Enbridge : MD&A and Financial Statements

ENBRIDGE INC.

CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

March 31, 2020

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF EARNINGS

	Three months ended
	March 31,
	2020	2019
(unaudited; millions of Canadian dollars, except per share amounts)
Operating revenues
Commodity sales	7,389	6,632
Transportation and other services	3,208	4,348
Gas distribution sales	1,416	1,876
Total operating revenues (Note 3)	12,013	12,856
Operating expenses
Commodity costs	7,163	6,565
Gas distribution costs	855	1,207
Operating and administrative	1,600	1,625
Depreciation and amortization	882	840
Total operating expenses	10,500	10,237
Operating income	1,513	2,619
Income from equity investments	163	413
Impairment of equity investments (Note 9)	(1,736)	-
Other income/(expense)
Net foreign currency gain/(loss)	(956)	214
Other	(191)	46
Interest expense	(706)	(685)
Earnings/(loss) before income taxes	(1,913)	2,607
Income tax recovery/(expense) (Note 11)	549	(584)
Earnings/(loss)	(1,364)	2,023
(Earnings)/loss attributable to noncontrolling interests	31	(37)
Earnings/(loss) attributable to controlling interests	(1,333)	1,986
Preference share dividends	(96)	(95)
Earnings/(loss) attributable to common shareholders	(1,429)	1,891
Earnings/(loss) per common share attributable to common shareholders (Note 5)	(0.71)	0.94
Diluted earnings/(loss) per common share attributable to common shareholders	(0.71)	0.94
(Note 5)

See accompanying notes to the interim consolidated financial statements.

1

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

	Three months ended
	March 31,
	2020	2019
(unaudited; millions of Canadian dollars)
Earnings/(loss)	(1,364)	2,023
Other comprehensive income/(loss), net of tax
Change in unrealized loss on cash flow hedges	(513)	(192)
Change in unrealized gain/(loss) on net investment hedges	(715)	94
Other comprehensive income/(loss) from equity investees	(10)	12
Excluded components of fair value hedges	3	-
Reclassification to earnings of loss on cash flow hedges	32	11
Reclassification to earnings of pension and other postretirement benefits	3	38
(OPEB) amounts
Foreign currency translation adjustments	5,637	(1,291)
Other comprehensive income/(loss), net of tax	4,437	(1,328)
Comprehensive income	3,073	695
Comprehensive (income)/loss attributable to noncontrolling interests	(145)	13
Comprehensive income attributable to controlling interests	2,928	708
Preference share dividends	(96)	(95)
Comprehensive income attributable to common shareholders	2,832	613

See accompanying notes to the interim consolidated financial statements.

2

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

	Three months ended
	March 31,
	2020		2019
(unaudited; millions of Canadian dollars, except per share amounts)
Preference shares (Note 5)
Balance at beginning and end of period	7,747		7,747
Common shares (Note 5)
Balance at beginning of period	64,746		64,677
Shares issued on exercise of stock options	14		51
Balance at end of period	64,760		64,728
Additional paid-in capital
Balance at beginning of period	187		-
Stock-based compensation	14		4
Options exercised	(16)		(43)
Change in reciprocal interest	12		109
Other	5		2
Balance at end of period	202		72
Deficit
Balance at beginning of period	(6,314)		(5,538)
Earnings/(loss) attributable to controlling interests	(1,333)		1,986
Preference share dividends	(96)		(95)
Dividends paid to reciprocal shareholder	5		5
Modified retrospective adoption ofASU 2016-13 Financial Instruments - Credit Losses (Note 2)	(66)		-
Other	(4)		2
Balance at end of period	(7,808)		(3,640)
Accumulated other comprehensive income/(loss) (Note 8)
Balance at beginning of period	(272)		2,672
Other comprehensive income/(loss) attributable to common shareholders, net of tax	4,261		(1,278)
Other	-		55
Balance at end of period	3,989		1,449
Reciprocal shareholding
Balance at beginning of period	(51)		(88)
Change in reciprocal interest	4		37
Balance at end of period	(47)		(51)
Total Enbridge Inc. shareholders' equity	68,843		70,305
Noncontrolling interests
Balance at beginning of period	3,364		3,965
Earnings/(loss) attributable to noncontrolling interests	(31)		37
Other comprehensive income/(loss) attributable to noncontrolling interests, net of tax
Change in unrealized loss on cash flow hedges	(2)		(1)
Foreign currency translation adjustments	178		(49)
	176		(50)
Comprehensive income/(loss) attributable to noncontrolling interests	145		(13)
Contributions	15		3
Distributions	(76)		(46)
Redemption of preferred shares held by subsidiary	-		(300)
Other	-		5
Balance at end of period	3,448		3,614
Total equity	72,291		73,919
Dividends paid per common share	0.810		0.738
Earnings/(loss) per common share attributable to common shareholders (Note 5)	(0.71)		0.94
Diluted earnings/(loss) per common share attributable to common shareholders (Note 5)	(0.71)		0.94

See accompanying notes to the interim consolidated financial statements.

3

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Three months ended
	March 31,
	2020		2019
(unaudited; millions of Canadian dollars)
Operating activities
Earnings/(loss)	(1,364)		2,023
Adjustments to reconcile earnings to net cash provided by operating activities:
Depreciation and amortization	882		840
Deferred income tax (recovery)/expense	(713)		435
Changes in unrealized (gain)/loss on derivative instruments, net (Note 10)	1,556		(538)
Earnings from equity investments	(163)		(413)
Distributions from equity investments	428		466
Impairment of equity investments (Note 9)	1,736		-
Other	253		30
Changes in operating assets and liabilities	194		(667)
Net cash provided by operating activities	2,809		2,176
Investing activities
Capital expenditures	(1,147)		(1,612)
Long-term investments and restricted long-term investments	(87)		(565)
Distributions from equity investments in excess of cumulative earnings	77		139
Additions to intangible assets	(69)		(26)
Affiliate loans, net	(44)		(84)
Net cash used in investing activities	(1,270)		(2,148)
Financing activities
Net change in short-term borrowings	(63)		(154)
Net change in commercial paper and credit facility draws	1,159		2,773
Debenture and term note issues, net of issue costs	990		1,195
Debenture and term note repayments	(1,657)		(1,789)
Contributions from noncontrolling interests	15		3
Distributions to noncontrolling interests	(76)		(46)
Common shares issued	1		18
Preference share dividends	(96)		(90)
Common share dividends	(1,641)		(1,486)
Redemption of preferred shares held by subsidiary	-		(300)
Other	(18)		(25)
Net cash provided by/(used in) financing activities	(1,386)		99
Effect of translation of foreign denominated cash and cash equivalents and	11		(7)
restricted cash
Net increase in cash and cash equivalents and restricted cash	164		120
Cash and cash equivalents and restricted cash at beginning of period	676		637
Cash and cash equivalents and restricted cash at end of period	840		757

See accompanying notes to the interim consolidated financial statements.

4

ENBRIDGE INC.

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

	March 31,	December 31,
	2020	2019
(unaudited; millions of Canadian dollars; number of shares in millions)
Assets
Current assets
Cash and cash equivalents	799	648
Restricted cash	41	28
Accounts receivable and other	6,574	6,781
Accounts receivable from affiliates	38	69
Inventory	699	1,299
	8,151	8,825
Property, plant and equipment, net	98,483	93,723
Long-term investments	15,986	16,528
Restricted long-term investments	443	434
Deferred amounts and other assets	8,155	7,433
Intangible assets, net	2,239	2,173
Goodwill	35,549	33,153
Deferred income taxes	1,248	1,000
Total assets	170,254	163,269
Liabilities and equity
Current liabilities
Short-term borrowings	835	898
Accounts payable and other	8,306	10,063
Accounts payable to affiliates	11	21
Interest payable	615	624
Current portion of long-term debt	4,221	4,404
	13,988	16,010
Long-term debt	63,571	59,661
Other long-term liabilities	10,499	8,324
Deferred income taxes	9,905	9,867
	97,963	93,862
Contingencies (Note 13)
Equity
Share capital
Preference shares	7,747	7,747
Common shares(2,025 and 2,025 outstanding at March 31, 2020 and	64,760	64,746
December 31, 2019, respectively)
Additional paid-in capital	202	187
Deficit	(7,808)	(6,314)
Accumulated other comprehensive income/(loss) (Note 8)	3,989	(272)
Reciprocal shareholding	(47)	(51)
Total Enbridge Inc. shareholders' equity	68,843	66,043
Noncontrolling interests	3,448	3,364
	72,291	69,407
Total liabilities and equity	170,254	163,269

See accompanying notes to the interim consolidated financial statements.

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NOTES TO THE INTERIM CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

1. BASIS OF PRESENTATION

The accompanying unaudited interim consolidated financial statements of Enbridge Inc. ("we", "our", "us" and "Enbridge") have been prepared in accordance with generally accepted accounting principles in the United States of America (U.S. GAAP) and Regulation S-X for interim consolidated financial information. They do not include all of the information and notes required by U.S. GAAP for annual consolidated financial statements and should therefore be read in conjunction with our audited consolidated financial statements and notes for the year ended December 31, 2019. In the opinion of management, the interim consolidated financial statements contain all normal recurring adjustments necessary to present fairly our financial position, results of operations and cash flows for the interim periods reported. These interim consolidated financial statements follow the same significant accounting policies as those included in our audited consolidated financial statements for the year ended December 31, 2019, except for the adoption of new standards (Note 2). Amounts are stated in Canadian dollars unless otherwise noted.

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

2. CHANGES IN ACCOUNTING POLICIES

ADOPTION OF NEW ACCOUNTING STANDARDS

Clarifying Interaction between Collaborative Arrangements and Revenue from Contracts with Customers

Effective January 1, 2020, we adopted Accounting Standards Update (ASU) 2018-18 on a retrospective basis. The new standard was issued in November 2018 to provide clarity on when transactions between entities in a collaborative arrangement should be accounted for under the new revenue standard, Accounting Standards Codification (ASC) 606. In determining whether transactions in collaborative arrangements should be accounted for under the revenue standard, the update specifies that entities shall apply unit of account guidance to identify distinct goods or services and whether such goods and services are separately identifiable from other promises in the contract. ASU 2018-18 also precludes entities from presenting transactions with a collaborative partner which are not in scope of the new revenue standard together with revenue from contracts with customers. The adoption of this ASU did not have a material impact on our consolidated financial statements.

Disclosure Effectiveness

Effective January 1, 2020, we adopted ASU 2018-13 on both a retrospective and prospective basis depending on the change. The new standard was issued to improve the disclosure requirements for fair value measurements by eliminating and modifying some disclosures, while also adding new disclosures. The adoption of this ASU did not have a material impact on our consolidated financial statements.

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Accounting for Credit Losses

Effective January 1, 2020, we adopted ASU 2016-13 on a modified retrospective basis.

The new standard 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. The previous accounting treatment used the incurred loss methodology for recognizing credit losses that delayed the recognition until it was probable a loss had 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 recognizes as an allowance its estimate of expected credit losses, which the Financial Accounting Standards Board believes results in more timely recognition of such losses.

Further, ASU 2018-19 was issued in November 2018 to clarify that operating lease receivables should be accounted for under the new leases standard, ASC 842, and are not within the scope of ASC 326, Financial Instruments - Credit Losses.

For accounts receivable, a loss allowance matrix is utilized to measure lifetime expected credit losses. The matrix contemplates historical credit losses by age of receivables, adjusted for any forward-looking information and management expectations. Other loan receivables and off-balance sheet commitments in scope of the new standard utilize a discounted cash flow methodology which calculates the current expected credit losses based on historical default probability rates associated with the credit rating of the counterparty and the related term of the loan or commitment, adjusted for forward-looking information and management expectations.

On January 1, 2020 we recorded $66 million of additional Deficit on our Statements of Financial Position in connection with the adoption of ASU 2016-13. The adoption of this ASU did not have a material impact on the Consolidated Statements of Earnings, Comprehensive Income or Cash Flows during the period.

FUTURE ACCOUNTING POLICY CHANGES

Reference Rate Reform

ASU 2020-04 was issued in March 2020 to provide temporary optional guidance in accounting for reference rate reform. The new guidance provides optional expedients and exceptions for applying generally accepted accounting principles when accounting for contract modifications, hedging relationships and other transactions impacted by rate reform, subject to meeting certain criteria. ASU 2020-04 is effective as of March 12, 2020 through December 31, 2022. We are currently assessing the impact of the new standard and the rate reform on our consolidated financial statements.

Clarifying Interaction between Equity Securities, Equity Method Investments and Derivatives ASU2020-01was issued in January 2020 and clarifies that observable transactions should be considered for the purpose of applying the measurement alternative in accordance with ASC 321 immediately before the application or upon discontinuance of the equity method of accounting. Furthermore, the ASU clarifies that forward contracts or purchased options on equity securities are not out of scope of ASC 815 guidance only because, upon the contracts' exercise, the equity securities could be accounted for under the equity method of accounting or fair value option. ASU2020-01is effective January 1, 2021 with early adoption permitted and is applied prospectively. We are currently assessing the impact of the new standard on our consolidated financial statements.

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Accounting for Income Taxes

ASU 2019-12 was issued in December 2019 with the intent of simplifying the accounting for income taxes. The accounting update removes certain exceptions to the general principles in ASC 740 as well as provides simplification by clarifying and amending existing guidance. ASU 2019-12 is effective January 1, 2021 and entities are permitted to adopt the standard early. We are currently assessing the impact of the new standard on our consolidated financial statements.

Disclosure Effectiveness

ASU 2018-14 was issued in August 2018 to improve disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. The amendment modifies the current guidance by adding and removing several disclosure requirements while also clarifying the guidance on current disclosure requirements. ASU 2018-14 is effective January 1, 2021 and entities are permitted to adopt the standard early. The adoption of ASU 2018-14 is not expected to have a material impact on our consolidated financial statements.

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3. REVENUES

REVENUE FROM CONTRACTS WITH CUSTOMERS

Major Products and Services

		Gas	Gas
		Transmission	Distribution	Renewable
Three months ended	Liquids	and	and	Power	Energy	Eliminations
March 31, 2020	Pipelines	Midstream	Storage	Generation	Services	and Other	Consolidated
(millions of Canadian dollars)
Transportation revenues	2,440	1,255	215	-	-	-	3,910
Storage and other revenues	26	79	47	-	-	-	152
Gas gathering and processing	-	7	-	-	-	-	7
revenues
Gas distribution revenue	-	-	1,417	-	-	-	1,417
Electricity and transmission	-	-	-	50	-	-	50
revenues
Total revenue from contracts with	2,466	1,341	1,679	50	-	-	5,536
customers
Commodity sales	-	-	-	-	7,389	-	7,389
Other revenues1,2	(1,017)	16	(1)	103	(7)	(6)	(912)
Intersegment revenues	85	-	4	-	16	(105)	-
Total revenues	1,534	1,357	1,682	153	7,398	(111)	12,013
		Gas	Gas
		Transmission	Distribution	Renewable
Three months ended	Liquids	and	and	Power	Energy	Eliminations
March 31, 2019	Pipelines	Midstream	Storage	Generation	Services	and Other	Consolidated
(millions of Canadian dollars)	2,214	1,137	249				3,600
Transportation revenues	-	-	-
Storage and other revenues	27	53	54	-	-	-	134
Gas gathering and processing	-	116	-	-	-	-	116
revenues
Gas distribution revenues	-	-	1,856	-	-	-	1,856
Electricity and transmission	-	-	-	50	-	-	50
revenues
Total revenue from contracts with	2,241	1,306	2,159	50	-	-	5,756
customers
Commodity sales	-	-	-	-	6,632	-	6,632
Other revenues1, 2	340	10	29	102	6	(19)	468
Intersegment revenues	77	2	3	-	35	(117)	-
Total revenues	2,658	1,318	2,191	152	6,673	(136)	12,856

1. Includesmark-to-market gains/(losses) from our hedging program for the three months ended March 31, 2020 and 2019 of $1,106 million loss and $258 million gain, respectively.
2. Includes revenues from lease contracts for the three months ended March 31, 2020 and 2019 of $158 million and $164 million, respectively.

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

Contract Balances
	Receivables	Contract	Contract
	Assets	Liabilities
(millions of Canadian dollars)
Balance as at December 31, 2019	2,099	216	1,424
Balance as at March 31, 2020	2,287	224	1,500

Contract receivables represent the amount of receivables derived from contracts with customers.

9

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

Contract liabilities represent payments received for performance obligations which have not been fulfilled. Contract liabilities primarily relate to make-up rights and deferred revenues. Revenue recognized during the three months ended March 31, 2020 included in contract liabilities at the beginning of the period was $86 million. Increases in contract liabilities from cash received, net of amounts recognized as revenues during the three months ended March 31, 2020 were $76 million.

Performance Obligations

There were no material revenues recognized in the three months ended March 31, 2020 from performance obligations satisfied in previous periods.

Revenues to be Recognized from Unfulfilled Performance Obligations

Total revenues from performance obligations expected to be fulfilled in future periods is $68.0 billion, of which $5.5 billion and $6.4 billion is expected to be recognized during the nine months ending December 31, 2020, and the year ending December 31, 2021, 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 revenue from contracts with customers. Certain revenues such as flow-through operating costs charged to shippers are recognized at the amount for which we have the right to invoice our customers and are excluded from the amounts for revenues to be recognized in the future from unfulfilled performance obligations above. Variable consideration is excluded from the amounts above due to the uncertainty of the associated consideration, which is generally resolved when actual volumes and prices are determined. For example, we consider interruptible transportation service revenues to be variable revenues since volumes cannot be estimated. Additionally, the effect of escalation on certain tolls which are contractually escalated for inflation has not been reflected in the amounts above as it is not possible to reliably estimate future inflation rates. Revenues for periods extending beyond the current rate settlement term for regulated contracts where the tolls are periodically reset by the regulator are excluded from the amounts above since future tolls remain unknown. Finally, revenue from contracts with customers which have an original expected duration of one year or less are excluded from the amounts above.

Recognition and Measurement of Revenues

		Gas	Gas
		Transmission	Distribution	Renewable
Three months ended	Liquids	and	and	Power	Energy
March 31, 2020	Pipelines	Midstream	Storage	Generation	Services	Consolidated
(millions of Canadian dollars)
Revenues from products transferred at a point	-	-	15	-	-	15
in time
Revenues from products and services	2,466	1,341	1,664	50	-	5,521
transferred over time1
Total revenue from contracts with customers	2,466	1,341	1,679	50	-	5,536
		Gas	Gas
		Transmission	Distribution	Renewable
Three months ended	Liquids	and	and	Power	Energy
March 31, 2019	Pipelines	Midstream	Storage	Generation	Services	Consolidated
(millions of Canadian dollars)
Revenues from products transferred at a point	-	-	17	-	-	17
in time
Revenues from products and services	2,241	1,306	2,142	50	-	5,739
transferred over time1
Total revenue from contracts with customers	2,241	1,306	2,159	50	-	5,756

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

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4. SEGMENTED INFORMATION

		Gas	Gas
		Transmission	Distribution	Renewable
Three months ended	Liquids	and	and	Power	Energy	Eliminations
March 31, 2020	Pipelines	Midstream	Storage	Generation	Services	and Other	Consolidated
(millions of Canadian dollars)
Revenues	1,534	1,357	1,682	153	7,398	(111)	12,013
Commodity and gas distribution	(7)	-	(872)	-	(7,243)	104	(8,018)
costs
Operating and administrative	(865)	(507)	(249)	(50)	(28)	99	(1,600)
Income/(loss) from equity	197	(75)	23	16	2	-	163
investments
Impairment of equity investments	-	(1,736)	-	-	-	-	(1,736)
Other income/(expense)	(9)	(93)	20	1	(8)	(1,058)	(1,147)
Earnings/(loss) before interest,
income taxes, and depreciation	850	(1,054)	604	120	121	(966)	(325)
and amortization
Depreciation and amortization							(882)
Interest expense							(706)
Income tax recovery							549
Loss							(1,364)
Capital expenditures1	500	391	222	23	-	22	1,158
		Gas	Gas
		Transmission	Distribution	Renewable
Three months ended	Liquids	and	and	Power	Energy	Eliminations
March 31, 2019	Pipelines	Midstream	Storage	Generation	Services	and Other	Consolidated
(millions of Canadian dollars)	2,658	1,318	2,191	152	6,673	(136)	12,856
Revenues
Commodity and gas distribution	(6)	-	(1,264)	(1)	(6,629)	128	(7,772)
costs
Operating and administrative	(801)	(513)	(294)	(42)	(33)	58	(1,625)
Income/(loss) from equity	197	197	11	14	(7)	1	413
investments
Other income	24	18	18	1	2	197	260
Earnings before interest, income
taxes, and depreciation and	2,072	1,020	662	124	6	248	4,132
amortization
Depreciation and amortization							(840)
Interest expense							(685)
Income tax expense							(584)
Earnings							2,023
Capital expenditures1	1,020	394	173	14	1	25	1,627

1 Includes allowance for equity funds used during construction.

5. EARNINGS PER COMMON SHARE AND DIVIDENDS PER SHARE

BASIC

Earnings per common share is calculated by dividing earnings attributable to common shareholders by the weighted average number of common shares outstanding. The weighted average number of common shares outstanding has been reduced by our pro-rata weighted average interest in our own common shares of 6 million for both the three months ended March 31, 2020 and 2019, resulting from our reciprocal investment in Noverco Inc.

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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,

2020 2019

(number of common shares in millions)
Weighted average shares outstanding	2,019	2,016
Effect of dilutive options	2	3
Diluted weighted average shares outstanding	2,021	2,019

For the three months ended March 31, 2020 and 2019, 16.7 million and 10.5 million, respectively, anti- dilutive stock options with a weighted average exercise price of $56.26 and $55.32, respectively, were excluded from the diluted earnings per common share calculation.

DIVIDENDS PER SHARE

On May 5, 2020, our Board of Directors declared the following quarterly dividends. All dividends are payable on June 1, 2020, to shareholders of record on May 15, 2020.

	Dividend per
	share
Common Shares1	$0.81000
Preference Shares, Series A	$0.34375
Preference Shares, Series B	$0.21340
Preference Shares, Series C2	$0.25458
Preference Shares, Series D	$0.27875
Preference Shares, Series F	$0.29306
Preference Shares, Series H	$0.27350
Preference Shares, Series J	US$0.30540
Preference Shares, Series L	US$0.30993
Preference Shares, Series N	$0.31788
Preference Shares, Series P	$0.27369
Preference Shares, Series R	$0.25456
Preference Shares, Series 1	US$0.37182
Preference Shares, Series 3	$0.23356
Preference Shares, Series 5	US$0.33596
Preference Shares, Series 7	$0.27806
Preference Shares, Series 9	$0.25606
Preference Shares, Series 113	$0.24613
Preference Shares, Series 13	$0.27500
Preference Shares, Series 15	$0.27500
Preference Shares, Series 17	$0.32188
Preference Shares, Series 19	$0.30625

1. The quarterly dividend per common share was increased 9.8% to $0.81 from $0.738, effective March 1, 2020.
2. The quarterly dividend per share paid on Series C was increased to $0.25458 from $0.25305 on March 1, 2020 due to reset on a quarterly basis following the date of issuance of the Series C Preference Shares.
3. The quarterly dividend per share paid on Series 11 was decreased to $0.24613 from $0.275 on March 1, 2020, due to the reset of the annual dividend on March 1, 2020, and every five years thereafter.

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6. ACQUISITIONS AND DISPOSITIONS

ASSETS HELD FOR SALE

Line 10 Crude Oil Pipeline

In the first quarter of 2018, we satisfied the condition as set out in our agreements for the sale of our Line 10 crude oil pipeline (Line 10), which originates near Hamilton, Ontario and terminates at West Seneca, New York. Our subsidiaries, Enbridge Pipelines Inc. and EEP, own the Canadian and United States portions of Line 10, respectively, and the related assets are included in our Liquids Pipelines segment. Subject to certain regulatory approvals and customary closing conditions, the transaction is expected to close in 2020.

Montana-Alberta Tie Line

In the fourth quarter of 2019, we committed to a plan to sell the Montana-Alberta Tie Line transmission assets, a 345 kilometer transmission line from Great Falls, Montana to Lethbridge, Alberta. Its related assets are included in our Renewable Power Generation segment. The purchase and sale agreement was signed in January 2020. The transaction closed on May 1, 2020, please refer to Note 14. Subsequent Events.

Ozark Gas Transmission

In the first quarter of 2020, we agreed to sell our Ozark Gas Transmission and Ozark Gas Gathering assets (Ozark assets). The Ozark assets are composed of a 367 mile transmission system that extends from southeastern Oklahoma through Arkansas to southeastern Missouri, and a fee-based 330 mile gathering system that accesses Fayetteville Shale and Arkoma production. These assets are included in our Gas Transmission and Midstream segment. The transaction closed on April 1, 2020, please refer to Note 14. Subsequent Events.

Upon the reclassification and subsequent remeasurement of the Ozark assets as held for sale, a loss of $19 million was included within Operating and administrative expenses on the Consolidated Statements of Earnings for the three months ended March 31, 2020.

Summary of Assets Held for Sale

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

	March 31,	December 31,
	2020	2019
(millions of Canadian dollars)
Accounts receivable and other (current assets held for sale)	17	28
Deferred amounts and other assets (long-term assets held for sale)1	330	269
Accounts payable and other (current liabilities held for sale)	(8)	-
Net assets held for sale	339	297

1 Included within Deferred amounts and other assets at March 31, 2020 and December 31, 2019 is property, plant and equipment of $241 million and $181 million, respectively.

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7. DEBT

CREDIT FACILITIES

The following table provides details of our committed credit facilities as at March 31, 2020:

	Maturity	Total	Draws1	Available
	Facilities
(millions of Canadian dollars)
Enbridge Inc.	2021-2024	10,959	6,250	4,709
Enbridge (U.S.) Inc.	2021-2024	7,829	2,162	5,667
Enbridge Pipelines Inc.	20212	3,000	2,155	845
Enbridge Gas Inc.	20212	2,000	835	1,165
Total committed credit facilities		23,788	11,402	12,386

1. Includes facility draws and commercial paper issuances that areback-stopped by credit facility.
2. Maturity date is inclusive of the one year term out option.

On February 24, 2020, Enbridge Inc. entered into a two year, non-revolving credit facility for US$1 billion with a syndicate of lenders.

On February 25, 2020, Enbridge Inc. entered into two, one year, non-revolving, bilateral credit facilities for a total of US$500 million.

On March 31, 2020, Enbridge Inc. entered into a one year, revolving, syndicated credit facility for $1.7 billion. On April 9, 2020, Enbridge Inc. exercised an accordion provision and increased the facility to $3.0 billion.

In addition to the committed credit facilities noted above, we maintain $806 million of uncommitted demand credit facilities, of which $523 million were unutilized as at March 31, 2020. As at December 31, 2019, we had $916 million of uncommitted credit facilities, of which $476 million were unutilized.

Our credit facilities carry a weighted average standby fee of 0.1% per annum on the unused portion and draws bear interest at market rates. Certain credit facilities serve as a back-stop to the commercial paper programs and we have the option to extend such facilities, which are currently scheduled to mature from 2021 to 2024.

As at March 31, 2020 and December 31, 2019, commercial paper and credit facility draws, net of short- term borrowings and non-revolving credit facilities that mature within one year, of $9,855 million and $8,974 million, respectively, were supported by the availability of long-term committed credit facilities and therefore have been classified as long-term debt.

LONG-TERM DEBT ISSUANCES

During the three months ended March 31, 2020, we completed the following long-term debt issuances:

Company Issue Date	Principal
Amount
(millions of Canadian dollars, unless otherwise stated)
Enbridge Inc.
February 2020 Floating rate notes	US$750

On April 1, 2020, Enbridge Gas Inc. (Enbridge Gas) issued $600 million of 2.90% 10-yearmedium-term notes and $600 million of 3.65% 30-year medium term notes payable semi-annually in arrears. The notes mature on April 1, 2030 and April 1, 2050, respectively.

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LONG-TERM DEBT REPAYMENTS

During the three months ended March 31, 2020, we completed the following long-term debt repayments:

Company Repayment Date		Principal
	Amount
(millions of Canadian dollars, unless otherwise stated)
Enbridge Inc.
January 2020	Floating rate notes	US$700
March 2020	4.53% medium-term notes	$500
Spectra Energy Partners, LP
January 2020	6.09% senior secured notes	US$111
Westcoast Energy Inc.
January 2020	9.90% debentures	$100

SUBORDINATED TERM NOTES

As at March 31, 2020 and December 31, 2019, our fixed-to-floating subordinated term notes had a principal value of $6,955 million and $6,550 million, respectively.

FAIR VALUE ADJUSTMENT

As at March 31, 2020, the net fair value adjustment for total debt assumed in the acquisition of Spectra Energy was $847 million. During the three months ended March 31, 2020, the amortization of the fair value adjustment, recorded as a reduction to Interest expense in the Consolidated Statements of Earnings, was $15 million.

DEBT COVENANTS

Our credit facility agreements and term debt indentures include standard events of default and covenant provisions whereby accelerated repayment and/or termination of the agreements may result if we were to default on payment or violate certain covenants. As at March 31, 2020, 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, 2020 and 2019 are as follows:

		Excluded	Net	Cumulative		Pension
		Components		and
	Cash Flow	of Fair Value	Investment	Translation	Equity	OPEB
	Hedges	Hedges	Hedges	Adjustment	Investees	Adjustment	Total
(millions of Canadian dollars)
Balance as at January 1, 2020	(1,073)	-	(317)	1,396	67	(345)	(272)
Other comprehensive income/(loss)	(693)	3	(715)	5,459	(7)	-	4,047
retained in AOCI
Other comprehensive (income)/loss
reclassified to earnings
Interest rate contracts1	43	-	-	-	-	-	43
Foreign exchange contracts2	1	-	-	-	-	-	1
Amortization of pension and OPEB	-	-	-	-	-	4	4
actuarial loss and prior service costs4
	(649)	3	(715)	5,459	(7)	4	4,095

Tax impact

Income tax on amounts retained in

AOCI

Income tax on amounts reclassified to earnings

182 - - - (3) - 179

(12) - - - - (1) (13)

	170	-	-	-	(3)	(1)	166
Balance as at March 31, 2020	(1,552)	3	(1,032)	6,855	57	(342)	3,989

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		Net	Cumulative		Pension
			and
	Cash Flow	Investment	Translation	Equity	OPEB
	Hedges	Hedges	Adjustment	Investees	Adjustment	Total
(millions of Canadian dollars)
Balance as at January 1, 2019	(770)	(598)	4,323	34	(317)	2,672
Other comprehensive income/(loss) retained in	(312)	109	(1,242)	8	-	(1,437)
AOCI
Other comprehensive (income)/loss reclassified to
earnings
Interest rate contracts1	32	-	-	-	-	32
Foreign exchange contracts2	2	-	-	-	-	2
Other contracts3	(9)	-	-	-	-	(9)
Amortization of pension and OPEB actuarial loss	-	-	-	-	53	53
and prior service costs4
Tax impact	(287)	109	(1,242)	8	53	(1,359)
Income tax on amounts retained in AOCI	121	(15)	-	4	-	110
Income tax on amounts reclassified to earnings	(14)	-	-	-	(15)	(29)
	107	(15)	-	4	(15)	81
Other	-	-	-	-	55	55
Balance as at March 31, 2019	(950)	(504)	3,081	46	(224)	1,449

1. Reported within Interest expense in the Consolidated Statements of Earnings.
2. Reported within Transportation and other services revenues and Net foreign currency gain/(loss) in the Consolidated Statements of Earnings.
3. Reported within Operating and administrative expense in the Consolidated Statements of Earnings.
4. These components are included in the computation of net periodic benefit costs and are reported within Other income/(expense) in the Consolidated Statements of Earnings.

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9. IMPAIRMENT OF EQUITY INVESTMENTS

For the three months ended March 31, 2020, we recorded a loss of $1,736 million resulting from an other than temporary impairment to the carrying value of our equity method investment in DCP Midstream, LLC (DCP Midstream). DCP Midstream holds a limited partner interest in and is the owner of the general partner of DCP Midstream, LP. The impairment in our equity investment is related to a decline in the market price of DCP Midstream, LP publicly-traded units as at March 31, 2020. In addition, we recorded a loss of $324 million from our equity pick up of the loss recorded by DCP Midstream in relation to DCP Midstream, LP's asset and goodwill impairment. This is recorded within Income from Equity Investments in the Consolidated Statement of Earnings. Our investment in DCP Midstream is part of the Gas Transmission and Midstream segment and our carrying value of the investment as at March 31, 2020 and December 31, 2019 was $341 million and $2,193 million, respectively.

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 risks). Formal risk management policies, processes and systems have been designed to mitigate these risks.

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

Foreign Exchange Risk

We generate certain revenues, incur expenses, and hold a number of investments and subsidiaries that are denominated in currencies other than Canadian dollars. As a result, our earnings, cash flows and OCI are exposed to fluctuations resulting from foreign exchange rate variability.

We employ financial derivative instruments to hedge foreign currency denominated earnings exposure. A combination of qualifying cash flow, fair value and non-qualifying derivative instruments is used to hedge anticipated foreign currency denominated revenues and expenses, and to manage variability in cash flows. We hedge certain net investments in United States dollar denominated investments and subsidiaries using foreign currency derivatives and United States dollar denominated debt.

Interest Rate Risk

Our earnings and cash flows are exposed to short-term interest rate variability due to the regular repricing of our variable rate debt, primarily commercial paper. We monitor our debt portfolio mix of fixed and variable rate debt instruments to manage a consolidated portfolio of floating rate debt within the Board of Directors approved policy limit of a maximum of 30% of floating rate debt as a percentage of total debt outstanding. We primarily use qualifying derivative instruments to manage interest rate risk. Pay fixed- receive floating interest rate swaps may be used to hedge against the effect of future interest rate movements. We have implemented a program to significantly mitigate the impact of short-term interest rate volatility on interest expense via execution of floating to fixed interest rate swaps with an average swap rate of 2.9%.

We are exposed to changes in the fair value of fixed rate debt that arise as a result of the changes in market interest rates. Pay floating-receive fixed interest rate swaps are used, when applicable, to hedge against future changes to the fair value of fixed rate debt which mitigates the impact of fluctuations in the fair value of fixed rate debt via execution of fixed to floating interest rate swaps. As at March 31, 2020, we do not have any pay floating-receive fixed interest rate swaps outstanding.

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Our earnings and cash flows are also exposed to variability in longer term interest rates ahead of anticipated fixed rate term debt issuances. Forward starting interest rate swaps are used to hedge against the effect of future interest rate movements. We have established a program within some of our subsidiaries to mitigate our exposure to long-term interest rate variability on select forecast term debt issuances via execution of floating to fixed interest rate swaps with an average swap rate of 3.1%.

Commodity Price Risk

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

Equity Price Risk

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

TOTAL DERIVATIVE INSTRUMENTS

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

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

The following table summarizes the maximum potential settlement amounts in the event of these specific circumstances. All amounts are presented gross in the Consolidated Statements of Financial Position.

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	Derivative	Derivative	Derivative	Non-	Total Gross
	Instruments	Instruments	Instruments	Derivative
	Used as	Used as Net	Used as	Qualifying	Instruments		Amounts	Total Net
	Cash Flow	Investment	Fair Value	Derivative	as		Available	Derivative
March 31, 2020	Hedges	Hedges	Hedges	Instruments	Presented		for Offset	Instruments
(millions of Canadian
dollars)
Accounts receivable and
other
Foreign exchange	-	-	49	56	105		(50)	55
Commodity contracts	2	-	-	961	963		(289)	674
	2	-	49	1,017	1,068	1	(339)	729
Deferred amounts and other
Foreign exchange	30	-	169	174	373		(128)	245
Commodity contracts	3	-	-	65	68		(22)	46
	33	-	169	239	441		(150)	291
Accounts payable and other
Foreign exchange	(5)	(20)	-	(899)	(924)		50	(874)
Interest rate contracts	(813)	-	-	(18)	(831)		-	(831)
Commodity contracts	-	-	-	(506)	(506)		289	(217)
Other Contracts	-	-	-	(1)	(1)		-	(1)
	(818)	(20)	-	(1,424)	(2,262)	2	339	(1,923)
Other long-term liabilities
Foreign exchange	-	-	-	(2,428)	(2,428)		128	(2,300)
Interest rate contracts	(395)	-	-	-	(395)		-	(395)
Commodity contracts	-	-	-	(81)	(81)		22	(59)
Other contracts	(4)	-	-	(3)	(7)		-	(7)
	(399)	-	-	(2,512)	(2,911)		150	(2,761)
Total net derivative assets/
(liabilities)
Foreign exchange	25	(20)	218	(3,097)	(2,874)		-	(2,874)
Interest rate contracts	(1,208)	-	-	(18)	(1,226)		-	(1,226)
Commodity contracts	5	-	-	439	444		-	444
Other contracts	(4)	-	-	(4)	(8)		-	(8)
	(1,182)	(20)	218	(2,680)	(3,664)		-	(3,664)

1. As at March 31, 2020, $1,067 million was reported within Accounts receivable and other and $1 million within Accounts receivable from affiliates on the Consolidated Statements of Financial Position.
2. As at March 31, 2020, $2,246 million was reported within Accounts payable and other and $16 million within Accounts payable to affiliates on the Consolidated Statements of Financial Position.

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	Derivative	Derivative	Non-	Total Gross
	Instruments	Instruments	Derivative
	Used as	Used as Net	Qualifying	Instruments	Amounts	Total Net
	Cash Flow	Investment	Derivative	as	Available	Derivative
December 31, 2019	Hedges	Hedges	Instruments	Presented	for Offset	Instruments
(millions of Canadian dollars)
Accounts receivable and other
Foreign exchange contracts	-	-	161	161	(78)	83
Commodity contracts	-	-	163	163	(47)	116
Other contracts	1	-	3	4	-	4
	1	-	327	328 1	(125)	203
Deferred amounts and other assets
Foreign exchange contracts	10	-	71	81	(42)	39
Commodity contracts	-	-	17	17	(2)	15
Other contracts	2	-	1	3	-	3
	12	-	89	101	(44)	57
Accounts payable and other
Foreign exchange contracts	(5)	(13)	(392)	(410)	78	(332)
Interest rate contracts	(353)	-	-	(353)	-	(353)
Commodity contracts	-	-	(173)	(173)	47	(126)
	(358)	(13)	(565)	(936) 2	125	(811)
Other long-term liabilities
Foreign exchange contracts	-	-	(934)	(934)	42	(892)
Interest rate contracts	(181)	-	-	(181)	-	(181)
Commodity contracts	(5)	-	(60)	(65)	2	(63)
	(186)	-	(994)	(1,180)	44	(1,136)
Total net derivative assets/(liabilities)
Foreign exchange contracts	5	(13)	(1,094)	(1,102)	-	(1,102)
Interest rate contracts	(534)	-	-	(534)	-	(534)
Commodity contracts	(5)	-	(53)	(58)	-	(58)
Other contracts	3	-	4	7	-	7
	(531)	(13)	(1,143)	(1,687)	-	(1,687)

1. As at December 31, 2019, $327 million was reported within Accounts receivable and other and $1 million within Accounts receivable from affiliates on the Consolidated Statements of Financial Position.
2. As at December 31, 2019, $920 million was reported within Accounts payable and other and $16 million within Accounts payable to affiliates on the Consolidated Statements of Financial Position.

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

March 31, 2020	2020	2021	2022	2023	2024	Thereafter	Total
Foreign exchange contracts - United States dollar
forwards - purchase(millions of United States	823	500	1,750	-	-	-	3,073
dollars)
Foreign exchange contracts - United States dollar
forwards - sell(millions of United States dollars)	4,416	5,631	5,703	3,784	1,856	-	21,390
Foreign exchange contracts - British pound (GBP)
forwards - sell(millions of GBP)	89	27	28	29	30	90		293
Foreign exchange contracts - Euro forwards - sell	23	94	94	92	91	515		909
(millions of Euro)
Foreign exchange contracts - Japanese yen
forwards - purchase (millions of yen)	-	-	72,500	-	-	-	72,500
Interest rate contracts - short-term pay fixed rate	4,618	4,284	422	50	36	121		9,531
(millions of Canadian dollars)
Interest rate contracts - long-term debt pay fixed
rate(millions of Canadian dollars)	3,544	1,619	-	-	-	-		5,163
Equity contracts(millions of Canadian dollars)	16	34	-	-	-	-		50
Commodity contracts - natural gas (billions of cubic	(38)	57	45	22	10	11		107
feet)
Commodity contracts - crude oil (millions of barrels)	5	4	1	-	-	-		10
Commodity contracts - power (megawatt per hour)	79	(3)	(43)	(43)	(43)	(43)	1	(16)	2
(MW/H)

1. As at March 31, 2020, thereafter includes an average net purchase/(sell) of power of (43) MW/H for 2025.
2. Total is an average net purchase/(sell) of power.

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Fair Value Derivatives

For foreign exchange 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 Net foreign currency gain/(loss) in the Consolidated Statements of Earnings. Any excluded components are included in the Statements of Comprehensive Income.

Three months ended

March 31,

2020 2019

(millions of Canadian dollars)
Unrealized gain on derivative	218	-
Unrealized loss on hedged item	(203)	-
Realized loss on derivative	(12)	-

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

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

	Three months ended
	March 31,
	2020		2019
(millions of Canadian dollars)
Amount of unrealized gain/(loss) recognized in OCI
Cash flow hedges
Foreign exchange contracts	19		(10)
Interest rate contracts	(715)		(296)
Commodity contracts	9		(3)
Other contracts	(7)		12
Fair value hedges
Foreign exchange contracts	3		-
Net investment hedges
Foreign exchange contracts	(7)		1
	(698)		(296)
Amount of (gain)/loss reclassified from AOCI to earnings
Foreign exchange contracts1	1		2
Interest rate contracts2	43		32
Other contracts3	-		(9)
	44		25

1. Reported within Transportation and other services revenues and Net foreign currency gain/(loss) in the Consolidated Statements of Earnings.
2. Reported within Interest expense in the Consolidated Statements of Earnings.
3. Reported within Operating and administrative expense in the Consolidated Statements of Earnings.

We estimate that a loss of $164 million of AOCI related to unrealized cash flow hedges will be reclassified to earnings in the next 12 months. Actual amounts reclassified to earnings depend on the foreign exchange rates, interest rates and commodity prices in effect when derivative contracts that are currently outstanding mature. For all forecasted transactions, the maximum term over which we are hedging exposures to the variability of cash flows is 21 months as at March 31, 2020.

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Non-Qualifying Derivatives

The following table presents the unrealized gains and losses associated with changes in the fair value of our non-qualifying derivatives:

	Three months ended
	March 31,
	2020		2019
(millions of Canadian dollars)
Foreign exchange contracts1	(2,003)		616
Interest rate contracts2	(18)		178
Commodity contracts3	473		(261)
Other contracts4	(8)		5
Total unrealized derivative fair value gain/(loss), net	(1,556)		538

1. For the respective three months ended periods, reported within Transportation and other services revenues (2020 - $1,061 million loss; 2019 - $352 million gain) and Net foreign currency gain/(loss) (2020 - $942 million loss; 2019 - $264 million gain) in the Consolidated Statements of Earnings.
2. Reported as an (increase)/decrease within Interest expense in the Consolidated Statements of Earnings.
3. For the respective three months ended periods, reported within Transportation and other services revenues (2020 - $34 million gain; 2019 - $26 million loss), Commodity sales (2020 - $1,493 million gain; 2019 - $642 million loss), Commodity costs (2020 - $1,045 million loss; 2019 - $398 million gain) and Operating and administrative expense (2020 - $9 million loss; 2019 - $9 million gain) in the Consolidated Statements of Earnings.
4. Reported within Operating and administrative expense in the Consolidated Statements of Earnings.

LIQUIDITY RISK

Liquidity risk is the risk that we will not be able to meet our financial obligations, including commitments and guarantees, as they become due. In order to mitigate this risk, we forecast cash requirements over a 12-month rolling time period to determine whether sufficient funds will be available and maintain substantial capacity under our committed bank lines of credit to address any contingencies. Our primary sources of liquidity and capital resources are funds generated from operations, the issuance of commercial paper and draws under committed credit facilities and long-term debt, which includes debentures and medium-term notes. We also maintain current shelf prospectuses with securities regulators which enables ready access to either the Canadian or United States public capital markets, subject to market conditions. 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, 2020. As a result, all credit facilities are available to us and the banks are obligated to fund and have been funding us under the terms of the facilities.

CREDIT RISK

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

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

	March 31,	December 31,
	2020	2019
(millions of Canadian dollars)
Canadian financial institutions	128	146
United States financial institutions	310	40
European financial institutions	165	3
Asian financial institutions	76	92
Other1	798	113
	1,477	394

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

As at March 31, 2020, we provided letters of credit totaling nil in lieu of providing cash collateral to our counterparties pursuant to the terms of the relevant International Swaps and Derivatives Association agreements. We held no cash collateral on derivative asset exposures as at March 31, 2020 and December 31, 2019.

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 Enbridge 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.

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Level 2

Level 2 includes derivative valuations determined using directly or indirectly observable inputs other than quoted prices included within Level 1. Derivatives in this category are valued using models or other industry standard valuation techniques derived from observable market data. Such valuation techniques include inputs such as quoted forward prices, time value, volatility factors and broker quotes that can be observed or corroborated in the market for the entire duration of the derivative. Derivatives valued using Level 2 inputs include non-exchange traded derivatives such as over-the-counter foreign exchange forward and cross currency swap contracts, interest rate swaps, physical forward commodity contracts, as well as commodity swaps and options for which observable inputs can be obtained.

We have also categorized the fair value of our held to maturity preferred share investment and long-term debt as Level 2. The fair value of our held to maturity preferred share investment is primarily based on the yield of certain Government of Canada bonds. The fair value of our long-term debt is based on quoted market prices for instruments of similar yield, credit risk and tenor.

Level 3

Level 3 includes derivative valuations based on inputs which are less observable, unavailable or where the observable data does not support a significant portion of the derivatives' fair value. Generally, Level 3 derivatives are longer dated transactions, occur in less active markets, occur at locations where pricing information is not available or have no binding broker quote to support Level 2 classification. We have developed methodologies, benchmarked against industry standards, to determine fair value for these derivatives based on extrapolation of observable future prices and rates. Derivatives valued using Level 3 inputs primarily include long-dated derivative power, crude, NGL and natural gas contracts, basis swaps, commodity swaps and energy swaps. 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. Depending on the type of derivative and nature of the underlying risk, we use observable market prices (interest, foreign exchange, commodity and share price) as primary inputs to these valuation techniques. Finally, we consider our own credit default swap spread as well as the credit default swap spreads associated with our counterparties in our estimation of fair value.

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

				Total Gross
				Derivative
March 31, 2020	Level 1	Level 2	Level 3	Instruments
(millions of Canadian dollars)
Financial assets
Current derivative assets
Foreign exchange contracts	-	105	-	105
Commodity contracts	90	73	800	963
	90	178	800	1,068
Long-term derivative assets
Foreign exchange contracts	-	373	-	373
Commodity contracts	33	19	16	68
	33	392	16	441
Financial liabilities
Current derivative liabilities
Foreign exchange contracts	-	(924)	-	(924)
Interest rate contracts	-	(831)	-	(831)
Commodity contracts	(58)	(20)	(428)	(506)
Other contracts	-	(1)	-	(1)
	(58)	(1,776)	(428)	(2,262)
Long-term derivative liabilities
Foreign exchange contracts	-	(2,428)	-	(2,428)
Interest rate contracts	-	(395)	-	(395)
Commodity contracts	(13)	(8)	(60)	(81)
Other contracts	-	(7)	-	(7)
	(13)	(2,838)	(60)	(2,911)
Total net financial assets/(liabilities)
Foreign exchange contracts	-	(2,874)	-	(2,874)
Interest rate contracts	-	(1,226)	-	(1,226)
Commodity contracts	52	64	328	444
Other contracts	-	(8)	-	(8)
	52	(4,044)	328	(3,664)

26

				Total Gross
				Derivative
December 31, 2019	Level 1	Level 2	Level 3	Instruments
(millions of Canadian dollars)
Financial assets
Current derivative assets
Foreign exchange contracts	-	161	-	161
Commodity contracts	-	33	130	163
Other contracts	-	4	-	4
	-	198	130	328
Long-term derivative assets
Foreign exchange contracts	-	81	-	81
Commodity contracts	-	12	5	17
Other contracts	-	3	-	3
	-	96	5	101
Financial liabilities
Current derivative liabilities
Foreign exchange contracts	-	(410)	-	(410)
Interest rate contracts	-	(353)	-	(353)
Commodity contracts	(5)	(23)	(145)	(173)
	(5)	(786)	(145)	(936)
Long-term derivative liabilities
Foreign exchange contracts	-	(934)	-	(934)
Interest rate contracts	-	(181)	-	(181)
Commodity contracts	-	(6)	(59)	(65)
	-	(1,121)	(59)	(1,180)
Total net financial assets/(liabilities)
Foreign exchange contracts	-	(1,102)	-	(1,102)
Interest rate contracts	-	(534)	-	(534)
Commodity contracts	(5)	16	(69)	(58)
Other contracts	-	7	-	7
	(5)	(1,613)	(69)	(1,687)

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

March 31, 2020	Fair	Unobservable	Minimum	Maximum	Weighted	Unit of
Value	Input	Price	Price	Average Price	Measurement
(fair value in millions of Canadian
dollars)
Commodity contracts - financial1						$/mmbtu2
Natural gas	(4)	Forward gas price	1.81	5.15	3.18
Crude	11	Forward crude price	4.46	96.53	46.61	$/barrel
Power	(57)	Forward power price	21.00	70.42	53.00	$/MW/H
Commodity contracts - physical1						$/mmbtu2
Natural gas	36	Forward gas price	1.51	7.53	2.56
Crude	336	Forward crude price	7.00	76.89	28.24	$/barrel
NGL	6	Forward NGL price	0.11	1.20	0.42	$/gallon
	328

1. Financial and physical forward commodity contracts are valued using a market approach valuation technique.
2. One million British thermal units (mmbtu).

27

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. Changes in forward commodity prices could result in significantly different fair values for our Level 3 derivatives.

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,
	2020		2019
(millions of Canadian dollars)
Level 3 net derivative liability at beginning of period	(69)		(11)
Total gain/(loss)
Included in earnings1	349		(52)
Included in OCI	9		(3)
Settlements	39		(156)
Level 3 net derivative liability at end of period	328		(222)

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

There were no transfers into or out of Level 3 as at March 31, 2020 or December 31, 2019.

FAIR VALUE OF OTHER FINANCIAL INSTRUMENTS

Our other long-term investments in other entities with no actively quoted prices are classified as Fair Value Measurement Alternative (FVMA) investments and are recorded at cost less impairment. The carrying value of FVMA other long-term investments totaled $56 million and $99 million as at March 31, 2020 and December 31, 2019, respectively.

We have Restricted long-term investments held in trust totaling $443 million and $434 million as at March 31, 2020 and December 31, 2019, respectively, which are recognized at fair value.

We have a held to maturity preferred share investment carried at its amortized cost of $566 million and $580 million as at March 31, 2020 and December 31, 2019, respectively. These preferred shares are entitled to a cumulative preferred dividend based on the yield of 10-year Government of Canada bonds plus a margin of 4.38%. The fair value of this preferred share investment is $566 million and $580 million as at March 31, 2020 and December 31, 2019, respectively.

As at March 31, 2020 and December 31, 2019, our long-term debt had a carrying value of $68.1 billion and $64.4 billion, respectively, before debt issuance costs and a fair value of $65.9 billion and $70.5 billion, respectively. We also have non-current notes receivable carried at book value and recorded in Deferred amounts and other assets in the Consolidated Statements of Financial Position. As at March 31, 2020 and December 31, 2019, the non-current notes receivable had a carrying value of $1,130 million and $1,026 million, respectively, which also approximates their fair value.

The fair value of financial assets and liabilities other than derivative instruments, long-term investments, restricted long-term investments, long-term debt and non-current notes receivable described above approximate their carrying value 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.

28

During the three months ended March 31, 2020 and 2019, we recognized an unrealized foreign exchange loss of $708 million and a gain of $108 million, respectively, on the translation of United States dollar denominated debt and unrealized loss of $7 million and a gain of $1 million, respectively, on the change in fair value of our outstanding foreign exchange forward contracts in OCI. During the three months ended March 31, 2020 and 2019, we recognized realized losses of nil, in OCI associated with the settlement of foreign exchange forward contracts and recognized realized losses of nil, in OCI associated with the settlement of United States dollar denominated debt that had matured during the period.

11. INCOME TAXES

The effective income tax rates for the three months ended March 31, 2020 and 2019 were 28.7% and 22.4%, respectively. The period-over-period increase in the effective income tax rate is due to the benefit of rate-regulated accounting for income taxes being partially offset by higher United States minimum tax.

12. PENSION AND OTHER POSTRETIREMENT BENEFITS

	Three months ended
	March 31,
	2020		2019
(millions of Canadian dollars)
Service cost	42		51
Interest cost	33		51
Expected return on plan assets	(67)		(84)
Amortization of actuarial loss and prior service costs	9		7
Net periodic benefit costs	17		25

13. CONTINGENCIES

We and our subsidiaries are involved in various 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. While the final outcome of such actions and proceedings cannot be predicted with certainty, management believes that the resolution of such actions and proceedings will not have a material impact on our interim consolidated financial position or results of operations.

TAX MATTERS

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

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14. SUBSEQUENT EVENTS

On April 1, 2020, we closed the sale of our Ozark assets for proceeds of approximately $60 million (US $43 million), subject to customary closing adjustments. Refer to Note 6. Acquisitions and Dispositionsfor further discussion of the transaction.

On May 1, 2020, we closed the sale of our Montana-Alberta Tie Line assets for proceeds of approximately $180 million, subject to customary closing adjustments. Refer to Note 6. Acquisitions and Dispositionsfor further discussion of the transaction.

On May 4, 2020, a rupture occurred on Line 10, a 30-inch natural gas pipeline that makes up part of the Texas Eastern natural gas pipeline system in Fleming County, Kentucky. There have been no reported injuries or damaged structures as a result of the rupture. Texas Eastern crews are on site and have secured the area. The impacted section of pipe was shut-in following the incident and remains isolated. The National Transportation Safety Board has assumed control of the site and is working with the Pipeline and Hazardous Materials Safety Administration and Enbridge to investigate.

The spread of the COVID-19 pandemic has caused significant volatility in Canada, the United States and international markets. We continue to monitor the impact of the COVID-19 pandemic, reduced crude oil demand and reduced commodity prices on our results of operations. These demand effects coincided with decisions by various global producers, including the Organization of Petroleum Exporting Countries and other oil producing nations (OPEC+) to increase global production levels, putting severe downward pressure on prices. As a result, prices of crude oil, natural gas, natural gas liquids and other commodities whose prices are highly correlated to crude oil have decreased substantially. Given the many outstanding questions as to the length and depth of the COVID-19 pandemic and the current low commodity price environment, the impact on us is uncertain; however, it is possible that they may have an adverse impact on our business and results of operations in the future.

30

ENBRIDGE INC.

MANAGEMENT'S DISCUSSION AND ANALYSIS

March 31, 2020

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

INTRODUCTION

The following discussion and analysis of our financial condition and results of operations is based on and should be read in conjunction with our consolidated financial statements and the accompanying notes included in Part 1. Item 1. Financial Statementsof this quarterly report on Form 10-Q and our annual report on Form 10-K for the year ended December 31, 2019.

As of the end of the second quarter of 2019, we have qualified as a foreign private issuer for purposes of the U.S. Securities Exchange Act of 1934, as amended (Exchange Act). We intend to continue to file annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K with the U.S. Securities and Exchange Commission instead of filing the reporting forms available to foreign private issuers. We also intend to maintain our Form S-3 registration statements.

RECENT DEVELOPMENTS

COVID-19 PANDEMIC, REDUCED CRUDE OIL DEMAND AND COMMODITY PRICES

The COVID-19 pandemic and the resulting emergency measures enacted by governments in Canada, the United States and around the world, have caused material disruption to many businesses resulting in a severe slow down in Canadian, United States and global economies, leading to increased volatility in financial markets worldwide and demand reduction for commodities. These demand effects coincided with decisions by various global producers, including the Organization of Petroleum Exporting Countries and other oil producing nations (OPEC+), to increase global production levels, putting severe downward pressure on prices including, in some instances, negative pricing. As a result, prices of crude oil, natural gas, natural gas liquids and other commodities whose prices are highly correlated to crude oil have decreased substantially.

We are taking proactive measures to deliver energy safely and reliably during the COVID-19 pandemic. We activated our crisis management team to focus on a number of priorities, including: (i) the health and safety of our employees and the public; (ii) operational reliability for our customers and markets; (iii) identification of essential personnel and procedures; and (iv) extensive stakeholder communication and outreach including updates to our Board of Directors. We are staying closely connected to recommendations from public health authorities and medical experts and have taken steps to help prevent our employees' exposure and the spread of COVID-19, including enacting work-at-home plans across the organization and implementing business continuity plans to enable the integrity of our operations and protect the health of our employees in pipeline control functions and service centers, our field representatives and other essential functions.

The safe operation of our facilities has not been impacted. We continue to employ all safety processes and procedures in the normal course. Our business continuity plans are designed to enable us to manage operational developments related to COVID-19 as they unfold. We provide an essential service across North America. Our customers, and the communities where we operate, depend on us to safely and reliably provide the energy they need to heat their homes and fuel their lives.

The COVID-19 pandemic has had a deep impact in the communities in which we operate. We are providing support in our communities by advancing funds to respond and provide relief to those who are most vulnerable. Our teams in our operating regions are working closely with our nonprofit community partners, our closest Indigenous and Tribal neighbors, and local governments to identify where resources are needed most.

1

The COVID-19 pandemic, reduced crude oil demand and reduced commodity prices present potential new or elevated risks to our business. In late March, we began to see impacts both on the supply of, and demand for, crude oil and other liquid hydrocarbons transported on our pipelines. Several shippers on our crude oil pipelines have responded to significantly lower demand caused by the COVID-19 pandemic, declining storage availability and refinery utilization, and commodity price declines by canceling delivery of previously nominated batches for the month of April. Average volumes for April were 400 thousand barrels per day (kbpd) lower than the 2,842 kbpd average for the first quarter of 2020 and we expect that these lower volumes will likely continue through the end of the second quarter of 2020. We currently expect that volumes will recover in the second half of the year asCOVID-19related travel restrictions are slowly lifted and mobility gradually returns to North America in the third and fourth quarter of 2020. This view is supported by our expectation that the refineries operating in our core Mainline System markets (i.e. the United States Midwest, Eastern Canada and the United States Gulf Coast) may be among the first to ramp back up given their scale, complexity and cost competitiveness.For every 100 kbpd increase or decrease in volumes, our revenues, net of power savings, are expected to increase or decline by approximately $35 million per quarter.

In our US Midstream business, our equity affiliate DCP Midstream, LP, responded to the drastic decline in commodity prices by decreasing their distributions to us by 50 percent (beginning with the first quarter distribution paid in May 2020), thereby modestly reducing our cash flows. As a further outcome of the drastic commodity price decline, we recorded a $1.7 billion impairment on our equity method investment in DCP Midstream, based on the decline in the market price of DCP Midstream, LP publicly-traded units as at March 31, 2020.

In addition, these circumstances have led to the deterioration of the credit profiles of some of our customers and suppliers. We will continue to monitor this risk and take credit mitigating actions.

The situation around the COVID-19 pandemic, reduced crude oil demand and reduced commodity prices is evolving and our assessment of risks is included in Part II, Item 1A. Risk Factors.

While the length and depth of the current energy demand reduction and its impact is challenging to estimate at this time, we have initiated several actions to further strengthen our resiliency and position for the future, while assuring that the safety and reliability of our operations remains our first priority. We will be reducing operating costs by approximately $300 million, including reductions to senior management and Board of Directors compensation. We have also recently executed $0.4 billion of asset sales and increased our available liquidity to approximately $14 billion. We are experiencing a natural slowing of 2020 capital spending in light of COVID-19 and the health and safety measures put into place by federal and regional governments. After a review of capital execution schedules, we expect that 2020 capital expenditures will be approximately $1 billion lower than budgeted and will primarily shift into 2021. In addition, the following factors further demonstrate the resiliency of our low-risk business model:

• Our assets are highly contracted and commercially underpinned bylong-termtake-or-pay and cost-of-service agreements;
• Approximately 95 percent of our revenue in the first quarter of 2020 is from investment grade customers ornon-investment grade customers who have provided credit enhancements;
• The acquisition of Spectra Energy in 2017 provided us with greater diversification into natural gas with embedded low risk commercial structures. We currently have approximately 40 different sources of cash flows by geography, and by different types of contract structure;
• A strong financial position with approximately $14 billion of net available liquidity which gives us the capacity to fund all of our capital projects and any debt maturities through 2021 without accessing the capital markets; and
• We limit the maximum cash flow loss that could arise from direct market price risks through a comprehensivelong-term economic hedging program.

2

We will continue to actively monitor the developing situations and may take further actions that we determine are in the best interests of Enbridge, our employees, customers, partners and stakeholders, or as required by federal, state or provincial authorities. At this time, given the many outstanding questions as to the length and depth of the COVID-19 pandemic and the current low commodity price environment, the impact on us is uncertain; however, it is possible that they may have an adverse impact on our business and results of operations.

TEXAS EASTERN RATE CASE

On February 25, 2020, Texas Eastern Transmission, LP (Texas Eastern) received approval from the Federal Energy Regulatory Commission (FERC) of its uncontested rate case settlement with customers. In the first quarter of 2020, Texas Eastern recognized revenues from the settled rates retroactive to June 1, 2019, and put the settled rates into effect on April 1, 2020.

FINANCING UPDATE

On February 20, 2020, we raised US$750 million of two-year floating rate notes in the United States markets and on April 1, 2020, Enbridge Gas completed a $1.2 billion dual tranche offering of 10-year and 30-year notes in the Canadian debt capital markets. Through these capital market activities, we continued to make significant progress on the execution of our funding plan and strengthened our financial position.

In February 2020, we closed three new non-revolving credit facilities totaling US$1.5 billion and on March 31, 2020, we established a new syndicated one-year revolving credit facility in the amount of $1.7 billion. On April 9, 2020, we increased the amount of our new revolving facility by an additional $1.3 billion bringing the total amount to $3.0 billion, significantly enhancing our available liquidity.

The financing activities noted above, in combination with the asset monetization activities noted below, enable us to fund our current portfolio of capital projects without requiring access to the capital markets through 2021 if market access is restricted or pricing is unattractive. Refer to Liquidity and Capital Resources.

ASSET MONETIZATION

Ozark Gas Transmission and Ozark Gas Gathering

On April 1, 2020, we closed the sale of our Ozark assets for proceeds of approximately $60 million.

Éolien Maritime France SAS

On May 1, 2020, we executed agreements to sell 49% of our investment in Éolien Maritime France SAS (EMF) to the Canada Pension Plan Investment Board (CPP Investments) for initial proceeds in excess of $100 million. Post closing, CPP Investments will fund their 49% share of all ongoing future development capital. Closing of the transaction is subject to customary regulatory approvals and is expected to occur in the fourth quarter of 2020. Refer to Growth Projects - Commercially Secured Projects - Renewable Power Generationand Other Announced Projects Under Development.

Montana-Alberta Tie Line

On May 1, 2020, we closed the sale of our Montana-Alberta Tie Line transmission assets for proceeds of approximately $180 million.

3

TEXAS EASTERN PIPELINE RUPTURE

On May 4, 2020, a rupture occurred on Line 10, a 30-inch natural gas pipeline that makes up part of the Texas Eastern natural gas pipeline system in Fleming County, Kentucky. There have been no reported injuries or damaged structures as a result of the rupture. Texas Eastern crews are on site and have secured the area. The impacted section of pipe was shut-in following the incident and remains isolated. The National Transportation Safety Board has assumed control of the site and is working with the Pipeline and Hazardous Materials Safety Administration and Enbridge to investigate. The Texas Eastern natural gas pipeline system extends approximately 1,700 miles from the Gulf Coast region of Texas and Louisiana to Ohio, Pennsylvania, New Jersey and New York.

FORWARD-LOOKING INFORMATION

Forward-looking information, or forward-looking statements, have been included in this MD&A to provide information about us and our subsidiaries and affiliates, including management's assessment of our and our subsidiaries' future plans and operations. This information may not be appropriate for other purposes. Forward-looking statements are typically identified by words such as ''anticipate", "believe", "estimate", "expect", "forecast", "intend", "likely", "plan", "project", "target" and similar words suggesting future outcomes or statements regarding an outlook. Forward-looking information or statements included or incorporated by reference in this document include, but are not limited to, statements with respect to the following: our corporate vision and strategy, including strategic priorities and enablers; the COVID-19 pandemic and the duration and impact thereof; the expected supply of, demand for and prices of crude oil, natural gas, natural gas liquids, liquified natural gas and renewable energy; anticipated utilization of our existing assets; expected earnings before interest, income taxes and depreciation and amortization (EBITDA); expected earnings/(loss); expected future cash flows; expected distributable cash flow; expected debt-to-EBITDA ratio; financial strength and flexibility; expectations on sources of liquidity and sufficiency of financial resources; expected strategic priorities and performance of the Liquids Pipelines, Gas Transmission and Midstream, Gas Distribution and Storage, Renewable Power Generation and Energy Services businesses; expected costs related to announced projects and projects under construction; expected in-service dates for announced projects and projects under construction; expected capital expenditures; expected equity funding requirements for our commercially secured growth program; expected future growth and expansion opportunities; expectations about our joint venture partners' ability to complete and finance projects under construction; expected closing of acquisitions and dispositions and the timing thereof; expected benefits of transactions, including the realization of efficiencies and synergies; expected future actions of regulators and related court proceedings and other litigation; anticipated competition; United States Line 3 Replacement Program (U.S. L3R Program); Line 5 related matters; estimated future dividends; our dividend payout policy; dividend growth and dividend payout expectation; and expectations on impact of our hedging program.

4

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 and risks include the following: the COVID-19 pandemic and the duration and impact thereof; 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, including the current weakness and volatility of such prices; anticipated utilization of our existing assets; exchange rates; inflation; interest rates; availability and price of labor and construction materials; operational reliability; customer and regulatory approvals; maintenance of support and regulatory approvals for our projects; anticipated in-service dates; weather; the timing and closing of acquisitions and dispositions; the realization of anticipated benefits and synergies of transactions; governmental legislation; impact of our dividend policy on our future cash flows; our credit ratings; capital project funding; expected EBITDA; expected earnings/(loss); expected future cash flows; expected distributable cash flow; 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 expected EBITDA, expected earnings/(loss), expected future cash flows, expected distributable cash flow 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; and the COVID-19 pandemic and the duration and impact thereof.

Our forward-looking statements are subject to risks and uncertainties pertaining to the successful execution of our strategic priorities, operating performance, regulatory parameters, changes in regulations applicable to our business, acquisitions, dispositions and other transactions, our dividend policy, project approval and support, renewals of rights- of-way, weather, economic and competitive conditions, public opinion, changes in tax laws and tax rates, changes in trade agreements, exchange rates, interest rates, commodity prices, political decisions, supply of and demand for commodities, and the COVID-19 pandemic and the duration and impact thereof, including but not limited to those risks and uncertainties discussed in this 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 statement made in this MD&A or otherwise, whether as a result of new information, future events or otherwise. All forward-looking statements, whether written or oral, attributable to us or persons acting on our behalf, are expressly qualified in their entirety by these cautionary statements.

5

RESULTS OF OPERATIONS

	Three months ended
	March 31,
	2020		2019
(millions of Canadian dollars, except per share amounts)
Segment earnings/(loss) before interest, income taxes and depreciation
and amortization
Liquids Pipelines	850		2,072
Gas Transmission and Midstream	(1,054)		1,020
Gas Distribution and Storage	604		662
Renewable Power Generation	120		124
Energy Services	121		6
Eliminations and Other	(966)		248
Depreciation and amortization	(882)		(840)
Interest expense	(706)		(685)
Income tax recovery/(expense)	549		(584)
(Earnings)/loss attributable to noncontrolling interests	31		(37)
Preference share dividends	(96)		(95)
Earnings/(loss) attributable to common shareholders	(1,429)		1,891
Earnings/(loss) per common share attributable to common shareholders	(0.71)		0.94
Diluted earnings/(loss) per common share attributable to common	(0.71)		0.94
shareholders

EARNINGS/(LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS

Three months ended March 31, 2020, compared with the three months ended March 31, 2019

Earnings/(loss) attributable to common shareholders were net negatively impacted by $3,348 million due to certain unusual, infrequent or other non-operating factors, primarily explained by the following:

• a combined loss of $2,060 million ($1,550 millionafter-tax) related to our equity method investment in DCP Midstream due to a loss of $1,736 million ($1,306 million after-tax) resulting from an impairment to the carrying value of our investment and a loss of $324 million ($244 million after-tax) resulting from further asset and goodwill impairment losses, refer to Item 1. Financial Statements - Note 9. Impairment of Equity Investments;
• anon-cash, unrealized derivative fair value loss of $1,956 million ($1,461 million after-tax) in 2020, compared with a gain of $600 million ($443 million after-tax) in 2019, 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 risks;
• anon-cash,write-down of crude oil and natural gas inventories to the lower of cost or market in our Energy Services business segment of $417 million ($311 million after-tax) in 2020, compared with $10 million ($8 million after-tax) in 2019; and
• a loss of $159 million ($119 millionafter-tax) in 2020 resulting from the recent Texas Eastern rate case settlement that re-established the Excess Accumulated Deferred Income Tax (EDIT) regulated liability that was previously eliminated in December 2018.

The negative factors above were partially offset by a non-cash, unrealized gain of $551 million ($412 million after-tax) in 2020, compared with a loss of $160 million ($118 million after-tax) in 2019, reflecting the revaluation of derivatives used to manage the profitability of transportation and storage transactions, as well as manage the exposure to movements in commodity prices.

6

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

After taking into consideration the factors above, the remaining $28 million increase in earnings/(loss) attributable to common shareholders is primarily explained by the following significant business factors:

• stronger contributions from our Liquids Pipelines segment due to a higher International Joint Tariff (IJT) Benchmark Toll and higher Mainline Systemex-Gretna throughput driven by an increase in supply and continuous capacity optimization;
• increased earnings from our Gas Transmission and Midstream segment due to settled rates on Texas Eastern, retroactive to June 1, 2019, resulting from the recent rate case settlement;
• increased earnings from new Liquids Pipelines and Gas Transmission and Midstream assets that were placed into service throughout 2019; and
• decreased income tax expense due to decreased earnings and the effects ofrate-regulated accounting, partially offset by a change in the United States minimum tax.

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

• decreased earnings from our Energy Services segment due to the significant compression of location and quality differentials in certain markets and fewer opportunities to achieve profitable transportation margins on facilities which hold capacity obligations;
• decreased earnings from our Gas Distribution and Storage segment due to warmer weather experienced in our franchise areas;
• the absence of earnings in 2020 from thefederally-regulated portion of our Canadian natural gas gathering and processing businesses which were sold on December 31, 2019; and
• higher depreciation and amortization expense as a result of new assets placed into service throughout 2019.

BUSINESS SEGMENTS

LIQUIDS PIPELINES

Three months ended

March 31,

2020 2019

(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization	850	2,072

Three months ended March 31, 2020, compared with the three months ended March 31, 2019

EBITDA was negatively impacted by $1,412 million due to certain unusual, infrequent or other non- operating factors, primarily explained by a non-cash, unrealized loss of $1,066 million in 2020, compared with a gain of $343 million in 2019, 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 risks.

After taking into consideration the factor above, the remaining $190 million increase is primarily explained by the following significant business factors:

• a higher IJT Benchmark Toll on our Mainline System of US$4.21 in 2020 compared with US$4.15 in 2019;
• higher Mainline Systemex-Gretna throughput of 2,842 kbpd in 2020 compared with 2,717 kbpd in 2019 driven by an increase in supply and continuous capacity optimization;

7

• contributions from the Canadian Line 3 Replacement (L3R) Program that was placed into service on December 1, 2019 with an interim surcharge on Mainline System volumes of US$0.20 per barrel for the IJT Benchmark Toll; and
• higher Flanagan South Pipeline and Spearhead Pipeline throughputperiod-over-period driven by the redirection of throughput to the Gulf Coast resulting from refinery outages in the United States Midwest.

GAS TRANSMISSION AND MIDSTREAM

Three months ended

March 31,

2020 2019

(millions of Canadian dollars)
Earnings/(loss) before interest, income taxes and depreciation and amortization	(1,054)	1,020

Three months ended March 31, 2020, compared with the three months ended March 31, 2019

EBITDA was negatively impacted by $2,131 million due to certain unusual, infrequent or other non- operating factors, primarily explained by the following:

• a loss of $1,736 million in 2020 resulting from an impairment to the carrying value of our equity method investment in DCP Midstream related to a decline in the market price of DCP Midstream, LP'spublicly-traded units;
• a loss of $324 million in 2020 resulting from further asset and goodwill impairment losses at our equity method investee, DCP Midstream; and
• a loss of $159 million in 2020 resulting from the recent Texas Eastern rate case settlement thatre-established the EDIT regulated liability that was previously eliminated in December 2018.

The negative factors above were partially offset by a non-cash, positive equity earnings adjustment of $53 million in 2020 compared with a negative adjustment of $14 million in 2019 related to changes in the mark-to-market value of derivative financial instruments of our equity method investee, DCP Midstream.

After taking into consideration the factors above, the remaining $57 million increase is primarily explained by the following significant business factors:

• higher revenues from settled rates on Texas Eastern, retroactive to June 1, 2019, resulting from the recent rate case settlement; and
• contributions from the Stratton Ridge project and the second phase of the Atlantic Bridge project that were placed into service in the second and fourth quarters of 2019, respectively.

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

• the absence of earnings in 2020 from thefederally-regulated portion of our Canadian natural gas gathering and processing businesses which were sold on December 31, 2019;
• higher operating costs on our US Gas Transmission assets primarily due to higher pipeline integrity costs; and
• narrowing of theAECO-Chicago basis at our Alliance Pipeline joint venture.

8

GAS DISTRIBUTION AND STORAGE

Three months ended

March 31,

2020 2019

(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization	604	662

Three months ended March 31, 2020, compared with the three months ended March 31, 2019

EBITDA was positively impacted by $26 million due to certain unusual, infrequent and other non- operating factors, primarily explained by employee severance and transition costs of $7 million in 2020 compared with $35 million in 2019 related to the amalgamation of Enbridge Gas Distribution Inc. (EGD) and Union Gas Limited (Union Gas).

After taking into consideration the factor above, the remaining $84 million decrease is primarily explained by the following significant business factors:

• warmer weather experienced in our franchise service areas in 2020 when compared with the colder than normal weather experienced in 2019. When compared with the normal weather forecast embedded in rates, the warmer weather in 2020 negatively impacted 2020 EBITDA by approximately $41 million while the colder weather in 2019 positively impacted 2019 EBITDA by approximately $33 million; and
• the absence of earnings in 2020 from Enbridge Gas New Brunswick and St. Lawrence Gas Company, Inc. which were sold on October 1, 2019 and November 1, 2019, respectively.

The negative business factors above were partially offset by higher distribution charges resulting from increases in customer base, as well as synergy captures realized from the amalgamation of EGD and Union Gas.

RENEWABLE POWER GENERATION

Three months ended

March 31,

2020 2019

(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization	120	124

Three months ended March 31, 2020, compared with the three months ended March 31, 2019

EBITDA decreased by $4 million primarily due to lower wind resources at Canadian wind facilities. This negative business factor was partially offset by contributions from the Hohe See Offshore Wind Project, which reached full operating capacity in October 2019 and the expansion, which was placed into service in January 2020.

ENERGY SERVICES

Three months ended

March 31,

2020 2019

(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization	121	6

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.

9

Three months ended March 31, 2020, compared with the three months ended March 31, 2019

EBITDA was net positively impacted by $304 million due to certain unusual, infrequent or other non- operating factors, primarily explained by a non-cash, unrealized gain of $551 million in 2020, compared with a loss of $160 million in 2019, reflecting the revaluation of derivatives used to manage the profitability of transportation and storage transactions, as well as manage the exposure to movements in commodity prices. This positive factor was offset by a non-cash,write-down of crude oil and natural gas inventories to the lower of cost or market of $417 million in 2020 compared with $10 million in 2019.

After taking into consideration the factors above, the remaining $189 million decrease reflects the significant compression of location and quality differentials in certain markets and fewer opportunities to achieve profitable transportation margins on facilities which Energy Services holds capacity obligations. The first quarter of 2019 was exceptionally strong, benefiting from favorable location and quality differentials, which increased opportunities to realize profitable margins.

ELIMINATIONS AND OTHER

Three months ended

March 31,

2020 2019

(millions of Canadian dollars)
Earnings/(loss) before interest, income taxes and depreciation and amortization	(966)	248

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

Three months ended March 31, 2020, compared with the three months ended March 31, 2019

EBITDA was negatively impacted by $1,239 million due to certain unusual, infrequent and other non- operating factors, primarily explained by the following:

• anon-cash, unrealized loss of $898 million in 2020, compared with a gain of $252 million in 2019, reflecting net fair value gains and losses arising from the change in the mark-to-market value of derivative financial instruments used to manage foreign exchange risk;
• a loss of $74 million in 2020 fromnon-cash changes in a corporate guarantee obligation; and
• a loss of $43 million in 2020 from thewrite-down of certain minor investments in emerging energy and other technologies.

After taking into consideration the factors above, the remaining $25 million increase is primarily explained by lower operating and administrative costs in 2020 and the timing of the recovery of certain operating administrative costs allocated to the business segments.

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GROWTH PROJECTS - COMMERCIALLY SECURED PROJECTS

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

		Enbridge's	Estimated	Expenditures		Expected
		Ownership	Capital		In-Service
		Interest	Cost1	to Date2	Status	Date
(Canadian dollars, unless stated otherwise)
LIQUIDS PIPELINES
1.	United States Line 3	100%	US$2.9 billion	US$1.4 billion	Pre-	Under
	Replacement Program				construction	review3
2.	Southern Access	100%	US$0.5 billion	US$0.5 billion	Under	Under
	Expansion				construction	review4
3.	Other - United States	100%	US$0.1 billion	No significant	Under	1H - 2021
				expenditures	construction
				to date
GAS TRANSMISSION AND MIDSTREAM
4.	T-South Reliability &	100%	$1.0 billion	$0.5 billion	Under	2H - 2021
	Expansion Program				construction
5.	Spruce Ridge Project	100%	$0.5 billion	$0.2 billion	Pre- 2H - 2021
					construction
6.	Other - United States5	Various	US$1.0 billion	US$0.4 billion	Various	2020 - 2023
					stages
GAS DISTRIBUTION AND STORAGE
7.	System Modernization -	100%	$0.2 billion	No significant	Pre- Q4 - 2020
	Windsor & Owen			expenditures	construction
	Sound			to date
8.	Dawn-Parkway	100%	$0.2 billion	No significant	Pre- 2H - 2021
	Expansion			expenditures	construction
				to date
RENEWABLE POWER GENERATION
9.	East-West Tie Line	25%	$0.2 billion	No significant	Under	2H - 2021
				expenditures	construction
				to date
10.	Saint-Nazaire France	25.5%	$0.9 billion	$0.1 billion	Under	2H - 2022
	Offshore Wind Project6		(€0.6 billion)	(€0.1 billion)	construction

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, 2020.

3 Update to in-service date pending receipt of all permits required to complete construction.

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

5 Includes the US$0.1 billion Sabal Trail Phase II project placed into service on May 1, 2020.

6 Reflects the sale of 49% of our investment in EMF to CPP Investments expected to close in the fourth quarter of 2020. After closing, our equity contribution will be $0.15 billion, with the remainder of the project financed through non-recourse project level debt.

A full description of each of our projects is provided in our annual report on Form 10-K. Significant updates that have occurred since the date of filing are discussed below.

GAS TRANSMISSION AND MIDSTREAM

• Sabal Trail Phase II -an expansion of our existing Sabal Trail pipeline through the addition of two new greenfield compressor stations in Albany, Georgia and Dunnellon, Florida. The expansion received FERC approval in April 2020 and was placed into service on May 1, 2020.

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RENEWABLE POWER GENERATION

• Saint-NazaireFrance Offshore Wind Project -on May 1, 2020, we executed agreements to sell 49% of our investment in EMF to CPP Investments, inclusive of the Saint-Nazaire France Offshore Wind Project. Post closing, CPP Investments will fund their 49% share of all ongoing future development capital. Closing of the transaction is subject to customary regulatory approvals and is expected to occur in the fourth quarter of 2020.

GROWTH PROJECTS - REGULATORY MATTERS

United States Line 3 Replacement Program

On February 3, 2020, the Minnesota Public Utilities Commission approved the adequacy of the revised Final Environmental Impact Statement and reinstated the Certificate of Need and Route Permit, allowing for construction of the pipeline to commence following the issuance of required permits.

As for environmental permits, the Minnesota Pollution Control Agency (MPCA) released a draft of the revised 401 Water Quality Certification in February 2020, and the public comment period closed on April 10, 2020. According to the MPCA permitting schedule, the next critical phase is focused on the MPCA reviewing and considering public comments before making a certification decision.

At this time, we cannot determine when all necessary permits to commence construction will be issued. Depending on the final in-service date, there is a risk that the project may exceed our total cost estimate of $9 billion for the combined L3R Program. However, at this time, we do not anticipate any capital cost impacts that would be material to our financial position and outlook.

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:

RENEWABLE POWER GENERATION

• Éolien Maritime France SAS -on May 1, 2020, we executed agreements to sell 49% of our investment in EMF to CPP Investments. Post closing, CPP Investments will fund their 49% share of all ongoing future development capital. Closing of the transaction is subject to customary regulatory approvals and is expected to occur in the fourth quarter of 2020. After the transaction closes, through our investment in EMF, we will own equity interests in three French offshore wind projects, including Saint-Nazaire (25.5%), Fecamp (17.9%), and Courseulles (21.7%). In 2019, the Saint-Nazaire France Offshore Wind Project reached a positive final investment decision and the remaining two projects are expected to reach a final investment decision by next year.

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

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LIQUIDITY AND CAPITAL RESOURCES

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

Our financing plan is regularly updated to reflect evolving capital requirements and financial market conditions and identifies a variety of potential sources of debt and equity funding alternatives. Our current financing plan does not include any issuances of additional common equity and was the primary consideration for the suspension of our Dividend Reinvestment and Share Purchase Plan in November 2018.

As discussed within Recent Developments - Financing Update, as a result of the COVID-19 pandemic and the corresponding impact on the capital markets, we have elected to increase our liquidity through additional credit facilities to ensure we will not have to access the capital markets through 2021 to fund our current portfolio of capital projects if market access is restricted or pricing is unattractive.

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, 2020:

	Maturity	Total	Draws1	Available
	Dates	Facilities
(millions of Canadian dollars)
Enbridge Inc.	2021-2024	10,959	6,250	4,709
Enbridge (U.S.) Inc.	2021-2024	7,829	2,162	5,667
Enbridge Pipelines Inc.	20212	3,000	2,155	845
Enbridge Gas Inc.	20212	2,000	835	1,165
Total committed credit facilities		23,788	11,402	12,386

1. Includes facility draws and commercial paper issuances that areback-stopped by credit facility.
2. Maturity date is inclusive of the one year term out option.

On February 24, 2020, Enbridge Inc. entered into a two year, non-revolving credit facility for US$1 billion with a syndicate of lenders.

On February 25, 2020, Enbridge Inc. entered into two, one year, non-revolving, bilateral credit facilities for a total of US$500 million.

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On March 31, 2020, Enbridge Inc. entered into a one year, revolving, syndicated credit facility for $1.7 billion. On April 9, 2020, Enbridge Inc. exercised an accordion provision and increased the facility to $3.0 billion.

In addition to the committed credit facilities noted above, we maintain $806 million of uncommitted demand credit facilities, of which $523 million were unutilized as at March 31, 2020. As at December 31, 2019, we had $916 million of uncommitted credit facilities, of which $476 million were unutilized.

Our net available liquidity of $13,185 million as at March 31, 2020, was inclusive of $799 million of unrestricted cash and cash equivalents as reported in the Consolidated Statements of Financial Position.

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, 2020, we were in compliance with all debt covenants and we expect to continue to comply with such covenants.

LONG-TERM DEBT ISSUANCES

During the three months ended March 31, 2020, we completed the following long-term debt issuances:

Company Issue Date	Principal
Amount
(millions of Canadian dollars)
Enbridge Inc.
February 2020 Floating rate notes	US$750

On April 1, 2020, Enbridge Gas Inc. (Enbridge Gas) issued $600 million of 2.90% 10-yearmedium-term notes and $600 million of 3.65% 30-year medium term notes payable semi-annually in arrears. The notes mature on April 1, 2030 and April 1, 2050, respectively.

LONG-TERM DEBT REPAYMENTS

During the three months ended March 31, 2020, we completed the following long-term debt repayments:

Company Repayment Date		Principal
	Amount
(millions of Canadian dollars, unless otherwise stated)
Enbridge Inc.
January 2020	Floating rate notes	US$700
March 2020	4.53% medium-term notes	$500
Spectra Energy Partners, LP
January 2020	6.09% senior secured notes	US$111
Westcoast Energy Inc.
January 2020	9.90% debentures	$100

Strong internal cash flow, proceeds from non-core asset dispositions, ready access to liquidity from diversified sources and a stable business model have enabled us to manage 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 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 EBITDA.

There are no material restrictions on our cash. Total restricted cash of $41 million, as reported on the Consolidated Statements of Financial Position, primarily includes cash collateral and amounts received in respect of specific shipper commitments. Cash and cash equivalents held by certain subsidiaries may not be readily accessible for alternative uses by us.

14

Excluding current maturities of long-term debt, we had a negative working capital position as at March 31, 2020. 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.

SOURCES AND USES OF CASH

	Three months ended
	March 31,
	2020	2019
(millions of Canadian dollars)
Operating activities	2,809	2,176
Investing activities	(1,270)	(2,148)
Financing activities	(1,386)	99
Effect of translation of foreign denominated cash and cash equivalents and	11	(7)
restricted cash
Increase in cash and cash equivalents and restricted cash	164	120

Significant sources and uses of cash for the three months ended March 31, 2020 and March 31, 2019 are summarized below:

Operating Activities

• The increase in cash provided by operating activities was primarily attributable to changes in operating assets and liabilities. Our operating assets and liabilities fluctuate in the normal course due to various factors, including the impact of fluctuations in commodity prices and activity levels on working capital within our business segments, the timing of tax payments, as well as timing of cash receipts and payments generally.
• The factor above was partially offset by the impact of certain unusual, infrequent or other non- operating factors as discussed underResults of Operations.

Investing Activities

• The decrease in cash used in investing activities was primarily attributable to lower contributions to the Gray Oak Holdings LLC equity investment in 2020 when compared with the corresponding period in 2019.
• We are continuing with the execution of our growth capital program which is further described inGrowth Projects - Commercially Secured Projects. The timing of project approval, construction and in-service dates impacts the timing of cash requirements.

Financing Activities

• The increase in cash used in financing activities was primarily attributable to a decrease in commercial paper and credit facility draws and issuances oflong-term debt in 2020 when compared with the corresponding period in 2019.
• The factor above was partially offset by the absence of Westcoast Energy Inc.'s redemption of all of its outstanding Series 7 and Series 8 preference shares in 2020 when compared with the corresponding period in 2019.
• Our common share dividend payments increasedperiod-over-period primarily due to the increase in our common share dividend rate.

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SUMMARIZED FINANCIAL INFORMATION

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

Consenting SEP notes and EEP notes under Guarantee

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

1. As at March 31, 2020, the aggregate outstanding principal amount of SEP notes was approximately US$3.9 billion.
2. As at March 31, 2020, the aggregate outstanding principal amount of EEP notes was approximately US$3.0 billion.

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Enbridge Notes under Guarantees
USD Denominated1	CAD Denominated2
Senior Floating Rate Notes due 2020	4.850% Senior Notes due 2020
Floating Rate Note due 2022	4.260% Senior Notes due 2021
2.900% Senior Notes due 2022	3.160% Senior Notes due 2021
4.000% Senior Notes due 2023	4.850% Senior Notes due 2022
3.500% Senior Notes due 2024	3.190% Senior Notes due 2022
2.500% Senior Notes due 2025	3.940% Senior Notes due 2023
4.250% Senior Notes due 2026	3.940% Senior Notes due 2023
3.700% Senior Notes due 2027	3.950% Senior Notes due 2024
3.125% Senior Notes due 2029	3.200% Senior Notes due 2027
4.500% Senior Notes due 2044	6.100% Senior Notes due 2028
5.500% Senior Notes due 2046	2.990% Senior Notes due 2029
4.000% Senior Notes due 2049	7.220% Senior Notes due 2030
	7.200% Senior Notes due 2032
	5.570% Senior Notes due 2035
	5.750% Senior Notes due 2039
	5.120% Senior Notes due 2040
	4.240% Senior Notes due 2042
	4.570% Senior Notes due 2044
	4.870% Senior Notes due 2044
	4.560% Senior Notes due 2064

1. As at March 31, 2020, the aggregate outstanding principal amount of the Enbridge United States dollar denominated notes was approximately US$8.0 billion.
2. As at March 31, 2020, the aggregate outstanding principal amount of the Enbridge Canadian dollar denominated notes was approximately $7.1 billion.

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

1. Enbridge Inc., the Parent Issuer and Guarantor;
2. SEP, a Subsidiary Issuer and Guarantor, and
3. EEP, a Subsidiary Issuer and Guarantor

We have provided summarized financial information for each of the Guarantors in line with the requirements of Rule 13-01, which requires that Guarantors with investment balances in Subsidiary Non- Guarantors be excluded and transactions and amounts with Non-Guarantors and other related parties be presented separately.

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Summarized Financial Information as at and for the three months ended March 31, 2020

	Parent Issuer and	Subsidiary Issuer and	Subsidiary Issuer and
	Guarantor	Guarantor - SEP	Guarantor - EEP
(millions of Canadian dollars)
Operating revenues	-	-	-
Operating income/(loss)	56	-	(1)
Earnings/(loss)	(1,195)	(27)	121
Earnings/(loss) attributable to common	(1,291)	(27)	121
shareholders
	Parent Issuer and	Subsidiary Issuer and	Subsidiary Issuer and
	Guarantor	Guarantor - SEP	Guarantor - EEP
(millions of Canadian dollars)
Accounts receivable from affiliates	1,065	-	35
Short-term loans receivable from affiliates	907	-	4,674
Other current assets	207	16	25
Long-term loans receivable from affiliates	47,939	73	2,095
Other long-term assets	5,027	1,012	-
Accounts payable to affiliates	808	698	-
Short-term loans payable to affiliates	367	1,992	2,112
Other current liabilities	4,289	679	81
Long-term loans payable to affiliates	33,610	-	3,416
Other long-term liabilities	32,225	5,160	4,172

Summarized Financial Information as at December 31, 2019

	Parent Issuer and	Subsidiary Issuer and	Subsidiary Issuer and
	Guarantor	Guarantor - SEP	Guarantor - EEP
(millions of Canadian dollars)	729
Accounts receivable from affiliates	-	12
Short-term loans receivable from affiliates	1,691	-	3,961
Other current assets	438	41	8
Long-term loans receivable from affiliates	47,285	73	2,387
Other long-term assets	3,681	933	1
Accounts payable to affiliates	736	367	68
Short-term loans payable to affiliates	367	2,058	1,991
Other current liabilities	5,204	598	52
Long-term loans payable to affiliates	33,686	-	3,112
Other long-term liabilities	28,585	4,708	3,801

The Guaranteed Enbridge Notes and the Guaranteed Partnership Notes are structurally subordinated to the indebtedness of the Subsidiary Non-Guarantors in respect of the assets of those Subsidiary Non- Guarantors.

Under United States bankruptcy law and comparable provisions of state fraudulent transfer laws, a guarantee can be voided, or claims may be subordinated to all other debts of that guarantor if, among other things, the guarantor, at the time the indebtedness evidenced by its guarantee or, in some states, when payments become due under the guarantee:

• received less than reasonably equivalent value or fair consideration for the incurrence of the guarantee and was insolvent or rendered insolvent by reason of such incurrence;
• was engaged in a business or transaction for which the guarantor's remaining assets constituted unreasonably small capital; or

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• intended to incur, or believed that it would incur, debts beyond its ability to pay those debts as they mature.

The guarantees of the Guaranteed Enbridge Notes contain provisions to limit the maximum amount of liability that the Partnerships could incur without causing the incurrence of obligations under the guarantee to be a fraudulent conveyance or fraudulent transfer under United States federal or state law.

Each of the Partnerships is entitled to a right of contribution from the other Partnership for 50% of all payments, damages and expenses incurred by that Partnership in discharging its obligations under the guarantees for the Guaranteed Enbridge Notes.

Under the terms of the guarantee agreement and applicable supplemental indentures, the guarantees of either of the Partnerships of any Guaranteed Enbridge Notes will be unconditionally released and discharged automatically upon the occurrence of any of the following events:

• any direct or indirect sale, exchange or transfer, whether by way of merger, sale or transfer of equity interests or otherwise, to any person that is not an affiliate of Enbridge, of any of Enbridge's direct or indirect limited partnership of other equity interests in that Partnership as a result of which the Partnership ceases to be a consolidated subsidiary of Enbridge;
• the merger of that Partnership into Enbridge or the other Partnership or the liquidation and dissolution of that Partnership;
• the repayment in full or discharge or defeasance of those Guaranteed Enbridge Notes, as contemplated by the applicable indenture or guarantee agreement
• with respect to EEP, the repayment in full or discharge or defeasance of each of the consenting EEP notes listed above;
• with respect to SEP, the repayment in full or discharge or defeasance of each of the consenting SEP notes listed above; or
• with respect to any series of Guaranteed Enbridge Notes, with the consent of holders of at least a majority of the outstanding principal amount of that series of Guaranteed Enbridge Notes.

The guarantee obligations of Enbridge of the Guaranteed Partnership Notes will terminate with respect to any series of Guaranteed Partnership Notes if that series is discharged or defeased.

LEGAL AND OTHER UPDATES

LIQUIDS PIPELINES

Dakota Access Pipeline

In August 2018, the United States Army Corps of Engineers (Army Corps) completed the environmental analysis required on remand by the June 2017 order of the United States Court for the District of Columbia and reaffirmed the issuance of the permit for the Dakota Access Pipeline. All four plaintiff Tribes subsequently amended their complaints to include claims challenging the adequacy of the Army Corps' August 2018 decision, and the parties filed cross-motions for summary judgment on the merits of the plaintiffs' amended claims. Briefing on the parties' cross-motions for summary judgment was completed on November 25, 2019. On March 25, 2020, the Court issued an opinion, granting and denying in part the parties' cross-motions for summary judgment. The Court ordered the Army Corps to prepare an Environmental Impact Statement to address unresolved controversy pertaining to potential spill impacts resulting from the Dakota Access Pipeline. The Court deferred a decision on remedy, ordering the parties to conduct further briefing, scheduled to be complete by May 27, 2020, on whether the Army Corps' permit for the Dakota Access Pipeline should be vacated during the remand process. The Court will issue a decision on remedy thereafter.

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Line 5 Dual Pipelines

On June 6, 2019, we filed a complaint with the Michigan Court of Claims to establish the constitutional validity of Michigan law PA 359 and enforceability of various agreements entered into between us and the State of Michigan related to the construction of the Line 5 Dual Pipelines Tunnel Project (Tunnel Project). On October 31, 2019, the Court determined that Michigan law PA 359 is valid and is not unconstitutional. On November 5, 2019, the Michigan Attorney General filed an appeal with the Michigan Court of Appeals and briefing for that appeal is now complete. A decision by the Michigan Court of Appeals is expected later in 2020. Both the Michigan Court of Claims and the Michigan Court of Appeals denied the Michigan Attorney General's motion for a stay pending an appeal.

On June 27, 2019, the Michigan Attorney General filed a complaint in the Michigan Ingham County Circuit Court that requests the Court to declare the easement that we have for the operation of the dual pipelines in the Straits of Mackinac (the Straits) to be invalid and to prohibit continued operation of the dual pipelines in the Straits "as soon as possible after a reasonable notice period to allow orderly adjustments by affected parties". On September 16, 2019, we filed our motion for summary disposition and requested dismissal of the State's Complaint in its entirety. On that same date, the State filed a motion for partial summary disposition and judgment in its favor on its claim that the easement was void from inception. The case is fully briefed and oral argument on the parties' motions remains scheduled for May 22, 2020.

On March 6, 2020, the Mackinac Straits Corridor Authority (Corridor Authority) held its first meeting since December 2018. At the meeting the Corridor Authority reviewed the actions that we have taken in accordance with the Tunnel Project agreement, and on formal motions approved those actions.

During the first quarter of 2020, we filed all major environmental permits, including the joint permit application with the Michigan Department of Environment, Great Lakes and Energy and the Army Corps, as well as an independent application to the Michigan Public Service Commission.

Upon receipt of all required permits, we expect to begin construction of the Tunnel Project, with the expected completion of construction, testing and commissioning sometime in 2024.

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. While the final outcome of such actions and proceedings cannot be predicted with certainty, management believes that the resolution of such actions and proceedings will not have a material impact on our consolidated financial position or results of operations.

CAPITAL EXPENDITURE COMMITMENTS

We have signed contracts for the purchase of services, pipe and other materials totaling approximately $2.3 billion which are expected to be paid over the next five years.

TAX MATTERS

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

CHANGES IN ACCOUNTING POLICIES

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

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