ENBRIDGE INC (Form: 10-Q, Received: 05/10/2018 07:32:59)

Receivables

Contract Assets

Contract Liabilities

(millions of Canadian dollars)

Balance at adoption date

Balance at reporting date

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, 2018



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		None
(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)

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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post 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, 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 (Do not check if a smaller reporting company)		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 1,704,740,177 common shares outstanding as of May 4, 2018.



		Page
	PART I
Item 1.	Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	38
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	59
Item 4.	Controls and Procedures	59
	PART II
Item 1.	Legal Proceedings	60
Item 1A.	Risk Factors	60
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	61
Item 3.	Defaults Upon Senior Securities	61
Item 4.	Mine Safety Disclosures	61
Item 5.	Other Information	61
Item 6.	Exhibits	61
	Signatures	62

GLOSSARY



AOCI	Accumulated other comprehensive income/(loss)
ALJ	Administrative Law Judge
ASU	Accounting Standards Update
Canadian L3R Program	Canadian portion of the Line 3 Replacement Program
CIACs	Contributions in Aid of Construction
EBITDA	Earnings before interest, income taxes and depreciation and amortization
Eddystone Rail	Eddystone Rail Company, LLC
EEP	Enbridge Energy Partners, L.P.
EGD	Enbridge Gas Distribution Inc.
Enbridge	Enbridge Inc.
FERC	Federal Energy Regulatory Commission
IDRs	Incentive distribution rights
Line 10	Line 10 crude oil pipeline
MNPUC	Minnesota Public Utilities Commission
NGL	Natural gas liquids
OCI	Other comprehensive income/(loss)
Route Permit	United States Line 3 Replacement Program route permit
Sabal Trail	Sabal Trail Transmission, LLC
SEP	Spectra Energy Partners, LP
TCJA	Tax Cuts and Jobs Act
Texas Express NGL pipeline system	Texas Express PL LLC and Texas Express Gathering LLC
the Merger Transaction	The stock-for-stock merger transaction on February 27, 2017 between Enbridge and Spectra Energy Corp

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 Enbridge and its 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, Green Power 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; estimated future dividends; recovery of the costs of the Canadian portion of the Line 3 Replacement Program (Canadian L3R Program); 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 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; impact of the Canadian L3R Program on existing integrity programs; the sponsored vehicle strategy; dividend payout policy; dividend growth and dividend payout expectation; expectations on impact of 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 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 respect to the impact of the Merger Transaction on us, expected EBITDA, earnings/(loss), earnings/(loss) per share, or estimated future dividends. The most relevant assumptions associated with forward-looking statements on 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 impact of the Merger Transaction, operating performance, regulatory parameters, 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 subsequent 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.

PART I - FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF EARNINGS



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

See accompanying notes to the interim consolidated financial statements.

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME



	Three months ended March 31,
	2018		2017
(unaudited; millions of Canadian dollars)
Earnings	510		945
Other comprehensive income/(loss), net of tax
Change in unrealized gain/(loss) on cash flow hedges	66		(2	)
Change in unrealized gain/(loss) on net investment hedges	(184	)	49
Other comprehensive income from equity investees	14		6
Reclassification to earnings of loss on cash flow hedges	37		41
Reclassification to earnings of pension and other postretirement benefits (OPEB) amounts	(39	)	4
Foreign currency translation adjustments	1,579		432
Other comprehensive income, net of tax	1,473		530
Comprehensive income	1,983		1,475
Comprehensive income attributable to noncontrolling interests and redeemable noncontrolling interests	(147	)	(374	)
Comprehensive income attributable to controlling interests	1,836		1,101
Preference share dividends	(89	)	(83	)
Comprehensive income attributable to common shareholders	1,747		1,018

See accompanying notes to the interim consolidated financial statements.

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY



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

See accompanying notes to the interim consolidated financial statements.

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS



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

See accompanying notes to the interim consolidated financial statements.

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION



	March 31, 2018		December 31, 2017
(unaudited; millions of Canadian dollars; number of shares in millions)
Assets
Current assets
Cash and cash equivalents	610		480
Restricted cash	113		107
Accounts receivable and other	6,271		7,053
Accounts receivable from affiliates	48		47
Inventory	872		1,528
	7,914		9,215
Property, plant and equipment, net	92,521		90,711
Long-term investments	17,360		16,644
Restricted long-term investments	280		267
Deferred amounts and other assets	5,614		6,442
Intangible assets, net	3,455		3,267
Goodwill	35,168		34,457
Deferred income taxes	1,182		1,090
Total assets	163,494		162,093

Liabilities and equity
Current liabilities
Short-term borrowings	1,004		1,444
Accounts payable and other	6,823		9,478
Accounts payable to affiliates	168		157
Interest payable	592		634
Environmental liabilities	33		40
Current portion of long-term debt	4,152		2,871
	12,772		14,624
Long-term debt	61,191		60,865
Other long-term liabilities	8,390		7,510
Deferred income taxes	9,812		9,295
	92,165		92,294
Contingencies (Note 13)
Redeemable noncontrolling interests	3,815		4,067
Equity
Share capital
Preference shares	7,747		7,747
Common shares (1,705 and 1,695 outstanding at March 31, 2018 and December 31, 2017, respectively)	51,127		50,737
Additional paid-in capital	4,313		3,194
Deficit	(1,982	)	(2,468	)
Accumulated other comprehensive income/(loss) (Note 8)	329		(973	)
Reciprocal shareholding	(102	)	(102	)
Total Enbridge Inc. shareholders’ equity	61,432		58,135
Noncontrolling interests	6,082		7,597
	67,514		65,732
Total liabilities and equity	163,494		162,093

See accompanying notes to the interim consolidated financial statements .

NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

1. BASIS OF PRESENTATION

The accompanying unaudited interim consolidated financial statements of Enbridge Inc. have been prepared in accordance with generally accepted accounting principles in the United States of America (U.S. GAAP) and Regulation S-X for interim consolidated financial information. They do not include all of the information and notes required by U.S. GAAP for annual consolidated financial statements and should therefore be read in conjunction with our audited consolidated financial statements and notes for the year ended December 31, 2017 included in our Annual Report on Form 10-K. In the opinion of management, the interim consolidated financial statements contain all normal recurring adjustments necessary to present fairly our financial position, results of operations and cash flows for the interim periods reported. These interim consolidated financial statements follow the same significant accounting policies as those included in our annual consolidated financial statements for the year ended December 31, 2017 , except for the adoption of new standards (Note 2) and the presentation of Cash and cash equivalents to include Bank indebtedness, as discussed below. Amounts are stated in Canadian dollars unless otherwise noted.

Our operations and earnings for interim periods can be affected by seasonal fluctuations within the gas distribution utility businesses, as well as other factors such as the supply of and demand for crude oil and natural gas, and may not be indicative of annual results.

Effective September 30, 2017, we combined Cash and cash equivalents and amounts previously presented as Bank indebtedness where the corresponding bank accounts are subject to cash pooling arrangements. As at March 31, 2018 and December 31, 2017 , $0.9 billion and $0.6 billion of Bank indebtedness has been combined within Cash and cash equivalents in our Consolidated Statements of Financial Position, respectively. Net cash provided by financing activities in our Consolidated Statements of Cash Flows for the three months period ended March 31, 2017 have been reduced by $0.2 billion to reflect this change.

Certain comparative figures in our Consolidated Statement of Cash Flows have been reclassified to conform with the current year's presentation. In addition, activities for the three months ended March 31, 2017 relating to distributions to noncontrolling interests in relation to the Merger Transaction have been reclassified, resulting in an increase to investing activities of $67 million and a decrease to financing activities of $67 million .

2. CHANGES IN ACCOUNTING POLICIES

ADOPTION OF NEW STANDARDS

Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income

Effective January 1, 2018, we adopted Accounting Standards Update (ASU) 2018-02 to address a specific consequence of the Tax Cuts and Jobs Act (TCJA) enacted by the United States federal government on December 22, 2017. The amendments in this accounting update allow a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the TCJA. The amendments will eliminate the stranded tax effects as a result of the reduction of the historical United States federal corporate income tax rate to the newly enacted United States federal corporate income tax rate. The adoption of this accounting update did not have a material impact on our consolidated financial statements.

Clarifying Guidance on the Application of Modification Accounting on Stock Compensation

following conditions are met: 1) there is no change to the fair value of the award, 2) the vesting conditions have not changed, and 3) the classification of the award as an equity instrument or a debt instrument has not changed. The adoption of this accounting update is not expected to have a material impact on our consolidated financial statements.

Improving the Presentation of Net Periodic Benefit Cost related to Defined Benefit Plans

Effective January 1, 2018, we adopted ASU 2017-07 which was issued primarily to improve the income statement presentation of the components of net periodic pension cost and net periodic postretirement benefit cost for an entity’s sponsored defined benefit pension and other postretirement plans. Upon adoption of this accounting update, our consolidated statement of earnings presents the current service cost within Operating and administrative expenses and the other components of net benefit cost within Other income/(expense). Previously, all components of net benefit cost were presented within Operating and administrative expenses. In addition, only the service cost component of net benefit cost will be capitalized on a prospective basis. The adoption of this accounting update did not, and is not expected to have a material impact on our consolidated financial statements.

Clarifying Guidance on Derecognition and Partial Sales of Nonfinancial Assets

Effective January 1, 2018, we adopted ASU 2017-05 on a modified retrospective basis. The new standard clarifies the scope provisions of nonfinancial assets and how to allocate consideration to each distinct asset, and amends the guidance for derecognition of a distinct nonfinancial asset in partial sale transactions. The adoption of this accounting update did not have a material impact on our consolidated financial statements.

Clarifying the Presentation of Restricted Cash in the Statement of Cash Flows

Effective January 1, 2018, we adopted ASU 2016-18 on a retrospective basis. The new standard clarifies guidance on the classification and presentation of changes in restricted cash and restricted cash equivalents within the statement of cash flows. The amendments require that changes in restricted cash and restricted cash equivalents be included within cash and cash equivalents when reconciling the opening and closing period amounts shown on the statement of cash flows. For current and comparative periods, we amended the presentation in the Consolidated Statement of Cash Flows to include restricted cash and restricted cash equivalents with cash and cash equivalents.

Simplifying Cash Flow Classification

Effective January 1, 2018, we adopted ASU 2016-15 on a retrospective basis. The new standard reduces diversity in practice of how certain cash receipts and cash payments are classified in the Consolidated Statement of Cash Flows. The new guidance addresses eight specific presentation issues. We assessed each of the eight specific presentation issues and the adoption of this ASU did not have a material impact on our consolidated financial statements.

Recognition and Measurement of Financial Assets and Liabilities

Effective January 1, 2018, we adopted ASU 2016-01 on a prospective basis. The new standard addresses certain aspects of recognition, measurement, presentation and disclosure of financial assets and liabilities. Investments in equity securities, excluding equity method and consolidated investments, are no longer classified as trading or available-for-sale securities. All investments in equity securities with readily determinable fair values are classified as investments at fair value through net income. Investments in equity securities without readily determinable fair values are measured using the fair value measurement alternative and are recorded at cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for an identical or similar investment of the same issuer. Investments in equity securities measured using the fair value measurement alternative are reviewed for indicators of impairment each reporting period. Fair value of financial instruments for disclosure purposes is measured using exit price. The adoption of this accounting update did not have a material impact on our consolidated financial statements.

Revenue from Contracts with Customers

Effective January 1, 2018, we adopted ASU 2014-09 on a modified retrospective basis to contracts that were not complete at the date of initial application. The new standard was issued with the intent of significantly enhancing consistency and comparability of revenue recognition practices across entities and industries. The new standard establishes a single, principles-based five-step model to be applied to all contracts with customers and introduces new and enhanced disclosure requirements. It also requires the use of more estimates and judgments than the previous standards .

In adopting Accounting Standards Codification (ASC) 606, we applied the practical expedient for contract modifications whereby contracts that were modified before January 1, 2018 were not retrospectively restated. Instead, the aggregate effect of all contract modifications occurring before that time has been reflected when identifying satisfied and unsatisfied performance obligations, determining the transaction price and allocating the transaction price to satisfied and unsatisfied obligations.

The below table presents the cumulative, immaterial effect of the adoption of ASC 606 on our Consolidated Statement of Financial Position as at January 1, 2018 on each affected financial statement line item along with explanations of those effects. For the three months ended March 31, 2018 , the effect of the adoption of ASC 606 on our Consolidated Statement of Earnings was not material.



	Balance at December 31, 2017		Adjustments Due to ASC 606		Balance at January 1, 2018
(millions of Canadian dollars)
Assets
Deferred amounts and other assets ^1,2	6,442		(170	)	6,272
Property, plant and equipment, net ²	90,711		112		90,823
Liabilities and equity
Accounts payable and other ^1,2	9,478		62		9,540
Other long-term liabilities ²	7,510		66		7,576
Deferred income taxes ^1,2	9,295		(62	)	9,233
Redeemable noncontrolling interests ^1,2	4,067		(38	)	4,029
Deficit ^1,2	(2,468	)	(86	)	(2,554	)


1	Revenue was previously recognized for a certain contract within the Liquids Pipelines business unit using a formula-based method. Under the new revenue standard, revenue is recognized on a straight-line basis over the term of the agreement in order to reflect the fulfillment of our performance obligation to provide up to a specified volume of pipeline capacity throughout the term of the contract.

Certain payments received from customers to offset the cost of constructing assets required to provide services to those customers, referred to as Contributions in Aid of Construction (CIACs) were previously recorded as reductions of property, plant and equipment regardless of whether the amounts were imposed by regulation or arose from negotiations with customers. Under the new revenue standard, CIACs which are negotiated as part of an agreement to provide transportation and other services to a customer are deemed to be advance payments for future services and are recognized as revenue when those future services are provided. Accordingly, negotiated CIACs are accounted for as deferred revenue and recognized as revenue over the term of the associated revenue contract. Amounts which are required to be collected from the customer based on requirements of the regulator continue to be accounted for as reductions of property, plant and equipment.

FUTURE ACCOUNTING POLICY CHANGES

Improvements to Accounting for Hedging Activities

ASU 2017-12 was issued in August 2017 with the objective of better aligning a company’s risk management activities and the resulting hedge accounting reflected in the financial statements. The amendments allow cash flow hedging of contractually specified components in financial and non-financial items. Under the new guidance, hedge ineffectiveness is no longer required to be measured and hedging instruments’ fair value changes will be recorded in the same income statement line as the hedged item. The ASU also allows the initial quantitative hedge effectiveness assessment to be performed at any time before the end of the quarter in which the hedge is designated. After initial quantitative testing is performed, an ongoing qualitative effectiveness assessment is permitted. The accounting update is effective January 1, 2019, with early adoption permitted, and is to be applied on a modified retrospective

basis. We are currently assessing the impact of the new standard on our consolidated financial statements.

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

ASU 2017-08 was issued in March 2017 with the intent of shortening the amortization period to the earliest call date for certain callable debt securities held at a premium. The accounting update is effective January 1, 2019 and will be applied on a modified retrospective basis. We are currently assessing the impact of the new standard on our consolidated financial statements.

Accounting for Credit Losses

ASU 2016-13 was issued in June 2016 with the intent of providing financial statement users with more useful information about the expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity at each reporting date. Current treatment uses the incurred loss methodology for recognizing credit losses that delays the recognition until it is probable a loss has been incurred. The accounting update adds a new impairment model, known as the current expected credit loss model, which is based on expected losses rather than incurred losses. Under the new guidance, an entity will recognize as an allowance its estimate of expected credit losses, which the Financial Accounting Standards Board believes will result in more timely recognition of such losses. The accounting update is effective January 1, 2020. We are currently assessing the impact of the new standard on our consolidated financial statements.

Recognition of Leases

ASU 2016-02 was issued in February 2016 with the intent to increase transparency and comparability among organizations. It requires lessees of operating lease arrangements to recognize lease assets and lease liabilities on the statement of financial position and disclose additional key information about lease agreements. The accounting update also replaces the current definition of a lease and requires that an arrangement be recognized as a lease when a customer has the right to obtain substantially all of the economic benefits from the use of an asset, as well as the right to direct the use of the asset. We are currently gathering a complete inventory of our lease contracts in order to assess the impact of the new standard on our consolidated financial statements. We will adopt the new standard on January 1, 2019 and we are currently evaluating options with respect to the transition practical expedients offered in connection with this update.

Further, ASU 2018-01 was issued in January 2018 to address stakeholder concerns about the costs and complexity of complying with the transition provisions of the new lease requirements as they relate to land easements. The amendments provide an optional transition practical expedient to not evaluate existing or expired land easements that were not previously accounted for as leases under existing guidance. We intend to elect this practical expedient in connection with the adoption of the new lease requirements.

3. REVENUE

REVENUE FROM CONTRACTS WITH CUSTOMERS

Major Products and Services



	Liquids Pipelines		Gas Transmission and Midstream	Gas Distribution	Green Power and Transmission	Energy Services	Eliminations and Other		Consolidated
Three months ended March 31, 2018	Liquids Pipelines		Gas Transmission and Midstream	Gas Distribution	Green Power and Transmission	Energy Services	Eliminations and Other		Consolidated
(millions of Canadian dollars)
Transportation revenue	2,058		952	239	—	—	—		3,249
Storage and other revenue	40		60	66	—	—	—		166
Gas gathering and processing revenue	—		205	—	—	—	—		205
Gas distribution revenue	—		—	1,926	—	—	—		1,926
Electricity and transmission revenue	—		—	—	154	—	—		154
Commodity sales	—		693	—	—	—	—		693
Total revenue from contracts with customers	2,098		1,910	2,231	154	—	—		6,393
Commodity sales	—		—	—	—	6,575	—		6,575
Other revenue ¹	(269	)	25	2	3	—	(3	)	(242	)
Intersegment revenue	80		2	4	—	57	(143	)	—
Total revenue	1,909		1,937	2,237	157	6,632	(146	)	12,726


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

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

Contract Balances

Contract assets represent the amount of revenue which has been recognized in advance of payments received for performance obligations we have fulfilled (or partially fulfilled) and prior to the point in time at which our right to the payment is unconditional. Amounts included in contract assets are transferred to accounts receivable when our right to the consideration becomes unconditional.

Contract liabilities represent payments received for performance obligations which have not been fulfilled. Contract liabilities primarily relate to make-up rights and deferred revenue. Revenue recognized during the current period included in contract liabilities at the beginning of the period is $95 million . Increases in contract liabilities from cash received, net of amounts recognized as revenue during the three months ended March 31, 2018 , were $96 million during the period.

Performance Obligations



Business Unit	Nature of Performance Obligation
Transportation services - pipelines	• Transportation and storage of crude oil, natural gas and natural gas liquids (NGL)
Gas Transmission and Midstream	• Sale of crude oil, natural gas and NGLs
Gas Transmission and Midstream	• Transportation, storage, gathering, compression and treating of natural gas
Gas Distribution	• Supply and delivery of natural gas
	• Transportation of natural gas
	• Storage of natural gas
Green Power and transmission	• Generation and transmission of electricity
Green Power and transmission	• Delivery of electricity from renewable energy generation facilities

There was no material revenue recognized in the current period from performance obligations satisfied in previous periods.

Payment Terms

Payments are received monthly from customers under long-term transportation, commodity sales, and gas gathering and processing contracts. Payments from Gas Distribution customers are received on a continuous basis based on established billing cycles.

Certain contracts in the United States offshore business provide for us to receive a series of fixed monthly payments (FMPs) for a specified period which is less than the period during which the performance obligations are satisfied. As a result, a portion of the FMPs is recorded as a contract liability. The FMPs are not considered to be a financing arrangement because the payments are scheduled to match the production profiles of offshore oil and gas fields, which generate greater revenue in the initial years of their productive lives.

Revenue to be Recognized from Unfulfilled Performance Obligations

Total revenue from performance obligations expected to be fulfilled in future periods is $63.8 billion , of which $5.7 billion and $5.9 billion is expected to be recognized during the nine months ending December 31, 2018 and year ending December 31, 2019 , respectively.

The revenues excluded from the amounts above based on optional exemptions available under ASC 606, as explained below, represent a significant portion of our overall revenues and revenues from contracts with customers. Certain revenues such as flow-through operating costs charged to shippers are recognized at the amount for which we have the right to invoice our customers. Those revenues are not included in the amounts for revenue to be recognized in the future from unfulfilled performance obligations above. Variable consideration is excluded from the amounts above due to the uncertainty of the associated consideration, which is generally resolved when actual volumes and prices are determined. Additionally, the effect of escalation on certain tolls which are contractually escalated for inflation has not been reflected in the amounts above as it is not possible to reliably estimate future inflation rates. Finally, revenues from contracts with customers which have an original expected duration of one year or less are excluded from the amounts above.

SIGNIFICANT JUDGMENTS MADE IN RECOGNIZING REVENUE

Long-Term Transportation Agreements

For long-term transportation agreements, significant judgments pertain to the period over which revenue is recognized and whether the agreement provides for make-up rights for the shippers. Transportation revenue earned from firm contracted capacity arrangements is recognized ratably over the contract period. Transportation revenue from interruptible or volumetric-based arrangements is recognized when services are performed.

Estimates of Variable Consideration

Revenue from arrangements subject to variable consideration is recognized only to the extent that it is probable that a significant reversal in the amount of cumulative revenue recognized will not occur when the uncertainty associated with the variable consideration is subsequently resolved. Uncertainties associated with variable consideration relate principally to differences between estimated and actual volumes and prices. These uncertainties are resolved each month when actual volumes sold or transported and actual tolls and prices are determined.

Recognition and Measurement of Revenue



	Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution	Green Power and Transmission	Energy Services	Consolidated
Three months ended March 31, 2018	Liquids Pipelines	Gas Transmission and Midstream	Gas Distribution	Green Power and Transmission	Energy Services	Consolidated
(millions of Canadian dollars)
Revenue from products transferred at a point in time ¹	—	693	25	—	—	718
Revenue from products and services transferred over time ²	2,098	1,217	2,206	154	—	5,675
Total revenue from contracts with customers	2,098	1,910	2,231	154	—	6,393


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


2	Revenue from crude oil and natural gas pipeline transportation, storage, natural gas gathering, compression and treating, natural gas distribution, natural gas storage services and electricity sales.

Performance Obligations Satisfied at a Point in Time

Revenue from commodity sales where the commodity is not immediately consumed prior to use is recognized at the point in time when the contractually specified volume of the commodity has been delivered, as control over the commodity transfers to the customer upon delivery.

Performance Obligations Satisfied Over Time

For arrangements involving the transportation and sale of petroleum products and natural gas where the transportation services or commodities are simultaneously received and consumed by the shipper or customer, we recognize revenue over time using an output method based on volumes of commodities delivered or transported. The measurement of the volumes transported or delivered corresponds directly to the benefits received by the shippers or customers during that period.

Determination of Transaction Prices

Prices for gas processing and transportation services are determined based on the capital cost of the facilities, pipelines and associated infrastructure required to provide such services plus a rate of return on capital invested that is determined either through negotiations with customers or through regulatory processes for those operations that are subject to rate regulation.

Prices for commodities sold are determined by reference to market price indices plus or minus a negotiated differential and in certain cases a marketing fee.

Prices for natural gas sold and distribution services provided by regulated natural gas distribution operations are prescribed by regulation.


4.	SEGMENTED INFORMATION

Effective December 31, 2017, we changed our segment-level profit measure to Earnings before interest, income taxes and depreciation and amortization from the previous measure of Earnings before interest and income taxes. We also renamed the Gas Pipelines and Processing segment to Gas Transmission and Midstream. The presentation of the prior year table has been revised in order to align with the current presentation.



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



	Liquids Pipelines		Gas Transmission and Midstream		Gas Distribution		Green Power and Transmission		Energy Services		Eliminations and Other		Consolidated
Three months ended March 31, 2017	Liquids Pipelines		Gas Transmission and Midstream		Gas Distribution		Green Power and Transmission		Energy Services		Eliminations and Other		Consolidated
(millions of Canadian dollars)
Revenues	2,155		1,235		1,584		137		6,133		(98	)	11,146
Commodity and gas distribution costs	(3	)	(647	)	(1,046	)	1		(5,968	)	98		(7,565	)
Operating and administrative	(760	)	(254	)	(189	)	(40	)	(12	)	(296	)	(1,551	)
Income from equity investments	86		110		36		2		2		—		236
Other income/(expense)	2		31		2		1		1		(2	)	35
Earnings/(loss) before interest, income taxes, and depreciation and amortization	1,480		475		387		101		156		(298	)	2,301
Depreciation and amortization													(672	)
Interest expense													(486	)
Income tax expense													(198	)
Earnings													945
Capital expenditures ¹	654		655		183		114		—		59		1,665


1	Includes allowance for equity funds used during construction.

TOTAL ASSETS



	March 31, 2018	December 31, 2017
(millions of Canadian dollars)
Liquids Pipelines	64,842	63,881
Gas Transmission and Midstream	61,880	60,745
Gas Distribution	25,784	25,956
Green Power and Transmission	6,466	6,289
Energy Services	1,628	2,514
Eliminations and Other	2,894	2,708
	163,494	162,093


5.	EARNINGS PER COMMON SHARE

BASIC

Earnings per common share is calculated by dividing earnings attributable to common shareholders by the weighted average number of common shares outstanding. The weighted average number of common shares outstanding has been reduced by our pro-rata weighted average interest in our own common shares of 13 million for the three months ended March 31, 2018 and 2017 , resulting from our reciprocal investment in Noverco Inc.

DILUTED

The treasury stock method is used to determine the dilutive impact of stock options. This method assumes any proceeds from the exercise of stock options would be used to purchase common shares at the average market price during the period.

Weighted average shares outstanding used to calculate basic and diluted earnings per share are as follows:



	Three months ended March 31,
	2018	2017
(number of common shares in millions)
Weighted average shares outstanding	1,685	1,177
Effect of dilutive options	4	10
Diluted weighted average shares outstanding	1,689	1,187

For the three months ended March 31, 2018 and 2017 , 29,882,142 and 13,545,193 , respectively, of anti-dilutive stock options with a weighted average exercise price of $49.80 and $57.71 , respectively, were excluded from the diluted earnings per common share calculation.


6.	ASSETS HELD FOR SALE

Midcoast Operating, L.P.

On May 9, 2018 our indirect subsidiary, Enbridge (U.S.) Inc. entered into a definitive agreement to sell Midcoast Operating, L.P. and its subsidiaries (Sales Agreement), which conducts our United States natural gas and NGL gathering, processing, transportation and marketing businesses, to AL Midcoast Holdings, LLC (an affiliate of ArcLight Capital Partners, LLC) for a cash purchase price of US $1.1 billion , subject to customary closing adjustments. The transaction is expected to close in the third quarter of 2018, subject to receipt of customary regulatory approvals and satisfaction of other customary closing conditions.

These assets, excluding our equity method investment in the Texas Express NGL pipeline system, were classified as held for sale and were measured at the lower of their carrying value or fair value less costs to sell as at December 31, 2017. As a result of entering into the Sales Agreement, the fair value of the assets held for sale as at March 31, 2018 were revised based on the sale price. Accordingly, we recorded a loss of $913 million ( $701 million after-tax attributable to us). This loss has been included within Asset impairment on the Consolidated Statements of Earnings for the three months ended March 31, 2018.

Line 10 Crude Oil Pipeline

At March 31, 2018 , we satisfied the condition as set out in our agreements for the sale of our Line 10 crude oil pipeline (Line 10), which originates near Hamilton, Ontario and terminates at West Seneca, New York. Our subsidiaries, Enbridge Pipelines Inc. and Enbridge Energy Partners, L.P., own the Canadian and United States portion of Line 10, respectively, and the related assets are included in our Liquids Pipeline segment.

We expect to close the sale of Line 10 within one year, subject to regulatory approval and certain closing conditions. As such, we classified Line 10 assets as held for sale and measured them at the lower of their carrying value or fair value less costs to sell, which resulted in a loss of $144 million ( $85 million after-tax attributable to us) included within Asset impairment on the Consolidated Statements of Earnings for the three months ended March 31, 2018 .

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



	March 31, 2018		December 31, 2017
(millions of Canadian dollars)
Accounts receivable and other (current assets held for sale)	305		424
Deferred amounts and other assets (long-term assets held for sale)	422		1,190
Accounts payable and other (current liabilities held for sale)	(233	)	(315	)
Other long-term liabilities (long-term liabilities held for sale)	(37	)	(34	)
Net assets held for sale	457		1,265


7.	DEBT

CREDIT FACILITIES

The following table provides details of our committed credit facilities at March 31, 2018 :



		March 31, 2018
	Maturity	Total Facilities	Draws ¹	Available
(millions of Canadian dollars)
Enbridge Inc. ²	2019-2022	6,644	2,616	4,028
Enbridge (U.S.) Inc.	2019	2,469	1,142	1,327
Enbridge Energy Partners, L.P. ³	2019-2022	3,385	1,660	1,725
Enbridge Gas Distribution Inc. (EGD)	2019	1,017	884	133
Enbridge Income Fund	2020	1,500	566	934
Enbridge Pipelines Inc.	2019	3,000	1,730	1,270
Spectra Energy Partners, LP ⁴	2022	3,223	2,135	1,088
Union Gas Limited (Union Gas)	2021	700	130	570
Total committed credit facilities		21,938	10,863	11,075


1	Includes facility draws, letters of credit and commercial paper issuances that are back-stopped by the credit facility.


2	Includes $135 million , $161 million (US $125 million ) and $150 million of commitments that expire in 2018, 2018 and 2020, respectively.


3	Includes $226 million (US $175 million ) and $239 million (US $185 million ) of commitments that expire in 2018 and 2020, respectively.


4	Includes $434 million (US $336 million ) of commitments that expire in 2021.

During the first quarter of 2018, Enbridge terminated a US$650 million credit facility, which was set to mature in 2019, and repaid drawn amounts. In addition, Enbridge (U.S.) Inc. terminated an unutilized US$950 million credit facility, which was set to mature in 2019.

During the first quarter of 2018, Westcoast Energy Inc. terminated an unutilized $400 million credit facility with a syndicate of banks. The facility was set to mature in 2021.

In addition to the committed credit facilities noted above, we have $790 million of uncommitted demand credit facilities, of which $511 million were unutilized as at March 31, 2018 . As at December 31, 2017, we had $792 million of uncommitted credit facilities, of which $518 million were unutilized.

Our credit facilities carry a weighted average standby fee of 0.2% per annum on the unused portion and draws bear interest at market rates. Certain credit facilities serve as a back-stop to the commercial paper programs and we have the option to extend such facilities, which are currently set to mature from 2019 to 2022.

As at March 31, 2018 and December 31, 2017 , commercial paper and credit facility draws, net of short-term borrowings and non-revolving credit facilities that mature within one year of $9,832 million and $10,055 million , respectively, are supported by the availability of long-term committed credit facilities and therefore have been classified as long-term debt.

LONG-TERM DEBT ISSUANCES

During the first quarter of 2018, we completed the following long-term debt issuances:



Company	Issue Date		Principal Amount
(millions of dollars)
Enbridge Inc.
	March 2018	Fixed-to-floating rate notes due 2078 ¹	US$850
Spectra Energy Partners, LP ²
	January 2018	3.50% senior notes due 2028	US$400
	January 2018	4.15% senior notes due 2048	US$400


1	Notes mature in 60 years and are callable on or after year 10 . For the initial 10 years, the notes carry a fixed interest rate of 6.25% . Subsequently, the interest rate will be set to equal the three-month London Interbank Offered Rate (LIBOR) plus a margin of 364 basis points from years 10 to 30 , and a margin of 439 basis points from years 30 to 60 .


2	Issued through Texas Eastern Transmission, LP, a wholly-owned operating subsidiary of Spectra Energy Partners, LP (SEP).

LONG-TERM DEBT REPAYMENTS

During the first quarter of 2018, we completed the following long-term debt repayments :



Company	Retirement/Repayment Date		Principal Amount	Cash Consideration
(millions of Canadian dollars unless otherwise stated)
Enbridge Southern Lights LP
	January 2018	4.01% medium-term notes due June 2040	9
Spectra Energy Capital, LLC ¹
Repurchase via Tender Offer
	March 2018	6.75% senior unsecured notes due 2032	US$64	US$80
	March 2018	7.50% senior unsecured notes due 2038	US$43	US$59
Redemption
	March 2018	5.65% senior unsecured notes due 2020	US$163	US$172
	March 2018	3.30% senior unsecured notes due 2023	US$498	US$508


1	The loss on debt extinguishment of $37 million ( US$29 million ), net of the fair value adjustment recorded upon completion of the stock-for-stock merger transaction on February 27, 2017 between Enbridge and Spectra Energy Corp ( the Merger Transaction ) , was reported within Interest expense in the Consolidated Statements of Earnings.

DEBT COVENANTS

Our credit facility agreements and term debt indentures include standard events of default and covenant provisions whereby accelerated repayment and/or termination of the agreements may result if we were to default on payment or violate certain covenants. As at March 31, 2018 , we were in compliance with all debt covenants.


8.	COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME

Changes in Accumulated other comprehensive income (AOCI) attributable to our common shareholders for the three months ended March 31, 2018 and 2017 are as follows:



	Cash Flow Hedges		Net Investment Hedges		Cumulative Translation Adjustment	Equity Investees	Pension and OPEB Adjustment		Total
(millions of Canadian dollars)
Balance at January 1, 2018	(644	)	(139	)	77	10	(277	)	(973	)
Other comprehensive income/(loss) retained in AOCI	70		(213	)	1,425	2	—		1,284
Other comprehensive (income)/loss reclassified to earnings
Interest rate contracts ¹	28		—		—	—	—		28
Commodity contracts ²	(1	)	—		—	—	—		(1	)
Foreign exchange contracts ³	4		—		—	—	—		4
Other contracts ⁴	9		—		—	—	—		9
Amortization of pension and OPEB actuarial loss and prior service costs ⁵	—		—		—	—	(38	)	(38	)
	110		(213	)	1,425	2	(38	)	1,286
Tax impact
Income tax on amounts retained in AOCI	(9	)	29		—	8	—		28
Income tax on amounts reclassified to earnings	(11	)	—		—	—	(1	)	(12	)
	(20	)	29		—	8	(1	)	16
Balance at March 31, 2018	(554	)	(323	)	1,502	20	(316	)	329



	Cash Flow Hedges		Net Investment Hedges		Cumulative Translation Adjustment	Equity Investees	Pension and OPEB Adjustment		Total
(millions of Canadian dollars)
Balance at January 1, 2017	(746	)	(629	)	2,700	37	(304	)	1,058
Other comprehensive income/(loss) retained in AOCI	(1	)	50		293	5	—		347
Other comprehensive (income)/loss reclassified to earnings
Interest rate contracts ¹	31		—		—	—	—		31
Commodity contracts ²	(2	)	—		—	—	—		(2	)
Other contracts ⁴	9		—		—	—	—		9
Amortization of pension and OPEB actuarial loss and prior service costs ⁵	—		—		—	—	6		6
	37		50		293	5	6		391
Tax impact
Income tax on amounts retained in AOCI	(1	)	(1	)	—	1	—		(1	)
Income tax on amounts reclassified to earnings	(8	)	—		—	—	(2	)	(10	)
	(9	)	(1	)	—	1	(2	)	(11	)
Balance at March 31, 2017	(718	)	(580	)	2,993	43	(300	)	1,438


1	Reported within Interest expense in the Consolidated Statements of Earnings.


2	Reported within Commodity costs in the Consolidated Statements of Earnings.


3	Reported within Other income/(expense) in the Consolidated Statements of Earnings.


4	Reported within Operating and administrative expense in the Consolidated Statements of Earnings.


5	These components are included in the computation of net periodic benefit costs and are reported within Other income/(expense) in the Consolidated Statements of Earnings.

9. NONCONTROLLING INTERESTS

As at December 31, 2017, we collectively owned a 75% ownership interest in SEP, together with 100% of SEP's incentive distribution rights (IDRs). On January 22, 2018, Enbridge and SEP announced the execution of a definitive agreement, resulting in us converting all of our IDRs and general partner economic interests in SEP into 172.5 million newly issued SEP common units. As part of the transaction, all of the IDRs have been eliminated. We now hold a non-economic general partner interest in SEP and own approximately 403 million of SEP common units, representing 83% of SEP's outstanding common units. As a result of this restructuring, we recorded a decrease in Noncontrolling interests of $1.5 billion and increases in Additional paid-in capital and Deferred income taxes of $1.1 billion and $333 million , respectively, for the three months ended March 31, 2018 .

10. RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

MARKET RISK

Our earnings, cash flows and other comprehensive income (OCI) are subject to movements in foreign exchange rates, interest rates, commodity prices and our share price (collectively, market risk). Formal risk management policies, processes and systems have been designed to mitigate these risks.

The following summarizes the types of market risks to which we are exposed and the risk management instruments used to mitigate them. We use a combination of qualifying and non-qualifying derivative instruments to manage the risks noted below.

Foreign Exchange Risk

We generate certain revenues, incur expenses, and hold a number of investments and subsidiaries that

are denominated in currencies other than Canadian dollars. As a result, our earnings, cash flows and OCI

are exposed to fluctuations resulting from foreign exchange rate variability.

We employ financial derivative instruments to hedge foreign currency denominated earnings exposure. A

combination of qualifying and non-qualifying derivative instruments are used to hedge anticipated foreign

currency denominated revenues and expenses, and to manage variability in cash flows. We hedge

certain net investments in United States dollar denominated investments and subsidiaries using foreign

currency derivatives and United States dollar denominated debt.

Interest Rate Risk

Our earnings and cash flows are exposed to short-term interest rate variability due to the regular repricing

of our variable rate debt, primarily commercial paper. Pay fixed-receive floating interest rate swaps are

used to hedge against the effect of future interest rate movements. We have implemented a program to

significantly mitigate the impact of short-term interest rate volatility on interest expense via execution of

floating to fixed interest rate swaps with an average swap rate of 2.6% .

As a result of the Merger Transaction, we are exposed to changes in the fair value of fixed rate debt that

arise as a result of the changes in market interest rates. Pay floating-receive fixed interest rate swaps are

used to hedge against future changes to the fair value of fixed rate debt. We have assumed a program

within our subsidiaries to mitigate the impact of fluctuations in the fair value of fixed rate debt via

execution of fixed to floating interest rate swaps with an average swap rate of 2.1% .

Our earnings and cash flows are also exposed to variability in longer term interest rates ahead of

anticipated fixed rate term debt issuances. Forward starting interest rate swaps are used to hedge against

the effect of future interest rate movements. We have assumed a program within some of our subsidiaries

to mitigate our exposure to long-term interest rate variability on select forecast term debt issuances via

execution of floating to fixed interest rate swaps with an average swap rate of 3.4% .

We also monitor our debt portfolio mix of fixed and variable rate debt instruments to manage a

consolidated portfolio of floating rate debt as a percentage of total debt outstanding. We primarily use qualifying derivative instruments to manage interest rate risk.

Commodity Price Risk

Our earnings and cash flows are exposed to changes in commodity prices as a result of our ownership

interests in certain assets and investments, as well as through the activities of our energy services

subsidiaries. These commodities include natural gas, crude oil, power and NGL. We employ financial and

physical derivative instruments to fix a portion of the variable price exposures that arise from physical

transactions involving these commodities. We use primarily non-qualifying derivative instruments to

manage commodity price risk.

Emission Allowance Price Risk

Emission allowance price risk is the risk of gain or loss due to changes in the market price of emission

allowances that our gas distribution business is required to purchase for itself and most of its customers

to meet greenhouse gas compliance obligations under the Ontario Cap and Trade framework. Similar to the gas supply procurement framework, the Ontario Energy Board's (OEB) framework for emission allowance procurement allows recovery of fluctuations in emission allowance prices in customer rates, subject to OEB approval.

Equity Price Risk

Equity price risk is the risk of earnings fluctuations due to changes in our share price. We have exposure

to our own common share price through the issuance of various forms of stock-based compensation,

which affect earnings through revaluation of the outstanding units every period. We use equity derivatives

to manage the earnings volatility derived from one form of stock-based compensation, restricted share

units. We use a combination of qualifying and non-qualifying derivative instruments to manage equity

price risk.

TOTAL DERIVATIVE INSTRUMENTS

The following table summarizes the Consolidated Statements of Financial Position location and carrying

value of our derivative instruments.

We generally have a policy of entering into individual International Swaps and Derivatives

Association, Inc. agreements, or other similar derivative agreements, with the majority of our financial

derivative counterparties. These agreements provide for the net settlement of derivative instruments

outstanding with specific counterparties in the event of bankruptcy or other significant credit events, and

reduces our credit risk exposure on financial derivative asset positions outstanding with the

counterparties in those circumstances. The following table summarizes the maximum potential settlement

in the event of these specific circumstances. All amounts are presented gross in the Consolidated

Statements of Financial Position.



March 31, 2018	Derivative Instruments Used as Cash Flow Hedges		Derivative Instruments Used as Net Investment Hedges		Derivative Instruments Used as Fair Value Hedges		Non- Qualifying Derivative Instruments		Total Gross Derivative Instruments as Presented		Amounts Available for Offset		Total Net Derivative Instruments
(millions of Canadian dollars)
Accounts receivable and other
Foreign exchange contracts	—		3		—		131		134		(70	)	64
Interest rate contracts	27		—		—		—		27		(5	)	22
Commodity contracts	—		—		—		100		100		(34	)	66
	27		3		—		231		261		(109	)	152
Deferred amounts and other assets
Foreign exchange contracts	18		—		—		92		110		(58	)	52
Interest rate contracts	15		—		—		—		15		—		15
Commodity contracts	19		—		—		3		22		(19	)	3
Other contracts	—		—		—		—		—		—		—
	52		—		—		95		147		(77	)	70
Accounts payable and other
Foreign exchange contracts	(5	)	(23	)	—		(327	)	(355	)	70		(285	)
Interest rate contracts	(112	)	—		(9	)	(185	)	(306	)	5		(301	)
Commodity contracts	(2	)	—		—		(244	)	(246	)	34		(212	)
Other contracts	(2	)	—		—		(8	)	(10	)	—		(10	)
	(121	)	(23	)	(9	)	(764	)	(917	)	109		(808	)
Other long-term liabilities
Foreign exchange contracts	—		(10	)	—		(1,650	)	(1,660	)	58		(1,602	)
Interest rate contracts	(20	)	—		(2	)	—		(22	)	—		(22	)
Commodity contracts	—		—		—		(160	)	(160	)	19		(141	)
Other contracts	(5	)	—		—		(3	)	(8	)	—		(8	)
	(25	)	(10	)	(2	)	(1,813	)	(1,850	)	77		(1,773	)
Total net derivative asset/(liability)
Foreign exchange contracts	13		(30	)	—		(1,754	)	(1,771	)	—		(1,771	)
Interest rate contracts	(90	)	—		(11	)	(185	)	(286	)	—		(286	)
Commodity contracts	17		—		—		(301	)	(284	)	—		(284	)
Other contracts	(7	)	—		—		(11	)	(18	)	—		(18	)
	(67	)	(30	)	(11	)	(2,251	)	(2,359	)	—		(2,359	)



December 31, 2017	Derivative Instruments Used as Cash Flow Hedges		Derivative Instruments Used as Net Investment Hedges		Derivative Instruments Used as Fair Value Hedges		Non- Qualifying Derivative Instruments		Total Gross Derivative Instruments as Presented		Amounts Available for Offset		Total Net Derivative Instruments
(millions of Canadian dollars)
Accounts receivable and other
Foreign exchange contracts	1		4		—		138		143		(83	)	60
Interest rate contracts	6		—		2		—		8		(3	)	5
Commodity contracts	2		—		—		143		145		(64	)	81
	9		4		2		281		296		(150	)	146
Deferred amounts and other assets					2
Foreign exchange contracts	1		1		—		143		145		(125	)	20
Interest rate contracts	7		—		6		—		13		(2	)	11
Commodity contracts	17		—		—		6		23		(19	)	4
	25		1		6		149		181		(146	)	35
Accounts payable and other
Foreign exchange contracts	(5	)	(42	)	—		(312	)	(359	)	83		(276	)
Interest rate contracts	(140	)	—		(6	)	(183	)	(329	)	3		(326	)
Commodity contracts	—		—		—		(439	)	(439	)	64		(375	)
Other contracts	(1	)	—		—		(2	)	(3	)	—		(3	)
	(146	)	(42	)	(6	)	(936	)	(1,130	)	150		(980	)
Other long-term liabilities
Foreign exchange contracts	(4	)	(9	)	—		(1,299	)	(1,312	)	125		(1,187	)
Interest rate contracts	(38	)	—		(2	)	—		(40	)	2		(38	)
Commodity contracts	—		—		—		(186	)	(186	)	19		(167	)
Other contracts	(1	)	—		—		—		(1	)	—		(1	)
	(43	)	(9	)	(2	)	(1,485	)	(1,539	)	146		(1,393	)
Total net derivative asset/(liability)					-2
Foreign exchange contracts	(7	)	(46	)	—		(1,330	)	(1,383	)	—		(1,383	)
Interest rate contracts	(165	)	—		—		(183	)	(348	)	—		(348	)
Commodity contracts	19		—		—		(476	)	(457	)	—		(457	)
Other contracts	(2	)	—		—		(2	)	(4	)	—		(4	)
	(155	)	(46	)	—		(1,991	)	(2,192	)	—		(2,192	)

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



March 31, 2018	2018		2019		2020		2021		2022		Thereafter ¹
Foreign exchange contracts - United States dollar forwards - purchase (millions of United States dollars)	544		2		1		—		—		—
Foreign exchange contracts - United States dollar forwards - sell (millions of United States dollars)	3,215		3,247		3,258		1,689		1,676		3,489
Foreign exchange contracts - British pound (GBP) forwards - purchase (millions of GBP)	—		—		—		—		—		—
Foreign exchange contracts - GBP forwards - sell (millions of GBP)	—		89		25		27		28		149
Foreign exchange contracts - Euro forwards - purchase (millions of Euro)	264		375		—		—		—		—
Foreign exchange contracts - Euro forwards - sell (millions of Euro)	—		—		35		169		169		889
Foreign exchange contracts - Japanese yen forwards - purchase (millions of yen)	—		32,662		—		—		20,000		—
Interest rate contracts - short-term pay fixed rate (millions of Canadian dollars)	3,749		2,100		527		109		93		203
Interest rate contracts - long-term receive fixed rate (millions of Canadian dollars)	728		580		553		188		102		—
Interest rate contracts - long-term debt pay fixed rate (millions of Canadian dollars)	2,242		800		447		—		—		—
Equity contracts (millions of Canadian dollars)	40		37		8		—		—		—
Commodity contracts - natural gas (billions of cubic feet)	(16	)	(57	)	(23	)	(2	)	14		2
Commodity contracts - crude oil (millions of barrels)	1		2		—		—		—		—
Commodity contracts - NGL (millions of barrels)	(10	)	(1	)	—		—		—		—
Commodity contracts - power (megawatt per hour) (MW/H))	60		64		66		(3	)	(43	)	(43	)

1 As at March 31, 2018 , thereafter includes an average net purchase/(sell) of power of (43) MW/H for 2023 through 2025 .

The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income

The following table presents the effect of cash flow hedges and net investment hedges on our consolidated earnings and consolidated comprehensive income, before the effect of income taxes:



	Three months ended March 31,
	2018		2017
(millions of Canadian dollars)
Amount of unrealized gain/(loss) recognized in OCI
Cash flow hedges
Foreign exchange contracts	21		(2	)
Interest rate contracts	100		(14	)
Commodity contracts	(2	)	21
Other contracts	(14	)	(9	)
Net investment hedges
Foreign exchange contracts	16		8
	121		4
Amount of (gain)/loss reclassified from AOCI to earnings (effective portion)
Foreign exchange contracts ¹	(1	)	1
Interest rate contracts ²	41		48
Commodity contracts ³	(1	)	(2	)
Other contracts ⁴	9		9
	48		56
Amount of (gain)/loss reclassified from AOCI to earnings (ineffective portion and amount excluded from effectiveness testing)
Interest rate contracts ²	(1	)	2
	(1	)	2


1	Reported within Transportation and other services revenues and Other income/(expense) in the Consolidated Statements of Earnings.


2	Reported within Interest expense in the Consolidated Statements of Earnings.


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


4	Reported within Operating and administrative expense in the Consolidated Statements of Earnings.

We estimate that a loss of $22 million of AOCI related to cash flow hedges will be reclassified to earnings in the next 12 months. Actual amounts reclassified to earnings depend on the foreign exchange rates, interest rates and commodity prices in effect when derivative contracts that are currently outstanding mature. For all forecasted transactions, the maximum term over which we are hedging exposures to the variability of cash flows is 33 months as at March 31, 2018 .

Fair Value Derivatives

For interest rate derivative instruments that are designated and qualify as fair value hedges, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item attributable to the hedged risk is included in Interest expense in the Consolidated Statements of Earnings. During the three months ended March 31, 2018 and 2017 , we recognized an unrealized loss of $8 million and $2 million , respectively, on the derivative and an unrealized gain of $8 million and $2 million , respectively, on the hedged item in earnings. During the three months ended March 31, 2018 and 2017 , we recognized a realized loss of $3 million and nil , respectively, on the derivative and a realized gain of $3 million and nil , respectively, on the hedged item in earnings. The difference in the amounts, if any, represents hedge ineffectiveness.

Non-Qualifying Derivatives

The following table presents the unrealized gains and losses associated with changes in the fair value of

our non-qualifying derivatives:



	Three months ended March 31,
	2018		2017
(millions of Canadian dollars)
Foreign exchange contracts ¹	(424	)	273
Interest rate contracts ²	(2	)	(18	)
Commodity contracts ³	175		163
Other contracts ⁴	(9	)	—
Total unrealized derivative fair value gain/(loss), net	(260	)	418


1	For the respective three months ended periods, reported within Transportation and other services revenues ( 2018 - $297 million loss ; 2017 - $159 million gain ) and Other income/(expense) ( 2018 - $127 million loss ; 2017 - $114 million gain ) in the Consolidated Statements of Earnings.


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

For the respective three months ended periods, reported within Transportation and other services revenues ( 2018 - $1 million loss ; 2017 - $22 million loss ), Commodity sales ( 2018 - $82 million gain ; 2017 - $187 million gain ), Commodity costs ( 2018 - $84 million gain ; 2017 - $5 million gain ) and Operating and administrative expense ( 2018 - $10 million gain ; 2017 - $7 million loss ) in the Consolidated Statements of Earnings.


4	Reported within Operating and administrative expense in the Consolidated Statements of Earnings.

LIQUIDITY RISK

Liquidity risk is the risk that we will not be able to meet our financial obligations, including commitments

and guarantees, as they become due. In order to mitigate this risk, we forecast cash requirements over a

12 month rolling time period to determine whether sufficient funds will be available and maintain

substantial capacity under our committed bank lines of credit to address any contingencies. Our primary

sources of liquidity and capital resources are funds generated from operations, the issuance of

commercial paper and draws under committed credit facilities and long-term debt, which includes

debentures and medium-term notes. We also maintain current shelf prospectuses with securities

regulators which enables, subject to market conditions, ready access to either the Canadian or United

States public capital markets. In addition, we maintain sufficient liquidity through committed credit facilities

with a diversified group of banks and institutions which, if necessary, enables us to fund all anticipated

requirements for approximately one year without accessing the capital markets. We are in compliance

with all the terms and conditions of our committed credit facility agreements and term debt indentures as

at March 31, 2018 . As a result, all credit facilities are available to us and the banks are obligated to

fund and have been funding us under the terms of the facilities.

CREDIT RISK

Entering into derivative instruments may result in exposure to credit risk from the possibility that a

counterparty will default on its contractual obligations. In order to mitigate this risk, we enter into risk

management transactions primarily with institutions that possess investment grade credit ratings. Credit

risk relating to derivative counterparties is mitigated by credit exposure limits and contractual

requirements, netting arrangements, and ongoing monitoring of counterparty credit exposure using

external credit rating services and other analytical tools.

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



	March 31, 2018	December 31, 2017
(millions of Canadian dollars)
Canadian financial institutions	49	82
United States financial institutions	29	19
European financial institutions	143	145
Asian financial institutions	15	2
Other ¹	72	137
	308	385


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

As at March 31, 2018 , we provided letters of credit totaling nil in lieu of providing cash collateral to our counterparties pursuant to the terms of the relevant ISDA agreements. We held no cash collateral on derivative asset exposures as at March 31, 2018 and December 31, 2017 .

Gross derivative balances have been presented without the effects of collateral posted. Derivative assets

are adjusted for non-performance risk of our counterparties using their credit default swap spread rates,

and are reflected at fair value. For derivative liabilities, our non-performance risk is considered in the

valuation.

Credit risk also arises from trade and other long-term receivables, and is mitigated through credit exposure limits and contractual requirements, assessment of credit ratings and netting arrangements. Within EGD and Union Gas, credit risk is mitigated by the utilities' large and diversified customer base and the ability to recover an estimate for doubtful accounts through the ratemaking process. We actively monitor the financial strength of large industrial customers and, in select cases, have obtained additional security to minimize the risk of default on receivables. Generally, we classify and provide for receivables older than 30 days as past due. The maximum exposure to credit risk related to non-derivative financial assets is their carrying value.

FAIR VALUE MEASUREMENTS

Our financial assets and liabilities measured at fair value on a recurring basis include derivative

instruments. We also disclose the fair value of other financial instruments not measured at fair value. The

fair value of financial instruments reflects our best estimates of market value based on generally accepted

valuation techniques or models and is supported by observable market prices and rates. When such

values are not available, we use discounted cash flow analysis from applicable yield curves based on

observable market inputs to estimate fair value.

FAIR VALUE OF FINANCIAL INSTRUMENTS

We categorize our derivative instruments measured at fair value into one of three different levels

depending on the observability of the inputs employed in the measurement.

Level 1

Level 1 includes derivatives measured at fair value based on unadjusted quoted prices for identical

assets and liabilities in active markets that are accessible at the measurement date. An active market for

a derivative is considered to be a market where transactions occur with sufficient frequency and volume

to provide pricing information on an ongoing basis. Our Level 1 instruments consist primarily of exchange-traded derivatives used to mitigate the risk of crude oil price fluctuations.

Level 2

Level 2 includes derivative valuations determined using directly or indirectly observable inputs other than

quoted prices included within Level 1. Derivatives in this category are valued using models or other

industry standard valuation techniques derived from observable market data. Such valuation techniques

include inputs such as quoted forward prices, time value, volatility factors and broker quotes that can be

observed or corroborated in the market for the entire duration of the derivative. Derivatives valued using

Level 2 inputs include non-exchange traded derivatives such as over-the-counter foreign exchange

forward and cross currency swap contracts, interest rate swaps, physical forward commodity contracts, as

well as commodity swaps and options for which observable inputs can be obtained.

We have also categorized the fair value of our held to maturity preferred share investment and long-term

debt as Level 2. The fair value of our held to maturity preferred share investment is primarily based on the

yield of certain Government of Canada bonds. The fair value of our long-term debt is based on quoted

market prices for instruments of similar yield, credit risk and tenor.

Level 3

Level 3 includes derivative valuations based on inputs which are less observable, unavailable or where

the observable data does not support a significant portion of the derivatives’ fair value. Generally, Level 3

derivatives are longer dated transactions, occur in less active markets, occur at locations where pricing

information is not available or have no binding broker quote to support Level 2 classification. We have

developed methodologies, benchmarked against industry standards, to determine fair value for these

derivatives based on extrapolation of observable future prices and rates. Derivatives valued using Level 3

inputs primarily include long-dated derivative power contracts and NGL and natural gas contracts, basis

swaps, commodity swaps, power and energy swaps, as well as options. We do not have any other

financial instruments categorized in Level 3.

We use the most observable inputs available to estimate the fair value of our derivatives. When possible,

we estimate the fair value of our derivatives based on quoted market prices. If quoted market prices are

not available, we use estimates from third party brokers. For non-exchange traded derivatives classified

in Levels 2 and 3, we use standard valuation techniques to calculate the estimated fair value. These

methods include discounted cash flows for forwards and swaps and Black-Scholes-Merton pricing models

for options. Depending on the type of derivative and nature of the underlying risk, we use observable

market prices (interest, foreign exchange, commodity and share price) and volatility as primary inputs to

these valuation techniques. Finally, we consider our own credit default swap spread as well as the credit

default swap spreads associated with our counterparties in our estimation of fair value.

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



March 31, 2018	Level 1		Level 2		Level 3		Total Gross Derivative Instruments
(millions of Canadian dollars)
Financial assets
Current derivative assets
Foreign exchange contracts	—		134		—		134
Interest rate contracts	—		27		—		27
Commodity contracts	—		18		82		100
	—		179		82		261
Long-term derivative assets
Foreign exchange contracts	—		110		—		110
Interest rate contracts	—		15		—		15
Commodity contracts	—		1		21		22
Other contracts	—		—		—		—
	—		126		21		147
Financial liabilities
Current derivative liabilities
Foreign exchange contracts	—		(355	)	—		(355	)
Interest rate contracts	—		(306	)	—		(306	)
Commodity contracts	(6	)	(88	)	(152	)	(246	)
Other contracts	—		(10	)	—		(10	)
	(6	)	(759	)	(152	)	(917	)
Long-term derivative liabilities
Foreign exchange contracts	—		(1,660	)	—		(1,660	)
Interest rate contracts	—		(22	)	—		(22	)
Commodity contracts	—		(4	)	(156	)	(160	)
Other contracts	—		(8	)	—		(8	)
	—		(1,694	)	(156	)	(1,850	)
Total net financial liabilities
Foreign exchange contracts	—		(1,771	)	—		(1,771	)
Interest rate contracts	—		(286	)	—		(286	)
Commodity contracts	(6	)	(73	)	(205	)	(284	)
Other contracts	—		(18	)	—		(18	)
	(6	)	(2,148	)	(205	)	(2,359	)



December 31, 2017	Level 1		Level 2		Level 3		Total Gross Derivative Instruments
(millions of Canadian dollars)
Financial assets
Current derivative assets
Foreign exchange contracts	—		143		—		143
Interest rate contracts	—		8		—		8
Commodity contracts	1		30		114		145
	1		181		114		296
Long-term derivative assets
Foreign exchange contracts	—		145		—		145
Interest rate contracts	—		13		—		13
Commodity contracts	—		2		21		23
	—		160		21		181
Financial liabilities
Current derivative liabilities
Foreign exchange contracts	—		(359	)	—		(359	)
Interest rate contracts	—		(329	)	—		(329	)
Commodity contracts	(13	)	(87	)	(339	)	(439	)
Other contracts	—		(3	)	—		(3	)
	(13	)	(778	)	(339	)	(1,130	)
Long-term derivative liabilities
Foreign exchange contracts	—		(1,312	)	—		(1,312	)
Interest rate contracts	—		(40	)	—		(40	)
Commodity contracts	—		(3	)	(183	)	(186	)
Other contracts	—		(1	)	—		(1	)
	—		(1,356	)	(183	)	(1,539	)
Total net financial liabilities
Foreign exchange contracts	—		(1,383	)	—		(1,383	)
Interest rate contracts	—		(348	)	—		(348	)
Commodity contracts	(12	)	(58	)	(387	)	(457	)
Other contracts	—		(4	)	—		(4	)
	(12	)	(1,793	)	(387	)	(2,192	)

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



March 31, 2018	Fair Value		Unobservable Input	Minimum Price/Volatility		Maximum Price/Volatility		Weighted Average Price		Unit of Measurement
(fair value in millions of Canadian dollars)
Commodity contracts - financial ¹
Natural gas	9		Forward gas price	2.49		4.25		3.20		$/mmbtu ³
Crude	(4	)	Forward crude price	48.92		63.73		53.07		$/barrel
NGL	(4	)	Forward NGL price	0.34		1.83		1.29		$/gallon
Power	(100	)	Forward power price	14.30		76.27		52.00		$/MW/H
Commodity contracts - physical ¹
Natural gas	(81	)	Forward gas price	0.78		4.91		2.57		$/mmbtu ³
Crude	(29	)	Forward crude price	38.01		91.27		75.29		$/barrel
NGL	5		Forward NGL price	0.34		1.88		0.86		$/gallon
Commodity options ²
Crude	(1	)	Option volatility	22	%	24	%	23	%
NGL	—		Option volatility	—	%	—	%	—	%
Power	—		Option volatility	23	%	26	%	24	%
	(205	)


1	Financial and physical forward commodity contracts are valued using a market approach valuation technique.


2	Commodity options contracts are valued using an option model valuation technique.


3	One million British thermal units (mmbtu).

If adjusted, the significant unobservable inputs disclosed in the table above would have a direct impact on

the fair value of our Level 3 derivative instruments. The significant unobservable inputs used in the fair

value measurement of Level 3 derivative instruments include forward commodity prices and, for option

contracts, price volatility. Changes in forward commodity prices could result in significantly different fair

values for our Level 3 derivatives. Changes in price volatility would change the value of the option

contracts. Generally, a change in the estimate of forward commodity prices is unrelated to a change in the

estimate of price volatility.

Changes in net fair value of derivative assets and liabilities classified as Level 3 in the fair value hierarchy were as follows:



	Three months ended March 31,
	2018		2017
(millions of Canadian dollars)
Level 3 net derivative liability at beginning of period	(387	)	(295	)
Total gain/(loss)
Included in earnings ¹	31		83
Included in OCI	(3	)	19
Settlements	154		70
Level 3 net derivative liability at end of period	(205	)	(123	)


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

Our policy is to recognize transfers as at the last day of the reporting period. There were no transfers between levels as at March 31, 2018 or 2017 .

FAIR VALUE OF OTHER FINANCIAL INSTRUMENTS

Our other long-term investments in other entities with no actively quoted prices are classified as Fair Value Measurement Alternative (FMVA) investments and are recorded at cost less impairment. The carrying value of FMVA other long-term investments totaled $100 million and $99 million as at March 31, 2018 and December 31, 2017 , respectively.

We have Restricted long-term investments held in trust totaling $280 million and $267 million as at March 31, 2018 and December 31, 2017 , respectively, which are recognized at fair value.

We have a held to maturity preferred share investment carried at its amortized cost of $382 million and $371 million as at March 31, 2018 and December 31, 2017 , respectively. These preferred shares are entitled to a cumulative preferred dividend based on the yield of 10 -year Government of Canada bonds plus a margin of 4.50% . As at March 31, 2018 and December 31, 2017 , the fair value of this preferred share investment approximates its face value of $580 million .

As at March 31, 2018 and December 31, 2017 , our long-term debt had a carrying value of $65.6 billion and $64.0 billion , respectively, before debt issuance costs and a fair value of $68.0 billion and $67.4 billion , respectively. We also have noncurrent notes receivable carried at book value recorded in Deferred amounts and other assets in the Consolidated Statements of Financial Position. As at March 31, 2018 and December 31, 2017 , the noncurrent notes receivable has a carrying value of $92 million and $89 million , respectively, and a fair value of $92 million and $89 million , respectively.

The fair value of other financial assets and liabilities other than derivative instruments, other long-term investments, Restricted long-term investments and long-term debt approximate their cost due to the short period to maturity.

NET INVESTMENT HEDGES

We have designated a portion of our United States dollar denominated debt, as well as a portfolio of

foreign exchange forward contracts, as a hedge of our net investment in United States dollar

denominated investments and subsidiaries.

During the three months ended March 31, 2018 and 2017 , we recognized an unrealized foreign exchange

loss of $194 million on the translation of United States dollar denominated debt and a gain of $20 million , respectively, and an unrealized gain on the change in fair value of our outstanding foreign exchange forward contracts of $15 million and $9 million , respectively, in OCI. During the three months ended March 31, 2018 and 2017 , we recognized a realized loss of $23 million and gain of $1 million , respectively, in OCI associated with the settlement of foreign exchange forward contracts and recognized a realized loss of $11 million and gain of $20 million , respectively, in OCI associated with the settlement of United States dollar denominated debt that had matured during the period. There was no ineffectiveness during the three months ended March 31, 2018 and 2017 .

11. INCOME TAXES

The effective income tax rates for the three months ended March 31, 2018 and 2017 were (16.7)% and 17.3% , respectively. The period-over-period decrease in the effective income tax rate is primarily due to the effects of rate-regulated accounting for income taxes and other permanent items relative to the decrease in earnings for the three months ended March 31, 2018 as well as the impact of the United States federal corporate income tax rate reduction enacted in 2017.

On December 22, 2017, the United States enacted the TCJA and we made reasonable estimates for the measurement and accounting of certain effects of the TCJA in our consolidated financial statements for the year ended December 31, 2017. We recorded a nil provision in the first quarter of 2018, based on

existing guidance and legislation, for the remaining effects of the TCJA including the Global Intangible Low Taxed Income tax and the Base Erosion and Anti-abuse tax.

12. PENSION AND OTHER POSTRETIREMENT BENEFITS



	Three months ended March 31,
	2018		2017
(millions of Canadian dollars)
Service cost	65		54
Interest cost	45		32
Expected return on plan assets	(82	)	(51	)
Amortization of prior service costs	(1	)	—
Amortization of actuarial loss	7		9
Net periodic benefit costs	34		44

13. CONTINGENCIES

We are involved in various other legal and regulatory actions and proceedings which arise in the normal course of business, including interventions in regulatory proceedings and challenges to regulatory approvals and permits by special interest groups. While the final outcome of such actions and proceedings cannot be predicted with certainty, management believes that the resolution of such actions and proceedings will not have a material impact on our interim consolidated financial position or results of operations.

TAX MATTERS

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

14. SUBSEQUENT EVENTS

On April 12, 2018, we completed an offering of $750 million of fixed-to-floating rate subordinated

notes that mature in 60 years and are callable on or after year 10 . For the initial 10 years , the notes carry

a fixed interest rate of 6.625% . After the initial 10 years , the interest rate will be set to equal the Canadian Dollar Offered Rate plus a margin of 432 basis points from years 10 to 30 , and a margin of 507 basis points from years 30 to 60 .

On April 12, 2018, we completed an offering of US$600 million of fixed-to-floating rate subordinated

notes that mature in 60 years and are callable on or after year 5 . For the initial 5 years , the notes carry a fixed interest rate of 6.375% . After the initial 5 years , the interest rate will be set to equal the three-month LIBOR plus a margin of 359 basis points from years 5 to 10 , a margin of 384 basis points from years 10 to 25 , and a margin of 459 basis points from years 25 to 60 .

On April 30, 2018, Sabal Trail Transmission, LLC (Sabal Trail), a joint venture in which SEP owns a 50% interest, issued US $500 million in aggregate principal amount of 4.246% senior notes due in 2028,

US $600 million in aggregate principal amount of 4.682% due in 2038 and US $400 million in aggregate principle amount of 4.832% due in 2048. Sabal Trail distributed net proceeds from the offering to the partners as a partial reimbursement of construction and development costs incurred by the partners. The net contribution made to SEP was approximately US $750 million to be used to pay down indebtedness.

On May 9, 2018 we entered into agreements with the Canadian Pension Plan Investment Board to sell a 49% interest in all of our Canadian renewable energy generation assets, 49% of two large United States renewable assets and 49% of our interest in the Hohe See Offshore wind farm and its subsequent expansion, both concurrently under construction in Germany (collectively, the Assets). Initial proceeds from the transaction are $1.75 billion . In addition, our partner will fund their pro-rata share of the remaining capital on the Hohe See Offshore wind project. We will maintain a 51% interest in the Assets and continue to manage, operate and provide administrative services for the Assets. The transaction is subject to closing adjustments and conditions customary in transactions of this nature. Closing is expected to occur during the third quarter of 2018 subject to the receipt of all necessary regulatory approvals and consents.

On May 9, 2018 our indirect subsidiary, Enbridge (U.S.) Inc. entered into a definitive agreement to sell Midcoast Operating, L.P. and its subsidiaries (Sales Agreement), which conducts our United States natural gas and NGL gathering, processing, transportation and marketing businesses, to AL Midcoast Holdings, LLC (an affiliate of ArcLight Capital Partners, LLC) for a cash purchase price of US$ 1.1 billion , subject to customary closing adjustments. The transaction is expected to close in the third quarter of 2018, subject to receipt of customary regulatory approvals and satisfaction of other customary closing conditions.

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 Item 1. Financial Statements of this report and in conjunction with the audited consolidated financial statements and accompanying footnotes in our Annual Report on Form 10-K for the year ended December 31, 2017, as filed with the Securities and Exchange Commission on February 16, 2018.

UNITED STATES TAX REFORM UPDATE

On December 22, 2017, the United States enacted the Tax Cuts and Jobs Act (TCJA). As disclosed in our Annual Report on Form 10-K, as filed with the Securities and Exchange Commission on February 16, 2018, we made certain estimates for the measurement and accounting of certain effects of the TCJA for the year ended and as at December 31, 2017. As we continue to gather, prepare and analyze the necessary information in reasonable detail to complete the accounting for the impact of the TCJA, we continue to refine our estimates. During the first quarter of 2018 we refined our calculation of the regulatory liability associated with the TCJA. This resulted in a reduction of the US$860 million overall regulatory liability at Spectra Energy Partners, LP (SEP) by US$25 million.

We have also recorded a nil provision in the first quarter of 2018, based on existing guidance and

legislation, for the Global Intangible Low Taxed Income tax and the Base Erosion and Anti-abuse

tax.

SEP INCENTIVE DISTRIBUTION RIGHTS

On January 22, 2018, Enbridge and SEP announced the execution of a definitive agreement, resulting in us converting all of our incentive distribution rights (IDRs) and general partner economic interests in SEP into 172.5 million newly issued SEP common units. As part of the transaction, all of the IDRs have been eliminated. We now hold a non-economic general partner interest in SEP and own approximately 403 million of SEP common units, representing approximately 83% of SEP's outstanding common units.

REVISED FERC POLICY ON TREATMENT OF INCOME TAXES

On March 15, 2018, the Federal Energy Regulatory Commission (FERC) revised a long standing policy announcing that it would no longer permit entities organized as Master Limited Partnerships (MLPs) to recover an income tax allowance for interstate pipeline assets with cost-of-service rates. The announcement of the Revised Policy Statement was accompanied by: (i) a Notice of Proposed Rulemaking proposing interstate natural gas pipelines file a one-time report to quantify the impact of the federal income tax rate reduction and the impact of the revised Policy Statement on each pipeline; and (ii) a Notice of Inquiry seeking comment on how FERC should address changes related to accumulated deferred income taxes and bonus depreciation.

We hold United States liquids and natural gas pipelines through a number of different ownership structures, including MLPs. Spectra Energy Partners (SEP) and Enbridge Energy Partners (EEP) have responded to the FERC announcement regarding tax allowance, both directly and through industry associations, objecting to the change in FERC policy and requesting a re-hearing. On April 27, 2018, the FERC issued a tolling order for the purpose of affording it additional time for consideration of matters raised on rehearing. These FERC announcements have adversely affected MLPs generally, including

SEP and EEP. Both the direct consequences of the change in FERC policy as well as the adverse market effect may negatively impact the longer-term availability of capital to SEP and EEP at attractive terms.

While there will likely be varying impacts to each of the sponsored vehicles, on a consolidated basis, we do not expect a material impact to our results of operations or cash flows over the 2018 to 2020 horizon. Under the International Joint Toll mechanism on the Mainline System, reductions in the EEP tariff would create an offsetting revenue increase on the Canadian Mainline system owned by the Fund Group. In addition, while many uncertainties remain in regard to the implementation of the recent FERC actions, if implemented as announced, we estimate the unmitigated impact to revenue from SEP would not be material to us. We continue to evaluate a variety of options to mitigate the negative impact of the FERC policy change on both EEP and SEP.

ASSET MONETIZATION

On May 9, 2018 we entered into agreements with the Canadian Pension Plan Investment Board to sell a 49% interest in all of our Canadian renewable energy generation assets, 49% of two large United States renewable assets and 49% of our interest in the Hohe See Offshore wind farm and its subsequent expansion, both concurrently under construction in Germany, (collectively, the Assets). Initial proceeds from the transaction are $1.75 billion. In addition, our partner will fund their pro-rata share of the remaining capital on the Hohe See Offshore wind project. We will maintain a 51% interest in the Assets and continue to manage, operate and provide administrative services for the Assets. The transaction is subject to closing adjustments and conditions customary in transactions of this nature. Closing is expected to occur during the third quarter of 2018 subject to the receipt of all necessary regulatory approvals and consents.

On May 9, 2018 our indirect subsidiary, Enbridge (U.S.) Inc. entered into a definitive agreement to sell Midcoast Operating, L.P. and its subsidiaries, which conducts our United States natural gas and natural gas liquids gathering, processing, transportation and marketing businesses, to AL Midcoast Holdings, LLC (an affiliate of ArcLight Capital Partners, LLC) for a cash purchase price of US$1.1 billion, subject to customary closing adjustments. The transaction is expected to close in the third quarter of 2018, subject to receipt of customary regulatory approvals and satisfaction of other customary closing conditions.

FORWARD-LOOKING INFORMATION

Forward-looking information, or forward-looking statements, have been included in this quarterly report on MD&A to provide information about us and our subsidiaries and affiliates, including management’s assessment of Enbridge and its 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, Green Power 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; estimated future dividends; recovery of the costs of the Canadian portion of the Line 3 Replacement Program (Canadian L3R Program); 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 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; impact of the Canadian L3R Program on existing integrity programs; the sponsored

vehicle strategy; dividend payout policy; dividend growth and dividend payout expectation; expectations on impact of hedging program; and expectations resulting from the successful execution of our 2018-2020 Strategic Plan.

Our forward-looking statements are subject to risks and uncertainties pertaining to the impact of the Merger Transaction, operating performance, regulatory parameters, 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 MD&A 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 MD&A or otherwise, whether as a result of new information, future events or otherwise. All subsequent 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.

RESULTS OF OPERATIONS



	Three months ended March 31,
	2018		2017
(millions of Canadian dollars, except per share amounts)
Segment earnings/(loss) before interest, income taxes and depreciation and amortization
Liquids Pipelines	1,156		1,480
Gas Transmission and Midstream	126		475
Gas Distribution	636		387
Green Power and Transmission	109		101
Energy Services	169		156
Eliminations and Other	(279	)	(298	)

Depreciation and amortization	(824	)	(672	)
Interest expense	(656	)	(486	)
Income tax expense	73		(198	)
(Earnings)/loss attributable to noncontrolling interests and redeemable noncontrolling interests	24		(224	)
Preference share dividends	(89	)	(83	)
Earnings attributable to common shareholders	445		638
Earnings per common share	0.26		0.54
Diluted earnings per common share	0.26		0.54

EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS

Three months ended March 31, 2018 , compared with the three months ended March 31, 2017

Earnings Attributable to Common Shareholders for the period ended March 31, 2018 were positively impacted by contributions of approximately $364 million from new assets following the completion of the stock-for-stock merger transaction on February 27, 2017 between Enbridge and Spectra Energy Corp (Merger Transaction).

After taking into consideration the contribution of additional earnings from the Merger Transaction, Earnings Attributable to Common Shareholders was negatively impacted by $893 million due to certain unusual, infrequent or other factors, primarily explained by the following:


•	a loss of $913 million ($701 million after-tax attributable to us) on Midcoast Operating, L.P. and its subsidiaries resulting from a revision to the fair value of the assets held for sale based on the sale price; refer to Part I. Item 1. Financial Statements - Note 6. Assets Held for Sale ;

•

a non-cash, unrealized derivative fair value loss of $277 million ($146 million after-tax attributable to us) in 2018, compared with a gain of $416 million ($245 million after-tax attributable to us) in the corresponding 2017 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;


•	a loss of $144 million ($85 million after-tax attributable to us) in 2018 related to the Line 10 crude oil pipeline (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;


•	employee severance, transition and transformation costs of $97 million ($96 million after-tax attributable to us) in 2018, compared with $129 million ($78 million after-tax attributable to us) in the corresponding 2017 period, related to the Merger Transaction; partially offset by


•	the absence of transaction costs of $152 million ($111 million after-tax attributable to us) recorded in 2017 related to the Merger Transaction;


•	a gain of $50 million after-tax attributable to us in 2018, compared with a loss $40 million in the corresponding 2017 period, resulting from the reallocation of income between our interest and the

noncontrolling interests in Enbridge Energy Partners, L.P. (EEP) to resolve capital account deficits as required under EEP’s partnership agreement; and


•	a gain of $63 million after-tax attributable to us in 2018 resulting from the impact of the TCJA on our United States Green Power and Transmission assets.

As it pertains to the non-cash, unrealized derivative fair value gains and losses discussed above, we have a comprehensive long-term economic hedging program to mitigate interest rate, foreign exchange and commodity price risks. This creates volatility in 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 $336 million increase is primarily explained by the following significant business factors:


•	stronger contributions from our Liquids Pipelines segment due to a higher foreign exchange hedge rate used to record United States dollar denominated Canadian Mainline revenues, a higher International Joint Tariff (IJT) Benchmark Toll and higher throughput driven by capacity optimization initiatives implemented in 2017;


•	contributions from new Liquids Pipelines assets placed into service in 2017; and


•	increased earnings from our Gas Distribution segment due to colder weather and higher distribution charges.

BUSINESS SEGMENTS

LIQUIDS PIPELINES



	Three months ended March 31,
	2018	2017
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization	1,156	1,480

Three months ended March 31, 2018 , compared with the three months ended March 31, 2017

Earnings before interest, income taxes and depreciation and amortization (EBITDA) for the period ended March 31, 2018 was positively impacted by $53 million of contributions from new assets following the completion of the Merger Transaction.

After taking into consideration the contribution of additional earnings from the Merger Transaction, EBITDA decreased by $626 million due to certain unusual, infrequent or other factors, primarily explained by the following:


•	a non-cash, unrealized loss of $298 million in 2018 compared with a $164 million gain in 2017 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


•	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 $249 million increase is primarily explained by the following significant business factors:


•	increased earnings resulting from a higher foreign exchange hedge rate used to record United States dollar denominated Canadian Mainline revenues of $1.25 in 2018 compared with $1.04 in 2017;


•	increased earnings resulting from a higher IJT Benchmark Toll of $4.07 in 2018 compared with $4.05 in 2017, and higher toll surcharges for the recovery of costs related to certain expansion projects;


•	increased earnings resulting from higher Canadian Mainline and Lakehead Pipeline System ex-Gretna throughput of 2,625 thousands of barrels per day (kbpd) in 2018 compared with 2,593 kbpd in 2017 driven by capacity optimization initiatives implemented in 2017;


•	contributions from assets placed into service during 2017, including the Wood Buffalo Extension Pipeline, the Athabasca Pipeline Twin and the Norlite Pipeline System and the acquisition of a minority interest in the Bakken Pipeline System;


•	increased transportation revenues resulting from an increase in the level of committed take-or-pay volumes and higher spot volumes on Flanagan South Pipeline driven by strong demand in the United States Gulf Coast; partially offset by


•	the net unfavorable effect of translating United States dollar EBITDA at a lower Canadian to United States dollar average exchange rate (Average Exchange Rate) of $1.26 in 2018 compared with $1.32 in 2017.

GAS TRANSMISSION AND MIDSTREAM



	Three months ended March 31,
	2018	2017
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization	126	475

Three months ended March 31, 2018 , compared with the three months ended March 31, 2017

EBITDA for the period ended March 31, 2018 was positively impacted by $570 million of contributions from new assets following the completion of the Merger Transaction. When compared to pre-merger results from the prior period, operating results from the new assets include higher earnings primarily from business expansion projects on Algonquin Gas Transmission, Sabal Trail Transmission and Texas Eastern Transmission, LP.

After taking into consideration the contribution of additional earnings from the Merger Transaction, EBITDA decreased by $923 million due to certain unusual, infrequent or other market factors primarily explained by the following:


•	a loss of $913 million on Midcoast Operating, L.P. and its subsidiaries resulting from a revision to the fair value of the assets held for sale based on the sale price; refer to Part I. Item 1. Financial Statements - Note 6. Assets Held for Sale ; and


•	a non-cash, unrealized gain of $6 million in 2018 compared with a gain of $10 million in 2017 reflecting net fair value gains and losses arising from the change in the mark-to-market of derivative financial instruments used to manage foreign exchange and commodity price risk.

After taking into consideration the factors above, the remaining $4 million increase is primarily explained by the following significant business factors:


•	operational efficiencies of $13 million achieved on our United States Midstream and Canadian assets;


•	increased earnings of $6 million from our Alliance joint venture due to favorable seasonal firm and interruptible revenues that resulted from wider basis differentials; partially offset by


•	decreased margins of $13 million on our United States Midstream assets resulting from lower volumes.

GAS DISTRIBUTION



	Three months ended March 31,
	2018	2017
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization	636	387

Three months ended March 31, 2018 , compared with the three months ended March 31, 2017

EBITDA for the period ended March 31, 2018 was positively impacted by $180 million of contributions from Union Gas Limited (Union Gas) following the completion of the Merger Transaction. When compared to pre-merger results from the prior period, Union Gas' operating results benefited from colder weather and higher revenues primarily due to expansion.

After taking into consideration the contribution of additional earnings from the Merger Transaction, EBITDA decreased by $16 million due to certain unusual, infrequent and other business factors, primarily explained by the following:


•	a non-cash, unrealized gain of $1 million in 2018 compared with a gain of $10 million in 2017 arising from the change in the mark-to-market value of Noverco Inc.'s derivative financial instruments; and


•	a negative equity earnings adjustment of $9 million at Noverco Inc. in 2018 arising from the United States TCJA.

After taking into consideration the factors above, the remaining $85 million increase is primarily explained by the following significant business factors:


•	increased earnings of $25 million resulting from colder weather experienced in our franchise service areas; and


•	higher distribution charges primarily reflecting growth in rate base.

GREEN POWER AND TRANSMISSION



	Three months ended March 31,
	2018	2017
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization	109	101

Three months ended March 31, 2018 , compared with the three months ended March 31, 2017

EBITDA decreased by $30 million due to certain unusual, infrequent and other factors, primarily explained by the following:


•	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


▪	a loss of $11 million in 2018 from our equity investment in Rampion Offshore Wind Limited resulting from damaged cables.

After taking into consideration the factors above, the remaining $38 million increase is primarily explained by the following significant business factors:


•	stronger wind resources of $13 million at Canadian and United States wind farms;


•	contributions from the Chapman Ranch Wind Project, which was placed into service in October 2017;


•	contributions from the Rampion Offshore Wind Project, which is expected to be fully operational in the second quarter of 2018; and


•	a net gain of $11 million from an arbitration settlement related to our Canadian wind facilities.

ENERGY SERVICES



	Three months ended March 31,
	2018	2017
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization	169	156

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, 2018 , compared with the three months ended March 31, 2017

EBITDA decreased by $13 million due to certain unusual, infrequent or other factors, primarily explained by the following:


•	a non-cash, unrealized gain of $147 million in 2018 compared with a gain of $160 million in 2017 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 $26 million increase is primarily explained by the following significant business factors:


•	increased earnings of $17 million from Energy Services’ natural gas operations due to increased asset positions in core markets, which allowed for optimization of wider differentials in 2018; and


•	increased earnings of $6 million from Energy Services' Canadian and United States crude operations due to the widening of certain location and quality differentials in 2018, which increased opportunities to generate profitable margins.

ELIMINATIONS AND OTHER



	Three months ended March 31,
	2018		2017
(millions of Canadian dollars)
Loss before interest, income taxes and depreciation and amortization	(279	)	(298	)

Eliminations and Other includes operating and administrative costs and the impact of foreign exchange hedge settlements, all of which are not allocated to business segments. Eliminations and Other also includes new business development activities, general corporate investments and a portion of the synergies achieved thus far related to the integration of corporate functions due to the Merger Transaction.

Three months ended March 31, 2018 , compared with the three months ended March 31, 2017

Loss before interest, income taxes and depreciation and amortization decreased by $5 million due to certain unusual, infrequent and other factors, primarily explained by the following:


•	the absence of transaction costs in 2018 compared with $149 million of costs recorded in 2017 related to the Merger Transaction;


•	employee severance, transition and transformation costs of $62 million in 2018 compared with $125 million in 2017; partially offset by


•	a non-cash, unrealized loss of $136 million in 2018 compared with a $72 million gain in 2017 reflecting net fair value gains and losses arising from the change in the mark-to-market of derivative financial instruments used to manage foreign exchange risk.

After taking into consideration the factors above, the remaining $14 million decrease is primarily explained by the following significant business factors:


•	a realized loss of $42 million in 2018 compared with a loss of $72 million in 2017 related to settlements under our foreign exchange risk management program; partially offset by


•	two additional months of eliminations and other costs post-Merger Transaction, net of corporate synergies.

GROWTH PROJECTS – COMMERCIALLY SECURED PROJECTS

The following table summarizes the status of our commercially secured projects, organized by business segment. Expenditures to date reflect total cumulative expenditures incurred from inception of the project to March 31, 2018 .



		Enbridge's Ownership Interest	Estimated Capital Cost ¹	Expenditures to Date ²	Status	Expected In-Service Date
(Canadian dollars, unless stated otherwise)
LIQUIDS PIPELINES
1.	Canadian Line 3 Replacement Program (the Fund Group) ³	100%	$5.3 billion	$2.5 billion	Under construction	2H - 2019
2.	U.S. Line 3 Replacement Program (EEP) ⁴	100%	US$2.9 billion	US$0.8 billion	Pre-construction ⁵	2H - 2019
3.	Other - United States ⁶	100%	US$0.4 billion	US$0.4 billion	Substantially complete	2H - 2019
4.	Other - Canada	100%	$0.1 billion	No significant expenditures to date	Under construction	Q2 - 2018
GAS TRANSMISSION AND MIDSTREAM
5.	Atlantic Bridge (SEP)	100%	US$0.5 billion	US$0.4 billion	Under construction	Q4 - 2018
6.	NEXUS (SEP)	50%	US$1.3 billion	US$0.7 billion	Under construction	Q3 - 2018
7.	Reliability and Maintainability Project	100%	$0.5 billion	$0.4 billion	Under construction	Q3 - 2018
8.	Valley Crossing Pipeline	100%	US$1.6 billion	US$1.4 billion	Under construction	Q4 - 2018
9.	Spruce Ridge Program	100%	$0.5 billion	$0.1 billion	Pre-construction	2H - 2019
10.	T-South Expansion Program	100%	$1.0 billion	No significant expenditures to date	Pre-construction	2H - 2020
11.	Other - United States ⁷	100%	US$1.7 billion	US$0.9 billion	Various stages	2018 - 2019
12.	Other - Canada ⁸	100%	$0.6 billion	$0.6 billion	Complete	In service
GREEN POWER AND TRANSMISSION
13.	Rampion Offshore Wind Project	24.9%	$0.8 billion (£0.37 billion)	$0.6 billion (£0.3 billion)	Under construction	Q2 - 2018
14.	Hohe See Offshore Wind Project and Expansion	50%	$2.1 billion (€1.34 billion)	$0.8 billion (€0.6 billion)	Under construction	2H - 2019

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, 2018 .

3 The Fund Group is comprised of Enbridge Income Fund, Enbridge Commercial Trust, Enbridge Income Partners LP and the subsidiaries and investees of Enbridge Income Partners LP.

4 The United States portion of the Line 3 Replacement Program (U.S. L3R Program) is being funded 99% by Enbridge and 1% by EEP.

5 Construction of the Wisconsin portion of the project is mechanically complete as noted below. The remaining project is in pre-construction status.

6 Estimated in-service date will be adjusted to coincide with the in-service date of the U.S. L3R Program.

7 Includes the US$0.2 billion Stampede Offshore oil lateral placed into service in the first quarter of 2018.

8 Includes the $0.4 billion High Pine and the $0.2 billion Wyndwood pipeline expansion, both placed into service in the first quarter of 2018.

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 16, 2018. Significant updates that have occurred since the date of filing are discussed below.

LIQUIDS PIPELINES


•	United States Line 3 Replacement Program (EEP) - construction on the Wisconsin portion of the U.S. L3R Program commenced in late June 2017, was mechanically completed in February 2018 and is expected to be commissioned in May 2018. For additional updates on the project, refer to Growth Projects - Regulatory Matters .

GAS TRANSMISSION AND MIDSTREAM

•

Valley Crossing Pipeline - a natural gas pipeline connecting the Agua Dulce hub in Texas to an offshore tie-in with the Sur de Texas-Tuxpan project, which is being constructed by a third party. The project will help Mexico meet its growing gas fired electric generation needs by providing capacity of up to approximately 2.6 bcf/d. Based on an updated execution plan, the revised cost of the project is US$1.6 billion. This is roughly 12% above prior estimates and reflects scope changes, reroutes and offshore weather delays.

GREEN POWER AND TRANSMISSION


•	Rampion Offshore Wind Project - the project generated first power in November 2017. All remaining turbines were commissioned in March 2018 and full operating capacity is expected to be reached in the second quarter of 2018.

GROWTH PROJECTS - REGULATORY MATTERS

United States Line 3 Replacement Program (EEP)

EEP is in the process of obtaining the appropriate permits for constructing the U.S. L3R Program in Minnesota. The project requires both a Certificate of Need and an approval of the pipeline’s route (Route Permit) from the Minnesota Public Utilities Commission ( MNPUC). On February 1, 2016, the MNPUC issued a written order requiring the Minnesota Department of Commerce (DOC) to prepare an Environmental Impact Statement (EIS) before the Certificate of Need and Route Permit processes commence. The DOC issued the final EIS on August 17, 2017. The MNPUC determined the final EIS to be inadequate in four specific areas on December 7, 2017, which the MNPUC directed the DOC to address. As a result, the DOC provided a supplemental EIS on February 12, 2018 and the MNPUC deemed it adequate on March 15, 2018. Progress continues with the parallel Certificate and Route Permit dockets, with public and evidentiary hearings now complete.

On April 23, 2018, an Administrative Law Judge (ALJ) issued Findings of Fact, Conclusions of Law and Recommendation (the ALJ Report) to the MNPUC in connection with EEP's application for a Certificate and Route Permit. The ALJ recommended that the MNPUC grant EEP's application for a Certificate, but only if the MNPUC also selects a route that would require in-trench replacement of the existing Line 3, which is not EEP's preferred route. The ALJ Report is not binding on the MNPUC and the MNPUC is expected to issue a ruling in the Certificate and Route Permit dockets late in the second quarter of 2018. EEP believes that its preferred route remains the best solution for Minnesota and EEP intends to continue its efforts to secure MNPUC approval for its preferred route. On May 9, 2018, EEP filed its exceptions to the ALJ Report with the MNPUC, in which EEP set out its proposed revisions to the ALJ’s summary of the evidentiary record, as well as EEP's points of disagreement with her conclusions and route recommendation.

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

•

Gray Oak Pipeline Project - the Gray Oak Pipeline, LLC announced on April 24, 2018, that it has received sufficient binding commitments on an initial open season to proceed with construction of the Gray Oak Pipeline system. The Gray Oak Pipeline will provide crude oil transportation from West Texas to destinations in the Corpus Christi and Sweeny/Freeport markets. The pipeline is expected to be placed in service by the end of 2019. A second open season has been launched to secure additional volume commitments, which if fully subscribed, the pipeline could have an ultimate capacity of approximately one million barrels per day. We have secured an option to acquire an interest in the pipeline.

GAS TRANSMISSION AND MIDSTREAM

•

Alliance Pipeline Expansion Project - on March 28, 2018, Alliance Pipeline announced an open season for binding bids for additional long-term firm transportation service contracts on the Alliance Pipeline Canada and Alliance Pipeline US systems in support of up to 400 million cubic feet per day (mmcf/d) of expanded services on Alliance Pipeline Canada and up to 430 mmcf/d of expanded services on Alliance Pipeline US. The open season closes on May 30, 2018. The projected in-service date for the potential expansion is the fourth quarter of 2021.

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, including utilization of our sponsored vehicles.

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, 2018 .



		March 31, 2018
	Maturity Dates	Total Facilities	Draws ¹	Available
(millions of Canadian dollars)
Enbridge Inc. ²	2019-2022	6,644	2,616	4,028
Enbridge (U.S.) Inc.	2019	2,469	1,142	1,327
Enbridge Energy Partners, L.P. ³	2019-2022	3,385	1,660	1,725
Enbridge Gas Distribution Inc.	2019	1,017	884	133
Enbridge Income Fund	2020	1,500	566	934
Enbridge Pipelines Inc.	2019	3,000	1,730	1,270
Spectra Energy Partners, LP ⁴	2022	3,223	2,135	1,088
Union Gas Limited	2021	700	130	570
Total committed credit facilities		21,938	10,863	11,075


1	Includes facility draws, letters of credit and commercial paper issuances that are back-stopped by the credit facility.


2	Includes $135 million , $161 million (US$125 million) and $150 million of commitments that expire in 2018, 2018 and 2020, respectively.


3	Includes $226 million (US$175 million) and $239 million (US$185 million) of commitments that expire in 2018 and 2020, respectively.


4	Includes $434 million (US$336 million) of commitments that expire in 2021.

During the first quarter of 2018, Westcoast Energy Inc. terminated an unutilized $400 million credit facility with a syndicate of banks. The facility was set to mature in 2021.

Our net available liquidity of $11,685 million as at March 31, 2018 , was inclusive of $610 million of unrestricted cash and cash equivalents as reported in the Consolidated Statements of Financial Position.

LONG-TERM DEBT ISSUANCES

During the first quarter of 2018, we completed the following long-term debt issuances:



Company	Issue Date		Principal Amount
(millions of dollars)
Enbridge Inc.
	March 2018	Fixed-to-floating rate notes due 2078 ¹	US$850
Spectra Energy Partners, LP ²
	January 2018	3.50% senior notes due 2028	US$400
	January 2018	4.15% senior notes due 2048	US$400


1	Notes mature in 60 years and are callable on or after year 10 . For the initial 10 years, the notes carry a fixed interest rate of 6.25% . Subsequently, the interest rate will be set to equal the three-month London Interbank Offered Rate (LIBOR) plus a margin of 364 basis points from years 10 to 30 , and a margin of 439 basis points from years 30 to 60 .


2	Issued through Texas Eastern Transmission, LP, a wholly-owned operating subsidiary of SEP.

On April 12, 2018, we completed an offering of $750 million of fixed-to-floating rate subordinated notes that mature in 60 years and are callable on or after year 10 . For the initial 10 years , the notes carry a fixed interest rate of 6.625% . After the initial 10 years , the interest rate will be set to equal the Canadian Dollar Offered Rate plus a margin of 432 basis points from years 10 to 30 , and a margin of 507 basis points from years 30 to 60 .

On April 12, 2018, we completed an offering of US$600 million of fixed-to-floating rate subordinated notes that mature in 60 years and are callable on or after year 5 . For the initial 5 years , the notes carry a fixed interest rate of 6.375% . After the initial 5 years , the interest rate will be set to equal the three-month LIBOR plus a margin of 359 basis points from years 5 to 10 , a margin of 384 basis points from years 10 to 25 , and a margin of 459 basis points from years 25 to 60 .

LONG-TERM DEBT REPAYMENTS

During the first quarter of 2018, we completed the following long-term debt repayments to further simplify our debt financing structure post-merger:



Company	Retirement/Repayment Date		Principal Amount	Cash Consideration
(millions of Canadian dollars unless otherwise stated)
Enbridge Southern Lights LP
	January 2018	4.01% medium-term notes due June 2040	9
Spectra Energy Capital, LLC ¹
Repurchase via Tender Offer
	March 2018	6.75% senior unsecured notes due 2032	US$64	US$80
	March 2018	7.50% senior unsecured notes due 2038	US$43	US$59
Redemption
	March 2018	5.65% senior unsecured notes due 2020	US$163	US$172
	March 2018	3.30% senior unsecured notes due 2023	US$498	US$508


1	The loss on debt extinguishment of $37 million ( US$29 million ), net of the fair value adjustment recorded upon completion of the Merger Transaction , was reported within Interest expense in the Consolidated Statements of Earnings.

Strong growth in internal cash flow, ready access to liquidity from diversified sources and a stable business model support our 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 help ensure 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, 2018 , our debt capitalization ratio was 48.2% , compared with 48.3% as at December 31, 2017 .

There are no material restrictions on our cash. Total restricted cash of $113 million , includes EGD’s and Union Gas’ 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 EEP, the Fund Group and SEP are generally not readily accessible by us until distributions are declared and paid by these entities, which occurs quarterly for EEP and SEP, and monthly for the Fund Group. Further, cash and cash equivalents held by certain foreign 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, 2018 . 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, 2018 and December 31, 2017 , our net available liquidity totaled $11,685 million and $12,959 million , respectively.

SOURCES AND USES OF CASH



	Three months ended March 31,
	2018		2017
(millions of Canadian dollars)
Operating activities	3,194		1,776
Investing activities	(2,068	)	(3,448	)
Financing activities	(1,009	)	1,313
Effect of translation of foreign denominated cash and cash equivalents and restricted cash	19		(9	)
Increase/(decrease) in cash and cash equivalents and restricted cash	136		(368	)

Significant sources and uses of cash for the three months ended March 31, 2018 and March 31, 2017 are summarized below:

Operating Activities


•	The growth in cash flow delivered by operations in the first quarter of 2018 is a reflection of the positive operating factors discussed under Results of Operations . The increase in operating cash flow was driven mainly from the contributions from new assets and distributions from additional long-term investments following the completion of the Merger Transaction.

•

Changes in operating assets and liabilities included within operating activities were $ 622 million and $ 340 million for the three months ended March 31, 2018 and 2017, respectively. 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.

Investing Activities

•

The quarter-over-quarter decrease of cash used in investing activities was primarily attributable to activity in the first quarter of 2017 that was not present in the first quarter of 2018, related primarily to the acquisition of an interest in the Bakken Pipeline System of $2.0 billion (US $1.5 billion), partially offset by cash acquired in the Merger Transaction of $0.7 billion and cash received from asset dispositions of $0.3 billion.


•	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 quarter-over-quarter decrease in cash provided by financing activities was primarily attributable to repayments of maturing term notes and credit facilities. During the three months ended March 31, 2018 , we issued hybrid securities, the proceeds of which were used to repay maturing term notes and credit facilities and to finance growth capital programs. Proceeds from the hybrid securities were primarily used to repay credit facilities and to repurchase or redeem Spectra Energy Capital, LLC’s outstanding senior unsecured notes as discussed in Liquidity and Capital Resources - Long-Term Debt Repayments.

•

Finally, with the exception of dividends paid to Spectra Energy shareholders that were declared prior to the Merger Transaction, our common share dividend payments increased in the first quarter of 2018, primarily due to the increase in the common share dividend rate in the second and fourth quarters of 2017, as well as an increase in the number of common shares outstanding as a result of common shares issued in connection with the Merger Transaction.

Dividend Reinvestment and Share Purchase Plan

Participants in our Dividend Reinvestment and Share Purchase Plan (DRIP) receive a 2% discount on the purchase of common shares with reinvested dividends. For the three months ended March 31, 2018 and 2017 , total dividends paid were $1,138 million and $548 million, respectively, of which $764 million and $354 million, respectively, were paid in cash and reflected in financing activities. The remaining $374 million and $194 million, respectively, of dividends paid were reinvested pursuant to the DRIP and resulted in the issuance of common shares rather than a cash payment. In addition to amounts paid in cash and reflected in financing activities for the three months ended March 31, 2017, were $414 million in dividends declared to Spectra Energy shareholders prior to the Merger Transaction that were paid after the Merger Transaction. For the three months ended March 31, 2018 and 2017 , 32.9% and 35.4%, respectively, of total dividends paid were reinvested through the DRIP.

Our Board of Directors has declared the following quarterly dividends. All dividends are payable on June 1, 2018, to shareholders of record on May 15, 2018.



Common Shares		$0.67100
Preference Shares, Series A		$0.34375
Preference Shares, Series B		$0.21340
Preference Shares, Series C ¹		$0.22685
Preference Shares, Series D ²		$0.27875
Preference Shares, Series F		$0.25000
Preference Shares, Series H		$0.25000
Preference Shares, Series J	US$0.30540
Preference Shares, Series L	US$0.30993
Preference Shares, Series N		$0.25000
Preference Shares, Series P		$0.25000
Preference Shares, Series R		$0.25000
Preference Shares, Series 1	US$0.25000
Preference Shares, Series 3		$0.25000
Preference Shares, Series 5	US$0.27500
Preference Shares, Series 7		$0.27500
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 ³		$0.30625


1	The quarterly dividend amounts of Series C was increased to $0.22685 from $0.20342 on March 1, 2018, due to reset on a quarterly basis.


2	The quarterly dividend amounts of Series D was increased to $0.27875 from $0.25000 on March 1, 2018, due to reset of the annual dividend on March 1, 2018, and every five years thereafter.


3	The Series 19 increase from $0.26850 to the regular quarterly dividend of $0.30625 will take effect on June 1, 2018.

LEGAL AND OTHER UPDATES

LIQUIDS PIPELINES

Eddystone Rail Legal Matter

In February 2017, Eddystone Rail Company, LLC (Eddystone Rail) filed an action against several defendants in the United States District Court for the Eastern District of Pennsylvania. 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’ 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 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.

GAS TRANSMISSION AND MIDSTREAM

Sabal Trail FERC Certificate Review

Sierra Club and two other non-governmental organizations filed a Petition for Review of Sabal Trail’s FERC certificate on September 20, 2016 in the D.C. Circuit Court of Appeals. On August 22, 2017, the D.C. Circuit issued an opinion denying one of the petitions, and granting the other petition in part, vacating the certificates, and remanding the case to FERC to supplement the environmental impact

statement for the project to estimate the quantity of green-house gases to be released into the environment by the gas-fired generation plants in Florida that will consume the gas transported by Sabal Trail. The court withheld issuance of the mandate requiring vacatur of the certificate until seven days after the disposition of any timely petition for rehearing. On October 6, 2017, Sabal Trail and FERC each filed timely petitions for rehearing. On January 31, 2018, the court denied FERC’s and Sabal Trail’s petitions for rehearing. On February 5, 2018, FERC issued its final supplemental environmental impact statement in compliance with the D.C. Circuit decision. In addition, on February 6, 2018, FERC filed a motion with the court requesting a 45-day stay of the mandate. On March 7, 2018, the Court granted FERC’s 45-day request for stay, and directed that issuance of the mandate be withheld through March 26, 2018. On March 14, 2018 FERC issued its Order on Remand Reinstating Certificate and Abandonment Authorizations which addressed the Court’s ruling in the August 22, 2017 decision, and on March 30, 2018 the Court issued its mandate.

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 $2,265 million 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

ADOPTION OF NEW STANDARDS

Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income

Effective January 1, 2018, we adopted Accounting Standards Update (ASU) 2018-02 to address a specific consequence of the TCJA enacted by the United States federal government on December 22, 2017. The amendments in this accounting update allow a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the TCJA. The amendments will eliminate the stranded tax effects as a result of the reduction of the historical United States federal corporate income tax rate to the newly enacted United States federal corporate income tax rate. The adoption of this accounting update did not have a material impact on our consolidated financial statements.

Clarifying Guidance on the Application of Modification Accounting on Stock Compensation

Effective January 1, 2018, we adopted ASU 2017-09 and applied the standard on a prospective basis. The new standard was issued to clarify the scope of modification accounting. Under the new guidance, modification accounting is required for all changes to share based payment awards, unless all of the following conditions are met: 1) there is no change to the fair value of the award, 2) the vesting conditions have not changed, and 3) the classification of the award as an equity instrument or a debt instrument has not changed. The adoption of this accounting update is not expected to have a material impact on our consolidated financial statements.

Improving the Presentation of Net Periodic Benefit Cost related to Defined Benefit Plans

Clarifying Guidance on Derecognition and Partial Sales of Nonfinancial Assets

Clarifying the Presentation of Restricted Cash in the Statement of Cash Flows

Simplifying Cash Flow Classification

Recognition and Measurement of Financial Assets and Liabilities

Revenue from Contracts with Customers

use of more estimates and judgments than the previous standards of the consolidated financial statements.



	Balance at December 31, 2017		Adjustments Due to ASC 606		Balance at January 1, 2018
(millions of Canadian dollars)
Assets
Deferred amounts and other assets ^1,2	6,442		(170	)	6,272
Property, plant and equipment, net ²	90,711		112		90,823
Liabilities and equity
Accounts payable and other ^1,2	9,478		62		9,540
Other long-term liabilities ²	7,510		66		7,576
Deferred income taxes ^1,2	9,295		(62	)	9,233
Redeemable noncontrolling interests ^1,2	4,067		(38	)	4,029
Deficit ^1,2	(2,468	)	(86	)	(2,554	)


1	Revenue was previously recognized for a certain contract within the Liquids Pipelines business unit using a formula-based method. Under the new revenue standard, revenue is recognized on a straight-line basis over the term of the agreement in order to reflect the fulfillment of our performance obligation to provide up to a specified volume of pipeline capacity throughout the term of the contract.

FUTURE ACCOUNTING POLICY CHANGES

Improvements to Accounting for Hedging Activities

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

January 1, 2019 and will be applied on a modified retrospective basis. We are currently assessing the impact of the new standard on our consolidated financial statements.

Accounting for Credit Losses

Recognition of Leases

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our exposure to market risk is described in Part II. Item 7A of our Annual Report on Form 10-K for the fiscal year ended December 31, 2017 , filed with the SEC on February 16, 2018. 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.

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 of March 31, 2018 , 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 submits 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, 2018 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 in our Annual Report on Form 10-K for the year ended December 31, 2017, which could materially affect our financial condition or future results. Other than as set out below, there have been no modifications to those risk factors.

Our operations are subject to pipeline safety laws and regulations, compliance with which may require significant capital expenditures, increase our cost of operations and affect or limit our business plans.

Many of our operations are regulated. The nature and degree of regulation and legislation affecting energy companies in Canada and the United States have changed significantly in past years and further substantial changes may occur.

On February 8, 2018, the Government of Canada introduced legislation to revise the process for assessing major resource projects. If the legislation is passed in its current form, we believe it would have adverse impacts on pipeline companies, particularly in relation to the regulatory review process for proposed new projects that are “designated projects”, by making overall timelines for the development and execution of these projects longer and significantly increasing uncertainty.

Compliance with legislative changes may impose additional costs on new pipeline projects as well as on existing operations. Failure to comply with applicable regulations could result in a number of consequences which may have an adverse effect on our operations, earnings, financial condition and cash flows.

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

None.

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. Exhibits designated with a “+” constitute a management contract or compensatory plan arrangement.



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)
3.1		Certificate of Amendment, dated February 27, 2018 incorporated by reference to Enbridge’s Current Report on Form 8-K filed March 1, 2018)
3.2		Certificate of Amendment, dated April 9, 2018 incorporated by reference to Enbridge’s Current Report on Form 8-K filed April 12, 2018)
3.3		Certificate of Amendment, dated April 10, 2018 incorporated by reference to Enbridge’s Current Report on Form 8-K filed April 12, 2018)
4.1		Fourth Supplemental Indenture between Enbridge Inc. and Deutsche Bank Trust Company Americas, dated March 1, 2018 (incorporated by reference to Enbridge’s Current Report on Form 8-K filed March 1, 2018)
4.2		Fifth Supplemental Indenture between Enbridge Inc. and Deutsche Bank Trust Company Americas, dated April 12, 2018 (incorporated by reference to Enbridge’s Current Report on Form 8-K filed April 12, 2018)
		Certain instruments defining the rights of holders of long-term debt securities of the Registrant and its subsidiaries are omitted pursuant to Item 601(b)(4)(iii) of Regulation S-K. The Registrant hereby undertakes to furnish to the SEC, upon request, copies of any such instruments.
10.1*+		The Enbridge Supplemental Pension Plan, As Amended and Restated Effective January 1, 2018
10.2*+		Third Amendment to The Enbridge Supplemental Pension Plan for United States Employees (As Amended and Restated Effective January 1, 2005)
10.3*+		Enbridge Inc. Directors’ Compensation Plan dated February 14, 2018, Effective January 1, 2018
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.
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.

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, 2018	By:	/s/ Al Monaco
			Al Monaco President and Chief Executive Officer

Date:	May 10, 2018	By:	/s/ John K. Whelen
			John K. Whelen Executive Vice President and Chief Financial Officer (Principal Financial Officer)

Exhibit 10.1

October 18, 2006

The Enbridge Supplemental Pension Plan

As Amended and Restated

Effective January 1, 2018

CERTIFIED to be a true and complete copy of the text of the Enbridge Supplemental Pension Plan.

Date: c/s

H-616392_ . DOC January 1 , 2005 1 of 1

Table of Contents

1. GENERAL 1

1.1 INTRODUCTION 1

1.2 CONSTRUCTION, INTERPRETATION AND DEFINITIONS 2

1.3 ELIGIBILITY AND MEMBERSHIP 8

1.4 CONTRIBUTIONS 9

1.5 GRANTOR TRUST FUND 12

1.6 RCA FUND 15

1.7 ADMINISTRATION OF THE PLAN 18

1.8 GENERAL PROVISIONS 20

1.9 AMENDMENT OR DISCONTINUANCE 22

2. DEFINED BENEFIT PROVISIONS RELATING TO EI PLAN BENEFITS ACCRUED BY ACTIVE MEMBERS 26

2.0 APPLICATION OF ARTICLE 2 26

2.1 RETIREMENT BENEFITS 26

2.2 DEATH BENEFITS 27

2.3 TERMINATION BENEFITS 30

3. DEFINED BENEFIT PROVISIONS RELATING TO EGD PLAN BENEFITS 33

3.0 APPLICATION OF ARTICLE 3 33

3.1 RETIREMENT BENEFITS 33

3.2 DEATH BENEFITS 36

3.3 TERMINATION BENEFITS 38

4. BENEFITS PAYABLE TO RETIRED MEMBERS FROM THE EI PLAN 40

4.0 APPLICATION OF ARTICLE 4 40

4.1 RETIREMENT BENEFITS 40

5. POST-RETIREMENT PENSION INCREASES 41

6. DEFINED CONTRIBUTION PROVISIONS 43

6.0 APPLICATION OF ARTICLE 6 43

6.1 ESTABLISHMENT AND MAINTENANCE OF NOTIONAL ACCOUNTS 43

6.2 NOTIONAL AMOUNTS OF CONTRIBUTIONS 43

6.3 NOTIONAL AMOUNTS OF INVESTMENT EARNINGS 43

6.4 PAYMENT OF DC PENSION BENEFITS 44

APPENDIX A 45

APPENDIX B 46

Restatement effective January 1 , 2018 1


1.	General


1.1	Introduction


1.1.01	The Plan was originally established effective January 1, 2000 , and was amended and restated effective as of January 1, 2005. The Plan is hereby restated effective as of January 1, 2018 to incorporate prior amendments and to harmonize with restatements to the underlying registered pension plans also made effective as of that date. The purposes of the Plan are:


(a)	to ensure that Senior Management Employees receive retirement benefits in accordance with the Senior Management Pension Plan,


(b)	to ensure that, where agreed to by the Parent, Employees who are not Senior Management Employees receive certain retirement benefits as defined in the EGD Plan and the EI Plan without limitation due to Maximum Pension Rules or Maximum DC Pension Rules, and


(c)	to ensure that Members receive any retirement benefits agreed to by the Parent within a Member’s executive employment agreement.

For further clarity, the Plan does not provide retirement benefits in respect of a Member’s service accrued while a US Tax Resident.

1.1.02

With the exception of Article 4, the provisions of the Plan apply to Members for whom the earlier of retirement, termination of employment with a Participating Employer or death occurs on or after January 1, 2000. Benefits, if any, in respect of a Retired Member who retired, terminated employment with a Participating Employer, or died prior to January 1, 2000 will be governed in accordance with Article 4 of this Plan.

1.1.03

The Plan is not a registered pension plan under the Income Tax Act or under Canadian Pension Laws. Any contributions made to the Plan with respect to benefits earned while a Member is not (i) a US Tax Resident , (ii) a US Expatriate or (iii) otherwise subject to Code Section 409A, will be deposited in the RCA Fund and are to be considered as contributions to retirement compensation arrangements under the Income Tax Act. Any contributions made to the Plan with respect to benefits earned by a Member while he is a US Expatriate or otherwise subject to Code Section 409A, will be deposited in the Grantor Trust Fund.


1.1.04	The Plan is intended to satisfy the requirements of Code Section 409A for any benefits accrued or payable under the Plan to or on behalf of a Member who is subject to United States federal income taxation, but only to the extent such Member’s benefits are subject to Code Section 409A, and do not satisfy any

Restatement effective January 1 , 2018 2

exception thereto either with respect to the Member individually or the Plan as a whole.


1.2	Construction, Interpretation and Definitions

For the purposes of this Plan, including this Section, the expressions set out below have the following meanings, regardless of any definitions in any other document that may be at variance with them:


1.2.01	“Active Member” means an Employee who is eligible to participate in the Plan in accordance with Section 1.3.01 and who is entitled to benefits from the Plan.


1.2.02	“Actuarial Equivalent” has the same meaning as in the EGD Plan or the EI Plan as is applicable in the circumstances.


1.2.03	“Actuary” means an individual, a firm or a corporation from time to time appointed by the Parent to carry out actuarial valuations and provide such actuarial advice and services as may be required for the purposes of the Plan. The Actuary shall at all times be a person who is, or a firm that has on its staff, a Fellow of the Canadian Institute of Actuaries.


1.2.04	“Associate Company” has the same meaning as in the EI Plan.


1.2.05	“Beneficiary” of a Member is the same person or persons designated by the Member as his beneficiary for the purposes of the EGD Plan or the EI Plan as is applicable in the circumstances.

1.2.06

“Benefit Commencement Date” means, with respect to benefits subject to Code Section 409A for Plan Years beginning on or after January 1, 2008, (i) for a Member whose date of Separation from Service is prior to his 55 ^th birthday, the first day of the month coincident with or next following the date he attains age 60, and (ii) for a Member whose date of Separation from Service is on or after his 55 ^th birthday, the first day of the month coincident with or next following the date that is six (6) months after the date of his Separation from Service.


1.2.07	“Board of Directors” means the Board of Directors of the Parent.


1.2.08	“Canadian Pension Laws” means the federal Pension Benefits Standards Act, 1985 and any regulations pursuant thereto and any amendment or substitute therefor as well as any similar statute applicable to the EGD Plan or the EI Plan and any regulation pursuant thereto adopted by the Canadian or any provincial government.


1.2.09	“ Change of Control” has the meaning set forth in Section 1.4.07.

Restatement effective January 1 , 2018 3


1.2.10	“Code” means the United States Internal Revenue Code of l986, as amended, and the regulations and other authority issued thereunder by the appropriate governmental authority. References herein to any section of the Code shall include references to any successor section or provision of the Code.


1.2.01	“ Commuted Lump Sum Value” has the same meaning as in the EI Plan or the definition of commuted value in the EGD Plan as applicable in the circumstances. Income tax payable upon termination, death or retirement on any benefit provided under the Plan shall not be considered in the calculation of any Commuted Lump Sum Value.


1.2.02	“Consumer Price Index” has the same meaning as in the EGD Plan or the EI Plan as is applicable in the circumstances.


1.2.03	“Effective Date” means January 1, 2000, the original effective date of the Plan.


1.2.04	“EGD Plan” means the Pension Plan for Employees of Enbridge Gas Distribution, Inc. and Affiliates, as amended from time to time, formerly named the Pension Plan for Employees of the Consumers’ Gas Company Ltd. and Designated Affiliated, Associated, and Subsidiary Companies .


1.2.05	“EGD Supplementary Plan” means the Supplementary Executive Retirement Plan for Employees of Enbridge Gas Distribution Inc. and Affiliates, as amended from time to time, formerly named the Supplementary Executive Retirement Plan of the Consumers’ Gas Company Ltd.


1.2.06	“EI Plan” means the Retirement Plan for the Employees of Enbridge Inc. and Affiliates as in effect at January 1, 2018, and as subsequently amended from time to time.


1.2.07	“Employee” has the same meaning as in the EGD Plan or the EI Plan as is applicable in the circumstances.


1.2.08	“EUS Plan” means the Enbridge (U.S.) Inc. Employees’ Annuity Plan as in effect at January 1, 2005, and as subsequently amended from time to time or the Pension Plan for Employees of the St. Lawrence Gas Company, Inc. as in effect at January 1 , 2005, and as amended from time to time, as is applicable in the circumstances.


1.2.09	“Excess Assets” means excess assets as defined in the Funding Policy.


1.2.10	“Final Average Earnings” has the same meaning as in the EI Plan.

Restatement effective January 1 , 2018 4


1.2.11	“Funding Agency” means the original trustee, or trustees, that the Parent may appoint to hold and to administer the RCA Fund, and any duly appointed successor trustee or trustees.


1.2.12	“Funding Agreement” means any agreement governing the RCA Fund now or hereafter entered into between the Parent and the Funding Agency.


1.2.13	“Funding Policy” means the funding policy of the Plan as agreed to by the Human Resources & Compensation Committee and as amended from time to time.


1.2.14	“Grantor Trust Agreement” means any agreement governing the Grantor Trust Fund now or hereafter entered into between the Parent and the Grantor Trustee. The trust established under the Grantor Trust Agreement is intended to be a grantor trust within the meaning of Code Sections 671-677, and is not intended to constitute offshore trust property within the meaning of Code Section 409A(b).


1.2.15	“Grantor Trust Fund” means the trust fund established with the Grantor Trustee for the purpose of providing benefits under the Plan.


1.2.16	“Grantor Trustee” means the original trustee, or trustees, that the Parent may appoint to hold and to administer the Grantor Trust Fund, and any duly appointed successor, trustee, or trustees, or any combination thereof.


1.2.17	“Human Resources & Compensation Committee” means the Committee of the Board of Directors of the Parent from time to time appointed to fix the remuneration of the executives of the Parent or the Participating Employers or, if such committee has not been appointed, means the Board of Directors of the Parent.


1.2.18	“Income Tax Act” means the Income Tax Act (Canada) and any applicable provincial income tax act, as amended from time to time, together with any relevant regulations and application rules made thereunder from time to time.


1.2.19	“Maximum DC Pension Rules” means any rule or rules established by or under the Income Tax Act that limits contributions to an Active Member’s account under the EGD Plan or the EI Plan as of the date on which a contribution would otherwise have been payable. Such rules include, but are not necessarily limited to :


(a)	maximum contribution limits resulting from the money purchase limit as defined by the Income Tax Act, and


(b)	limitations on the contributions permitted for Active Members employed by a Foreign Affiliate (as defined under the EGD Plan or the EI Plan).

Restatement effective January 1 , 2018 5


1.2.20	“Maximum Pension Rules” means any rule or rules established by or under the Income Tax Act that limits a benefit payable to a Member under the EGD Plan or the EI Plan as of the date in respect of which a determination of his benefit thereunder is required for purposes of this Plan. Such rules include, but are not necessarily limited to:


(a)	limitations on defined benefit pension benefits payable to high income employees,


(b)	limitations on the recognition of earnings for the purpose of determining the amount of defined benefit pensions,


(c)	limitations on the crediting of service for employees employed outside of Canada,


(d)	limitations on the annual defined benefit accrual rate, and


(e)	limitations on the crediting of service prior to employment.


1.2.21	“Member” means an Active Member or a Retired Member.

1.2.22

Normal Benefit Form” means, with respect to benefits subject to Code Section 409A, (a) for a Member who is not married on his or her benefit commencement date, a pension payable on the first day of each month during the Member’s lifetime commencing with the benefit commencement date, and terminating with the payment for the month in which the Member dies, but with a minimum of one hundred eighty (180) monthly payments (even if the Member should die prior to receiving such minimum number of payments); and (b) for a Member who is married on his or benefit commencement date, an annuity for the life of the Member with a survivor annuity payable to the Member’s spouse in an amount equal to sixty percent (60%) of the monthly amount of the annuity payable to the Member during the Member’s lifetime; provided, however, that if the Member’s spouse is more than eight (8) years younger than the Member, the monthly amount payable to the Member shall be reduced by three tenths (3/10) of one percent (1%) for each year that the difference in age between the Member and his or her spouse exceeds eight (8) years.


1.2.23	“Notional Account” means an Active Member’s account established and maintained pursuant to the provisions of Section 6.1.


1.2.24	“Notional Investment Earnings” means the notional amount of investment income credited to an Active Member’s Notional Account pursuant to the provisions of Section 6.3.


1.2.25	“Parent” means Enbridge Inc.

Restatement effective January 1 , 2018 6


1.2.26	“Participating Employer” means any employer who meets the definition of “Company” in accordance with the EI Plan or “Participating Employer” in accordance with the EGD Plan, as applicable, who, subject to the consent of the Board of Directors, agrees to participate in the Plan and be bound by the terms of the Plan.


1.2.37	“Participating Employer Account” means the portion of each of the RCA Fund and the Grantor Trust Fund allocated to a Participating Employer.


1.2.38	“Plan” means this Enbridge Supplemental Pension Plan , as originally effective January 1, 2000, and amended and restated as of January 1, 2005, and as it may thereafter be amended from time to time.


1.2.39	“Plan Assets” means plan assets as defined in the Funding Policy and includes any investment income earned by such assets.

1.2.40 “Plan Year” means the calendar year.


1.2.41	“Post Retirement Adjustment Provisions” means the provisions of the EGD Plan or the EI Plan as applicable in the circumstances that may increase the amount of periodic lifetime retirement benefit after a Member’s retirement.


1.2.42	“RCA Fund” means the trust fund established with the Funding Agency for the purpose of providing benefits under the Plan.

1.2.43 “Retired Member” means a person as defined in Section 1.3.02.


1.2.44	“Senior Management Employee” has the same meaning as in the EI Plan or the EGD Plan, as the case may be.

1.2.45

“Senior Management Pension Plan” means the supplemental pension arrangement described in the employee booklet entitled “The Enbridge Senior Management Pension Plan” effective January 1, 2000 and as amended thereafter. Any and all benefits relating to the Senior Management Pension Plan for the period that a Senior Management Employee is employed by a Participating Employer are documented in this Plan, the EI Plan or the EGD Plan.

1.2.46

“Separation from Service” means the cessation of a Member’s services as an Employee of the Parent and any Participating Employer for any reason; provided, however, that transfer of employment between two entities that are included in a “controlled group” within the meaning of Code Sections 414 and 1563 will not constitute Separation from Service for purposes of this Plan; and provided further, the term Separation from Service shall be administered and interpreted in accordance with Code Section 409A.

Restatement effective January 1 , 2018 7

1.2.47

“Specified Employee” means a Member who is a “key employee” (as defined in Code Section 416(i) without regard to Code Section 416(i)(5)) of the Parent (or an entity which is considered to be a single employer with the Parent under Code Section 414(b) or 414(c)), as determined under Code Section 409A at any time during the twelve (12) month period ending on December 31, but only if the Parent has any stock that is publicly traded on an established securities market or otherwise. Notwithstanding the foregoing, a Member will be deemed to be a Specified Employee solely for the period of April 1 through March 31 following such December 31, except as otherwise may be required under Code Section 409A.


1.2.48	“Spouse” means a Member’s spouse as defined in the EGD Plan or the EI Plan as is applicable in the circumstances.


1.2.49	“US Expatriate” means a resident of Canada who is required by the Internal Revenue Code of the United States of America to file a federal income tax return with the Internal Revenue Service of the United States of America.


1.2.50	“US Supplemental Pension Plan” means the Enbridge Supplemental Pension Plan for United States Employees effective as of January 1, 2000, as amended thereafter from time to time.


1.2.51	“US Tax Resident” means a resident of the United States of America.

In the Plan, words importing the singular number include the plural and vice versa, words importing any gender include any other gender, and references to an Article, Articles, Section, Sections, Paragraph or Paragraphs mean an Article, Articles, Section, Sections, Paragraph or Paragraphs in this instrument.

Where the terms of the EGD Plan, the EI Plan or the EUS Plan are referenced, subject to any decision of the Parent to the contrary in a particular case, the reference is to the plan to which the Plan benefits in question are related.

Restatement effective January 1 , 2018 8


1.3	Eligibility and Membership


1.3.01	Each of the following persons shall be eligible to participate in the Plan and shall be considered an Active Member of the Plan:


(a)	any member of the EI Plan whose benefits accrued under the EI Plan on or after the Effective Date are limited as a result of the Maximum Pension Rules or the Maximum DC Pension Rules, and


(b)	any member of the EGD Plan whose benefits accrued under the EGD Plan on or after the Effective Date are limited as a result of the Maximum Pension Rules or the Maximum DC Pension Rules,

provided that any accrual of benefits under the Plan shall be suspended during any period that the person is a US Tax Resident.


1.3.02	The following persons are Retired Members:


(a)	retired members of the EI Plan listed in Appendix A.


1.4	Contributions


1.4.01	Members are neither required nor permitted to contribute to the Plan.


1.4.02	(a) The Parent shall contribute amounts to the RCA Fund and the Grantor Trust Fund in accordance with the Funding Policy.


(b)	The Funding Policy shall define the target level of assets for purposes of Sections 1.4.02(a) and 1.4.05 and shall define Excess Assets for purposes of Sections 1.2.15 and 1.4.06.

Excess Assets, or any portion thereof, may be used to reduce the contributions by the Parent that would otherwise be required under the Plan.

If, due to an administrative or clerical error, the Parent contributes an amount to the RCA Fund or the Grantor Trust Fund that exceeds the amount it is required to contribute in accordance with the Funding Policy, the Parent may require the Funding Agency or the Grantor Trustee, as applicable in the circumstances, to refund the excess contributions to the Parent, provided that the request by the Parent for the refund is made within 60 days following the discovery of the error and such refund is permitted by the related Funding Agreement or Grantor Trust Agreement .

1.4.03

Each Participating Employer shall pay the Parent the portion of the contributions made by the Parent under Section 1.4.02 that are in respect of the Members which the particular Participating Employer employs or has employed, as determined by the Actuary, within 30 days of the contribution made by the Parent. Such payments shall include the refundable tax amounts that the Parent is required to withhold in accordance with Section 1.5.02.


1.4.04	Subject to Sections 1.4.05 and 1.8, at any time, by resolution of the Human Resources & Compensation Committee amending the Funding Policy, the Parent may elect to discontinue or resume the contributions under Section 1.4.02 to the RCA Fund or the Grantor Trust Fund.


1.4.05	In the event of a Change of Control of the Parent as defined in Section 1.4.07, the Parent shall make contributions to the RCA Fund and the Grantor Trust Fund within a reasonable timeframe, but n ot later than 180 days after such Change of Control , such that, as of the date of the Change of Control , Plan Assets are no less than the target level of assets as defined in the Funding Policy.


1.4.06	Subject to the provisions of the Grantor Trust Agreement, Sections 1.5.03, 1.5.07, 1.6.03, 1.6.07 and 1.9.02, or any amendment thereto, and notwithstanding any other provisions in the Plan or the Funding Policy to the contrary, the Plan Assets determined at any time shall only be used for the payment of the pension

Restatement effective January 1 , 2018 9

liabilities in respect of which such Plan Assets were contributed by the Parent pursuant to the Funding Policy. Nevertheless, when permitted by the Plan and the related Funding Agreement or Grantor Trust Agreement, Plan Assets that constitute Excess Assets may be paid or transferred to the Parent.


1.4.07	For the purposes of Section 1.4.05, “ Change of Control ” means:

(a)

the sale to a person or acquisition by a person not affiliated with the Parent or its subsidiaries of net assets of the Parent or its subsidiaries having a value greater than 50% of the fair market value of the assets of the Parent 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,

(b)

any change in the holding, direct or indirect, of shares of the Parent by a person not affiliated with the Parent 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 Parent 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 Parent 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 Parent 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 Parent,

(c)

any reconstruction, reorganization, recapitalization, consolidation, amalgamation, arrangement, merger, transfer, sale or other transaction involving the Parent where shareholders of the Parent 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 Parent or of the continuing corporation following completion of such reconstruction, reorganization, recapitalization, consolidation, amalgamation, arrangement, merger, transfer, sale or other transaction,

Restatement effective January 1 , 2018 10


(d)	the Parent ceases to be a distributing corporation as that term is defined in the Canada Business Corporations Act,


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


(f)	incumbent directors cease to be a majority of the Board of Directors,

provided that any transaction whereby shares held by shareholders of the Parent 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 Parent previously owned by the shareholders of the Parent and the former shareholders of the Parent 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 Parent prior to the transaction will be deemed not to constitute a Change of Control.


1.4.08	Excess Assets may be paid or transferred to the Parent from the RCA Fund and the Grantor Trust Fund if specific provision to that effect is made in Section 1.5, or 1.6, and in accordance with Section 1.9.02.


1.5	Grantor Trust Fund


1.5.01	The Grantor Trust Fund will be maintained and administered by the Grantor Trustee in accordance with the terms of the Grantor Trust Agreement. The Parent will be responsible for the selection of the Grantor Trustee and may appoint additional or successor Grantor Trustees as, in its sole discretion, may be necessary or desirable for purposes of the Plan.

1.5.02

The Parent shall withhold from its contributions to the Grantor Trust Fund the amount of refundable tax that is required to be withheld under the Income Tax Act with respect to contributions to a retirement compensation arrangement. The refundable tax which is withheld shall be remitted to the Canada Customs and Revenue Agency within the time periods specified in the Income Tax Act. The Parent shall also file the required tax form with respect to total contributions made by the Parent to the Grantor Trust Fund in the calendar year, and any other documents as it may be required to file under the Income Tax Act or the Code , within the time periods specified in the Income Tax Act or the Code .

1.5.03

The Grantor Trustee shall prepare and file the annual tax return for the Grantor Trust Fund, remit from the Grantor Trust Fund any refundable tax required with respect to investment earnings in the Grantor Trust Fund, and file any other documents as it may be required to file under the Income Tax Act or the Code , within the time periods specified in the Income Tax Act or the Code . In addition, where the Canada Customs and Revenue Agency fails to refund to the Grantor Trust Fund any excess refundable tax after assessing an annual tax return, the Grantor Trustee shall promptly apply for a refund of such amounts.

1.5.04

The benefit obligations of the Plan earned by Members while they are US Expatriates, or otherwise subject to Code Section 409A, shall be paid from the Grantor Trust Fund in accordance with the instructions of the Parent. The Grantor Trustee shall be responsible for withholding any taxes and any other statutory deductions required by applicable law from benefit payments from the Grantor Trust Fund.

1.5.05

Notwithstanding Section 1.5.04, the Parent or a Participating Employer may elect to pay benefit obligations of the Plan earned by Members while they are US Expatriates, or otherwise subject to Code Section 409A, from its general funds. The Parent or the Participating Employer shall be responsible for withholding any taxes and any other statutory deductions required by applicable law from benefit payments from its general funds. Payment of benefit obligations made by the Parent or the Participating Employer shall discharge the liability of the Plan that would otherwise have been payable from the Grantor Trust Fund.


1.5.06	The fiscal year of the Grantor Trust Fund shall be the Plan Year.

1.5.07

Fees of the Grantor Trustee, fees of any investment manager, investment brokerage, transfer taxes and similar costs arising as a result of the making of investments, the sale of assets or the realization of investment yield, and the expenses reasonably incurred or compensation properly paid (including fees and disbursements for the services of the Grantor Trustee, the Actuary, accountants, lawyers and other advisors) in the course of the administration of the Plan with regard to Members who are US Expatriates, or whose benefits are otherwise subject to Code Section 409A, may be paid from the Grantor Trust Fund. (For greater certainty, the fees of an investment manager may be paid from the proceeds of the sale of assets managed by that investment manager.) The Parent may pay any such fees, costs, expenses or other amounts on behalf of the Grantor Trust Fund, subject to reimbursement by the Grantor Trust Fund if permitted under the terms of the Grantor Trust Agreement. Reimbursement may be waived by the Parent. In the event that such fees, costs, expenses or other amounts are paid by the Parent and the Parent waives reimbursement by the Grantor Trust Fund, the Parent may recover an appropriate amount of such fees, costs, expenses or other amounts from each Participating Employer.


1.5.08	No Member, annuitant, joint annuitant, beneficiary or estate or any other person shall have any interest in or right to any part of the earnings of the Grantor Trust Fund, or any rights in or to any part of the assets thereof, except as expressly provided for in the Plan or the Grantor Trust Agreement, and then such interest or rights shall only be to the extent of such provisions.


1.5.09	The Parent, or its duly appointed delegate, shall have full authority to direct the investment of the Grantor Trust Fund, provided that such investment shall be directed so that the Grantor Trustee has liquid assets available as required for benefit payments and other payments that the Funding Agency is required to make from the Grantor Trust Fund as they fall due.


1.5.10	A Participating Employer Account shall be established on behalf of each Participating Employer whose employees accrue benefits that are payable from the Grantor Trust Fund. Any and all transactions in respect of the Grantor Trust Fund shall be allocated to the applicable Participating Employer Account in a manner determined by the Parent on the advice of the Actuary.


1.5.11	There may be paid or transferred to the Parent by the Grantor Trustee, at any time in a year upon resolution of the Human Resources & Compensation Committee, assets from the Grantor Trust Fund in an amount that does not exceed the Excess Assets at the particular time if permitted under the terms of the Grantor Trust Agreement .


1.5.12	The Parent may, in its sole discretion and by way of a resolution of the Human Resources & Compensation Committee, pay or transfer Excess Assets that have been paid from the Grantor Trust Fund that are attributable to a Participating Employer to the Participating Employer Account of another Participating Employer.


1.6	RCA Fund


1.6.01	The RCA Fund will be maintained and administered by the Funding Agency in accordance with the terms of the Funding Agreement. The Parent will be responsible for the selection of the Funding Agency and may appoint additional or successor Funding Agencies as, in its sole discretion, may be necessary or desirable for purposes of the Plan.

1.6.02

The Parent shall withhold from its contributions to the RCA Fund the amount of refundable tax that is required to be withheld under the Income Tax Act with respect to contributions to a retirement compensation arrangement. The refundable tax which is withheld shall be remitted to the Canada Customs and Revenue Agency within the time periods specified in the Income Tax Act. The Parent shall also file the required tax form with respect to total contributions made by the Parent to the RCA Fund in the calendar year, and any other documents as it may be required to file under the Income Tax Act, within the time periods specified in the Income Tax Act.

1.6.03

The Funding Agency shall prepare and file the annual tax return for the RCA Fund, remit from the RCA Fund any refundable tax required with respect to investment earnings in the RCA Fund, and file any other documents as it may be required to file under the Income Tax Act, within the time periods specified in the Income Tax Act. In addition, where the Canada Customs and Revenue Agency fails to refund to the RCA Fund any excess refundable tax after assessing an annual tax return, the Funding Agency shall promptly apply for a refund of such amounts.


1.6.04	The benefit obligations of the Plan earned by Members while they are not US Tax Residents or US Expatriates shall be paid from the RCA Fund in accordance with the instructions of the Parent. The Funding Agency shall be responsible for withholding any taxes and any other statutory deductions required by applicable law from benefit payments from the RCA Fund.

1.6.05

Notwithstanding Section 1.6.04, the Parent or a Participating Employer may elect to pay benefit obligations of the Plan earned by Members while they are not US Tax Residents or US Expatriates from its general funds. The Parent or the Participating Employer shall be responsible for withholding any taxes and any other statutory deductions required by applicable law from benefit payments from its general funds. Payment of benefit obligations made by the Parent or the Participating Employer shall discharge the liability of the Plan that would otherwise have been payable from the RCA Fund.


1.6.06	The fiscal year of the RCA Fund shall be the Plan Year.

Restatement effective January 1 , 2018 11

1.6.07

Fees of the Funding Agency, fees of any investment manager, investment brokerage, transfer taxes and similar costs arising as a result of the making of investments, the sale of assets or the realization of investment yield, and the expenses reasonably incurred or compensation properly paid (including fees and disbursements for the services of the Funding Agency, the Actuary, accountants, lawyers and other advisors) in the course of the administration of the Plan in respect of Members who are not US Tax Residents or US Expatriates may be paid from the RCA Fund. (For greater certainty, the fees of an investment manager may be paid from the proceeds of the sale of assets managed by that investment manager.) The Parent may pay any such fees, costs, expenses or other amounts on behalf of the RCA Fund, subject to reimbursement by the RCA Fund. Reimbursement may be waived by the Parent. In the event that such fees, costs, expenses or other amounts are paid by the Parent and the Parent waives reimbursement by the RCA Fund, the Parent may recover an appropriate amount of such fees, costs, expenses or other amounts from each Participating Employer.


1.6.08	No Member, annuitant, joint annuitant, Beneficiary, estate or any other person shall have any interest in or right to any part of the earnings of the RCA Fund, or any rights in or to any part of the assets thereof, except as expressly provided for in the Plan, and then such interest or rights shall only be to the extent of such provisions.


1.6.09	The Parent, or its duly appointed delegate, shall have full authority to direct the investment of the RCA Fund, provided that such investment shall be directed so that the Funding Agency has liquid assets available as required for benefit payments and other payments that the Funding Agency is required to make from the RCA Fund as they fall due.


1.6.10	A Participating Employer Account shall be established on behalf of each Participating Employer whose employees accrue benefits that are payable from the RCA Fund. Any and all transactions in respect of the RCA Fund shall be allocated to the applicable Participating Employer Account in a manner determined by the Parent on the advice of the Actuary.


1.6.11	There may be paid or transferred to the Parent by the Funding Agency, at any time in a year upon resolution of the Human Resources & Compensation Committee, assets from the RCA Fund in an amount that does not exceed the Excess Assets at the particular time.


1.6.12	The Parent may, in its sole discretion and by way of a resolution of the Human Resources & Compensation Committee, pay or transfer Excess Assets from the RCA Fund that are attributable to a Participating Employer to the Participating Employer Account of another Participating Employer.

Restatement effective January 1 , 2018 12

1.6.13

Notwithstanding any other provision herein, if a Member who is not a US Expatriate becomes a US Tax Resident and a member of the US Supplemental Plan, any increase in the amount of benefit payable to such Member under the Plan based on his earnings while a member of the US Supplemental Plan shall be paid from the Grantor Trust Fund. If such Member ceases to be a US Tax Resident, the benefit payable from the Grantor Trust Fund under this section shall cease to be payable therefrom and shall be payable from the RCA Fund, unless such benefit earned while a member of the US Supplemental Plan is subject to Code Section 409A, in which case the benefit shall remain payable from the Grantor Trust Fund.


1.7	Administration of the Plan

1.7.01

The Parent shall be responsible for the overall administration, interpretation, and application of the Plan, and all decisions of the Parent in connection with the administration, interpretation, and application of the Plan shall be binding upon the Parent, the Participating Employers and the Members. The Parent may enact such rules and regulations relating to the operation of the Plan as are consistent with the terms of the Plan and as it considers necessary for the carrying out of its provisions and may amend or revoke such rules and regulations from time to time.

1.7.02

The Parent may delegate its powers and duties with respect to the Plan to any person, persons or firm as it may determine, whether or not the members of the firm or the person or persons are employees, officers or directors of the Parent. The Parent may authorize the firm, person or persons so determined by it to act on its behalf and to execute instruments on its behalf. The Funding Agency and the Grantor Trustee may rely upon any instrument signed on behalf of such firm, or by any person or persons so authorized by the Parent and certified by the Parent to be so authorized, as properly and effectively evidencing the action of the Parent.

1.7.03

The Parent, the Participating Employers, the Human Resources & Compensation Committee members or any employee or servant of the Parent or the Participating Employers shall not be liable for any honest error in judgement, nor shall they be liable for any liability or debt of the RCA Fund or the Grantor Trust Fund, nor for the non-fulfilment of any contract, nor for any other liability arising in connection with the administration of the RCA Fund, the Grantor Trust Fund or the Plan, nor for any other duty or obligation as referred to in the Plan; provided, however, that nothing herein shall exempt the Parent, the Participating Employers, the Human Resources & Compensation Committee members or any employee or servant of the Parent or the Participating Employers from any liability, obligation or debt arising out of their acts or omissions done or suffered in bad faith or through wilful misconduct.

1.7.04

The Parent shall indemnify and save harmless the Human Resources & Compensation Committee members and any employee or servant of the Parent or the Participating Employers who are involved in the administration of the Plan from any and all claims, losses, damages, expenses and liability which may result from their acts, omissions or conduct in their formal capacity to the full extent permitted by law except for their acts or omissions done or suffered in bad faith or through wilful misconduct provided, however, that no part of the RCA Fund or the Grantor Trust Fund shall be used for indemnification payments.


1.7.05	The Parent and any person or firm appointed by the Parent in accordance with Section 1.7.02 shall be entitled to rely conclusively upon all tables, valuations, certifications, opinions and reports which may be furnished by the Actuary or by an accountant, counsel or other person who may be employed or engaged for such purposes.


1.7.06	Whenever the records of the Parent or a Participating Employer are used for the purposes of the Plan, such records shall be conclusive of the facts with which they are concerned unless and until they are proven to be in error.


1.7.07	All benefits payable from the Plan shall be paid in the lawful currency of Canada.


1.8	General Provisions

1.8.01

Participation in this Plan does not confer upon any Member any rights that he did not otherwise possess as an Employee except to such benefits as have specifically accrued to him under the terms of the Plan. Nothing contained in the Plan may be deemed to give any Employee the right to be retained in the employ of the Participating Employer or to interfere with the right of the Participating Employer to discharge any Employee at any time without regard to the effect that such discharge might have upon the Employee as a Member under the Plan.

1.8.02

Except as otherwise required by applicable law, all benefits provided under the terms of the Plan are for the Member’s own use and benefit, are not capable of assignment or alienation, and do not confer upon any Member, personal representative or dependent, or any other person, any right or interest in the benefit or deferred benefit that is capable of being assigned or otherwise alienated, nor is any such benefit capable of surrender or commutation except as provided in the Plan.


1.8.03	(a) Except as otherwise required by applicable law, no benefit, or portion thereof, paid or payable under the Plan:


(i)	is subject to execution, seizure or attachment in satisfaction of an order for support or maintenance enforceable in Alberta or another relevant jurisdiction; or


(ii)	may be divided at source or become payable to the Spouse or former Spouse of a Member in respect of such Member’s marriage breakdown, divorce, or other dissolution, including, without limitation, pursuant to any “ domestic relations order” within the meaning of Code Section 414(p)(1)(B).

(b)

The limitations set out in (a) above apply notwithstanding any division of benefits on marriage breakdown occurring with respect to benefits payable from the EGD Plan or the EI Plan, as applicable. Provisions of the Plan stating that Plan benefits are payable on the same terms and conditions as benefits payable from the EGD Plan or the EI Plan, as applicable, shall be interpreted to exclude such a division of benefits.


(c)	Notwithstanding any provision to the contrary in this Section 1.8.03, if, as required by applicable law, a benefit payable under this Plan is divided at source or become payable to the Spouse or former Spouse of a Member in respect of such Member’s marriage breakdown, such benefit shall be calculated and paid to the Spouse or former Spouse in the manner

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determined by the Parent. For purposed of clarity, “as required by applicable law” as used in this provision shall not be construed to include a “domestic relations order” within the meaning of Code Section 414(p)(1)(B).

1.8.04

If the Parent receives evidence which in its absolute discretion is satisfactory to it that a person entitled to receive any payment provided for in the Plan is physically or mentally incompetent to receive such payment and to give a valid release therefor, then the Parent may direct the payment to the duly appointed legal guardian, committee or other legal representative of the payee, and such payment shall be a valid and complete discharge to the Plan for the payment.


1.8.05	Any application, notice or election under the Plan by a Member, Spouse or Beneficiary must be made, given or communicated, as the case may be, in such manner as the Parent may determine.


1.8.06	Any payment to be made under the Plan to a person during his lifetime only will cease with the payment made in the month which his death occurs.


1.8.07	No benefits shall be paid under the Plan while a Member continues to accrue service under the EGD Plan, the EI Plan or the EUS Plan, as applicable in the circumstances, except as provided for upon the discontinuance of the Plan or the discontinuance of the participation in the Plan by a Participating Employer pursuant to Section 1.9.


1.8.08	The Plan and all rights thereunder shall be governed, interpreted and administered in accordance with (a) the laws of the province of Alberta and the laws of Canada applicable therein, and (b) for Members subject to United States federal income taxation, the Code .


1.8.09	If any provision of the Plan is held to be invalid or unenforceable by a court of competent jurisdiction, its invalidity or unenforceability shall not affect any other provision of the Plan and the Plan shall be interpreted and enforced as if such provision had not been included therein.

1.8.10

The Parent, the RCA Fund and the Grantor Trust Fund are not liable to pay in total any more than the benefit determined under the applicable provision of the Plan, whether to either or both of a Member and any person who establishes a claim against the Member’s entitlement. In particular, but without restricting the generality of the foregoing, if there is any requirement in law that a person other than the person identified by the terms of the Plan is entitled to all or part of the benefit payable under the Plan, then the lawful requirement shall prevail over the provisions of the Plan.


1.9	Amendment or Discontinuance


1.9.01	The Parent expects to continue the Plan indefinitely, but nevertheless reserves the right to:


(a)	amend the Plan;


(b)	discontinue the Plan; or


(c)	amend the Plan to merge or consolidate the Plan with any other pension plan adopted by the Board of Directors;

provided that no such action shall reduce the benefits which have accrued immediately prior to the time such action is taken, except as provided in Section 1.9.02.

Any amendment or discontinuation of the Plan shall be made by:


(d)	the adoption of a resolution by the Board of Directors;


(e)	the execution of a certificate of amendment by an officer of the Parent authorized by a resolution of the Board of Directors to amend the plan; or


(f)	the adoption of a resolution by the Human Resources & Compensation Committee when authorized to do so by the Board of Directors.


1.9.02	If the Plan is wholly terminated:


(a)	the Parent shall not be obligated to make any further contributions to the Plan,


(b)	the assets then held under the RCA Fund and the Grantor Trust Fund shall be allocated for the provision of benefits, and

(c)

the Commuted Lump Sum Values and the value of the Notional Accounts accrued to the date of Plan termination pursuant to the applicable provisions of the Plan, to which the Members, their Spouses, Beneficiaries and joint annuitants are entitled, as determined by the Parent in consultation with the Actuary, shall become due and payable , unless the payment thereof would result in adverse taxation to the Member under Code Section 409A .

Notwithstanding Paragraph 1.9.02(a), in the event that assets held under the RCA Fund or the Grantor Trust Fund are not sufficient to provide all benefits payable therefrom, the Parent shall contribute to the RCA Fund or the Grantor Trust Fund, as is applicable, the amount of the insufficiency such that the Commuted Lump Sum Values and the value of the Notional Accounts payable from the RCA Fund and the Grantor Trust Fund are paid in full. Amounts equal to such additional contributions shall be paid by each Participating Employer, as is applicable, to the Parent.

In the event that such additional contributions cannot be made by the Parent due to bankruptcy or insolvency, the Funding Agency or the Grantor Trustee, as is applicable, shall pay the following amounts in the order indicated:


(d)	first, the termination expenses and any unpaid trustee expenses payable under the Funding Agreement or the Grantor Trust Agreement, as is applicable;


(e)	second, if there are Plan Assets still remaining in the RCA Fund or the Grantor Trust Fund, as is applicable, there shall be paid to each Member, Spouse or Beneficiary entitled to a benefit from the applicable fund the lesser of:


(i)	an amount equal to the fund's pension liability described in Section 1.4.06 applicable to such Member, Spouse or Beneficiary at the date of the termination of the Plan; and


(ii)	an amount equal to the ratio of the amount determined in subparagraph (e)(i) above for such Member, Spouse or Beneficiary to the aggregate of the amounts determined in subparagraph (e)(i) above for all such Members, Spouses or Beneficiaries multiplied by the applicable Plan Assets; and


(f)	third, if there are Plan Assets still remaining in the RCA Fund or the Grantor Trust Fund, as is applicable, there shall be paid to each Member, Spouse or Beneficiary entitled to a benefit from the applicable fund the lesser of:


(i)	any portion of the Commuted Lump Sum Value and the value of the Notional Account applicable to the fund and to such Member, Spouse or Beneficiary at the date of the termination of the Plan that was not paid under subparagraph (e)(i) above; and


(ii)	an amount equal to the ratio of the amount determined in subparagraph (f)(i) above for such Member, Spouse or Beneficiary to the aggregate of the amounts determined in subparagraph (f)(i) above for all such Members, Spouses and Beneficiaries multiplied by the applicable Plan Assets.

If after the provision of all such Commuted Lump Sum Values and the value of any Notional Accounts, as is applicable, to the Members, their Spouses, Beneficiaries and joint annuitants, there remain any Excess Assets in the RCA Fund or the Grantor Trust Fund, the Excess Assets shall revert to the Parent or shall be applied as the Parent may direct.


1.9.03	In the event that a Participating Employer’s board of directors passes a resolution to discontinue its participation in the Plan or the Board of Directors passes a resolution that states that a Participating Employer is no longer permitted to participate in the Plan:


(a)	the Parent shall not be obligated to make any further contributions to the Plan with respect to the Members employed by such Participating Employer,


(b)	the assets allocated to the relevant Participating Employer Account shall be allocated for the provision of benefits accrued by Members in respect of their employment with the Participating Employer, and

(c)

the associated Commuted Lump Sum Values and the value of the Notional Accounts accrued to the date of termination relating to benefits accrued by Members in respect of their employment with the Participating Employer, pursuant to the applicable provisions of the Plan, to which the Members, their Spouses, Beneficiaries and joint annuitants are entitled, as determined by the Parent in consultation with the Actuary, shall become due and payable, unless payment thereof would result in adverse taxation to the Member under Code Section 409A.

Notwithstanding Paragraph 1.9.03(a), in the event that assets held under the Participating Employer Account of the RCA Fund or the Grantor Trust Fund are not sufficient to provide all benefits payable therefrom, the Parent shall contribute to the RCA Fund or the Grantor Trust Fund, as is applicable, the amount of the insufficiency such that the Commuted Lump Sum Values and the value of the Notional Accounts are paid in full. An amount equal to such additional contribution shall be paid by the Participating Employer to the Parent.

If after the provision of all such accrued benefits to the Members, their Spouses, Beneficiaries and joint annuitants, there remain any Plan Assets in the Participating Employer Account, those Plan Assets shall revert to the Parent or shall be applied as the Parent may direct.

1.9.04

Where one or more Members cease to be employed by a Participating Employer and thereby cease to accrue benefits due to the sale of all or a portion of a Participating Employer or its business to a third-party purchaser, the Parent may elect, subject to the agreement of the purchaser, to transfer to the purchaser any and all obligations payable under the terms of the Plan with regard to such Participating Employer. The Parent may also elect, subject to the agreement of the purchaser, to transfer the value of the applicable Participating Employer Account to (a) an RCA trust (as defined in subsection 207.5(1) of the Income Tax Act) established by the purchaser or (b) a grantor trust within the meaning of Code Sections 671-677, as is applicable. Following the transfer of such obligations and Participating Employer Account, if applicable, Members whose benefits would have been payable pursuant to the Plan shall cease to be Members and shall have no further entitlement under the Plan.


1.9.05	Amounts payable pursuant to Sections 1.9.02 and 1.9.03 shall be paid:


(a)	if the Member is alive, directly to the Member,


(b)	if the Member is not alive, directly to the Member’s Spouse or Beneficiary as applicable in the circumstances.


1.9.06	Notwithstanding the other provisions of the Plan, for the purposes of Sections 1.9.02 and 1.9.03, the calculation of Commuted Lump Sum Values shall be based on the interest rate that would otherwise be used to determine the Commuted Lump Sum Value multiplied by one minus the highest marginal personal income tax rate applicable at the relevant time in the appropriate jurisdiction.


2.	Defined Benefit Provisions Relating to EI Plan Benefits Accrued by Active Members


2.1	Application of Article 2

The benefits payable, if any, from the Plan to an Active Member associated with his benefits accrued under the defined benefit provisions of the EI Plan are those determined in accordance with the following Sections of this Article 2. For all purposes of Article 2, any benefit attributable to service accrued while a US Tax Resident shall be excluded from the calculation of the benefit payable from the defined benefit provisions of the EI Plan.


2.1	Retirement Benefits


2.1.01	Amount of Retirement Benefits

An Active Member who retires under the terms of the EI Plan shall be entitled to a monthly retirement benefit equal to the excess, if any, of:


(a)	the Active Member’s monthly retirement benefit payable in accordance with the defined benefit provisions of the EI Plan, but as if the Maximum Pension Rules did not apply and the Post Retirement Adjustment Provisions were replaced by Section 5.1.01; over


(b)	the monthly retirement benefit payable in accordance with the defined benefit provisions of the EI Plan.


2.1.02	Payment of Retirement Benefits

The monthly retirement benefit provided to a Member under Section 2.1.01 shall be payable to the Member at the same time and on the same terms and conditions that apply to the pension benefit paid to the Member from the EI Plan . Notwithstanding the previous sentence, with respect to any Member who is a Specified Employee as of the date of such Member’s Separation from Service due to retirement, benefits that are subject to Code Section 409A shall not commence payment earlier than the first day of the month coincident with or next following the date that is six (6) months after the date of the Member’s Separation from Service.

With respect to Plan Years beginning on or after January 1, 2008, the accrued benefits of any Member subject to Code Section 409A shall commence payment on his Benefit Commencement Date. Benefits subject to Code Section 409A shall be paid in the form of monthly pension payable in the Normal Benefit Form. However, if a Member has not commenced receiving a benefit payment under the Plan, the Member may request, on a form provided by the Parent, that the form of distribution be changed from one type of life annuity (within the meaning of Code Section 409A) to another type of life annuity, to the extent such forms of benefit payment are available under the Plan and the EI Plan.

With respect to Plan Years beginning on or after January 1, 2008, for any Member whose date of Separation from Service is on or after such Member’s 55th birthday, the payment in the first month will be equal to the sum of seven monthly pension payments. This initial payment will constitute seven monthly payments for the purposes of determining the number of guaranteed monthly payments that have been paid to, or on behalf of, the Member.

In determining the amount of monthly retirement benefit for the purposes of Section 2.1.01(a):


(a)	the monthly retirement benefit under an elected optional form in accordance with the defined benefit provisions of the EI Plan may exceed the amount of retirement income payable under the normal form,


(b)	where section 1.5.03(a) of the EI Plan applies, the amounts considered as offsets in sections 2.1.02(a)(vi) and 2.1.02(b)(ii) of the EI Plan shall include amounts payable from both the EUS Plan and the US Supplemental Pension Plan,


(c)	a Member’s Earnings shall include amounts received by the Member from an Associate Company except that, where section 1.5.03(a) of the EI Plan applies and the Member’s employment ceases while he is employed by an Associate Company, amounts received by a Member from the Associate Company continue to be excluded, and


(d)	a Member’s Final Average Earnings shall be determined in the same manner as in section 1.2.33 of the EI Plan, except without regard to the final paragraph in that section.

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2.2	Death Benefits


2.2.01	Pre-Retirement Death Benefits in Respect of Service Prior to January 1, 2000

In the event of the death of an Active Member who was a Senior Management Employee on January 1, 2000, who had participated in the defined benefit provisions of the EI Plan and who was eligible for pre-retirement death benefits in accordance with the EI Plan, the Active Member’s surviving Spouse, or Beneficiary if there is no surviving Spouse, shall be entitled to a death benefit equal to the excess, if any, of :


(a)	the death benefit payable in accordance with the defined benefit provisions of the EI Plan in respect of service prior to January 1, 2000, but, if the Active Member was a Senior Management Employee on January 1, 2000, as if the Maximum Pension Rules did not apply; over


(b)	the death benefit payable in accordance with the defined benefit provisions of the EI Plan in respect of service prior to January 1, 2000.


2.2.02	Pre-Retirement Death Benefits in Respect of Service After December 31, 1999 and Prior to July 1, 2001

In the event of the death of an Active Member who had participated in the defined benefit provisions of the EI Plan as a Senior Management Employee prior to July 1, 2001, and who was eligible for pre-retirement death benefits in accordance with the EI Plan, the Active Member’s surviving Spouse, or Beneficiary if there is no surviving Spouse, shall be entitled to a death benefit equal to the excess, if any, of:


(a)	the death benefit payable in accordance with the defined benefit provisions of the EI Plan in respect of service after December 31, 1999 and prior to July 1, 2001 while the Member was a Senior Management Employee, but , for the period that the Active Member was a Senior Management Employee, as if the Maximum Pension Rules did not apply; over


(b)	the death benefit payable in accordance with the defined benefit provisions of the EI Plan in respect of service after December 31, 1999 and prior to July 1, 2001 while the Member was a Senior Management Employee.


2.2.03	Pre-Retirement Death Benefits in Respect of Service After June 30, 2001

In the event of the death of an Active Member who had accrued benefits under the defined benefit provisions of the EI Plan and who was eligible for pre-retirement death benefits in accordance with the EI Plan, the Active Member’s surviving Spouse, or Beneficiary if there is no surviving Spouse, shall be entitled to a death benefit equal to the excess, if any, of:


(a)	the death benefit payable in accordance with the defined benefit provisions of the EI Plan in respect of service after June 30, 2001, but as if the Maximum Pension Rules did not apply; over


(b)	the death benefit payable in accordance with the defined benefit provisions of the EI Plan in respect of service after June 30, 2001.

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2.2.04	Payment of Pre-Retirement Death Benefits

A pre-retirement death benefit payable in accordance with this Section shall be payable at the same time and on the same terms and conditions that apply to the pre-retirement death benefit paid to the surviving Spouse or Beneficiary from the EI Plan. provided, however , if the surviving Spouse or Beneficiary elects to transfer the Commuted Lump Sum Value of the death benefit payable in accordance with the defined benefit provisions of the EI Plan, the Commuted Lump Sum Value of the death benefit payable in accordance with this Section shall be paid to the surviving Spouse or Beneficiary in a cash lump sum, subject to applicable tax withholding, and no further entitlement under Article 2 shall be payable.

Notwithstanding the above paragraph, for Plan Years beginning on or after January 1, 2008, death benefits subject to Code Section 409A shall be paid to the Member’s surviving Spouse in the form of an annuity for the life of the Member’s surviving Spouse, commencing as of the Member’s Benefit Commencement Date as if the Member had survived to that date. Notwithstanding the foregoing, if the lump sum value of such annuity payable to the Member’s surviving Spouse is $10,000 or less, the Plan shall pay the Member’s surviving Spouse the lump sum without the surviving Spouse’s consent provided that (a) such payment constitutes the Member’s entire interest in the Plan and (b) distribution of the Member’s entire interest in all similar arrangements constituting nonqualified deferred compensation plans under Code Section 409A is also made as soon as administratively practicable after the Parent receives notification of the Member’s death, but in no event later than the later of (1) December 31 of the calendar year of the Member’s death or (2) the date that is 2½ months after the date of Member’s death. In determining the amount of death benefit for the purposes of Sections 2.2.01(a), 2.2.02(a), and 2.2.03(a):


(a)	where Section 1.5.03(a) of the EI Plan applies, the amounts considered as offsets in sections 2.1.02(a)(vi) and 2.1.02(b)(ii) of the EI Plan shall include amounts payable from both the EUS Plan and the US Supplemental Pension Plan,


(b)	an Active Member’s Earnings shall include amounts received by the Member from an Associate Company except that, where Section 1.5.03(a) of the EI Plan applies and the Member’s employment ceases while he is employed by an Associate Company, amounts received by an Active Member from the Associate Company continue to be excluded, and


(c)	an Active Member’s Final Average Earnings shall be determined in the same manner as in Section 1.2.33 of the EI Plan , except without regard to the final paragraph in that section.

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2.3	Termination Benefits


2.3.01	Pre-Retirement Termination Benefits in Respect of Service Prior to January 1, 2000

In the event of the termination of employment of an Active Member who was a Senior Management Employee on January 1, 2000 and who had participated in the defined benefit provisions of the EI Plan, provided that the termination of employment is for a reason other than death and occurs prior to the date on which he becomes eligible to retire in accordance with the EI Plan, the Active Member shall be entitled to a monthly retirement benefit equal to the excess, if any, of:


(a)	the termination benefit payable in accordance with the defined benefit provisions of the EI Plan in respect of service prior to January 1, 2000, but , if the Active Member was a Senior Management Employee on January 1, 2000, as if the Maximum Pension Rules did not apply; over


(b)	the termination benefit payable in accordance with the defined benefit provisions of the EI Plan in respect of service prior to January 1, 2000.


2.3.02	Pre-Retirement Termination Benefits in Respect of Service After December 31, 1999 and Prior to July 1, 2001

In the event of the termination of employment of an Active Member who had participated in the defined benefit provisions of the EI Plan as a Senior Management Employee prior to July 1, 2001, provided that the termination of employment is for a reason other than death and occurs prior to the date on which he becomes eligible to retire in accordance with the EI Plan, the Active Member shall be entitled to a monthly retirement benefit equal to the excess, if any, of:


(a)	the termination benefit payable in accordance with the defined benefit provisions of the EI Plan in respect of service after December 31, 1999 and prior to July 1, 2001 while the Member was a Senior Management Employee, but , for the period that the Active Member was a Senior Management Employee, as if the Maximum Pension Rules did not apply; over


(b)	the termination benefit payable in accordance with the defined benefit provisions of the EI Plan in respect of service after December 31, 1999 and prior to July 1, 2001 while the Member was a Senior Management Employee.


2.3.03	Pre-Retirement Termination Benefits in Respect of Service After June 30, 2001

In the event of the termination of employment of an Active Member who had participated in the defined benefit provisions of the EI Plan, provided that the termination of employment is for a reason other than death and occurs prior to the date on which he becomes eligible to retire in accordance with the EI Plan, the Active Member shall be entitled to a monthly retirement benefit equal to the excess, if any, of:


(a)	the termination benefit payable in accordance with the defined benefit provisions of the EI Plan in respect of service after June 30, 2001, but as if the Maximum Pension Rules did not apply; over


(b)	the termination benefit payable in accordance with the defined benefit provisions of the EI Plan in respect of service after June 30, 2001.


2.3.04	Payment of Termination Benefits

A pre-retirement termination benefit payable in accordance with this Section shall be payable at the same time and on the same terms and conditions that apply to the benefit paid to the Member from the EI Plan; provided, however, if the Member is a Specified Employee, termination benefits will commence payment on the first day of the month coincident with or next following the date he attains age 60. Notwithstanding the preceding sentence, if the Member elects to transfer the Commuted Lump Sum Value of his pre-retirement termination benefit payable in accordance with the defined benefit provisions of the E I Plan, the Commuted Lump Sum Value of the termination benefit payable in accordance with this Section shall be paid to the Member in a cash lump sum, subject to applicable tax withholding. Upon receipt of this payment, the Member will cease to be a Member and no further entitlement under Article 2 shall be payable.

For Plan Years beginning on or after January 1, 2008, termination benefits subject to Code Section 409A shall be payable only upon the Member’s Separation from Service. Benefits subject to Code Section 409A shall be paid in the form of monthly pension payable in the Normal Benefit Form. However, if a Member has not commenced receiving a benefit payment under the Plan, the Member may request, on a form provided by the Parent, that the form of distribution be changed from one type of life annuity (within the meaning of Code Section 409A) to another type of life annuity, to the extent such forms of benefit payment are available under the Plan and the EI Plan.

In determining the amount of termination benefit for the purposes of Sections 2.3.01(a), 2.3.02(a), and 2.3.03(a):


(a)	where Section 1.5.03(a) of the EI Plan applies, the amounts considered as offsets in Sections 2.1.02(a)(vi) and 2.1.02(b)(ii) of the EI Plan shall include amounts payable from both the EUS Plan and the US Supplemental Pension Plan,


(b)	a Member’s Earnings shall include amounts received by the Member from an Associate Company except that, where Section 1.5.03(a) of the EI RPP applies and the Member’s employment ceases while he is employed by an Associate Company, amounts received by a Member from the Associate Company continue to be excluded, and


(c)	an Active Member’s Final Average Earnings shall be determined in the same manner as in Section 1.2.33 of the EI RPP, except without regard to the final paragraph in that section.


3.	Defined Benefit Provisions Relating to EGD Plan Benefits


2.2	Application of Article 3

The benefits payable, if any, from the Plan to an Active Member associated with his benefits accrued under the defined benefit provisions of the EGD Plan and the EGD Supplementary Plan are those determined in accordance with the following Sections of this Article 3. For all purposes of Article 3, any benefit attributable to service accrued while a US Tax Resident shall be excluded from the calculation of the benefit payable from the defined benefit provisions of the EGD Plan and the EGD Supplementary Plan.


3.1	Retirement Benefits


3.1.01	Amount of Retirement Benefits in Respect of Service Prior to January 1, 2000 for Members who were Senior Management Employees on January 1, 2000

An Active Member who was a Senior Management Employee on January 1, 2000 and who retires under the terms of the EGD Plan shall be entitled to a monthly retirement benefit equal to the excess, if any, of:

(a)

the Active Member’s monthly retirement benefit payable in accordance with the defined benefit provisions of the EGD Plan and the EGD Supplementary Plan in respect of service prior to January 1, 2000, but as if the reduction upon early retirement did not exceed ¼ of 1% for every complete month, if any, prior to his attainment of age 60 and, if he is a member of the EGD Supplementary Plan, as if the Maximum Pension Rules did not apply; over


(b)	the monthly retirement benefit payable in accordance with the defined benefit provisions of the EGD Plan and the EGD Supplementary Plan in respect of service prior to January 1, 2000.


3.1.02	Amount of Retirement Benefits in Respect of Service Prior to July 1, 2001

An Active Member who retires under the terms of the EGD Plan shall be entitled to a monthly retirement benefit equal to the excess, if any, of:


(a)	the Active Member’s monthly retirement benefit payable in accordance with the defined benefit provisions of the EGD Plan in respect of service prior to July 1, 2001, but as if Section 4.02(2) of the EGD Plan did not restrict earnings growth to increases in the Average Industrial Wage, over


(b)	the monthly retirement benefit payable in accordance with the defined benefit provisions of the EGD Plan in respect of service prior to July 1, 2001.


3.1.03	Amount of Retirement Benefits in Respect of Service After June 30, 2001

An Active Member who retires under the terms of the EGD Plan shall be entitled to a monthly retirement benefit equal to the excess, if any, of:


(a)	the Active Member’s monthly retirement benefit payable at retirement in accordance with the defined benefit provisions of the EGD Plan and the EGD Supplementary Plan in respect of service after June 30, 2001, but as if the Maximum Pension Rules did not apply and as if Section 4.02(2) of the EGD Plan did not restrict earnings growth to increases in the Average Industrial Wage , over


(b)	the monthly normal retirement benefit payable in accordance with the defined benefit provisions of the EGD Plan and the EGD Supplementary Plan in respect of service after June 30, 2001.


3.1.04	Payment of Retirement Benefits

The monthly retirement benefit payable to a Member under Sections 3.1.01, 3.1.02 and 3.1.03 of the Plan shall be payable to the Member at the same time and on the same terms and conditions that apply to the pension benefit paid to the Member fro m the EGD Plan. Notwithstanding the previous sentence, with respect to any Member who is a Specified Employee as of the date of such Member’s Separation from Service due to retirement, benefits that are subject to Code Section 409A shall not commence payment earlier than the first day of the month coincident with or next following the date that is six (6) months after the date of the Member’s Separation from Service.

In determining the amount of monthly retirement benefits for the purposes of Section 3.1.01(a), the monthly retirement benefit under an elected optional form in accordance with the defined benefit provisions of the EGD Plan may exceed the amount of retirement income payable under the normal form.


3.2	Death Benefits


3.2.01	Pre-Retirement Death Benefits in Respect of Service Prior to January 1, 2000 for Members who were Senior Management Employees on January 1, 2000

In the event of the death of an Active Member who was a Senior Management Employee on January 1, 2000, who had participated in the defined benefit provisions of the EGD Plan and who was eligible for pre-retirement death benefits in accordance with the EGD Plan, the Active Member’s surviving Spouse, or Beneficiary if there is no surviving Spouse, shall be entitled to a death benefit equal to the excess, if any, of:

(a)

the death benefit payable in accordance with the defined benefit provisions of the EGD Plan and the EGD Supplementary Plan in respect of service prior to January 1, 2000, but in accordance with the normal form of pension applicable to Section 3.1.01(a) and as if the reduction upon early retirement did not exceed ¼ of 1% for every complete month, if any, prior to his attainment of age 60 and if he was a member of the EGD Supplementary Plan, as if the Maximum Pension Rules did not apply; over


(b)	the death benefit payable in accordance with the defined benefit provisions of the EGD Plan and the EGD Supplementary Plan in respect of service prior to January 1, 2000.


3.2.02	Pre-Retirement Death Benefits in Respect of Service Prior to July 1, 2001

In the event of the death of an Active Member who had participated in the defined benefit provisions of the EGD Plan and who was eligible for pre-retirement death benefits in accordance with the EGD Plan, the Active Member’s surviving Spouse, or Beneficiary if there is no surviving Spouse, shall be entitled to a death benefit equal to the excess, if any, of:


(a)	the death benefit payable in accordance with the defined benefit provisions of the EGD Plan in respect of service prior to July 1, 2001, but as if Section 4.02(2) of the EGD Plan did not restrict earnings growth to increases in the Average Industrial Wage, over


(b)	the death benefit payable in accordance with the defined benefit provisions of the EGD Plan in respect of service prior to July 1, 2001.


3.2.03	Pre-Retirement Death Benefits in Respect of Service After June 30, 2001


(a)	the death benefit payable in accordance with the defined benefit provisions of the EGD Plan in respect of service after June 30, 2001, but as if the Maximum Pension Rules did not apply but as if Section 4.02(2) of the EGD Plan did not restrict earnings growth to increases in the Average Industrial Wage, over


(b)	the death benefit payable in accordance with the defined benefit provisions of the EGD Plan in respect of service after June 30, 2001.


3.2.04	Payment of Pre-Retirement Death Benefits

A pre-retirement death benefit payable in accordance with this Section shall be payable at the same time and on the same terms and conditions that apply to the pre-retirement death benefit paid to the surviving Spouse or Beneficiary from the EGD Plan; provided, however, if the surviving Spouse or Beneficiary elects to transfer the Commuted Lump Sum Value of the death benefit payable in accordance with the defined benefit provisions of the EGD Plan, the Commuted Lump Sum Value of the death benefit payable in accordance with this Section shall be paid to the surviving Spouse or Beneficiary in a cash lump sum, subject to applicable tax withholding, and no further entitlement under Article 3 shall be payable.


3.3	Termination Benefits


3.3.01	Pre-Retirement Termination Benefits in Respect of Service Prior to January 1, 2000 for Members who were Senior Management Employees on January 1, 2000

In the event of the termination of employment of an Active Member who was a Senior Management Employee on January 1, 2000 and who had participated in the defined benefit provisions of the EGD Plan, provided that the termination of employment is for a reason other than death and occurs prior to the date on which he becomes eligible to retire in accordance with the EGD Plan, the Active Member shall be entitled to a monthly retirement benefit equal to the excess, if any, of:

(a)

the termination benefit payable in accordance with the defined benefit provisions of the EGD Plan and the EGD Supplementary Plan in respect of service prior to January 1, 2000, but in accordance with the normal form of pension applicable to Section 3.1.01(a) and as if the reduction upon early retirement did not exceed ¼ of 1% for every complete month, if any, prior to his attainment of age 60 and if he is a member of the EGD Supplementary Plan, as if the Maximum Pension Rules did not apply; over


(b)	the termination benefit payable in accordance with the defined benefit provisions of the EGD Plan and the EGD Supplementary Plan in respect of service prior to January 1, 2000.


3.3.02	Pre-Retirement Termination Benefits in Respect of Service Prior to July 1, 2001

In the event of the termination of employment of an Active Member who had participated in the defined benefit provisions of the EGD Plan, provided that the termination of employment is for a reason other than death and occurs prior to the date on which he becomes eligible to retire in accordance with the EGD Plan, the Active Member shall be entitled to a monthly retirement benefit equal to the excess, if any, of:


(a)	the termination benefit payable in accordance with the defined benefit provisions of the EGD Plan in respect of service prior to July 1, 2001, but as if Section 4.02(2) of the EGD Plan did not restrict earnings growth to increases in the Average Industrial Wage, over


(b)	the termination benefit payable in accordance with the defined benefit provisions of the EGD Plan and the EGD Supplementary Plan in respect of service prior to July 1, 2001.


3.3.03	Pre-Retirement Termination Benefits in Respect of Service After June 30, 2001


(a)	the termination benefit payable in accordance with the defined benefit provisions of the EGD Plan in respect of service after June 30, 2001, but as if the Maximum Pension Rules did not apply; over


(b)	the termination benefit payable in accordance with the defined benefit provisions of the EGD Plan in respect of service after June 30, 2001.


3.3.04	Payment of Termination Benefits

A pre-retirement termination benefit payable in accordance with this Section shall be payable at the same time and on the same terms and conditions that apply to the benefit paid to the Member from the EGD Plan; provided, however, if the Member is a Specified Employee, termination benefits will commence payment on the first day of the month coincident with or next following the date he attains age 60. Notwithstanding the previous sentence, if the Member elects to transfer the Commuted Lump Sum Value of his pre-retirement termination benefit payable in accordance with the defined benefit provisions of the EGD Plan , the Commuted Lump Sum Value of the termination benefit payable in accordance with this Section shall be paid to the Member in a cash lump sum, subject to applicable tax withholding. Upon receipt of this payment, the Member will cease to be a Member and no further entitlement under Article 3 shall be payable.


4.	Benefits Payable to Retired Members from the EI Plan


2.3	Application of Article 4

The benefits payable, if any, from the Plan to a Retired Member who retired, terminated employment with a Participating Employer, or died, prior to January 1, 2000, in respect of his service accrued under the defined benefit provisions of the EI Plan, are those determined in accordance with the following sections of this Article 4.


4.1	Retirement Benefits


4.1.01	Amount of Retirement Benefits

A Retired Member as defined in Paragraph 1.3.02(a) or, if applicable, his surviving Spouse shall be entitled to a monthly retirement benefit equal to the excess, if any, of:


(a)	the monthly retirement benefit as outlined in Appendix A; over


(b)	the monthly retirement benefit payable in accordance with the EI Plan.


4.1.02	Payment of Retirement Benefits

The monthly retirement benefit payable to a Retired Member as defined in Paragraph 1.3.02(a) or, if applicable, to his surviving Spouse shall be payable in accordance with the form specified in Appendix A.


5.	Post-Retirement Pension Increases


5.1.01	Annual Increases


(a)	Commencing December 1, 2001 and on December 1 of each calendar year thereafter, the amount of periodic lifetime retirement income payable to:


(i)	a Member who is entitled to post-retirement increases of the benefit payable to him pursuant to the EGD Plan or the EI Plan, as applicable, or


(ii)	the surviving Spouse or Beneficiary of such a Member

that was determined under one or more of Paragraphs 2.1.01(a), 3.1.02(a), 4.1.01(a) and 4.1.02 and Appendix B, including previous post-retirement increases provided in accordance with this Section 5.1.01, shall be increased by 50% of the increase in the Consumer Price Index for the calendar year, provided that at least 12 months have elapsed since the Member’s retirement date .

Notwithstanding the foregoing, annual increases will not be applied to that portion of the benefit under Paragraphs 2.1.01(a), 3.1.02(a), 4.1.01 (a) and 4.1.02 and Appendix B in respect of which no such increase is required to be applied pursuant to the EGD Plan or EI Plan, as applicable.


(b)	Commencing December 1, 2001 and on December 1 of each calendar year thereafter, the amount of periodic lifetime retirement income payable to:


(i)	a Member who is entitled to post-retirement increases of the benefit payable to him pursuant to the EGD Plan or the EI Plan, as applicable, or


(ii)	to the surviving Spouse or Beneficiary of such a Member

that was determined under Paragraph 3.1.01(a) shall be increased by 55% of the increase in the Consumer Price Index for the calendar year, provided that at least 12 months have elapsed since the Member’s Retirement Date and that the rate of increase for any calendar year does not exceed 5%. In the event that such an increase would have been in excess of 5%, the Participating Employer may in its discretion, carry forward the excess for application on a subsequent December 1st when the increase for that calendar year would have been less than 5%.


5.1.02	Annual Increases –Members with Canadian and United States Benefits

Notwithstanding Section 5.1.01 for Members who are entitled to annual increases under the US Supplemental Pension Plan, the annual increase that would otherwise have been determined in accordance with Section 5.1.01 may be determined and payable in accordance with the US Supplemental Pension Plan, provided that such determination is in accordance with the determination of Post Retirement Adjustment Provisions under the EI Plan and the EUS Plan.


6.	Defined Contribution Provisions

6.0 Application of Article 6

The benefits payable, if any, pursuant to the Plan to an Active Member associated with his benefits accrued under the defined contribution provisions of the EGD Plan or the EI Plan are those determined in accordance with the following Sections of this Article 6. For all purposes of Article 6, any benefit attributable to service accrued while a US Tax Resident shall be excluded from the calculation of the benefit payable from the defined contribution provisions of the EI Plan.


6.1	Establishment and Maintenance of Notional Accounts

The Parent shall establish and maintain a Notional Account for each Member which shall be notionally credited with:


(a)	the contributions determined in accordance with Section 6.2; plus


(b)	the Notional Investment Earnings credited thereon in the amounts and at the times determined in accordance with Section 6.3.


6.2	Notional Amounts of Contributions

The Notional Account of each Active Member shall be credited monthly with an amount equal to the excess, if any, of:


(a)	the company contribution in respect of the defined contribution provisions of the EGD Plan or the EI Plan, as applicable, but as if the Maximum DC Pension Rules did not apply; over


(b)	the company contribution in respect of the defined contribution provisions of the EGD Plan or the EI Plan, as applicable.


6.3	Notional Amounts of Investment Earnings

Notional Investment Earnings shall be periodically credited to an Active Member’s Notional Account, not less frequently than annually. For this purpose, the deemed income to be credited shall be the yield rate for Government of Canada Marketable Bonds with Average Yields Over 10 Years as published in the Bank of Canada Financial Statistics for the month of January of the Plan Year under CANSIM Series No. B14013, assuming such yield is compounded annually rather than semi-annually.


6.4	Payment of DC Pension Benefits


6.4.01	Retirement and Termination Benefits

An Active Member shall be entitled to the distribution of the value of his Notional Account as of the valuation date coincident with or immediately following the date that the Active Member:


(a)	retires under the terms of the EGD Plan or the EI Plan, as applicable;


(b)	ceases to be employed prior to retirement ; or


(a)	with respect to Notional Account benefits subject to Code Section 409A, incurs a Separation from Service .

Such amount shall be paid to the Member in an immediate cash lump sum, subject to applicable tax withholding. Upon receipt of this payment, the Member will cease to be a Member and no further entitlement under Article 6 shall be payable.

Notwithstanding the previous sentence, with respect to any Member who is a Specified Employee as of the date of his Separation from Service, benefits that are subject to Code Section 409A shall not be paid earlier than the first day of the month coincident with or next following the date that is six (6) months after the date of his Separation from Service.


6.4.02	Pre-retirement Death Benefits

In the event of the death of an Active Member prior to termination of his employment or retirement, the Active Member’s surviving Spouse, or if he has no surviving Spouse, the Active Member’s Beneficiary designated in accordance with the EGD Plan or the EI Plan, as applicable, shall be entitled to the distribution of the value of the Active Member’s Notional Account as of the valuation date coincident with or immediately following the death of the Active Member. Such amount shall be paid to the surviving Spouse or Beneficiary in a cash lump sum, subject to applicable tax withholding. Upon receipt of this payment, the Member will cease to be a Member and no further entitlement under Article 7 shall be payable.

Appendix A

For the purposes of Paragraph 4.1.01(a) and Section 4.1.02, monthly retirement benefits payable to Retired Members at January 1, 2000 are as follows:



Retired Member Name	Form of Pension	Monthly Pension Payable to Retired Member
		To Age 60		To Age 65		After Age 65 Until Death
BLIGHT, J.	Life Only	$	1,842.52	$	1,842.52	$	1,842.52
COLE, G.	Life Guaranteed 10 Years	9,659.60		9,659.60		9,659.60
HASKAYNE, R.	Life Only	23,848.64		23,848.64		23,848.64
KIRKWOOD, G.	Joint & Survivor 60%	4,727.12		4,727.12		3,927.15
MAC DERMOTT, D.	Joint & Survivor 100%	2,477.36		2,477.36		2,477.36
MC NEILL, K.	Joint & Survivor 100%	6,026.23		6,026.23		6,026.23
OMOTH, W.	Joint & Survivor 60%	3,967.79		3,967.79		3,024.32
PEARCE, W.	Life Only	5,301.82		5,301.82		5,301.82
PHILLIPS, B.	Joint & Survivor 100%	1,804.62		1,804.62		1,804.62
PICK, A.	Joint & Survivor 50%	3,447.24		3,447.24		2,295.30
POTTER, D.	Joint & Survivor 60%	2,576.75		2,421.02		1,442.02
ROSS, D.	Life Only	9,857.46		9,857.46		9,857.46
SAVARD, D.	Joint & Survivor 60%	10,232.20		10,117.33		9,662.28
STEPHENS, S.	Joint & Survivor 75%	5,004.26		5,004.26		5,004.26
WALDON, D.	Life Only	2,905.84		2,905.84		2,905.84
WATKINS, R.	Joint & Survivor 50%	5,901.96		5,901.96		5,901.96

For the purposes of Paragraph 4.1.01(a) and Section 4.1.02, monthly retirement benefits payable to the surviving Spouses of Retired Members at January 1, 2000 are as follows:



Retired Member Name	Form of Pension	Monthly Pension Payable to Retired Member
Retired Member Name	Form of Pension	To Age 60		To Age 65		After Age 65 Until Death
SHEASBY, B.A.	Life Only		$2,710.44		$2,710.44		$2,710.44
HEULE, D.	Life Only		$8,457.60		$8,457.60		$8,457.60

Appendix B

Negotiated Pension Benefits

In addition to any benefits payable in accordance with the other Articles of the Plan, the RCA Fund or the Grantor Trust Fund , as the case may be, shall pay any additional pension benefit that is not payable under the EGD Plan or the EI Plan and that is required pursuant to an executive employment agreement executed by a Member and the Parent except that any such additional pension benefit that is a result of a Member’s period of employment while a US Tax Resident shall be payable from the US Supplemental Pension Plan.

Restatement effective January 1 , 2018 17

Exhibit 10.2

Execution Version

THIRD AMENDMENT TO THE
ENBRIDGE SUPPLEMENTAL PENSION PLAN FOR UNITED STATES EMPLOYEES
(As Amended and Restated Effective January 1, 2005)

Pursuant to Section 8.1 of the Enbridge Employee Services, Inc. Employees’ Supplemental Plan, as amended (the “ Supplemental Plan ”), and the authority delegated to it by the Board of Directors of Enbridge Employee Services, Inc. (the “ EESI Board ”), the Human Resources & Compensation Committee of the Enbridge Inc. Board of Directors (the “ HRCC ”) has approved, confirmed, and adopted this Third Amendment at a meeting of the HRCC held on the 1st day of August 2017, at which a quorum was present.

PART I: CROSS-REFERENCES

1. Effective as of January 1, 2018, Section 3(a)(i)(F) of the Supplemental Plan is amended to replace “ Section 1.1(s)(i)(A) and 1.1(s)(ii)(A) ” with “ Section 1.1(u)(i)(A) and 1.1(u)(ii)(A) ” wherein it appears.

2. Effective as of January 1, 2018, Section 3(b)(i)(F) of the Supplemental Plan is amended to replace “ Section 1.1(s)(i)(B) and 1.1(s)(ii)(B) ” with “ Section 1.1(u)(i)(B) and 1.1(u)(ii)(B) ” wherein it appears.

3. Effective as of January 1, 2018, Section 3(b)(i)(G) of the Supplemental Plan is amended to replace “ (as determined pursuant to (E) above) ” with “ (as determined pursuant to (F) above) ” wherein it appears.

4. Effective as of January 1, 2018, the final paragraph of Section 3(b) of the Supplemental Plan is amended to replace “ subparagraph (i)(A)(x) and (ii) ” with “ subparagraphs (i)(A)(1) and (2) ” wherein it appears, and to replace “ subparagraphs (i)(A)(x) and (ii) ” with “ subparagraphs (i)(A)(1) and (2) ” wherein it appears.

PART II: BENEFIT CHANGES

1. Effective as of January 1, 2018, Section 1.1(e) of the Supplemental Plan is hereby deleted and replaced, in its entirety, with the following new Section 1.1(e):

(e) “ Average Final Pay ” for periods on and after January 1, 2018 has the same meaning as in the Qualified Plan. For periods prior to January 1, 2018, “Average Final Pay” has the same meaning as in the Qualified Plan, except that, in determining the amount of Average Final Pay for a Senior Management Employee who received benefits from an Affiliate’s long term disability program, Base Pay shall be deemed to have continued in the amount equal to the Participant’s Base Pay in effect immediately prior to the incurrence of the disability and shall be adjusted annually according to increases in the U.S. Consumer Price Index, up to a maximum of 5% per year.

2. Effective as of January 1, 2018, Section 3(b)(i)(E) of the Supplemental Plan is hereby deleted and replaced, in its entirety, with the following new Section 3(b)(i)(E):

(E) with respect to a Participant who terminates employment with all Affiliates:

(1) on or after the date on which he attains age 55, any adjustment for early benefit commencement under the Qualified Plan did not exceed ¼ of 1% for each month by which the Participant’s age at the Benefit Commencement Date precedes age 60; or

(2) prior to the date on which he attains age 55:

(i) with respect to the portion of the benefit described in Section 3(b)(i) attributable to Credited Service prior to January 1, 2018, any adjustment for early benefit commencement under the Qualified Plan did not exceed ¼ of 1% for each month by which the Participant’s age at the Benefit Commencement Date precedes age 60; and

(ii) with respect to the portion of the benefit described in Section 3(b)(i) attributable to Credited Service on or after January 1, 2018, any adjustment for early benefit commencement under the Qualified Plan did not exceed ½ of 1% for each month by which the Participant’s age at the Benefit Commencement Date precedes age 65;

3. Effective as of January 1, 2018, Section 4.2 of the Supplemental Plan is hereby deleted and replaced, in its entirety, with the following new Section 4.2:

4.2 Cost of Living Supplements . The amount of each periodic benefit payment to a Participant, as determined pursuant to Section 4.1 , shall be increased to reflect a cost of living adjustment at the same time and in the same manner as under the Qualified Plan, but only with respect to that portion of the benefit which is attributable to Credited Service accrued before January 1, 2018. No cost of living adjustment shall be applied to that portion of the benefit that is attributable to Credited Service accrued on or after January 1, 2018. The benefit payable under this Section 4.2 applies to all Participants under the Plan, regardless of whether the Participant is entitled to a cost of living adjustment under the Qualified Plan.

4. Effective as of January 1, 2018, Section 5.3(d) of the Supplemental Plan is hereby deleted and replaced, in its entirety, with the following new Section 5.3(d):

(d) Cost of Living Supplements. The amount of each periodic payment to a Surviving Spouse or Beneficiary, as determined pursuant to paragraph (c) above, that is attributable to Credited Service accrued before January 1, 2018, shall be increased to reflect a cost of living adjustment at the same time and in the same manner as under the Qualified Plan.

5. Effective as of January 1, 2018, Section 9.9 of the Supplemental Plan is hereby deleted and replaced, in its entirety, with the following new Section 9.9:

9.9 Entire Agreement . Except as provided in Addendum C, the terms and conditions set forth herein constitute the entire understanding of the Company and the Participants with respect to the matters addressed herein.

6. Effective as of January 1, 2018, Addendum C of the Supplemental Plan is hereby deleted and replaced, in its entirety, with the following new Addendum C:

Special Negotiated Benefits

The Company may from time to time provide special benefits for one or more of its employees in addition to the benefits provided to him or her under the Plan and the Qualified Plan. In such case, the Company may, by separate agreement, set out the terms of that special benefit and may specify that the special benefit is provided under the Plan. The employee entitled to receive the special benefit shall be considered to be a Participant in the Plan, and the terms of the Plan shall apply to him or her except to the extent expressly specified in the separate agreement. For purposes of clarity, the term

“separate agreement,” as used in this Addendum C, includes (but is not limited to) any executive employment agreement, letter, or memorandum of understanding signed by the Participant and a duly authorized representative of either the Company or Enbridge Inc., which sets out the terms of the special benefit payable to or on behalf of the Participant under the Plan. Unless otherwise expressly stated in the separate agreement, any special benefit payable under the Plan pursuant to such separate agreement shall be paid in accordance with the rules set forth herein pertaining to the time and manner of payment of Plan distributions.

As amended hereby, the Supplemental Plan is hereby specifically ratified and reaffirmed in its entirety.

To record this Third Amendment, the undersigned delegate of the HRCC, pursuant to authorization of the HRCC, hereby confirms and executes the Third Amendment on this 15 ^th day of December 2017.


By:	Marc Weil, VP and Chief HR Officer on behalf of the Human Resources & Compensation Committee of the Enbridge Inc. Board of Directors

Exhibit 10.3

ENBRIDGE INC.

DIRECTORS’ COMPENSATION PLAN

February 14, 2018

Effective January 1, 2018

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” 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;

“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 to hold Shares and all the rights, privileges and benefits conferred by this Plan in trust for the Directors;

“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 C ompensation 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)	Certificates representing such Shares shall be registered in the name of the Director and held by the Trustee for the benefit of such Director and shall be delivered to such Director if and when requested by the Director.


(d)	The Trustee shall maintain an account for each Director and credit to that account all Shares acquired by the Trustee for the Director under this Section 8 and debit to that account all such Shares delivered by the Trustee to the Director under this Section 8.


(e)	A statement of account will be provided by the Trustee to each Director annually or in any event promptly after each purchase of Shares on such Director’s behalf, and will set out the number of Shares so purchased, the aggregate number of Shares held by the Trustee for such Director, and any information required by the Director for tax reporting purposes.


(f)	Shares held by the Trustee may not be pledged, sold or otherwise disposed of by a Director.


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 Form ¹
Compensation Elements	Annual Fee ²	Before minimum share ownership			After minimum share ownership
		Cash	Shares	DSUs	Cash ³	Shares ³	DSUs ³
Board Retainer	$260,000 ⁴	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.

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, 2018	By:	/s/ Al Monaco
			Al Monaco President and Chief Executive Officer Enbridge Inc.

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, 2018	By:	/s/ John K. Whelen
			John K. Whelen Executive Vice President and Chief Financial Officer (Principal Financial Officer) Enbridge Inc.

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, 2018 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, 2018	By:	/s/ Al Monaco
			Al Monaco President and Chief Executive Officer Enbridge Inc.

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, 2018 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, 2018	By:	/s/ John K. Whelen
			John K. Whelen Executive Vice President and Chief Financial Officer (Principal Financial Officer) Enbridge Inc.