or restricts in any way the rights of the Company and its Subsidiaries, which rights are hereby expressly reserved, to discharge or terminate the services of Participant at any time for any reason whatsoever, with or without Cause, and with or without notice, except to the extent expressly provided otherwise in a written agreement between the Company or a Subsidiary and Participant.

5.13Construction. Headings in this Agreement are included for convenience and will not be considered in the interpretation of this Agreement. Reference to any statute, rule, or regulation includes any amendment thereto or any replacement thereof, as well as the authoritative guidance issued thereunder by the appropriate governmental entity. Pronouns will be construed to include the masculine, feminine, neutral, singular or plural as the identity of the antecedent may require. A reference to any party to this Agreement will include such party’s successors and permitted assigns. This Agreement will be construed according to its fair meaning and not strictly construed against the Company.

5.14Counterparts. The Grant Notice may be executed in one or more counterparts, including by way of any electronic signature, subject to Applicable Laws, each of which will be deemed an original and all of which together will constitute one and the same instrument.

5.15Modification. Any modification of this Agreement shall be binding only if evidenced in writing and signed by the Administrator, or its delegate. The Participant’s consent to such modification shall be required unless (i) the action does not materially and adversely affect the Participant’s rights under the Agreement and Grant Notice, or (ii) the change is permitted under Article X or pursuant to Section 12.5 of the Plan.

[End]

Exhibit IPERFORMANCE MEASURES – 2019 GRANT

I.    Performance Goals.

The number of PSUs earned shall be determined by reference to the [Performance Goal[s]].

II.    Determination of Performance Multiplier.

The Performance Multiplier is calculated in accordance with the following equation:

Performance Multiplier = ([50]% * [Performance Goal]) + ([50]% * [Performance Goal])

The [Performance Goal] multiplier ranges from [0] – [2.0] based on performance as follows:

	Threshold	Target	Maximum
Multiplier	[0.00]x	[1.00]x	[2.00]x
[Performance Goal]

The [Performance Goal] multiplier ranges from [0] – [2.0] based on performance as follows:

	Threshold	Target	Maximum
Multiplier	[0.00]x	[1.00]x	[2.00]x
[Performance Goal]

III.    Calculation of Payment in Respect of PSUs.

The amount payable to the Participant shall be determined by multiplying the number of PSUs determined by the Administrator to have vested with respect to the Performance Period (including, for the avoidance of doubt additional PSUs credited in the form of Dividend Equivalent Units) by (i) the Performance Multiplier and (ii) the Fair Market Value on the Maturity Date in accordance with Section 3.3(b) of the Agreement.

The amounts determined under this Exhibit A shall be subject to any proration that shall apply as set forth in the Award Agreement.

IV.    Adjustments.

To the extent determined by the Administrator in its discretion to be necessary or appropriate to maintain the intended economics of the award, the Administrator may make adjustments, including to or to the calculation of the [Performance Goal[s]], as it deems to be equitable in light of changed circumstances (which may include unusual or non-recurring events), resulting from changes in accounting methods, practices or policies, changes in capital structure by reason of legal or regulatory requirements, a material change in the Company’s or a Peer Company’s revenue mix or business activities or such other changed circumstances as the Administrator may deem appropriate.

SC1:4764192.3B PSU Grant Notice

EX-10.6

EXHIBIT 10.6

ENBRIDGE INC.
2019 LONG TERM INCENTIVE PLAN

RESTRICTED STOCK UNIT GRANT NOTICE

Pursuant to the Enbridge Inc. 2019 Long Term Incentive Plan (the “Plan”), Enbridge Inc. (the “Company”) has granted to the participant listed below (“Participant”) an award (the “Award”) of Restricted Stock Units (the “RSUs”), as described in this Restricted Stock Unit Grant Notice (this “Grant Notice”), subject to the terms and conditions of the Plan and the Restricted Stock Unit Award Agreement attached hereto as Exhibit A (the “Agreement”), both of which are incorporated into this Grant Notice by reference. Capitalized terms not specifically defined in this Grant Notice will have the meanings given to them in the Agreement, and if not defined in the Agreement, the meanings given to them in the Plan.

Participant:

Grant Date:

Number of RSUs:

Term:

Maturity Date:

By Participant’s signature below, Participant agrees to be bound by the terms of this Grant Notice, the Plan and the Agreement, effective as of the Grant Date. Participant has reviewed the Plan, this Grant Notice and the Agreement in their entireties, and acknowledges that the Company hereby advises Participant to obtain the advice of counsel prior to executing this Grant Notice. Participant fully understands and accepts all provisions of the Plan, this Grant Notice and the Agreement (including, without limitation, the shareholder approval requirement set forth in Section 1.2 of the Agreement). Participant hereby agrees to accept as binding, conclusive and final all decisions or interpretations of the Administrator upon any questions arising under the Plan, this Grant Notice or the Agreement. Participant agrees that the Grant Notice, the Agreement and the Plan constitute the entire agreement with respect to the Award.

Enbridge Inc.:		Participant:
By:
	Signature	Signature
Name:		Name:
Title:

RSU Grant Notice

Exhibit A

RESTRICTED STOCK UNIT AWARD AGREEMENT

Article IGENERAL

1.1Award of RSUs and Dividend Equivalents Units. (a) Subject to the terms and conditions of this Agreement (including, without limitation, the shareholder approval requirement set forth in Section 1.2) and the Plan, the Company has granted to Participant, effective as of the Grant Date set forth in the Grant Notice (the “Grant Date”), an award of RSUs as set forth in the Grant Notice. Each RSU represents the right to receive a cash amount equal to the Fair Market Value of one Share in accordance with Section 2.3; provided, however, that Participant will have no right to any payment until such time, if ever, that an RSU has vested and become payable hereunder.

(a)In the event that any cash dividend is declared on Shares with a record date that occurs during the Dividend Equivalent Period (as defined below), the Participant will receive dividend equivalent rights in the form of additional RSUs (the “Dividend Equivalent Units”) at the time such dividend is paid to the Company’s shareholders. The number of Dividend Equivalent Units that the Participant will receive at any such time will be equal to (1) the cash dividend amount per Share times (2) the number of RSUs covered by the Participant’s Award (and, unless otherwise determined by the Company, any Dividend Equivalent Units previously credited under the Participant’s Award that have not been previously settled through the delivery of Shares (or cash) prior to, such date), divided by the Fair Market Value of one Share on the applicable dividend payment date; provided, that, in the event the Dividend Reinvestment Plan is then in effect, the number of Dividend Equivalent Units that the Participant will receive shall instead be calculated in accordance with the methodologies (including any discount feature) set forth therein, as determined by the Administrator in its sole discretion. Each Dividend Equivalent Unit will constitute an unfunded and unsecured promise of the Company to deliver (or cause to be delivered) one Share (or, cash equal to the Fair Market Value thereof) in accordance with the Plan, and will vest and be settled or paid at the same time, and subject to the same terms and conditions, as the RSUs on which such Dividend Equivalent Unit was accrued. “Dividend Equivalent Period” means the period commencing on the Grant Date and ending on the last day on which Shares (or cash) are delivered to the Participant with respect to the RSUs.

1.2[Shareholder Approval Requirement. This Award will be contingent upon and effective as of approval of the Plan by the Company’s shareholders at the 2019 Annual Meeting. If the shareholders do not approve the Plan at the 2019 Annual Meeting, then this Agreement shall be null and void and the Participant shall have no rights or interests of any kind with respect to the RSUs or the associated Dividend Equivalent Units.]

1.3Nature of Award. The RSUs granted to Participant pursuant to the Grant Notice and this Award are prospective in nature such that the Award is not in respect of service rendered in a year prior to the year that includes the Grant Date.

1.4Incorporation of Terms of Plan. The RSUs are subject to the terms and conditions set forth in this Agreement and the Plan, which is incorporated herein by reference. In the event of any inconsistency between the Plan and this Agreement, the terms of the Plan will control.

1.5Defined Terms. Capitalized terms not specifically defined in this Agreement will have the meanings specified in the Grant Notice or, if not defined in the Grant Notice, in the Plan.

1.6Unsecured Promise. The RSUs will at all times prior to settlement represent an unsecured Company obligation payable only from the Company’s general assets.

ARTICLE II
VESTING, FORFEITURE AND SETTLEMENT

2.1Vesting; Maturity Date. (a) The RSUs will become vested on the Maturity Date; provided, that except as otherwise set forth in Section 2.1(b), the Participant is, as of the applicable Maturity Date, and has been at all times since the Grant Date, an Employee.

(a)Accelerated Vesting.

(i)CIC Termination. In the event that Participant has a Termination of Service within two years following a Change in Control as a result of (1) involuntary Termination of Service by the Company or a Subsidiary without Cause or (2) Termination of Service by the Participant for Good Reason (in each case, a “CIC Termination”), then all unvested RSUs shall automatically become 100% vested on the Participant’s Termination of Service and be settled in accordance with Section 2.3.

(ii)Death or Disability. In the event that Participant has a Termination of Service due to the Participant’s death or Disability, then all unvested RSUs shall automatically become 100% vested on the Participant’s Termination of Service and be settled in accordance with Section 2.3.

(iii)Retirement. In the event that Participant has a Termination of Service due to the Participant’s Retirement, then a pro rata portion of the unvested RSUs shall immediately vest on the Participant’s Termination of Service and be settled in accordance with Section 2.3. The pro rata portion of the RSUs that vest shall be calculated by multiplying the total number of RSUs granted by a fraction, the numerator of which is the number of full calendar days that have elapsed since the beginning of the Term through the date of the Participant’s Termination of Service and the denominator of which is the total number of full calendar days in the Term. Notwithstanding

the foregoing, if the Participant is eligible for Retirement at a time when the Participant incurs an involuntary Termination of Service without Cause, then Section 2.1(iv) shall apply and govern the vesting of the RSUs.

(iv)Involuntary Termination Without Cause. In the event that Participant has a Termination of Service due to the Participant’s involuntary Termination of Service by the Company or a Subsidiary without Cause (other than a CIC Termination), then a pro rata portion of the unvested RSUs shall immediately vest on the Participant’s Termination of Service and be settled in accordance with Section 2.3. The pro rata portion of the RSUs that vest shall be calculated by multiplying the total number of RSUs granted by a fraction, the numerator of which is the number of full calendar days that have elapsed since the beginning of the Term through the date of the Participant’s Termination of Service (and, for these purposes, giving effect to any applicable Notice Period) and the denominator of which is the total number of full calendar days in the Term. For purposes of this Section 2.1(b)(iv), if a Participant’s employment terminates due to the constructive dismissal of the Participant or if a Participant ceases to be employed by a Subsidiary of the Company because such Participant’s employer ceases to be a Subsidiary of the Company, then such termination or cessation of employment shall be treated as an Termination of Service due to the Participant’s involuntary Termination without Cause.

2.2Forfeiture and Leave of Absence. (a) Any RSUs that do not vest in accordance with Section 2.1 above shall immediately and automatically be cancelled and forfeited on the Participant’s Termination of Service for any reason. Notwithstanding anything herein to the contrary, in the event that Participant has an involuntary Termination of Service for Cause, then any RSUs that have not been settled in accordance with Section 2.3 as of the Participant’s Termination of Service, whether vested or not, shall be immediately forfeited as of the date of the Participant’s Termination of Service.

(a)Notwithstanding anything in Section 2.1 to the contrary, in the event that the Participant was on Leave of Absence during the Term, the RSUs that vest pursuant to Section 2.1(a) shall be reduced on a pro-rata basis. The number of RSUs that shall be eligible to vest under Section 2.1(a) and settled under Section 2.3 shall be determined by multiplying the total number of RSUs granted by a fraction, the numerator of which is the number of full calendar days during the Term that the Participant was an Employee not on Leave of Absence and the denominator of which is the total number of full calendar days in the Term.

2.3Settlement. (a) RSUs will be paid in cash within thirty days following the Maturity Date; provided, that in the case of RSUs that become vested due to Sections 2.1(b)(i) or 2.1(b)(ii), the Maturity Date shall be the date of the Participant’s Termination of Service and payment shall be made within thirty days thereafter, and provided further, that in no case will any payment in respect of an RSU be made after the third year following the year that includes the Grant Date.

(a)The amount of cash paid with respect to the RSU will equal the Fair Market Value of a Share on the last trading day that immediately precedes the Maturity Date and will be

paid in the currency of Canada or the United States, depending on the applicable jurisdiction in which the Participant resides. For purposes of this Section 2.3, “Fair Market Value” shall mean, as of a particular day, the weighted average of the board lot trading prices per Share on the Toronto Stock Exchange, or the New York Stock Exchange, for the last twenty trading days immediately prior to such day.

2.4No Rights as Shareholder. Participant will have no rights as a shareholder (including, without limitation, the right to vote and to receive dividends) with respect to any RSUs covered by this Agreement.

ARTICLE III
TAXATION AND TAX WITHHOLDING

3.1Tax Withholding. (a) Participant must make arrangements acceptable to the Administrator for the satisfaction of any non-U.S., U.S.-federal, U.S.-state, or local income and employment tax withholding obligations arising in connection with the Award.

(a)Participant acknowledges that Participant is ultimately liable and responsible for all taxes owed in connection with the RSUs, regardless of any action the Company or any Subsidiary takes with respect to any tax withholding obligations that arise in connection with the RSUs. Neither the Company nor any Subsidiary makes any representation or undertaking regarding the treatment of any tax withholding in connection with the awarding, vesting or payment of the RSUs. The Company and the Subsidiaries do not commit to, and are under no obligation to structure this Award to, reduce or eliminate Participant’s tax liability.

(b)Participant acknowledges that the Company has advised Participant to obtain independent legal and tax advice regarding the grant and payment in respect of the RSUs.

3.2Section 409A. The provisions of this Section 3.2 apply to the Participant only if the Participant is a US taxpayer. This Agreement and the Plan provisions that apply to the RSUs are intended and will be construed to comply with Section 409A (including the requirements applicable to, or the conditions for exemption from treatment as, “deferred compensation” as defined in the regulations under Section 409A, whether by reason of short-term deferral treatment or other exceptions or provisions). The Administrator will have full authority to give effect to this intent. To the extent that any portion of the RSUs are intended to satisfy the requirements for short-term deferral treatment under Section 409A, delivery for such portion will occur by the March 15 coinciding with the last day of the applicable “short-term deferral” period described in Reg. 1.409A-1(b)(4) in order for the payment in respect of such RSUs to be within the short-term deferral exception unless, in order to permit all applicable conditions or restrictions on delivery to be satisfied, the Administrator elects, pursuant to Reg. 1.409A-1(b)(4)(i)(D) or otherwise as may be permitted in accordance with Section 409A, to delay payment to a later date within the same calendar year or to such later date as may be permitted under Section 409A. For the avoidance of doubt, if RSUs include a “series of installment payments” as described in Reg. 1.409A-2(b)

(2)(iii), the Participant’s right to the series of installment payments will be treated as a right to a series of separate payments and not as a right to a single payment, and if the Participant is a “specified employee” (as defined by the Company in accordance with Section 409A(a)(2)(i)(B) of the Code), payment will occur on the earlier of the date set forth under Section 2.3 or (to the extent required to avoid the imposition of additional tax under Section 409A) the date that is six months after the Participant’s Termination of Service. For purposes of Section 2.3, references in this Agreement to the Participant’s Termination of Service mean a Termination of Service which is also a separation from service (as defined by the Company in accordance with Section 409A). In no event will the Participant be permitted to designate, directly or indirectly, the taxable year of payment.

ARTICLE IV
OTHER PROVISIONS

4.1Adjustments. Participant acknowledges that the RSUs are subject to adjustment, modification and termination in certain events as provided in this Agreement and the Plan.

4.2Limited Transferability. The Award may not be sold, pledged, assigned, hypothecated, transferred, or disposed of in any manner other than by will or by the laws of descent or distribution.

4.3Conformity to Applicable Laws. Participant acknowledges that the Plan, the Grant Notice and this Agreement are intended to conform to the extent necessary with all Applicable Laws and, to the extent Applicable Laws permit, will be deemed to be amended to the minimum extent necessary to conform to Applicable Laws. Any determination in this regard that is made by the Administrator will be final, binding, and conclusive on all interested persons. The obligations of the Company and the rights of Participant are subject to compliance with all Applicable Laws.

Notwithstanding any other provision of the Plan or this Agreement, if Participant is subject to Section 16 of the Exchange Act, the Plan, the Grant Notice, this Agreement, the RSUs will be subject to any additional limitations set forth in any applicable exemptive rule under Section 16 of the Exchange Act (including any amendment to Rule 16b-3) that are requirements for the application of such exemptive rule. To the extent Applicable Laws permit, this Agreement will be deemed amended as necessary to conform to such applicable exemptive rule.

4.4Successors and Assigns. The Company may assign any of its rights under this Agreement to single or multiple assignees, and this Agreement will inure to the benefit of the successors and assigns of the Company. Subject to the restrictions on transfer set forth in the Plan and herein, this Agreement will be binding upon and inure to the benefit of the heirs, legatees, legal representatives, successors and assigns of the parties hereto.

4.5Notices. (a) General. Any document relating to participation in the Plan, or any notice required or permitted hereunder, shall be given in writing and shall be deemed effectively given upon personal delivery, electronic delivery at the electronic mail address, if any, provided for Participant by the Company, or, upon deposit in the U.S. Post Office or Canada Post, by registered or certified mail, or with a nationally recognized overnight courier service with postage and fees prepaid, addressed to the Company (c/o Corporate Secretary of the Company) at the Company’s principal office, and to Participant at the address appearing on the employment records of the Company, or at such other address as such party may designate in writing from time to time to the other party.

(a)Description of Electronic Delivery. The Plan documents, which may include, but do not necessarily include, the Plan, the Grant Notice, this Agreement, and any prospectus or other report of the Company provided generally to the Company’s shareholders, may be delivered to Participant electronically. In addition, if permitted by the Company, Participant may deliver electronically the Grant Notice to the Company or to such third party involved in administering the Plan as the Company may designate from time to time. Such means of electronic delivery may include, but do not necessarily include, the delivery of a link to a Company intranet or the internet site of a third party involved in administering the Plan, the delivery of the document via electronic mail, or such other means of electronic delivery as may be specified by the Company.

(b)Consent to Electronic Delivery. Participant hereby acknowledges that Participant has read and understands this Section 4.5, and hereby consents to the electronic delivery of any Plan documents as described in Section 4.5(b). Participant may receive from the Company a paper copy of any documents delivered electronically at no cost to Participant by providing written notice of such request to the Company. Participant will be provided with a paper copy of any documents if the attempted electronic delivery of such documents fails. Participant understands and hereby agrees that Participant must provide the Company or any designated third party administrator with a paper copy of any document if the attempted electronic delivery of such documents fails. Participant may change the electronic mail address to which such documents are to be delivered at any time by notifying the Company in writing of such revised electronic mail address.

4.6Administrator Authority; Decisions Conclusive and Binding. Participant hereby (a) acknowledges that a copy of the Plan has been made available for Participant’s review by the Company, (b) represents that Participant is familiar with the terms and provisions thereof, and (c) accepts the Award subject to all the terms and provisions thereof. The Administrator will have the power to (i) interpret this Agreement, the Grant Notice and the Plan, (ii) adopt such rules for the administration, interpretation and application of the Plan as are consistent therewith, and (iii) interpret or revoke any such rules. Participant hereby agrees to accept as binding, conclusive, and final all decisions of the Administrator upon any questions arising under the Plan, this Agreement or the Grant Notice. No employee of the Company who is acting with the requisite authority on behalf of the Administrator

will be personally liable for any action, determination or interpretation that is made in good faith with respect to the Plan, this Agreement or the Grant Notice.

4.7Entire Agreement. The Plan, the Grant Notice and this Agreement constitute the entire agreement of the parties and supersede, in their entirety, all prior undertakings and agreements of the Company and Participant with respect to the subject matter hereof. All prior negotiations and agreements between the parties with respect to the subject matter hereof are merged into this Agreement and the Grant Notice. Each party to this Agreement and the Grant Notice acknowledges that (a) no representations, inducements, promises, or agreements, orally or otherwise, have been made by any party or by anyone acting on behalf of any party, which are not embodied in this Agreement, the Grant Notice or the Plan, and (b) any agreement, statement, or promise that is not contained in this Agreement, the Grant Notice or the Plan will not be valid or binding or of any force or effect.

4.8Severability. Notwithstanding any contrary provision of the Grant Notice or this Agreement to the contrary, if any one or more of the provisions (or any part thereof) of the Grant Notice or this Agreement is held to be invalid, illegal, or unenforceable in any respect, such provision will be modified so as to make it valid, legal, and enforceable, and the validity, legality, and enforceability of the remaining provisions (or any part thereof) of the Grant Notice or this Agreement, as applicable, will not in any way be affected or impaired thereby.

4.9Survival of Certain Provisions. Wherever appropriate to the intention of the parties hereto, the respective rights and obligations of the parties hereunder will survive any termination or expiration of this Agreement or the Participant’s Termination of Service.

4.10Limitation on Participant’s Rights. Participation in the Plan confers no rights or interests other than as herein provided. This Agreement creates only a contractual obligation on the part of the Company as to amounts payable and may not be construed as creating a trust. Neither the Plan nor any underlying program, in and of itself, has any assets. Participant will have only the rights of a general unsecured creditor of the Company with respect to amounts credited and benefits payable, if any, with respect to the RSUs, and rights no greater than the right to receive cash as a general unsecured creditor with respect to the RSUs, as and when settled pursuant to the terms of this Agreement.

4.11Compensation Recoupment. The Award (and the cash issuable thereunder) are subject to the Company’s ability to recover incentive-based compensation from Participant, as is or may be required by (a) the Dodd-Frank Wall Street Reform and Consumer Protection Act, or any regulations or rules promulgated thereunder, (b) any other clawback provision required by Applicable Laws or the listing standards of any applicable stock exchange or national market system, (c) any clawback policies adopted by the Company to implement any such requirements, or (d) any other compensation recovery policies as may be adopted from time to time by the Company, all to the extent that is

determined by the Administrator, in its discretion, to be applicable with respect to Participant.

4.12No Effect on Employment or Service Relationship. Nothing in the Plan, the Grant Notice or this Agreement (a) confers upon Participant any right to continue as an Employee of the Company or any Subsidiary or (b) interferes with or restricts in any way the rights of the Company and its Subsidiaries, which rights are hereby expressly reserved, to discharge or terminate the services of Participant at any time for any reason whatsoever, with or without Cause, and with or without notice, except to the extent expressly provided otherwise in a written agreement between the Company or a Subsidiary and Participant.

4.13Construction. Headings in this Agreement are included for convenience and will not be considered in the interpretation of this Agreement. Reference to any statute, rule, or regulation includes any amendment thereto or any replacement thereof, as well as the authoritative guidance issued thereunder by the appropriate governmental entity. Pronouns will be construed to include the masculine, feminine, neutral, singular or plural as the identity of the antecedent may require. A reference to any party to this Agreement will include such party’s successors and permitted assigns. This Agreement will be construed according to its fair meaning and not strictly construed against the Company.

4.14Counterparts. The Grant Notice may be executed in one or more counterparts, including by way of any electronic signature, subject to Applicable Laws, each of which will be deemed an original and all of which together will constitute one and the same instrument.

4.15Modification. Any modification of this Agreement shall be binding only if evidenced in writing and signed by the Administrator, or its delegate. The Participant’s consent to such modification shall be required unless (i) the action does not materially and adversely affect the Participant’s rights under the Agreement and Grant Notice, or (ii) the change is permitted under Article X or pursuant to Section 12.5 of the Plan.

[End]

EX-10.7

EXHIBIT 10.7

ENBRIDGE INC.
2019 LONG TERM INCENTIVE PLAN

RESTRICTED STOCK UNIT GRANT NOTICE – ENERGY MARKETERS

Pursuant to the Enbridge Inc. 2019 Long Term Incentive Plan (the “Plan”), Enbridge Inc. (the “Company”) has granted to the participant listed below (“Participant”) an award (the “Award”) of Restricted Stock Units (the “RSUs”), as described in this Restricted Stock Unit Grant Notice (this “Grant Notice”), subject to the terms and conditions of the Plan and the Restricted Stock Unit Award Agreement attached hereto as Exhibit A (the “Agreement”), both of which are incorporated into this Grant Notice by reference. Capitalized terms not specifically defined in this Grant Notice will have the meanings given to them in the Agreement, and if not defined in the Agreement, the meanings given to them in the Plan.

Participant:

Grant Date:

Number of RSUs:

Term

Maturity Date:

By Participant’s signature below, Participant agrees to be bound by the terms of this Grant Notice, the Plan and the Agreement, effective as of the Grant Date. Participant has reviewed the Plan, this Grant Notice and the Agreement in their entireties, and acknowledges that the Company hereby advises Participant to obtain the advice of counsel prior to executing this Grant Notice. Participant fully understands and accepts all provisions of the Plan, this Grant Notice and the Agreement (including, without limitation, the shareholder approval requirement set forth in Section 1.2 of the Agreement). Participant hereby agrees to accept as binding, conclusive and final all decisions or interpretations of the Administrator upon any questions arising under the Plan, this Grant Notice or the Agreement. Participant agrees that the Grant Notice, the Agreement and the Plan constitute the entire agreement with respect to the Award.

Enbridge Inc.:		Participant:
By:
	Signature	Signature
Name:		Name:
Title:

RSU- Energy Marketers Grant Notice

Exhibit A

RESTRICTED STOCK UNIT AWARD AGREEMENT

Article IGENERAL

1.1Award of RSUs and Dividend Equivalents Units. (a) Subject to the terms and conditions of this Agreement (including, without limitation, the shareholder approval requirement set forth in Section 1.2) and the Plan, the Company has granted to Participant, effective as of the Grant Date set forth in the Grant Notice (the “Grant Date”), an award of RSUs as set forth in the Grant Notice. Each RSU represents the right to receive a cash amount equal to the Fair Market Value of one Share in accordance with Section 2.3; provided, however, that Participant will have no right to any payment until such time, if ever, that an RSU has vested and become payable hereunder.

(a)In the event that any cash dividend is declared on Shares with a record date that occurs during the Dividend Equivalent Period (as defined below), the Participant will receive dividend equivalent rights in the form of additional RSUs (the “Dividend Equivalent Units”) at the time such dividend is paid to the Company’s shareholders. The number of Dividend Equivalent Units that the Participant will receive at any such time will be equal to (1) the cash dividend amount per Share times (2) the number of RSUs covered by the Participant’s Award (and, unless otherwise determined by the Company, any Dividend Equivalent Units previously credited under the Participant’s Award that have not been previously settled through the delivery of Shares (or cash) prior to, such date), divided by the Fair Market Value of one Share on the applicable dividend payment date; provided, that, in the event the Dividend Reinvestment Plan is then in effect, the number of Dividend Equivalent Units that the Participant will receive shall instead be calculated in accordance with the methodologies (including any discount feature) set forth therein, as determined by the Administrator in its sole discretion. Each Dividend Equivalent Unit will constitute an unfunded and unsecured promise of the Company to deliver (or cause to be delivered) one Share (or, cash equal to the Fair Market Value thereof) in accordance with the Plan, and will vest and be settled or paid at the same time, and subject to the same terms and conditions, as the RSUs on which such Dividend Equivalent Unit was accrued. “Dividend Equivalent Period” means the period commencing on the Grant Date and ending on the last day on which Shares (or cash) are delivered to the Participant with respect to the RSUs.

1.2[Shareholder Approval Requirement. This Award will be contingent upon and effective as of approval of the Plan by the Company’s shareholders at the 2019 Annual Meeting. If the shareholders do not approve the Plan at the 2019 Annual Meeting, then this Agreement shall be null and void and the Participant shall have no rights or interests of any kind with respect to the RSUs or the associated Dividend Equivalent Units.]

1.3Nature of Award. The RSUs granted to Participant pursuant to the Grant Notice and this Award are prospective in nature such that the Award is not in respect of service rendered in a year prior to the year that includes the Grant Date.

1.4Incorporation of Terms of Plan. The RSUs are subject to the terms and conditions set forth in this Agreement and the Plan, which is incorporated herein by reference. In the event of any inconsistency between the Plan and this Agreement, the terms of the Plan will control.

1.5Defined Terms. Capitalized terms not specifically defined in this Agreement will have the meanings specified in the Grant Notice or, if not defined in the Grant Notice, in the Plan.

1.6Unsecured Promise. The RSUs will at all times prior to settlement represent an unsecured Company obligation payable only from the Company’s general assets.

ARTICLE II
VESTING, FORFEITURE AND SETTLEMENT

2.1Vesting; Maturity Date. (a) The RSUs will become vested on the Maturity Date; provided, that except as otherwise set forth in Section 2.1(b), the Participant is, as of the Maturity Date, and has been at all times since the Grant Date, an Employee.

(a)In the event that the Participant has a Termination of Service due to (i) death, (ii) Disability, (iii) Retirement or (iv) an involuntary Termination of Service by the Company or a Subsidiary without Cause, then all unvested RSUs shall automatically become 100% vested and be settled in accordance with Section 2.3.

(b)In the event of a Change in Control, all unvested RSUs shall automatically become 100% vested and be settled in accordance with Section 2.3.

2.2Forfeiture and Leave of Absence. Any RSUs that do not vest in accordance with Section 2.1 above shall immediately and automatically be cancelled and forfeited on the Participant’s Termination of Service for any reason. Notwithstanding anything herein to the contrary, (a) in the event that Participant has an involuntary Termination of Service for Cause, then any RSUs that have not been settled in accordance with Section 2.3 as of the Participant’s Termination of Service, whether vested or not, shall be immediately forfeited as of the date of the Participant’s Termination of Service and (b) in the event that Participant commences a Leave of Absence, all RSUs held by such Participant will remain outstanding and eligible to vest and be settled in accordance with Section 2.3.

2.3Settlement. (a) RSUs will be paid in cash within thirty days following the Maturity Date; provided, that (i) in the case of RSUs that become vested due to a Termination of Service due to the Participant’s death or the Participant’s Disability, the Maturity Date

shall be the date of the Participant’s Termination of Service and (ii) in the case of RSUs that become vested due to a Change in Control, subject to Section 2.3(b), the Maturity Date shall be the date of the Change in Control; provided, further, that in no case will any payment in respect of an RSU be made after the third year following the year that includes the Grant Date.

(a)Any payment to a Participant due upon a Change in Control pursuant to Section 2.3(a) will be paid only if such Change in Control constitutes a “change in ownership” or “change in effective control” within the meaning of Section 409A, and in the event that such Change in Control does not constitute a “change in the ownership” or “change in the effective control” within the meaning of Section 409A, the RSUs will vest upon the Change in Control and any payment will be delayed until the first compliant date under Section 409A. Any payment that is delayed until the first compliant date under Section 409A in accordance with this Section 2.3(b) shall, as of the date of the Change in Control, be paid into an irrevocable trust which is located in the United Stated and subject to the claims of the general creditors of the Company prior to the Change in Control.

(b)The amount of cash paid with respect to the RSU will equal the Fair Market Value of a Share on the last trading day that immediately precedes the Maturity Date and will be paid in the currency of Canada or the United States, depending on the applicable jurisdiction in which the Participant resides. For purposes of this Section 2.3, “Fair Market Value” shall mean, as of a particular day, the weighted average of the board lot trading prices per Share on the Toronto Stock Exchange, or the New York Stock Exchange, for the last twenty trading days immediately prior to such day.

2.4No Rights as Shareholder. Participant will have no rights as a shareholder (including, without limitation, the right to vote and to receive dividends) with respect to any RSUs covered by this Agreement.

ARTICLE III
TAXATION AND TAX WITHHOLDING

3.1Tax Withholding. (a) Participant must make arrangements acceptable to the Administrator for the satisfaction of any non-U.S., U.S.-federal, U.S.-state, or local income and employment tax withholding obligations arising in connection with the Award.

(a)Participant acknowledges that Participant is ultimately liable and responsible for all taxes owed in connection with the RSUs, regardless of any action the Company or any Subsidiary takes with respect to any tax withholding obligations that arise in connection with the RSUs. Neither the Company nor any Subsidiary makes any representation or undertaking regarding the treatment of any tax withholding in connection with the awarding, vesting or payment of the RSUs. The Company and the Subsidiaries do not commit to, and are under no obligation to structure this Award to, reduce or eliminate Participant’s tax liability.

(b)Participant acknowledges that the Company has advised Participant to obtain independent legal and tax advice regarding the grant and payment in respect of the RSUs.

3.2Section 409A. The provisions of this Section 3.2 apply to the Participant only if the Participant is a US taxpayer. This Agreement and the Plan provisions that apply to the RSUs are intended and will be construed to comply with Section 409A (including the requirements applicable to, or the conditions for exemption from treatment as, “deferred compensation” as defined in the regulations under Section 409A, whether by reason of short-term deferral treatment or other exceptions or provisions). The Administrator will have full authority to give effect to this intent. To the extent that any portion of the RSUs are intended to satisfy the requirements for short-term deferral treatment under Section 409A, delivery for such portion will occur by the March 15 coinciding with the last day of the applicable “short-term deferral” period described in Reg. 1.409A-1(b)(4) in order for the payment in respect of such RSUs to be within the short-term deferral exception unless, in order to permit all applicable conditions or restrictions on delivery to be satisfied, the Administrator elects, pursuant to Reg. 1.409A-1(b)(4)(i)(D) or otherwise as may be permitted in accordance with Section 409A, to delay payment to a later date within the same calendar year or to such later date as may be permitted under Section 409A. For the avoidance of doubt, if RSUs include a “series of installment payments” as described in Reg. 1.409A-2(b)(2)(iii), the Participant’s right to the series of installment payments will be treated as a right to a series of separate payments and not as a right to a single payment, and if the Participant is a “specified employee” (as defined by the Company in accordance with Section 409A(a)(2)(i)(B) of the Code), payment will occur on the earlier of the date set forth under Section 2.3 or (to the extent required to avoid the imposition of additional tax under Section 409A) the date that is six months after the Participant’s Termination of Service. For purposes of Section 2.3, references in this Agreement to the Participant’s Termination of Service mean a Termination of Service which is also a separation from service (as defined by the Company in accordance with Section 409A). In no event will the Participant be permitted to designate, directly or indirectly, the taxable year of payment.

ARTICLE IV
OTHER PROVISIONS

4.1Adjustments. Participant acknowledges that the RSUs are subject to adjustment, modification and termination in certain events as provided in this Agreement and the Plan.

4.2Limited Transferability. The Award may not be sold, pledged, assigned, hypothecated, transferred, or disposed of in any manner other than by will or by the laws of descent or distribution.

4.3Conformity to Applicable Laws. Participant acknowledges that the Plan, the Grant Notice and this Agreement are intended to conform to the extent necessary with all Applicable Laws and, to the extent Applicable Laws permit, will be deemed to be amended

to the minimum extent necessary to conform to Applicable Laws. Any determination in this regard that is made by the Administrator will be final, binding, and conclusive on all interested persons. The obligations of the Company and the rights of Participant are subject to compliance with all Applicable Laws.

Notwithstanding any other provision of the Plan or this Agreement, if Participant is subject to Section 16 of the Exchange Act, the Plan, the Grant Notice, this Agreement, the RSUs will be subject to any additional limitations set forth in any applicable exemptive rule under Section 16 of the Exchange Act (including any amendment to Rule 16b-3) that are requirements for the application of such exemptive rule. To the extent Applicable Laws permit, this Agreement will be deemed amended as necessary to conform to such applicable exemptive rule.

4.4Successors and Assigns. The Company may assign any of its rights under this Agreement to single or multiple assignees, and this Agreement will inure to the benefit of the successors and assigns of the Company. Subject to the restrictions on transfer set forth in the Plan and herein, this Agreement will be binding upon and inure to the benefit of the heirs, legatees, legal representatives, successors and assigns of the parties hereto.

4.5Notices. (a) General. Any document relating to participation in the Plan, or any notice required or permitted hereunder, shall be given in writing and shall be deemed effectively given upon personal delivery, electronic delivery at the electronic mail address, if any, provided for Participant by the Company, or, upon deposit in the U.S. Post Office or Canada Post, by registered or certified mail, or with a nationally recognized overnight courier service with postage and fees prepaid, addressed to the Company (c/o Corporate Secretary of the Company) at the Company’s principal office, and to Participant at the address appearing on the employment records of the Company, or at such other address as such party may designate in writing from time to time to the other party.

(a)Description of Electronic Delivery. The Plan documents, which may include, but do not necessarily include, the Plan, the Grant Notice, this Agreement, and any prospectus or other report of the Company provided generally to the Company’s shareholders, may be delivered to Participant electronically. In addition, if permitted by the Company, Participant may deliver electronically the Grant Notice to the Company or to such third party involved in administering the Plan as the Company may designate from time to time. Such means of electronic delivery may include, but do not necessarily include, the delivery of a link to a Company intranet or the internet site of a third party involved in administering the Plan, the delivery of the document via electronic mail, or such other means of electronic delivery as may be specified by the Company.

(b)Consent to Electronic Delivery. Participant hereby acknowledges that Participant has read and understands this Section 4.5, and hereby consents to the electronic delivery of any Plan documents as described in Section 4.5(b). Participant may receive from the Company a paper copy of any documents delivered electronically at no cost to Participant by providing written notice of such request to the Company. Participant will be provided with a paper copy of any documents if the attempted electronic delivery of such documents fails. Participant

understands and hereby agrees that Participant must provide the Company or any designated third party administrator with a paper copy of any document if the attempted electronic delivery of such documents fails. Participant may change the electronic mail address to which such documents are to be delivered at any time by notifying the Company in writing of such revised electronic mail address.

4.6Administrator Authority; Decisions Conclusive and Binding. Participant hereby (a) acknowledges that a copy of the Plan has been made available for Participant’s review by the Company, (b) represents that Participant is familiar with the terms and provisions thereof, and (c) accepts the Award subject to all the terms and provisions thereof. The Administrator will have the power to (i) interpret this Agreement, the Grant Notice and the Plan, (ii) adopt such rules for the administration, interpretation and application of the Plan as are consistent therewith, and (iii) interpret or revoke any such rules. Participant hereby agrees to accept as binding, conclusive, and final all decisions of the Administrator upon any questions arising under the Plan, this Agreement or the Grant Notice. No employee of the Company who is acting with the requisite authority on behalf of the Administrator will be personally liable for any action, determination or interpretation that is made in good faith with respect to the Plan, this Agreement or the Grant Notice.

4.7Entire Agreement. The Plan, the Grant Notice and this Agreement constitute the entire agreement of the parties and supersede, in their entirety, all prior undertakings and agreements of the Company and Participant with respect to the subject matter hereof. All prior negotiations and agreements between the parties with respect to the subject matter hereof are merged into this Agreement and the Grant Notice. Each party to this Agreement and the Grant Notice acknowledges that (a) no representations, inducements, promises, or agreements, orally or otherwise, have been made by any party or by anyone acting on behalf of any party, which are not embodied in this Agreement, the Grant Notice or the Plan, and (b) any agreement, statement, or promise that is not contained in this Agreement, the Grant Notice or the Plan will not be valid or binding or of any force or effect.

4.8Severability. Notwithstanding any contrary provision of the Grant Notice or this Agreement to the contrary, if any one or more of the provisions (or any part thereof) of the Grant Notice or this Agreement is held to be invalid, illegal, or unenforceable in any respect, such provision will be modified so as to make it valid, legal, and enforceable, and the validity, legality, and enforceability of the remaining provisions (or any part thereof) of the Grant Notice or this Agreement, as applicable, will not in any way be affected or impaired thereby.

4.9Survival of Certain Provisions. Wherever appropriate to the intention of the parties hereto, the respective rights and obligations of the parties hereunder will survive any termination or expiration of this Agreement or the Participant’s Termination of Service.

4.10Limitation on Participant’s Rights. Participation in the Plan confers no rights or interests other than as herein provided. This Agreement creates only a contractual

obligation on the part of the Company as to amounts payable and may not be construed as creating a trust. Neither the Plan nor any underlying program, in and of itself, has any assets. Participant will have only the rights of a general unsecured creditor of the Company with respect to amounts credited and benefits payable, if any, with respect to the RSUs, and rights no greater than the right to receive cash as a general unsecured creditor with respect to the RSUs, as and when settled pursuant to the terms of this Agreement.

4.11Compensation Recoupment. The Award (and the cash issuable thereunder) are subject to the Company’s ability to recover incentive-based compensation from Participant, as is or may be required by (a) the Dodd-Frank Wall Street Reform and Consumer Protection Act, or any regulations or rules promulgated thereunder, (b) any other clawback provision required by Applicable Laws or the listing standards of any applicable stock exchange or national market system, (c) any clawback policies adopted by the Company to implement any such requirements, or (d) any other compensation recovery policies as may be adopted from time to time by the Company, all to the extent that is determined by the Administrator, in its discretion, to be applicable with respect to Participant.

4.12No Effect on Employment or Service Relationship. Nothing in the Plan, the Grant Notice or this Agreement (a) confers upon Participant any right to continue as an Employee of the Company or any Subsidiary or (b) interferes with or restricts in any way the rights of the Company and its Subsidiaries, which rights are hereby expressly reserved, to discharge or terminate the services of Participant at any time for any reason whatsoever, with or without Cause, and with or without notice, except to the extent expressly provided otherwise in a written agreement between the Company or a Subsidiary and Participant.

4.13Construction. Headings in this Agreement are included for convenience and will not be considered in the interpretation of this Agreement. Reference to any statute, rule, or regulation includes any amendment thereto or any replacement thereof, as well as the authoritative guidance issued thereunder by the appropriate governmental entity. Pronouns will be construed to include the masculine, feminine, neutral, singular or plural as the identity of the antecedent may require. A reference to any party to this Agreement will include such party’s successors and permitted assigns. This Agreement will be construed according to its fair meaning and not strictly construed against the Company.

4.14Counterparts. The Grant Notice may be executed in one or more counterparts, including by way of any electronic signature, subject to Applicable Laws, each of which will be deemed an original and all of which together will constitute one and the same instrument.

4.15Modification. Any modification of this Agreement shall be binding only if evidenced in writing and signed by the Administrator, or its delegate. The Participant’s consent to such modification shall be required unless (i) the action does not materially and adversely affect the Participant’s rights under the Agreement and Grant Notice, or (ii) the change is permitted under Article X or pursuant to Section 12.5 of the Plan.

[End]

EX-31.1

Exhibit 31.1

CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Al Monaco, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Enbridge Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date:	May 10, 2019	By:	/s/ Al Monaco
			Al Monaco President and Chief Executive Officer Enbridge Inc.

EX-31.2

Exhibit 31.2

CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, John K. Whelen, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Enbridge Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting

Date:	May 10, 2019	By:	/s/ John K. Whelen
			John K. Whelen Executive Vice President and Chief Financial Officer (Principal Financial Officer) Enbridge Inc.

EX-32.1

EXHIBIT 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Enbridge Inc. on Form 10-Q for the period ending March 31, 2019 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Al Monaco, President and Chief Executive Officer of Enbridge Inc., certify, pursuant to 18 U.S.C. section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002, that:

1. The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Enbridge Inc.

Date:	May 10, 2019	By:	/s/ Al Monaco
			Al Monaco President and Chief Executive Officer Enbridge Inc.

EX-32.2

EXHIBIT 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Enbridge Inc. on Form 10-Q for the period ending March 31, 2019 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, John K. Whelen, Executive Vice President and Chief Financial Officer of Enbridge Inc., certify, pursuant to 18 U.S.C. section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002, that:

1. The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Enbridge Inc.

Date:	May 10, 2019	By:	/s/ John K. Whelen
			John K. Whelen Executive Vice President and Chief Financial Officer (Principal Financial Officer) Enbridge Inc.

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Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2019	May 03, 2019
Document And Entity Information [Abstract]
Entity Registrant Name	ENBRIDGE INC
Entity Central Index Key	0000895728
Document Type	10-Q
Document Period End Date	Mar. 31, 2019
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		2,023,709,816
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q1
Entity Emerging Growth Company	false
Entity Small Business	false

XML

CONSOLIDATED STATEMENTS OF EARNINGS - CAD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Operating revenues
Total operating revenues (Note 3)	$ 12,856	$ 12,726
Operating expenses
Operating and administrative	1,625	1,641
Depreciation and amortization	840	824
Impairment of long-lived assets	0	1,062
Total operating expenses	10,237	11,848
Operating income	2,619	878
Income from equity investments	413	335
Other income/(expense)
Net foreign currency gain/(loss)	214	(185)
Other	46	65
Interest expense	(685)	(656)
Earnings before income taxes	2,607	437
Income tax (expense)/recovery (Note 12)	(584)	73
Earnings	2,023	510
(Earnings)/loss attributable to noncontrolling interests and redeemable noncontrolling interests	(37)	24
Earnings attributable to controlling interests	1,986	534
Preference share dividends	(95)	(89)
Earnings attributable to common shareholders	$ 1,891	$ 445
Earnings per common share attributable to common shareholders (Note 5) (in Canadian dollars per share)	$ 0.94	$ 0.26
Diluted earnings per common share attributable to common shareholders (Note 5) (in Canadian dollars per share)	$ 0.94	$ 0.26
Commodity
Operating revenues
Total operating revenues (Note 3)	$ 6,632	$ 7,268
Operating expenses
Cost of goods and services sold	6,565	6,997
Gas Distribution
Operating revenues
Total operating revenues (Note 3)	1,876	1,926
Operating expenses
Cost of goods and services sold	1,207	1,324
Transportation and other services
Operating revenues
Total operating revenues (Note 3)	$ 4,348	$ 3,532

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - CAD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Statement of Comprehensive Income [Abstract]
Earnings	$ 2,023	$ 510
Other comprehensive income/(loss), net of tax
Change in unrealized gain/(loss) on cash flow hedges	(192)
Change in unrealized gain/(loss) on cash flow hedges		66
Change in unrealized gain/(loss) on net investment hedges	94	(184)
Other comprehensive income from equity investees	12	14
Reclassification to earnings of (gain)/loss on cash flow hedges	11
Reclassification to earnings of (gain)/loss on cash flow hedges		37
Reclassification to earnings of pension and other postretirement benefits (OPEB) amounts	38	(39)
Foreign currency translation adjustments	(1,291)	1,579
Other comprehensive income/(loss), net of tax	(1,328)	1,473
Comprehensive income	695	1,983
Comprehensive (income)/loss attributable to noncontrolling interests and redeemable noncontrolling interests	13	(147)
Comprehensive income attributable to controlling interests	708	1,836
Preference share dividends	(95)	(89)
Comprehensive income attributable to common shareholders	$ 613	$ 1,747

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CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY $ in Millions, $ in Millions	CAD ($) $ / shares	Preferred share investment CAD ($)	Common shares CAD ($)	Additional paid-in capital USD ($)	Additional paid-in capital CAD ($)	Retained earnings/(deficit) CAD ($)	Accumulated other comprehensive income CAD ($)	Reciprocal shareholding CAD ($)	Total Enbridge Inc. shareholders' equity CAD ($)	Noncontrolling interests CAD ($)
Balance at Dec. 31, 2017		$ 7,747	$ 50,737		$ 3,194	$ (2,468)	$ (973)	$ (102)		$ 7,597
Increase (Decrease) in Stockholders' Equity
Dividend Reinvestment and Share Purchase Plan			374
Options exercised			16		(6)
Stock-based compensation					17
Dilution gain on Spectra Energy Partners, LP restructuring					1,136
Dilution loss and other					(28)
Earnings attributable to controlling interests	$ 534					534
Preference share dividends						(89)
Dividends paid to reciprocal shareholder						7
Redemption value adjustment attributable to redeemable noncontrolling interests						120
Other										(15)
Other comprehensive income/(loss) attributable to common shareholders, net of tax							1,302
Earnings attributable to noncontrolling interests										23
Change in unrealized gain/(loss) on cash flow hedges										4
Foreign currency translation adjustments										152
Reclassification to earnings of loss on cash flow hedges										8
Other comprehensive income/(loss) attributable to noncontrolling interests, net of tax										164
Comprehensive income attributable to noncontrolling interests										187
Spectra Energy Partners, LP restructuring										(1,486)
Contributions										8
Distributions										(209)
Balance at Mar. 31, 2018	$ 67,514	7,747	51,127		4,313	(1,982)	329	(102)	$ 61,432	6,082
Increase (Decrease) in Stockholders' Equity
Dividends paid per common share (in Canadian dollars per share) | $ / shares	$ 0.671
Earnings per common share attributable to common shareholders (Note 5) (in Canadian dollars per share) | $ / shares	0.26
Diluted earnings per common share attributable to common shareholders (Note 5) (in Canadian dollars per share) | $ / shares	$ 0.26
Balance at Dec. 31, 2018	$ 73,435	7,747	64,677	$ 0		(5,538)	2,672	(88)		3,965
Increase (Decrease) in Stockholders' Equity
Options exercised			51		(43)
Stock-based compensation					4
Change in reciprocal interest					109
Dilution loss and other					2
Earnings attributable to controlling interests	1,986					1,986
Preference share dividends						(95)
Dividends paid to reciprocal shareholder						5
Other						2	55			5
Other comprehensive income/(loss) attributable to common shareholders, net of tax							(1,278)
Change in reciprocal interest								37
Earnings attributable to noncontrolling interests										37
Change in unrealized gain/(loss) on cash flow hedges										(1)
Foreign currency translation adjustments										(49)
Reclassification to earnings of loss on cash flow hedges										0
Other comprehensive income/(loss) attributable to noncontrolling interests, net of tax										(50)
Comprehensive income attributable to noncontrolling interests										(13)
Contributions										3
Distributions										(46)
Redemption of preferred shares held by subsidiary (Note 10)										(300)
Balance at Mar. 31, 2019	$ 73,919	$ 7,747	$ 64,728		$ 72	$ (3,640)	$ 1,449	$ (51)	$ 70,305	$ 3,614
Increase (Decrease) in Stockholders' Equity
Dividends paid per common share (in Canadian dollars per share) | $ / shares	$ 0.738
Earnings per common share attributable to common shareholders (Note 5) (in Canadian dollars per share) | $ / shares	0.94
Diluted earnings per common share attributable to common shareholders (Note 5) (in Canadian dollars per share) | $ / shares	$ 0.94

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CONSOLIDATED STATEMENTS OF CASH FLOWS - CAD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Operating activities
Earnings	$ 2,023	$ 510
Adjustments to reconcile earnings to net cash provided by operating activities:
Depreciation and amortization	840	824
Deferred income tax (recovery)/expense	435	(147)
Changes in unrealized (gain)/loss on derivative instruments, net (Note 11)	(538)	260
Earnings from equity investments	(413)	(335)
Distributions from equity investments	466	320
Impairment of long-lived assets	0	1,062
Other	30	78
Changes in operating assets and liabilities	(667)	622
Net cash provided by operating activities	2,176	3,194
Investing activities
Capital expenditures	(1,612)	(1,635)
Long-term investments and restricted long-term investments	(565)	(222)
Distributions from equity investments in excess of cumulative earnings	139	57
Additions to intangible assets	(26)	(258)
Affiliate loans, net	(84)	(10)
Net cash used in investing activities	(2,148)	(2,068)
Financing activities
Net change in short-term borrowings	(154)	(443)
Net change in commercial paper and credit facility draws	2,773	(465)
Debenture and term note issues, net of issue costs	1,195	2,061
Debenture and term note repayments	(1,789)	(996)
Debt extinguishment costs	0	(63)
Contributions from noncontrolling interests	3	8
Distributions to noncontrolling interests	(46)	(209)
Contributions from redeemable noncontrolling interests	0	20
Distributions to redeemable noncontrolling interests	0	(84)
Common shares issued	18	13
Preference share dividends	(90)	(87)
Common share dividends	(1,486)	(764)
Redemption of preferred shares held by subsidiary (Note 10)	(300)	0
Other	(25)	0
Net cash provided by/(used in) financing activities	99	(1,009)
Effect of translation of foreign denominated cash and cash equivalents and restricted cash	(7)	19
Net increase in cash and cash equivalents and restricted cash	120	136
Cash and cash equivalents and restricted cash at beginning of period	637	587
Cash and cash equivalents and restricted cash at end of period	$ 757	$ 723

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CONSOLIDATED STATEMENTS OF FINANCIAL POSITION - CAD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
Current assets
Cash and cash equivalents	$ 702	$ 518
Restricted cash	55	119
Accounts receivable and other	6,486	6,517
Accounts receivable from affiliates	92	79
Inventory	1,047	1,339
Total current assets	8,382	8,572
Property, plant and equipment, net	93,875	94,540
Long-term investments	16,902	16,707
Restricted long-term investments	356	323
Deferred amounts and other assets	9,505	8,558
Intangible assets, net	2,301	2,372
Goodwill	33,895	34,459
Deferred income taxes	1,292	1,374
Total assets	166,508	166,905
Current liabilities
Short-term borrowings	870	1,024
Accounts payable and other	7,331	9,863
Accounts payable to affiliates	30	40
Interest payable	573	669
Current portion of long-term debt	4,321	3,259
Total current liabilities	13,125	14,855
Long-term debt	60,680	60,327
Other long-term liabilities	9,044	8,834
Deferred income taxes	9,740	9,454
Total liabilities	92,589	93,470
Contingencies (Note 15)
Share capital
Preference shares	7,747	7,747
Common shares (2,024 and 2,022 outstanding at March 31, 2019 and December 31, 2018, respectively)	64,728	64,677
Additional paid-in capital	72	0
Deficit	(3,640)	(5,538)
Accumulated other comprehensive income (Note 9)	1,449	2,672
Reciprocal shareholding	(51)	(88)
Total Enbridge Inc. shareholders’ equity	70,305	69,470
Noncontrolling interests	3,614	3,965
Total equity	73,919	73,435
Total liabilities and equity	$ 166,508	$ 166,905

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CONSOLIDATED STATEMENTS OF FINANCIAL POSITION (Parenthetical) - shares shares in Millions	Mar. 31, 2019	Dec. 31, 2018
Statement of Financial Position [Abstract]
Common shares, outstanding (in shares)	2,024	2,022

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BASIS OF PRESENTATION

3 Months Ended

Mar. 31, 2019

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 updated consolidated financial statements and notes for the year ended December 31, 2018, as filed on Form 8-K with the Securities and Exchange Commission on May 10, 2019. 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 audited updated consolidated financial statements for the year ended December 31, 2018, 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.

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CHANGES IN ACCOUNTING POLICIES

3 Months Ended

Mar. 31, 2019

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

CHANGES IN ACCOUNTING POLICIES

CHANGES IN ACCOUNTING POLICIES

ADOPTION OF NEW STANDARDS

Cloud Computing Arrangements

Effective January 1, 2019, we adopted Accounting Standards Update (ASU) 2018-15 on a prospective basis. The new standard was issued to provide guidance on the accounting for implementation costs incurred in a cloud computing arrangement (CCA) that is a service contract. The ASU specifies that an entity would apply Accounting Standards Codification (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. The amendments in the update also require that the 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, in addition to specifying that the capitalized costs must be presented on the same balance sheet line as the prepayment of fees related to the hosting arrangement. The ASU requires similar consistency in classifications from a cash flow statement perspective. The adoption of this ASU did not have a material impact on our consolidated financial statements.

Improvements to Accounting for Hedging Activities

Effective January 1, 2019, we adopted ASU 2017-12 on a modified retrospective basis. The new standard was issued 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. As a result of the new standard, hedge ineffectiveness will no longer be measured or recorded, and hedging instruments’ fair value changes will be recorded in the same income statement line as the hedged item. The adoption of this accounting update did not have a material impact on our consolidated financial statements.

Amending the Amortization Period for Certain Callable Debt Securities Purchased at a Premium

Effective January 1, 2019, we adopted ASU 2017-08 on a modified retrospective basis. The new standard was issued with the intent of shortening the amortization period to the earliest call date for certain callable debt securities held at a premium. The adoption of this accounting update did not have a material impact on our consolidated financial statements.

Recognition of Leases

Effective January 1, 2019 we adopted ASU 2016-02 Leases (Topic 842) using the modified retrospective approach.

We recognize an arrangement 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 recognize right-of-use (ROU) assets and the related lease liabilities on the statement of financial position for operating lease arrangements with a term of 12 months or longer. We do not separate non-lease components from the associated lease components of our lessee contracts and account for both components as a single lease component. We combine lease and non-lease components within a contract for operating lessor leases when certain conditions are met. ROU assets are assessed for impairment using the same approach as is applied for other long-lived assets, as described under the Impairment section of the Significant Accounting Policies Note 2 in the annual consolidated financial statements.

Lease liabilities and ROU assets require the use of judgment and estimates, which are applied in determining the term of a lease, appropriate discount rates, whether an arrangement contains a lease, whether there are any indicators of impairment for ROU assets and whether any ROU assets should be grouped with other long-lived assets for impairment testing.

In adopting Topic 842, we elected the package of practical expedients permitted under the transition guidance. 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. The application of the package of practical expedients also permits entities not to reassess whether any expired or existing contracts contain leases in accordance with the new guidance, lease classifications, and whether initial direct costs capitalized under current guidance continue to meet the definition of initial direct costs under the new guidance. We also elected the practical expedient related to land easements, allowing us to carry forward our accounting treatment for land easements on existing agreements that had commenced prior to January 1, 2019.

On January 1, 2019, ROU assets and corresponding lease liabilities of $771 million were recorded in connection with the adoption of Topic 842. When added to the $85 million of pre-existing liabilities relating to operating leases for which we no longer utilize the leased assets, total lease liabilities at January 1, 2019 were $856 million. All lease liabilities were measured using a weighted average discount rate of 4.32%. The adoption of this standard had no impact to the Consolidated Statements of Earnings, Comprehensive Income, Changes in Equity or Cash Flows during the period.

FUTURE ACCOUNTING POLICY CHANGES

Clarifying Interaction between Collaborative Arrangements and Revenue from Contracts with Customers

In November 2018, ASU 2018-18 was issued to provide clarity on when transactions between entities in a collaborative arrangement should be accounted for under the new revenue standard, ASC 606. In determining whether transactions in collaborative arrangements should be accounted under the revenue standard, the update specifies that entities shall apply unit of account guidance to identify distinct goods or services and whether such goods and services are separately identifiable from other promises in the contract. ASU 2018-18 also precludes entities from presenting transactions with a collaborative partner which are not in scope of the new revenue standard together with revenue from contracts with customers. The accounting update is effective January 1, 2020 and early adoption is permitted. We are currently assessing the impact of the new standard on our consolidated financial statements.

Improvements to Related Party Guidance for Variable Interest Entities

ASU 2018-17 was issued in October 2018 to improve the related party guidance on determining whether fees paid to decision makers and service providers (“decision-maker fees”) are variable interests. Under the new guidance, reporting entities must consider indirect interests held through related parties in common control arrangements on a proportionate basis, rather than as the equivalent of a direct interest in its entirety, when determining if a decision maker’s fees constitute a variable interest. The accounting update is effective January 1, 2020 and must be applied on a retrospective basis. We are currently assessing the impact of the new standard on our consolidated financial statements.

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.

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 delay the recognition until it is probable a loss has been incurred. The accounting update adds a new impairment model, known as the current expected credit loss model, which is based on expected losses rather than incurred losses. Under the new guidance, an entity will recognize as an allowance its estimate of expected credit losses, which the Financial Accounting Standards Board believes will result in more timely recognition of such losses.

Further, ASU 2018-19 was issued in November 2018 to clarify that operating lease receivables should be accounted for under the new leases standard, ASC 842, and are not within the scope of ASC 326, Financial Instruments - Credit Losses. Both accounting updates are effective January 1, 2020. We are currently assessing the impact of the new standard on our consolidated financial statements.

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REVENUES

3 Months Ended

Mar. 31, 2019

Revenue from Contract with Customer [Abstract]

REVENUES

REVENUES

Effective January 1, 2019, we renamed the Green Power and Transmission segment to Renewable Power Generation and Transmission. The presentation of the prior years' tables has been revised in order to align with the current presentation.

REVENUE FROM CONTRACTS WITH CUSTOMERS

Major Products and Services

	Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution	Renewable Power Generation and Transmission	Energy Services	Eliminations and Other		Consolidated
Three months ended March 31, 2019
(millions of Canadian dollars)
Transportation revenues	2,214	1,137	249	—	—	—		3,600
Storage and other revenues	27	53	54	—	—	—		134
Gas gathering and processing revenues	—	116	—	—	—	—		116
Gas distribution revenue	—	—	1,856	—	—	—		1,856
Electricity and transmission revenues	—	—	—	50	—	—		50
Total revenue from contracts with customers	2,241	1,306	2,159	50	—	—		5,756
Commodity sales	—	—	—	—	6,632	—		6,632
Other revenues1,2	340	10	29	102	6	(19	)	468
Intersegment revenues	77	2	3	—	35	(117	)	—
Total revenues	2,658	1,318	2,191	152	6,673	(136	)	12,856

	Liquids Pipelines		Gas Transmission and Midstream	Gas Distribution	Renewable Power Generation and Transmission	Energy Services	Eliminations and Other		Consolidated
Three months ended March 31, 2018
(millions of Canadian dollars)
Transportation revenues	2,058		952	239	—	—	—		3,249
Storage and other revenues	40		60	66	—	—	—		166
Gas gathering and processing revenues	—		205	—	—	—	—		205
Gas distribution revenues	—		—	1,926	—	—	—		1,926
Electricity and transmission revenues	—		—	—	57	—	—		57
Commodity sales	—		693	—	—	—	—		693
Total revenue from contracts with customers	2,098		1,910	2,231	57	—	—		6,296
Commodity sales	—		—	—	—	6,575	—		6,575
Other revenues1, 2	(269	)	25	2	100	—	(3	)	(145	)
Intersegment revenues	80		2	4	—	57	(143	)	—
Total revenues	1,909		1,937	2,237	157	6,632	(146	)	12,726

1  Includes mark-to-market gains/(losses) from our hedging program.

2 Includes revenues from lease contracts, refer to Note 14 Leases.

We disaggregate revenues into categories which represent our principal performance obligations within each business segment because these revenues categories represent the most significant revenue streams in each segment and consequently are considered to be the most relevant revenues information for management to consider in evaluating performance.

Contract Balances

	Receivables	Contract Assets	Contract Liabilities
(millions of Canadian dollars)
Balance as at December 31, 2018	1,929	191	1,297
Balance as at March 31, 2019	2,338	191	1,262

Contract receivables represent the amount of receivables derived from contracts with customers. Contract assets represent the amount of revenues 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 revenues. Revenues recognized during the three months ended March 31, 2019 included in contract liabilities at the beginning of the period is $92 million. Increases in contract liabilities from cash received, net of amounts recognized as revenues during the three months ended March 31, 2019 were $74 million.

Performance Obligations

There was no material revenues recognized in the three months ended March 31, 2019 from performance obligations satisfied in previous periods.

Revenues to be Recognized from Unfulfilled Performance Obligations

Total revenues from performance obligations expected to be fulfilled in future periods is $66.7 billion, of which $5.3 billion and $5.8 billion is expected to be recognized during the nine months ending December 31, 2019, and the year ending December 31, 2020, 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 revenues 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.

Recognition and Measurement of Revenues

	Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution	Renewable Power Generation and Transmission	Energy Services	Consolidated
Three months ended March 31, 2019
(millions of Canadian dollars)
Revenues from products transferred at a point in time1	—	—	17	—	—	17
Revenues from products and services transferred over time2	2,241	1,306	2,142	50	—	5,739
Total revenue from contracts with customers	2,241	1,306	2,159	50	—	5,756

	Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution	Renewable Power Generation and Transmission	Energy Services	Consolidated
Three months ended March 31, 2018
(millions of Canadian dollars)
Revenues from products transferred at a point in time1	—	693	25	—	—	718
Revenues from products and services transferred over time2	2,098	1,217	2,206	57	—	5,578
Total revenue from contracts with customers	2,098	1,910	2,231	57	—	6,296

1  Revenues from sales of crude oil, natural gas and NGLs.

2 

Revenues 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.

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SEGMENTED INFORMATION

3 Months Ended

Mar. 31, 2019

Segment Reporting [Abstract]

SEGMENTED INFORMATION

SEGMENTED INFORMATION

	Liquids Pipelines		Gas Transmission and Midstream		Gas Distribution		Renewable Power Generation and Transmission		Energy Services		Eliminations and Other		Consolidated
Three months ended March 31, 2019
(millions of Canadian dollars)
Revenues	2,658		1,318		2,191		152		6,673		(136	)	12,856
Commodity and gas distribution costs	(6	)	—		(1,264	)	(1	)	(6,629	)	128		(7,772	)
Operating and administrative	(801	)	(513	)	(294	)	(42	)	(33	)	58		(1,625	)
Income/(loss) from equity investments	197		197		11		14		(7	)	1		413
Other income	24		18		18		1		2		197		260
Earnings before interest, income taxes, and depreciation and amortization	2,072		1,020		662		124		6		248		4,132
Depreciation and amortization													(840	)
Interest expense													(685	)
Income tax expense													(584	)
Earnings													2,023
Capital expenditures1	1,020		394		173		14		1		25		1,627

	Liquids Pipelines		Gas Transmission and Midstream		Gas Distribution		Renewable Power Generation and Transmission		Energy Services		Eliminations and Other		Consolidated
Three months ended March 31, 2018
(millions of Canadian dollars)
Revenues	1,909		1,937		2,237		157		6,632		(146	)	12,726
Commodity and gas distribution costs	(4	)	(620	)	(1,388	)	—		(6,455	)	146		(8,321	)
Operating and administrative	(747	)	(507	)	(248	)	(30	)	(12	)	(97	)	(1,641	)
Impairment of long-lived assets	(144	)	(913	)	—		—		—		(5	)	(1,062	)
Income from equity investments	131		208		17		(25	)	4		—		335
Other income/(expense)	11		21		18		7		—		(177	)	(120	)
Earnings/(loss) before interest, income taxes, and depreciation and amortization	1,156		126		636		109		169		(279	)	1,917
Depreciation and amortization													(824	)
Interest expense													(656	)
Income tax recovery													73
Earnings													510
Capital expenditures1	615		825		183		14		—		6		1,643

1 

Includes allowance for equity funds used during construction.

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EARNINGS PER COMMON SHARE AND DIVIDEND PER SHARE

3 Months Ended

Mar. 31, 2019

Earnings Per Share [Abstract]

EARNINGS PER COMMON SHARE AND DIVIDEND PER SHARE

EARNINGS PER COMMON SHARE AND DIVIDENDS PER 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 6 million and 13 million for the three months ended March 31, 2019 and 2018, 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 March 31,
	2019	2018
(number of common shares in millions)
Weighted average shares outstanding	2,016	1,685
Effect of dilutive options	3	4
Diluted weighted average shares outstanding	2,019	1,689

For the three months ended March 31, 2019 and 2018, 10,495,198 and 29,882,142, respectively, anti-dilutive stock options with a weighted average exercise price of $55.32 and $49.80, respectively, were excluded from the diluted earnings per common share calculation.

DIVIDENDS PER SHARE

On April 23, 2019, our Board of Directors declared the following quarterly dividends. All dividends are payable on June 1, 2019, to shareholders of record on May 15, 2019.

	Dividend per share
Common Shares		$0.73800
Preference Shares, Series A		$0.34375
Preference Shares, Series B		$0.21340
Preference Shares, Series C1		$0.25395
Preference Shares, Series D		$0.27875
Preference Shares, Series F		$0.29306
Preference Shares, Series H		$0.27350
Preference Shares, Series J		US$0.30540
Preference Shares, Series L		US$0.30993
Preference Shares, Series N		$0.31788
Preference Shares, Series P2		$0.27369
Preference Shares, Series R		$0.25000
Preference Shares, Series 1		US$0.37182
Preference Shares, Series 3		$0.25000
Preference Shares, Series 53		US$0.33596
Preference Shares, Series 74		$0.27806
Preference Shares, Series 9		$0.27500
Preference Shares, Series 11		$0.27500
Preference Shares, Series 13		$0.27500
Preference Shares, Series 15		$0.27500
Preference Shares, Series 17		$0.32188
Preference Shares, Series 19		$0.30625

1 The quarterly dividend per share paid on Series C was decreased to $0.25395 from $0.25459 on March 1, 2019, due to reset on a quarterly basis following the date of issuance of the Series C Preference Shares.

2 The quarterly dividend per share paid on Series P was increased to $0.27369 from $0.25000 on March 1, 2019, due to reset of the annual dividend on March 1, 2019, and every five years thereafter.

3 The quarterly dividend per share paid on Series 5 was increased to US$0.33596 from US$0.27500 on March 1, 2019, due to reset of the annual dividend on March 1, 2019, and every five years thereafter.

4 The quarterly dividend per share paid on Series 7 was increased to $0.27806 from $0.27500 on March 1, 2019, due to reset of the annual dividend on March 1, 2019, and every five years thereafter.

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AQUISITIONS AND DISPOSITIONS

3 Months Ended

Mar. 31, 2019

Discontinued Operations and Disposal Groups [Abstract]

AQUISITIONS AND DISPOSITIONS

ACQUISITIONS AND DISPOSITIONS

ACQUISITIONS

In January 2019, through our wholly-owned subsidiary Enbridge Pipelines (Athabasca) Inc., we acquired 75 kilometers of existing pipeline and tankage infrastructure (collectively, the Cheecham Assets) from Athabasca Oil Corporation for cash consideration of approximately $265 million, all of which was allocated to property, plant and equipment. The Cheecham Assets are a part of our Liquids Pipelines segment. The cash consideration is included in capital expenditures on our Consolidated Statements of Cash Flows for the three months ended March 31, 2019.

ASSETS HELD FOR SALE

Enbridge Gas New Brunswick

In December 2018, we entered into an agreement for the sale of Enbridge Gas New Brunswick Limited Partnership and Enbridge Gas New Brunswick Inc. (collectively, EGNB) to Liberty Utilities (Canada) LP, a wholly-owned subsidiary of Algonquin Power and Utilities Corp., for a cash purchase price of $331 million, subject to customary closing adjustments. EGNB operates and maintains natural gas distribution pipelines in southern New Brunswick, and its related assets are included in our Gas Distribution segment. Subject to certain regulatory approvals and customary closing conditions, the transaction is expected to close in 2019.

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. On October 1, 2018, we closed the sale of the provincially regulated facilities for proceeds of approximately $2.5 billion. Subject to certain regulatory approvals and customary closing conditions, the sale of the federally regulated facilities is expected to close in mid-2019 for proceeds of approximately $1.8 billion.

Line 10 Crude Oil Pipeline

In the first quarter of 2018, we satisfied the conditions 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 wholly-owned subsidiaries, Enbridge Pipelines Inc. and Enbridge Energy Partners, L.P. (EEP), own the Canadian and United States portions of Line 10. Subject to certain regulatory approvals and customary closing conditions, the transaction is expected to close in 2019.

St. Lawrence Gas Company, Inc.

In August 2017, we entered into an agreement to sell the issued and outstanding shares of St. Lawrence Gas Company, Inc. for cash proceeds of approximately $94 million (US$70 million). Subject to regulatory approval and certain pre-closing conditions, the transaction is expected to close in 2019.

The table below summarizes the presentation of net assets held for sale in our Consolidated Statements of Financial Position:

	March 31, 2019		December 31, 2018
(millions of Canadian dollars)
Accounts receivable and other (current assets held for sale)	101		117
Deferred amounts and other assets (long-term assets held for sale)1	2,415		2,383
Accounts payable and other (current liabilities held for sale)	(55	)	(63	)
Other long-term liabilities (long-term liabilities held for sale)	(99	)	(96	)
Net assets held for sale	2,362		2,341

1

Included within Deferred amounts and other assets at March 31, 2019 and December 31, 2018 respectively is property, plant and equipment of $2.2 billion and $2.1 billion.

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VARIABLE INTEREST ENTITIES

3 Months Ended

Mar. 31, 2019

VARIABLE INTEREST ENTITIES

VARIABLE INTEREST ENTITIES

VARIABLE INTEREST ENTITIES

Gray Oak Holdings LLC

In December 2018, Enbridge acquired an effective 22.8% interest in the Gray Oak crude oil pipeline through acquisition of a 35% membership interest in Gray Oak Holdings LLC (Gray Oak Holdings), which will construct and operate the Gray Oak crude oil pipeline from Texas to the Gulf coast of the United States.

Gray Oak Holdings is a variable interest entity (VIE) as it does not have sufficient equity at risk to finance its activities and requires subordinated financial support from Enbridge and other partners. We have determined that we do not have the power to direct the activities of Gray Oak Holdings that most significantly impact the VIE’s economic performance. Specifically, the power to direct the activities of the VIE is shared amongst the partners. Each partner has representatives that make up an executive committee that makes the significant decisions for the VIE and none of the partners may make major decisions unilaterally. Therefore, the VIE is accounted for as an unconsolidated VIE.

As at March 31, 2019 and December 31, 2018, the carrying amount of the investment in Gray Oak Holdings was $455 million and nil, respectively. Enbridge's maximum exposure to loss as at March 31, 2019 was approximately $931 million and primarily consists of our portion of the project construction costs.

On March 29, 2019, we and our partners of the Gray Oak Holdings investment executed a loan agreement to loan up to a maximum of US$1,230 million to the investment to finance the construction of the Gray Oak crude oil pipeline. The amount committed by us is US$280 million, which is proportionate to our effective ownership interest. Loans under this agreement are due on March 31, 2022, with early repayment permitted.

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DEBT

3 Months Ended

Mar. 31, 2019

Debt Disclosure [Abstract]

DEBT

DEBT

On January 22, 2019, Enbridge entered into supplemental indentures with its wholly-owned subsidiaries, Spectra Energy Partners, LP (SEP) and EEP (together, the Partnerships), pursuant to which Enbridge fully and unconditionally guaranteed, on a senior unsecured basis, the payment obligations of the Partnerships with respect to the outstanding series of notes issued under the respective indentures of the Partnerships. Concurrently, the Partnerships entered into a subsidiary guarantee agreement pursuant to which they guaranteed, on a senior unsecured basis, the outstanding series of senior notes of Enbridge. See Note 16 - Condensed Consolidating Financial Information for further discussion.

CREDIT FACILITIES

The following table provides details of our committed credit facilities as at March 31, 2019:

	Maturity	Total Facilities	Draws1	Available
(millions of Canadian dollars)
Enbridge Inc.	2019-2024	6,137	4,319	1,818
Enbridge (U.S.) Inc.	2021-2024	7,348	5,252	2,096
Enbridge Pipelines Inc.	2020	3,000	1,513	1,487
Enbridge Gas Inc.	2019-2021	2,017	879	1,138
Total committed credit facilities		18,502	11,963	6,539

1    Includes facility draws and commercial paper issuances that are back-stopped by credit facilities.

On February 7, 2019 and February 8, 2019, we terminated certain Canadian and United States dollar credit facilities, including facilities held by Enbridge, EGI, EEP and SEP. We also increased existing facilities or obtained new facilities to replace the terminated ones under Enbridge, Enbridge (U.S.) Inc. and EGI. As a result, our total credit facility availability increased by approximately $444 million.

In addition to the committed credit facilities noted above, we maintain $800 million of uncommitted demand credit facilities, of which $516 million were unutilized as at March 31, 2019. As at December 31, 2018, we had $807 million of uncommitted credit facilities, of which $548 million were unutilized.

Our credit facilities carry a weighted average standby fee of 0.1% 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 2020 to 2024.

As at March 31, 2019 and December 31, 2018, commercial paper and credit facility draws, net of short-term borrowings and non-revolving credit facilities that mature within one year of $10,689 million and $7,967 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 three months ended March 31, 2019, we completed the following long-term debt issuances:

Company	Issue Date		Principal Amount
(millions of Canadian dollars)
Enbridge Pipelines Inc.
	February 2019	3.52% medium-term notes due February 2029	$600
	February 2019	4.33% medium-term notes due February 2049	$600

LONG-TERM DEBT REPAYMENTS

During the three months ended March 31, 2019, we completed the following long-term debt repayments:

Company	Retirement/ Repayment Date		Principal Amount
(millions of Canadian dollars, unless otherwise stated)
Enbridge Inc.
Repayment
	February 2019	4.10% medium-term notes	$300
Enbridge Energy Partners, L.P.
Redemption
	February 2019	8.05% fixed/floating rate junior subordinated notes due 2067	US$400
Repayment
	March 2019	9.88% senior notes	US$500
Westcoast Energy Inc.
Repayment
	January 2019	5.60% medium-term notes	$250
	January 2019	5.60% medium-term notes	$50

SUBORDINATED TERM NOTES

As at March 31, 2019 and December 31, 2018, our fixed-to-floating subordinated term notes had a principal value of $6,675 million and $7,317 million, respectively.

FAIR VALUE ADJUSTMENT

As at March 31, 2019, the net fair value adjustment for total debt assumed in the Spectra Energy merger transaction was $930 million. During the three months ended March 31, 2019, the amortization of the fair value adjustment, recorded as a reduction to Interest expense in the Consolidated Statements of Earnings, was $17 million.

DEBT COVENANTS

Our credit facility agreements and term debt indentures include standard events of default and covenant provisions whereby accelerated repayment and/or termination of the agreements may result if we were to default on payment or violate certain covenants. As at March 31, 2019, we were in compliance with all debt covenants.

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COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME

3 Months Ended

Mar. 31, 2019

Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]

COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME

COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME

Changes in Accumulated Other Comprehensive Income (AOCI) attributable to our common shareholders for the three months ended March 31, 2019 and 2018 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, 2019	(770	)	(598	)	4,323		34	(317	)	2,672
Other comprehensive income/(loss) retained in AOCI	(312	)	109		(1,242	)	8	—		(1,437	)
Other comprehensive (income)/loss reclassified to earnings
Interest rate contracts1	32		—		—		—	—		32
Foreign exchange contracts3	2		—		—		—	—		2
Other contracts4	(9	)	—		—		—	—		(9	)
Amortization of pension and OPEB actuarial loss and prior service costs5	—		—		—		—	53		53
	(287	)	109		(1,242	)	8	53		(1,359	)
Tax impact
Income tax on amounts retained in AOCI	121		(15	)	—		4	—		110
Income tax on amounts reclassified to earnings	(14	)	—		—		—	(15	)	(29	)
	107		(15	)	—		4	(15	)	81
Other	—		—		—		—	55		55
Balance as at March 31, 2019	(950	)	(504	)	3,081		46	(224	)	1,449

	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	70		(213	)	1,425	2	—		1,284
Other comprehensive (income)/loss reclassified to earnings
Interest rate contracts1	28		—		—	—	—		28
Commodity contracts2	(1	)	—		—	—	—		(1	)
Foreign exchange contracts3	4		—		—	—	—		4
Other contracts4	9		—		—	—	—		9
Amortization of pension and OPEB actuarial loss and prior service costs5	—		—		—	—	(38	)	(38	)
	110		(213	)	1,425	2	(38	)	1,286
Tax impact
Income tax on amounts retained in AOCI	(9	)	29		—	8	—		28
Income tax on amounts reclassified to earnings	(11	)	—		—	—	(1	)	(12	)
	(20	)	29		—	8	(1	)	16
Balance as at March 31, 2018	(554	)	(323	)	1,502	20	(316	)	329

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.

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NONCONTROLLING INTERESTS

3 Months Ended

Mar. 31, 2019

Noncontrolling Interest [Abstract]

NONCONTROLLING INTERESTS

NONCONTROLLING INTERESTS

Preferred Shares Redemption

On March 20, 2019, Westcoast Energy Inc. exercised its right to redeem all of its outstanding 5.5% Cumulative Redeemable First Preferred Shares, Series 7 ("Series 7 Shares") and all of its outstanding 5.6% Cumulative Redeemable First Preferred Shares, Series 8 ("Series 8 Shares") at a price of $25.00 per Series 7 Share and $25.00 per Series 8 Share, respectively, for a total payment of $300 million. In addition, payment of $4 million was made for all accrued and unpaid dividends. As a result, we recorded a $300 million decrease in Noncontrolling interests.

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RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

3 Months Ended

Mar. 31, 2019

Derivative Instruments and Hedging Activities Disclosure [Abstract]

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

MARKET RISK

Our earnings, cash flows and Other Comprehensive Income (OCI) are subject to movements in foreign exchange rates, interest rates, commodity prices and our share price (collectively, market 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 is used to hedge anticipated foreign currency denominated revenues and expenses, and to manage variability in cash flows. We hedge

certain net investments in United States dollar denominated investments and subsidiaries using foreign currency derivatives and United States dollar denominated debt.

Interest Rate Risk

Our earnings and cash flows are exposed to short-term interest rate variability due to the regular repricing of our variable rate debt, primarily commercial paper. Pay fixed-receive floating interest rate swaps may be used to hedge against the effect of future interest rate movements. We have implemented a program to significantly mitigate the impact of short-term interest rate volatility on interest expense via execution of floating to fixed interest rate swaps with an average swap rate of 2.8%.

We are exposed to changes in the fair value of fixed rate debt that arise as a result of the changes in market interest rates. Pay floating-receive fixed interest rate swaps are used, when applicable, to hedge against future changes to the fair value of fixed rate debt which mitigates the impact of fluctuations in the fair value of fixed rate debt via execution of fixed to floating interest rate swaps. As at March 31, 2019, we do not have any pay floating-receive fixed interest rate swaps outstanding.

Our earnings and cash flows are also exposed to variability in longer term interest rates ahead of anticipated fixed rate term debt issuances. Forward starting interest rate swaps are used to hedge against the effect of future interest rate movements. We have established a program within some of our subsidiaries to mitigate our exposure to long-term interest rate variability on select forecast term debt issuances via execution of floating to fixed interest rate swaps with an average swap rate of 3%.

We also monitor our debt portfolio mix of fixed and variable rate debt instruments to manage a consolidated portfolio of floating rate debt within the Board of Directors approved policy limit of a maximum of 30% of floating rate debt as a percentage of total debt outstanding. We primarily use qualifying derivative instruments to manage interest rate risk.

Commodity Price Risk

Our earnings and cash flows are exposed to changes in commodity prices as a result of our ownership interests in certain assets and investments, as well as through the activities of our energy services subsidiaries. These commodities include natural gas, crude oil, power and NGL. We employ financial and physical derivative instruments to fix a portion of the variable price exposures that arise from physical transactions involving these commodities. We use primarily non-qualifying derivative instruments to manage commodity price risk.

Equity Price Risk

Equity price risk is the risk of earnings fluctuations due to changes in our share price. We have exposure to our own common share price through the issuance of various forms of stock-based compensation, which affect earnings through revaluation of the outstanding units every period. We use equity derivatives to manage the earnings volatility derived from one form of stock-based compensation, restricted share units. We use a combination of qualifying and non-qualifying derivative instruments to manage equity price risk.

TOTAL DERIVATIVE INSTRUMENTS

The following table summarizes the Consolidated Statements of Financial Position location and carrying value of our derivative instruments.

We generally have a policy of entering into individual International Swaps and Derivatives Association, Inc. agreements, or other similar derivative agreements, with the majority of our financial derivative counterparties. These agreements provide for the net settlement of derivative instruments outstanding with specific counterparties in the event of bankruptcy or other significant credit events, and reduce 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.

March 31, 2019	Derivative Instruments Used as Cash Flow Hedges		Derivative Instruments Used as Net Investment 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	—		—		26		26		(26	)	—
Interest rate contracts	7		—		—		7		—		7
Commodity contracts	1		—		171		172		(77	)	95
	8		—		197		205		(103	)	102
Deferred amounts and other assets
Foreign exchange contracts	13		—		37		50		(36	)	14
Interest rate contracts	—		—		—		—		—		—
Commodity contracts	17		—		18		35		(22	)	13
Other contracts	1		—		1		2		—		2
	31		—		56		87		(58	)	29
Accounts payable and other
Foreign exchange contracts	(5	)	—		(501	)	(506	)	26		(480	)
Interest rate contracts	(150	)	—		—		(150	)	—		(150	)
Commodity contracts	—		—		(289	)	(289	)	77		(212	)
Other contracts	—		—		(1	)	(1	)	—		(1	)
	(155	)	—		(791	)	(946	)	103		(843	)
Other long-term liabilities
Foreign exchange contracts	—		(14	)	(1,666	)	(1,680	)	36		(1,644	)
Interest rate contracts	(374	)	—		—		(374	)	—		(374	)
Commodity contracts	—		—		(152	)	(152	)	22		(130	)
Other contracts	—		—		—		—		—		—
	(374	)	(14	)	(1,818	)	(2,206	)	58		(2,148	)
Total net derivative asset/(liability)
Foreign exchange contracts	8		(14	)	(2,104	)	(2,110	)	—		(2,110	)
Interest rate contracts	(517	)	—		—		(517	)	—		(517	)
Commodity contracts	18		—		(252	)	(234	)	—		(234	)
Other contracts	1		—		—		1		—		1
	(490	)	(14	)	(2,356	)	(2,860	)	—		(2,860	)

December 31, 2018	Derivative Instruments Used as Cash Flow Hedges		Derivative Instruments Used as Net Investment 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	—		—		47		47		(37	)	10
Interest rate contracts	22		—		—		22		(2	)	20
Commodity contracts	2		—		427		429		(114	)	315
	24		—		474		498		(153	)	345
Deferred amounts and other assets
Foreign exchange contracts	23		—		39		62		(39	)	23
Interest rate contracts	5		—		—		5		—		5
Commodity contracts	19		—		33		52		(21	)	31
	47		—		72		119		(60	)	59
Accounts payable and other
Foreign exchange contracts	(5	)	—		(610	)	(615	)	37		(578	)
Interest rate contracts	(163	)	—		(178	)	(341	)	2		(339	)
Commodity contracts	—		—		(273	)	(273	)	114		(159	)
Other contracts	(1	)	—		(4	)	(5	)	—		(5	)
	(169	)	—		(1,065	)	(1,234	)	153		(1,081	)
Other long-term liabilities
Foreign exchange contracts	(1	)	(15	)	(2,196	)	(2,212	)	39		(2,173	)
Interest rate contracts	(201	)	—		—		(201	)	—		(201	)
Commodity contracts	—		—		(178	)	(178	)	21		(157	)
Other contracts	(1	)	—		(1	)	(2	)	—		(2	)
	(203	)	(15	)	(2,375	)	(2,593	)	60		(2,533	)
Total net derivative asset/(liability)
Foreign exchange contracts	17		(15	)	(2,720	)	(2,718	)	—		(2,718	)
Interest rate contracts	(337	)	—		(178	)	(515	)	—		(515	)
Commodity contracts	21		—		9		30		—		30
Other contracts	(2	)	—		(5	)	(7	)	—		(7	)
	(301	)	(15	)	(2,894	)	(3,210	)	—		(3,210	)

The following table summarizes the maturity and notional principal or quantity outstanding related to our derivative instruments.

March 31, 2019	2019		2020		2021		2022		2023		Thereafter1
Foreign exchange contracts - United States dollar forwards - purchase (millions of United States dollars)	895		1		—		—		—		—
Foreign exchange contracts - United States dollar forwards - sell (millions of United States dollars)	3,839		4,893		3,608		1,944		1,804		1,856
Foreign exchange contracts - British pound (GBP) forwards - sell (millions of GBP)	86		25		27		28		29		120
Foreign exchange contracts - Euro forwards - purchase (millions of Euro)	168		—		—		—		—		—
Foreign exchange contracts - Euro forwards - sell (millions of Euro)	—		23		94		94		92		606
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)	6,629		6,178		4,142		407		48		156
Interest rate contracts - long-term receive fixed rate (millions of Canadian dollars)	—		—		—		—		—		—
Interest rate contracts - long-term debt pay fixed rate (millions of Canadian dollars)	2,537		3,142		1,584		—		—		—
Equity contracts (millions of Canadian dollars)	32		20		—		—		—		—
Commodity contracts - natural gas (billions of cubic feet)	(75	)	(15	)	—		(84	)	1		—
Commodity contracts - crude oil (millions of barrels)	4		(2	)	—		—		—		—
Commodity contracts - NGL (millions of barrels)	1		—		—		—		—		—
Commodity contracts - power (megawatt per hour) (MW/H))	98		80		(3	)	(43	)	(43	)	(43	)

1 As at March 31, 2019, thereafter includes an average net purchase/(sell) of power of (43) MW/H for 2024 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 March 31,
	2019		2018
(millions of Canadian dollars)
Amount of unrealized gain/(loss) recognized in OCI
Cash flow hedges
Foreign exchange contracts	(10	)	21
Interest rate contracts	(296	)	100
Commodity contracts	(3	)	(2	)
Other contracts	12		(14	)
Net investment hedges
Foreign exchange contracts	1		16
	(296	)	121
Amount of (gain)/loss reclassified from AOCI to earnings
Foreign exchange contracts1	2		(1	)
Interest rate contracts2	32		40
Commodity contracts3	—		(1	)
Other contracts4	(9	)	9
	25		47

1 Reported within Transportation and other services revenues and Net foreign currency gain/(loss) in the Consolidated Statements of Earnings.

2 Reported within Interest expense in the Consolidated Statements of Earnings. Effective January 1, 2019 hedge ineffectiveness will no longer be measured or recorded. See Note 2 Changes in Accounting Policies.

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 $36 million of AOCI related to unrealized cash flow hedges will be reclassified to earnings in the next 12 months. Actual amounts reclassified to earnings depend on the foreign exchange rates, interest rates and commodity prices in effect when derivative contracts that are currently outstanding mature. For all forecasted transactions, the maximum term over which we are hedging exposures to the variability of cash flows is 33 months as at March 31, 2019.

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.

	Three months ended March 31,
	20191	2018
(millions of Canadian dollars)
Unrealized gain/(loss) on derivative	—	(8	)
Unrealized gain/(loss) on hedged item	—	8
Realized gain/(loss) on derivative	—	(3	)
Realized gain/(loss) on hedged item	—	3

1. For the three months ended March 31, 2019, there are no outstanding fair value hedges.

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 March 31,
	2019		2018
(millions of Canadian dollars)
Foreign exchange contracts1	616		(424	)
Interest rate contracts2	178		(2	)
Commodity contracts3	(261	)	175
Other contracts4	5		(9	)
Total unrealized derivative fair value gain/(loss), net	538		(260	)

1 For the respective three months ended periods, reported within Transportation and other services revenues (2019 - $352 million gain; 2018 - $297 million loss) and Net foreign currency gain/(loss) (2019 - $264 million gain; 2018 - $127 million loss) in the Consolidated Statements of Earnings.

2 Reported as an (increase)/decrease within Interest expense in the Consolidated Statements of Earnings.

3 For the respective three months ended periods, reported within Transportation and other services revenues (2019 - $26 million loss; 2018 - $1 million loss), Commodity sales (2019 - $642 million loss; 2018 - $82 million gain), Commodity costs (2019 - $398 million gain; 2018 - $84 million gain) and Operating and administrative expense (2019 - $9 million gain; 2018 - $10 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 March 31, 2019. As a result, all credit facilities are available to us and the banks are obligated to fund and have been funding us under the terms of the facilities.

CREDIT RISK

Entering into derivative instruments may result in exposure to credit risk from the possibility that a counterparty will default on its contractual obligations. In order to mitigate this risk, we enter into risk management transactions primarily with institutions that possess strong investment grade credit ratings. Credit risk relating to derivative counterparties is mitigated through maintenance and monitoring of credit exposure limits and contractual requirements, netting arrangements, and ongoing monitoring of counterparty credit exposure using external credit rating services and other analytical tools.

We have credit concentrations and credit exposure, with respect to derivative instruments, in the following counterparty segments:

	March 31, 2019	December 31, 2018
(millions of Canadian dollars)
Canadian financial institutions	21	28
United States financial institutions	51	107
European financial institutions	58	84
Asian financial institutions	—	6
Other1	132	337
	262	562

1 Other is comprised of commodity clearing house and physical natural gas and crude oil counterparties.

As at March 31, 2019, we provided letters of credit totaling nil in lieu of providing cash collateral to our counterparties pursuant to the terms of the relevant International Swaps and Derivatives Association (ISDA) agreements. We held no cash collateral on derivative asset exposures as at March 31, 2019 and December 31, 2018.

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 EGI, credit risk is mitigated by the utilities' large and diversified customer base and the ability to recover an estimate for doubtful accounts through the ratemaking process. We actively monitor the financial strength of large industrial customers, and in select cases, have obtained additional security to minimize the risk of default on receivables. Generally, we classify and provide for receivables older than 30 days as past due. The maximum exposure to credit risk related to non-derivative financial assets is their carrying value.

FAIR VALUE MEASUREMENTS

Our financial assets and liabilities measured at fair value on a recurring basis include derivative instruments. We also disclose the fair value of other financial instruments not measured at fair value. The fair value of financial instruments reflects our best estimates of market value based on generally accepted valuation techniques or models and is supported by observable market prices and rates. When such values are not available, we use discounted cash flow analysis from applicable yield curves based on observable market inputs to estimate fair value.

FAIR VALUE OF FINANCIAL INSTRUMENTS

We categorize our derivative instruments measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement.

Level 1

Level 1 includes derivatives measured at fair value based on unadjusted quoted prices for identical assets and liabilities in active markets that are accessible at the measurement date. An active market for a derivative is considered to be a market where transactions occur with sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 instruments consist primarily of exchange-traded derivatives used to mitigate the risk of crude oil price fluctuations.

Level 2

Level 2 includes derivative valuations determined using directly or indirectly observable inputs other than quoted prices included within Level 1. Derivatives in this category are valued using models or other industry standard valuation techniques derived from observable market data. Such valuation techniques include inputs such as quoted forward prices, time value, volatility factors and broker quotes that can be observed or corroborated in the market for the entire duration of the derivative. Derivatives valued using Level 2 inputs include non-exchange traded derivatives such as over-the-counter foreign exchange forward and cross currency swap contracts, interest rate swaps, physical forward commodity contracts, as well as commodity swaps and options for which observable inputs can be obtained.

We have also categorized the fair value of our held to maturity preferred share investment and long-term debt as Level 2. The fair value of our held to maturity preferred share investment is primarily based on the yield of certain Government of Canada bonds. The fair value of our long-term debt is based on quoted market prices for instruments of similar yield, credit risk and tenor.

Level 3

Level 3 includes derivative valuations based on inputs which are less observable, unavailable or where the observable data does not support a significant portion of the derivatives’ fair value. Generally, Level 3 derivatives are longer dated transactions, occur in less active markets, occur at locations where pricing information is not available or have no binding broker quote to support Level 2 classification. We have developed methodologies, benchmarked against industry standards, to determine fair value for these derivatives based on extrapolation of observable future prices and rates. Derivatives valued using Level 3 inputs primarily include long-dated derivative power contracts and NGL and natural gas contracts, basis swaps, commodity swaps, power and energy swaps, as well as options. We do not have any other financial instruments categorized in Level 3.

We use the most observable inputs available to estimate the fair value of our derivatives. When possible, we estimate the fair value of our derivatives based on quoted market prices. If quoted market prices are not available, we use estimates from third party brokers. For non-exchange traded derivatives classified in Levels 2 and 3, we use standard valuation techniques to calculate the estimated fair value. These methods include discounted cash flows for forwards and swaps and Black-Scholes-Merton pricing models for options. Depending on the type of derivative and nature of the underlying risk, we use observable market prices (interest, foreign exchange, commodity and share price) and volatility as primary inputs to these valuation techniques. Finally, we consider our own credit default swap spread as well as the credit default swap spreads associated with our counterparties in our estimation of fair value.

We have categorized our derivative assets and liabilities measured at fair value as follows:

March 31, 2019	Level 1		Level 2		Level 3		Total Gross Derivative Instruments
(millions of Canadian dollars)
Financial assets
Current derivative assets
Foreign exchange contracts	—		26		—		26
Interest rate contracts	—		7		—		7
Commodity contracts	3		10		159		172
	3		43		159		205
Long-term derivative assets
Foreign exchange contracts	—		50		—		50
Commodity contracts	—		13		22		35
Other contracts	—		2		—		2
	—		65		22		87
Financial liabilities
Current derivative liabilities
Foreign exchange contracts	—		(506	)	—		(506	)
Interest rate contracts	—		(150	)	—		(150	)
Commodity contracts	(7	)	(16	)	(266	)	(289	)
Other contracts	—		(1	)	—		(1	)
	(7	)	(673	)	(266	)	(946	)
Long-term derivative liabilities
Foreign exchange contracts	—		(1,680	)	—		(1,680	)
Interest rate contracts	—		(374	)	—		(374	)
Commodity contracts	—		(15	)	(137	)	(152	)
	—		(2,069	)	(137	)	(2,206	)
Total net financial liabilities
Foreign exchange contracts	—		(2,110	)	—		(2,110	)
Interest rate contracts	—		(517	)	—		(517	)
Commodity contracts	(4	)	(8	)	(222	)	(234	)
Other contracts	—		1		—		1
	(4	)	(2,634	)	(222	)	(2,860	)

December 31, 2018	Level 1		Level 2		Level 3		Total Gross Derivative Instruments
(millions of Canadian dollars)
Financial assets
Current derivative assets
Foreign exchange contracts	—		47		—		47
Interest rate contracts	—		22		—		22
Commodity contracts	24		45		360		429
	24		114		360		498
Long-term derivative assets
Foreign exchange contracts	—		62		—		62
Interest rate contracts	—		5		—		5
Commodity contracts	—		30		22		52
	—		97		22		119
Financial liabilities
Current derivative liabilities
Foreign exchange contracts	—		(615	)	—		(615	)
Interest rate contracts	—		(341	)	—		(341	)
Commodity contracts	(7	)	(28	)	(238	)	(273	)
Other contracts	—		(5	)	—		(5	)
	(7	)	(989	)	(238	)	(1,234	)
Long-term derivative liabilities
Foreign exchange contracts	—		(2,212	)	—		(2,212	)
Interest rate contracts	—		(201	)	—		(201	)
Commodity contracts	—		(23	)	(155	)	(178	)
Other contracts	—		(2	)	—		(2	)
	—		(2,438	)	(155	)	(2,593	)
Total net financial liabilities
Foreign exchange contracts	—		(2,718	)	—		(2,718	)
Interest rate contracts	—		(515	)	—		(515	)
Commodity contracts	17		24		(11	)	30
Other contracts	—		(7	)	—		(7	)
	17		(3,216	)	(11	)	(3,210	)

The significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments were as follows:

March 31, 2019	Fair Value		Unobservable Input	Minimum Price	Maximum Price	Weighted Average Price	Unit of Measurement
(fair value in millions of Canadian dollars)
Commodity contracts - financial1
Natural gas	(18	)	Forward gas price	2.55	5.17	3.47	$/mmbtu2
Crude	38		Forward crude price	42.96	166.19	69.21	$/barrel
Power	(82	)	Forward power price	30.79	71.28	50.21	$/MW/H
Commodity contracts - physical1
Natural gas	(125	)	Forward gas price	1.22	5.17	2.25	$/mmbtu2
Crude	(37	)	Forward crude price	33.12	127.36	76.83	$/barrel
NGL	2		Forward NGL price	0.17	1.11	0.37	$/gallon
	(222	)

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:

	Three months ended March 31,
	2019		2018
(millions of Canadian dollars)
Level 3 net derivative liability at beginning of period	(11	)	(387	)
Total gain/(loss)
Included in earnings1	(52	)	31
Included in OCI	(3	)	(3	)
Settlements	(156	)	154
Level 3 net derivative liability at end of period	(222	)	(205	)

1 Reported within Transportation and other services revenues, Commodity costs and Operating and administrative expense in the Consolidated Statements of Earnings.

Our policy is to recognize transfers as at the last day of the reporting period. There were no transfers between levels as at March 31, 2019 or December 31, 2018.

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 (if any), plus or minus changes resulting from observable price changes in orderly transactions for an identical or similar investment of the same issuer. The carrying value of FVMA other long-term investments totaled $101 million and $102 million as at March 31, 2019 and December 31, 2018, respectively.

We have Restricted long-term investments held in trust totaling $356 million and $323 million as at March 31, 2019 and December 31, 2018, respectively, which are recognized at fair value.

We have a held to maturity preferred share investment carried at its amortized cost of $582 million and $478 million as at March 31, 2019 and December 31, 2018, respectively. These preferred shares are entitled to a cumulative preferred dividend based on the yield of 10-year Government of Canada bonds plus a margin of 4.38%. The fair value of this preferred share investment approximates its face value of $582 million and $580 million as at March 31, 2019 and December 31, 2018 respectively.

As at March 31, 2019 and December 31, 2018, our long-term debt had a carrying value of $65.3 billion and $63.9 billion, respectively, before debt issuance costs and a fair value of $68.9 billion and $64.4 billion, respectively. We also have noncurrent notes receivable carried at book value recorded in Deferred amounts and other assets in the Consolidated Statements of Financial Position. As at March 31, 2019 and December 31, 2018, the noncurrent notes receivable had a carrying value of $95 million and $97 million, respectively, and a fair value of $95 million and $97 million, respectively.

The fair value of other financial assets and liabilities other than derivative instruments, other long-term investments, restricted long-term investments, long-term debt and non-current notes receivable described above approximate their cost due to the short period to maturity.

NET INVESTMENT HEDGES

We have designated a portion of our United States dollar denominated debt, as well as a portfolio of foreign exchange forward contracts, as a hedge of our net investment in United States dollar denominated investments and subsidiaries.

During the three months ended March 31, 2019 and 2018, we recognized an unrealized foreign exchange gain of $108 million and an unrealized foreign exchange loss of $194 million, respectively, on the translation of United States dollar denominated debt and unrealized gains of $1 million and $15 million, respectively, on the change in fair value of our outstanding foreign exchange forward contracts in OCI. During the three months ended March 31, 2019 and 2018, we recognized realized losses of nil and $23 million, respectively, in OCI associated with the settlement of foreign exchange forward contracts and recognized realized losses of nil and $11 million, respectively, in OCI associated with the settlement of United States dollar denominated debt that had matured during the period. There was no ineffectiveness during the three months ended March 31, 2019 and 2018.

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INCOME TAXES

3 Months Ended

Mar. 31, 2019

Income Tax Disclosure [Abstract]

INCOME TAXES

INCOME TAXES The effective income tax rates for the three months ended March 31, 2019 and 2018 were 22.4% and (16.7)%, respectively. The period-over-period increase in the effective income tax rate is due to the effects of rate-regulated accounting for income taxes and other permanent items relative to the increase in earnings for the three months ended March 31, 2019. Also contributing to the period-over-period increase in the effective income tax rate was the buy-in of our United States sponsored vehicles which results in Enbridge being taxed on all of our United States sponsored vehicle earnings rather than on just our proportionate share.

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PENSION AND OTHER POSTRETIREMENT BENEFITS

3 Months Ended

Mar. 31, 2019

Retirement Benefits [Abstract]

PENSION AND OTHER POSTRETIREMENT BENEFITS

PENSION AND OTHER POSTRETIREMENT BENEFITS

	Three months ended March 31,
	2019		2018
(millions of Canadian dollars)
Service cost	51		65
Interest cost	51		45
Expected return on plan assets	(84	)	(82	)
Amortization of actuarial loss	8		7
Amortization of prior service costs	(1	)	(1	)
Net periodic benefit costs	25		34

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LEASES

3 Months Ended

Mar. 31, 2019

Leases [Abstract]

LEASES

LEASES

We incur operating lease expense related primarily to real estate, pipelines, storage and equipment. Our operating leases have remaining lease terms of one month to 29 years.

For the three months ended March 31, 2019, we incurred operating lease expenses of $28 million. Operating lease expenses are reported under Operating and administrative expenses on the Consolidated Statements of Earnings.

For the three months ended March 31, 2019, operating lease payments to settle lease liabilities were $31 million. Operating lease payments are reported under operating activities in the Consolidated Statements of Cash Flows.

Supplemental Statements of Financial Position Information

	March 31, 2019		January 1, 2019
(millions of Canadian dollars, except lease term and discount rate)
Operating leases
Operating lease right-of-use assets, net1	745		771
Operating lease liabilities - current2	67		86
Operating lease liabilities - long-term3	757		770
Total operating lease liabilities	824		856
Weighted average remaining lease term
Operating leases	14 years		14 years
Weighted average discount rate
Operating leases	4.3	%	4.3	%

1 Right-of-use assets are reported under Deferred amounts and other assets in the Consolidated Statements of Financial Position.

2 Current lease liabilities are reported under Accounts payable and other in the Consolidated Statements of Financial Position.

3 Long-term lease liabilities are reported under Other long-term liabilities in the Consolidated Statements of Financial Position.

As at March 31, 2019, we have operating lease commitments as detailed below:

	Operating leases
(millions of Canadian dollars)
20191	83
2020	116
2021	94
2022	89
2023	79
Thereafter	663
Total undiscounted lease payments	1,124
Less imputed interest	(300	)
Total operating lease commitments	824

1 For the nine months remaining in the 2019 fiscal year.

LESSOR

We have operating leases primarily related to natural gas and crude oil storage and processing facilities, rail cars, and wind power generation assets. Our leases have remaining lease terms of 9 months to 24 years.

	Three months ended March 31, 2019
(millions of Canadian dollars)
Operating lease income	64
Variable lease income	100
Total lease income	164

The following table sets out future minimum lease payments expected to be received under lease contracts where we are the lessor:

	Operating leases
(millions of Canadian dollars)
20191	192
2020	216
2021	189
2022	186
2023	178
Thereafter	2,395
Total undiscounted lease payments	3,356

1

For the nine months remaining in the 2019 fiscal year.

LEASES

LEASES

We incur operating lease expense related primarily to real estate, pipelines, storage and equipment. Our operating leases have remaining lease terms of one month to 29 years.

For the three months ended March 31, 2019, we incurred operating lease expenses of $28 million. Operating lease expenses are reported under Operating and administrative expenses on the Consolidated Statements of Earnings.

For the three months ended March 31, 2019, operating lease payments to settle lease liabilities were $31 million. Operating lease payments are reported under operating activities in the Consolidated Statements of Cash Flows.

Supplemental Statements of Financial Position Information

	March 31, 2019		January 1, 2019
(millions of Canadian dollars, except lease term and discount rate)
Operating leases
Operating lease right-of-use assets, net1	745		771
Operating lease liabilities - current2	67		86
Operating lease liabilities - long-term3	757		770
Total operating lease liabilities	824		856
Weighted average remaining lease term
Operating leases	14 years		14 years
Weighted average discount rate
Operating leases	4.3	%	4.3	%

1 Right-of-use assets are reported under Deferred amounts and other assets in the Consolidated Statements of Financial Position.

2 Current lease liabilities are reported under Accounts payable and other in the Consolidated Statements of Financial Position.

3 Long-term lease liabilities are reported under Other long-term liabilities in the Consolidated Statements of Financial Position.

As at March 31, 2019, we have operating lease commitments as detailed below:

	Operating leases
(millions of Canadian dollars)
20191	83
2020	116
2021	94
2022	89
2023	79
Thereafter	663
Total undiscounted lease payments	1,124
Less imputed interest	(300	)
Total operating lease commitments	824

1 For the nine months remaining in the 2019 fiscal year.

LESSOR

We have operating leases primarily related to natural gas and crude oil storage and processing facilities, rail cars, and wind power generation assets. Our leases have remaining lease terms of 9 months to 24 years.

	Three months ended March 31, 2019
(millions of Canadian dollars)
Operating lease income	64
Variable lease income	100
Total lease income	164

The following table sets out future minimum lease payments expected to be received under lease contracts where we are the lessor:

	Operating leases
(millions of Canadian dollars)
20191	192
2020	216
2021	189
2022	186
2023	178
Thereafter	2,395
Total undiscounted lease payments	3,356

1

For the nine months remaining in the 2019 fiscal year.

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CONTINGENCIES

3 Months Ended

Mar. 31, 2019

Loss Contingency [Abstract]

CONTINGENCIES

CONTINGENCIES

We and our subsidiaries 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 and our subsidiaries maintain tax liabilities related to uncertain tax positions. While fully supportable in our view, these tax positions, if challenged by tax authorities, may not be fully sustained on review.

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CONDENSED CONSOLIDATING FINANCIAL INFORMATION

3 Months Ended

Mar. 31, 2019

Condensed Financial Information Disclosure [Abstract]

CONDENSED CONSOLIDATING FINACIAL INFORMATION

CONDENSED CONSOLIDATING FINANCIAL INFORMATION

On January 22, 2019, Enbridge entered into supplemental indentures with its wholly-owned subsidiaries, the Partnerships, pursuant to which Enbridge fully and unconditionally guaranteed, on a senior unsecured basis, the payment obligations of the Partnerships with respect to the outstanding series of notes issued under the respective indentures of the Partnerships. Concurrently, the Partnerships entered into a subsidiary guarantee agreement pursuant to which they guaranteed, on a senior unsecured basis, the outstanding series of senior notes of Enbridge. As a result of the guarantees, holders of any of the outstanding guaranteed notes of the Partnerships are in the same position with respect to the net assets, income and cash flows of Enbridge as holders of Enbridge's outstanding guaranteed notes, and vice versa. Other than the Partnerships, Enbridge subsidiaries (including the subsidiaries of the Partnerships, collectively, the Subsidiary Non-Guarantors), are not parties to the subsidiary guarantee agreement and have not otherwise guaranteed any of Enbridge's outstanding series of senior notes.

Consenting SEP notes and EEP notes under Guarantee

SEP Notes1	EEP Notes2
Floating Rate Senior Notes due 2020	5.200% Notes due 2020
4.600% Senior Notes due 2021	4.375% Notes due 2020
4.750% Senior Notes due 2024	4.200% Notes due 2021
3.500% Senior Notes due 2025	5.875% Notes due 2025
3.375% Senior Notes due 2026	5.950% Notes due 2033
5.950% Senior Notes due 2043	6.300% Notes due 2034
4.500% Senior Notes due 2045	7.500% Notes due 2038
	5.500% Notes due 2040
	7.375% Notes due 2045

1 As at March 31, 2019, the aggregate outstanding principal amount of SEP notes was approximately US$3.9 billion.

2 As at March 31, 2019, the aggregate outstanding principal amount of EEP notes was approximately US$4.0 billion.

Enbridge Notes under Guarantees

USD Denominated1	CAD Denominated2
Senior Floating Rate Notes due 2020	Senior Floating Rate Notes due 2019
Senior Floating Rate Notes due 2020	4.770% Senior Notes due 2019
2.900% Senior Notes due 2022	4.530% Senior Notes due 2020
4.000% Senior Notes due 2023	4.850% Senior Notes due 2020
3.500% Senior Notes due 2024	4.260% Senior Notes due 2021
4.250% Senior Notes due 2026	3.160% Senior Notes due 2021
3.700% Senior Notes due 2027	4.850% Senior Notes due 2022
4.500% Senior Notes due 2044	3.190% Senior Notes due 2022
5.500% Senior Notes due 2046	3.940% Senior Notes due 2023
	3.940% Senior Notes due 2023
	3.950% Senior Notes due 2024
	3.200% Senior Notes due 2027
	6.100% Senior Notes due 2028
	7.220% Senior Notes due 2030
	7.200% Senior Notes due 2032
	5.570% Senior Notes due 2035
	5.750% Senior Notes due 2039
	5.120% Senior Notes due 2040
	4.240% Senior Notes due 2042
	4.570% Senior Notes due 2044
	4.870% Senior Notes due 2044
	4.560% Senior Notes due 2064

1 As at March 31, 2019, the aggregate outstanding principal amount of the Enbridge United States dollar denominated notes was approximately US$5.9 billion.

2 As at March 31, 2019, the aggregate outstanding principal amount of the Enbridge Canadian dollar denominated notes was approximately $7.8 billion.

In accordance with Rule 3-10 of the SEC's Regulation S-X, which provides an exemption from the reporting requirements of the Securities Exchange Act of 1934 for subsidiary issuers of guaranteed securities and subsidiary guarantors, in lieu of filing separate financial statements for each of the Partnerships, we have included the accompanying condensed consolidating financial information with separate columns representing the following:

1. Enbridge Inc., the Parent Issuer and Guarantor;

2. SEP, a Subsidiary Issuer and Guarantor;

3. EEP, a Subsidiary Issuer and Guarantor;

4. Subsidiary Non-Guarantors, as defined herein;

5. Consolidating and elimination entries required to consolidate the Parent Issuer and Guarantor and its subsidiaries, including the Subsidiary Issuers and Guarantors, and

6. Enbridge Inc. and subsidiaries on a consolidated basis.

For the purposes of the condensed consolidating financial information only, investments in subsidiaries are accounted for under the equity method. In addition, the Condensed Consolidating Statements of Cash Flows present the intercompany loan and distribution activity, as well as cash collection and payments made on behalf of our subsidiaries, as cash activities. These intercompany investments and related activities eliminate on consolidation and are presented separately only for the purpose of the accompanying Condensed Consolidating Statements.

Condensed Consolidating Statements of Earnings and Comprehensive Income for the three months ended March 31, 2019

	Parent Issuer and Guarantor		Subsidiary Issuer and Guarantor - SEP		Subsidiary Issuer and Guarantor - EEP		Subsidiary Non-Guarantors		Consolidating and elimination adjustments		Consolidated - Enbridge
(millions of Canadian dollars)
Operating revenues
Commodity sales	—		—		—		6,632		—		6,632
Gas distribution sales	—		—		—		1,876		—		1,876
Transportation and other services	—		—		—		4,348		—		4,348
Total operating revenues	—		—		—		12,856		—		12,856
Operating Expenses
Commodity costs	—		—		—		6,565		—		6,565
Gas distribution costs	—		—		—		1,207		—		1,207
Operating and administrative	(34	)	2		1		1,656		—		1,625
Depreciation and amortization	15		—		—		825		—		840
Total operating expenses	(19	)	2		1		10,253		—		10,237
Operating income/(loss)	19		(2	)	(1	)	2,603		—		2,619
Income/(loss) from equity investments	59		31		—		382		(59	)	413
Equity earnings from consolidated subsidiaries	774		398		263		493		(1,928	)	—
Other
Net foreign currency gain/(loss)	1,221		—		—		(103	)	(904	)	214
Other, including other income from affiliates	330		—		41		123		(448	)	46
Interest expense	(308	)	(94	)	(158	)	(583	)	458		(685	)
Earnings before income taxes	2,095		333		145		2,915		(2,881	)	2,607
Income tax expense	(109	)	15		—		(596	)	106		(584	)
Earnings	1,986		348		145		2,319		(2,775	)	2,023
Earnings attributable to noncontrolling interests and redeemable noncontrolling interests	—		—		—		—		(37	)	(37	)
Earnings attributable to controlling interests	1,986		348		145		2,319		(2,812	)	1,986
Preference share dividends	(95	)	—		—		—		—		(95	)
Earnings attributable to common shareholders	1,891		348		145		2,319		(2,812	)	1,891
Earnings	1,986		348		145		2,319		(2,775	)	2,023
Total other comprehensive income/(loss)	(1,278	)	(16	)	15		(720	)	671		(1,328	)
Comprehensive income	708		332		160		1,599		(2,104	)	695
Comprehensive loss attributable to noncontrolling interests	—		—		—		—		13		13
Comprehensive income attributable to controlling interests	708		332		160		1,599		(2,091	)	708

Condensed Consolidating Statements of Earnings and Comprehensive Income for the three months ended March 31, 2018

	Parent Issuer and Guarantor		Subsidiary Issuer and Guarantor - SEP		Subsidiary Issuer and Guarantor - EEP		Subsidiary Non-Guarantors		Consolidating and elimination adjustments		Consolidated - Enbridge
(millions of Canadian dollars)
Operating revenues
Commodity sales	—		—		—		7,268		—		7,268
Gas distribution sales	—		—		—		1,926		—		1,926
Transportation and other services	—		—		—		3,532		—		3,532
Total operating revenues	—		—		—		12,726		—		12,726
Operating Expenses
Commodity costs	—		—		—		6,997		—		6,997
Gas distribution costs	—		—		—		1,324		—		1,324
Operating and administrative	67		1		4		1,569		—		1,641
Depreciation and amortization	14		—		—		810		—		824
Impairment of long-lived assets	—		—		—		1,062		—		1,062
Total operating expenses	81		1		4		11,762		—		11,848
Operating income/(loss)	(81	)	(1	)	(4	)	964		—		878
Income from equity investments	17		34		—		300		(16	)	335
Equity earnings from consolidated subsidiaries	707		551		203		608		(2,069	)	—
Other
Net foreign currency gain/(loss)	(199	)	2		—		(58	)	70		(185	)
Other, including other income/(expense) from affiliates	246		1		30		39		(251	)	65
Interest expense	(243	)	(72	)	(136	)	(479	)	274		(656	)
Earnings before income taxes	447		515		93		1,374		(1,992	)	437
Income tax recovery/(expense)	87		—		—		(23	)	9		73
Earnings	534		515		93		1,351		(1,983	)	510
Earnings attributable to noncontrolling interests and redeemable noncontrolling interests	—		—		—		—		24		24
Earnings attributable to controlling interests	534		515		93		1,351		(1,959	)	534
Preference share dividends	(89	)	—		—		—		—		(89	)
Earnings attributable to common shareholders	445		515		93		1,351		(1,959	)	445
Earnings	534		515		93		1,351		(1,983	)	510
Total other comprehensive income	1,302		19		8		253		(109	)	1,473
Comprehensive income	1,836		534		101		1,604		(2,092	)	1,983
Comprehensive income attributable to noncontrolling interests	—		—		—		—		(147	)	(147	)
Comprehensive income attributable to controlling interests	1,836		534		101		1,604		(2,239	)	1,836

Condensed Consolidating Statements of Financial Position as at March 31, 2019

	Parent Issuer and Guarantor	Subsidiary Issuer and Guarantor - SEP	Subsidiary Issuer and Guarantor - EEP	Subsidiary Non-Guarantors		Consolidating and elimination adjustments		Consolidated - Enbridge
(millions of Canadian dollars)
Assets
Current assets
Cash and cash equivalents	—	5	7	690		—		702
Restricted cash	9	—	—	46		—		55
Accounts receivable and other	283	1	—	6,202		—		6,486
Accounts receivable from affiliates	586	—	31	79		(604	)	92
Short-term loans receivable from affiliates	3,527	—	3,838	5,871		(13,236	)	—
Inventory	—	—	—	1,047		—		1,047
	4,405	6	3,876	13,935		(13,840	)	8,382
Property, plant and equipment, net	166	—	—	93,709		—		93,875
Long-term loans receivable from affiliates	26,504	73	2,472	15,524		(44,573	)	—
Investments in subsidiaries	78,271	19,741	6,209	15,032		(119,253	)	—
Long-term investments	4,619	961	—	14,890		(3,568	)	16,902
Restricted long-term investments	—	—	—	356		—		356
Deferred amounts and other assets	1,491	1	8	9,412		(1,407	)	9,505
Intangible assets, net	219	—	—	2,082		—		2,301
Goodwill	—	—	—	33,895		—		33,895
Deferred income taxes	744	—	—	220		328		1,292
Total assets	116,419	20,782	12,565	199,055		(182,313	)	166,508
Liabilities and equity
Current liabilities
Short-term borrowings	—	—	—	870		—		870
Accounts payable and other	756	19	14	6,552		(10	)	7,331
Accounts payable to affiliates	935	509	80	(891	)	(603	)	30
Interest payable	227	25	92	229		—		573
Short-term loans payable to affiliates	426	2,985	2,458	7,367		(13,236	)	—
Current portion of long-term debt	2,979	—	668	674		—		4,321
	5,323	3,538	3,312	14,801		(13,849	)	13,125
Long-term debt	23,519	5,095	4,565	27,501		—		60,680
Other long-term liabilities	2,145	8	22	8,276		(1,407	)	9,044
Long-term loans payable to affiliates	15,076	—	1,470	28,027		(44,573	)	—
Deferred income taxes	—	304	—	13,821		(4,385	)	9,740
	46,063	8,945	9,369	92,426		(64,214	)	92,589
Equity
Controlling interests1	70,356	11,837	3,196	106,629		(121,713	)	70,305
Noncontrolling interests	—	—	—	—		3,614		3,614
	70,356	11,837	3,196	106,629		(118,099	)	73,919
Total liabilities and equity	116,419	20,782	12,565	199,055		(182,313	)	166,508

1 Equity attributable to controlling interests for parent issuer and guarantor excludes reciprocal shareholding balance included within consolidating and elimination adjustments.

Condensed Consolidating Statements of Financial Position as at December 31, 2018

	Parent Issuer and Guarantor	Subsidiary Issuer and Guarantor - SEP	Subsidiary Issuer and Guarantor - EEP	Subsidiary Non-Guarantors		Consolidating and elimination adjustments		Consolidated - Enbridge
(millions of Canadian dollars)
Assets
Current assets
Cash and cash equivalents	—	16	—	502		—		518
Restricted cash	9	—	—	110		—		119
Accounts receivable and other	283	15	8	6,211		—		6,517
Accounts receivable from affiliates	726	—	13	(142	)	(518	)	79
Short-term loans receivable from affiliates	3,943	—	3,689	653		(8,285	)	—
Inventory	—	—	—	1,339		—		1,339
	4,961	31	3,710	8,673		(8,803	)	8,572
Property, plant and equipment, net	140	—	—	94,400		—		94,540
Long-term loans receivable from affiliates	10,318	73	2,539	1,344		(14,274	)	—
Investments in subsidiaries	78,474	19,777	6,363	15,567		(120,181	)	—
Long-term investments	4,561	987	—	14,841		(3,682	)	16,707
Restricted long-term investments	—	—	—	323		—		323
Deferred amounts and other assets	1,700	9	17	8,558		(1,726	)	8,558
Intangible assets, net	234	—	—	2,138		—		2,372
Goodwill	—	—	—	34,459		—		34,459
Deferred income taxes	817	—	—	229		328		1,374
Total assets	101,205	20,877	12,629	180,532		(148,338	)	166,905
Liabilities and equity
Current liabilities
Short-term borrowings	—	—	—	1,024		—		1,024
Accounts payable and other	2,742	7	34	7,086		(6	)	9,863
Accounts payable to affiliates	946	233	56	(677	)	(518	)	40
Interest payable	283	56	105	225		—		669
Short-term loans payable to affiliates	426	682	—	7,177		(8,285	)	—
Current portion of long-term debt	1,853	—	683	723		—		3,259
	6,250	978	878	15,558		(8,809	)	14,855
Long-term debt	22,893	7,276	6,943	23,215		—		60,327
Other long-term liabilities	2,428	2	30	8,100		(1,726	)	8,834
Long-term loans payable to affiliates	76	—	1,502	12,696		(14,274	)	—
Deferred income taxes	—	331	—	13,523		(4,400	)	9,454
	31,647	8,587	9,353	73,092		(29,209	)	93,470
Equity
Controlling interests1	69,558	12,290	3,276	107,440		(123,094	)	69,470
Noncontrolling interests	—	—	—	—		3,965		3,965
	69,558	12,290	3,276	107,440		(119,129	)	73,435
Total liabilities and equity	101,205	20,877	12,629	180,532		(148,338	)	166,905

1 Equity attributable to controlling interests for parent issuer and guarantor excludes reciprocal shareholding balance included within consolidating and elimination adjustments.

Condensed Consolidating Statements of Cash Flows for the three months ended March 31, 2019

	Parent Issuer and Guarantor		Subsidiary Issuer and Guarantor - SEP		Subsidiary Issuer and Guarantor - EEP		Subsidiary Non-Guarantors		Consolidating and elimination adjustments		Consolidated - Enbridge
(millions of Canadian dollars)
Net cash provided by/(used in) operating activities	(415	)	232		(1,418	)	4,566		(789	)	2,176
Investing activities
Capital expenditures	(24	)	—		—		(1,588	)	—		(1,612	)
Long-term investments and restricted long-term investments	—		(2	)	—		(563	)	—		(565	)
Distributions from equity investments in excess of cumulative earnings	—		7		536		132		(536	)	139
Additions to intangible assets	(16	)	—		—		(10	)	—		(26	)
Affiliate loans, net	—		—		—		(84	)	—		(84	)
Contributions to subsidiaries	(2,331	)	—		—		—		2,331		—
Return of share capital from subsidiaries	3,121		—		—		—		(3,121	)	—
Advances to affiliates	(19,908	)	—		(618	)	(21,542	)	42,068		—
Repayment of advances to affiliates	3,996		—		382		1,638		(6,016	)	—
Net cash provided by/(used in) investing activities	(15,162	)	5		300		(22,017	)	34,726		(2,148	)
Financing activities
Net change in short-term borrowings	—		—		—		(154	)	—		(154	)
Net change in commercial paper and credit facility draws	2,312		(2,010	)	—		2,471		—		2,773
Debenture and term note issues, net of issue costs	—		—		—		1,195		—		1,195
Debenture and term note repayments	(300	)	—		(1,189	)	(300	)	—		(1,789	)
Contributions from noncontrolling interests	—		—		—		—		3		3
Distributions to noncontrolling interests	—		—		—		—		(46	)	(46	)
Contributions from parents	—		—		—		2,331		(2,331	)	—
Distributions to parents	—		(505	)	(162	)	(3,822	)	4,489		—
Redemption of preferred shares	—		—		—		(300	)	—		(300	)
Common shares issued	18		—		—		—		—		18
Preference share dividends	(90	)	—		—		—		—		(90	)
Common share dividends	(1,513	)	—		—		27		—		(1,486	)
Advances from affiliates	15,150		3,498		2,894		20,526		(42,068	)	—
Repayment of advances from affiliates	—		(1,226	)	(412	)	(4,378	)	6,016		—
Other	—		(5	)	(6	)	(14	)	—		(25	)
Net cash (used in)/provided by financing activities	15,577		(248	)	1,125		17,582		(33,937	)	99
Effect of translation of foreign denominated cash and cash equivalents and restricted cash	—		—		—		(7	)	—		(7	)
Net increase/(decrease) in cash and cash equivalents and restricted cash	—		(11	)	7		124		—		120
Cash and cash equivalents and restricted cash at beginning of period	9		16		—		612		—		637
Cash and cash equivalents and restricted cash at end of period	9		5		7		736		—		757

Condensed Consolidating Statements of Cash Flows for the three months ended March 31, 2018

	Parent Issuer and Guarantor		Subsidiary Issuer and Guarantor - SEP		Subsidiary Issuer and Guarantor - EEP		Subsidiary Non-Guarantors		Consolidating and elimination adjustments		Consolidated - Enbridge
(millions of Canadian dollars)
Net cash (used in)/provided by operating activities	(135	)	803		(331	)	3,224		(367	)	3,194
Investing activities
Capital expenditures	(5	)	—		—		(1,630	)	—		(1,635	)
Long-term investments and restricted long-term investments	(16	)	(5	)	—		(217	)	16		(222	)
Distributions from equity investments in excess of cumulative earnings	336		15		488		42		(824	)	57
Additions to intangible assets	(6	)	—		—		(252	)	—		(258	)
Affiliate loans, net	—		—		—		(10	)	—		(10	)
Contributions to subsidiaries	(69	)	(77	)	(5	)	—		151		—
Advances to affiliates	(401	)	—		(496	)	(2,233	)	3,130		—
Repayment of advances to affiliates	—		506		548		1,890		(2,944	)	—
Net cash (used in)/provided by investing activities	(161	)	439		535		(2,410	)	(471	)	(2,068	)
Financing activities
Net change in short-term borrowings	—		—		—		(443	)	—		(443	)
Net change in commercial paper and credit facility draws	(105	)	(756	)	(218	)	614		—		(465	)
Debenture and term note issues, net of issue costs	1,080		—		—		981		—		2,061
Debenture and term note repayments	—		—		—		(996	)	—		(996	)
Debt extinguishment costs	—		—		—		(63	)	—		(63	)
Contributions from noncontrolling interests	—		—		—		—		8		8
Distributions to noncontrolling interests	—		—		—		—		(209	)	(209	)
Contributions from redeemable noncontrolling interests	—		—		—		—		20		20
Distributions to redeemable noncontrolling interests	—		—		—		—		(84	)	(84	)
Contributions from parents	—		—		—		151		(151	)	—
Distributions to parents	—		(453	)	(163	)	(824	)	1,440		—
Common shares issued	13		—		—		—		—		13
Preference share dividends	(87	)	—		—		—		—		(87	)
Common share dividends	(764	)	—		—		—		—		(764	)
Advances from affiliates	209		—		2,024		897		(3,130	)	—
Repayment of advances from affiliates	(43	)	—		(1,847	)	(1,054	)	2,944		—
Net cash provided by/(used in) financing activities	303		(1,209	)	(204	)	(737	)	838		(1,009	)
Effect of translation of foreign denominated cash and cash equivalents and restricted cash	—		—		—		19		—		19
Net increase in cash and cash equivalents and restricted cash	7		33		—		96		—		136
Cash and cash equivalents and restricted cash at beginning of period	2		14		—		571		—		587
Cash and cash equivalents and restricted cash at end of period	9		47		—		667		—		723

XML

CHANGES IN ACCOUNTING POLICIES (Policies)

3 Months Ended

Mar. 31, 2019

New Accounting Pronouncements and Changes in Accounting Principles [Abstract]

ADOPTION OF NEW STANDARDS and FUTURE ACCOUNTING POLICY CHANGES

ADOPTION OF NEW STANDARDS

Cloud Computing Arrangements

Effective January 1, 2019, we adopted Accounting Standards Update (ASU) 2018-15 on a prospective basis. The new standard was issued to provide guidance on the accounting for implementation costs incurred in a cloud computing arrangement (CCA) that is a service contract. The ASU specifies that an entity would apply Accounting Standards Codification (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. The amendments in the update also require that the 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, in addition to specifying that the capitalized costs must be presented on the same balance sheet line as the prepayment of fees related to the hosting arrangement. The ASU requires similar consistency in classifications from a cash flow statement perspective. The adoption of this ASU did not have a material impact on our consolidated financial statements.

Improvements to Accounting for Hedging Activities

Effective January 1, 2019, we adopted ASU 2017-12 on a modified retrospective basis. The new standard was issued 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. As a result of the new standard, hedge ineffectiveness will no longer be measured or recorded, and hedging instruments’ fair value changes will be recorded in the same income statement line as the hedged item. The adoption of this accounting update did not have a material impact on our consolidated financial statements.

Amending the Amortization Period for Certain Callable Debt Securities Purchased at a Premium

Effective January 1, 2019, we adopted ASU 2017-08 on a modified retrospective basis. The new standard was issued with the intent of shortening the amortization period to the earliest call date for certain callable debt securities held at a premium. The adoption of this accounting update did not have a material impact on our consolidated financial statements.

Recognition of Leases

Effective January 1, 2019 we adopted ASU 2016-02 Leases (Topic 842) using the modified retrospective approach.

We recognize an arrangement 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 recognize right-of-use (ROU) assets and the related lease liabilities on the statement of financial position for operating lease arrangements with a term of 12 months or longer. We do not separate non-lease components from the associated lease components of our lessee contracts and account for both components as a single lease component. We combine lease and non-lease components within a contract for operating lessor leases when certain conditions are met. ROU assets are assessed for impairment using the same approach as is applied for other long-lived assets, as described under the Impairment section of the Significant Accounting Policies Note 2 in the annual consolidated financial statements.

Lease liabilities and ROU assets require the use of judgment and estimates, which are applied in determining the term of a lease, appropriate discount rates, whether an arrangement contains a lease, whether there are any indicators of impairment for ROU assets and whether any ROU assets should be grouped with other long-lived assets for impairment testing.

In adopting Topic 842, we elected the package of practical expedients permitted under the transition guidance. 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. The application of the package of practical expedients also permits entities not to reassess whether any expired or existing contracts contain leases in accordance with the new guidance, lease classifications, and whether initial direct costs capitalized under current guidance continue to meet the definition of initial direct costs under the new guidance. We also elected the practical expedient related to land easements, allowing us to carry forward our accounting treatment for land easements on existing agreements that had commenced prior to January 1, 2019.

On January 1, 2019, ROU assets and corresponding lease liabilities of $771 million were recorded in connection with the adoption of Topic 842. When added to the $85 million of pre-existing liabilities relating to operating leases for which we no longer utilize the leased assets, total lease liabilities at January 1, 2019 were $856 million. All lease liabilities were measured using a weighted average discount rate of 4.32%. The adoption of this standard had no impact to the Consolidated Statements of Earnings, Comprehensive Income, Changes in Equity or Cash Flows during the period.

FUTURE ACCOUNTING POLICY CHANGES

Clarifying Interaction between Collaborative Arrangements and Revenue from Contracts with Customers

In November 2018, ASU 2018-18 was issued to provide clarity on when transactions between entities in a collaborative arrangement should be accounted for under the new revenue standard, ASC 606. In determining whether transactions in collaborative arrangements should be accounted under the revenue standard, the update specifies that entities shall apply unit of account guidance to identify distinct goods or services and whether such goods and services are separately identifiable from other promises in the contract. ASU 2018-18 also precludes entities from presenting transactions with a collaborative partner which are not in scope of the new revenue standard together with revenue from contracts with customers. The accounting update is effective January 1, 2020 and early adoption is permitted. We are currently assessing the impact of the new standard on our consolidated financial statements.

Improvements to Related Party Guidance for Variable Interest Entities

ASU 2018-17 was issued in October 2018 to improve the related party guidance on determining whether fees paid to decision makers and service providers (“decision-maker fees”) are variable interests. Under the new guidance, reporting entities must consider indirect interests held through related parties in common control arrangements on a proportionate basis, rather than as the equivalent of a direct interest in its entirety, when determining if a decision maker’s fees constitute a variable interest. The accounting update is effective January 1, 2020 and must be applied on a retrospective basis. We are currently assessing the impact of the new standard on our consolidated financial statements.

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.

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 delay the recognition until it is probable a loss has been incurred. The accounting update adds a new impairment model, known as the current expected credit loss model, which is based on expected losses rather than incurred losses. Under the new guidance, an entity will recognize as an allowance its estimate of expected credit losses, which the Financial Accounting Standards Board believes will result in more timely recognition of such losses.

Further, ASU 2018-19 was issued in November 2018 to clarify that operating lease receivables should be accounted for under the new leases standard, ASC 842, and are not within the scope of ASC 326, Financial Instruments - Credit Losses. Both accounting updates are effective January 1, 2020. We are currently assessing the impact of the new standard on our consolidated financial statements.

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REVENUES (Tables)

3 Months Ended

Mar. 31, 2019

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue

	Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution	Renewable Power Generation and Transmission	Energy Services	Eliminations and Other		Consolidated
Three months ended March 31, 2019
(millions of Canadian dollars)
Transportation revenues	2,214	1,137	249	—	—	—		3,600
Storage and other revenues	27	53	54	—	—	—		134
Gas gathering and processing revenues	—	116	—	—	—	—		116
Gas distribution revenue	—	—	1,856	—	—	—		1,856
Electricity and transmission revenues	—	—	—	50	—	—		50
Total revenue from contracts with customers	2,241	1,306	2,159	50	—	—		5,756
Commodity sales	—	—	—	—	6,632	—		6,632
Other revenues1,2	340	10	29	102	6	(19	)	468
Intersegment revenues	77	2	3	—	35	(117	)	—
Total revenues	2,658	1,318	2,191	152	6,673	(136	)	12,856

	Liquids Pipelines		Gas Transmission and Midstream	Gas Distribution	Renewable Power Generation and Transmission	Energy Services	Eliminations and Other		Consolidated
Three months ended March 31, 2018
(millions of Canadian dollars)
Transportation revenues	2,058		952	239	—	—	—		3,249
Storage and other revenues	40		60	66	—	—	—		166
Gas gathering and processing revenues	—		205	—	—	—	—		205
Gas distribution revenues	—		—	1,926	—	—	—		1,926
Electricity and transmission revenues	—		—	—	57	—	—		57
Commodity sales	—		693	—	—	—	—		693
Total revenue from contracts with customers	2,098		1,910	2,231	57	—	—		6,296
Commodity sales	—		—	—	—	6,575	—		6,575
Other revenues1, 2	(269	)	25	2	100	—	(3	)	(145	)
Intersegment revenues	80		2	4	—	57	(143	)	—
Total revenues	1,909		1,937	2,237	157	6,632	(146	)	12,726

1  Includes mark-to-market gains/(losses) from our hedging program.

2 Includes revenues from lease contracts, refer to Note 14 Leases.

Contract with Customer, Asset and Liability

	Receivables	Contract Assets	Contract Liabilities
(millions of Canadian dollars)
Balance as at December 31, 2018	1,929	191	1,297
Balance as at March 31, 2019	2,338	191	1,262

Schedule of New Accounting Pronouncements and Changes in Accounting Principles

	Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution	Renewable Power Generation and Transmission	Energy Services	Consolidated
Three months ended March 31, 2019
(millions of Canadian dollars)
Revenues from products transferred at a point in time1	—	—	17	—	—	17
Revenues from products and services transferred over time2	2,241	1,306	2,142	50	—	5,739
Total revenue from contracts with customers	2,241	1,306	2,159	50	—	5,756

	Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution	Renewable Power Generation and Transmission	Energy Services	Consolidated
Three months ended March 31, 2018
(millions of Canadian dollars)
Revenues from products transferred at a point in time1	—	693	25	—	—	718
Revenues from products and services transferred over time2	2,098	1,217	2,206	57	—	5,578
Total revenue from contracts with customers	2,098	1,910	2,231	57	—	6,296

1  Revenues from sales of crude oil, natural gas and NGLs.

2  Revenues 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.

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SEGMENTED INFORMATION (Tables)

3 Months Ended

Mar. 31, 2019

Segment Reporting [Abstract]

Schedule of reporting information by segment

	Liquids Pipelines		Gas Transmission and Midstream		Gas Distribution		Renewable Power Generation and Transmission		Energy Services		Eliminations and Other		Consolidated
Three months ended March 31, 2019
(millions of Canadian dollars)
Revenues	2,658		1,318		2,191		152		6,673		(136	)	12,856
Commodity and gas distribution costs	(6	)	—		(1,264	)	(1	)	(6,629	)	128		(7,772	)
Operating and administrative	(801	)	(513	)	(294	)	(42	)	(33	)	58		(1,625	)
Income/(loss) from equity investments	197		197		11		14		(7	)	1		413
Other income	24		18		18		1		2		197		260
Earnings before interest, income taxes, and depreciation and amortization	2,072		1,020		662		124		6		248		4,132
Depreciation and amortization													(840	)
Interest expense													(685	)
Income tax expense													(584	)
Earnings													2,023
Capital expenditures1	1,020		394		173		14		1		25		1,627

	Liquids Pipelines		Gas Transmission and Midstream		Gas Distribution		Renewable Power Generation and Transmission		Energy Services		Eliminations and Other		Consolidated
Three months ended March 31, 2018
(millions of Canadian dollars)
Revenues	1,909		1,937		2,237		157		6,632		(146	)	12,726
Commodity and gas distribution costs	(4	)	(620	)	(1,388	)	—		(6,455	)	146		(8,321	)
Operating and administrative	(747	)	(507	)	(248	)	(30	)	(12	)	(97	)	(1,641	)
Impairment of long-lived assets	(144	)	(913	)	—		—		—		(5	)	(1,062	)
Income from equity investments	131		208		17		(25	)	4		—		335
Other income/(expense)	11		21		18		7		—		(177	)	(120	)
Earnings/(loss) before interest, income taxes, and depreciation and amortization	1,156		126		636		109		169		(279	)	1,917
Depreciation and amortization													(824	)
Interest expense													(656	)
Income tax recovery													73
Earnings													510
Capital expenditures1	615		825		183		14		—		6		1,643

1 

Includes allowance for equity funds used during construction.

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EARNINGS PER COMMON SHARE AND DIVIDEND PER SHARE (Tables)

3 Months Ended

Mar. 31, 2019

Earnings Per Share [Abstract]

Schedule of Preferred Stock Characteristics by Class

	Dividend per share
Common Shares		$0.73800
Preference Shares, Series A		$0.34375
Preference Shares, Series B		$0.21340
Preference Shares, Series C1		$0.25395
Preference Shares, Series D		$0.27875
Preference Shares, Series F		$0.29306
Preference Shares, Series H		$0.27350
Preference Shares, Series J		US$0.30540
Preference Shares, Series L		US$0.30993
Preference Shares, Series N		$0.31788
Preference Shares, Series P2		$0.27369
Preference Shares, Series R		$0.25000
Preference Shares, Series 1		US$0.37182
Preference Shares, Series 3		$0.25000
Preference Shares, Series 53		US$0.33596
Preference Shares, Series 74		$0.27806
Preference Shares, Series 9		$0.27500
Preference Shares, Series 11		$0.27500
Preference Shares, Series 13		$0.27500
Preference Shares, Series 15		$0.27500
Preference Shares, Series 17		$0.32188
Preference Shares, Series 19		$0.30625

1 The quarterly dividend per share paid on Series C was decreased to $0.25395 from $0.25459 on March 1, 2019, due to reset on a quarterly basis following the date of issuance of the Series C Preference Shares.

2 The quarterly dividend per share paid on Series P was increased to $0.27369 from $0.25000 on March 1, 2019, due to reset of the annual dividend on March 1, 2019, and every five years thereafter.

3 The quarterly dividend per share paid on Series 5 was increased to US$0.33596 from US$0.27500 on March 1, 2019, due to reset of the annual dividend on March 1, 2019, and every five years thereafter.

4 The quarterly dividend per share paid on Series 7 was increased to $0.27806 from $0.27500 on March 1, 2019, due to reset of the annual dividend on March 1, 2019, and every five years thereafter.

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 March 31,
	2019	2018
(number of common shares in millions)
Weighted average shares outstanding	2,016	1,685
Effect of dilutive options	3	4
Diluted weighted average shares outstanding	2,019	1,689

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AQUISITIONS AND DISPOSITIONS (Tables)

3 Months Ended

Mar. 31, 2019

Discontinued Operations and Disposal Groups [Abstract]

Disposal Groups, Including Discontinued Operations

The table below summarizes the presentation of net assets held for sale in our Consolidated Statements of Financial Position:

	March 31, 2019		December 31, 2018
(millions of Canadian dollars)
Accounts receivable and other (current assets held for sale)	101		117
Deferred amounts and other assets (long-term assets held for sale)1	2,415		2,383
Accounts payable and other (current liabilities held for sale)	(55	)	(63	)
Other long-term liabilities (long-term liabilities held for sale)	(99	)	(96	)
Net assets held for sale	2,362		2,341

1 Included within Deferred amounts and other assets at March 31, 2019 and December 31, 2018 respectively is property, plant and equipment of $2.2 billion and $2.1 billion.

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DEBT (Tables)

3 Months Ended

Mar. 31, 2019

Debt Disclosure [Abstract]

Schedule of credit facilities

The following table provides details of our committed credit facilities as at March 31, 2019:

	Maturity	Total Facilities	Draws1	Available
(millions of Canadian dollars)
Enbridge Inc.	2019-2024	6,137	4,319	1,818
Enbridge (U.S.) Inc.	2021-2024	7,348	5,252	2,096
Enbridge Pipelines Inc.	2020	3,000	1,513	1,487
Enbridge Gas Inc.	2019-2021	2,017	879	1,138
Total committed credit facilities		18,502	11,963	6,539

1    Includes facility draws and commercial paper issuances that are back-stopped by credit facilities.

Schedule of Long-term Debt Instruments

During the three months ended March 31, 2019, we completed the following long-term debt issuances:

Company	Issue Date		Principal Amount
(millions of Canadian dollars)
Enbridge Pipelines Inc.
	February 2019	3.52% medium-term notes due February 2029	$600
	February 2019	4.33% medium-term notes due February 2049	$600

SEP Notes1	EEP Notes2
Floating Rate Senior Notes due 2020	5.200% Notes due 2020
4.600% Senior Notes due 2021	4.375% Notes due 2020
4.750% Senior Notes due 2024	4.200% Notes due 2021
3.500% Senior Notes due 2025	5.875% Notes due 2025
3.375% Senior Notes due 2026	5.950% Notes due 2033
5.950% Senior Notes due 2043	6.300% Notes due 2034
4.500% Senior Notes due 2045	7.500% Notes due 2038
	5.500% Notes due 2040
	7.375% Notes due 2045

1 As at March 31, 2019, the aggregate outstanding principal amount of SEP notes was approximately US$3.9 billion.

2

As at March 31, 2019, the aggregate outstanding principal amount of EEP notes was approximately US$4.0 billion.

USD Denominated1	CAD Denominated2
Senior Floating Rate Notes due 2020	Senior Floating Rate Notes due 2019
Senior Floating Rate Notes due 2020	4.770% Senior Notes due 2019
2.900% Senior Notes due 2022	4.530% Senior Notes due 2020
4.000% Senior Notes due 2023	4.850% Senior Notes due 2020
3.500% Senior Notes due 2024	4.260% Senior Notes due 2021
4.250% Senior Notes due 2026	3.160% Senior Notes due 2021
3.700% Senior Notes due 2027	4.850% Senior Notes due 2022
4.500% Senior Notes due 2044	3.190% Senior Notes due 2022
5.500% Senior Notes due 2046	3.940% Senior Notes due 2023
	3.940% Senior Notes due 2023
	3.950% Senior Notes due 2024
	3.200% Senior Notes due 2027
	6.100% Senior Notes due 2028
	7.220% Senior Notes due 2030
	7.200% Senior Notes due 2032
	5.570% Senior Notes due 2035
	5.750% Senior Notes due 2039
	5.120% Senior Notes due 2040
	4.240% Senior Notes due 2042
	4.570% Senior Notes due 2044
	4.870% Senior Notes due 2044
	4.560% Senior Notes due 2064

1 As at March 31, 2019, the aggregate outstanding principal amount of the Enbridge United States dollar denominated notes was approximately US$5.9 billion.

2

As at March 31, 2019, the aggregate outstanding principal amount of the Enbridge Canadian dollar denominated notes was approximately $7.8 billion.

Schedule of Repayment of Debt

During the three months ended March 31, 2019, we completed the following long-term debt repayments:

Company	Retirement/ Repayment Date		Principal Amount
(millions of Canadian dollars, unless otherwise stated)
Enbridge Inc.
Repayment
	February 2019	4.10% medium-term notes	$300
Enbridge Energy Partners, L.P.
Redemption
	February 2019	8.05% fixed/floating rate junior subordinated notes due 2067	US$400
Repayment
	March 2019	9.88% senior notes	US$500
Westcoast Energy Inc.
Repayment
	January 2019	5.60% medium-term notes	$250
	January 2019	5.60% medium-term notes	$50

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COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME (Tables)

3 Months Ended

Mar. 31, 2019

Comprehensive Income (Loss), Net of Tax, Attributable to Parent [Abstract]

Schedule of changes in AOCI attributable to Enbridge Inc. common shareholders

Changes in Accumulated Other Comprehensive Income (AOCI) attributable to our common shareholders for the three months ended March 31, 2019 and 2018 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, 2019	(770	)	(598	)	4,323		34	(317	)	2,672
Other comprehensive income/(loss) retained in AOCI	(312	)	109		(1,242	)	8	—		(1,437	)
Other comprehensive (income)/loss reclassified to earnings
Interest rate contracts1	32		—		—		—	—		32
Foreign exchange contracts3	2		—		—		—	—		2
Other contracts4	(9	)	—		—		—	—		(9	)
Amortization of pension and OPEB actuarial loss and prior service costs5	—		—		—		—	53		53
	(287	)	109		(1,242	)	8	53		(1,359	)
Tax impact
Income tax on amounts retained in AOCI	121		(15	)	—		4	—		110
Income tax on amounts reclassified to earnings	(14	)	—		—		—	(15	)	(29	)
	107		(15	)	—		4	(15	)	81
Other	—		—		—		—	55		55
Balance as at March 31, 2019	(950	)	(504	)	3,081		46	(224	)	1,449

	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	70		(213	)	1,425	2	—		1,284
Other comprehensive (income)/loss reclassified to earnings
Interest rate contracts1	28		—		—	—	—		28
Commodity contracts2	(1	)	—		—	—	—		(1	)
Foreign exchange contracts3	4		—		—	—	—		4
Other contracts4	9		—		—	—	—		9
Amortization of pension and OPEB actuarial loss and prior service costs5	—		—		—	—	(38	)	(38	)
	110		(213	)	1,425	2	(38	)	1,286
Tax impact
Income tax on amounts retained in AOCI	(9	)	29		—	8	—		28
Income tax on amounts reclassified to earnings	(11	)	—		—	—	(1	)	(12	)
	(20	)	29		—	8	(1	)	16
Balance as at March 31, 2018	(554	)	(323	)	1,502	20	(316	)	329

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.

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RISK MANAGEMENT AND FINANCIAL INSTRUMENTS (Tables)

3 Months Ended

Mar. 31, 2019

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Summary of the Consolidated Statements of Financial Position location and carrying value of derivative instruments

March 31, 2019	Derivative Instruments Used as Cash Flow Hedges		Derivative Instruments Used as Net Investment 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	—		—		26		26		(26	)	—
Interest rate contracts	7		—		—		7		—		7
Commodity contracts	1		—		171		172		(77	)	95
	8		—		197		205		(103	)	102
Deferred amounts and other assets
Foreign exchange contracts	13		—		37		50		(36	)	14
Interest rate contracts	—		—		—		—		—		—
Commodity contracts	17		—		18		35		(22	)	13
Other contracts	1		—		1		2		—		2
	31		—		56		87		(58	)	29
Accounts payable and other
Foreign exchange contracts	(5	)	—		(501	)	(506	)	26		(480	)
Interest rate contracts	(150	)	—		—		(150	)	—		(150	)
Commodity contracts	—		—		(289	)	(289	)	77		(212	)
Other contracts	—		—		(1	)	(1	)	—		(1	)
	(155	)	—		(791	)	(946	)	103		(843	)
Other long-term liabilities
Foreign exchange contracts	—		(14	)	(1,666	)	(1,680	)	36		(1,644	)
Interest rate contracts	(374	)	—		—		(374	)	—		(374	)
Commodity contracts	—		—		(152	)	(152	)	22		(130	)
Other contracts	—		—		—		—		—		—
	(374	)	(14	)	(1,818	)	(2,206	)	58		(2,148	)
Total net derivative asset/(liability)
Foreign exchange contracts	8		(14	)	(2,104	)	(2,110	)	—		(2,110	)
Interest rate contracts	(517	)	—		—		(517	)	—		(517	)
Commodity contracts	18		—		(252	)	(234	)	—		(234	)
Other contracts	1		—		—		1		—		1
	(490	)	(14	)	(2,356	)	(2,860	)	—		(2,860	)

December 31, 2018	Derivative Instruments Used as Cash Flow Hedges		Derivative Instruments Used as Net Investment 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	—		—		47		47		(37	)	10
Interest rate contracts	22		—		—		22		(2	)	20
Commodity contracts	2		—		427		429		(114	)	315
	24		—		474		498		(153	)	345
Deferred amounts and other assets
Foreign exchange contracts	23		—		39		62		(39	)	23
Interest rate contracts	5		—		—		5		—		5
Commodity contracts	19		—		33		52		(21	)	31
	47		—		72		119		(60	)	59
Accounts payable and other
Foreign exchange contracts	(5	)	—		(610	)	(615	)	37		(578	)
Interest rate contracts	(163	)	—		(178	)	(341	)	2		(339	)
Commodity contracts	—		—		(273	)	(273	)	114		(159	)
Other contracts	(1	)	—		(4	)	(5	)	—		(5	)
	(169	)	—		(1,065	)	(1,234	)	153		(1,081	)
Other long-term liabilities
Foreign exchange contracts	(1	)	(15	)	(2,196	)	(2,212	)	39		(2,173	)
Interest rate contracts	(201	)	—		—		(201	)	—		(201	)
Commodity contracts	—		—		(178	)	(178	)	21		(157	)
Other contracts	(1	)	—		(1	)	(2	)	—		(2	)
	(203	)	(15	)	(2,375	)	(2,593	)	60		(2,533	)
Total net derivative asset/(liability)
Foreign exchange contracts	17		(15	)	(2,720	)	(2,718	)	—		(2,718	)
Interest rate contracts	(337	)	—		(178	)	(515	)	—		(515	)
Commodity contracts	21		—		9		30		—		30
Other contracts	(2	)	—		(5	)	(7	)	—		(7	)
	(301	)	(15	)	(2,894	)	(3,210	)	—		(3,210	)

Summary of the maturity and notional principal or quantity outstanding related to derivative instruments

The following table summarizes the maturity and notional principal or quantity outstanding related to our derivative instruments.

March 31, 2019	2019		2020		2021		2022		2023		Thereafter1
Foreign exchange contracts - United States dollar forwards - purchase (millions of United States dollars)	895		1		—		—		—		—
Foreign exchange contracts - United States dollar forwards - sell (millions of United States dollars)	3,839		4,893		3,608		1,944		1,804		1,856
Foreign exchange contracts - British pound (GBP) forwards - sell (millions of GBP)	86		25		27		28		29		120
Foreign exchange contracts - Euro forwards - purchase (millions of Euro)	168		—		—		—		—		—
Foreign exchange contracts - Euro forwards - sell (millions of Euro)	—		23		94		94		92		606
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)	6,629		6,178		4,142		407		48		156
Interest rate contracts - long-term receive fixed rate (millions of Canadian dollars)	—		—		—		—		—		—
Interest rate contracts - long-term debt pay fixed rate (millions of Canadian dollars)	2,537		3,142		1,584		—		—		—
Equity contracts (millions of Canadian dollars)	32		20		—		—		—		—
Commodity contracts - natural gas (billions of cubic feet)	(75	)	(15	)	—		(84	)	1		—
Commodity contracts - crude oil (millions of barrels)	4		(2	)	—		—		—		—
Commodity contracts - NGL (millions of barrels)	1		—		—		—		—		—
Commodity contracts - power (megawatt per hour) (MW/H))	98		80		(3	)	(43	)	(43	)	(43	)

1 As at March 31, 2019, thereafter includes an average net purchase/(sell) of power of (43) MW/H for 2024 through 2025.

Schedule of effect of cash flow hedges and net investment hedges on consolidated earnings and consolidated comprehensive income, before income taxes

	Three months ended March 31,
	20191	2018
(millions of Canadian dollars)
Unrealized gain/(loss) on derivative	—	(8	)
Unrealized gain/(loss) on hedged item	—	8
Realized gain/(loss) on derivative	—	(3	)
Realized gain/(loss) on hedged item	—	3

1.

For the three months ended March 31, 2019, there are no outstanding fair value hedges.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 March 31,
	2019		2018
(millions of Canadian dollars)
Amount of unrealized gain/(loss) recognized in OCI
Cash flow hedges
Foreign exchange contracts	(10	)	21
Interest rate contracts	(296	)	100
Commodity contracts	(3	)	(2	)
Other contracts	12		(14	)
Net investment hedges
Foreign exchange contracts	1		16
	(296	)	121
Amount of (gain)/loss reclassified from AOCI to earnings
Foreign exchange contracts1	2		(1	)
Interest rate contracts2	32		40
Commodity contracts3	—		(1	)
Other contracts4	(9	)	9
	25		47

1 Reported within Transportation and other services revenues and Net foreign currency gain/(loss) in the Consolidated Statements of Earnings.

2 Reported within Interest expense in the Consolidated Statements of Earnings. Effective January 1, 2019 hedge ineffectiveness will no longer be measured or recorded. See Note 2 Changes in Accounting Policies.

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 March 31,
	2019		2018
(millions of Canadian dollars)
Foreign exchange contracts1	616		(424	)
Interest rate contracts2	178		(2	)
Commodity contracts3	(261	)	175
Other contracts4	5		(9	)
Total unrealized derivative fair value gain/(loss), net	538		(260	)

1 For the respective three months ended periods, reported within Transportation and other services revenues (2019 - $352 million gain; 2018 - $297 million loss) and Net foreign currency gain/(loss) (2019 - $264 million gain; 2018 - $127 million loss) in the Consolidated Statements of Earnings.

2 Reported as an (increase)/decrease within Interest expense in the Consolidated Statements of Earnings.

3 For the respective three months ended periods, reported within Transportation and other services revenues (2019 - $26 million loss; 2018 - $1 million loss), Commodity sales (2019 - $642 million loss; 2018 - $82 million gain), Commodity costs (2019 - $398 million gain; 2018 - $84 million gain) and Operating and administrative expense (2019 - $9 million gain; 2018 - $10 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:

	March 31, 2019	December 31, 2018
(millions of Canadian dollars)
Canadian financial institutions	21	28
United States financial institutions	51	107
European financial institutions	58	84
Asian financial institutions	—	6
Other1	132	337
	262	562

1

Other is comprised of commodity clearing house and physical natural gas and crude oil counterparties.

Schedule of derivative assets and liabilities measured at fair value

We have categorized our derivative assets and liabilities measured at fair value as follows:

March 31, 2019	Level 1		Level 2		Level 3		Total Gross Derivative Instruments
(millions of Canadian dollars)
Financial assets
Current derivative assets
Foreign exchange contracts	—		26		—		26
Interest rate contracts	—		7		—		7
Commodity contracts	3		10		159		172
	3		43		159		205
Long-term derivative assets
Foreign exchange contracts	—		50		—		50
Commodity contracts	—		13		22		35
Other contracts	—		2		—		2
	—		65		22		87
Financial liabilities
Current derivative liabilities
Foreign exchange contracts	—		(506	)	—		(506	)
Interest rate contracts	—		(150	)	—		(150	)
Commodity contracts	(7	)	(16	)	(266	)	(289	)
Other contracts	—		(1	)	—		(1	)
	(7	)	(673	)	(266	)	(946	)
Long-term derivative liabilities
Foreign exchange contracts	—		(1,680	)	—		(1,680	)
Interest rate contracts	—		(374	)	—		(374	)
Commodity contracts	—		(15	)	(137	)	(152	)
	—		(2,069	)	(137	)	(2,206	)
Total net financial liabilities
Foreign exchange contracts	—		(2,110	)	—		(2,110	)
Interest rate contracts	—		(517	)	—		(517	)
Commodity contracts	(4	)	(8	)	(222	)	(234	)
Other contracts	—		1		—		1
	(4	)	(2,634	)	(222	)	(2,860	)

December 31, 2018	Level 1		Level 2		Level 3		Total Gross Derivative Instruments
(millions of Canadian dollars)
Financial assets
Current derivative assets
Foreign exchange contracts	—		47		—		47
Interest rate contracts	—		22		—		22
Commodity contracts	24		45		360		429
	24		114		360		498
Long-term derivative assets
Foreign exchange contracts	—		62		—		62
Interest rate contracts	—		5		—		5
Commodity contracts	—		30		22		52
	—		97		22		119
Financial liabilities
Current derivative liabilities
Foreign exchange contracts	—		(615	)	—		(615	)
Interest rate contracts	—		(341	)	—		(341	)
Commodity contracts	(7	)	(28	)	(238	)	(273	)
Other contracts	—		(5	)	—		(5	)
	(7	)	(989	)	(238	)	(1,234	)
Long-term derivative liabilities
Foreign exchange contracts	—		(2,212	)	—		(2,212	)
Interest rate contracts	—		(201	)	—		(201	)
Commodity contracts	—		(23	)	(155	)	(178	)
Other contracts	—		(2	)	—		(2	)
	—		(2,438	)	(155	)	(2,593	)
Total net financial liabilities
Foreign exchange contracts	—		(2,718	)	—		(2,718	)
Interest rate contracts	—		(515	)	—		(515	)
Commodity contracts	17		24		(11	)	30
Other contracts	—		(7	)	—		(7	)
	17		(3,216	)	(11	)	(3,210	)

Schedule of significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments

The significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments were as follows:

March 31, 2019	Fair Value		Unobservable Input	Minimum Price	Maximum Price	Weighted Average Price	Unit of Measurement
(fair value in millions of Canadian dollars)
Commodity contracts - financial1
Natural gas	(18	)	Forward gas price	2.55	5.17	3.47	$/mmbtu2
Crude	38		Forward crude price	42.96	166.19	69.21	$/barrel
Power	(82	)	Forward power price	30.79	71.28	50.21	$/MW/H
Commodity contracts - physical1
Natural gas	(125	)	Forward gas price	1.22	5.17	2.25	$/mmbtu2
Crude	(37	)	Forward crude price	33.12	127.36	76.83	$/barrel
NGL	2		Forward NGL price	0.17	1.11	0.37	$/gallon
	(222	)

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:

	Three months ended March 31,
	2019		2018
(millions of Canadian dollars)
Level 3 net derivative liability at beginning of period	(11	)	(387	)
Total gain/(loss)
Included in earnings1	(52	)	31
Included in OCI	(3	)	(3	)
Settlements	(156	)	154
Level 3 net derivative liability at end of period	(222	)	(205	)

1

Reported within Transportation and other services revenues, Commodity costs and Operating and administrative expense in the Consolidated Statements of Earnings.

XML

PENSION AND OTHER POSTRETIREMENT BENEFITS (Tables)

3 Months Ended

Mar. 31, 2019

Retirement Benefits [Abstract]

Schedule of net benefit costs recognized

	Three months ended March 31,
	2019		2018
(millions of Canadian dollars)
Service cost	51		65
Interest cost	51		45
Expected return on plan assets	(84	)	(82	)
Amortization of actuarial loss	8		7
Amortization of prior service costs	(1	)	(1	)
Net periodic benefit costs	25		34

XML

LEASES (Tables)

3 Months Ended

Mar. 31, 2019

Leases [Abstract]

Assets and Liabilities, Lessee

Supplemental Statements of Financial Position Information

	March 31, 2019		January 1, 2019
(millions of Canadian dollars, except lease term and discount rate)
Operating leases
Operating lease right-of-use assets, net1	745		771
Operating lease liabilities - current2	67		86
Operating lease liabilities - long-term3	757		770
Total operating lease liabilities	824		856
Weighted average remaining lease term
Operating leases	14 years		14 years
Weighted average discount rate
Operating leases	4.3	%	4.3	%

1 Right-of-use assets are reported under Deferred amounts and other assets in the Consolidated Statements of Financial Position.

2 Current lease liabilities are reported under Accounts payable and other in the Consolidated Statements of Financial Position.

3 Long-term lease liabilities are reported under Other long-term liabilities in the Consolidated Statements of Financial Position.

Lessee, Operating Lease, Liability, Maturity

As at March 31, 2019, we have operating lease commitments as detailed below:

	Operating leases
(millions of Canadian dollars)
20191	83
2020	116
2021	94
2022	89
2023	79
Thereafter	663
Total undiscounted lease payments	1,124
Less imputed interest	(300	)
Total operating lease commitments	824

1 For the nine months remaining in the 2019 fiscal year.

Operating Lease, Lease Income

	Three months ended March 31, 2019
(millions of Canadian dollars)
Operating lease income	64
Variable lease income	100
Total lease income	164

Lessor, Operating Lease, Payments to be Received, Maturity

The following table sets out future minimum lease payments expected to be received under lease contracts where we are the lessor:

	Operating leases
(millions of Canadian dollars)
20191	192
2020	216
2021	189
2022	186
2023	178
Thereafter	2,395
Total undiscounted lease payments	3,356

1

For the nine months remaining in the 2019 fiscal year.

XML

CONDENSED CONSOLIDATING FINANCIAL INFORMATION (Tables)

3 Months Ended

Mar. 31, 2019

Condensed Financial Information Disclosure [Abstract]

Schedule of Long-term Debt Instruments

During the three months ended March 31, 2019, we completed the following long-term debt issuances:

Company	Issue Date		Principal Amount
(millions of Canadian dollars)
Enbridge Pipelines Inc.
	February 2019	3.52% medium-term notes due February 2029	$600
	February 2019	4.33% medium-term notes due February 2049	$600

SEP Notes1	EEP Notes2
Floating Rate Senior Notes due 2020	5.200% Notes due 2020
4.600% Senior Notes due 2021	4.375% Notes due 2020
4.750% Senior Notes due 2024	4.200% Notes due 2021
3.500% Senior Notes due 2025	5.875% Notes due 2025
3.375% Senior Notes due 2026	5.950% Notes due 2033
5.950% Senior Notes due 2043	6.300% Notes due 2034
4.500% Senior Notes due 2045	7.500% Notes due 2038
	5.500% Notes due 2040
	7.375% Notes due 2045

1 As at March 31, 2019, the aggregate outstanding principal amount of SEP notes was approximately US$3.9 billion.

2

As at March 31, 2019, the aggregate outstanding principal amount of EEP notes was approximately US$4.0 billion.

USD Denominated1	CAD Denominated2
Senior Floating Rate Notes due 2020	Senior Floating Rate Notes due 2019
Senior Floating Rate Notes due 2020	4.770% Senior Notes due 2019
2.900% Senior Notes due 2022	4.530% Senior Notes due 2020
4.000% Senior Notes due 2023	4.850% Senior Notes due 2020
3.500% Senior Notes due 2024	4.260% Senior Notes due 2021
4.250% Senior Notes due 2026	3.160% Senior Notes due 2021
3.700% Senior Notes due 2027	4.850% Senior Notes due 2022
4.500% Senior Notes due 2044	3.190% Senior Notes due 2022
5.500% Senior Notes due 2046	3.940% Senior Notes due 2023
	3.940% Senior Notes due 2023
	3.950% Senior Notes due 2024
	3.200% Senior Notes due 2027
	6.100% Senior Notes due 2028
	7.220% Senior Notes due 2030
	7.200% Senior Notes due 2032
	5.570% Senior Notes due 2035
	5.750% Senior Notes due 2039
	5.120% Senior Notes due 2040
	4.240% Senior Notes due 2042
	4.570% Senior Notes due 2044
	4.870% Senior Notes due 2044
	4.560% Senior Notes due 2064

1 As at March 31, 2019, the aggregate outstanding principal amount of the Enbridge United States dollar denominated notes was approximately US$5.9 billion.

2

As at March 31, 2019, the aggregate outstanding principal amount of the Enbridge Canadian dollar denominated notes was approximately $7.8 billion.

Condensed Income Statement

Condensed Consolidating Statements of Earnings and Comprehensive Income for the three months ended March 31, 2019

	Parent Issuer and Guarantor		Subsidiary Issuer and Guarantor - SEP		Subsidiary Issuer and Guarantor - EEP		Subsidiary Non-Guarantors		Consolidating and elimination adjustments		Consolidated - Enbridge
(millions of Canadian dollars)
Operating revenues
Commodity sales	—		—		—		6,632		—		6,632
Gas distribution sales	—		—		—		1,876		—		1,876
Transportation and other services	—		—		—		4,348		—		4,348
Total operating revenues	—		—		—		12,856		—		12,856
Operating Expenses
Commodity costs	—		—		—		6,565		—		6,565
Gas distribution costs	—		—		—		1,207		—		1,207
Operating and administrative	(34	)	2		1		1,656		—		1,625
Depreciation and amortization	15		—		—		825		—		840
Total operating expenses	(19	)	2		1		10,253		—		10,237
Operating income/(loss)	19		(2	)	(1	)	2,603		—		2,619
Income/(loss) from equity investments	59		31		—		382		(59	)	413
Equity earnings from consolidated subsidiaries	774		398		263		493		(1,928	)	—
Other
Net foreign currency gain/(loss)	1,221		—		—		(103	)	(904	)	214
Other, including other income from affiliates	330		—		41		123		(448	)	46
Interest expense	(308	)	(94	)	(158	)	(583	)	458		(685	)
Earnings before income taxes	2,095		333		145		2,915		(2,881	)	2,607
Income tax expense	(109	)	15		—		(596	)	106		(584	)
Earnings	1,986		348		145		2,319		(2,775	)	2,023
Earnings attributable to noncontrolling interests and redeemable noncontrolling interests	—		—		—		—		(37	)	(37	)
Earnings attributable to controlling interests	1,986		348		145		2,319		(2,812	)	1,986
Preference share dividends	(95	)	—		—		—		—		(95	)
Earnings attributable to common shareholders	1,891		348		145		2,319		(2,812	)	1,891
Earnings	1,986		348		145		2,319		(2,775	)	2,023
Total other comprehensive income/(loss)	(1,278	)	(16	)	15		(720	)	671		(1,328	)
Comprehensive income	708		332		160		1,599		(2,104	)	695
Comprehensive loss attributable to noncontrolling interests	—		—		—		—		13		13
Comprehensive income attributable to controlling interests	708		332		160		1,599		(2,091	)	708

Condensed Consolidating Statements of Earnings and Comprehensive Income for the three months ended March 31, 2018

	Parent Issuer and Guarantor		Subsidiary Issuer and Guarantor - SEP		Subsidiary Issuer and Guarantor - EEP		Subsidiary Non-Guarantors		Consolidating and elimination adjustments		Consolidated - Enbridge
(millions of Canadian dollars)
Operating revenues
Commodity sales	—		—		—		7,268		—		7,268
Gas distribution sales	—		—		—		1,926		—		1,926
Transportation and other services	—		—		—		3,532		—		3,532
Total operating revenues	—		—		—		12,726		—		12,726
Operating Expenses
Commodity costs	—		—		—		6,997		—		6,997
Gas distribution costs	—		—		—		1,324		—		1,324
Operating and administrative	67		1		4		1,569		—		1,641
Depreciation and amortization	14		—		—		810		—		824
Impairment of long-lived assets	—		—		—		1,062		—		1,062
Total operating expenses	81		1		4		11,762		—		11,848
Operating income/(loss)	(81	)	(1	)	(4	)	964		—		878
Income from equity investments	17		34		—		300		(16	)	335
Equity earnings from consolidated subsidiaries	707		551		203		608		(2,069	)	—
Other
Net foreign currency gain/(loss)	(199	)	2		—		(58	)	70		(185	)
Other, including other income/(expense) from affiliates	246		1		30		39		(251	)	65
Interest expense	(243	)	(72	)	(136	)	(479	)	274		(656	)
Earnings before income taxes	447		515		93		1,374		(1,992	)	437
Income tax recovery/(expense)	87		—		—		(23	)	9		73
Earnings	534		515		93		1,351		(1,983	)	510
Earnings attributable to noncontrolling interests and redeemable noncontrolling interests	—		—		—		—		24		24
Earnings attributable to controlling interests	534		515		93		1,351		(1,959	)	534
Preference share dividends	(89	)	—		—		—		—		(89	)
Earnings attributable to common shareholders	445		515		93		1,351		(1,959	)	445
Earnings	534		515		93		1,351		(1,983	)	510
Total other comprehensive income	1,302		19		8		253		(109	)	1,473
Comprehensive income	1,836		534		101		1,604		(2,092	)	1,983
Comprehensive income attributable to noncontrolling interests	—		—		—		—		(147	)	(147	)
Comprehensive income attributable to controlling interests	1,836		534		101		1,604		(2,239	)	1,836

Condensed Statement of Comprehensive Income

	Parent Issuer and Guarantor		Subsidiary Issuer and Guarantor - SEP		Subsidiary Issuer and Guarantor - EEP		Subsidiary Non-Guarantors		Consolidating and elimination adjustments		Consolidated - Enbridge
(millions of Canadian dollars)
Operating revenues
Commodity sales	—		—		—		6,632		—		6,632
Gas distribution sales	—		—		—		1,876		—		1,876
Transportation and other services	—		—		—		4,348		—		4,348
Total operating revenues	—		—		—		12,856		—		12,856
Operating Expenses
Commodity costs	—		—		—		6,565		—		6,565
Gas distribution costs	—		—		—		1,207		—		1,207
Operating and administrative	(34	)	2		1		1,656		—		1,625
Depreciation and amortization	15		—		—		825		—		840
Total operating expenses	(19	)	2		1		10,253		—		10,237
Operating income/(loss)	19		(2	)	(1	)	2,603		—		2,619
Income/(loss) from equity investments	59		31		—		382		(59	)	413
Equity earnings from consolidated subsidiaries	774		398		263		493		(1,928	)	—
Other
Net foreign currency gain/(loss)	1,221		—		—		(103	)	(904	)	214
Other, including other income from affiliates	330		—		41		123		(448	)	46
Interest expense	(308	)	(94	)	(158	)	(583	)	458		(685	)
Earnings before income taxes	2,095		333		145		2,915		(2,881	)	2,607
Income tax expense	(109	)	15		—		(596	)	106		(584	)
Earnings	1,986		348		145		2,319		(2,775	)	2,023
Earnings attributable to noncontrolling interests and redeemable noncontrolling interests	—		—		—		—		(37	)	(37	)
Earnings attributable to controlling interests	1,986		348		145		2,319		(2,812	)	1,986
Preference share dividends	(95	)	—		—		—		—		(95	)
Earnings attributable to common shareholders	1,891		348		145		2,319		(2,812	)	1,891
Earnings	1,986		348		145		2,319		(2,775	)	2,023
Total other comprehensive income/(loss)	(1,278	)	(16	)	15		(720	)	671		(1,328	)
Comprehensive income	708		332		160		1,599		(2,104	)	695
Comprehensive loss attributable to noncontrolling interests	—		—		—		—		13		13
Comprehensive income attributable to controlling interests	708		332		160		1,599		(2,091	)	708

Condensed Consolidating Statements of Earnings and Comprehensive Income for the three months ended March 31, 2018

	Parent Issuer and Guarantor		Subsidiary Issuer and Guarantor - SEP		Subsidiary Issuer and Guarantor - EEP		Subsidiary Non-Guarantors		Consolidating and elimination adjustments		Consolidated - Enbridge
(millions of Canadian dollars)
Operating revenues
Commodity sales	—		—		—		7,268		—		7,268
Gas distribution sales	—		—		—		1,926		—		1,926
Transportation and other services	—		—		—		3,532		—		3,532
Total operating revenues	—		—		—		12,726		—		12,726
Operating Expenses
Commodity costs	—		—		—		6,997		—		6,997
Gas distribution costs	—		—		—		1,324		—		1,324
Operating and administrative	67		1		4		1,569		—		1,641
Depreciation and amortization	14		—		—		810		—		824
Impairment of long-lived assets	—		—		—		1,062		—		1,062
Total operating expenses	81		1		4		11,762		—		11,848
Operating income/(loss)	(81	)	(1	)	(4	)	964		—		878
Income from equity investments	17		34		—		300		(16	)	335
Equity earnings from consolidated subsidiaries	707		551		203		608		(2,069	)	—
Other
Net foreign currency gain/(loss)	(199	)	2		—		(58	)	70		(185	)
Other, including other income/(expense) from affiliates	246		1		30		39		(251	)	65
Interest expense	(243	)	(72	)	(136	)	(479	)	274		(656	)
Earnings before income taxes	447		515		93		1,374		(1,992	)	437
Income tax recovery/(expense)	87		—		—		(23	)	9		73
Earnings	534		515		93		1,351		(1,983	)	510
Earnings attributable to noncontrolling interests and redeemable noncontrolling interests	—		—		—		—		24		24
Earnings attributable to controlling interests	534		515		93		1,351		(1,959	)	534
Preference share dividends	(89	)	—		—		—		—		(89	)
Earnings attributable to common shareholders	445		515		93		1,351		(1,959	)	445
Earnings	534		515		93		1,351		(1,983	)	510
Total other comprehensive income	1,302		19		8		253		(109	)	1,473
Comprehensive income	1,836		534		101		1,604		(2,092	)	1,983
Comprehensive income attributable to noncontrolling interests	—		—		—		—		(147	)	(147	)
Comprehensive income attributable to controlling interests	1,836		534		101		1,604		(2,239	)	1,836

Condensed Balance Sheet

Condensed Consolidating Statements of Financial Position as at March 31, 2019

	Parent Issuer and Guarantor	Subsidiary Issuer and Guarantor - SEP	Subsidiary Issuer and Guarantor - EEP	Subsidiary Non-Guarantors		Consolidating and elimination adjustments		Consolidated - Enbridge
(millions of Canadian dollars)
Assets
Current assets
Cash and cash equivalents	—	5	7	690		—		702
Restricted cash	9	—	—	46		—		55
Accounts receivable and other	283	1	—	6,202		—		6,486
Accounts receivable from affiliates	586	—	31	79		(604	)	92
Short-term loans receivable from affiliates	3,527	—	3,838	5,871		(13,236	)	—
Inventory	—	—	—	1,047		—		1,047
	4,405	6	3,876	13,935		(13,840	)	8,382
Property, plant and equipment, net	166	—	—	93,709		—		93,875
Long-term loans receivable from affiliates	26,504	73	2,472	15,524		(44,573	)	—
Investments in subsidiaries	78,271	19,741	6,209	15,032		(119,253	)	—
Long-term investments	4,619	961	—	14,890		(3,568	)	16,902
Restricted long-term investments	—	—	—	356		—		356
Deferred amounts and other assets	1,491	1	8	9,412		(1,407	)	9,505
Intangible assets, net	219	—	—	2,082		—		2,301
Goodwill	—	—	—	33,895		—		33,895
Deferred income taxes	744	—	—	220		328		1,292
Total assets	116,419	20,782	12,565	199,055		(182,313	)	166,508
Liabilities and equity
Current liabilities
Short-term borrowings	—	—	—	870		—		870
Accounts payable and other	756	19	14	6,552		(10	)	7,331
Accounts payable to affiliates	935	509	80	(891	)	(603	)	30
Interest payable	227	25	92	229		—		573
Short-term loans payable to affiliates	426	2,985	2,458	7,367		(13,236	)	—
Current portion of long-term debt	2,979	—	668	674		—		4,321
	5,323	3,538	3,312	14,801		(13,849	)	13,125
Long-term debt	23,519	5,095	4,565	27,501		—		60,680
Other long-term liabilities	2,145	8	22	8,276		(1,407	)	9,044
Long-term loans payable to affiliates	15,076	—	1,470	28,027		(44,573	)	—
Deferred income taxes	—	304	—	13,821		(4,385	)	9,740
	46,063	8,945	9,369	92,426		(64,214	)	92,589
Equity
Controlling interests1	70,356	11,837	3,196	106,629		(121,713	)	70,305
Noncontrolling interests	—	—	—	—		3,614		3,614
	70,356	11,837	3,196	106,629		(118,099	)	73,919
Total liabilities and equity	116,419	20,782	12,565	199,055		(182,313	)	166,508

1 Equity attributable to controlling interests for parent issuer and guarantor excludes reciprocal shareholding balance included within consolidating and elimination adjustments.

Condensed Consolidating Statements of Financial Position as at December 31, 2018

	Parent Issuer and Guarantor	Subsidiary Issuer and Guarantor - SEP	Subsidiary Issuer and Guarantor - EEP	Subsidiary Non-Guarantors		Consolidating and elimination adjustments		Consolidated - Enbridge
(millions of Canadian dollars)
Assets
Current assets
Cash and cash equivalents	—	16	—	502		—		518
Restricted cash	9	—	—	110		—		119
Accounts receivable and other	283	15	8	6,211		—		6,517
Accounts receivable from affiliates	726	—	13	(142	)	(518	)	79
Short-term loans receivable from affiliates	3,943	—	3,689	653		(8,285	)	—
Inventory	—	—	—	1,339		—		1,339
	4,961	31	3,710	8,673		(8,803	)	8,572
Property, plant and equipment, net	140	—	—	94,400		—		94,540
Long-term loans receivable from affiliates	10,318	73	2,539	1,344		(14,274	)	—
Investments in subsidiaries	78,474	19,777	6,363	15,567		(120,181	)	—
Long-term investments	4,561	987	—	14,841		(3,682	)	16,707
Restricted long-term investments	—	—	—	323		—		323
Deferred amounts and other assets	1,700	9	17	8,558		(1,726	)	8,558
Intangible assets, net	234	—	—	2,138		—		2,372
Goodwill	—	—	—	34,459		—		34,459
Deferred income taxes	817	—	—	229		328		1,374
Total assets	101,205	20,877	12,629	180,532		(148,338	)	166,905
Liabilities and equity
Current liabilities
Short-term borrowings	—	—	—	1,024		—		1,024
Accounts payable and other	2,742	7	34	7,086		(6	)	9,863
Accounts payable to affiliates	946	233	56	(677	)	(518	)	40
Interest payable	283	56	105	225		—		669
Short-term loans payable to affiliates	426	682	—	7,177		(8,285	)	—
Current portion of long-term debt	1,853	—	683	723		—		3,259
	6,250	978	878	15,558		(8,809	)	14,855
Long-term debt	22,893	7,276	6,943	23,215		—		60,327
Other long-term liabilities	2,428	2	30	8,100		(1,726	)	8,834
Long-term loans payable to affiliates	76	—	1,502	12,696		(14,274	)	—
Deferred income taxes	—	331	—	13,523		(4,400	)	9,454
	31,647	8,587	9,353	73,092		(29,209	)	93,470
Equity
Controlling interests1	69,558	12,290	3,276	107,440		(123,094	)	69,470
Noncontrolling interests	—	—	—	—		3,965		3,965
	69,558	12,290	3,276	107,440		(119,129	)	73,435
Total liabilities and equity	101,205	20,877	12,629	180,532		(148,338	)	166,905

1 Equity attributable to controlling interests for parent issuer and guarantor excludes reciprocal shareholding balance included within consolidating and elimination adjustments.

Condensed Cash Flow Statement

Condensed Consolidating Statements of Cash Flows for the three months ended March 31, 2019

	Parent Issuer and Guarantor		Subsidiary Issuer and Guarantor - SEP		Subsidiary Issuer and Guarantor - EEP		Subsidiary Non-Guarantors		Consolidating and elimination adjustments		Consolidated - Enbridge
(millions of Canadian dollars)
Net cash provided by/(used in) operating activities	(415	)	232		(1,418	)	4,566		(789	)	2,176
Investing activities
Capital expenditures	(24	)	—		—		(1,588	)	—		(1,612	)
Long-term investments and restricted long-term investments	—		(2	)	—		(563	)	—		(565	)
Distributions from equity investments in excess of cumulative earnings	—		7		536		132		(536	)	139
Additions to intangible assets	(16	)	—		—		(10	)	—		(26	)
Affiliate loans, net	—		—		—		(84	)	—		(84	)
Contributions to subsidiaries	(2,331	)	—		—		—		2,331		—
Return of share capital from subsidiaries	3,121		—		—		—		(3,121	)	—
Advances to affiliates	(19,908	)	—		(618	)	(21,542	)	42,068		—
Repayment of advances to affiliates	3,996		—		382		1,638		(6,016	)	—
Net cash provided by/(used in) investing activities	(15,162	)	5		300		(22,017	)	34,726		(2,148	)
Financing activities
Net change in short-term borrowings	—		—		—		(154	)	—		(154	)
Net change in commercial paper and credit facility draws	2,312		(2,010	)	—		2,471		—		2,773
Debenture and term note issues, net of issue costs	—		—		—		1,195		—		1,195
Debenture and term note repayments	(300	)	—		(1,189	)	(300	)	—		(1,789	)
Contributions from noncontrolling interests	—		—		—		—		3		3
Distributions to noncontrolling interests	—		—		—		—		(46	)	(46	)
Contributions from parents	—		—		—		2,331		(2,331	)	—
Distributions to parents	—		(505	)	(162	)	(3,822	)	4,489		—
Redemption of preferred shares	—		—		—		(300	)	—		(300	)
Common shares issued	18		—		—		—		—		18
Preference share dividends	(90	)	—		—		—		—		(90	)
Common share dividends	(1,513	)	—		—		27		—		(1,486	)
Advances from affiliates	15,150		3,498		2,894		20,526		(42,068	)	—
Repayment of advances from affiliates	—		(1,226	)	(412	)	(4,378	)	6,016		—
Other	—		(5	)	(6	)	(14	)	—		(25	)
Net cash (used in)/provided by financing activities	15,577		(248	)	1,125		17,582		(33,937	)	99
Effect of translation of foreign denominated cash and cash equivalents and restricted cash	—		—		—		(7	)	—		(7	)
Net increase/(decrease) in cash and cash equivalents and restricted cash	—		(11	)	7		124		—		120
Cash and cash equivalents and restricted cash at beginning of period	9		16		—		612		—		637
Cash and cash equivalents and restricted cash at end of period	9		5		7		736		—		757

Condensed Consolidating Statements of Cash Flows for the three months ended March 31, 2018

	Parent Issuer and Guarantor		Subsidiary Issuer and Guarantor - SEP		Subsidiary Issuer and Guarantor - EEP		Subsidiary Non-Guarantors		Consolidating and elimination adjustments		Consolidated - Enbridge
(millions of Canadian dollars)
Net cash (used in)/provided by operating activities	(135	)	803		(331	)	3,224		(367	)	3,194
Investing activities
Capital expenditures	(5	)	—		—		(1,630	)	—		(1,635	)
Long-term investments and restricted long-term investments	(16	)	(5	)	—		(217	)	16		(222	)
Distributions from equity investments in excess of cumulative earnings	336		15		488		42		(824	)	57
Additions to intangible assets	(6	)	—		—		(252	)	—		(258	)
Affiliate loans, net	—		—		—		(10	)	—		(10	)
Contributions to subsidiaries	(69	)	(77	)	(5	)	—		151		—
Advances to affiliates	(401	)	—		(496	)	(2,233	)	3,130		—
Repayment of advances to affiliates	—		506		548		1,890		(2,944	)	—
Net cash (used in)/provided by investing activities	(161	)	439		535		(2,410	)	(471	)	(2,068	)
Financing activities
Net change in short-term borrowings	—		—		—		(443	)	—		(443	)
Net change in commercial paper and credit facility draws	(105	)	(756	)	(218	)	614		—		(465	)
Debenture and term note issues, net of issue costs	1,080		—		—		981		—		2,061
Debenture and term note repayments	—		—		—		(996	)	—		(996	)
Debt extinguishment costs	—		—		—		(63	)	—		(63	)
Contributions from noncontrolling interests	—		—		—		—		8		8
Distributions to noncontrolling interests	—		—		—		—		(209	)	(209	)
Contributions from redeemable noncontrolling interests	—		—		—		—		20		20
Distributions to redeemable noncontrolling interests	—		—		—		—		(84	)	(84	)
Contributions from parents	—		—		—		151		(151	)	—
Distributions to parents	—		(453	)	(163	)	(824	)	1,440		—
Common shares issued	13		—		—		—		—		13
Preference share dividends	(87	)	—		—		—		—		(87	)
Common share dividends	(764	)	—		—		—		—		(764	)
Advances from affiliates	209		—		2,024		897		(3,130	)	—
Repayment of advances from affiliates	(43	)	—		(1,847	)	(1,054	)	2,944		—
Net cash provided by/(used in) financing activities	303		(1,209	)	(204	)	(737	)	838		(1,009	)
Effect of translation of foreign denominated cash and cash equivalents and restricted cash	—		—		—		19		—		19
Net increase in cash and cash equivalents and restricted cash	7		33		—		96		—		136
Cash and cash equivalents and restricted cash at beginning of period	2		14		—		571		—		587
Cash and cash equivalents and restricted cash at end of period	9		47		—		667		—		723

XML

CHANGES IN ACCOUNTING POLICIES (Details) - CAD ($) $ in Millions	Jan. 01, 2019	Mar. 31, 2019
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operating lease right-of-use assets, net	$ 771	$ 745
Lease impairment	85
Operating lease liability	$ 856	$ 824
Weighted average discount rate, percent	4.30%	4.30%
Accounting Standards Update 2016-02 [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operating lease right-of-use assets, net	$ 771
Operating lease liability	$ 856
Weighted average discount rate, percent	4.32%

XML

REVENUES (Details) $ in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2019 USD ($)	Mar. 31, 2019 CAD ($)	Mar. 31, 2018 USD ($)	Mar. 31, 2018 CAD ($)
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		$ 5,756		$ 6,296
Revenues		12,856		12,726
Transferred at Point in Time
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		17		718
Transferred over Time
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		5,739		5,578
Transportation revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		3,600		3,249
Storage and Other Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		134		166
Gas Gathering and Processing Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		116		205
Gas Distribution
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		1,856		1,926
Revenues		1,876		1,926
Electricity and Transmission Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		50		57
Commodity
Disaggregation of Revenue [Line Items]
Revenue from contract with customer				693
Revenue not from contract with customers		6,632		6,575
Revenues		6,632		7,268
Other Revenue
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers		468		(145)
Liquids Pipelines
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		2,241		2,098
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		2,241		2,098
Gas Transmission and Midstream
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		1,306		1,910
Gas Transmission and Midstream | Transferred at Point in Time
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		0		693
Gas Transmission and Midstream | Transferred over Time
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		1,306		1,217
Gas Distribution
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		2,159		2,231
Gas Distribution | Transferred at Point in Time
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		17		25
Gas Distribution | Transferred over Time
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		2,142		2,206
Renewable Power Generation and Transmission
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		50		57
Renewable Power Generation and Transmission | Transferred at Point in Time
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		0		0
Renewable Power Generation and Transmission | Transferred over Time
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		50		57
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		2,241		2,098
Revenues		2,658		1,909
Business segments | Liquids Pipelines | Transportation revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		2,214		2,058
Business segments | Liquids Pipelines | Storage and Other Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		27		40
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
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
Disaggregation of Revenue [Line Items]
Revenue from contract with customer				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		340		(269)
Business segments | Gas Transmission and Midstream
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		1,306		1,910
Revenues		1,318		1,937
Business segments | Gas Transmission and Midstream | Transportation revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		1,137		952
Business segments | Gas Transmission and Midstream | Storage and Other Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		53		60
Business segments | Gas Transmission and Midstream | Gas Gathering and Processing Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		116		205
Business segments | Gas Transmission and Midstream | Gas Distribution
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
Disaggregation of Revenue [Line Items]
Revenue from contract with customer				693
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		10		25
Business segments | Gas Distribution
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		2,159		2,231
Revenues		2,191		2,237
Business segments | Gas Distribution | Transportation revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		249		239
Business segments | Gas Distribution | Storage and Other Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		54		66
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
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		1,856		1,926
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
Disaggregation of Revenue [Line Items]
Revenue from contract with customer				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		29		2
Business segments | Renewable Power Generation and Transmission
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		50		57
Revenues		152		157
Business segments | Renewable Power Generation and Transmission | Transportation revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		0		0
Business segments | Renewable Power Generation and Transmission | Storage and Other Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		0		0
Business segments | Renewable Power Generation and Transmission | Gas Gathering and Processing Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		0		0
Business segments | Renewable Power Generation and Transmission | Gas Distribution
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		0		0
Business segments | Renewable Power Generation and Transmission | Electricity and Transmission Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		50		57
Business segments | Renewable Power Generation and Transmission | Commodity
Disaggregation of Revenue [Line Items]
Revenue from contract with customer				0
Revenue not from contract with customers		0		0
Business segments | Renewable Power Generation and Transmission | Other Revenue
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers		102		100
Business segments | Energy Services
Disaggregation of Revenue [Line Items]
Revenue from contract with customer		0		0
Revenues		6,673		6,632
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
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
Disaggregation of Revenue [Line Items]
Revenue from contract with customer				0
Revenue not from contract with customers		6,632		6,575
Business segments | Energy Services | Other Revenue
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers		6		0
Eliminations and Other
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	$ 0		$ 0
Revenues		(136)		(146)
Eliminations and Other | Transportation revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0		0
Eliminations and Other | Storage and Other Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0		0
Eliminations and Other | Gas Gathering and Processing Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0		0
Eliminations and Other | Gas Distribution
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	0		0
Eliminations and Other | Electricity and Transmission Revenue
Disaggregation of Revenue [Line Items]
Revenue from contract with customer	$ 0		0
Eliminations and Other | Commodity
Disaggregation of Revenue [Line Items]
Revenue from contract with customer			$ 0
Revenue not from contract with customers		0		0
Eliminations and Other | Other Revenue
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers		(19)		(3)
Intersegment Eliminations
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers		(117)		(143)
Revenues		(136)		(146)
Intersegment Eliminations | Liquids Pipelines
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers		77		80
Intersegment Eliminations | Gas Transmission and Midstream
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers		2		2
Intersegment Eliminations | Gas Distribution
Disaggregation of Revenue [Line Items]
Revenue not from contract with customers		3		4
Intersegment Eliminations | Renewable Power Generation 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		$ 35		$ 57

XML

REVENUES - Contract Balances (Details) - CAD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
Revenue from Contract with Customer [Abstract]
Accounts receivable, net	$ 2,338	$ 1,929
Contract with customer, asset	191	191
Contract with customer, liability	$ 1,262	$ 1,297

XML

REVENUES - Narrative (Details) $ in Millions	3 Months Ended
	Mar. 31, 2019 CAD ($)
Revenue from Contract with Customer [Abstract]
Revenue recognized	$ 92
Increase (decrease) in contract with customers, liability	74
Remaining performance obligation	66,700
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-04-01
Revenue from Contract with Customer [Abstract]
Remaining performance obligation	$ 5,300
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]: 2020-04-01
Revenue from Contract with Customer [Abstract]
Remaining performance obligation	$ 5,800

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SEGMENTED INFORMATION (Details) - CAD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Segmented Information
Revenues	$ 12,856	$ 12,726
Commodity and gas distribution costs	(7,772)	(8,321)
Operating and administrative	(1,625)	(1,641)
Asset impairment	0	(1,062)
Income/(loss) from equity investments	413	335
Other	260	(120)
Earnings/(loss) before interest and income taxes	4,132	1,917
Depreciation and amortization	(840)	(824)
Interest expense	(685)	(656)
Income tax recovery/(expense)	(584)	73
Earnings	2,023	510
Capital expenditures	1,627	1,643
Intersegment Eliminations
Segmented Information
Revenues	(136)	(146)
Commodity and gas distribution costs	128	146
Operating and administrative	58	(97)
Asset impairment		(5)
Income/(loss) from equity investments	1	0
Other	197	(177)
Earnings/(loss) before interest and income taxes	248	(279)
Capital expenditures	25	6
Liquids Pipelines | Business segments
Segmented Information
Revenues	2,658	1,909
Commodity and gas distribution costs	(6)	(4)
Operating and administrative	(801)	(747)
Asset impairment		(144)
Income/(loss) from equity investments	197	131
Other	24	11
Earnings/(loss) before interest and income taxes	2,072	1,156
Capital expenditures	1,020	615
Gas Transmission and Midstream | Business segments
Segmented Information
Revenues	1,318	1,937
Commodity and gas distribution costs	0	(620)
Operating and administrative	(513)	(507)
Asset impairment		(913)
Income/(loss) from equity investments	197	208
Other	18	21
Earnings/(loss) before interest and income taxes	1,020	126
Capital expenditures	394	825
Gas Distribution | Business segments
Segmented Information
Revenues	2,191	2,237
Commodity and gas distribution costs	(1,264)	(1,388)
Operating and administrative	(294)	(248)
Asset impairment		0
Income/(loss) from equity investments	11	17
Other	18	18
Earnings/(loss) before interest and income taxes	662	636
Capital expenditures	173	183
Renewable Power Generation and Transmission | Business segments
Segmented Information
Revenues	152	157
Commodity and gas distribution costs	(1)	0
Operating and administrative	(42)	(30)
Asset impairment		0
Income/(loss) from equity investments	14	(25)
Other	1	7
Earnings/(loss) before interest and income taxes	124	109
Capital expenditures	14	14
Energy Services | Business segments
Segmented Information
Revenues	6,673	6,632
Commodity and gas distribution costs	(6,629)	(6,455)
Operating and administrative	(33)	(12)
Asset impairment		0
Income/(loss) from equity investments	(7)	4
Other	2	0
Earnings/(loss) before interest and income taxes	6	169
Capital expenditures	$ 1	$ 0

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EARNINGS PER COMMON SHARE AND DIVIDEND PER SHARE - Basic (Details) - shares shares in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Earnings Per Share [Abstract]
Prorata weighted average interest in entity's own common shares (in shares)	6	13

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EARNINGS PER COMMON SHARE AND DIVIDEND PER SHARE - Diluted (Details) - $ / shares	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Weighted average number of common shares outstanding diluted
Weighted average common shares outstanding (in shares)	2,016,000,000	1,685,000,000
Effect of dilutive options (in shares)	3,000,000	4,000,000
Diluted weighted average common shares outstanding (in shares)	2,019,000,000	1,689,000,000
Stock options
Weighted average number of common shares outstanding diluted
Antidilutive securities excluded from the diluted earnings per common share calculation (in shares)	10,495,198	29,882,142
Weighted average exercise price of antidilutive securities (in Canadian dollars per share)	$ 55.32	$ 49.80

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EARNINGS PER COMMON SHARE AND DIVIDEND PER SHARE - Dividend Per Share (Details)	1 Months Ended		2 Months Ended		3 Months Ended
	Mar. 31, 2019 $ / shares	Mar. 31, 2019 $ / shares	Feb. 28, 2019 $ / shares	Feb. 28, 2019 $ / shares	Mar. 31, 2019 $ / shares	Mar. 31, 2019 $ / shares
Common shares
Dividends Payable [Line Items]
Common stock, dividends, per share, declared (in dollars per share)					$ 0.73800
Preference Shares, Series A | Preferred share investment
Dividends Payable [Line Items]
Dividend per share (in dollars per share)					0.34375
Preference Shares, Series B | Preferred share investment
Dividends Payable [Line Items]
Dividend per share (in dollars per share)					0.21340
Preference Shares, Series C | Preferred share investment
Dividends Payable [Line Items]
Dividend per share (in dollars per share)	$ 0.25395		$ 0.25459		0.25395
Preference Shares, Series D | Preferred share investment
Dividends Payable [Line Items]
Dividend per share (in dollars per share)					0.27875
Preference Shares, Series F | Preferred share investment
Dividends Payable [Line Items]
Dividend per share (in dollars per share)					0.29306
Preference Shares, Series H | Preferred share investment
Dividends Payable [Line Items]
Dividend per share (in dollars per share)					0.27350
Preference Shares, Series J | Preferred share investment
Dividends Payable [Line Items]
Dividend per share (in dollars per share)						$ 0.30540
Preference Shares, Series L | Preferred share investment
Dividends Payable [Line Items]
Dividend per share (in dollars per share)						0.30993
Preference Shares, Series N | Preferred share investment
Dividends Payable [Line Items]
Dividend per share (in dollars per share)					0.31788
Preference Shares, Series P | Preferred share investment
Dividends Payable [Line Items]
Dividend per share (in dollars per share)	0.27369		0.25000		0.27369
Preference Shares, Series R | Preferred share investment
Dividends Payable [Line Items]
Dividend per share (in dollars per share)					0.25000
Preference Shares, Series 1 | Preferred share investment
Dividends Payable [Line Items]
Dividend per share (in dollars per share)						0.37182
Preference Shares, Series 3 | Preferred share investment
Dividends Payable [Line Items]
Dividend per share (in dollars per share)					0.25000
Preference Shares, Series 5 | Preferred share investment
Dividends Payable [Line Items]
Dividend per share (in dollars per share)		$ 0.33596		$ 0.27500		$ 0.33596
Preference Shares, Series 7 | Preferred share investment
Dividends Payable [Line Items]
Dividend per share (in dollars per share)	$ 0.27806		$ 0.27500		0.27806
Preference Shares, Series 9 | Preferred share investment
Dividends Payable [Line Items]
Dividend per share (in dollars per share)					0.27500
Preference Shares, Series 11 | Preferred share investment
Dividends Payable [Line Items]
Dividend per share (in dollars per share)					0.27500
Preference Shares, Series 13 | Preferred share investment
Dividends Payable [Line Items]
Dividend per share (in dollars per share)					0.27500
Preference Shares, Series 15 | Preferred share investment
Dividends Payable [Line Items]
Dividend per share (in dollars per share)					0.27500
Preference Shares, Series 17 | Preferred share investment
Dividends Payable [Line Items]
Dividend per share (in dollars per share)					0.32188
Preference Shares, Series 19 | Preferred share investment
Dividends Payable [Line Items]
Dividend per share (in dollars per share)					$ 0.30625

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AQUISITIONS AND DISPOSITIONS - Narrative (Details) $ in Millions, $ in Millions	1 Months Ended			3 Months Ended
	Jan. 31, 2019 CAD ($)	Aug. 31, 2017 USD ($)	Aug. 31, 2017 CAD ($)	Mar. 31, 2019 CAD ($)	Mar. 31, 2018 CAD ($)	Jun. 30, 2019 CAD ($)	Dec. 31, 2018 CAD ($)	Oct. 01, 2018 CAD ($)	Jul. 04, 2018 CAD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Cash consideration for acquisition of property, plant and equipment	$ 265			$ 1,612	$ 1,635
Disposal Group, Held-for-sale, Not Discontinued Operations | Enbridge Gas New Brunswick
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal group, consideration							$ 331
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
Disposed of by sale, not discontinued operations | Canadian Natural Gas Gathering and Processing Business
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal group, consideration								$ 2,500
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
Enbridge Gas Distribution | Disposal Group, Held-for-sale, Not Discontinued Operations | St. Lawrence Gas Company
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from divestiture of interest in subsidiaries and affiliates		$ 70	$ 94

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AQUISITIONS AND DISPOSITIONS - Assets Held for Sale (Details) - Disposal Group, Held-for-sale, Not Discontinued Operations - CAD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Accounts receivable and other (current assets held for sale)	$ 101	$ 117
Deferred amounts and other assets (long-term assets held for sale)	2,415	2,383
Accounts payable and other (current liabilities held for sale)	(55)	(63)
Other long-term liabilities (long-term liabilities held for sale)	(99)	(96)
Net assets held for sale	2,362	2,341
Property, plant and equipment, noncurrent	$ 2,200	$ 2,100

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VARIABLE INTEREST ENTITIES (Details)	1 Months Ended
	Dec. 31, 2018 CAD ($)	Mar. 31, 2019 CAD ($)	Mar. 29, 2019 USD ($)
VIE, Not Primary Beneficiary
Variable Interest Entity, Not Primary Beneficiary
Ownership interest in VIE (as a percent)	22.80%
Carrying amount of investment	$ 0	$ 455,000,000
VEI, maximum loss exposure, amount		$ 931,000,000
Gray Oak Holdings LLC
Variable Interest Entity, Not Primary Beneficiary
Ownership interest in VIE (as a percent)	35.00%
Maximum borrowing capacity			$ 280,000,000
Gray Oak Holdings LLC and Enbridge Inc | Gray Oak Holdings LLC
Variable Interest Entity, Not Primary Beneficiary
Maximum borrowing capacity			$ 1,230,000,000

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DEBT - Credit Facilities (Details) - Committed credit facilities $ in Millions	Mar. 31, 2019 CAD ($)
CREDIT FACILITIES
Total Facilities	$ 18,502
Draws	11,963
Available	6,539
Enbridge Inc.
CREDIT FACILITIES
Total Facilities	6,137
Draws	4,319
Available	1,818
Enbridge (U.S.) Inc.
CREDIT FACILITIES
Total Facilities	7,348
Draws	5,252
Available	2,096
Enbridge Pipelines Inc.
CREDIT FACILITIES
Total Facilities	3,000
Draws	1,513
Available	1,487
Union Gas Limited
CREDIT FACILITIES
Total Facilities	2,017
Draws	879
Available	$ 1,138

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DEBT - Narrative (Details) - CAD ($)	3 Months Ended
	Mar. 31, 2019	Dec. 31, 2018
Line of Credit Facility [Line Items]
Line of credit facility, increase (decrease), net	$ 444,000,000
Commitment fee percentage	0.10%
Long-term debt	$ 60,680,000,000	$ 60,327,000,000
Long-term debt, fair value adjustment	930,000,000
Amortization of fair value adjustment	17,000,000
Uncommitted demand credit facilities
Line of Credit Facility [Line Items]
Amount of credit facility	800,000,000	807,000,000
Unutilized amount of facility	516,000,000	548,000,000
Commercial paper and credit facility draws
Line of Credit Facility [Line Items]
Long-term debt	10,689,000,000	7,967,000,000
Subordinated Debt | Fixed To Floating Subordinated Term Notes
Line of Credit Facility [Line Items]
Subordinated debt	$ 6,675,000,000	$ 7,317,000,000

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DEBT - Long Term Debt Issuance (Details) - Enbridge Pipelines Inc.	Feb. 28, 2019 CAD ($)
3.52% Medium Term Notes Due February 2029
DEBT
Face amount of notes issued	$ 600,000,000
Interest rate (as a percent)	3.52%
4.33% Medium Term Notes Due February 2049
DEBT
Face amount of notes issued	$ 600,000,000
Interest rate (as a percent)	4.33%

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DEBT - Long Term Debt Repayments (Details) $ in Millions, $ in Millions	1 Months Ended
	Mar. 31, 2019 USD ($)	Feb. 28, 2019 USD ($)	Feb. 28, 2019 CAD ($)	Jan. 31, 2019 CAD ($)
Enbridge Energy Partners, L.P. | 8.05% Fixed To Floating Rate Junior Subordinated Notes Due 2067
DEBT
Extinguishment of debt		$ 400
Interest rate (as a percent)		8.05%	8.05%
Enbridge Energy Partners, L.P. | 9.88% Senior Notes
DEBT
Extinguishment of debt	$ 500
Interest rate (as a percent)	9.88%
Westcoast Energy Inc | 5.60% Medium-Term Notes
DEBT
Extinguishment of debt				$ 250
Interest rate (as a percent)				5.60%
Westcoast Energy Inc | 5.60% Medium-term Notes
DEBT
Extinguishment of debt				$ 50
Enbridge Inc. | 4.10% Medium-Term Notes Due February 2019
DEBT
Extinguishment of debt			$ 300
Interest rate (as a percent)		4.10%	4.10%

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COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME (Details) - CAD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Changes in AOCI
Balance at the beginning of the period	$ 69,470
Other comprehensive income/(loss) retained in AOCI	(1,437)	$ 1,284
Other comprehensive (income)/loss reclassified to earnings, cash flow hedges	25
Other comprehensive (income)/loss reclassified to earnings, pension and OPEB	53	(38)
Total before tax impact	(1,359)	1,286
Income tax on amounts retained in AOCI	110	28
Income tax on amounts reclassified to earnings	(29)	(12)
Tax impact	81	16
Other	55
Balance at the end of the period	70,305
Interest rate contracts
Changes in AOCI
Other comprehensive (income)/loss reclassified to earnings, cash flow hedges	32
Other comprehensive income (loss), reclassification adjustment to earnings, cash flow hedge		28
Commodity contracts
Changes in AOCI
Other comprehensive (income)/loss reclassified to earnings, cash flow hedges	0
Other comprehensive income (loss), reclassification adjustment to earnings, cash flow hedge		(1)
Foreign exchange contracts
Changes in AOCI
Other comprehensive (income)/loss reclassified to earnings, cash flow hedges	2
Other comprehensive income (loss), reclassification adjustment to earnings, cash flow hedge		4
Other contracts
Changes in AOCI
Other comprehensive (income)/loss reclassified to earnings, cash flow hedges	(9)
Other comprehensive income (loss), reclassification adjustment to earnings, cash flow hedge		9
Accumulated other comprehensive income
Changes in AOCI
Balance at the beginning of the period	2,672	(973)
Balance at the end of the period	1,449	329
Cash Flow Hedge
Changes in AOCI
Balance at the beginning of the period	(770)
Other comprehensive income/(loss) retained in AOCI	(312)
Total before tax impact	(287)
Income tax on amounts retained in AOCI	121
Income tax on amounts reclassified to earnings	(14)
Tax impact	107
Balance at the end of the period	(950)
Cash Flow Hedge | Interest rate contracts
Changes in AOCI
Other comprehensive (income)/loss reclassified to earnings	32
Cash Flow Hedge | Foreign exchange contracts
Changes in AOCI
Other comprehensive (income)/loss reclassified to earnings	2
Cash Flow Hedge | Other contracts
Changes in AOCI
Other comprehensive (income)/loss reclassified to earnings	(9)
Cash Flow Hedges
Changes in AOCI
Balance at the beginning of the period		(644)
Other comprehensive income/(loss) retained in AOCI		70
Total before tax impact		110
Income tax on amounts retained in AOCI		(9)
Income tax on amounts reclassified to earnings		(11)
Tax impact		(20)
Balance at the end of the period		(554)
Cash Flow Hedges | Interest rate contracts
Changes in AOCI
Other comprehensive (income)/loss reclassified to earnings		28
Cash Flow Hedges | Commodity contracts
Changes in AOCI
Other comprehensive (income)/loss reclassified to earnings		(1)
Cash Flow Hedges | Foreign exchange contracts
Changes in AOCI
Other comprehensive (income)/loss reclassified to earnings		4
Cash Flow Hedges | Other contracts
Changes in AOCI
Other comprehensive (income)/loss reclassified to earnings		9
Net Investment Hedges
Changes in AOCI
Balance at the beginning of the period	(598)	(139)
Other comprehensive income/(loss) retained in AOCI	109	(213)
Total before tax impact	109	(213)
Income tax on amounts retained in AOCI	(15)	29
Tax impact	(15)	29
Balance at the end of the period	(504)	(323)
Cumulative Translation Adjustment
Changes in AOCI
Balance at the beginning of the period	4,323	77
Other comprehensive income/(loss) retained in AOCI	(1,242)	1,425
Total before tax impact	(1,242)	1,425
Balance at the end of the period	3,081	1,502
Equity Investees
Changes in AOCI
Balance at the beginning of the period	34	10
Other comprehensive income/(loss) retained in AOCI	8	2
Total before tax impact	8	2
Income tax on amounts retained in AOCI	4	8
Tax impact	4	8
Balance at the end of the period	46	20
Pension and OPEB Adjustment
Changes in AOCI
Balance at the beginning of the period	(317)	(277)
Other comprehensive (income)/loss reclassified to earnings	53	(38)
Total before tax impact	53	(38)
Income tax on amounts reclassified to earnings	(15)	(1)
Tax impact	(15)	(1)
Other	55
Balance at the end of the period	$ (224)	$ (316)

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NONCONTROLLING INTERESTS (Details) $ / shares in Units, $ in Millions	Mar. 20, 2019 CAD ($) $ / shares
Noncontrolling Interest [Line Items]
Dividends	$ 300
Noncontrolling interest, period decrease	300
Preferred share investment
Noncontrolling Interest [Line Items]
Payments of Dividends	$ 4
Preferred share investment | Preference Shares, Series 7
Noncontrolling Interest [Line Items]
Preferred stock, dividend rate, percentage	5.50%
Preferred stock, redemption price per share (in Canadian dollars per share) | $ / shares	$ 25.00
Preferred share investment | Preference Shares, Series 8
Noncontrolling Interest [Line Items]
Preferred stock, dividend rate, percentage	5.60%
Preferred stock, redemption price per share (in Canadian dollars per share) | $ / shares	$ 25.00

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RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Market Risk (Details)	3 Months Ended
	Mar. 31, 2019 Number_of_equity
Interest rate contracts - short-term borrowings
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
Average swap rate, variable (as a percent)	2.80%
Interest rate contracts - long-term debt
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
Average swap rate, variable (as a percent)	3.00%
Equity contracts
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
Number of forms of stock-based compensation with equity price risk	1
Maximum
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
Floating rate debt as target percentage of total debt outstanding	30.00%

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RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Total Derivative Instruments (Details) - CAD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	$ (2,860)	$ (3,210)
Derivative liabilities, Total Net Derivative Instruments	(2,860)	(3,210)
Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(2,356)	(2,894)
Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(490)	(301)
Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(14)	(15)
Accounts receivable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	205	498
Derivative assets, Amounts Available for Offset	(103)	(153)
Derivative assets, Total Net Derivative Instruments	102	345
Accounts receivable and other | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	197	474
Accounts receivable and other | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	8	24
Accounts receivable and other | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	0	0
Deferred amounts and other assets
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	87	119
Derivative assets, Amounts Available for Offset	(58)	(60)
Derivative assets, Total Net Derivative Instruments	29	59
Deferred amounts and other assets | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	56	72
Deferred amounts and other assets | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	31	47
Deferred amounts and other assets | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	0	0
Accounts payable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	(946)	(1,234)
Derivative liabilities, Amounts Available for Offset	103	153
Derivative liabilities, Total Net Derivative Instruments	(843)	(1,081)
Accounts payable and other | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	(791)	(1,065)
Accounts payable and other | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	(155)	(169)
Accounts payable and other | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	0	0
Other long-term liabilities
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	(2,206)	(2,593)
Derivative liabilities, Amounts Available for Offset	58	60
Derivative liabilities, Total Net Derivative Instruments	(2,148)	(2,533)
Other long-term liabilities | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	(1,818)	(2,375)
Other long-term liabilities | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	(374)	(203)
Other long-term liabilities | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	(14)	(15)
Foreign exchange contracts
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(2,110)	(2,718)
Derivative liabilities, Total Net Derivative Instruments	(2,110)	(2,718)
Foreign exchange contracts | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(2,104)	(2,720)
Foreign exchange contracts | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	8	17
Foreign exchange contracts | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(14)	(15)
Foreign exchange contracts | Accounts receivable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	26	47
Derivative assets, Amounts Available for Offset	(26)	(37)
Derivative assets, Total Net Derivative Instruments	0	10
Foreign exchange contracts | Accounts receivable and other | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	26	47
Foreign exchange contracts | Accounts receivable and other | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	0	0
Foreign exchange contracts | Accounts receivable and other | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	0	0
Foreign exchange contracts | Deferred amounts and other assets
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	50	62
Derivative assets, Amounts Available for Offset	(36)	(39)
Derivative assets, Total Net Derivative Instruments	14	23
Foreign exchange contracts | Deferred amounts and other assets | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	37	39
Foreign exchange contracts | Deferred amounts and other assets | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	13	23
Foreign exchange contracts | Deferred amounts and other assets | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	0	0
Foreign exchange contracts | Accounts payable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	(506)	(615)
Derivative liabilities, Amounts Available for Offset	26	37
Derivative liabilities, Total Net Derivative Instruments	(480)	(578)
Foreign exchange contracts | Accounts payable and other | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	(501)	(610)
Foreign exchange contracts | Accounts payable and other | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	(5)	(5)
Foreign exchange contracts | Accounts payable and other | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	0	0
Foreign exchange contracts | Other long-term liabilities
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	(1,680)	(2,212)
Derivative liabilities, Amounts Available for Offset	36	39
Derivative liabilities, Total Net Derivative Instruments	(1,644)	(2,173)
Foreign exchange contracts | Other long-term liabilities | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	(1,666)	(2,196)
Foreign exchange contracts | Other long-term liabilities | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	0	(1)
Foreign exchange contracts | Other long-term liabilities | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	(14)	(15)
Interest rate contracts
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(517)	(515)
Derivative liabilities, Total Net Derivative Instruments	(517)	(515)
Interest rate contracts | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	0	(178)
Interest rate contracts | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(517)	(337)
Interest rate contracts | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	0	0
Interest rate contracts | Accounts receivable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	7	22
Derivative assets, Amounts Available for Offset	0	(2)
Derivative assets, Total Net Derivative Instruments	7	20
Interest rate contracts | Accounts receivable and other | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	0	0
Interest rate contracts | Accounts receivable and other | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	7	22
Interest rate contracts | Accounts receivable and other | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	0	0
Interest rate contracts | Deferred amounts and other assets
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	0	5
Derivative assets, Amounts Available for Offset	0	0
Derivative assets, Total Net Derivative Instruments	0	5
Interest rate contracts | Deferred amounts and other assets | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	0	0
Interest rate contracts | Deferred amounts and other assets | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	0	5
Interest rate contracts | Deferred amounts and other assets | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	0	0
Interest rate contracts | Accounts payable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	(150)	(341)
Derivative liabilities, Amounts Available for Offset	0	2
Derivative liabilities, Total Net Derivative Instruments	(150)	(339)
Interest rate contracts | Accounts payable and other | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	0	(178)
Interest rate contracts | Accounts payable and other | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	(150)	(163)
Interest rate contracts | Accounts payable and other | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	0	0
Interest rate contracts | Other long-term liabilities
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	(374)	(201)
Derivative liabilities, Amounts Available for Offset	0	0
Derivative liabilities, Total Net Derivative Instruments	(374)	(201)
Interest rate contracts | Other long-term liabilities | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	0	0
Interest rate contracts | Other long-term liabilities | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	(374)	(201)
Interest rate contracts | Other long-term liabilities | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	0	0
Commodity contracts
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(234)	30
Derivative liabilities, Total Net Derivative Instruments	(234)	30
Commodity contracts | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	(252)	9
Commodity contracts | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	18	21
Commodity contracts | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	0	0
Commodity contracts | Accounts receivable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	172	429
Derivative assets, Amounts Available for Offset	(77)	(114)
Derivative assets, Total Net Derivative Instruments	95	315
Commodity contracts | Accounts receivable and other | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	171	427
Commodity contracts | Accounts receivable and other | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	1	2
Commodity contracts | Accounts receivable and other | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	0	0
Commodity contracts | Deferred amounts and other assets
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	35	52
Derivative assets, Amounts Available for Offset	(22)	(21)
Derivative assets, Total Net Derivative Instruments	13	31
Commodity contracts | Deferred amounts and other assets | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	18	33
Commodity contracts | Deferred amounts and other assets | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	17	19
Commodity contracts | Deferred amounts and other assets | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	0	0
Commodity contracts | Accounts payable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	(289)	(273)
Derivative liabilities, Amounts Available for Offset	77	114
Derivative liabilities, Total Net Derivative Instruments	(212)	(159)
Commodity contracts | Accounts payable and other | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	(289)	(273)
Commodity contracts | Accounts payable and other | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	0	0
Commodity contracts | Accounts payable and other | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	0	0
Commodity contracts | Other long-term liabilities
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	(152)	(178)
Derivative liabilities, Amounts Available for Offset	22	21
Derivative liabilities, Total Net Derivative Instruments	(130)	(157)
Commodity contracts | Other long-term liabilities | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	(152)	(178)
Commodity contracts | Other long-term liabilities | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	0	0
Commodity contracts | Other long-term liabilities | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	0	0
Other contracts
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	1	(7)
Derivative liabilities, Total Net Derivative Instruments	1	(7)
Other contracts | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	0	(5)
Other contracts | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	1	(2)
Other contracts | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Total net derivative asset/(liability)	0	0
Other contracts | Deferred amounts and other assets
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	2
Derivative assets, Amounts Available for Offset	0
Derivative assets, Total Net Derivative Instruments	2
Other contracts | Deferred amounts and other assets | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	1
Other contracts | Deferred amounts and other assets | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	1
Other contracts | Deferred amounts and other assets | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative assets	0
Other contracts | Accounts payable and other
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	(1)	(5)
Derivative liabilities, Amounts Available for Offset	0	0
Derivative liabilities, Total Net Derivative Instruments	(1)	(5)
Other contracts | Accounts payable and other | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	(1)	(4)
Other contracts | Accounts payable and other | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	0	(1)
Other contracts | Accounts payable and other | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	0	0
Other contracts | Other long-term liabilities
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	0	(2)
Derivative liabilities, Amounts Available for Offset	0	0
Derivative liabilities, Total Net Derivative Instruments	0	(2)
Other contracts | Other long-term liabilities | Non-Qualifying Derivative Instruments
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	0	(1)
Other contracts | Other long-term liabilities | Cash Flow Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	0	(1)
Other contracts | Other long-term liabilities | Net Investment Hedges | Designated as hedging instrument
TOTAL DERIVATIVE INSTRUMENTS
Derivative liabilities	$ 0	$ 0

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RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Notional Principal or Quantity Information (Details) - Mar. 31, 2019 € in Millions, ¥ in Millions, £ in Millions, MMBbls in Millions, $ in Millions, $ in Millions, Bcf in Billions	USD ($) MWh Bcf MMBbls	CAD ($) MWh Bcf MMBbls	GBP (£) MWh Bcf MMBbls	EUR (€) MWh Bcf MMBbls	JPY (¥) MWh Bcf MMBbls
Euro
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2020 | €				€ 23
2021 | €				94
Foreign exchange contracts - forwards - purchase | United States dollar
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2019	$ 895
2020	1
Foreign exchange contracts - forwards - purchase | Euro
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2019 | €				168
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
2019	3,839
2020	4,893
2021	3,608
2022	1,944
2023	1,804
Thereafter	$ 1,856
Foreign exchange contracts - forwards - sell | GBP
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2019 | £			£ 86
2020 | £			25
2021 | £			27
2022 | £			28
2023 | £			29
Thereafter | £			£ 120
Foreign exchange contracts - forwards - sell | Euro
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2022 | €				94
2023 | €				92
Thereafter | €				€ 606
Interest rate contracts - short-term borrowings
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2019		$ 6,629
2020		6,178
2021		4,142
2022		407
2023		48
Thereafter		156
Interest rate contracts - long-term receive fixed rate
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2019		0
2020		0
2021		0
2022		0
2023		0
Interest rate contracts - long-term debt pay fixed rate
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2019		2,537
2020		3,142
2021		1,584
Equity contracts
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2019		32
2020		$ 20
Commodity contracts | Natural gas
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2019 | Bcf	(75)	(75)	(75)	(75)	(75)
2020 | Bcf	(15)	(15)	(15)	(15)	(15)
2022 | Bcf	(84)	(84)	(84)	(84)	(84)
2023 | Bcf	1	1	1	1	1
Commodity contracts | Crude oil
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2019 | MMBbls	4	4	4	4	4
2020 | MMBbls	(2)	(2)	(2)	(2)	(2)
Commodity contracts | NGL
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2019 | MMBbls	1	1	1	1	1
Commodity contracts | Power
RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
2019 | MWh	98	98	98	98	98
2020 | MWh	80	80	80	80	80
2021 | MWh	(3)	(3)	(3)	(3)	(3)
2022 | MWh	(43)	(43)	(43)	(43)	(43)
2023 | MWh	(43)	(43)	(43)	(43)	(43)
Thereafter | MWh	(43)	(43)	(43)	(43)	(43)

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RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Earnings and Comprehensive Income (Details) - CAD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Cash flow hedge, amount of unrealized gain (loss) recognized in OCI	$ (296)
Cash flow hedge, amount of unrealized gain (loss) recognized in OCI		$ 121
Amount of (gain) loss reclassified from AOCI to earnings	25
Amount of (gain) loss reclassified from AOCI to earnings		47
Estimated gain of AOCI related to cash flow hedges reclassified to earnings in the next 12 months	$ 36
Period to hedge exposures to the variability of cash flows for all forecasted transactions	33 months
Unrealized gain/(loss) on derivative		(8)
Unrealized gain/(loss) on hedged item		8
Realized gain/(loss) on derivative		(3)
Realized gain/(loss) on hedged item		3
Unrealized gain (loss) on derivatives	$ 538	(260)
Non-Qualifying Derivative Instruments
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain (loss) on derivatives	538	(260)
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	2
Amount of (gain) loss reclassified from AOCI to earnings		(1)
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	616	(424)
Foreign exchange contracts | Non-Qualifying Derivative Instruments | Transportation and other services
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain (loss) on derivatives	352	(297)
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	264	(127)
Foreign exchange contracts | Cash Flow Hedges
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Cash flow hedge, amount of unrealized gain (loss) recognized in OCI	(10)
Cash flow hedge, amount of unrealized gain (loss) recognized in OCI		21
Foreign exchange contracts | Net Investment Hedges
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Cash flow hedge, amount of unrealized gain (loss) recognized in OCI	1
Cash flow hedge, amount of unrealized gain (loss) recognized in OCI		16
Interest rate contracts
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of (gain) loss reclassified from AOCI to earnings	32
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	32
Amount of (gain) loss reclassified from AOCI to earnings		40
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	178	(2)
Interest rate contracts | Cash Flow Hedges
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Cash flow hedge, amount of unrealized gain (loss) recognized in OCI	(296)
Cash flow hedge, amount of unrealized gain (loss) recognized in OCI		100
Commodity contracts
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of (gain) loss reclassified from AOCI to earnings	0
Amount of (gain) loss reclassified from AOCI to earnings		(1)
Commodity contracts | Non-Qualifying Derivative Instruments
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain (loss) on derivatives	(261)	175
Commodity contracts | Non-Qualifying Derivative Instruments | Transportation and other services
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain (loss) on derivatives	(26)	(1)
Commodity contracts | Non-Qualifying Derivative Instruments | Commodity
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain (loss) on derivatives	(642)	82
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	398	84
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	9	10
Commodity contracts | Cash Flow Hedges
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Cash flow hedge, amount of unrealized gain (loss) recognized in OCI	(3)
Cash flow hedge, amount of unrealized gain (loss) recognized in OCI		(2)
Other contracts
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Amount of (gain) loss reclassified from AOCI to earnings	(9)
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	(9)
Amount of (gain) loss reclassified from AOCI to earnings		9
Other contracts | Non-Qualifying Derivative Instruments
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Unrealized gain (loss) on derivatives	5	(9)
Other contracts | Cash Flow Hedges
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
Cash flow hedge, amount of unrealized gain (loss) recognized in OCI	$ 12
Cash flow hedge, amount of unrealized gain (loss) recognized in OCI		$ (14)

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RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Liquidity and Credit Risk (Details) - CAD ($)	3 Months Ended	12 Months Ended
	Mar. 31, 2019	Dec. 31, 2018
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	$ 262,000,000	$ 562,000,000
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	21,000,000	28,000,000
Derivative instruments | United States financial institutions
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	51,000,000	107,000,000
Derivative instruments | European financial institutions
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	58,000,000	84,000,000
Derivative instruments | Asian financial institutions
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	0	6,000,000
Derivative instruments | Other
LIQUIDITY RISK AND CREDIT RISK
Maximum credit exposure with respect to derivative instruments	$ 132,000,000	$ 337,000,000

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RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Fair Value of Derivatives (Details) - CAD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018
Fair Value of Derivatives
Total net derivative asset/(liability)	$ (2,860)	$ (3,210)
Foreign exchange contracts
Fair Value of Derivatives
Total net derivative asset/(liability)	(2,110)	(2,718)
Interest rate contracts
Fair Value of Derivatives
Total net derivative asset/(liability)	(517)	(515)
Commodity contracts
Fair Value of Derivatives
Total net derivative asset/(liability)	(234)	30
Other contracts
Fair Value of Derivatives
Total net derivative asset/(liability)	1	(7)
Recurring basis
Fair Value of Derivatives
Current derivative assets	205	498
Long-term derivative assets	87	119
Current derivative liabilities	(946)	(1,234)
Long-term derivative liabilities	(2,206)	(2,593)
Total net derivative asset/(liability)	(2,860)	(3,210)
Recurring basis | Foreign exchange contracts
Fair Value of Derivatives
Current derivative assets	26	47
Long-term derivative assets	50	62
Current derivative liabilities	(506)	(615)
Long-term derivative liabilities	(1,680)	(2,212)
Total net derivative asset/(liability)	(2,110)	(2,718)
Recurring basis | Interest rate contracts
Fair Value of Derivatives
Current derivative assets	7	22
Long-term derivative assets		5
Current derivative liabilities	(150)	(341)
Long-term derivative liabilities	(374)	(201)
Total net derivative asset/(liability)	(517)	(515)
Recurring basis | Commodity contracts
Fair Value of Derivatives
Current derivative assets	172	429
Long-term derivative assets	35	52
Current derivative liabilities	(289)	(273)
Long-term derivative liabilities	(152)	(178)
Total net derivative asset/(liability)	(234)	30
Recurring basis | Other contracts
Fair Value of Derivatives
Long-term derivative assets	2
Current derivative liabilities	(1)	(5)
Long-term derivative liabilities		(2)
Total net derivative asset/(liability)	1	(7)
Level 1 | Recurring basis
Fair Value of Derivatives
Current derivative assets	3	24
Long-term derivative assets	0	0
Current derivative liabilities	(7)	(7)
Long-term derivative liabilities	0	0
Total net derivative asset/(liability)	(4)	17
Level 1 | Recurring basis | Foreign exchange contracts
Fair Value of Derivatives
Current derivative assets		0
Long-term derivative assets	0	0
Current derivative liabilities	0	0
Long-term derivative liabilities	0	0
Total net derivative asset/(liability)	0	0
Level 1 | Recurring basis | Interest rate contracts
Fair Value of Derivatives
Current derivative assets		0
Long-term derivative assets	0	0
Current derivative liabilities	0	0
Long-term derivative liabilities	0	0
Total net derivative asset/(liability)	0	0
Level 1 | Recurring basis | Commodity contracts
Fair Value of Derivatives
Current derivative assets	3	24
Long-term derivative assets	0	0
Current derivative liabilities	(7)	(7)
Long-term derivative liabilities	0	0
Total net derivative asset/(liability)	(4)	17
Level 1 | Recurring basis | Other contracts
Fair Value of Derivatives
Long-term derivative assets	0
Current derivative liabilities	0	0
Long-term derivative liabilities		0
Total net derivative asset/(liability)	0	0
Level 2 | Recurring basis
Fair Value of Derivatives
Current derivative assets	43	114
Long-term derivative assets	65	97
Current derivative liabilities	(673)	(989)
Long-term derivative liabilities	(2,069)	(2,438)
Total net derivative asset/(liability)	(2,634)	(3,216)
Level 2 | Recurring basis | Foreign exchange contracts
Fair Value of Derivatives
Current derivative assets	26	47
Long-term derivative assets	50	62
Current derivative liabilities	(506)	(615)
Long-term derivative liabilities	(1,680)	(2,212)
Total net derivative asset/(liability)	(2,110)	(2,718)
Level 2 | Recurring basis | Interest rate contracts
Fair Value of Derivatives
Current derivative assets	7	22
Long-term derivative assets		5
Current derivative liabilities	(150)	(341)
Long-term derivative liabilities	(374)	(201)
Total net derivative asset/(liability)	(517)	(515)
Level 2 | Recurring basis | Commodity contracts
Fair Value of Derivatives
Current derivative assets	10	45
Long-term derivative assets	13	30
Current derivative liabilities	(16)	(28)
Long-term derivative liabilities	(15)	(23)
Total net derivative asset/(liability)	(8)	24
Level 2 | Recurring basis | Other contracts
Fair Value of Derivatives
Long-term derivative assets	2
Current derivative liabilities	(1)	(5)
Long-term derivative liabilities		(2)
Total net derivative asset/(liability)	1	(7)
Level 3 | Recurring basis
Fair Value of Derivatives
Current derivative assets	159	360
Long-term derivative assets	22	22
Current derivative liabilities	(266)	(238)
Long-term derivative liabilities	(137)	(155)
Total net derivative asset/(liability)	(222)	(11)
Level 3 | Recurring basis | Foreign exchange contracts
Fair Value of Derivatives
Current derivative assets		0
Long-term derivative assets	0	0
Current derivative liabilities	0	0
Long-term derivative liabilities	0	0
Total net derivative asset/(liability)	0	0
Level 3 | Recurring basis | Interest rate contracts
Fair Value of Derivatives
Current derivative assets		0
Long-term derivative assets	0	0
Current derivative liabilities	0	0
Long-term derivative liabilities	0	0
Total net derivative asset/(liability)	0	0
Level 3 | Recurring basis | Commodity contracts
Fair Value of Derivatives
Current derivative assets	159	360
Long-term derivative assets	22	22
Current derivative liabilities	(266)	(238)
Long-term derivative liabilities	(137)	(155)
Total net derivative asset/(liability)	(222)	(11)
Level 3 | Recurring basis | Other contracts
Fair Value of Derivatives
Long-term derivative assets	0
Current derivative liabilities	0	0
Long-term derivative liabilities		0
Total net derivative asset/(liability)	$ 0	$ 0

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RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Level 3 Inputs (Details) $ in Millions	Mar. 31, 2019 CAD ($) $ / bbl $ / MWh $ / MillionsofBTU-MMBTU $ / Gallon-gal	Dec. 31, 2018 CAD ($)
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	$ (2,860)	$ (3,210)
Recurring basis
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	(2,860)	(3,210)
Level 3 | Recurring basis
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Fair Value	$ (222)	$ (11)
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	2.55
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	5.17
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	3.47
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	42.96
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	166.19
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	69.21
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	30.79
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	71.28
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	50.21
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	1.22
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	5.17
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	2.25
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	33.12
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	127.36
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	76.83
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	0.17
Market approach valuation technique | Level 3 | Commodity Contracts - Physical | NGL | Maximum
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | $ / Gallon-gal	1.11
Market approach valuation technique | Level 3 | Commodity Contracts - Physical | NGL | Weighted Average
Significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments
Forward price | $ / Gallon-gal	0.37
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	$ (18)
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	(82)
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	(125)
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	(37)
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	$ 2

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RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Changes in Level 3 (Details) - CAD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Changes in net fair value of derivative assets and liabilities classified as Level 3
Level 3 net derivative asset/(liability) at beginning of period	$ (11)	$ (387)
Total gain/(loss)
Included in earnings	(52)	31
Included in OCI	(3)	(3)
Settlements	(156)	154
Level 3 net derivative liability at end of period	$ (222)	$ (205)

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RISK MANAGEMENT AND FINANCIAL INSTRUMENTS - Other Financial Instruments (Details) - CAD ($)	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018	Dec. 31, 2018
Fair Value of Other Financial Instruments
FMVA investments	$ 101,000,000		$ 102,000,000
Long-term debt, carrying value	65,300,000,000		63,900,000,000
Long-term debt	68,900,000,000		64,400,000,000
Net Investment Hedges
Fair Value of Other Financial Instruments
Unrealized foreign exchange gain (loss) on translation of United States dollar denominated debt	(108,000,000)	$ 194,000,000
Unrealized gain (loss) on change in fair value of outstanding forward exchange forward contracts	1,000,000
Unrealized gain (loss) on change in fair value of outstanding forward exchange forward contracts		15,000,000
Realized gain (loss) associated with the settlement of foreign exchange forward contracts	0
Realized gain (loss) associated with the settlement of foreign exchange forward contracts		(23,000,000)
Realized gain (loss) associated with the settlement of United Stated dollar denominated debt that matured	0	(11,000,000)
Amount of ineffectiveness	0
Amount of ineffectiveness		$ 0
Preferred share investment
Fair Value of Other Financial Instruments
Held to maturity investment at amortized cost	$ 582,000,000		478,000,000
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)	4.38%
Held to maturity investment, fair value	$ 582,000,000		580,000,000
Carrying value
Fair Value of Other Financial Instruments
Noncurrent notes receivable	95,000,000		97,000,000
Fair Value
Fair Value of Other Financial Instruments
Restricted long-term investments held in trust	356,000,000		323,000,000
Noncurrent notes receivable	$ 95,000,000		$ 97,000,000

XML

INCOME TAXES (Details)	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Income Tax Disclosure [Abstract]
Effective income tax rate (as a percent)	22.40%	(16.70%)

XML

PENSION AND OTHER POSTRETIREMENT BENEFITS (Details) - CAD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) [Abstract]
Service cost	$ 51	$ 65
Interest cost	51	45
Expected return on plan assets	(84)	(82)
Amortization of actuarial loss	8	7
Amortization of prior service costs	(1)	(1)
Net periodic benefit costs	$ 25	$ 34

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LEASES - Narrative (Details) $ in Millions	3 Months Ended
	Mar. 31, 2019 CAD ($)
Lessee, Lease, Description [Line Items]
Operating lease, expense	$ 28
Operating lease, payments	$ 31
Minimum
Lessee, Lease, Description [Line Items]
Lessee, operating lease, remaining lease term	1 month
Lessor, operating lease, remaining lease term	9 months
Maximum
Lessee, Lease, Description [Line Items]
Lessee, operating lease, remaining lease term	29 years
Lessor, operating lease, remaining lease term	24 years

XML

LEASES - Supplemental Statements of Financial Position (Details) - CAD ($) $ in Millions	Mar. 31, 2019	Jan. 01, 2019
Leases [Abstract]
Operating lease right-of-use assets, net	$ 745	$ 771
Operating lease liabilities - current	67	86
Operating lease liabilities - long-term	757	770
Total operating lease liabilities	$ 824	$ 856
Weighted average remaining lease term	14 years	14 years
Weighted average discount rate	4.30%	4.30%

XML

LEASES - Operating Lease Commitments (Details) - CAD ($) $ in Millions	Mar. 31, 2019	Jan. 01, 2019
Leases [Abstract]
2019	$ 83
2020	116
2021	94
2022	89
2023	79
Thereafter	663
Total undiscounted lease payments	1,124
Less imputed interest	(300)
Total operating lease commitments	$ 824	$ 856

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LEASES - Lessor Lease Income (Details) $ in Millions	3 Months Ended
	Mar. 31, 2019 CAD ($)
Leases [Abstract]
Operating lease income	$ 64
Variable lease income	100
Total lease income	$ 164

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LEASES - Lessor Future Expected Lease Payments (Details) $ in Millions	Mar. 31, 2019 CAD ($)
Leases [Abstract]
2019	$ 192
2020	216
2021	189
2022	186
2023	178
Thereafter	2,395
Total undiscounted lease payments	$ 3,356

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CONDENSED CONSOLIDATING FINANCIAL INFORMATION - Notes under Guarantees (Details) $ in Billions, $ in Billions	Mar. 31, 2019 USD ($)	Mar. 31, 2019 CAD ($)
5.200% Notes due 2020 | Enbridge Energy Partners, L.P.
Debt Instrument [Line Items]
Interest rate (as a percent)	5.20%	5.20%
4.375% Notes due 2020 | Enbridge Energy Partners, L.P.
Debt Instrument [Line Items]
Interest rate (as a percent)	4.375%	4.375%
4.200% Notes due 2021 | Enbridge Energy Partners, L.P.
Debt Instrument [Line Items]
Interest rate (as a percent)	4.20%	4.20%
5.875% Notes due 2025 | Enbridge Energy Partners, L.P.
Debt Instrument [Line Items]
Interest rate (as a percent)	5.875%	5.875%
5.950% Notes due 2033 | Enbridge Energy Partners, L.P.
Debt Instrument [Line Items]
Interest rate (as a percent)	5.95%	5.95%
6.300% Notes due 2034 | Enbridge Energy Partners, L.P.
Debt Instrument [Line Items]
Interest rate (as a percent)	6.30%	6.30%
7.500% Notes due 2038 | Enbridge Energy Partners, L.P.
Debt Instrument [Line Items]
Interest rate (as a percent)	7.50%	7.50%
5.500% Notes due 2040 | Enbridge Energy Partners, L.P.
Debt Instrument [Line Items]
Interest rate (as a percent)	5.50%	5.50%
7.375% Notes due 2045 | Enbridge Energy Partners, L.P.
Debt Instrument [Line Items]
Interest rate (as a percent)	7.375%	7.375%
Senior Notes
Debt Instrument [Line Items]
Long-term debt	$ 5.9	$ 7.8
Senior Notes | Spectra Energy Partners L P
Debt Instrument [Line Items]
Long-term debt	3.9
Senior Notes | Enbridge Energy Partners, L.P.
Debt Instrument [Line Items]
Long-term debt	$ 4.0
Senior Notes | 4.600% Senior Notes due 2021 | Spectra Energy Partners L P
Debt Instrument [Line Items]
Interest rate (as a percent)	4.60%	4.60%
Senior Notes | 4.750% Senior Notes due 2024 | Spectra Energy Partners L P
Debt Instrument [Line Items]
Interest rate (as a percent)	4.75%	4.75%
Senior Notes | 3.500% Senior Notes due 2025 | Spectra Energy Partners L P
Debt Instrument [Line Items]
Interest rate (as a percent)	3.50%	3.50%
Senior Notes | 3.375% Senior Notes due 2026 | Spectra Energy Partners L P
Debt Instrument [Line Items]
Interest rate (as a percent)	3.375%	3.375%
Senior Notes | 5.950% Senior Notes due 2043 | Spectra Energy Partners L P
Debt Instrument [Line Items]
Interest rate (as a percent)	5.95%	5.95%
Senior Notes | 4.500% Senior Notes due 2045 | Spectra Energy Partners L P
Debt Instrument [Line Items]
Interest rate (as a percent)	4.50%	4.50%
Senior Notes | 2.900% Senior Notes due 2022
Debt Instrument [Line Items]
Interest rate (as a percent)	2.90%	2.90%
Senior Notes | 4.000% Senior Notes due 2023
Debt Instrument [Line Items]
Interest rate (as a percent)	4.00%	4.00%
Senior Notes | 3.500% Senior Notes due 2024
Debt Instrument [Line Items]
Interest rate (as a percent)	3.50%	3.50%
Senior Notes | 4.250% Senior Notes due 2026
Debt Instrument [Line Items]
Interest rate (as a percent)	4.25%	4.25%
Senior Notes | 3.700% Senior Notes due 2027
Debt Instrument [Line Items]
Interest rate (as a percent)	3.70%	3.70%
Senior Notes | 4.500% Senior Notes due 2044
Debt Instrument [Line Items]
Interest rate (as a percent)	4.50%	4.50%
Senior Notes | 5.500% Senior Notes due 2046
Debt Instrument [Line Items]
Interest rate (as a percent)	5.50%	5.50%
Senior Notes | 4.770% Senior Notes due 2019
Debt Instrument [Line Items]
Interest rate (as a percent)	4.77%	4.77%
Senior Notes | 4.530% Senior Notes due 2020
Debt Instrument [Line Items]
Interest rate (as a percent)	4.53%	4.53%
Senior Notes | 4.850% Senior Notes due 2020
Debt Instrument [Line Items]
Interest rate (as a percent)	4.85%	4.85%
Senior Notes | 4.260% Senior Notes due 2021
Debt Instrument [Line Items]
Interest rate (as a percent)	4.26%	4.26%
Senior Notes | 3.160% Senior Notes due 2021
Debt Instrument [Line Items]
Interest rate (as a percent)	3.16%	3.16%
Senior Notes | 4.850% Senior Notes due 2022
Debt Instrument [Line Items]
Interest rate (as a percent)	4.85%	4.85%
Senior Notes | 3.190% Senior Notes due 2022
Debt Instrument [Line Items]
Interest rate (as a percent)	3.19%	3.19%
Senior Notes | 3.940% Senior Notes due 2023
Debt Instrument [Line Items]
Interest rate (as a percent)	3.94%	3.94%
Senior Notes | 3.950% Senior Notes due 2024
Debt Instrument [Line Items]
Interest rate (as a percent)	3.95%	3.95%
Senior Notes | 3.200% Senior Notes due 2027
Debt Instrument [Line Items]
Interest rate (as a percent)	3.20%	3.20%
Senior Notes | 6.100% Senior Notes due 2028
Debt Instrument [Line Items]
Interest rate (as a percent)	6.10%	6.10%
Senior Notes | 7.220% Senior Notes due 2030
Debt Instrument [Line Items]
Interest rate (as a percent)	7.22%	7.22%
Senior Notes | 7.200% Senior Notes due 2032
Debt Instrument [Line Items]
Interest rate (as a percent)	7.20%	7.20%
Senior Notes | 5.570% Senior Notes due 2035
Debt Instrument [Line Items]
Interest rate (as a percent)	5.57%	5.57%
Senior Notes | 5.750% Senior Notes due 2039
Debt Instrument [Line Items]
Interest rate (as a percent)	5.75%	5.75%
Senior Notes | 5.120% Senior Notes due 2040
Debt Instrument [Line Items]
Interest rate (as a percent)	5.12%	5.12%
Senior Notes | 4.240% Senior Notes due 2042
Debt Instrument [Line Items]
Interest rate (as a percent)	4.24%	4.24%
Senior Notes | 4.570% Senior Notes due 2044
Debt Instrument [Line Items]
Interest rate (as a percent)	4.57%	4.57%
Senior Notes | 4.870% Senior Notes due 2044
Debt Instrument [Line Items]
Interest rate (as a percent)	4.87%	4.87%
Senior Notes | 4.560% Senior Notes due 2064
Debt Instrument [Line Items]
Interest rate (as a percent)	4.56%	4.56%

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CONDENSED CONSOLIDATING FINANCIAL INFORMATION - Statement of Earnings and Comprehensive Income (Details) - CAD ($) $ in Millions	3 Months Ended
	Mar. 31, 2019	Mar. 31, 2018
Operating revenues
Revenues	$ 12,856	$ 12,726
Operating expenses
Operating and administrative	1,625	1,641
Depreciation and amortization	840	824
Impairment of long-lived assets	0	1,062
Total operating expenses	10,237	11,848
Operating income	2,619	878
Income from equity investments	413	335
Equity earnings from consolidated subsidiaries	0	0
Other
Net foreign currency gain/(loss)	214	(185)
Other	46	65
Interest expense	(685)	(656)
Earnings before income taxes	2,607	437
Income tax recovery/(expense)	(584)	73
Earnings	2,023	510
(Earnings)/loss attributable to noncontrolling interests and redeemable noncontrolling interests	(37)	24
Earnings attributable to controlling interests	1,986	534
Preference share dividends	(95)	(89)
Earnings attributable to common shareholders	1,891	445
Total other comprehensive income/(loss)	(1,328)	1,473
Comprehensive income	695	1,983
Comprehensive (income)/loss attributable to noncontrolling interests and redeemable noncontrolling interests	13	(147)
Comprehensive income attributable to controlling interests	708	1,836
Consolidation, Eliminations
Operating revenues
Revenues	0	0
Operating expenses
Operating and administrative	0	0
Depreciation and amortization	0	0
Impairment of long-lived assets		0
Total operating expenses	0	0
Operating income	0	0
Income from equity investments	(59)	(16)
Equity earnings from consolidated subsidiaries	(1,928)	(2,069)
Other
Net foreign currency gain/(loss)	(904)	70
Other	(448)	(251)
Interest expense	458	274
Earnings before income taxes	(2,881)	(1,992)
Income tax recovery/(expense)	106	9
Earnings	(2,775)	(1,983)
(Earnings)/loss attributable to noncontrolling interests and redeemable noncontrolling interests	(37)	24
Earnings attributable to controlling interests	(2,812)	(1,959)
Preference share dividends	0	0
Earnings attributable to common shareholders	(2,812)	(1,959)
Total other comprehensive income/(loss)	671	(109)
Comprehensive income	(2,104)	(2,092)
Comprehensive (income)/loss attributable to noncontrolling interests and redeemable noncontrolling interests	13	(147)
Comprehensive income attributable to controlling interests	(2,091)	(2,239)
Parent Issuer and Guarantor | Reportable Legal Entities
Operating revenues
Revenues	0	0
Operating expenses
Operating and administrative	(34)	67
Depreciation and amortization	15	14
Impairment of long-lived assets		0
Total operating expenses	(19)	81
Operating income	19	(81)
Income from equity investments	59	17
Equity earnings from consolidated subsidiaries	774	707
Other
Net foreign currency gain/(loss)	1,221	(199)
Other	330	246
Interest expense	(308)	(243)
Earnings before income taxes	2,095	447
Income tax recovery/(expense)	(109)	87
Earnings	1,986	534
(Earnings)/loss attributable to noncontrolling interests and redeemable noncontrolling interests	0	0
Earnings attributable to controlling interests	1,986	534
Preference share dividends	(95)	(89)
Earnings attributable to common shareholders	1,891	445
Total other comprehensive income/(loss)	(1,278)	1,302
Comprehensive income	708	1,836
Comprehensive (income)/loss attributable to noncontrolling interests and redeemable noncontrolling interests	0	0
Comprehensive income attributable to controlling interests	708	1,836
Subsidiary Non-Guarantors | Reportable Legal Entities
Operating revenues
Revenues	12,856	12,726
Operating expenses
Operating and administrative	1,656	1,569
Depreciation and amortization	825	810
Impairment of long-lived assets		1,062
Total operating expenses	10,253	11,762
Operating income	2,603	964
Income from equity investments	382	300
Equity earnings from consolidated subsidiaries	493	608
Other
Net foreign currency gain/(loss)	(103)	(58)
Other	123	39
Interest expense	(583)	(479)
Earnings before income taxes	2,915	1,374
Income tax recovery/(expense)	(596)	(23)
Earnings	2,319	1,351
(Earnings)/loss attributable to noncontrolling interests and redeemable noncontrolling interests	0	0
Earnings attributable to controlling interests	2,319	1,351
Preference share dividends	0	0
Earnings attributable to common shareholders	2,319	1,351
Total other comprehensive income/(loss)	(720)	253
Comprehensive income	1,599	1,604
Comprehensive (income)/loss attributable to noncontrolling interests and redeemable noncontrolling interests	0	0
Comprehensive income attributable to controlling interests	1,599	1,604
Spectra Energy Partners L P | Subsidiary Issuer and Guarantor - SEP and EEP | Reportable Legal Entities
Operating revenues
Revenues	0	0
Operating expenses
Operating and administrative	2	1
Depreciation and amortization	0	0
Impairment of long-lived assets		0
Total operating expenses	2	1
Operating income	(2)	(1)
Income from equity investments	31	34
Equity earnings from consolidated subsidiaries	398	551
Other
Net foreign currency gain/(loss)	0	2
Other	0	1
Interest expense	(94)	(72)
Earnings before income taxes	333	515
Income tax recovery/(expense)	15	0
Earnings	348	515
(Earnings)/loss attributable to noncontrolling interests and redeemable noncontrolling interests	0	0
Earnings attributable to controlling interests	348	515
Preference share dividends	0	0
Earnings attributable to common shareholders	348	515
Total other comprehensive income/(loss)	(16)	19
Comprehensive income	332	534
Comprehensive (income)/loss attributable to noncontrolling interests and redeemable noncontrolling interests	0	0
Comprehensive income attributable to controlling interests	332	534
Enbridge Energy Partners, L.P. | Subsidiary Issuer and Guarantor - SEP and EEP | Reportable Legal Entities
Operating revenues
Revenues	0	0
Operating expenses
Operating and administrative	1	4
Depreciation and amortization	0	0
Impairment of long-lived assets		0
Total operating expenses	1	4
Operating income	(1)	(4)
Income from equity investments	0	0
Equity earnings from consolidated subsidiaries	263	203
Other
Net foreign currency gain/(loss)	0	0
Other	41	30
Interest expense	(158)	(136)
Earnings before income taxes	145	93
Income tax recovery/(expense)	0	0
Earnings	145	93
(Earnings)/loss attributable to noncontrolling interests and redeemable noncontrolling interests	0	0
Earnings attributable to controlling interests	145	93
Preference share dividends	0	0
Earnings attributable to common shareholders	145	93
Total other comprehensive income/(loss)	15	8
Comprehensive income	160	101
Comprehensive (income)/loss attributable to noncontrolling interests and redeemable noncontrolling interests	0	0
Comprehensive income attributable to controlling interests	160	101
Commodity
Operating revenues
Revenues	6,632	7,268
Operating expenses
Cost of goods and services sold	6,565	6,997
Commodity | Consolidation, Eliminations
Operating revenues
Revenues	0	0
Operating expenses
Cost of goods and services sold	0	0
Commodity | Parent Issuer and Guarantor | Reportable Legal Entities
Operating revenues
Revenues	0	0
Operating expenses
Cost of goods and services sold	0	0
Commodity | Subsidiary Non-Guarantors | Reportable Legal Entities
Operating revenues
Revenues	6,632	7,268
Operating expenses
Cost of goods and services sold	6,565	6,997
Commodity | Spectra Energy Partners L P | Subsidiary Issuer and Guarantor - SEP and EEP | Reportable Legal Entities
Operating revenues
Revenues	0	0
Operating expenses
Cost of goods and services sold	0	0
Commodity | Enbridge Energy Partners, L.P. | Subsidiary Issuer and Guarantor - SEP and EEP | Reportable Legal Entities
Operating revenues
Revenues	0	0
Operating expenses
Cost of goods and services sold	0	0
Gas Distribution
Operating revenues
Revenues	1,876	1,926
Operating expenses
Cost of goods and services sold	1,207	1,324
Gas Distribution | Consolidation, Eliminations
Operating revenues
Revenues	0	0
Operating expenses
Cost of goods and services sold	0	0
Gas Distribution | Parent Issuer and Guarantor | Reportable Legal Entities
Operating revenues
Revenues	0	0
Operating expenses
Cost of goods and services sold	0	0
Gas Distribution | Subsidiary Non-Guarantors | Reportable Legal Entities
Operating revenues
Revenues	1,876	1,926
Operating expenses
Cost of goods and services sold	1,207	1,324
Gas Distribution | Spectra Energy Partners L P | Subsidiary Issuer and Guarantor - SEP and EEP | Reportable Legal Entities
Operating revenues
Revenues	0	0
Operating expenses
Cost of goods and services sold	0	0
Gas Distribution | Enbridge Energy Partners, L.P. | Subsidiary Issuer and Guarantor - SEP and EEP | Reportable Legal Entities
Operating revenues
Revenues	0	0
Operating expenses
Cost of goods and services sold	0	0
Transportation and other services
Operating revenues
Revenues	4,348	3,532
Transportation and other services | Consolidation, Eliminations
Operating revenues
Revenues	0	0
Transportation and other services | Parent Issuer and Guarantor | Reportable Legal Entities
Operating revenues
Revenues	0	0
Transportation and other services | Subsidiary Non-Guarantors | Reportable Legal Entities
Operating revenues
Revenues	4,348	3,532
Transportation and other services | Spectra Energy Partners L P | Subsidiary Issuer and Guarantor - SEP and EEP | Reportable Legal Entities
Operating revenues
Revenues	0	0
Transportation and other services | Enbridge Energy Partners, L.P. | Subsidiary Issuer and Guarantor - SEP and EEP | Reportable Legal Entities
Operating revenues
Revenues	$ 0	$ 0

XML

CONDENSED CONSOLIDATING FINANCIAL INFORMATION - Statement of Financial Position (Details) - CAD ($) $ in Millions	Mar. 31, 2019	Dec. 31, 2018	Mar. 31, 2018
Current assets
Cash and cash equivalents	$ 702	$ 518
Restricted cash	55	119
Accounts receivable and other	6,486	6,517
Accounts receivable from affiliates	92	79
Short-term loans receivable from affiliates	0	0
Inventory	1,047	1,339
Total current assets	8,382	8,572
Property, plant and equipment, net	93,875	94,540
Long-term loans receivable from affiliates	0	0
Long-term investments	0	0
Long-term investments	16,902	16,707
Restricted long-term investments	356	323
Deferred amounts and other assets	9,505	8,558
Intangible assets, net	2,301	2,372
Goodwill	33,895	34,459
Deferred income taxes	1,292	1,374
Total assets	166,508	166,905
Current liabilities
Short-term borrowings	870	1,024
Accounts payable and other	7,331	9,863
Accounts payable to affiliates	30	40
Interest payable	573	669
Short-term loans payable to affiliates	0	0
Current portion of long-term debt	4,321	3,259
Total current liabilities	13,125	14,855
Long-term debt	60,680	60,327
Other long-term liabilities	9,044	8,834
Long-term loans payable to affiliates	0	0
Deferred income taxes	9,740	9,454
Total liabilities	92,589	93,470
Equity
Controlling interests	70,305	69,470
Noncontrolling interests	3,614	3,965
Total equity	73,919	73,435	$ 67,514
Total liabilities and equity	166,508	166,905
Consolidation, Eliminations
Current assets
Cash and cash equivalents	0	0
Restricted cash	0	0
Accounts receivable and other	0	0
Accounts receivable from affiliates	(604)	(518)
Short-term loans receivable from affiliates	(13,236)	(8,285)
Inventory	0	0
Total current assets	(13,840)	(8,803)
Property, plant and equipment, net	0	0
Long-term loans receivable from affiliates	(44,573)	(14,274)
Long-term investments	(119,253)	(120,181)
Long-term investments	(3,568)	(3,682)
Restricted long-term investments	0	0
Deferred amounts and other assets	(1,407)	(1,726)
Intangible assets, net	0	0
Goodwill	0	0
Deferred income taxes	328	328
Total assets	(182,313)	(148,338)
Current liabilities
Short-term borrowings	0	0
Accounts payable and other	(10)	(6)
Accounts payable to affiliates	(603)	(518)
Interest payable	0	0
Short-term loans payable to affiliates	(13,236)	(8,285)
Current portion of long-term debt	0	0
Total current liabilities	(13,849)	(8,809)
Long-term debt	0	0
Other long-term liabilities	(1,407)	(1,726)
Long-term loans payable to affiliates	(44,573)	(14,274)
Deferred income taxes	(4,385)	(4,400)
Total liabilities	(64,214)	(29,209)
Equity
Controlling interests	(121,713)	(123,094)
Noncontrolling interests	3,614	3,965
Total equity	(118,099)	(119,129)
Total liabilities and equity	(182,313)	(148,338)
Parent Issuer and Guarantor | Reportable Legal Entities
Current assets
Cash and cash equivalents	0	0
Restricted cash	9	9
Accounts receivable and other	283	283
Accounts receivable from affiliates	586	726
Short-term loans receivable from affiliates	3,527	3,943
Inventory	0	0
Total current assets	4,405	4,961
Property, plant and equipment, net	166	140
Long-term loans receivable from affiliates	26,504	10,318
Long-term investments	78,271	78,474
Long-term investments	4,619	4,561
Restricted long-term investments	0	0
Deferred amounts and other assets	1,491	1,700
Intangible assets, net	219	234
Goodwill	0	0
Deferred income taxes	744	817
Total assets	116,419	101,205
Current liabilities
Short-term borrowings	0	0
Accounts payable and other	756	2,742
Accounts payable to affiliates	935	946
Interest payable	227	283
Short-term loans payable to affiliates	426	426
Current portion of long-term debt	2,979	1,853
Total current liabilities	5,323	6,250
Long-term debt	23,519	22,893
Other long-term liabilities	2,145	2,428
Long-term loans payable to affiliates	15,076	76
Deferred income taxes	0	0
Total liabilities	46,063	31,647
Equity
Controlling interests	70,356	69,558
Noncontrolling interests	0	0
Total equity	70,356	69,558
Total liabilities and equity	116,419	101,205
Subsidiary Non-Guarantors | Reportable Legal Entities
Current assets
Cash and cash equivalents	690	502
Restricted cash	46	110
Accounts receivable and other	6,202	6,211
Accounts receivable from affiliates	79	(142)
Short-term loans receivable from affiliates	5,871	653
Inventory	1,047	1,339
Total current assets	13,935	8,673
Property, plant and equipment, net	93,709	94,400
Long-term loans receivable from affiliates	15,524	1,344
Long-term investments	15,032	15,567
Long-term investments	14,890	14,841
Restricted long-term investments	356	323
Deferred amounts and other assets	9,412	8,558
Intangible assets, net	2,082	2,138
Goodwill	33,895	34,459
Deferred income taxes	220	229
Total assets	199,055	180,532
Current liabilities
Short-term borrowings	870	1,024
Accounts payable and other	6,552	7,086
Accounts payable to affiliates	(891)	(677)
Interest payable	229	225
Short-term loans payable to affiliates	7,367	7,177
Current portion of long-term debt	674	723
Total current liabilities	14,801	15,558
Long-term debt	27,501	23,215
Other long-term liabilities	8,276	8,100
Long-term loans payable to affiliates	28,027	12,696
Deferred income taxes	13,821	13,523
Total liabilities	92,426	73,092
Equity
Controlling interests	106,629	107,440
Noncontrolling interests	0	0
Total equity	106,629	107,440
Total liabilities and equity	199,055	180,532
Spectra Energy Partners L P | Subsidiary Issuer and Guarantor - SEP and EEP | Reportable Legal Entities
Current assets
Cash and cash equivalents	5	16
Restricted cash	0	0
Accounts receivable and other	1	15
Accounts receivable from affiliates	0	0
Short-term loans receivable from affiliates	0	0
Inventory	0	0
Total current assets	6	31
Property, plant and equipment, net	0	0
Long-term loans receivable from affiliates	73	73
Long-term investments	19,741	19,777
Long-term investments	961	987
Restricted long-term investments	0	0
Deferred amounts and other assets	1	9
Intangible assets, net	0	0
Goodwill	0	0
Deferred income taxes	0	0
Total assets	20,782	20,877
Current liabilities
Short-term borrowings	0	0
Accounts payable and other	19	7
Accounts payable to affiliates	509	233
Interest payable	25	56
Short-term loans payable to affiliates	2,985	682
Current portion of long-term debt	0	0
Total current liabilities	3,538	978
Long-term debt	5,095	7,276
Other long-term liabilities	8	2
Long-term loans payable to affiliates	0	0
Deferred income taxes	304	331
Total liabilities	8,945	8,587
Equity
Controlling interests	11,837	12,290
Noncontrolling interests	0	0
Total equity	11,837	12,290
Total liabilities and equity	20,782	20,877
Enbridge Energy Partners, L.P. | Subsidiary Issuer and Guarantor - SEP and EEP | Reportable Legal Entities
Current assets
Cash and cash equivalents	7	0
Restricted cash	0	0
Accounts receivable and other	0	8
Accounts receivable from affiliates	31	13
Short-term loans receivable from affiliates	3,838	3,689
Inventory	0	0
Total current assets	3,876	3,710
Property, plant and equipment, net	0	0
Long-term loans receivable from affiliates	2,472	2,539
Long-term investments	6,209	6,363
Long-term investments	0	0
Restricted long-term investments	0	0
Deferred amounts and other assets	8	17
Intangible assets, net	0	0
Goodwill	0	0
Deferred income taxes	0	0
Total assets	12,565	12,629
Current liabilities
Short-term borrowings	0	0
Accounts payable and other	14	34
Accounts payable to affiliates	80	56
Interest payable	92	105
Short-term loans payable to affiliates	2,458	0
Current portion of long-term debt	668	683
Total current liabilities	3,312	878
Long-term debt	4,565	6,943
Other long-term liabilities	22	30
Long-term loans payable to affiliates	1,470	1,502
Deferred income taxes	0	0
Total liabilities	9,369	9,353
Equity
Controlling interests	3,196	3,276
Noncontrolling interests	0	0
Total equity	3,196	3,276
Total liabilities and equity	$ 12,565	$ 12,629

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CONDENSED CONSOLIDATING FINANCIAL INFORMATION - Statements of Cash Flow (Details) - CAD ($) $ in Millions	1 Months Ended	3 Months Ended
	Jan. 31, 2019	Mar. 31, 2019	Mar. 31, 2018
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by operating activities		$ 2,176	$ 3,194
Investing activities
Capital expenditures	$ (265)	(1,612)	(1,635)
Long-term investments and restricted long-term investments		(565)	(222)
Distributions from equity investments in excess of cumulative earnings		139	57
Additions to intangible assets		(26)	(258)
Affiliate loans, net		(84)	(10)
Contributions to subsidiaries		0	0
Return of share capital from subsidiaries		0
Advances to affiliates		0	0
Repayment of advances to affiliates		0	0
Net cash used in investing activities		(2,148)	(2,068)
Financing activities
Net change in short-term borrowings		(154)	(443)
Net change in commercial paper and credit facility draws		2,773	(465)
Debenture and term note issues, net of issue costs		1,195	2,061
Debenture and term note repayments		(1,789)	(996)
Debt extinguishment costs		0	(63)
Contributions from noncontrolling interests		3	8
Distributions to noncontrolling interests		(46)	(209)
Contributions from redeemable noncontrolling interests		0	20
Distributions to redeemable noncontrolling interests		0	(84)
Contributions from parents		0	0
Distributions to parents		0	0
Redemption of preferred shares held by subsidiary (Note 10)		(300)	0
Common shares issued		18	13
Preference share dividends		(90)	(87)
Common share dividends		(1,486)	(764)
Advances from affiliates		0	0
Repayment of advances from affiliates		0	0
Other		(25)	0
Net cash provided by/(used in) financing activities		99	(1,009)
Effect of translation of foreign denominated cash and cash equivalents and restricted cash		(7)	19
Net increase in cash and cash equivalents and restricted cash		120	136
Cash and cash equivalents and restricted cash at beginning of period	637	637	587
Cash and cash equivalents and restricted cash at end of period		757	723
Consolidation, Eliminations
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by operating activities		(789)	(367)
Investing activities
Capital expenditures		0	0
Long-term investments and restricted long-term investments		0	16
Distributions from equity investments in excess of cumulative earnings		(536)	(824)
Additions to intangible assets		0	0
Affiliate loans, net		0	0
Contributions to subsidiaries		2,331	151
Return of share capital from subsidiaries		(3,121)
Advances to affiliates		42,068	3,130
Repayment of advances to affiliates		(6,016)	(2,944)
Net cash used in investing activities		34,726	(471)
Financing activities
Net change in short-term borrowings		0	0
Net change in commercial paper and credit facility draws		0	0
Debenture and term note issues, net of issue costs		0	0
Debenture and term note repayments		0	0
Debt extinguishment costs			0
Contributions from noncontrolling interests		3	8
Distributions to noncontrolling interests		(46)	(209)
Contributions from redeemable noncontrolling interests			20
Distributions to redeemable noncontrolling interests			(84)
Contributions from parents		(2,331)	(151)
Distributions to parents		4,489	1,440
Redemption of preferred shares held by subsidiary (Note 10)		0
Common shares issued		0	0
Preference share dividends		0	0
Common share dividends		0	0
Advances from affiliates		(42,068)	(3,130)
Repayment of advances from affiliates		6,016	2,944
Other		0
Net cash provided by/(used in) financing activities		(33,937)	838
Effect of translation of foreign denominated cash and cash equivalents and restricted cash		0	0
Net increase in cash and cash equivalents and restricted cash		0	0
Cash and cash equivalents and restricted cash at beginning of period	0	0	0
Cash and cash equivalents and restricted cash at end of period		0	0
Parent Issuer and Guarantor | Reportable Legal Entities
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by operating activities		(415)	(135)
Investing activities
Capital expenditures		(24)	(5)
Long-term investments and restricted long-term investments		0	(16)
Distributions from equity investments in excess of cumulative earnings		0	336
Additions to intangible assets		(16)	(6)
Affiliate loans, net		0	0
Contributions to subsidiaries		(2,331)	(69)
Return of share capital from subsidiaries		3,121
Advances to affiliates		(19,908)	(401)
Repayment of advances to affiliates		3,996	0
Net cash used in investing activities		(15,162)	(161)
Financing activities
Net change in short-term borrowings		0	0
Net change in commercial paper and credit facility draws		2,312	(105)
Debenture and term note issues, net of issue costs		0	1,080
Debenture and term note repayments		(300)	0
Debt extinguishment costs			0
Contributions from noncontrolling interests		0	0
Distributions to noncontrolling interests		0	0
Contributions from redeemable noncontrolling interests			0
Distributions to redeemable noncontrolling interests			0
Contributions from parents		0	0
Distributions to parents		0	0
Redemption of preferred shares held by subsidiary (Note 10)		0
Common shares issued		18	13
Preference share dividends		(90)	(87)
Common share dividends		(1,513)	(764)
Advances from affiliates		15,150	209
Repayment of advances from affiliates		0	(43)
Other		0
Net cash provided by/(used in) financing activities		15,577	303
Effect of translation of foreign denominated cash and cash equivalents and restricted cash		0	0
Net increase in cash and cash equivalents and restricted cash		0	7
Cash and cash equivalents and restricted cash at beginning of period	9	9	2
Cash and cash equivalents and restricted cash at end of period		9	9
Subsidiary Non-Guarantors | Reportable Legal Entities
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by operating activities		4,566	3,224
Investing activities
Capital expenditures		(1,588)	(1,630)
Long-term investments and restricted long-term investments		(563)	(217)
Distributions from equity investments in excess of cumulative earnings		132	42
Additions to intangible assets		(10)	(252)
Affiliate loans, net		(84)	(10)
Contributions to subsidiaries		0	0
Return of share capital from subsidiaries		0
Advances to affiliates		(21,542)	(2,233)
Repayment of advances to affiliates		1,638	1,890
Net cash used in investing activities		(22,017)	(2,410)
Financing activities
Net change in short-term borrowings		(154)	(443)
Net change in commercial paper and credit facility draws		2,471	614
Debenture and term note issues, net of issue costs		1,195	981
Debenture and term note repayments		(300)	(996)
Debt extinguishment costs			(63)
Contributions from noncontrolling interests		0	0
Distributions to noncontrolling interests		0	0
Contributions from redeemable noncontrolling interests			0
Distributions to redeemable noncontrolling interests			0
Contributions from parents		2,331	151
Distributions to parents		(3,822)	(824)
Redemption of preferred shares held by subsidiary (Note 10)		(300)
Common shares issued		0	0
Preference share dividends		0	0
Common share dividends		27	0
Advances from affiliates		20,526	897
Repayment of advances from affiliates		(4,378)	(1,054)
Other		(14)
Net cash provided by/(used in) financing activities		17,582	(737)
Effect of translation of foreign denominated cash and cash equivalents and restricted cash		(7)	19
Net increase in cash and cash equivalents and restricted cash		124	96
Cash and cash equivalents and restricted cash at beginning of period	612	612	571
Cash and cash equivalents and restricted cash at end of period		736	667
Spectra Energy Partners L P | Subsidiary Issuer and Guarantor - SEP and EEP | Reportable Legal Entities
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by operating activities		232	803
Investing activities
Capital expenditures		0	0
Long-term investments and restricted long-term investments		(2)	(5)
Distributions from equity investments in excess of cumulative earnings		7	15
Additions to intangible assets		0	0
Affiliate loans, net		0	0
Contributions to subsidiaries		0	(77)
Return of share capital from subsidiaries		0
Advances to affiliates		0	0
Repayment of advances to affiliates		0	506
Net cash used in investing activities		5	439
Financing activities
Net change in short-term borrowings		0	0
Net change in commercial paper and credit facility draws		(2,010)	(756)
Debenture and term note issues, net of issue costs		0	0
Debenture and term note repayments		0	0
Debt extinguishment costs			0
Contributions from noncontrolling interests		0	0
Distributions to noncontrolling interests		0	0
Contributions from redeemable noncontrolling interests			0
Distributions to redeemable noncontrolling interests			0
Contributions from parents		0	0
Distributions to parents		(505)	(453)
Redemption of preferred shares held by subsidiary (Note 10)		0
Common shares issued		0	0
Preference share dividends		0	0
Common share dividends		0	0
Advances from affiliates		3,498	0
Repayment of advances from affiliates		(1,226)	0
Other		(5)
Net cash provided by/(used in) financing activities		(248)	(1,209)
Effect of translation of foreign denominated cash and cash equivalents and restricted cash		0	0
Net increase in cash and cash equivalents and restricted cash		(11)	33
Cash and cash equivalents and restricted cash at beginning of period	16	16	14
Cash and cash equivalents and restricted cash at end of period		5	47
Enbridge Energy Partners, L.P. | Subsidiary Issuer and Guarantor - SEP and EEP | Reportable Legal Entities
Condensed Cash Flow Statements, Captions [Line Items]
Net cash provided by operating activities		(1,418)	(331)
Investing activities
Capital expenditures		0	0
Long-term investments and restricted long-term investments		0	0
Distributions from equity investments in excess of cumulative earnings		536	488
Additions to intangible assets		0	0
Affiliate loans, net		0	0
Contributions to subsidiaries		0	(5)
Return of share capital from subsidiaries		0
Advances to affiliates		(618)	(496)
Repayment of advances to affiliates		382	548
Net cash used in investing activities		300	535
Financing activities
Net change in short-term borrowings		0	0
Net change in commercial paper and credit facility draws		0	(218)
Debenture and term note issues, net of issue costs		0	0
Debenture and term note repayments		(1,189)	0
Debt extinguishment costs			0
Contributions from noncontrolling interests		0	0
Distributions to noncontrolling interests		0	0
Contributions from redeemable noncontrolling interests			0
Distributions to redeemable noncontrolling interests			0
Contributions from parents		0	0
Distributions to parents		(162)	(163)
Redemption of preferred shares held by subsidiary (Note 10)		0
Common shares issued		0	0
Preference share dividends		0	0
Common share dividends		0	0
Advances from affiliates		2,894	2,024
Repayment of advances from affiliates		(412)	(1,847)
Other		(6)
Net cash provided by/(used in) financing activities		1,125	(204)
Effect of translation of foreign denominated cash and cash equivalents and restricted cash		0	0
Net increase in cash and cash equivalents and restricted cash		7	0
Cash and cash equivalents and restricted cash at beginning of period	$ 0	0	0
Cash and cash equivalents and restricted cash at end of period		$ 7	$ 0

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Label	Element	Value
Retained Earnings [Member]
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	$ (86,000,000)