UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
xFORM10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 20182022
OR
o

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from            to           
Commission file number 1-10934
enb-20220331_g1.jpg
ENBRIDGE INC.
(Exact Name of Registrant as Specified in Its Charter)
CanadaNone98-0377957
(State or Other Jurisdiction of
Incorporation or Organization)
(I.R.S. Employer
Identification No.)
200, 425 - 1st Street S.W.
Calgary, Alberta, CanadaT2P 3L8
(Address of Principal Executive Offices) (Zip Code)
(403) (403) 231-3900
(Registrant’s Telephone Number, Including Area Code)

Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading Symbol(s)Name of each exchange on which registered
Common SharesENBNew York Stock Exchange
6.375% Fixed-to-Floating Rate Subordinated Notes Series 2018-B due 2078ENBANew York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yesx Noo
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yesx Noo
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer
x
Accelerated filer
Accelerated filer o
Non-accelerated filero (Do not check if a smaller reporting company)
Smaller reporting companyo
Emerging growth companyo
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). YesoNox
The registrant had 1,704,740,1772,026,382,505 common shares outstanding as of May 4, 2018.
at April 29, 2022.


1


1


Page
PART IPage
PART I
Item 1.
Item 2.
Item 3.
Item 4.
PART II
Item 1.
Item 1A.
Item 2.
Item 3.
Item 4.
Item 5.
Item 6.




2




GLOSSARY
 
AOCIAccumulated other comprehensive income/(loss)loss
ALJAdministrative Law Judge
ASU
ASUAccounting Standards Update
Canadian L3R ProgramCanadian portion of the Line 3 Replacement Program
CIACsContributions in Aid of Construction
EBITDA
EBITDAEarnings before interest, income taxes and depreciation and amortization
Eddystone RailEddystone Rail Company, LLC
EEPEnbridge Energy Partners, L.P.
EGDEnbridge Gas Distribution Inc.
EnbridgeEnbridge Inc.
FERCFederal Energy Regulatory Commission
IDRsIncentive distribution rights
Line 10EnbridgeLine 10 crude oil pipelineEnbridge Inc.
MNPUCMinnesota Public Utilities Commission
NGL
Exchange ActUnited States Securities Exchange Act of 1934, as amended
L3RLine 3 Replacement
LNGLiquified natural gas
NGLNatural gas liquids
OCI
OCIOther comprehensive income/(loss)
Route PermitUnited States Line 3 Replacement Program route permit
Sabal TrailOEBSabal Trail Transmission, LLCOntario Energy Board
SEPOPEBOther postretirement benefits
SEPSpectra Energy Partners, LP
TCJATax Cuts and Jobs Act
Texas Express NGL pipeline systemTexas Express PL LLC and Texas Express Gathering LLC
Texas EasternTexas Eastern Transmission, LP
the Merger TransactionPartnershipsThe stock-for-stock merger transaction on February 27, 2017 between Enbridge and
Spectra Energy CorpPartners, LP (SEP) and Enbridge Energy Partners, L.P. (EEP)

USUnited States of America
US$Unites States dollars


3




CONVENTIONS


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


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


FORWARD-LOOKING INFORMATION

Forward-looking information, or forward-looking statements, have been included in this quarterly report on Form 10-Q to provide information about us and our subsidiaries and affiliates, including management’s assessment of Enbridgeour and itsour 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; energy intensity and emissions reduction targets and related environmental, social and governance matters; expected supply of, demand for and prices of crude oil, natural gas, natural gas liquids (NGL), liquified natural gas (LNG) and renewable energy; energy transition; expected earnings before interest, income taxes and depreciation and amortization (EBITDA); expected earnings/(loss); expected earnings/(loss) per share; expected future cash flows; expected performance of the Liquids Pipelines, Gas Transmissionflows and Midstream, Gas Distribution, Green Powerdistributable cash flow; dividend growth and Transmission, and Energy Services businesses;payout policy; 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 and benefits related to announced projects and projects under construction; expected in-service dates for announced projects and projects under construction;construction and for maintenance; expected capital expenditures;expenditures, expected equity funding requirements for our commercially secured growth program; expected future growth and expansion opportunities;expectations about our joint venture partners’ ability to complete and finance projects under construction; expected closing of acquisitions and dispositions;estimated future dividends; recovery of the costs of the Canadian portion of the Line 3 Replacement Program (Canadian L3R Program); expected future actions of regulators; expected costs relatedregulators and courts; and toll and rate cases discussions and filings, including those relating to leak remediationGas Transmission and potential insurance recoveries; expectations regarding commodity prices; supply forecasts; expectations regarding the impact of the stock-for-stock merger transaction on February 27, 2017 between EnbridgeMidstream and Spectra Energy Corp (the Merger Transaction) including our combined scale, financial flexibility, growth program, future business prospectsGas Distribution and performance; impact of the Canadian L3R Program on existing integrity programs; the sponsored vehicle strategy; dividend payout policy; dividend growth and dividend payout expectation; expectations on impact of hedging program; and expectations resulting from the successful execution of our 2018-2020 Strategic Plan.Storage.


Although we believe these forward-looking statements are reasonable based on the information available on the date such statements are made and processes used to prepare the information, such statements are not guarantees of future performance and readers are cautioned against placing undue reliance on forward-looking statements. By their nature, these statements involve a variety of assumptions, known and unknown risks and uncertainties and other factors, which may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Material assumptions include assumptions about the following: the COVID-19 pandemic and the duration and impact thereof; the expected supply of and demand for crude oil, natural gas, natural gas liquids (NGL)NGL and renewable energy; prices of crude oil, natural gas, NGL and renewable energy; energy transition; anticipated utilization of 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 the Merger Transaction;transactions; governmental legislation; acquisitionslitigation; estimated future dividends and the timing thereof; the success of integration plans;impact of theour dividend policy on our future cash flows; our credit ratings; capital project funding; hedging program; expected EBITDA; expected earnings/(loss); expected earnings/(loss) per share; expected future cash flowsflows; and estimated future dividends.expected distributable cash flow. 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 and the COVID-19 pandemic impact the economies and business environments in which we operate and may impact levels of demand for our services and cost of inputs, and are therefore inherent in all forward-looking statements. Due to the interdependencies and correlation of these macroeconomic factors, the impact of any one assumption on a forward-looking statement cannot be determined with certainty,particularly with respect to the impact of the Merger Transaction on us,expected EBITDA, expected earnings/(loss), earnings/(loss) per share,expected future cash flows, expected distributable cash flow or estimated future dividends. The most relevant assumptions associated with forward-looking statements onregarding announced projects and projects under


4


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
4


rates on labor and material costs; the effects of interest rates on borrowing costs; the impact of weather and customer, government, court and regulatory approvals on construction and in-service schedules and cost recovery regimes.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 impactsuccessful execution of the Merger Transaction,our strategic priorities, operating performance, legislative and regulatory parameters,parameters; litigation; acquisitions, dispositions and other transactions and the realization of anticipated benefits therefrom; our dividend policy,policy; project approval and support,support; renewals of rights-of-way, weather,rights-of-way; weather; economic and competitive conditions,conditions; public opinion,opinion; changes in tax laws and tax rates, changes in trade agreements,rates; exchange rates,rates; interest rates,rates; commodity prices,prices; political decisions anddecisions; the supply of, and demand for commodities,and prices of commodities; and the COVID-19 pandemic, including but not limited to those risks and uncertainties discussed in this quarterly report on Form 10-Q and in our other filings with Canadian and United States (US) 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 statementsstatement made in this quarterly report on Form 10-Q or otherwise, whether as a result of new information, future events or otherwise. All subsequent forward-looking statements, whether written or oral, attributable to us or persons acting on our behalf, are expressly qualified in their entirety by these cautionary statements.



NON-GAAP AND OTHER FINANCIAL MEASURES
Part I.Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) in this Quarterly Report on Form 10-Q makes reference to non-GAAP and other financial measures, including EBITDA. EBITDA is defined as earnings before interest, income taxes, depreciation and amortization. Management uses EBITDA to assess performance of Enbridge and to set targets. Management believes the presentation of EBITDA gives useful information to investors as it provides increased transparency and insight into the performance of Enbridge.

The non-GAAP and other financial measures described above are not measures that have a standardized meaning prescribed by generally accepted accounting principles in the United States of America (US GAAP) and are not US GAAP measures. Therefore, these measures may not be comparable with similar measures presented by other issuers. A reconciliation of historical non-GAAP and other financial measures to the most directly comparable GAAP measures is set out in this MD&A and is available on our website. Additional information on non-GAAP and other financial measures may be found on our website, www.sedar.com or www.sec.gov.

5




PART I - FINANCIAL INFORMATION


ITEM 1. FINANCIAL STATEMENTS


ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF EARNINGS

Three months ended
March 31,
Three months ended
March 31,
2018
2017
20222021
(unaudited; millions of Canadian dollars, except per share amounts) 
 
(unaudited; millions of Canadian dollars, except per share amounts)  
Operating revenues 
 
Operating revenues  
Commodity sales7,268
6,866
Commodity sales8,325 6,429 
Gas distribution sales1,926
1,363
Gas distribution sales2,098 1,540 
Transportation and other services3,532
2,917
Transportation and other services4,674 4,168 
Total operating revenues (Note 3)
12,726
11,146
Total operating revenues (Note 3)
15,097 12,137 
Operating expenses  Operating expenses
Commodity costs6,997
6,550
Commodity costs8,291 6,198 
Gas distribution costs1,324
1,015
Gas distribution costs1,456 950 
Operating and administrative1,641
1,551
Operating and administrative1,875 1,559 
Depreciation and amortization824
672
Depreciation and amortization1,055 932 
Asset impairment (Note 6)
1,062

Total operating expenses11,848
9,788
Total operating expenses12,677 9,639 
Operating income878
1,358
Operating income2,420 2,498 
Income from equity investments335
236
Income from equity investments491 395 
Other income/(expense)  
Net foreign currency loss(185)(5)
Other incomeOther income
Net foreign currency gainNet foreign currency gain369 152 
Other65
40
Other89 109 
Interest expense(656)(486)Interest expense(719)(657)
Earnings before income taxes437
1,143
Earnings before income taxes2,650 2,497 
Income tax recovery/(expense) (Note 11)
73
(198)
Income tax expense (Note 9)
Income tax expense (Note 9)
(593)(483)
Earnings510
945
Earnings2,057 2,014 
(Earnings)/loss attributable to noncontrolling interests and redeemable noncontrolling interests24
(224)
Earnings attributable to noncontrolling interestsEarnings attributable to noncontrolling interests(28)(22)
Earnings attributable to controlling interests534
721
Earnings attributable to controlling interests2,029 1,992 
Preference share dividends(89)(83)Preference share dividends(102)(92)
Earnings attributable to common shareholders445
638
Earnings attributable to common shareholders1,927 1,900 
Earnings per common share attributable to common
shareholders (Note 5)

0.26
0.54
Earnings per common share attributable to common shareholders (Note 5)
0.95 0.94 
Diluted earnings per common share attributable to common shareholders (Note 5)
0.26
0.54
Diluted earnings per common share attributable to common shareholders (Note 5)
0.95 0.94 
SeeThe accompanying notes to theare an integral part of these interim consolidated financial statements.


6




ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Three months ended
March 31,
Three months ended
March 31,
2018
2017
20222021
(unaudited; millions of Canadian dollars) 
 
(unaudited; millions of Canadian dollars)  
Earnings510
945
Earnings2,057 2,014 
Other comprehensive income/(loss), net of tax  Other comprehensive income/(loss), net of tax
Change in unrealized gain/(loss) on cash flow hedges66
(2)
Change in unrealized gain/(loss) on net investment hedges(184)49
Other comprehensive income from equity investees14
6
Change in unrealized gain on cash flow hedgesChange in unrealized gain on cash flow hedges294 370 
Change in unrealized gain on net investment hedgesChange in unrealized gain on net investment hedges133 93 
Other comprehensive loss from equity investeesOther comprehensive loss from equity investees (22)
Excluded components of fair value hedgesExcluded components of fair value hedges(1)(1)
Reclassification to earnings of loss on cash flow hedges37
41
Reclassification to earnings of loss on cash flow hedges57 52 
Reclassification to earnings of pension and other postretirement benefits (OPEB) amounts(39)4
Reclassification to earnings of pension and other postretirement benefits (OPEB) amounts(2)
Foreign currency translation adjustments1,579
432
Foreign currency translation adjustments(708)(796)
Other comprehensive income, net of tax1,473
530
Other comprehensive loss, net of taxOther comprehensive loss, net of tax(227)(299)
Comprehensive income1,983
1,475
Comprehensive income1,830 1,715 
Comprehensive income attributable to noncontrolling interests and redeemable noncontrolling interests(147)(374)
Comprehensive (income)/loss attributable to noncontrolling interestsComprehensive (income)/loss attributable to noncontrolling interests(13)
Comprehensive income attributable to controlling interests1,836
1,101
Comprehensive income attributable to controlling interests1,817 1,718 
Preference share dividends(89)(83)Preference share dividends(102)(92)
Comprehensive income attributable to common shareholders1,747
1,018
Comprehensive income attributable to common shareholders1,715 1,626 
SeeThe accompanying notes to theare an integral part of these interim consolidated financial statements.


7




ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

Three months ended
March 31,
Three months ended
March 31,
2018
2017
20222021
(unaudited; millions of Canadian dollars, except per share amounts) 
 
(unaudited; millions of Canadian dollars, except per share amounts)  
Preference shares  Preference shares
Balance at beginning and end of period7,747
7,255
Balance at beginning of periodBalance at beginning of period7,747 7,747 
Redemption of preference sharesRedemption of preference shares(737)— 
Balance at end of periodBalance at end of period7,010 7,747 
Common shares 
 
Common shares 
Balance at beginning of period50,737
10,492
Balance at beginning of period64,799 64,768 
Common shares issued in Merger Transaction
37,428
Dividend Reinvestment and Share Purchase Plan374
194
Shares issued on exercise of stock options16
33
Shares issued on exercise of stock options36 
Share purchases at stated valueShare purchases at stated value(30)— 
OtherOther(4)— 
Balance at end of period51,127
48,147
Balance at end of period64,801 64,772 
Additional paid-in capital 
 
Additional paid-in capital  
Balance at beginning of period3,194
3,399
Balance at beginning of period365 277 
Stock-based compensation17
35
Stock-based compensation13 11 
Fair value of outstanding earned stock-based compensation from Merger Transaction
77
Options exercised(6)(49)Options exercised(34)(3)
Dilution gain on Spectra Energy Partners, LP restructuring (Note 9)
1,136

Dilution loss and other(28)(36)
Change in reciprocal interestChange in reciprocal interest 39 
OtherOther(28)— 
Balance at end of period4,313
3,426
Balance at end of period316 324 
Deficit 
 
Deficit  
Balance at beginning of period(2,468)(716)Balance at beginning of period(10,989)(9,995)
Earnings attributable to controlling interests534
721
Earnings attributable to controlling interests2,029 1,992 
Preference share dividends(89)(83)Preference share dividends(102)(92)
Common share dividends declared
(548)
Dividends paid to reciprocal shareholder7
7
Dividends paid to reciprocal shareholder 
Retrospective adoption of accounting standard (Note 2)
(86)
Redemption value adjustment attributable to redeemable noncontrolling interests120
152
Adjustment for the recognition of unutilized tax deductions for stock-based compensation expense
41
Share purchases in excess of stated valueShare purchases in excess of stated value(20)— 
OtherOther (1)
Balance at end of period(1,982)(426)Balance at end of period(9,082)(8,093)
Accumulated other comprehensive income/(loss) (Note 8)
 
 
Accumulated other comprehensive loss (Note 7)
Accumulated other comprehensive loss (Note 7)
  
Balance at beginning of period(973)1,058
Balance at beginning of period(1,096)(1,401)
Other comprehensive income attributable to common shareholders, net of tax1,302
380
Other comprehensive loss attributable to common shareholders, net of taxOther comprehensive loss attributable to common shareholders, net of tax(212)(274)
Balance at end of period329
1,438
Balance at end of period(1,308)(1,675)
Reciprocal shareholding 
 
Reciprocal shareholding  
Balance at beginning and end of period(102)(102)
Balance at beginning of periodBalance at beginning of period (29)
Change in reciprocal interestChange in reciprocal interest 12 
Balance at end of periodBalance at end of period (17)
Total Enbridge Inc. shareholders’ equity61,432
59,738
Total Enbridge Inc. shareholders’ equity61,737 63,058 
Noncontrolling interests 
 
Noncontrolling interests  
Balance at beginning of period7,597
577
Balance at beginning of period2,542 2,996 
Earnings attributable to noncontrolling interests23
192
Earnings attributable to noncontrolling interests28 22 
Other comprehensive income/(loss) attributable to noncontrolling interests, net of tax  Other comprehensive income/(loss) attributable to noncontrolling interests, net of tax
Change in unrealized gain/(loss) on cash flow hedges4
(1)Change in unrealized gain/(loss) on cash flow hedges2 (3)
Foreign currency translation adjustments152
141
Foreign currency translation adjustments(17)(22)
Reclassification to earnings of loss on cash flow hedges8
10
164
150
(15)(25)
Comprehensive income attributable to noncontrolling interests187
342
Noncontrolling interests resulting from Merger Transaction
8,792
Enbridge Energy Company, Inc. common control transaction
43
Comprehensive income/(loss) attributable to noncontrolling interestsComprehensive income/(loss) attributable to noncontrolling interests13 (3)
Distributions(209)(191)Distributions(60)(66)
Contributions8
215
Contributions6 
Spectra Energy Partners, LP restructuring (Note 9)
(1,486)
Other(15)3
Other35 — 
Balance at end of period6,082
9,781
Balance at end of period2,536 2,930 
Total equity67,514
69,519
Total equity64,273 65,988 
Dividends paid per common share0.671
0.583
Dividends paid per common share0.860 0.835 
SeeThe accompanying notes to theare an integral part of these interim consolidated financial statements.


8




ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS

Three months ended
March 31,
Three months ended
March 31,
2018
2017
20222021
(unaudited; millions of Canadian dollars)  (unaudited; millions of Canadian dollars)  
Operating activities  Operating activities  
Earnings510
945
Earnings2,057 2,014 
Adjustments to reconcile earnings to net cash provided by operating activities: 
 
Adjustments to reconcile earnings to net cash provided by operating activities:  
Depreciation and amortization824
672
Depreciation and amortization1,055 932 
Deferred income tax expense(147)161
Deferred income tax expense423 369 
Changes in unrealized (gain)/loss on derivative instruments, net (Note 10)
260
(418)
Earnings from equity investments(335)(236)
Unrealized derivative fair value gain, net (Note 8)
Unrealized derivative fair value gain, net (Note 8)
(369)(315)
Income from equity investmentsIncome from equity investments(491)(395)
Distributions from equity investments320
214
Distributions from equity investments394 388 
Asset impairment1,062

Gain on dispositions
(14)
(Gain)/loss on dispositions(Gain)/loss on dispositions2 (41)
Other78
112
Other120 30 
Changes in operating assets and liabilities622
340
Changes in operating assets and liabilities(252)(418)
Net cash provided by operating activities3,194
1,776
Net cash provided by operating activities2,939 2,564 
Investing activities 
 
Investing activities  
Capital expenditures(1,635)(1,642)Capital expenditures(1,048)(2,059)
Long-term investments(209)(2,537)
Long-term investments and restricted long-term investmentsLong-term investments and restricted long-term investments(314)(61)
Distributions from equity investments in excess of cumulative earnings57
11
Distributions from equity investments in excess of cumulative earnings97 61 
Restricted long-term investments(13)(15)
Additions to intangible assets(258)(233)Additions to intangible assets(53)(65)
Cash acquired in Merger Transaction
681
Proceeds from dispositions
289
Proceeds from dispositionProceeds from disposition 122 
Affiliate loans, net(10)(2)Affiliate loans, net 44 
Net cash used in investing activities(2,068)(3,448)Net cash used in investing activities(1,318)(1,958)
Financing activities 
 
Financing activities  
Net change in short-term borrowings(443)110
Net change in short-term borrowings89 (27)
Net change in commercial paper and credit facility draws(465)2,662
Net change in commercial paper and credit facility draws(283)1,727 
Debenture and term note issues, net of issue costs2,061

Debenture and term note issues, net of issue costs2,643 629 
Debenture and term note repayments(996)(513)Debenture and term note repayments(1,155)(912)
Debt extinguishment costs(63)
Contributions from noncontrolling interests8
215
Contributions from noncontrolling interests6 
Distributions to noncontrolling interests(209)(271)Distributions to noncontrolling interests(60)(66)
Contributions from redeemable noncontrolling interests20
11
Distributions to redeemable noncontrolling interests(84)(54)
Common shares issued13
4
Common shares issued2 — 
Common shares repurchasedCommon shares repurchased(50)— 
Preference share dividends(87)(83)Preference share dividends(91)(92)
Common share dividends(764)(768)Common share dividends(1,742)(1,691)
Net cash provided by/(used in) financing activities(1,009)1,313
Redemption of preferred shares held by subsidiaryRedemption of preferred shares held by subsidiary (115)
Redemption of preference sharesRedemption of preference shares(750)— 
OtherOther(92)(21)
Net cash used in financing activitiesNet cash used in financing activities(1,483)(565)
Effect of translation of foreign denominated cash and cash equivalents and restricted cash19
(9)Effect of translation of foreign denominated cash and cash equivalents and restricted cash(4)(7)
Net increase/(decrease) in cash and cash equivalents and restricted cash136
(368)
Net increase in cash and cash equivalents and restricted cashNet increase in cash and cash equivalents and restricted cash134 34 
Cash and cash equivalents and restricted cash at beginning of period587
1,562
Cash and cash equivalents and restricted cash at beginning of period320 490 
Cash and cash equivalents and restricted cash at end of period723
1,194
Cash and cash equivalents and restricted cash at end of period454 524 
Supplementary cash flow information  
Property, plant and equipment non-cash accruals754
1,019
SeeThe accompanying notes to theare an integral part of these interim consolidated financial statements.


9




ENBRIDGE INC.
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

March 31,
2018

December 31,
2017

March 31,
2022
December 31,
2021
(unaudited; millions of Canadian dollars; number of shares in millions) 
 
(unaudited; millions of Canadian dollars; number of shares in millions)  
Assets 
 
Assets  
Current assets 
 
Current assets  
Cash and cash equivalents610
480
Cash and cash equivalents413 286 
Restricted cash113
107
Restricted cash41 34 
Accounts receivable and other6,271
7,053
Accounts receivable and other8,408 6,862 
Accounts receivable from affiliates48
47
Accounts receivable from affiliates220 107 
Inventory872
1,528
Inventory1,212 1,670 
7,914
9,215
10,294 8,959 
Property, plant and equipment, net92,521
90,711
Property, plant and equipment, net99,346 100,067 
Long-term investments17,360
16,644
Long-term investments13,361 13,324 
Restricted long-term investments280
267
Restricted long-term investments594 630 
Deferred amounts and other assets5,614
6,442
Deferred amounts and other assets9,123 8,613 
Intangible assets, net3,455
3,267
Intangible assets, net3,895 4,008 
Goodwill35,168
34,457
Goodwill32,503 32,775 
Deferred income taxes1,182
1,090
Deferred income taxes275 488 
Total assets163,494
162,093
Total assets169,391 168,864 
  
Liabilities and equity 
 
Liabilities and equity  
Current liabilities 
 
Current liabilities  
Short-term borrowings1,004
1,444
Short-term borrowings1,604 1,515 
Accounts payable and other6,823
9,478
Accounts payable and other8,512 9,767 
Accounts payable to affiliates168
157
Accounts payable to affiliates112 90 
Interest payable592
634
Interest payable605 693 
Environmental liabilities33
40
Current portion of long-term debt4,152
2,871
Current portion of long-term debt4,379 6,164 
12,772
14,624
15,212 18,229 
Long-term debt61,191
60,865
Long-term debt70,490 67,961 
Other long-term liabilities8,390
7,510
Other long-term liabilities7,431 7,617 
Deferred income taxes9,812
9,295
Deferred income taxes11,985 11,689 
92,165
92,294
105,118 105,496 
Contingencies (Note 13)




Redeemable noncontrolling interests3,815
4,067
Contingencies (Note 11)
Contingencies (Note 11)
00
Equity 
 
Equity  
Share capital 
 
Share capital  
Preference shares7,747
7,747
Preference shares7,010 7,747 
Common shares (1,705 and 1,695 outstanding at March 31, 2018 and December 31, 2017, respectively)
51,127
50,737
Common shares (2,026 outstanding at March 31, 2022 and December 31, 2021)
Common shares (2,026 outstanding at March 31, 2022 and December 31, 2021)
64,801 64,799 
Additional paid-in capital4,313
3,194
Additional paid-in capital316 365 
Deficit(1,982)(2,468)Deficit(9,082)(10,989)
Accumulated other comprehensive income/(loss) (Note 8)
329
(973)
Reciprocal shareholding(102)(102)
Total Enbridge Inc. shareholders’ equity61,432
58,135
Accumulated other comprehensive loss (Note 7)
Accumulated other comprehensive loss (Note 7)
(1,308)(1,096)
Total Enbridge Inc. shareholders' equityTotal Enbridge Inc. shareholders' equity61,737 60,826 
Noncontrolling interests6,082
7,597
Noncontrolling interests2,536 2,542 
67,514
65,732
64,273 63,368 
Total liabilities and equity163,494
162,093
Total liabilities and equity169,391 168,864 
SeeThe accompanying notes to theare an integral part of these interim consolidated financial statements.statements.




10




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.(US GAAP) and Regulation S-X for interim consolidated financial information. They do not include all of the information and notes required by U.S.US GAAP for annual consolidated financial statements and should therefore be read in conjunction with our audited consolidated financial statements and notes for the year ended December 31, 2017 included in our Annual Report on Form 10-K.2021. 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 annualaudited consolidated financial statements for the year ended December 31, 2017,2021, except for the adoption of new standards (Note 2)and the presentation of Cash and cash equivalents to include Bank indebtedness, as discussed below. . Amounts are stated in Canadian dollars unless otherwise noted.

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

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


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


2. CHANGES IN ACCOUNTING POLICIES

ADOPTION OF NEW ACCOUNTING STANDARDS
Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income Disclosures About Government Assistance
Effective January 1, 2018,2022, we adopted Accounting Standards Update (ASU) 2018-02 to address a specific consequence of the Tax Cuts and Jobs Act (TCJA) enacted by the United States federal government on December 22, 2017. The amendments in this accounting update allow a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the TCJA. The amendments will eliminate the stranded tax effects as a result of the reduction of the historical United States federal corporate income tax rate to the newly enacted United States federal corporate income tax rate. The adoption of this accounting update did not have a material impact on our consolidated financial statements.

Clarifying Guidance on the Application of Modification Accounting on Stock Compensation
Effective January 1, 2018, we adopted ASU 2017-09 and applied the standard2021-10 on a prospective basis. The new standard was issued in November 2021 to clarifyincrease the scopetransparency of modification accounting. Undergovernment assistance to business entities. The ASU adds new disclosure requirements for transactions with governments that are accounted for using a grant or contribution accounting model by analogy. The required disclosures include information about the new guidance, modificationnature of transactions, accounting is required for all changes to share based payment awards, unless all of the


11


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

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

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

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

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


Recognition and Measurement of Financial Assets and Liabilities Accounting for Certain Lessor Leases with Variable Lease Payments
Effective January 1, 2018,2022, we adopted ASU 2016-012021-05 on a prospective basis. The new standard addresseswas issued in July 2021 to amend lessor accounting for certain aspectsleases with variable lease payments that do not depend on a reference index or a rate and would have resulted in the recognition of recognition, measurement, presentation and disclosure of financial assets and liabilities. Investments in equity securities, excluding equity method and consolidated investments, are no longera loss at lease commencement if classified as tradinga sales-type or available-for-sale securities. All investmentsa direct financing lease. The ASU amends the classification requirements of such leases for lessors to result in equity securities with readily determinable fair values are classified as investments at fair value through net income. Investments in equity securities without readily determinable fair values are measured using the fair value measurement alternative and are recorded at cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for an identical or similar investment of the same issuer. Investments in equity securities measured using the fair value measurement alternative are reviewed for indicators of impairment each reporting period. Fair value of financial instruments for disclosure purposes is measured using exit price.operating lease classification. The adoption of this accounting updateASU did not have a material impact on our consolidated financial statements.



12



Revenue fromAccounting for Modifications or Exchanges of Certain Equity-Classified Contracts with Customers
Effective January 1, 2018,2022, we adopted ASU 2014-092021-04 on a modified retrospective basis to contracts that were not complete at the date of initial application.prospective basis. The new standard was issued within May 2021 to clarify issuer accounting for modifications or exchanges of freestanding equity-classified written call options that remain equity classified after modification or exchange. The ASU requires an issuer to determine the intentaccounting for the modification or exchange based on the economic substance of significantly enhancing consistencythe modification or exchange. The adoption of this ASU did not have a material impact on our consolidated financial statements.

11


Accounting for Convertible Instruments and comparability of revenue recognition practices across entities and industries.Contracts in an Entity’s Own Equity
Effective January 1, 2022, we adopted ASU 2020-06 on a modified retrospective basis. The new standard establishes a single, principles-based five-step modelwas issued in August 2020 to simplify accounting for certain financial instruments. The ASU eliminates the current models that require separation of beneficial conversion and cash conversion features from convertible instruments and simplifies the derivative scope exception guidance pertaining to equity classification of contracts in an entity’s own equity. The ASU also introduces additional disclosures for convertible debt and freestanding instruments that are indexed to and settled in an entity’s own equity. The ASU amends the diluted earnings per share guidance, including the requirement to use if-converted method for all convertible instruments and an update for instruments that can be applied to all contracts with customers and introduces new and enhanced disclosure requirements. It also requires the use of more estimates and judgments than the previous standards.
In adopting Accounting Standards Codification (ASC) 606, we applied the practical expedient for contract modifications whereby contracts that were modified before January 1, 2018 were not retrospectively restated. Instead, the aggregate effect of all contract modifications occurring before that time has been reflected when identifying satisfied and unsatisfied performance obligations, determining the transaction price and allocating the transaction price to satisfied and unsatisfied obligations.
settled in either cash or shares. The below table presents the cumulative, immaterial effect of the adoption of ASC 606this ASU did not have a material impact on our Consolidated Statement of Financial Position as at January consolidated financial statements.

3. REVENUE

REVENUE FROM CONTRACTS WITH CUSTOMERS
Major Products and Services
Liquids PipelinesGas Transmission and MidstreamGas Distribution and StorageRenewable Power GenerationEnergy ServicesEliminations and OtherConsolidated
Three months ended
March 31, 2022
(millions of Canadian dollars)       
Transportation revenue2,685 1,194 251    4,130 
Storage and other revenue51 84 47    182 
Gas gathering and processing revenue 15     15 
Gas distribution revenue  2,098    2,098 
Electricity and transmission revenue   62   62 
Total revenue from contracts with customers2,736 1,293 2,396 62   6,487 
Commodity sales    8,325  8,325 
Other revenue1,2
178 7 4 94 2  285 
Intersegment revenue141  11  10 (162) 
Total revenue3,055 1,300 2,411 156 8,337 (162)15,097 

Liquids PipelinesGas Transmission and MidstreamGas Distribution and StorageRenewable Power GenerationEnergy ServicesEliminations and OtherConsolidated
Three months ended
March 31, 2021
(millions of Canadian dollars)       
Transportation revenue2,329 1,121 216 — — — 3,666 
Storage and other revenue26 74 58 — — — 158 
Gas gathering and processing revenue— — — — — 
Gas distribution revenue— — 1,534 — — — 1,534 
Electricity and transmission revenue— — — 26 — — 26 
Total revenue from contracts with customers2,355 1,202 1,808 26 — — 5,391 
Commodity sales— — — — 6,429 — 6,429 
Other revenue1,2
212 12 91 — (4)317 
Intersegment revenue132 — — (145)— 
Total revenue2,699 1,214 1,823 117 6,433 (149)12,137 
1 2018 on each affected financial statement line item along with explanations of those effects. ForIncludes mark-to-market gains from our hedging program for the three months ended March 31, 2018,2022 and 2021 of $94 million and $130 million, respectively.
2 Includes revenues from lease contracts for the effectthree months ended March 31, 2022 and 2021 of the adoption of ASC 606 on our Consolidated Statement of Earnings was not material. $164 million and $159 million, respectively.

12
 Balance at December 31, 2017Adjustments Due to ASC 606
Balance at
January 1, 2018
(millions of Canadian dollars)   
Assets   
Deferred amounts and other assets1,2
6,442
(170)6,272
Property, plant and equipment, net2
90,711
112
90,823
Liabilities and equity   
Accounts payable and other1,2
9,478
62
9,540
Other long-term liabilities2
7,510
66
7,576
Deferred income taxes1,2
9,295
(62)9,233
Redeemable noncontrolling interests1,2
4,067
(38)4,029
Deficit1,2
(2,468)(86)(2,554)
Revenue was previously recognized for a certain contract within the Liquids Pipelines business unit using a formula-based method. Under the new revenue standard, revenue is recognized on a straight-line basis over the term of the agreement in order to reflect the fulfillment of our performance obligation to provide up to a specified volume of pipeline capacity throughout the term of the contract.
Certain payments received from customers to offset the cost of constructing assets required to provide services to those customers, referred to as Contributions in Aid of Construction (CIACs) were previously recorded as reductions of property, plant and equipment regardless of whether the amounts were imposed by regulation or arose from negotiations with customers. Under the new revenue standard, CIACs which are negotiated as part of an agreement to provide transportation and other services to a customer are deemed to be advance payments for future services and are recognized as revenue when those future services are provided. Accordingly, negotiated CIACs are accounted for as deferred revenue and recognized as revenue over the term of the associated revenue contract. Amounts which are required to be collected from the customer based on requirements of the regulator continue to be accounted for as reductions of property, plant and equipment.

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


13



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

Amending the Amortization Period for Certain Callable Debt Securities Purchased at a Premium
ASU 2017-08 was issued in March 2017 with the intent of shortening the amortization period to the earliest call date for certain callable debt securities held at a premium. The accounting update is effective January 1, 2019 and will be applied on a modified retrospective basis. We are currently assessing the impact of the new standard on our consolidated financial statements.
Accounting for Credit Losses
ASU 2016-13 was issued in June 2016 with the intent of providing financial statement users with more useful information about the expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity at each reporting date. Current treatment uses the incurred loss methodology for recognizing credit losses that delays the recognition until it is probable a loss has been incurred. The accounting update adds a new impairment model, known as the current expected credit loss model, which is based on expected losses rather than incurred losses. Under the new guidance, an entity will recognize as an allowance its estimate of expected credit losses, which the Financial Accounting Standards Board believes will result in more timely recognition of such losses. The accounting update is effective January 1, 2020. We are currently assessing the impact of the new standard on our consolidated financial statements.

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

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




14


3. REVENUE

REVENUE FROM CONTRACTS WITH CUSTOMERS

Major Products and Services
 Liquids Pipelines
Gas Transmission and Midstream
Gas Distribution
Green Power and Transmission
Energy Services
Eliminations and Other
Consolidated
Three months ended
March 31, 2018
(millions of Canadian dollars) 
  
 
 
 
 
Transportation revenue2,058
952
239



3,249
Storage and other revenue40
60
66



166
Gas gathering and processing revenue
205




205
Gas distribution revenue

1,926



1,926
Electricity and transmission revenue


154


154
Commodity sales
693




693
Total revenue from contracts with customers2,098
1,910
2,231
154


6,393
Commodity sales



6,575

6,575
Other revenue1
(269)25
2
3

(3)(242)
Intersegment revenue80
2
4

57
(143)
Total revenue1,909
1,937
2,237
157
6,632
(146)12,726
Includes mark-to-market gains/(losses) from our hedging program.

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

Contract Balances
Contract ReceivablesContract AssetsContract Liabilities
(millions of Canadian dollars)
Balance as at March 31, 20222,784 216 1,913 
Balance as at December 31, 20212,369 213 1,898 
 ReceivablesContract AssetsContract Liabilities
(millions of Canadian dollars)   
Balance at adoption date

2,475
290
992
Balance at reporting date

2,533
290
1,008


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

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

Contract liabilities represent payments received for performance obligations which have not been fulfilled. Contract liabilities primarily relate to make-up rights and deferred revenue. Revenue recognized during the current periodthree months ended March 31, 2022 included in contract liabilities at the beginning of the period is $95$61 million. Increases in contract liabilities from cash received, net of amounts recognized as revenue during the three months ended March 31, 2018,2022 were $96 million during the period.$97 million.


15



Performance Obligations
Business UnitNature of Performance Obligation
Transportation services - pipelines

Transportation and storage of crude oil, natural gas and natural gas liquids (NGL)
Gas Transmission and Midstream
Sale of crude oil, natural gas and NGLs
Transportation, storage, gathering, compression and treating of natural gas
Gas Distribution
Supply and delivery of natural gas
Transportation of natural gas
Storage of natural gas
Green Power and transmission

Generation and transmission of electricity
Delivery of electricity from renewable energy generation facilities

There was no material revenue recognized in the current periodthree months ended March 31, 2022 from performance obligations satisfied in previous periods.
Payment Terms
Payments are received monthly from customers under long-term transportation, commodity sales, and gas gathering and processing contracts. Payments from Gas Distribution customers are received on a continuous basis based on established billing cycles.
Certain contracts in the United States offshore business provide for us to receive a series of fixed monthly payments (FMPs) for a specified period which is less than the period during which the performance obligations are satisfied. As a result, a portion of the FMPs is recorded as a contract liability. The FMPs are not considered to be a financing arrangement because the payments are scheduled to match the production profiles of offshore oil and gas fields, which generate greater revenue in the initial years of their productive lives.
Revenue to be Recognized from Unfulfilled Performance Obligations
Total revenue from performance obligations expected to be fulfilled in future periods is $63.8$58.3 billion, of which $5.7$5.5 billion and $5.9$6.1 billion isare expected to be recognized during the remaining nine months ending December 31, 20182022 and year ending December 31, 2019,2023, respectively.


The revenues excluded from the amounts above based on optional exemptions available under ASCAccounting Standards Codification (ASC) 606, as explained below, represent a significant portion of our overall revenues and revenues from contracts with customers. Certain revenues such as flow-through operating costs charged to shippers are recognized at the amount for which we have the right to invoice our customers. Those revenuescustomers and are not included inexcluded from the amounts for revenue to be recognized in the future from unfulfilled performance obligations above. Variable consideration is excluded from the amounts above due to the uncertainty of the associated consideration, which is generally resolved when actual volumes and prices are determined. For example, we consider interruptible transportation service revenues to be variable revenues since volumes cannot be estimated. Additionally, the effect of escalation on certain tolls which are contractually escalated for inflation has not been reflected in the amounts above as it is not possible to reliably estimate future inflation rates. Revenues for periods extending beyond the current rate settlement term for regulated contracts where the tolls are periodically reset by the regulator are excluded from the amounts above since future tolls remain unknown. Finally, revenues from contracts with customers which have an original expected duration of one year or less are excluded from the amounts above.
SIGNIFICANT JUDGMENTS MADE IN RECOGNIZING REVENUE
Long-Term Transportation Agreements
13


For long-term transportation agreements, significant judgments pertainVariable Consideration
During the three months ended March 31, 2022, revenue for the Canadian Mainline has been recognized in accordance with the terms of the Competitive Tolling Settlement, which expired on June 30, 2021. The tolls in place on June 30, 2021 continue on an interim basis until a new commercial arrangement is implemented and are subject to finalization and adjustment applicable to the interim period, over which revenue is recognized and whether the agreement provides for make-up rights for the shippers. Transportation revenue earned from firm contracted capacity arrangements is recognized ratably over the contract period. Transportation revenue from interruptible or volumetric-based arrangements is recognized when services are performed.


16


Estimates of Variable Consideration
Revenue from arrangements subject to variable consideration is recognized onlyif any. Due to the extent that it is probable thatuncertainty of adjustment to tolling pursuant to a significant reversal in the amount of cumulativeCanada Energy Regulator decision and potential customer negotiations, interim toll revenue recognized will not occur whenduring the uncertainty associated with thethree months ended March 31, 2022 is considered variable consideration is subsequently resolved. Uncertainties associated with variable consideration relate principally to differences between estimated and actual volumes and prices. These uncertainties are resolved each month when actual volumes sold or transported and actual tolls and prices are determined.consideration.

Recognition and Measurement of RevenueRevenues
Liquids PipelinesGas Transmission and MidstreamGas Distribution and StorageRenewable Power GenerationConsolidated
Three months ended
March 31, 2022
(millions of Canadian dollars)    
Revenue from products transferred at a point in time  16  16 
Revenue from products and services transferred over time1
2,736 1,293 2,380 62 6,471 
Total revenue from contracts with customers2,736 1,293 2,396 62 6,487 
 Liquids Pipelines
Gas Transmission and Midstream
Gas Distribution
Green Power and Transmission
Energy Services
Consolidated
Three months ended
March 31, 2018
(millions of Canadian dollars) 
  
 
 
 
Revenue from products transferred at a point in time1

693
25


718
Revenue from products and services transferred over time2
2,098
1,217
2,206
154

5,675
Total revenue from contracts with customers2,098
1,910
2,231
154

6,393

1
Revenue from sales of crude oil, natural gas and NGLs.
2
Liquids PipelinesGas Transmission and MidstreamGas Distribution and StorageRenewable Power GenerationConsolidated
Three months ended
March 31, 2021
(millions of Canadian dollars)
Revenue from products transferred at a point in time— — 17 — 17 
Revenue from products and services transferred over time1
2,355 1,202 1,791 26 5,374 
Total revenue from contracts with customers2,355 1,202 1,808 26 5,391 
1     Revenue from crude oil and natural gas pipeline transportation, storage, natural gas gathering, compression and treating, natural gas distribution, natural gas storage services and electricity sales.

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

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

Determination of Transaction Prices
Prices for gas processing and transportation services are determined based on the capital cost of the facilities, pipelines and associated infrastructure required to provide such services plus a rate of return on capital invested that is determined either through negotiations with customers or through regulatory processes for those operations that are subject to rate regulation.
Prices for commodities sold are determined by reference to market price indices plus or minus a negotiated differential and in certain cases a marketing fee.
Prices forstorage, natural gas soldgathering, compression and distribution services provided by regulatedtreating, natural gas distribution, operations are prescribed by regulation.natural gas storage services and electricity sales.

4.
SEGMENTED INFORMATION

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



14
17



4. SEGMENTED INFORMATION

Liquids PipelinesGas Transmission and MidstreamGas Distribution and StorageRenewable Power GenerationEnergy ServicesEliminations and OtherConsolidated
Three months ended
March 31, 2022
(millions of Canadian dollars)       
Operating revenues3,055 1,300 2,411 156 8,337 (162)15,097 
Commodity and gas distribution costs(11) (1,468)(4)(8,427)163 (9,747)
Operating and administrative(947)(530)(299)(48)(14)(37)(1,875)
Income from equity investments215 221  55   491 
Other income17 23 21 3 3 391 458 
Earnings/(loss) before interest, income taxes, and depreciation and amortization2,329 1,014 665 162 (101)355 4,424 
Depreciation and amortization(1,055)
Interest expense      (719)
Income tax expense      (593)
Earnings     2,057 
Capital expenditures1
545 229 266 6  12 1,058 

Liquids PipelinesGas Transmission and MidstreamGas Distribution and StorageRenewable Power GenerationEnergy ServicesEliminations and OtherConsolidated
Three months ended
March 31, 2021
(millions of Canadian dollars)       
Operating revenues2,699 1,214 1,823 117 6,433 (149)12,137 
Commodity and gas distribution costs(3)— (958)— (6,353)166 (7,148)
Operating and administrative(819)(434)(272)(43)(14)23 (1,559)
Income from equity investments154 182 22 37 — — 395 
Other income/(expense)11 19 45 (2)180 261 
Earnings before interest, income taxes, and depreciation and amortization2,039 973 634 156 64 220 4,086 
Depreciation and amortization(932)
Interest expense      (657)
Income tax expense      (483)
Earnings      2,014 
Capital expenditures1
1,195 482 219 — 12 1,913 
1 Includes allowance for equity funds used during construction.

15
 Liquids Pipelines
Gas Transmission and Midstream
Gas Distribution
Green Power and Transmission
Energy Services
Eliminations and Other
Consolidated
Three months ended
March 31, 2018
(millions of Canadian dollars) 
  
 
 
 
 
Revenues1,909
1,937
2,237
157
6,632
(146)12,726
Commodity and gas distribution costs(4)(620)(1,388)
(6,455)146
(8,321)
Operating and administrative(747)(507)(248)(30)(12)(97)(1,641)
Asset impairment(144)(913)


(5)(1,062)
Income/(loss) from equity investments131
208
17
(25)4

335
Other income/(expense)11
21
18
7

(177)(120)
Earnings/(loss) before interest, income taxes, and depreciation and amortization

1,156
126
636
109
169
(279)1,917
Depreciation and amortization      (824)
Interest expense 
 
 
 
 
 
(656)
Income tax recovery 
 
 
 
 
 
73
Earnings  
 
 
 
 
510
Capital expenditures1
615
825
183
14

6
1,643



 Liquids Pipelines
Gas Transmission and Midstream
Gas Distribution
Green Power and Transmission
Energy Services
Eliminations and Other
Consolidated
Three months ended
March 31, 2017
(millions of Canadian dollars) 
  
 
 
 
 
Revenues2,155
1,235
1,584
137
6,133
(98)11,146
Commodity and gas distribution costs(3)(647)(1,046)1
(5,968)98
(7,565)
Operating and administrative(760)(254)(189)(40)(12)(296)(1,551)
Income from equity investments86
110
36
2
2

236
Other income/(expense)2
31
2
1
1
(2)35
Earnings/(loss) before interest, income taxes, and depreciation and amortization

1,480
475
387
101
156
(298)2,301
Depreciation and amortization      (672)
Interest expense 
 
 
 
 
 
(486)
Income tax expense 
 
 
 
 
 
(198)
Earnings 
 
 
 
 
 
945
Capital expenditures1
654
655
183
114

59
1,665
5. EARNINGS PER COMMON SHARE AND DIVIDENDS PER SHARE
1
Includes allowance for equity funds used during construction.

TOTAL ASSETS
 March 31, 2018
December 31, 2017
(millions of Canadian dollars) 
 
Liquids Pipelines64,842
63,881
Gas Transmission and Midstream61,880
60,745
Gas Distribution25,784
25,956
Green Power and Transmission6,466
6,289
Energy Services1,628
2,514
Eliminations and Other2,894
2,708
 163,494
162,093




18


5.
EARNINGS PER COMMON SHARE

BASIC
Earnings per common share is calculated by dividing earnings attributable to common shareholders by the weighted average number of common shares outstanding. TheOn December 30, 2021, we closed the sale of our minority ownership of Noverco Inc. (Noverco). For the three months ended March 31, 2021, the weighted average number of common shares outstanding has beenwas reduced by our pro-rata weighted average interest in our own common shares of 13approximately 3 million, for the three months ended March 31, 2018 and 2017, resulting from our reciprocal investment in Noverco Inc.Noverco.

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,
 20222021
(number of shares in millions)  
Weighted average shares outstanding2,026 2,022 
Effect of dilutive options3 
Diluted weighted average shares outstanding2,029 2,023 
 Three months ended
March 31,
 2018
2017
(number of common shares in millions) 
 
Weighted average shares outstanding1,685
1,177
Effect of dilutive options4
10
Diluted weighted average shares outstanding1,689
1,187


For the three months ended March 31, 20182022 and 2017, 29,882,1422021, 12.9 million and 13,545,193,27.6 million, respectively, of anti-dilutive stock options with a weighted average exercise price of $49.80$56.09 and $57.71,$51.42, respectively, were excluded from the diluted earnings per common share calculation.

16


DIVIDENDS PER SHARE
On May 3, 2022, our Board of Directors declared the following quarterly dividends. All dividends are payable on June 1, 2022 to shareholders of record on May 13, 2022.
Dividend per share
Common Shares1
$0.86000 
Preference Shares, Series A$0.34375 
Preference Shares, Series B$0.21340 
Preference Shares, Series C2
$0.18400 
Preference Shares, Series D$0.27875 
Preference Shares, Series F$0.29306 
Preference Shares, Series H$0.27350 
Preference Shares, Series J3
US$0.30540 
Preference Shares, Series LUS$0.30993 
Preference Shares, Series N$0.31788 
Preference Shares, Series P$0.27369 
Preference Shares, Series R$0.25456 
Preference Shares, Series 1US$0.37182 
Preference Shares, Series 3$0.23356 
Preference Shares, Series 5US$0.33596 
Preference Shares, Series 7$0.27806 
Preference Shares, Series 9$0.25606 
Preference Shares, Series 11$0.24613 
Preference Shares, Series 13$0.19019 
Preference Shares, Series 15$0.18644 
6.Preference Shares, Series 19
ASSETS HELD FOR SALE
$0.30625 
Midcoast Operating, L.P.1 The quarterly dividend per common share was increased 3% to $0.86 from $0.835, effective March 1, 2022.
2 The quarterly dividend per share paid on Series C was increased to $0.18400 from $0.15719 on March 1, 2022, due to reset on a quarterly basis following the date of issuance of the Series C Preference Shares.
3 On May 9, 2018 our indirect subsidiary, Enbridge (U.S.) Inc. entered into a definitive agreement to sell Midcoast Operating, L.P. and its subsidiaries (Sales Agreement), which conducts our United States natural gas and NGL gathering, processing, transportation and marketing businesses, to AL Midcoast Holdings, LLC (an affiliate of ArcLight Capital Partners, LLC) for a cash purchase price of US$1.1 billion, subject to customary closing adjustments. The transaction is expected to close in the third quarter of 2018, subject to receipt of customary regulatory approvals and satisfaction of other customary closing conditions.

These assets, excluding our equity method investment in the Texas Express NGL pipeline system, were classified as held for sale and were measured at the lower of their carrying value or fair value less costs to sell as at December 31, 2017. As a result of entering into the Sales Agreement, the fair value of the assets held for sale as at March 31, 2018 were revised based on the sale price. Accordingly,2, 2022, we recorded a loss of $913 million ($701 million after-tax attributable to us). This loss has been included within Asset impairment on the Consolidated Statements of Earnings for the three months ended March 31, 2018.

Line 10 Crude Oil Pipeline
At March 31, 2018, we satisfied the condition as set out in our agreements for the salenotified holders of our Line 10 crude oil pipeline (Line 10), which originates near Hamilton, Ontario and terminates at West Seneca, New York. Our subsidiaries, Enbridge Pipelines Inc. and Enbridge Energy Partners, L.P., own the Canadian and United States portionoutstanding Cumulative Redeemable Preference Shares, Series J (Series J Shares) (TSX: ENB.PR.U) of Line 10, respectively, and the related assets are included in our Liquids Pipeline segment.intention to redeem all US$200 million outstanding Series J Shares on June 1, 2022.



19


6. DEBT

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

The table below summarizes the presentation of net assets held for sale in our Consolidated Statements of Financial Position:
 March 31, 2018
December 31, 2017
(millions of Canadian dollars) 
 
Accounts receivable and other (current assets held for sale)305
424
Deferred amounts and other assets (long-term assets held for sale)422
1,190
Accounts payable and other (current liabilities held for sale)(233)(315)
Other long-term liabilities (long-term liabilities held for sale)(37)(34)
Net assets held for sale457
1,265

7.
DEBT


CREDIT FACILITIES
The following table provides details of our committed credit facilities as at March 31, 2018:2022:
 
 
  March 31, 2018
 Maturity
Total
Facilities

Draws1

Available
(millions of Canadian dollars)    
Enbridge Inc.2
2019-20226,644
2,616
4,028
Enbridge (U.S.) Inc.20192,469
1,142
1,327
Enbridge Energy Partners, L.P.3
2019-20223,385
1,660
1,725
Enbridge Gas Distribution Inc. (EGD)20191,017
884
133
Enbridge Income Fund20201,500
566
934
Enbridge Pipelines Inc.20193,000
1,730
1,270
Spectra Energy Partners, LP4
20223,223
2,135
1,088
Union Gas Limited (Union Gas)2021700
130
570
Total committed credit facilities 21,938
10,863
11,075
Maturity1
Total
Facilities
Draws2
Available
(millions of Canadian dollars)    
Enbridge Inc.2022 - 20267,616 7,012 604 
Enbridge (U.S.) Inc.2023 - 20266,870 5,351 1,519 
Enbridge Pipelines Inc.20233,000 627 2,373 
Enbridge Gas Inc.20232,000 1,604 396 
Total committed credit facilities 19,486 14,594 4,892 
 
1
Includes facility draws, letters of credit and commercial paper issuances that are back-stopped by the credit facility.
2
Includes $135 million, $161 million (US$125 million) and$150 million of commitments that expire in 2018, 2018 and 2020, respectively.
3Includes $226 million (US$175 million) and $239 million (US$185 million) of commitments that expire in 2018 and 2020, respectively.
4Includes $434 million (US$336 million) of commitments that expire in 2021.

1Maturity date is inclusive of the one-year term out option for certain credit facilities.
During the first quarter of 2018, Enbridge terminated a US$650 million2Includes facility draws and commercial paper issuances that are back-stopped by credit facilities.

On February 10, 2022, we renewed our three year $1.0 billion sustainability-linked credit facility, which was setextending the maturity date out to mature in 2019, and repaid drawn amounts. In addition, Enbridge (U.S.) Inc. terminated an unutilizedUS$950 million credit facility, which was set to mature in 2019.July 2025.


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

In addition to the committed credit facilities noted above, we have $790 millionmaintain $1.3 billion of uncommitted demand letter of credit facilities, of which $511$947 million werewas unutilized as at March 31, 2018.2022. As at December 31, 2017,2021, we had $792 million$1.3 billion of uncommitted demand letter of credit facilities, of which $518$854 million werewas unutilized.




17
20



Our credit facilities carry a weighted average standby fee of 0.2%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 setscheduled to mature from 20192022 to 2022.2026.


As at March 31, 20182022 and December 31, 2017,2021, commercial paper and credit facility draws, net of short-term borrowings and non-revolving credit facilities that mature within one year, of $9,832 million$12.4 billion and $10,055 million,$11.3 billion, respectively, arewere supported by the availability of long-term committed credit facilities and, therefore, have been classified as long-term debt.


LONG-TERM DEBT ISSUANCES
During the first quarter of 2018,three months ended March 31, 2022, we completed the following long-term debt issuances: issuances totaling US$1.5 billion and $750 million:
CompanyIssue DatePrincipal Amount
(millions of Canadian dollars unless otherwise stated)
Enbridge Inc.
January 20225.00%hybrid fixed-to-fixed subordinated notes due January 2082$750
February 2022
Floating rate senior notes due February 20241
US$600
February 20222.15%senior notes due February 2024US$400
February 20222.50%senior notes due February 2025US$500
CompanyIssue DatePrincipal Amount
(millions of dollars)
Enbridge Inc.
March 2018
Fixed-to-floating rate notes due 20781
  US$850
Spectra Energy Partners, LP2
January 20183.50% senior notes due 2028  US$400
January 20184.15% senior notes due 2048US$400
1
Notes mature in 60 years and are callable on or after year 10. For the initial 10 years, the notes carry a fixed interest rate of 6.25%. Subsequently, the interest rate will be set to equal the three-month London Interbank Offered Rate (LIBOR) plus a margin of 364 basis points from years 10 to 30, and a margin of 439 basis points from years 30 to 60.
2Issued through Texas Eastern Transmission, LP, a wholly-owned operating subsidiary of Spectra Energy Partners, LP (SEP).

1Notes carry an interest rate set to equal Secured Overnight Financing Rate plus a margin of 63 basis points.

LONG-TERM DEBT REPAYMENTS
During the first quarter of 2018,three months ended March 31, 2022, we completed the following long-term debt repayments:repayments totaling $200 million and US$750 million:
CompanyRepayment DatePrincipal Amount
(millions of Canadian dollars unless otherwise stated)
Enbridge Inc.
February 2022
Floating rate notes1
US$750
February 20224.85%medium-term notes$200
CompanyRetirement/Repayment DatePrincipal Amount
Cash Consideration
(millions of Canadian dollars unless otherwise stated)
Enbridge Southern Lights LP
January 20184.01% medium-term notes due June 20409
Spectra Energy Capital, LLC1
Repurchase via Tender Offer
March 20186.75% senior unsecured notes due 2032US$64US$80
March 20187.50% senior unsecured notes due 2038US$43US$59
Redemption
March 20185.65% senior unsecured notes due 2020US$163US$172
March 20183.30% senior unsecured notes due 2023US$498US$508
1Notes carried an interest rate set to equal the three-month London Interbank Offered Rate plus a margin of 50 basis points.
1
The loss on debt extinguishment of $37 million (US$29 million), net of the fair value adjustment recorded upon completion of the stock-for-stock merger transaction on February 27, 2017 between Enbridge and Spectra Energy Corp (the Merger Transaction), was reported within Interest expense in the Consolidated Statements of Earnings.


SUBORDINATED TERM NOTES
As at March 31, 2022 and December 31, 2021, our fixed-to-floating rate and fixed-to-fixed rate subordinated term notes had a principal value of $8.4 billion and $7.7 billion, respectively.

FAIR VALUE ADJUSTMENT
As at March 31, 2022 and December 31, 2021, the net fair value adjustments to total debt assumed in a historical acquisition were $646 million and $667 million, respectively. During the three months ended March 31, 2022 and 2021, amortization of the fair value adjustment recorded as a reduction to Interest expense in the Consolidated Statements of Earnings was $11 million and $12 million, respectively.

DEBT COVENANTS
Our credit facility agreements and term debt indentures include standard events of default and covenant provisions whereby accelerated repayment and/or termination of the agreements may result if we were to default on payment or violate certain covenants. As at March 31, 2018,2022, we were in compliance with all debt covenants.covenant provisions.





18
21



7. COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE LOSS
8.COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME

Changes in Accumulated other comprehensive incomeloss (AOCI) attributable to our common shareholders for the three months ended March 31, 20182022 and 20172021 are as follows:
Cash
Flow
Hedges
Excluded
Components
of Fair Value
Hedges
Net
Investment
Hedges
Cumulative
Translation
Adjustment
Equity
Investees
Pension
and
OPEB
Adjustment
Total
(millions of Canadian dollars)      
Balance as at January 1, 2022(897) (166)56 (5)(84)(1,096)
Other comprehensive income/(loss) retained in AOCI384 (1)133 (691)  (175)
Other comprehensive loss/(income) reclassified to earnings
Interest rate contracts1
76      76 
Commodity contracts2
       
Foreign exchange contracts3
(4)     (4)
Other contracts4
2      2 
Amortization of pension and OPEB actuarial gain5
     (3)(3)
458 (1)133 (691) (3)(104)
Tax impact      
Income tax on amounts retained in AOCI(92)     (92)
Income tax on amounts reclassified to earnings(17)    1 (16)
(109)    1 (108)
Balance as at March 31, 2022(548)(1)(33)(635)(5)(86)(1,308)
 
Cash Flow 
Hedges

Net
Investment
Hedges

Cumulative
Translation
Adjustment

Equity
Investees

Pension and
OPEB
Adjustment

Total
(millions of Canadian dollars)      
Balance at January 1, 2018(644)(139)77
10
(277)(973)
Other comprehensive income/(loss) retained in AOCI70
(213)1,425
2

1,284
Other comprehensive (income)/loss reclassified to earnings     

Interest rate contracts1
28




28
Commodity contracts2
(1)



(1)
Foreign exchange contracts3
4




4
Other contracts4
9




9
Amortization of pension and OPEB actuarial loss and prior service costs5




(38)(38)
 110
(213)1,425
2
(38)1,286
Tax impact 
 
 
 
 
 
Income tax on amounts retained in AOCI(9)29

8

28
Income tax on amounts reclassified to earnings(11)


(1)(12)
 (20)29

8
(1)16
Balance at March 31, 2018(554)(323)1,502
20
(316)329
 
Cash Flow
Hedges

Net
Investment
Hedges

Cumulative
Translation
Adjustment

Equity
Investees

Pension and
OPEB
Adjustment

Total
(millions of Canadian dollars)      
Balance at January 1, 2017(746)(629)2,700
37
(304)1,058
Other comprehensive income/(loss) retained in AOCI(1)50
293
5

347
Other comprehensive (income)/loss reclassified to earnings     

Interest rate contracts1
31




31
Commodity contracts2
(2)



(2)
Other contracts4
9




9
Amortization of pension and OPEB actuarial loss and prior service costs5





6
6
 37
50
293
5
6
391
Tax impact      
Income tax on amounts retained in AOCI(1)(1)
1

(1)
Income tax on amounts reclassified to earnings(8)


(2)(10)
 (9)(1)
1
(2)(11)
Balance at March 31, 2017(718)(580)2,993
43
(300)1,438
1Reported within Interest expense in the Consolidated Statements of Earnings.
2Reported within Commodity costs in the Consolidated Statements of Earnings.
3Reported within Other income/(expense) in the Consolidated Statements of Earnings.
4Reported within Operating and administrative expense in the Consolidated Statements of Earnings.
5These components are included in the computation of net periodic benefit costs and are reported within Other income/(expense) in the Consolidated Statements of Earnings.




22


9. NONCONTROLLING INTERESTS
Cash
Flow
Hedges
Excluded
Components
of Fair Value
Hedges
Net
Investment
Hedges
Cumulative
Translation
Adjustment
Equity
Investees
Pension
and
OPEB
Adjustment
Total
(millions of Canadian dollars)
Balance as at January 1, 2021(1,326)(215)568 66 (499)(1,401)
Other comprehensive income/(loss) retained in AOCI493 (1)105 (774)(26)— (203)
Other comprehensive loss/(income) reclassified to earnings
Interest rate contracts1
63 — — — — — 63 
Commodity contracts2
— — — — — 
Foreign exchange contracts3
— — — — — 
Amortization of pension and OPEB actuarial loss5
— — — — — 
Other17 — — (20)— — 
575 (1)105 (794)(23)(131)
Tax impact
Income tax on amounts retained in AOCI(120)— (12)— — (128)
Income tax on amounts reclassified to earnings(13)— — — — (2)(15)
(133)— (12)— (2)(143)
Balance as at March 31, 2021(884)(122)(226)47 (494)(1,675)
 
As at December 31, 2017, we collectively owned a 75% ownership interest1 Reported within Interest expense in SEP, together with 100%the Consolidated Statements of SEP's incentive distribution rights (IDRs). On January 22, 2018, EnbridgeEarnings.
2 Reported within Transportation and SEP announcedother services revenues, Commodity sales revenue, Commodity costs and Operating and administrative expense in the executionConsolidated Statements of a definitive agreement, resultingEarnings.
3 Reported within Transportation and other services revenues and Net foreign currency gain in us converting allthe Consolidated Statements of our IDRsEarnings.
4 Reported within Operating and general partner economic interestsadministrative expense in SEP into 172.5 million newly issued SEP common units. As partthe Consolidated Statements of Earnings.
5 These components are included in the transaction, allcomputation of net periodic benefit costs and are reported within Other income in the IDRs have been eliminated. We now hold a non-economic general partner interest in SEP and own approximately 403 millionConsolidated Statements of SEP common units, representing 83% of SEP's outstanding common units. As a result of this restructuring, we recorded a decrease in Noncontrolling interests of $1.5 billion and increases in Additional paid-in capital and Deferred income taxes of $1.1 billion and $333 million, respectively, for the three months ended March 31, 2018.Earnings.


19
10.


8. RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

MARKET RISK
Our earnings, cash flows and other comprehensive incomeincome/(loss) (OCI) are subject to movements in foreign exchange rates, interest rates, commodity prices and our share price (collectively, market risk)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 areis 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 (US) dollar denominated investments and subsidiaries using foreign
currency derivatives and United StatesUS dollar denominated debt.

Interest Rate Risk
Our earnings and cash flows are exposed to short-term interest rate variability due to the regular repricing
of our variable rate debt, primarily commercial paper. Pay fixed-receive floating interest rate swaps are
used to hedge against the effect of future interest rate movements. We have implemented a program to
significantly mitigate the impact of short-term interest rate volatility on interest expense via execution of
floating to fixed interest rate swaps with an average swap rate of 2.6%.

As a result of the Merger Transaction, we are exposed to changes in the fair value of fixed rate debt that
arise as a result of the changes in market interest rates. Pay floating-receive fixed interest rate swaps are
used to hedge against future changes to the fair value of fixed rate debt. We have assumed a program
within our subsidiaries to mitigate the impact of fluctuations in the fair value of fixed rate debt via
execution of fixed to floating interest rate swaps with an average swap rate of 2.1%.
Our earnings and cash flows are also exposed to variability in longer term interest rates ahead of
anticipated fixed rate term debt issuances. Forward starting interest rate swaps are used to hedge against
the effect of future interest rate movements. We have assumed a program within some of our subsidiaries
to mitigate our exposure to long-term interest rate variability on select forecast term debt issuances via
execution of floating to fixed interest rate swaps with an average swap rate of 3.4%.


23


We also monitor our debt portfolio mix of fixed and variable rate debt instruments to manage a
consolidated portfolio of floating rate debt within the Board of Directors approved policy limit of a maximum of 30% of floating rate debt as a percentage of total debt outstanding. We primarily use qualifying derivative instruments to manage interest rate risk. 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 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 2.1%.


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, 2022, we do not have any pay floating-receive fixed interest rate swaps outstanding.

Our earnings and cash flows are also exposed to variability in longer term interest rates ahead of anticipated fixed rate term debt issuances. Forward starting interest rate swaps are used to hedge against the effect of future interest rate movements. We have established a program including 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 2.1%.

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.

Emission Allowance Price Risk
20

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

allowances that our gas distribution business is required to purchase for itself and most of its customers
to meet greenhouse gas compliance obligations under the Ontario Cap and Trade framework. Similar to the gas supply procurement framework, the Ontario Energy Board's (OEB) framework for emission allowance procurement allows recovery of fluctuations in emission allowance prices in customer rates, subject to OEB approval.
Equity Price Risk
Equity price risk is the risk of earnings fluctuations due to changes in our share price. We have exposure
to our own common share price through the issuance of various forms of stock-based compensation,
which affect earnings through revaluation of the outstanding units every period. We use equity derivatives
to manage the earnings volatility derived from one1 form of stock-based compensation, restricted share
units. We use a combination of qualifying and non-qualifying derivative instruments to manage equity
price risk.

TOTAL DERIVATIVE INSTRUMENTS
The following table summarizes the Consolidated Statements of Financial Position location and carrying
value of our derivative instruments.
We generally have a policy of entering into individual International Swaps and Derivatives
Association, Inc. agreements, or other similar derivative agreements, with the majority of our financial
derivative counterparties. These agreements provide for the net settlement of derivative instruments
outstanding with specific counterparties in the event of bankruptcy or other significant credit events, and
reduces reduce our credit risk exposure on financial derivative asset positions outstanding with the
counterparties in those circumstances.

The following table summarizes the Consolidated Statements of Financial Position location and carrying value of our derivative instruments, as well as the maximum potential settlement
amounts in the event of thesethe specific circumstances.circumstances described above. All amounts are presented gross in the Consolidated
Statements of Financial Position.



March 31, 2022Derivative
Instruments
Used as
Cash Flow
Hedges
Derivative
Instruments
Used as
Fair Value
 Hedges
Non-
Qualifying
Derivative
Instruments
Total Gross
Derivative
Instruments
as Presented
Amounts
Available
for Offset
Total Net
Derivative
Instruments
(millions of Canadian dollars)
Accounts receivable and other
Foreign exchange contracts  342 342 (52)290 
Interest rate contracts149   149  149 
Commodity contracts  274 274 (186)88 
Other contracts3  7 10  10 
152  623 775 (238)537 
Deferred amounts and other assets
Foreign exchange contracts  470 470 (142)328 
Interest rate contracts283   283  283 
Commodity contracts  56 56 (23)33 
Other contracts3  2 5  5 
286  528 814 (165)649 
Accounts payable and other
Foreign exchange contracts  (187)(187)52 (135)
Interest rate contracts(28) (23)(51) (51)
Commodity contracts(14) (381)(395)186 (209)
(42) (591)(633)238 (395)
Other long-term liabilities
Foreign exchange contracts (37)(292)(329)142 (187)
Interest rate contracts(4)  (4) (4)
Commodity contracts(13) (96)(109)23 (86)
(17)(37)(388)(442)165 (277)
Total net derivative assets/(liabilities)
Foreign exchange contracts (37)333 296  296 
Interest rate contracts400  (23)377  377 
Commodity contracts(27) (147)(174) (174)
Other contracts6  9 15  15 
379 (37)172 514  514 


21
24



March 31, 2018
Derivative
Instruments
Used as
Cash Flow Hedges

Derivative
Instruments
Used as Net
Investment Hedges

Derivative
Instruments
Used as
Fair Value Hedges

Non-
Qualifying
Derivative Instruments

Total Gross
Derivative
Instruments as Presented

Amounts
Available for Offset

Total Net
Derivative Instruments

December 31, 2021December 31, 2021Derivative
Instruments
Used as
Cash Flow
Hedges
Derivative
Instruments
Used as
Fair Value
 Hedges
Non-
Qualifying
Derivative
Instruments
Total Gross
Derivative
Instruments
as Presented
Amounts
Available
for Offset
Total Net
Derivative
Instruments
(millions of Canadian dollars) (millions of Canadian dollars)
Accounts receivable and other Accounts receivable and other
Foreign exchange contracts
3

131
134
(70)64
Foreign exchange contracts— — 259 259 (41)218 
Interest rate contracts27



27
(5)22
Interest rate contracts64 — — 64 — 64 
Commodity contracts


100
100
(34)66
Commodity contracts— — 204 204 (129)75 
Other contractsOther contracts— — — 
27
3

231
261
(109)152
64 — 465 529 (170)359 
Deferred amounts and other assets Deferred amounts and other assets
Foreign exchange contracts18


92
110
(58)52
Foreign exchange contracts— — 240 240 (61)179 
Interest rate contracts15



15

15
Interest rate contracts88 — — 88 (1)87 
Commodity contracts19


3
22
(19)3
Commodity contracts— — 29 29 (13)16 
Other contracts






Other contracts— — — 
52


95
147
(77)70
88 — 272 360 (75)285 
Accounts payable and other Accounts payable and other
Foreign exchange contracts(5)(23)
(327)(355)70
(285)Foreign exchange contracts(15)(112)(176)(303)41 (262)
Interest rate contracts(112)
(9)(185)(306)5
(301)Interest rate contracts(150)— — (150)— (150)
Commodity contracts(2)

(244)(246)34
(212)Commodity contracts(14)— (250)(264)129 (135)
Other contracts(2)

(8)(10)
(10)
(121)(23)(9)(764)(917)109
(808)(179)(112)(426)(717)170 (547)
Other long-term liabilities Other long-term liabilities
Foreign exchange contracts
(10)
(1,650)(1,660)58
(1,602)Foreign exchange contracts— — (423)(423)61 (362)
Interest rate contracts(20)
(2)
(22)
(22)Interest rate contracts(1)— (23)(24)(23)
Commodity contracts


(160)(160)19
(141)Commodity contracts(17)— (67)(84)13 (71)
Other contracts(5)

(3)(8)
(8)
(25)(10)(2)(1,813)(1,850)77
(1,773)
Total net derivative asset/(liability) 
(18)— (513)(531)75 (456)
Total net derivative assets/(liabilities)Total net derivative assets/(liabilities)
Foreign exchange contracts13
(30)
(1,754)(1,771)
(1,771)Foreign exchange contracts(15)(112)(100)(227)— (227)
Interest rate contracts(90)
(11)(185)(286)
(286)Interest rate contracts— (23)(22)— (22)
Commodity contracts17


(301)(284)
(284)Commodity contracts(31)— (84)(115)— (115)
Other contracts(7)

(11)(18)
(18)Other contracts— — — 
(67)(30)(11)(2,251)(2,359)
(2,359)(45)(112)(202)(359)— (359)


25


December 31, 2017
Derivative
Instruments
Used as
Cash Flow Hedges

Derivative
Instruments
Used as Net
Investment Hedges

Derivative Instruments Used as Fair Value Hedges
Non-
Qualifying
Derivative Instruments

Total Gross
Derivative
Instruments as Presented

Amounts
Available for Offset

Total Net
Derivative Instruments

(millions of Canadian dollars)       
Accounts receivable and other       
Foreign exchange contracts1
4

138
143
(83)60
Interest rate contracts6

2

8
(3)5
Commodity contracts2


143
145
(64)81
 9
4
2
281
296
(150)146
Deferred amounts and other assets  2
    
Foreign exchange contracts1
1

143
145
(125)20
Interest rate contracts7

6

13
(2)11
Commodity contracts17


6
23
(19)4
 25
1
6
149
181
(146)35
Accounts payable and other       
Foreign exchange contracts(5)(42)
(312)(359)83
(276)
Interest rate contracts(140)
(6)(183)(329)3
(326)
Commodity contracts


(439)(439)64
(375)
Other contracts(1)

(2)(3)
(3)
 (146)(42)(6)(936)(1,130)150
(980)
Other long-term liabilities       
Foreign exchange contracts(4)(9)
(1,299)(1,312)125
(1,187)
Interest rate contracts(38)
(2)
(40)2
(38)
Commodity contracts


(186)(186)19
(167)
Other contracts(1)


(1)
(1)
 (43)(9)(2)(1,485)(1,539)146
(1,393)
Total net derivative asset/(liability)  -2
    
Foreign exchange contracts(7)(46)
(1,330)(1,383)
(1,383)
Interest rate contracts(165)

(183)(348)
(348)
Commodity contracts19


(476)(457)
(457)
Other contracts(2)

(2)(4)
(4)
 (155)(46)
(1,991)(2,192)
(2,192)



26



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

March 31, 20182018
2019
2020
2021
2022
Thereafter1

Foreign exchange contracts - United States dollar forwards - purchase (millions of United States dollars)
544
2
1



Foreign exchange contracts - United States dollar forwards - sell (millions of United States dollars)
3,215
3,247
3,258
1,689
1,676
3,489
Foreign exchange contracts - British pound (GBP) forwards - purchase (millions of GBP)






Foreign exchange contracts - GBP forwards - sell (millions of GBP)

89
25
27
28
149
Foreign exchange contracts - Euro forwards - purchase (millions of Euro)
264
375




Foreign exchange contracts - Euro forwards - sell (millions of Euro)


35
169
169
889
Foreign exchange contracts - Japanese yen forwards - purchase (millions of yen)

32,662


20,000

Interest rate contracts - short-term pay fixed rate (millions of Canadian dollars)
3,749
2,100
527
109
93
203
Interest rate contracts - long-term receive fixed rate (millions of Canadian dollars)
728
580
553
188
102

Interest rate contracts - long-term debt pay fixed rate (millions of Canadian dollars)
2,242
800
447



Equity contracts (millions of Canadian dollars)
40
37
8



Commodity contracts - natural gas (billions of cubic feet)
(16)(57)(23)(2)14
2
Commodity contracts - crude oil (millions of barrels)
1
2




Commodity contracts - NGL (millions of barrels)
(10)(1)



Commodity contracts - power (megawatt per hour) (MW/H))
60
64
66
(3)(43)(43)
March 31, 202220222023202420252026ThereafterTotal
Foreign exchange contracts - US dollar forwards - purchase (millions of US dollars)
848  1,000 500   2,348 
Foreign exchange contracts - US dollar forwards - sell (millions of US dollars)
7,544 5,794 4,544 3,372 2,772 492 24,518 
Foreign exchange contracts - British pound (GBP) forwards - sell (millions of GBP)
21 29 30 30 28 32 170 
Foreign exchange contracts - Euro forwards - sell (millions of Euro)
95 92 91 86 85 343 792 
Foreign exchange contracts - Japanese yen forwards - purchase (millions of yen)
52,500      52,500 
Interest rate contracts - short-term debt pay fixed rate (millions of Canadian dollars)
536 796 128 30 26 64 1,580 
Interest rate contracts - long-term debt pay fixed rate (millions of Canadian dollars)
2,549 2,587 1,687 562   7,385 
Equity contracts (millions of Canadian dollars)
 26 21    47 
Commodity contracts - natural gas (billions of cubic feet)1
172 33 13 11   229 
Commodity contracts - crude oil (millions of barrels)1
10 (1)    9 
Commodity contracts - power (megawatt per hour) (MW/H)
(14)(43)(43)(43)  (37)2
1 As at March 31, 2018, thereafter includesTotal is a net purchase/(sale) of underlying commodity.
2 Total is an average net purchase/(sell)(sale) of power of (43) MW/H for 2023 through 2025.


power.

22
27



Fair Value Derivatives
For foreign exchange derivative instruments that are designated and qualify as fair value hedges, the gain or loss on the derivative is included in Net foreign currency gain or Interest expense in the Consolidated Statements of Earnings. The offsetting loss or gain on the hedged item attributable to the hedged risk is included in Net foreign currency gain in the Consolidated Statements of Earnings. Any excluded components are included in the Consolidated Statements of Comprehensive Income.

Three months ended
March 31,
20222021
(millions of Canadian dollars)
Unrealized gain/(loss) on derivative76 (3)
Unrealized loss on hedged item(87)(4)
Realized loss on derivative(75)(39)
Realized gain on hedged item85 45 

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,
 2018
2017
(millions of Canadian dollars)  
Amount of unrealized gain/(loss) recognized in OCI  
Cash flow hedges  
Foreign exchange contracts21
(2)
Interest rate contracts100
(14)
Commodity contracts(2)21
Other contracts(14)(9)
Net investment hedges  
Foreign exchange contracts16
8
 121
4
Amount of (gain)/loss reclassified from AOCI to earnings (effective portion)
  
Foreign exchange contracts1
(1)1
Interest rate contracts2
41
48
Commodity contracts3
(1)(2)
Other contracts4
9
9
 48
56
Amount of (gain)/loss reclassified from AOCI to earnings (ineffective portion and amount excluded from effectiveness testing)
  
Interest rate contracts2
(1)2
 (1)2
1Reported within Transportation and other services revenues and Other income/(expense) in the Consolidated Statements of Earnings.
2Reported within Interest expense in the Consolidated Statements of Earnings.
3Reported within Transportation and other services revenues, Commodity sales revenues, Commodity costs and Operating and administrative expense in the Consolidated Statements of Earnings.
4Reported within Operating and administrative expense in the Consolidated Statements of Earnings.

Three months ended
March 31,
20222021
(millions of Canadian dollars)
Amount of unrealized gain/(loss) recognized in OCI
Cash flow hedges
Foreign exchange contracts2 (20)
Interest rate contracts377 497 
Commodity contracts4 (8)
Other contracts3 
Fair value hedges
Foreign exchange contracts(1)(1)
385 471 
Amount of loss reclassified from AOCI to earnings
Foreign exchange contracts1
13 
Interest rate contracts2
76 63 
Commodity contracts 
Other contracts3
2 — 
 91 65 
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 lossgain of $22$3 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 3345 months as at March 31, 2018.2022.
 
Fair Value Derivatives
For interest rate derivative instruments that are designated and qualify as fair value hedges, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item attributable to the hedged risk is included in Interest expense in the Consolidated Statements of Earnings. During the three months ended March 31, 2018 and 2017, we recognized an unrealized loss of $8 million and $2 million, respectively, on the derivative and an unrealized gain of $8 million and $2 million, respectively, on the hedged item in earnings. During the three months ended March 31, 2018 and 2017, we recognized a realized loss of $3 million and nil, respectively, on the derivative and a realized gain of $3 million and nil, respectively, on the hedged item in earnings. The difference in the amounts, if any, represents hedge ineffectiveness.



23
28



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,
20222021
(millions of Canadian dollars)
Foreign exchange contracts1
433 236 
Interest rate contracts2
 
Commodity contracts3
(68)72 
Other contracts4
4 
Total unrealized derivative fair value gain/(loss), net369 315 
 Three months ended
March 31,
 2018
2017
(millions of Canadian dollars)  
Foreign exchange contracts1
(424)273
Interest rate contracts2
(2)(18)
Commodity contracts3
175
163
Other contracts4
(9)
Total unrealized derivative fair value gain/(loss), net(260)418
1    For the respective three months ended periods, reported within Transportation and other services revenues (2022 - $134 million gain; 2021 - $154 million gain) and Net foreign currency gain (2022 - $299 million gain; 2021 - $82 million gain) in the Consolidated Statements of Earnings.
1For the respective three months ended periods, reported within Transportation and other services revenues (2018 - $297 million loss; 2017 - $159 million gain) and Other income/(expense) (2018 - $127 million loss; 2017 - $114 million gain) in the Consolidated Statements of Earnings.
2Reported as an (increase)/decrease within Interest expense in the Consolidated Statements of Earnings.
3For the respective three months ended periods, reported within Transportation and other services revenues (2018 - $1 million loss; 2017 - $22 million loss), Commodity sales (2018 - $82 million gain; 2017 - $187 million gain), Commodity costs (2018 - $84 million gain; 2017 - $5 million gain) and Operating and administrative expense (2018 - $10 million gain; 2017 - $7 million loss) in the Consolidated Statements of Earnings.
4Reported within Operating and administrative expense 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 (2022 - $16 million loss; 2021 - $3 million loss), Commodity sales (2022 - $16 million loss; 2021 - $171 million gain), Commodity costs (2022 - $37 million loss; 2021 - $100 million loss) and Operating and administrative expense (2022 - $1 million gain; 2021 - $4 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 12-month rolling time period to determine whether sufficient funds will be available and maintain
substantial capacity under our committed bank lines of credit to address any contingencies. Our primary
sources of liquidity and capital resources are funds generated from operations, the issuance of
commercial paper and draws under committed credit facilities and long-term debt, which includes
debentures and medium-term notes. We also maintain current shelf prospectuses with securities
regulators which enables subject to market conditions, ready access to either the Canadian or United
StatesUS public capital markets.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, 2018.2022. 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 bythrough 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.






24
29



We have credit concentrations and credit exposure, with respect to derivative instruments, in the following counterparty segments:
March 31,
2018

December 31,
2017

March 31,
2022
December 31,
2021
(millions of Canadian dollars)  (millions of Canadian dollars)
Canadian financial institutions49
82
Canadian financial institutions800 424 
United States financial institutions29
19
US financial institutionsUS financial institutions210 130 
European financial institutions143
145
European financial institutions347 181 
Asian financial institutions15
2
Asian financial institutions66 30 
Other1
72
137
Other1
161 122 
308
385
1,584 887 
 
1Other is comprised of commodity clearing house and physical natural gas and crude oil counterparties.
1    Other is comprised of commodity clearing house and physical natural gas and crude oil counterparties.

As at March 31, 2018,2022, we provided letters of credit totaling nil in lieu of providing cash collateral to our counterparties pursuant to the terms of the relevant ISDAInternational Swaps and Derivatives Association agreements. We held no cash collateral on derivative asset exposures as at March 31, 20182022 and December 31, 2017.2021.

Gross derivative balances have been presented without the effects of collateral posted. Derivative assets
are adjusted for non-performance risk of our counterparties using their credit default swap spread rates,
and are reflected at fair value. For derivative liabilities, our non-performance risk is considered in the
valuation.


Credit risk also arises from trade and other long-term receivables, and is mitigated through credit exposure limits and contractual requirements, assessment of credit ratings and netting arrangements. Within EGD and UnionEnbridge Gas Inc., credit risk is mitigated by the utilities'utility's large and diversified customer base and the ability to recover an estimate for doubtful accountsexpected credit losses 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 classifyutilize a loss allowance matrix which contemplates historical credit losses by age of receivables, adjusted for any forward-looking information and provide for receivables older than 30 days as past due.management expectations to measure lifetime expected credit losses of receivables. 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
and other financial 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 derivativefinancial 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 derivativesfinancial instruments 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 derivativefinancial instrument 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.




fluctuations, as well as restricted long-term investments in Canadian equity securities that are held in trust in accordance with the Canada Energy Regulator's (CER) regulatory requirements under the Land Matters Consultation Initiative (LMCI).

25
30



Level 2
Level 2 includes derivativefinancial instrument valuations determined using directly or indirectly observable inputs other than
quoted prices included within Level 1. DerivativesFinancial instruments 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.financial instrument. 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 maturityavailable-for-sale preferred share investment, long-term debt and restricted long-term
debt investments in Canadian government bonds held in trust in accordance with the CER's regulatory requirements under the LMCI as Level 2. The fair value of our held to maturityavailable-for-sale preferred share investment is primarily based on the
yield of certain Government of Canada bonds. redemption value, which equals the face value plus accrued and unpaid interest periodically reset based on market interest rates. The fair value of our long-term debt is based on quoted
market prices for instruments of similar yield, credit risk and tenor. When possible, the fair value of our restricted long-term investments is based on quoted market prices for similar instruments and, if not available, based on broker quotes.


Level 3
Level 3 includes derivative valuations based on inputs which are less observable, unavailable or where
the observable data does not support a significant portion of the derivatives’ fair value. Generally, Level 3
derivatives are longer dated transactions, occur in less active markets, occur at locations where pricing
information is not available or have no binding broker quote to support Level 2 classification. We have
developed methodologies, benchmarked against industry standards, to determine fair value for these
derivatives based on extrapolation of observable future prices and rates. Derivatives valued using Level 3
inputs primarily include long-dated derivative power, contracts and NGL and natural gas contracts, basis
swaps, commodity swaps, and power and energy swaps, as well as options.physical forward commodity contracts. We do not have any other
financial instruments categorized in Level 3.


We use the most observable inputs available to estimate the fair value of our derivatives. When possible,
we estimate the fair value of our derivatives based on quoted market prices. If quoted market prices are
not available, we use estimates from third party brokers. For non-exchange traded derivatives classified
in Levels 2 and 3, we use standard valuation techniques to calculate the estimated fair value. These
methods include discounted cash flows for forwards and swaps and Black-Scholes-Merton pricing models
for options. Depending on the type of derivative and nature of the underlying risk, we use observable
market prices (interest, foreign exchange, commodity and share price) and volatility as primary inputs to
these valuation techniques. Finally, we consider our own credit default swap spread as well as the credit
default swap spreads associated with our counterparties in our estimation of fair value.




26
31



We have categorized our derivative assets and liabilities measured at fair value as follows:
March 31, 2018Level 1
Level 2
Level 3
Total Gross
Derivative
Instruments

March 31, 2022March 31, 2022Level 1Level 2Level 3Total Gross
Derivative
Instruments
(millions of Canadian dollars) 
 
 
 
(millions of Canadian dollars) 
Financial assets 
 
 
 
Financial assets 
Current derivative assets 
 
 
 
Current derivative assets 
Foreign exchange contracts
134

134
Foreign exchange contracts 342  342 
Interest rate contracts
27

27
Interest rate contracts 149  149 
Commodity contracts
18
82
100
Commodity contracts36 172 66 274 
Other contractsOther contracts 10  10 

179
82
261
36 673 66 775 
Long-term derivative assets 
 
 
 
Long-term derivative assets 
Foreign exchange contracts
110

110
Foreign exchange contracts 470  470 
Interest rate contracts
15

15
Interest rate contracts 283  283 
Commodity contracts
1
21
22
Commodity contracts 24 32 56 
Other contracts



Other contracts 5  5 

126
21
147
 782 32 814 
Financial liabilities 
 
 
 
Financial liabilities 
Current derivative liabilities 
 
 
 
Current derivative liabilities 
Foreign exchange contracts
(355)
(355)Foreign exchange contracts (187) (187)
Interest rate contracts
(306)
(306)Interest rate contracts (51) (51)
Commodity contracts(6)(88)(152)(246)Commodity contracts(27)(168)(200)(395)
Other contracts
(10)
(10)
(6)(759)(152)(917) (27)(406)(200)(633)
Long-term derivative liabilities 
 
 
 
Long-term derivative liabilities 
Foreign exchange contracts
(1,660)
(1,660)Foreign exchange contracts (329) (329)
Interest rate contracts
(22)
(22)Interest rate contracts (4) (4)
Commodity contracts
(4)(156)(160)Commodity contracts (31)(78)(109)
Other contracts
(8)
(8)

(1,694)(156)(1,850)
Total net financial liabilities 
 
 
 
 (364)(78)(442)
Total net financial assets/(liabilities)Total net financial assets/(liabilities) 
Foreign exchange contracts
(1,771)
(1,771)Foreign exchange contracts 296  296 
Interest rate contracts
(286)
(286)Interest rate contracts 377  377 
Commodity contracts(6)(73)(205)(284)Commodity contracts9 (3)(180)(174)
Other contracts
(18)
(18)Other contracts 15  15 
(6)(2,148)(205)(2,359) 9 685 (180)514 

27
32



December 31, 2017Level 1
Level 2
Level 3
Total Gross
Derivative
Instruments

December 31, 2021December 31, 2021Level 1Level 2Level 3Total Gross
Derivative
Instruments
(millions of Canadian dollars) 
 
 
 
(millions of Canadian dollars) 
Financial assets 
 
 
 
Financial assets 
Current derivative assets 
 
 
 
Current derivative assets 
Foreign exchange contracts
143

143
Foreign exchange contracts— 259 — 259 
Interest rate contracts
8

8
Interest rate contracts— 64 — 64 
Commodity contracts1
30
114
145
Commodity contracts38 71 95 204 
Other contractsOther contracts— — 
1
181
114
296
38 396 95 529 
Long-term derivative assets 
 
 
 
Long-term derivative assets 
Foreign exchange contracts
145

145
Foreign exchange contracts— 240 — 240 
Interest rate contracts
13

13
Interest rate contracts— 88 — 88 
Commodity contracts
2
21
23
Commodity contracts— 21 29 
Other contractsOther contracts— — 

160
21
181
— 352 360 
Financial liabilities 
 
 
 
Financial liabilities 
Current derivative liabilities 
 
 
 
Current derivative liabilities 
Foreign exchange contracts
(359)
(359)Foreign exchange contracts— (303)— (303)
Interest rate contracts
(329)
(329)Interest rate contracts— (150)— (150)
Commodity contracts(13)(87)(339)(439)Commodity contracts(52)(66)(146)(264)
Other contracts
(3)
(3)
(13)(778)(339)(1,130)(52)(519)(146)(717)
Long-term derivative liabilities 
 
 
 
Long-term derivative liabilities 
Foreign exchange contracts
(1,312)
(1,312)Foreign exchange contracts— (423)— (423)
Interest rate contracts
(40)
(40)Interest rate contracts— (24)— (24)
Commodity contracts
(3)(183)(186)Commodity contracts— (19)(65)(84)
Other contracts
(1)
(1)

(1,356)(183)(1,539)
Total net financial liabilities 
 
 
 
— (466)(65)(531)
Total net financial assets/(liabilities)Total net financial assets/(liabilities) 
Foreign exchange contracts
(1,383)
(1,383)Foreign exchange contracts— (227)— (227)
Interest rate contracts
(348)
(348)Interest rate contracts— (22)— (22)
Commodity contracts(12)(58)(387)(457)Commodity contracts(14)(108)(115)
Other contracts
(4)
(4)Other contracts— — 
(12)(1,793)(387)(2,192) (14)(237)(108)(359)


33



The significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments were as follows:
March 31, 2022Fair
Value
Unobservable
Input
Minimum
Price
Maximum
Price
Weighted
Average Price
Unit of
Measurement
(fair value in millions of Canadian dollars)
Commodity contracts - financial1
Natural gas5 Forward gas price3.94 9.60 6.24 
$/mmbtu2
Crude(3)Forward crude price83.47 124.49 106.20 $/barrel
Power(54)Forward power price22.33 121.08 77.14 $/MW/H
Commodity contracts - physical1
Natural gas(97)Forward gas price3.48 15.02 6.23 
$/mmbtu2
Crude(31)Forward crude price97.55 139.67 118.41 $/barrel
(180)
March 31, 2018
Fair
Value

Unobservable
Input
Minimum
Price/Volatility

Maximum
Price/Volatility

Weighted
Average Price

Unit of
Measurement
(fair value in millions of Canadian dollars)      
Commodity contracts - financial1
      
Natural gas9
Forward gas price2.49
4.25
3.20
$/mmbtu3
Crude(4)Forward crude price48.92
63.73
53.07
$/barrel
NGL(4)Forward NGL price0.34
1.83
1.29
$/gallon
Power(100)Forward power price14.30
76.27
52.00
$/MW/H
Commodity contracts - physical1
      
Natural gas(81)Forward gas price0.78
4.91
2.57
$/mmbtu3
Crude(29)Forward crude price38.01
91.27
75.29
$/barrel
NGL5
Forward NGL price0.34
1.88
0.86
$/gallon
Commodity options2
      
Crude(1)Option volatility22%24%23% 
NGL
Option volatility%%% 
Power
Option volatility23%26%24% 
 (205)     
1    Financial and physical forward commodity contracts are valued using a market approach valuation technique.
1Financial and physical forward commodity contracts are valued using a market approach valuation technique.
2Commodity options contracts are valued using an option model valuation technique.
3One million British thermal units (mmbtu).
2    One million British thermal units (mmbtu).
 


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If adjusted, the significant unobservable inputs disclosed in the table above would have a direct impact on
the fair value of our Level 3 derivative instruments. The significant unobservable inputs used in the fair
value measurement of Level 3 derivative instruments include forward commodity prices and, for option
contracts, price volatility.prices. Changes in forward commodity prices could result in significantly different fair
values for our Level 3 derivatives. Changes in price volatility would change the value of the option
contracts. Generally, a change in the estimate of forward commodity prices is unrelated to a change in the
estimate of price volatility.


Changes in net fair value of derivative assets and liabilities classified as Level 3 in the fair value hierarchy were as follows:
Three months ended
March 31,
 20222021
(millions of Canadian dollars)  
Level 3 net derivative liability at beginning of period(108)(191)
Total gain/(loss)  
Included in earnings1
(52)(72)
Included in OCI4 (5)
Settlements(24)149 
Level 3 net derivative liability at end of period(180)(119)
 Three months ended
March 31,
 2018
2017
(millions of Canadian dollars) 
 
Level 3 net derivative liability at beginning of period(387)(295)
Total gain/(loss) 
 
Included in earnings1
31
83
Included in OCI(3)19
Settlements154
70
Level 3 net derivative liability at end of period(205)(123)
1Reported within Transportation and other services revenues, Commodity costs and Operating and administrative expense in the Consolidated Statements of Earnings.
1Reported within Transportation and other services revenues, Commodity costs and Operating and administrative expense in the Consolidated Statements of Earnings.
Our policy is to recognize transfers as at the last day of the reporting period.
There were no transfers between levelsinto or out of Level 3 as at March 31, 20182022 or 2017.December 31, 2021.


NET INVESTMENT HEDGES

We currently have designated a portion of our US dollar denominated debt, as well as a portfolio of foreign exchange forward contracts in prior periods, as a hedge of our net investment in US dollar denominated investments and subsidiaries.
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During the three months ended March 31, 2022 and 2021, we recognized an unrealized foreign exchange gain of $133 million and $105 million, respectively, on the translation of US dollar denominated debt. During the three months ended March 31, 2022 and 2021, we recognized NaN on the change in fair value of our outstanding foreign exchange forward contracts in OCI and nil in OCI associated with the settlement of foreign exchange forward contracts or with the settlement of US dollar denominated debt that had matured during the period.

FAIR VALUE OF OTHER FINANCIAL INSTRUMENTS
Our otherCertain long-term investments in other entities with no actively quoted prices are classified as Fair Value Measurement Alternative (FMVA)(FVMA) investments and are recorded at cost less impairment. The carrying value of FMVA other long-termFVMA investments totaled $100 million and $99$52 million as at March 31, 20182022 and December 31, 2017, respectively.2021.

We have Restricted long-term investments held in trust totaling $280$213 million and $267$217 million as at March 31, 20182022 and December 31, 2017,2021, respectively, which are classified as Level 1 in the fair value hierarchy. We also have Restricted long-term investments held in trust totaling $381 million and $413 million as at March 31, 2022 and December 31, 2021, respectively, which are classified as Level 2 in the fair value hierarchy. Level 1 and Level 2 Restricted long-term investments are recognized at fair value. These securities are classified as restricted funds which are collected from customers and held in trust for the purpose of funding pipeline abandonment in accordance with regulatory requirements. There were unrealized holding losses of $60 million and $45 million for the three months ended March 31, 2022 and 2021, respectively.
 
We have a held to maturity preferred share investment carried at its amortized cost of $382 million and $371 million as at March 31, 2018 and December 31, 2017, respectively. These preferred shares are entitled to a cumulative preferred dividend based on the yield of 10-year Government of Canada bonds plus a margin of 4.50%. As at March 31, 2018 and December 31, 2017, the fair value of this preferred share investment approximates its face value of $580 million.
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As at March 31, 20182022 and December 31, 2017,2021, our long-term debt had a carrying value of $65.6$75.2 billion and $64.0$74.4 billion, respectively, before debt issuance costs and a fair value of $68.0$75.5 billion and $67.4$82.0 billion, respectively. We also have noncurrentnon-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, 20182022 and December 31, 2017,2021, the noncurrentnon-current notes receivable hashad a carrying value of $92 million$0.9 billion and $89 million,$1.0 billion, respectively, and awhich also approximates their fair value of $92 million and $89 million, respectively.value.


The fair value of other financial assets and liabilities other than derivative instruments, other long-term investments, Restrictedrestricted long-term investments, and long-term debt and non-current notes receivable described above approximate their costcarrying 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.
During the three months ended March 31, 2018 and 2017, we recognized an unrealized foreign exchange
loss of $194 million on the translation of United States dollar denominated debt and a gain of $20 million, respectively, and an unrealized gain on the change in fair value of our outstanding foreign exchange forward contracts of $15 million and $9 million, respectively, in OCI. During the three months ended March 31, 2018 and 2017, we recognized a realized loss of $23 million and gain of $1 million, respectively, in OCI associated with the settlement of foreign exchange forward contracts and recognized a realized loss of $11 million and gain of $20 million, respectively, in OCI associated with the settlement of United States dollar denominated debt that had matured during the period. There was no ineffectiveness during the three months ended March 31, 2018 and 2017.

11. 9. INCOME TAXES


The effective income tax rates for the three months ended March 31, 20182022 and 20172021 were (16.7)%22.4% and 17.3%19.3%, respectively. The period-over-period decreaseincrease in the effective income tax rate is primarily due to the effectseffect of rate-regulated accounting for income taxes and other permanent items relative to the decreaseearnings and an increase in earnings for the three months ended March 31, 2018 as well as the impact of the United States federal corporate income tax rate reduction enacted in 2017.US minimum tax.


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


35


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

12. 10. PENSION AND OTHER POSTRETIREMENT BENEFITS
Three months ended March 31,
20222021
(millions of Canadian dollars)
Service cost45 48 
Interest cost1
41 32 
Expected return on plan assets1
(98)(84)
Amortization of actuarial (gain)/loss1
(1)14 
Net periodic benefit (credit)/cost(13)10 
1 Reported within Other income in the Consolidated Statements of Earnings.

11. CONTINGENCIES
 Three months ended
March 31,
 2018
2017
(millions of Canadian dollars)  
Service cost65
54
Interest cost45
32
Expected return on plan assets(82)(51)
Amortization of prior service costs(1)
Amortization of actuarial loss7
9
Net periodic benefit costs34
44

13. CONTINGENCIES

We and our subsidiaries are involved in various other legal and regulatory actions and proceedings which arise in the normal course of business, including interventions in regulatory proceedings and challenges to regulatory approvals and permits by special interest groups.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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36


14. SUBSEQUENT EVENTS


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

On April 12, 2018, we completed an offering of US$600 million of fixed-to-floating rate subordinated
notes that mature in 60 years and are callable on or after year5. For the initial 5 years, the notes carry a fixed interest rate of 6.375%. After the initial 5 years, the interest rate will be set to equal the three-month LIBOR plus a margin of 359 basis points from years5 to 10, a margin of 384 basis points from years 10 to 25, and a margin of 459 basis points from years 25 to 60.

On April 30, 2018, Sabal Trail Transmission, LLC (Sabal Trail), a joint venture in which SEP owns a 50% interest, issued US$500 million in aggregate principal amount of 4.246% senior notes due in 2028,
US$600 million in aggregate principal amount of 4.682% due in 2038 and US$400 million in aggregate principle amount of 4.832% due in 2048. Sabal Trail distributed net proceeds from the offering to the partners as a partial reimbursement of construction and development costs incurred by the partners. The net contribution made to SEP was approximately US$750 million to be used to pay down indebtedness.

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

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




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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 interim consolidated financial statements and the accompanying notes included in Part I. Item 1. Financial Statements of this quarterly report on Form 10-Q and in conjunction with the auditedour consolidated financial statements and the accompanying footnotesnotes included in Part II. Item 8. Financial Statements and Supplementary Data of our Annual Reportannual report on Form 10-K for the year ended December 31, 2017,2021.

We continue to qualify as fileda foreign private issuer for purposes of the United States Securities Exchange Act of 1934, as amended (Exchange Act), as determined annually as of the end of our second fiscal quarter. 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 US Securities and Exchange Commission on February 16, 2018.(SEC) instead of filing the reporting forms available to foreign private issuers. We also intend to maintain our Form S-3 registration statements.


UNITED STATES TAX REFORM UPDATERECENT DEVELOPMENTS


ADVANCEMENT OF ALBERTA CARBON HUB

On December 22, 2017,March 31, 2022, the United States enactedGovernment of Alberta announced that we have been awarded the Tax Cutsright to pursue development of a carbon dioxide (CO2) sequestration hub west of Edmonton, Alberta. We are developing the Open Access Wabamun Carbon Hub (the Hub) to support near-term carbon capture projects being advanced by project partners Capital Power Corporation (Capital Power) and Jobs Act (TCJA)Lehigh Cement, a division of Lehigh Hanson Materials Limited (Lehigh Cement). As disclosed

The Hub and associated carbon capture projects being advanced by Capital Power and Lehigh Cement represent an opportunity to avoid nearly 4 million tonnes of atmospheric CO2 emissions with phased in-service dates starting as early as 2025. Once built, the Hub will be among the largest integrated carbon capture and sequestration projects in our Annual Report on Form 10-K, asthe world and can be scaled to meet the needs of other nearby industrial emitters.

The Hub's carbon transportation and sequestration facilities will be co-developed and ultimately co-owned with local Indigenous partners, including the First Nations Capital Investment Partnership (comprised of Alexander First Nation, Alexis Nakota Sioux Nation, Enoch Cree Nation and Paul First Nation) and the Lac Ste. Anne Métis Community.

GAS TRANSMISSION AND MIDSTREAM RATE PROCEEDINGS

Texas Eastern Transmission
Texas Eastern Transmission, LP (Texas Eastern) filed withtwo rate cases in the Securitiesthird quarter of 2021. These two rate proceedings have since been consolidated and Exchange Commission on February 16, 2018, we made certain estimates for the measurement and accounting of certain effects of the TCJA for the year ended and as at December 31, 2017. As we continue to gather, prepare and analyze the necessary information in reasonable detail to complete the accounting for the impact of the TCJA, we continue to refine our estimates. Duringsettlement negotiations began during the first quarter of 2018 we refined our calculation of the regulatory liability associated with the TCJA. This resulted in a reduction of the US$860 million overall regulatory liability at Spectra Energy Partners, LP (SEP) by US$25 million.

We have also recorded a nil provision in the first quarter of 2018, based on existing guidance and
legislation, for the Global Intangible Low Taxed Income tax and the Base Erosion and Anti-abuse
tax.

SEP INCENTIVE DISTRIBUTION RIGHTS

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

REVISED FERC POLICY ON TREATMENT OF INCOME TAXES

2022. On March 15, 2018,24, 2022, the Federal Energy Regulatory Commission (FERC) revised a long standing policy announcing that it would no longer permit entities organizedclosed the remaining directive and accepted Texas Eastern’s response, effectively upholding the charge crediting process as Master Limited Partnerships (MLPs) to recover an income tax allowance for interstate pipeline assetsbeing in accordance with cost-of-service rates. The announcement of the Revised Policy Statement was accompanied by: (i) a Notice of Proposed Rulemaking proposing interstate natural gas pipelines file a one-time report to quantify the impact of the federal income tax rate reduction and the impact of the revised Policy Statement on each pipeline; and (ii) a Notice of Inquiry seeking comment on how FERC should address changes related to accumulated deferred income taxes and bonus depreciation.
We hold United States liquids and natural gas pipelines through a number of different ownership structures, including MLPs. Spectra Energy Partners (SEP) and Enbridge Energy Partners (EEP) have responded to the FERC announcement regarding tax allowance, both directly and through industry associations, objecting to the change in FERC policy and requesting a re-hearing. On April 27, 2018, the FERC issued a tolling order for the purpose of affording it additional time for consideration of matters raised on rehearing. These FERC announcements have adversely affected MLPs generally, including

policy.

31
38



Maritimes & Northeast (M&N) Pipeline
SEP and EEP. BothIn December 2021, the direct consequences of the change in FERC policy as well as the adverse market effect may negatively impact the longer-term availability of capital to SEP and EEP at attractive terms.
While there will likely be varying impacts to each of the sponsored vehicles, on a consolidated basis, we do not expect a material impact to our results of operations or cash flows over the 2018 to 2020 horizon. Under the International Joint Toll mechanism on the Mainline System, reductions in the EEP tariff would create an offsetting revenue increase on the Canadian Mainline system owned by the Fund Group. In addition, while many uncertainties remain in regard to the implementation of the recent FERC actions, if implemented as announced, we estimate the unmitigated impact to revenue from SEP would not be material to us. We continue to evaluate a variety of options to mitigate the negative impact of the FERC policy change on both EEP and SEP.
ASSET MONETIZATION

On May 9, 2018 we entered into agreements with the Canadian Pension Plan Investment Board to sell a49% interest in all of our Canadian renewable energy generation assets, 49% of two large United States renewable assets and 49% of our interest in the Hohe See Offshore wind farm and its subsequent expansion, both concurrently under construction in Germany, (collectively, the Assets). Initial proceeds from the transaction are $1.75 billion. In addition, our partner will fund their pro-rata share of the remaining capital on the Hohe See Offshore wind project. We will maintain a 51% interest in the Assets and continue to manage, operate and provide administrative servicesCanada Energy Regulator (CER) approved interim rates for the Assets.  The transaction is subject to closing adjustments and conditions customary in transactions of this nature. Closing is expected to occur during the third quarter of 2018 subject to the receipt of all necessary regulatory approvals and consents.

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

FORWARD-LOOKING INFORMATION
Forward-looking information, or forward-looking statements, have been included in this quarterly report on MD&A to provide information about us and our subsidiaries and affiliates, including management’s assessment of Enbridge and its subsidiaries’ future plans and operations. This information may not be appropriate for other purposes. Forward-looking statements are typically identified by words such as ‘‘anticipate”, “believe”, “estimate”, “expect”, “forecast”, “intend”, “likely”, “plan”, “project”, “target” and similar words suggesting future outcomes or statements regarding an outlook. Forward-looking information or statements included or incorporated by reference in this document include, but are not limited to, statements with respect to the following: expected earnings before interest, income taxes and depreciation and amortization (EBITDA); expected earnings/(loss); expected earnings/(loss) per share; expected future cash flows; expected performance of the Liquids Pipelines, Gas Transmission and Midstream, Gas Distribution, Green Power and Transmission, and Energy Services businesses; financial strength and flexibility; expectations on sources of liquidity and sufficiency of financial resources; expected costs related to announced projects and projects under construction; expected in-service dates for announced projects and projects under construction; expected capital expenditures; expected equity funding requirements for our commercially secured growth program; expected future growth and expansion opportunities; expectations about our joint venture partners’ ability to complete and finance projects under construction; expected closing of acquisitions and dispositions; estimated future dividends; recovery of the costs of the Canadian portion of the Line 3 Replacement Program (Canadian L3R Program); expected future actions of regulators; expected costs related to leak remediation and potential insurance recoveries; expectations regarding commodity prices; supply forecasts; expectations regarding the impact of the stock-for-stock merger transaction on February 27, 2017 between Enbridge and Spectra Energy Corp (the Merger Transaction) including our combined scale, financial flexibility, growth program, future business prospects and performance; impact of the Canadian L3R Program on existing integrity programs; the sponsored


39


vehicle strategy; dividend payout policy; dividend growth and dividend payout expectation; expectations on impact of hedging program; and expectations resulting from the successful execution of our 2018-2020 Strategic Plan.
Although we believe these forward-looking statements are reasonableM&N Pipeline effective January 1, 2022, which were based on the information availablenegotiated 2022 rates in the 2022-2023 settlement agreement and unanimously supported by shippers. The 2022-2023 M&N Canada settlement agreement was approved by the CER in February 2022.

British Columbia (BC) Pipeline
The settlement agreement for our BC Pipeline system expired in December 2021. The CER has approved 2022 interim tolls for BC Pipeline effective January 1, 2022 and settlement agreement negotiations are ongoing, with an expected agreement to be reached in the second half of 2022.

GAS DISTRIBUTION AND STORAGE RATE APPLICATIONS

2022 Rate Application
In June 2021, Enbridge Gas Inc. (Enbridge Gas) filed Phase 1 of the application with the Ontario Energy Board (OEB) for the setting of rates for 2022 (the 2022 Application). The 2022 Application was filed in accordance with the parameters of Enbridge Gas' OEB approved Price Cap Incentive Regulation rate setting mechanism and represents the fourth year of a five-year term. In October 2021, the OEB approved a Phase 1 Settlement Proposal and Interim Rate Order effective January 1, 2022. In April 2022, the OEB issued its decision on Phase 2 of the date such statements2022 Application filed in October 2021, addressing incremental capital module funding requirements, under which $127 million of Enbridge Gas' requested capital funding was approved. The capital funding approved will be incorporated into final rates, which will be made effective July 1, 2022. The current Phase 1 interim rates in effect from January through June 2022 are also expected to be made and processesfinal at that time.

FINANCING UPDATE

On January 19, 2022, we closed a $750 million private placement of non-call 10-year fixed-to-fixed subordinated notes which mature on January 19, 2082. The net proceeds from the offering were used to prepareredeem Preference Shares, Series 17 at par on March 1, 2022.

On February 17, 2022, we closed a three tranche offering of aggregate US$1.5 billion senior notes consisting of US$600 million two-year floating rate notes, US$400 million two-year notes and US$500 million three-year notes. Each tranche is payable semi-annually in arrears and matures on February 16, 2024, February 16, 2024 and February 14, 2025, respectively.

These financing activities, in combination with the information, such statements are not guaranteesfinancing activities executed in 2021, provide significant liquidity that we expect will enable us to fund our current portfolio of future performance and readers are cautioned against placing undue reliance on forward-looking statements. By their nature, these statements involve a variety of assumptions, known and unknown risks and uncertainties and other factors, which may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Material assumptions include assumptions about the following: the expected supply of and demand for crude oil, natural gas, natural gas liquids (NGL) and renewable energy; prices of crude oil, natural gas, NGL and renewable energy; exchange rates; inflation; interest rates; availability and price of labor and construction materials; operational reliability; customer and regulatory approvals; maintenance of support and regulatory approvals for our projects; anticipated in-service dates; weather; the realization of anticipated benefits and synergies of the Merger Transaction; governmental legislation; acquisitions and the timing thereof; the success of integration plans; impact of the dividend policy on our future cash flows; credit ratings; capital project funding; expected EBITDA; expected earnings/(loss); expected earnings/(loss) per share; expected future cash flows and estimated future dividends. Assumptions regarding the expected supply of and demand for crude oil, natural gas, NGL and renewable energy, and the prices of these commodities, are material to and underlie all forward-looking statements, as they may impact current and future levels of demand for our services. Similarly, exchange rates, inflation and interest rates impact the economies and business environments in which we operate and may impact levels of demand for our services and cost of inputs, and are therefore inherent in all forward-looking statements. Dueprojects without requiring access to the interdependenciescapital markets for the next 12 months should market access be restricted or pricing be unattractive. Refer to Liquidity and correlation of these macroeconomic factors, the impact of any one assumption on a forward-looking statement cannot be determined with certainty, particularly with respect to the impact of the Merger Transaction on us, expected EBITDA, earnings/(loss), earnings/(loss) per share, or estimated future dividends. The most relevant assumptions associated with forward-looking statements on announced projects and projects under construction, including estimated completion dates and expected capital expenditures, include the following: the availability and price of labor and construction materials; the effects of inflation and foreign exchange rates on labor and material costs; the effects of interest rates on borrowing costs; the impact of weather and customer, government and regulatory approvals on construction and in-service schedules and cost recovery regimes.Capital Resources.
Our forward-looking statements are subject to risks and uncertainties pertaining to the impact of the Merger Transaction, operating performance, regulatory parameters, dividend policy, project approval and support, renewals of rights-of-way, weather, economic and competitive conditions, public opinion, changes in tax laws and tax rates, changes in trade agreements, exchange rates, interest rates, commodity prices, political decisions and supply of and demand for commodities, including but not limited to those risks and uncertainties discussed in this quarterly report on MD&A and in our other filings with Canadian and United States securities regulators. The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these are interdependent and our future course of action depends on management’s assessment of all information available at the relevant time. Except to the extent required by applicable law, Enbridge Inc. assumes no obligation to publicly update or revise any forward-looking statements made in this quarterly report on MD&A or otherwise, whether as a result of new information, future events or otherwise. All subsequent forward-looking statements, whether written or oral, attributable to us or persons acting on our behalf, are expressly qualified in their entirety by these cautionary statements.

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RESULTS OF OPERATIONS

Three months ended
March 31,
 20222021
(millions of Canadian dollars, except per share amounts)  
Segment earnings/(loss) before interest, income taxes and depreciation and amortization1
Liquids Pipelines2,329 2,039 
Gas Transmission and Midstream1,014 973 
Gas Distribution and Storage665 634 
Renewable Power Generation162 156 
Energy Services(101)64 
Eliminations and Other355 220 
Earnings before interest, income taxes and depreciation and amortization1
4,424 4,086 
Depreciation and amortization(1,055)(932)
Interest expense(719)(657)
Income tax expense(593)(483)
Earnings attributable to noncontrolling interests(28)(22)
Preference share dividends(102)(92)
Earnings attributable to common shareholders1,927 1,900 
Earnings per common share attributable to common shareholders0.95 0.94 
Diluted earnings per common share attributable to common shareholders0.95 0.94 

1Non-GAAP financial measures. Please refer to Non-GAAP and Other Financial Measures.

40


 Three months ended March 31,
 2018
2017
(millions of Canadian dollars, except per share amounts) 
 
Segment earnings/(loss) before interest, income taxes and depreciation and amortization  
Liquids Pipelines1,156
1,480
Gas Transmission and Midstream126
475
Gas Distribution636
387
Green Power and Transmission109
101
Energy Services169
156
Eliminations and Other(279)(298)
   
Depreciation and amortization(824)(672)
Interest expense(656)(486)
Income tax expense73
(198)
(Earnings)/loss attributable to noncontrolling interests and redeemable noncontrolling interests24
(224)
Preference share dividends(89)(83)
Earnings attributable to common shareholders445
638
Earnings per common share0.26
0.54
Diluted earnings per common share0.26
0.54

EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS


Three months ended March 31, 2018,2022, compared with the three months ended March 31, 20172021

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

After taking into consideration the contribution of additional earnings from the Merger Transaction, Earnings Attributable to Common Shareholders was negatively impacted by $893$44 million due to certain unusual, infrequent or other non-operating factors, primarily explained by the following:
a loss of $913 million ($701 million after-tax attributable to us) on Midcoast Operating, L.P. and its subsidiaries resulting from a revision to the fair value of the assets held for sale based on the sale price; refer to Part I. Item 1. Financial Statements - Note 6. Assets Held for Sale;
a non-cash, unrealized derivative fair value lossgain of $277$433 million ($146331 million after-tax attributable to us)after-tax) in 2018,2022, compared with a gain of $416$279 million ($245211 million after-tax attributable to us)after-tax) in the corresponding 2017 period,2021, 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; and commodity prices risks;
$44 million ($33 million after-tax) impairment of lease assets due to office relocation plans; partially offset by
a non-cash, unrealized loss of $144$21 million ($8516 million after-tax attributable to us)after-tax) in 2018 related to the Line 10 crude oil pipeline (Line 10), which is a component of our mainline system, resulting from its classification as an asset held for sale and the subsequent measurement at the lower of carrying value or fair value less costs to sell;
employee severance, transition and transformation costs of $97 million ($96 million after-tax attributable to us) in 2018,2022, compared with $129an unrealized gain of $139 million ($78105 million after-tax attributableafter-tax) in 2021, reflecting the revaluation of derivatives used to us)manage the profitability of transportation and storage transactions, as well as manage the exposure to movements in the corresponding 2017 period, related to the Merger Transaction; partially offset bycommodity prices.
the absence of transaction costs of $152 million ($111 million after-tax attributable to us) recorded in 2017 related to the Merger Transaction;
a gain of $50 million after-tax attributable to us in 2018, compared with a loss $40 million in the corresponding 2017 period, resulting from the reallocation of income between our interest and the


41


noncontrolling interests in Enbridge Energy Partners, L.P. (EEP) to resolve capital account deficits as required under EEP’s partnership agreement; and
a gain of $63 million after-tax attributable to us in 2018 resulting from the impact of the TCJA on our United States Green Power and Transmission assets.

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


33


After taking into consideration the factors above, the remaining $336$71 million increase in earnings attributable to common shareholders is primarily explained by the following significant business factors:
strongerhigher throughput within our Liquids Pipeline segment driven by the continued recovery in demand from the impacts of the COVID-19 pandemic and incremental Line 3 replacement (L3R) capacity;
increased earnings within our Liquids Pipeline segment from the implementation of the full L3R surcharge beginning in October 2021 and from new export assets acquired in October 2021;
increased earnings from our Gas Transmission and Midstream segment primarily as a result of higher commodity prices benefiting our investments in DCP Midstream LLC, (DCP Midstream) and Aux Sable, as well as contributions from our Liquids Pipelines segment due to a higher foreign exchange hedge rate used to record United States dollar denominated Canadian Mainline revenues, a higher International Joint Tariff (IJT) Benchmark Toll and higher throughput driven by capacity optimization initiatives implemented in 2017;
contributions from new Liquids Pipelines assetsprojects placed into service in 2017;November 2021; and
increased earnings from our Gas Distribution and Storage segment due to colder weather experienced in our franchise areas when compared with the normal weather forecast embedded in rates; partially offset by
higher interest expense primarily due to reduced capitalized interest associated with the United States (US) portion of the L3R Project placed into service in the fourth quarter of 2021, as well as higher average principal and higher distribution charges.interest rates.


BUSINESS SEGMENTS


LIQUIDS PIPELINES
 
Three months ended
March 31,
 20222021
(millions of Canadian dollars)  
Earnings before interest, income taxes and depreciation and amortization1
2,329 2,039 
 Three months ended
March 31,
 2018
2017
(millions of Canadian dollars) 
 
Earnings before interest, income taxes and depreciation and amortization1,156
1,480
1Non-GAAP financial measure. Please refer to Non-GAAP and Other Financial Measures.


Three months ended March 31, 2018,2022, compared with the three months ended March 31, 20172021


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

After taking into consideration the contribution of additional earnings from the Merger Transaction, EBITDA decreased by $626$46 million due to certain unusual, infrequent or othernon-operating factors, primarily explained by the following:
a non-cash, unrealized lossgains of $298$122 million in 20182022, compared with a $164unrealized gains of $161 million gain in 20172021, reflecting net fair value gains and losses arising from changes in the mark-to-market value of derivative financial instruments used to manage foreign exchange and commodity price risks; andrisks.
a loss of $144 million in 2018 related to Line 10, which is a component of our mainline system, resulting from its classification as an asset held for sale and the subsequent measurement at the lower of carrying value or fair value less costs to sell.


After taking into consideration the factors above, the remaining $249$336 million increase is primarily explained by the following significant business factors:
increased earnings resulting from a higher foreign exchange hedge rate used to record United States dollar denominated Canadian Mainline revenues of $1.25 in 2018 compared with $1.04 in 2017;


42


increased earnings resulting from a higher IJT Benchmark Toll of $4.07 in 2018 compared with $4.05 in 2017, and higher toll surcharges for the recovery of costs related to certain expansion projects;
increased earnings resulting from higher Canadian Mainline and Lakehead Pipeline System ex-Gretna average throughput of 2,625 thousands of3.0 million barrels per day (kbpd)(mmbpd) in 20182022 as compared with 2,593 kbpdto 2.7 mmbpd in 20172021 driven by higher demand and incremental L3R capacity optimization initiatives implemented in 2017;that came into service October 2021;
implementation of full L3R surcharge of US$0.93 per barrel beginning October 2021 compared to the Canadian L3R program US$0.20 per barrel;
higher contributions from assets placed into service during 2017, including the Wood Buffalo Extension Pipeline, the Athabasca Pipeline TwinGulf Coast and the Norlite PipelineMid-Continent System anddue primarily to the acquisition of a minority interestthe Ingleside Energy Center, and related assets, in the fourth quarter of 2021; and higher contributions from our Bakken Pipeline System;
increased transportation revenues resulting from an increase in the level of committed take-or-pay volumesSystem, Seaway Crude Pipeline System, Gray Oak Pipeline, and higher spot volumes on Flanagan South Pipeline driven by strong demand in the United States Gulf Coast;on higher volumes to meet growing crude oil demand; partially offset by
the net unfavorable effectrecognition of translating United States dollar EBITDA at a lower Canadian to United States dollar average exchange rate (Average Exchange Rate) of $1.26provision against the interim Mainline International Joint Tariff (IJT) for barrels shipped in 2018 compared with $1.32 in 2017.2022.



34


GAS TRANSMISSION AND MIDSTREAM
 
Three months ended
March 31,
 20222021
(millions of Canadian dollars)  
Earnings before interest, income taxes and depreciation and amortization1
1,014 973 
 Three months ended
March 31,
 2018
2017
(millions of Canadian dollars)  
Earnings before interest, income taxes and depreciation and amortization126
475
1Non-GAAP financial measure. Please refer to Non-GAAP and Other Financial Measures.

 
Three months ended March 31, 2018,2022, compared with the three months ended March 31, 20172021


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

After taking into consideration the contribution of additional earnings from the Merger Transaction, EBITDA decreased by $923$10 million due to certain unusual, infrequent or other marketnon-operating factors, primarily explained by the following:
a lossnet non-cash equity investment losses relating to our share of $913 million on Midcoast Operating, L.P. and its subsidiaries resulting from a revision to the fair value of the assets held for sale based on the sale price; refer to Part I. Item 1. Financial Statements - Note 6. Assets Held for Sale; and
a non-cash, unrealized gain of $6 million in 2018 compared with a gain of $10 million in 2017 reflecting net fair value gains and losses arising from the changechanges in the mark-to-market value of derivative financial instruments used to manage foreign exchangeof our equity method investees, DCP Midstream and commodity price risk.Aux Sable.


After taking into consideration the factors above, theThe remaining $4$51 million increase is primarily explained by the following significant business factors:
operational efficiencies of $13 million achieved on our United States Midstream and Canadian assets;
increasedhigher commodity prices benefiting earnings of $6 million from our Allianceinvestments in Aux Sable and DCP joint venture dueventures;
contributions from the T-South and Spruce Ridge expansion projects after service commenced in November 2021; and
contributions from the Cameron Extension, Middlesex Extension and the Appalachia to favorable seasonal firm and interruptible revenues that resulted from wider basis differentials;Market projects placed into service in the fourth quarter of 2021; partially offset by
decreased marginslower U.S. Gas Transmission contributions on the timing of $13 million on our United States Midstream assets resulting from lower volumes.operating cost expenditures.


GAS DISTRIBUTION AND STORAGE


43


Three months ended
March 31,
Three months ended
March 31,
2018
2017
20222021
(millions of Canadian dollars)  (millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization636
387
Earnings before interest, income taxes and depreciation and amortization1
Earnings before interest, income taxes and depreciation and amortization1
665 634 
 

1Non-GAAP financial measure. Please refer to Non-GAAP and Other Financial Measures.

Three months ended March 31, 2018,2022, compared with the three months ended March 31, 20172021


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

After taking into consideration the contribution of additional earnings from the Merger Transaction, EBITDA decreased by $16 million due to certain unusual, infrequent and other business factors, primarily explained by the following:
a non-cash, unrealized gain of $1 million in 2018 compared with a gain of $10 million in 2017 arising from the change in the mark-to-market value of Noverco Inc.'s derivative financial instruments; and
a negative equity earnings adjustment of $9 million at Noverco Inc. in 2018 arising from the United States TCJA.

After taking into consideration the factors above, the remaining $85 million increase is primarily explained by the following significant business factors:
increased earnings of $25when compared with the normal weather forecast embedded in rates, weather was colder in 2022 and warmer in 2021. Colder than normal weather in 2022 positively impacted 2022 EBITDA by approximately $27 million resulting from colderwhile warmer than normal weather experienced in our franchise service areas;2021 negatively impacted 2021 EBITDA by approximately $24 million; and
higher distribution charges primarily reflecting growthresulting from increases in rate base.rates and customer base; partially offset by

the absence of earnings from Noverco Inc. (Noverco) due to the sale of our minority investment in Noverco in December 2021.

GREEN
35


RENEWABLE POWER AND TRANSMISSIONGENERATION
 
 
Three months ended
March 31,
 20222021
(millions of Canadian dollars)  
Earnings before interest, income taxes and depreciation and amortization1
162 156 
 Three months ended
March 31,
 2018
2017
(millions of Canadian dollars) 
 
Earnings before interest, income taxes and depreciation and amortization109
101
1Non-GAAP financial measure. Please refer to Non-GAAP and Other Financial Measures.

Three months ended March 31, 2018,2022, compared with the three months ended March 31, 20172021


EBITDA decreasedwas positively impacted by $30$6 million primarily due to certain unusual, infrequent and other factors, primarily explained by the following:
an asset impairment charge of $22 million in 2018 from our equity investment in NRGreen Power Limited Partnership related to the Chickadee Creek waste heat recovery facility in Alberta; and
a loss of $11 million in 2018 from our equity investment in Rampion Offshore Wind Limited resulting from damaged cables.

After taking into consideration the factors above, the remaining $38 million increase is primarily explained by the following significant business factors:
stronger wind resources of $13 million at Canadian and United StatesEuropean offshore wind farms;facilities;
contributionshigher energy pricing at the Rampion offshore wind facilities; and
the absence in 2022 of the effects from the Chapman Ranch Wind Project, which was placed into servicemajor winter storm in October 2017;Texas during February 2021; partially offset by
contributions from the Rampion Offshore Wind Project, which is expected to be fully operationalabsence in 2022 of a promote fee received in the secondfirst quarter of 2018; and2021 associated with the closing of the sale of 49% of our interest in three European offshore wind projects to Canada Pension Plan Investment Board (CPP Investments).
a net gain of $11 million from an arbitration settlement related to our Canadian wind facilities.



44


ENERGY SERVICES

Three months ended
March 31,
 20222021
(millions of Canadian dollars)  
Earnings/(loss) before interest, income taxes and depreciation and amortization1
(101)64 
1Non-GAAP financial measure. Please refer to Non-GAAP and Other Financial Measures.
 Three months ended
March 31,
 2018
2017
(millions of Canadian dollars) 
 
Earnings before interest, income taxes and depreciation and amortization169
156

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


Three months ended March 31, 2018,2022, compared with the three months ended March 31, 20172021


EBITDA decreasedwas negatively impacted by $13$169 million due to certain unusual, infrequent or othernon-operating factors, primarily explained by the following:
a non-cash, unrealized loss of $21 million in 2022, compared with an unrealized gain of $147$139 million in 2018 compared with a gain of $160 million in 20172021, reflecting the revaluation of financial derivatives used to manage the profitability of transportation and storage transactions, andas well as manage the exposure to movements in commodity prices.


After taking into consideration the factor above, the remaining $26$4 million increase is primarily explained by the following significant business factors:
increased earningsthe absence in 2022 of $17 millionadverse impacts from Energy Services’ natural gas operations due to increased asset positionsthe major winter storm experienced across the US Midwest during February 2021; partially offset by
a more pronounced market structure backwardation than in core markets, which allowed for optimizationthe same period of wider2021 and significant compression of location differentials in 2018; andcertain markets.
increased earnings of $6 million from Energy Services' Canadian and United States crude operations due to the widening of certain location and quality differentials in 2018, which increased opportunities to generate profitable margins.

36


ELIMINATIONS AND OTHER
 
Three months ended
March 31,
20222021
(millions of Canadian dollars)
Earnings before interest, income taxes and depreciation and amortization1
355 220 
 Three months ended
March 31,
 2018
2017
(millions of Canadian dollars)  
Loss before interest, income taxes and depreciation and amortization(279)(298)
1Non-GAAP financial measure. Please refer to Non-GAAP and Other Financial Measures.

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


Three months ended March 31, 2018,2022, compared with the three months ended March 31, 20172021


Loss before interest, income taxes and depreciation and amortization decreasedEBITDA was positively impacted by $5$156 million due to certain unusual, infrequent and othernon-operating factors, primarily explained by the following:
the absencean unrealized gain of transaction costs$309 million in 20182022, compared with $149 millionunrealized gains of costs recorded in 2017 related to the Merger Transaction;
employee severance, transition and transformation costs of $62$109 million in 2018 compared with $125 million in 2017; partially offset by
a non-cash, unrealized loss of $136 million in 2018 compared with a $72 million gain in 20172021, 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.risk, partially offset by $44 million in 2022 resulting from the impairment of lease assets due to office relocation plans.



45



After taking into consideration the non-operating factors above, the remaining $14$21 million decrease is primarily explained by the following significanttiming of certain operating and administrative cost recoveries from the business factors:
aunits, partially offset by higher realized loss of $42 million in 2018 compared with a loss of $72 million in 2017 related to settlements under our foreign exchange risk management program; partially offset bygains in 2022.
two additional months of eliminations and other costs post-Merger Transaction, net of corporate synergies.




37
46



GROWTH PROJECTS – COMMERCIALLY SECURED PROJECTS
 
The following table summarizes the status of our significant commercially secured projects, organized by business segment. Expenditures to date reflect total cumulative expenditures incurred from inception of the project to March 31, 2018.segment:
Enbridge's Ownership Interest
Estimated
Capital
Cost1
Expenditures
to Date
2
Status2
Expected
In-Service
Date
(Canadian dollars, unless stated otherwise)(Canadian dollars, unless stated otherwise)
 Enbridge's Ownership Interest
Estimated
Capital
Cost1
Expenditures
to Date
2
StatusExpected
In-Service
Date
(Canadian dollars, unless stated otherwise) 
LIQUIDS PIPELINES 
GAS TRANSMISSION AND MIDSTREAMGAS TRANSMISSION AND MIDSTREAM
1.
Canadian Line 3 Replacement Program (the Fund Group)3
100%$5.3 billion$2.5 billionUnder construction2H - 20191.Gulfstream Phase VI50 %US$0.1 billionUnder construction3Q - 2022
2.
U.S. Line 3 Replacement Program (EEP)4
100%US$2.9 billionUS$0.8 billion
Pre-construction5
2H - 20192.Vito Gas & Oil100 %US$0.3 billionUS$0.2 billionUnder construction4Q - 2022
3.
Other - United States6
100%US$0.4 billionSubstantially
complete
2H - 20193.Texas Eastern Modernization100 %US$0.4 billionNo significant expenditures to datePre-construction2024 - 2025
4.Other - Canada100%$0.1 billionNo significant
expenditures to date
Under constructionQ2 - 20184.Appalachia to Market II100 %US$0.1 billionNo significant expenditures to datePre-construction2025
GAS TRANSMISSION AND MIDSTREAM 
GAS DISTRIBUTION AND STORAGEGAS DISTRIBUTION AND STORAGE
5.Atlantic Bridge (SEP)100%US$0.5 billionUS$0.4 billionUnder constructionQ4 - 20185.Storage Enhancements100 %$0.1 billionNo significant expenditures to dateUnder construction2H - 2022
6.
NEXUS (SEP)

50%US$1.3 billionUS$0.7 billionUnder constructionQ3 - 20186.System Enhancement Projects100 %$0.3 billionNo significant expenditures to dateVarious stages2022 - 2023
7.Reliability and Maintainability Project100%$0.5 billion$0.4 billionUnder constructionQ3 - 20187.
Natural Gas Expansion Program3
100 %$0.1 billionNo significant expenditures to datePre-construction2022 - 2027
8.Valley Crossing Pipeline100%US$1.6 billionUS$1.4 billionUnder constructionQ4 - 20188.Panhandle Regional Expansion100 %$0.3 billionNo significant expenditures to datePre-construction2023 - 2024
RENEWABLE POWER GENERATIONRENEWABLE POWER GENERATION
9.Spruce Ridge Program100%$0.5 billion$0.1 billionPre-construction2H - 20199.East-West Tie Line25.0 %$0.2 billionCompleteIn service
10.
T-South Expansion Program
   
100%$1.0 billion
No significant
expenditures to date
Pre-construction2H - 202010.Solar Self-Power Projects100 %US$0.2 billionNo significant expenditures to dateUnder construction2022 - 2023
11.
Other - United States7
100%UStd.7 billionUS$0.9 billionVarious stages2018 - 201911.
Saint-Nazaire France Offshore Wind Project4
25.5 %$0.9 billion$0.5 billionUnder constructionQ4 - 2022
11.(€0.6 billion)(€0.4 billion)
Other - Canada8
100%$0.6 billionCompleteIn service12.
Provence Grand Large Floating Offshore Wind Project5
25 %$0.1 billionNo significant expenditures to date
Under construction6
2023
GREEN POWER AND TRANSMISSION 
12.12.
Provence Grand Large Floating Offshore Wind Project5
25 %(€0.1 billion)No significant expenditures to date
Under construction6
2023
$0.7 billion
13.Rampion Offshore Wind Project24.9%$0.8 billion
(£0.37 billion)
$0.6 billion
(£0.3 billion)
Under constructionQ2 - 201813.
Fécamp Offshore Wind Project7
17.9 %(€0.5 billion)(€0.2 billion)Under construction2023
14.Hohe See Offshore Wind Project and Expansion50%td.1 billion
(€1.34 billion)
$0.8 billion
(€0.6 billion)
Under construction2H - 2019$0.9 billion$0.2 billion
14.14.
Calvados Offshore Wind Project7
21.7 %(€0.6 billion)(€0.2 billion)Under construction2024
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 inceptionand status of the project up toare determined as at March 31, 2018.2022.
3 The Fund Group is comprisedRepresents Phase 2 of Enbridge Income Fund, Enbridge Commercial Trust, Enbridge Income Partners LPthe Natural Gas Expansion Program and the subsidiaries and investeesestimated capital cost is presented net of Enbridge Income Partners LP.the maximum funding assistance we expect to receive from the Government of Ontario. The expected in-service dates represent the expected completion dates of the leave to construct requirements.
4 The United States portion ofOur equity contribution is $0.15 billion, with the Line 3 Replacement Program (U.S. L3R Program) is being funded 99% by Enbridge and 1% by EEP.
5 Construction of the Wisconsin portionremainder of the project financed through non-recourse project level debt.
5Our equity contribution is mechanically complete as noted below. The remaining project is in pre-construction status.
6 Estimated in-service date will be adjusted to coincide$0.05 billion, with the in-service dateremainder of the U.S. L3R Program.project financed through non-recourse project level debt.
6Commenced onshore construction only.
7 IncludesOur equity contribution is $0.1 billion, with the US$0.2 billion Stampede Offshore oil lateral placed into service inremainder of the first quarter of 2018.project financed through non-recourse project level debt for each project.
8 Includes the $0.4 billion High Pine and the $0.2 billion Wyndwood pipeline expansion, both placed into service in the first quarter of 2018.



47



A full description of each of our projects is provided in our Annual Reportannual report on Form 10-K as filed withfor the Securities and Exchange Commission on February 16, 2018.year ended December 31, 2021. Significant updates that have occurred since the date of filing of our Form 10-K are discussed below.




38
48


GAS DISTRIBUTION AND STORAGE


LIQUIDS PIPELINES

United States Line 3 Replacement Program (EEP) - construction on the Wisconsin portionPanhandle Regional Expansion Project – Expansion of the U.S. L3R Program commencedPanhandle Transmission System, which supplies natural gas from the Dawn Hub to customers in late June 2017, was mechanically completed in February 2018 andSouthern Ontario west of Dawn. The project is expected to be commissioned in May 2018. For additional updates on the project, refer to Growth Projects - Regulatory Matters.
receive a full cost-of-service regulated return upon OEB approval with target in-service dates of November 2023 and November 2024.


GAS TRANSMISSION AND MIDSTREAM

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

GREEN POWER AND TRANSMISSION

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

GROWTH PROJECTS - REGULATORY MATTERS

United States Line 3 Replacement Program (EEP)
EEP is in the process of obtaining the appropriate permits for constructing the U.S. L3R Program in Minnesota. The project requires both a Certificate of Need and an approval of the pipeline’s route (Route Permit) from the Minnesota Public Utilities Commission (MNPUC). On February 1, 2016, the MNPUC issued a written order requiring the Minnesota Department of Commerce (DOC) to prepare an Environmental Impact Statement (EIS) before the Certificate of Need and Route Permit processes commence. The DOC issued the final EIS on August 17, 2017. The MNPUC determined the final EIS to be inadequate in four specific areas on December 7, 2017, which the MNPUC directed the DOC to address. As a result, the DOC provided a supplemental EIS on February 12, 2018 and the MNPUC deemed it adequate on March 15, 2018. Progress continues with the parallel Certificate and Route Permit dockets, with public and evidentiary hearings now complete.

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

OTHER ANNOUNCED PROJECTS UNDER DEVELOPMENT
 
The following projects have been announced by us during the quarter, but have not yet met our criteria to be classified as commercially secured:



49


LIQUIDS PIPELINES

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


GAS TRANSMISSION AND MIDSTREAM


Alliance PipelineValley Crossing Expansion Project -on March 28, 2018, AllianceOn January 10, 2022, we executed a precedent agreement with Texas LNG Brownsville LLC (Texas LNG) under which, via an expansion of our Valley Crossing Pipeline, announced an open season for binding bids for additional long-termwe will provide 0.72 bcf/d firm transportation service contracts oncapacity to Texas LNG’s proposed LNG liquefaction and export facility in the Alliance Pipeline Canada and Alliance Pipeline US systems in supportPort of upBrownsville, Texas for a term of at least 20 years. Expansion of the pipeline will be subject to 400 million cubic feet per day (mmcf/d)Texas LNG’s export facility reaching a final investment decision.

We also have a portfolio of expanded services on Alliance Pipeline Canada and upadditional projects under development that have not yet progressed to 430 mmcf/dthe point of expanded services on Alliance Pipeline US. The open season closes on May 30, 2018. The projected in-service date for the potential expansion is the fourth quarter of 2021.
securement.





50


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 help 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, execute share repurchases under our normal course issuer bid (NCIB) 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.

We have signed capital obligation contracts for the purchase of services, pipe and other materials totaling approximately $1.4 billion which are expected to be paid over the next five years.
 
Our financing plan is regularly updated to reflect evolving capital requirements and financial market conditions and identifies a variety of potential sources of debt and equity funding alternatives, including utilizationalternatives. Our current financing plan does not include any issuances of our sponsored vehicles.additional common equity.

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.


39


Credit Facilities and Liquidity
To ensure ongoing liquidity and to mitigate the risk of capital market disruption, we maintain ready access to funds through committed bank credit facilities and actively manage our bank funding sources to optimize pricing and other terms. The following table provides details of our committed credit facilities as at March 31, 2018.2022:
  March 31, 2018
 
Maturity
Dates
Total
Facilities

Draws1

Available
(millions of Canadian dollars)    
Enbridge Inc.2
2019-20226,644
2,616
4,028
Enbridge (U.S.) Inc.20192,469
1,142
1,327
Enbridge Energy Partners, L.P.3
2019-20223,385
1,660
1,725
Enbridge Gas Distribution Inc.20191,017
884
133
Enbridge Income Fund20201,500
566
934
Enbridge Pipelines Inc.20193,000
1,730
1,270
Spectra Energy Partners, LP4
20223,223
2,135
1,088
Union Gas Limited2021700
130
570
Total committed credit facilities 21,938
10,863
11,075
Maturity1
Total
Facilities
Draws2
Available
(millions of Canadian dollars)    
Enbridge Inc.2022 - 20267,616 7,012 604 
Enbridge (U.S.) Inc.2023 - 20266,870 5,351 1,519 
Enbridge Pipelines Inc.20233,000 627 2,373 
Enbridge Gas Inc.20232,000 1,604 396 
Total committed credit facilities19,486 14,594 4,892 
 
1
Includes facility draws, letters of credit and commercial paper issuances that are back-stopped by the credit facility.
2
Includes $135 million, $161 million (US$125 million) and$150 million of commitments that expire in 2018, 2018 and 2020, respectively.
3
Includes $226 million (US$175 million) and $239 million (US$185 million) of commitments that expire in 2018 and 2020, respectively.
4
Includes $434 million (US$336 million) of commitments that expire in 2021.

1Maturity date is inclusive of the one-year term out option for certain credit facilities.
During the first quarter of 2018, Enbridge terminated a US$650 million2Includes facility draws and commercial paper issuances that are back-stopped by credit facilities.

On February 10, 2022, we renewed our three year $1.0 billion sustainability-linked credit facility, which was setextending the maturity date out to mature in 2019, and repaid drawn amounts. In addition, Enbridge (U.S.) Inc. terminated an unutilizedUS$950 million credit facility, which was set to mature in 2019. July 2025.




51


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

In addition to the committed credit facilities noted above, we have $790 millionmaintain $1.3 billion of uncommitted demand letter of credit facilities, of which $511$947 million werewas unutilized as at March 31, 2018.2022. As at December 31, 2017,2021, we had $792 million$1.3 billion of uncommitted demand letter of credit facilities, of which $518$854 million werewas unutilized.


OurAs at March 31, 2022, our net available liquidity totaled $5.3 billion (December 31, 2021 - $6.5 billion), consisting of $11,685 million as at Marchavailable credit facilities of $4.9 billion (December 31, 2018,2021 - $6.2 billion) and was inclusive of $610 million of unrestricted cash and cash equivalents of $413 million (December 31, 2021 - $286 million) 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, 2018,2022, we were in compliance with all debt covenants and expects to continue to comply with such covenants.covenant provisions.


LONG-TERM DEBT ISSUANCES
During the first quarter of 2018,three months ended March 31, 2022, we completed the following long-term debt issuances: issuances totaling US$1.5 billion and $750 million:
CompanyIssue DatePrincipal Amount
(millions of Canadian dollars unless otherwise stated)
Enbridge Inc.
January 20225.00%hybrid fixed-to-fixed subordinated notes due January 2082$750
February 2022
Floating rate senior notes due February 20241
US$600
February 20222.15%senior notes due February 2024US$400
February 20222.50%senior notes due February 2025US$500
CompanyIssue DatePrincipal Amount
(millions of dollars)
Enbridge Inc.
March 2018
Fixed-to-floating rate notes due 20781
  US$850
Spectra Energy Partners, LP2
January 20183.50% senior notes due 2028  US$400
January 20184.15% senior notes due 2048US$400
1Notes mature in 60 years and are callable on or after year 10. For the initial 10 years, the notes carry a fixed1Notes carry an interest rate of 6.25%. Subsequently, the interest rate will be set to equal the three-month London Interbank Offered Rate (LIBOR) plus a margin of 364 basis points from years 10 to 30, and a margin of 439 basis points from years 30 to 60.
2Issued through Texas Eastern Transmission, LP, a wholly-owned operating subsidiary of SEP.

On April 12, 2018, we completed an offering of $750 million of fixed-to-floating rate subordinated notes that mature in 60 years and are callable on or after year 10. For the initial 10 years, the notes carry a fixed interest rate of 6.625%. After the initial 10 years, the interest rate will be set to equal the Canadian Dollar OfferedSecured Overnight Financing Rate plus a margin of 43263 basis points from years 10 to 30, and a margin of 507 basis points from years 30 to 60.points.

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




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LONG-TERM DEBT REPAYMENTS
During the first quarter of 2018,three months ended March 31, 2022, we completed the following long-term debt repayments totaling $200 million and US$750 million:
CompanyRepayment DatePrincipal Amount
(millions of Canadian dollars unless otherwise stated)
Enbridge Inc.
February 2022
Floating rate notes1
US$750
February 20224.85%medium-term notes$200
1Notes carried an interest rate set to further simplify our debt financing structure post-merger:equal the three-month London Interbank Offered Rate plus a margin of 50 basis points.
CompanyRetirement/Repayment DatePrincipal Amount
Cash Consideration
(millions of Canadian dollars unless otherwise stated)
Enbridge Southern Lights LP
January 20184.01% medium-term notes due June 20409
Spectra Energy Capital, LLC1
Repurchase via Tender Offer
March 20186.75% senior unsecured notes due 2032US$64US$80
March 20187.50% senior unsecured notes due 2038US$43US$59
Redemption
March 20185.65% senior unsecured notes due 2020US$163US$172
March 20183.30% senior unsecured notes due 2023US$498US$508
1
The loss on debt extinguishment of $37 million (US$29 million), net of the fair value adjustment recorded upon completion of the Merger Transaction, was reported within Interest expense in the Consolidated Statements of Earnings.


Strong growth in internal cash flow, ready access to liquidity from diversified sources and a stable business model supporthave 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 help ensure ongoing access to bank funding and term debt capital on attractive terms. Key measures of financial strength that are closely managed include the ability to service debt obligations from operating cash flow and the ratio of debt to total capital. As at March 31, 2018, our debt capitalization ratio was 48.2%, compared with 48.3% as at December 31, 2017.EBITDA.


There are no material restrictions on our cash. Total restricted cash of $113$41 million, includes EGD’s and Union Gas’ receiptas reported on the Consolidated Statements of cash from the Government of Ontario to fund its Green Investment Fund program. In addition, our restricted cashFinancial Position, primarily includes cash collateral, future pipeline abandonment costs collected and held in trust, amounts received in respect of specific shipper commitments.commitments and capital projects. Cash and cash equivalents held by EEP, the Fund Group and SEP are generally not readily accessible by us until distributions are declared and paid by these entities, which occurs quarterly for EEP and SEP, and monthly for the Fund Group. Further, cash and cash equivalents held by certain foreign subsidiaries may not be readily accessible for alternative uses by us.

Excluding current maturities of long-term debt, we had a negative working capital position as at March 31, 2018.2022. The major contributing factor to the negative working capital position was the ongoing funding of our growth capital program.
To address this negative working capital position, we maintain significant liquidity in the form of committed credit facilities and other sources as previously discussed, which enable the funding of liabilities as they become due. As at March 31, 2018 and December 31, 2017, our net available liquidity totaled $11,685 million and $12,959 million, respectively.


SOURCES AND USES OF CASH
 
Three months ended
March 31,
 20222021
(millions of Canadian dollars)  
Operating activities2,939 2,564 
Investing activities(1,318)(1,958)
Financing activities(1,483)(565)
Effect of translation of foreign denominated cash and cash equivalents and restricted cash(4)(7)
Net increase in cash and cash equivalents and restricted cash134 34 
 Three months ended
March 31,
 2018
2017
(millions of Canadian dollars) 
 
Operating activities3,194
1,776
Investing activities(2,068)(3,448)
Financing activities(1,009)1,313
Effect of translation of foreign denominated cash and cash equivalents and restricted cash19
(9)
Increase/(decrease) in cash and cash equivalents and restricted cash136
(368)


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Significant sources and uses of cash for the three months ended March 31, 20182022 and March 31, 20172021 are summarized below:

Operating Activities
 
The growth inTypically, the primary factors impacting cash flow delivered by operationsfrom operating activities period-over-period include changes in the first quarter of 2018 is a reflection of the positive operating factors discussed under Results of Operations. The increase in operating cash flow was driven mainly from the contributions from new assets and distributions from additional long-term investments following the completion of the Merger Transaction.
Changes inour operating assets and liabilities included within operating activities were $622 million and $340 million for the three months ended March 31, 2018 and 2017, respectively. Our operating assets and liabilities fluctuate in the normal course due to various factors, including the impact of fluctuations in commodity prices and activity levels on working capital within the Energy Services and Gas Distributionour business segments, the timing of tax payments, as well as timing of cash receipts and payments generally. Cash provided by operating activities is also impacted by changes in earnings and certain unusual, infrequent and other non-operating factors, as discussed under Results of Operations.


41


Investing Activities
The quarter-over-quarter decrease of cashCash used in investing activities was primarily attributablerelates to activity in the first quarter of 2017 that was not present in the first quarter of 2018, related primarilycapital expenditures to the acquisition of an interest in the Bakken Pipeline System of $2.0 billion (US $1.5 billion), partially offset by cash acquired in the Merger Transaction of $0.7 billion and cash received from asset dispositions of $0.3 billion.
We are continuing with the execution ofexecute our growth capital program, which is further described in Growth Projects - Commercially Secured Projects.The timing of project approval, construction and in-service dates impacts the timing of cash requirements.
Factors impacting the decrease in cash used in investing activities period-over-period primarily include:
lower capital expenditures due to the US L3R Program that was placed into service in the fourth quarter of 2021; partially offset by
increased contributions made to our equity investment in MarEn Bakken Company LLC due to debt servicing requirements for the Bakken Pipeline System; and
the absence of proceeds received from the sale of 49% of an entity that holds our 50% interest in Éolien Maritime France SAS to CPP Investments in the first quarter of 2021.

Financing Activities
The quarter-over-quarter decreaseCash provided by and used in financing activities primarily relates to issuances and repayments of external debt, as well as transactions with our common and preference shareholders relating to dividends, share issuances, share redemptions and common share repurchases under our NCIB. Cash flow from financing activities is also impacted by changes in distributions to, and contributions from, noncontrolling interests. Factors impacting the increase in cash provided byused in financing activities wasperiod-over-period primarily attributable to repayments of maturing term notesinclude:
net commercial paper and credit facilities. Duringfacility repayments in 2022 when compared to net issuances during the three months ended March 31, 2018, we issued hybrid securities,same period in 2021, as well as higher long-term debt repayments made during the proceedsfirst quarter of which were used to repay maturing term notes2022;
the redemption of Preference Shares, Series 17 and credit facilitiesthe repurchase and to finance growth capital programs. Proceeds fromcancellation of 950,024 common shares under our NCIB for approximately $50 million during the hybrid securities were primarily used to repay credit facilitiesfirst quarter of 2022; and to repurchase or redeem Spectra Energy Capital, LLC’s outstanding senior unsecured notes as discussed in Liquidity and Capital Resources - Long-Term Debt Repayments.
Finally, with the exception of dividends paid to Spectra Energy shareholders that were declared prior to the Merger Transaction, our common share dividend payments increased in the first quarter of 2018,period-over-period primarily due to the increase in theour common share dividend raterate.

The factors above were partially offset by:
net issuances of short-term borrowings in 2022 when compared to net repayments during the second and fourth quarters of 2017,same period in 2021, as well as an increasehigher long-term term debt issuances during the first quarter of 2022; and
the redemption of Westcoast Energy Inc.'s preferred shares in the numberfirst quarter of common shares2021.

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, LP (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 asseries 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 common shares issuedthe guarantees, holders of any of the outstanding guaranteed notes of the Partnerships (the Guaranteed Partnership Notes) are in connectionthe same position with the Merger Transaction.

Dividend Reinvestment and Share Purchase Plan
Participants in our Dividend Reinvestment and Share Purchase Plan (DRIP) receive a 2% discount on the purchase of common shares with reinvested dividends. For the three months ended March 31, 2018 and 2017, total dividends paid were $1,138 million and $548 million, respectively, of which $764 million and $354 million, respectively, were paid in cash and reflected in financing activities. The remaining $374 million and $194 million, respectively, of dividends paid were reinvested pursuantrespect to the DRIPnet assets, income and resulted incash flows of Enbridge as holders of Enbridge's outstanding guaranteed notes (the Guaranteed Enbridge Notes), and vice versa. Other than the issuancePartnerships, Enbridge subsidiaries (including the subsidiaries of common shares rather than a cash payment. In addition to amounts paid in cash and reflected in financing activities for the three months ended March 31, 2017, were $414 million in dividends declared to Spectra Energy shareholders priorPartnerships, collectively, the Subsidiary Non-Guarantors), are not parties to the Merger Transaction that were paid after the Merger Transaction. For the three months ended March 31, 2018subsidiary guarantee agreement and 2017, 32.9% and 35.4%, respectively,have not otherwise guaranteed any of total dividends paid were reinvested through the DRIP.Enbridge's outstanding series of senior notes.




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54



Our Board of Directors has declared the following quarterly dividends. All dividends are payable on June 1, 2018, to shareholders of record on May 15, 2018.
Consenting SEP notes and EEP notes under Guarantee
Common Shares
SEP Notes1

$0.67100
EEP Notes2
Preference Shares, Series A4.750% Senior Notes due 2024
$0.34375
5.875% Notes due 2025
Preference Shares, Series B3.500% Senior Notes due 2025
$0.21340
5.950% Notes due 2033
Preference Shares, Series C1
3.375% Senior Notes due 2026

$0.22685
6.300% Notes due 2034
Preference Shares, Series D2
5.950% Senior Notes due 2043

$0.27875
7.500% Notes due 2038
Preference Shares, Series F4.500% Senior Notes due 2045
$0.25000
5.500% Notes due 2040
Preference Shares, Series H
$0.25000
Preference Shares, Series JUS$0.30540
Preference Shares, Series LUS$0.30993
Preference Shares, Series N
$0.25000
Preference Shares, Series P
$0.25000
Preference Shares, Series R
$0.25000
Preference Shares, Series 1US$0.25000
Preference Shares, Series 3
$0.25000
Preference Shares, Series 5US$0.27500
Preference Shares, Series 7
$0.27500
Preference Shares, Series 9
$0.27500
Preference Shares, Series 11
$0.27500
Preference Shares, Series 13
$0.27500
Preference Shares, Series 15
$0.27500
Preference Shares, Series 17
$0.32188
Preference Shares, Series 193

$0.30625
7.375% Notes due 2045
1As at March 31, 2022, the aggregate outstanding principal amount of SEP notes was approximately US$3.2 billion.
2As at March 31, 2022, the aggregate outstanding principal amount of EEP notes was approximately US$2.4 billion.

Enbridge Notes under Guarantees
USD Denominated1
The quarterly dividend amountsCAD Denominated2
Floating Rate Senior Notes due 20233.190% Senior Notes due 2022
Floating Rate Senior Notes due 20243.940% Senior Notes due 2023
2.900% Senior Notes due 20223.940% Senior Notes due 2023
4.000% Senior Notes due 20233.950% Senior Notes due 2024
0.550% Senior Notes due 20232.440% Senior Notes due 2025
3.500% Senior Notes due 20243.200% Senior Notes due 2027
2.150% Senior Notes due 20246.100% Senior Notes due 2028
2.500% Senior Notes due 20252.990% Senior Notes due 2029
2.500% Senior Notes due 20257.220% Senior Notes due 2030
4.250% Senior Notes due 20267.200% Senior Notes due 2032
1.600% Senior Notes due 20263.100% Sustainability-Linked Senior Notes due 2033
3.700% Senior Notes due 20275.570% Senior Notes due 2035
3.125% Senior Notes due 20295.750% Senior Notes due 2039
2.500% Sustainability-Linked Senior Notes due 20335.120% Senior Notes due 2040
4.500% Senior Notes due 20444.240% Senior Notes due 2042
5.500% Senior Notes due 20464.570% Senior Notes due 2044
4.000% Senior Notes due 20494.870% Senior Notes due 2044
3.400% Senior Notes due 20514.100% Senior Notes due 2051
4.560% Senior Notes due 2064
1As at March 31, 2022, the aggregate outstanding principal amount of the Enbridge US dollar denominated notes was approximately US$11.7 billion.
2As at March 31, 2022, the aggregate outstanding principal amount of the Enbridge Canadian dollar denominated notes was approximately $9.0 billion.

Rule 3-10 of the US Securities and Exchange Commission's (SEC) Regulation S-X provides an
exemption from the reporting requirements of the Exchange Act for fully consolidated subsidiary issuers of guaranteed securities and subsidiary guarantors and allows for summarized financial information in lieu of filing separate financial statements for each of the Partnerships.

The following Summarized Combined Statement of Earnings and Summarized Combined Statements of Financial Position combines the balances of EEP, SEP and Enbridge Inc.
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Summarized Combined Statement of Earnings
Three months ended March 31, 2022
(millions of Series C was increased to $0.22685 from $0.20342 on March 1, 2018, due to reset on a quarterly basis.Canadian dollars)
2Operating loss
The quarterly dividend amounts of Series D was increased to $0.27875 from $0.25000 on March 1, 2018, due to reset of the annual dividend on March 1, 2018, and every five years thereafter.
(28)
3Earnings
The Series 19 increase from $0.26850989
Earnings attributable to the regular quarterly dividend of $0.30625 will take effect on June 1, 2018.common shareholders887


Summarized Combined Statements of Financial Position
March 31,
2022
December 31,
2021
(millions of Canadian dollars)
Accounts receivable from affiliates3,400 3,442 
Short-term loans receivable from affiliates4,645 4,947 
Other current assets631 605 
Long-term loans receivable from affiliates48,731 51,983 
Other long-term assets3,975 3,732 
Accounts payable to affiliates1,971 1,982 
Short-term loans payable to affiliates3,549 2,891 
Other current liabilities4,073 8,110 
Long-term loans payable to affiliates39,043 41,370 
Other long-term liabilities43,606 41,353 
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 US 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
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 US 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;
44


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 will terminate with respect to any series of Guaranteed Partnership Notes if that series is discharged or defeased.

The Partnerships also guarantee the obligations of Enbridge under its existing credit facilities.

LEGAL AND OTHER UPDATES

LIQUIDS PIPELINES
Eddystone Rail Legal Matter
In February 2017, Eddystone Rail Company, LLC (Eddystone Rail) filed an action against several defendants in the United States District Court for the Eastern District of Pennsylvania. Eddystone Rail alleges that the defendants transferred valuable assets from Eddystone Rail’s counterparty in a maritime contract, so as to avoid outstanding obligations to Eddystone Rail. Eddystone Rail is seeking payment of compensatory and punitive damages in excess of US$140 million. On July 19, 2017, the defendants’ motions to dismiss Eddystone Rail’s claims were denied. Defendants have filed Answers and Counterclaims, which together with subsequent amendments, seek damages from Eddystone Rail in excess of US$32 million. Eddystone filed a motion to dismiss the counterclaims and defendants amended their Answer and Counterclaims on September 21, 2017. On October 12, 2017 Eddystone Rail moved to dismiss the latest version of defendants’ counterclaims. On February 6, 2018, the Court denied without prejudice Eddystone Rail's motion to dismiss the defendants' counterclaims. The defendants’ chances of success on their counterclaims cannot be predicted at this time.

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


55


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


OTHER LITIGATION
We and our subsidiaries are involved in various other legal and regulatory actions and proceedings which arise in the normal course of business, including interventions in regulatory proceedings and challenges to regulatory approvals and permits by special interest groups.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 $2,265 million which are expected to be paid over the next five years.


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

CHANGES IN ACCOUNTING POLICIES
 
ADOPTION OF NEW STANDARDSRefer to Part I. Item 1. Financial Statements - Note 2. Changes in Accounting Policies.
Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income
Effective January 1, 2018, we adopted Accounting Standards Update (ASU) 2018-02 to address a specific consequence of theTCJAenacted by the United States federal government on December 22, 2017. The amendments in this accounting update allow a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the TCJA. The amendments will eliminate the stranded tax effects as a result of the reduction of the historical United States federal corporate income tax rate to the newly enacted United States federal corporate income tax rate. The adoption of this accounting update did not have a material impact on our consolidated financial statements.

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

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


56


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

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

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

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

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

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


57


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

In adopting Accounting Standards Codification (ASC) 606, we applied the practical expedient for contract modifications whereby contracts that were modified before January 1, 2018 were not retrospectively restated. Instead, the aggregate effect of all contract modifications occurring before that time has been reflected when identifying satisfied and unsatisfied performance obligations, determining the transaction price and allocating the transaction price to satisfied and unsatisfied obligations.
The below table presents the cumulative, immaterial effect of the adoption of ASC 606 on our Consolidated Statement of Financial Position as at January 1, 2018 on each affected financial statement line item along with explanations of those effects. For the three months ended March 31, 2018, the effect of the adoption of ASC 606 on our Consolidated Statement of Earnings was not material.
 Balance at December 31, 2017Adjustments Due to ASC 606
Balance at
January 1, 2018
(millions of Canadian dollars)   
Assets   
Deferred amounts and other assets1,2
6,442
(170)6,272
Property, plant and equipment, net2
90,711
112
90,823
Liabilities and equity   
Accounts payable and other1,2
9,478
62
9,540
Other long-term liabilities2
7,510
66
7,576
Deferred income taxes1,2
9,295
(62)9,233
Redeemable noncontrolling interests1,2
4,067
(38)4,029
Deficit1,2
(2,468)(86)(2,554)
Revenue was previously recognized for a certain contract within the Liquids Pipelines business unit using a formula-based method. Under the new revenue standard, revenue is recognized on a straight-line basis over the term of the agreement in order to reflect the fulfillment of our performance obligation to provide up to a specified volume of pipeline capacity throughout the term of the contract.
Certain payments received from customers to offset the cost of constructing assets required to provide services to those customers, referred to as Contributions in Aid of Construction (CIACs) were previously recorded as reductions of property, plant and equipment regardless of whether the amounts were imposed by regulation or arose from negotiations with customers. Under the new revenue standard, CIACs which are negotiated as part of an agreement to provide transportation and other services to a customer are deemed to be advance payments for future services and are recognized as revenue when those future services are provided. Accordingly, negotiated CIACs are accounted for as deferred revenue and recognized as revenue over the term of the associated revenue contract. Amounts which are required to be collected from the customer based on requirements of the regulator continue to be accounted for as reductions of property, plant and equipment.

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

Amending the Amortization Period for Certain Callable Debt Securities Purchased at a Premium
ASU 2017-08 was issued in March 2017 with the intent of shortening the amortization period to the earliest call date for certain callable debt securities held at a premium. The accounting update is effective


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January 1, 2019 and will be applied on a modified retrospective basis. We are currently assessing the impact of the new standard on our consolidated financial statements.
Accounting for Credit Losses
ASU 2016-13 was issued in June 2016 with the intent of providing financial statement users with more useful information about the expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity at each reporting date. Current treatment uses the incurred loss methodology for recognizing credit losses that delays the recognition until it is probable a loss has been incurred. The accounting update adds a new impairment model, known as the current expected credit loss model, which is based on expected losses rather than incurred losses. Under the new guidance, an entity will recognize as an allowance its estimate of expected credit losses, which the Financial Accounting Standards Board believes will result in more timely recognition of such losses. The accounting update is effective January 1, 2020. We are currently assessing the impact of the new standard on our consolidated financial statements.

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

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK


Our exposure to market risk is described in Part II. Item 7A7A.Quantitative and Qualitative Disclosures About Market Risk of our Annual Reportannual report on Form 10-K for the fiscal year ended December 31, 2017, filed with the SEC on February 16, 2018.2021. We believe our exposure to market risk has not changed materially since then.


ITEM 4. CONTROLS AND PROCEDURES


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




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Under the supervision of and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, we have evaluated the effectiveness of our disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as ofat March 31, 2018,2022, and based upon this evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that these controls and procedures are effective in ensuring that information required to be disclosed by us in reports that we file with or submitssubmit to the SEC and the Canadian Securities Administrators is recorded, processed, summarized and reported within the time periods required.


Changes in Internal Control over Financial Reporting
Under the supervision of and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, we have evaluated changes in internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that occurred during the fiscal quarter ended March 31, 20182022 and found no change that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.



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PART II - OTHER INFORMATION


ITEM 1. LEGAL PROCEEDINGS


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


SEC regulations require the disclosure of any proceeding under environmental laws to which a governmental authority is a party unless the registrant reasonably believes it will not result in monetary sanctions over a certain threshold. Given the size of our operations, we have elected to use a threshold of US$1 million for the purposes of determining proceedings requiring disclosure.

The Minnesota Department of Natural Resources (DNR) issued an Administrative Penalty Order on September 16, 2021 due to an uncontrolled groundwater flow at Clearbrook. After implementing agency-approved remedial actions plans at Clearbrook and two other locations relating to L3R construction, all groundwater flows have been stopped. We continue the process of restoration, monitoring and mitigation for all three sites and are working on a comprehensive resolution with the DNR. In addition, in October 2021, the Minnesota Pollution Control Agency (MPCA) notified us that it was investigating certain matters relating to L3R construction. Each matter was redressed during construction. Additional information was provided to the MPCA in response. We continue to work towards a comprehensive resolution with the MPCA. Financial penalties are not expected to be material.

ITEM 1A. RISK FACTORS


In addition to the other information set forth in this report, careful consideration should be given to the factors discussed in Part I. Item 1A. 1A. Risk Factors in of our Annual Reportannual report on Form 10-K for the year ended December 31, 2017,2021, which could materially affect our financial condition or future results. Other than as set out below, thereThere have been no material modifications to those risk factors.

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

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

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

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



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


None.ISSUER PURCHASES OF EQUITY SECURITIES


PeriodTotal number of shares purchasedAverage price paid per shareTotal number of shares purchased as part of publicly announced plans or programs
Maximum number of shares that may yet be purchased under the plans or programs1
January 2022
(January 1 - January 31)
— N/A— 31,062,331 
February 2022
(February 1 - February 28)
950,024 CAD$52.65 (TSX)/
US$41.29 (NYSE)
950,024 30,112,307 
March 2022
(March 1 - March 31)
— N/A— 30,112,307 
1 On December 31, 2021, the Toronto Stock Exchange (TSX) approved our NCIB to purchase, for cancellation, up to 31,062,331 of the outstanding common shares of Enbridge to an aggregate amount of up to $1.5 billion, subject to certain restrictions on the number of common shares that may be purchased on a single day. Purchases under the NCIB may be made through the facilities of the TSX, the New York Stock Exchange (NYSE) and other designated exchanges and alternative trading systems. Our NCIB commenced on January 5, 2022, and continues until January 4, 2023, when it expires, or such earlier date on which we have either acquired the maximum number of common shares allowable or otherwise decide not to make further repurchases.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES


None.


ITEM 4. MINE SAFETY DISCLOSURES


Not applicable.


ITEM 5. OTHER INFORMATION


None.We issued a press release on May 4, 2022 announcing the election of two new Directors to our Board, which is attached hereto as Exhibit 99.2.


Jason B. Few and Steven W. Williams were each elected as Directors on our Board on a vote by ballot during the regular business proceedings at Enbridge’s Annual Meeting of Shareholders held on May 4 2022, to serve until the next Annual Meeting of Shareholders of Enbridge in 2023. The Board, on recommendation of its Governance Committee, appointed Mr. Few to the Sustainability Committee and the Safety & Reliability Committee and appointed Mr. Williams to the Audit, Finance & Risk Committee and the Safety & Reliability Committee, all effective May 4, 2022.

In accordance with our standard compensatory arrangement for non-employee directors, Mr. Few and Mr. Williams will each receive a US$285,000 annual retainer, in a combination of cash, Enbridge shares and deferred share units. We have entered into our standard form of indemnification agreement with each of Mr. Few and Mr. Williams.

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ITEM 6. EXHIBITS

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


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Exhibit No.Description
2.1
3.1
3.2
3.3
4.1
4.2
Certain instruments defining the rights of holders of long-term debt securities of the Registrant and its subsidiaries are omitted pursuant to Item 601(b)(4)(iii) of Regulation S-K. The Registrant hereby undertakes to furnish to the SEC, upon request, copies of any such instruments.
10.1*+
10.2*+
10.3*+
31.1*  
101.INS* XBRL Instance Document.
101.SCH*Inline XBRL Taxonomy Extension Schema Document.
101.CAL*Inline XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF*Inline XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB*Inline XBRL Taxonomy Extension Label Linkbase Document.
101.PRE*Inline XBRL Taxonomy Extension Presentation Linkbase Document.
104Cover Page Interactive Data File - the cover page XBRL tags are embedded within the Inline XBRL document (included in Exhibit 101)



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


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ENBRIDGE INC.
(Registrant)
Date:May 10, 20186, 2022By: /s/ Al Monaco
Al Monaco
President and Chief Executive Officer
(Principal Executive Officer)
Date:May 10, 20186, 2022By:/s/ John K. WhelenVern D. Yu
John K. Whelen
Vern D. Yu
Executive Vice President, Corporate Development and Chief Financial Officer
(Principal Financial Officer)


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